ANNUAL REPORT
DIAMOND OFFSHORE DRILLING , INC .
FINANCIAL HIGHLIGHTS ((cid:2)DOLL ARS IN MILLIONS(cid:2))
2015
2014
2013
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,419 $
2,815 $
2,920
Depreciation & Amortization . . . . . . . . . . . . . . . . . . . .
Operating Expenses . . . . . . . . . . . . . . . . . . . . . . . .
493
2,713
456
2,242
Earnings Before Interest, Taxes, Depreciation & Amortization ( EBITDA ) . . .
1,060
1,139
Net (Loss) Income . . . . . . . . . . . . . . . . . . . . . . . .
Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . .
(274)
831
387
2,033
388
2,119
1,190
549
958
Cash and Investments . . . . . . . . . . . . . . . . . . . . . . .
$
131
$
250 $
2,097
Drilling & Other Property & Equipment, Net . . . . . . . . . . . . . .
Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long - term Debt . . . . . . . . . . . . . . . . . . . . . . . . .
Shareholders’ Equity . . . . . . . . . . . . . . . . . . . . . . .
6,379
7,165
1,995
4,113
6,946
8,021
2,244
4,451
5,467
8,391
2,494
4,637
ABOUT THE COMPANY
Diamond Offshore is a leader in offshore drilling, providing contract drilling services to the energy
industry around the globe with a total fleet of 32 offshore drilling rigs, including one rig under
construction. Diamond Offshore's fleet consists of 23 semisubmersibles, of which one harsh environ-
ment semi is under construction, four dynamically positioned drillships, and five jack-ups. Diamond
Offshore’s headquarters are in Houston, Texas. Primary regional offices are located in Brazil, Scotland,
and Singapore, with local offices in other countries as required to support operations. Approximately
3,400 people work for the Company on board our rigs and in our offices. Diamond Offshore’s
common stock is listed on the New York Stock Exchange under the symbol “DO.”
ABOUT THE COVER
The Ocean BlackLion is currently working in the Gulf of Mexico.
Our Fleet (as of February 16, 2016)
DRILLSHIPS
Ultra-deepwater Rigs (7,500+ Ft.)
¬
¬
¬
¬
Ocean
BlackHawk
12,000 Ft.
DP; 15K; 5M; 7R
GOM
Ocean
BlackHornet
12,000 Ft.
DP; 15K; 5M; 7R
GOM
Ocean
BlackLion
12,000 Ft.
DP; 15K; 5M; 7R
GOM
Ocean
BlackRhino
12,000 Ft.
DP; 15K; 5M; 7R
GOM
SEMISUBMERSIBLE RIGS
Ultra-deepwater Rigs (7,500+ Ft.)
J
J
J
N
J
J
J
J
Ocean
Confidence
10,000 Ft.
DP; 15K; 4M; 6R
Canary Islands
(Cold
stacked)
Ocean
Courage
10,000 Ft.
DP; 15K; 4M; 6R
Brazil
Ocean
Endeavor
10,000 Ft.
VC; 15K; 4M; 5R
Romania
Ocean
GreatWhite
10,000 Ft.
DP; 15K; 4M; 6R
South Korea
Ocean
Monarch
10,000 Ft.
VC; 15K; 4M; 5R
Australia
Ocean
Valor
10,000 Ft.
DP; 15K; 4M; 6R
Brazil
Under
Construction
Ocean
Baroness
8,000 Ft.
VC; 15K; 4M; 4R
GOM
(Cold
stacked)
Ocean
Rover
8,000 Ft.
VC; 15K; 4M; 5R
Malaysia
Deepwater Rigs (5,000 – 7,500 Ft.)
l
l
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l
l
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l
Ocean
Apex
6,000 Ft.
VC; 15K; 4M; 5R
Malaysia
Ocean
Onyx
6,000 Ft.
VC; 15K; 4M; 5R
GOM
(Cold
stacked)
Ocean
America
5,500 Ft.
SP; 15K; 3M; 5R
Malaysia
(Cold
stacked)
Ocean
Star
5,500 Ft.
VC; 15K; 3M; 4R
GOM
(Cold
stacked)
Ocean
Valiant
5,500 Ft.
SP; 15K; 3M; 4R
UK
Ocean
Victory
5,500 Ft.
VC; 15K; 3M; 5R
Trinidad
Ocean
Alliance
5,250 Ft.
DP; 15K; 3M; 4R
GOM
(Cold
stacked)
Mid-water Rigs (450 – 5,000 Ft.)
J
J
J
Ocean
Quest
4,000 Ft.
VC; 15K; 3M; 4R
Malaysia
(Cold
stacked)
Ocean
General
3,000 Ft.
3M; 4R
Malaysia
(Cold
stacked)
Ocean
Patriot
3,000 Ft.
15K; 3M; 5R
UK
J
Ocean
Guardian
1,500 Ft.
15K; 3M; 5R
UK
J
Ocean
Princess
1,500 Ft.
15K; 3M; 4R
UK
(Cold
stacked)
J
Ocean
Vanguard
1,500 Ft.
15K; 3M; 4R
UK
(Cold
stacked)
J
Ocean
Nomad
1,200 Ft.
3M; 4R
UK
(Cold
stacked)
J
Ocean
Ambassador
1,100 Ft.
3M; 4R
Mexico
JACK-UP RIGS
K
Ocean
Scepter
350 Ft.
IC; 15K; 3M
Mexico
K
Ocean
King
300 Ft.
IC; 3M
GOM
(Cold
stacked)
K
Ocean
Nugget
300 Ft.
IC
GOM
(Cold
stacked)
K
Ocean
Spur
300 Ft.
IC
Malaysia
(Cold
stacked)
K
Ocean
Summit
300 Ft.
IC
GOM
(Cold
stacked)
KEY
IC Independent-Leg Cantilevered Rig
(cid:204) DP Dynamically Positioned
(cid:204) GOM US Gulf of Mexico
(cid:204)
(cid:204) SP Self Propelled
(cid:204) VC Victory Class
(cid:204) 3M Three Mud Pumps
(cid:204) 4M Four Mud Pumps
15K 15,000 PSI Well Control System
(cid:204) 5M Five Mud Pumps
(cid:204)
(cid:204) 4R Four Ram Blowout Preventer
(cid:204) 5R Five Ram Blowout Preventer
(cid:204) 6R Six Ram Blowout Preventer
(cid:204)
7R Seven Ram Blowout Preventer
JACK-UP RIGS
SEMISUBMERSIBLE RIGS
DRILLSHIPS
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MID-WATER RIGS
(450 – 5,000 Ft.)
DEEPWATER RIGS
(5,000 – 7,500 Ft.)
ULTRA-DEEPWATER RIGS
(7,500+ Ft.)
RATED WATER DEPTH
For semisubmersible rigs and drillships, the indicated
depth reflects the operating water depth capacity for
each drilling unit. In many cases, individual rigs are
capable of achieving, or have achieved, greater water
depths. In all cases, floating rigs are capable of working
successfully at greater depths than their rated water
depth. On a case-by-case basis, a greater depth capacity
may be achieved by providing additional equipment.
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Energy markets have
given no respite for
investors as the collapse
of the price of Brent oil
continued through the
year and into early 2016.
The price per barrel of
crude has fallen by over
40 percent since the
start of 2015, and despite
a modest rebound
from the low, the
economics of deepwater
remain challenged.
In response to market conditions
and the expectation that a price
recovery is not yet on the horizon,
E&P companies have slashed
their capital budgets by more than
20 percent, in aggregate, for a
second consecutive year. The result
across the industry has been a
dramatic shortage of contracting
opportunities for new ultra-
deepwater drillships entering the
market as well as for drilling rigs
rolling off of existing contracts.
LETTER TO
SHAREHOLDERS
Marc Edwards
President and Chief Executive Officer
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At Diamond Offshore,
we have proactively
taken a number
of important steps to
position our
company for the
difficult industry
conditions we face.
CONTRACTS
All of our newbuild ultra-deepwater
drillships have had long-term
contracts in place upon delivery
from the shipyard. Our first unit,
the Ocean BlackHawk, began
operating in the Gulf of Mexico in
May 2014, and in April 2015 it was
joined by the Ocean BlackHornet,
with both rigs working for Anadarko
on five-year terms. In May 2015
the Ocean BlackRhino began its
inaugural contract, which has since
concluded, and it will begin a
new three-year contract with Hess
in Q4 2016. Our fourth and final
newbuild drillship, the Ocean
BlackLion, has recently started
a four-year contract with Hess,
also in the US Gulf of Mexico.
Having all of our drillships working
in the same region creates
economies of scale by having key
personnel and support infrastructure
centrally located here on the Gulf
Coast, near our corporate head-
quarters in Houston. Additionally,
the Gulf of Mexico is one of the
lowest-cost offshore drilling
markets in the world.
Our final newbuild unit, a harsh
environment semisubmersible, the
Ocean GreatWhite, is scheduled for
delivery mid-year 2016, and her
three-year contract with BP will
commence off South Australia in
Q4 2016.
Across the industry, many of
our competitors’ newbuild rigs will
be delivered without immediate
prospects for work. For Diamond
Offshore, however, all of our newbuild
units are contracted at attractive
rates into 2019 and beyond.
COST
CONTROL
While continuing to invest in safety,
equipment maintenance and training,
we are aggressively controlling
costs, including the unfortunate
necessity of reducing the size of our
workforce. We have lowered comp-
ensation across the organization,
cut capex wherever prudent, and
successfully negotiated discounts
with our vendors on capital
equipment. The full economic
benefits of cost reductions are now
positively impacting results.
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CASH
In prior years we built a sizable cash
reserve and increased our revolving
credit facility to 1.5 billion dollars
in anticipation of the capital
obligations associated with our
newbuild program. With only one
remaining shipyard payment,
we have liquidity well in excess of
remaining capital needs.
In February 2015 we announced
that the Board of Directors had
chosen not to declare a special
dividend, which had an impact of
over $400 million per year on capital
flexibility. In February 2016, we
announced the elimination of the
regular quarterly dividend, which
was previously $0.125 per share.
This will add additional liquidity
for the company of $69 million per
year. Given the weakness in industry
fundamentals, we believe it is
prudent to conserve cash, and by
doing so we will improve our
flexibility to take advantage of
strategic opportunities that may
materialize.
Even with Diamond
Offshore’s conservative
financial management
and solid contract
backlog, difficult
market conditions have
taken a toll on 2015
financial results.
During 2015, in response to the
continued deterioration of the
market fundamentals in the oil and
gas industry, we determined that
the carrying values of 17 of our rigs
were impaired, and therefore,
results for full-year 2015 included
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a noncash impairment charge of
$860 million, or $5.05 per share
after tax.
For the year ended December 31,
2015, Diamond Offshore reported
a net loss of $274 million, or a loss of
$2.00 per diluted share, compared
to net income of $387 million,
or $2.81 per diluted share, in 2014.
Revenues for full year 2015 were
$2.419 billion compared to $2.815
billion in 2014.
We have scrapped or sold 13 rigs
since the beginning of 2014; 11 rigs
are currently cold stacked, and we
have classified four jack-up units
as held-for-sale. Additional rigs may
be cold stacked or scrapped before
the market recovers.
The challenging road
ahead for our industry
does not deter
our optimism about
the future of
Diamond Offshore.
Despite the disappointing
financial results for the year, we
accomplished a number of important
achievements. We delivered record
breaking performance as it relates
to both safety and uptime, and our
early efforts to position the company
for a protracted downturn by
reducing costs began to impact the
bottom line.
I am particularly proud that
our organization delivered the
best safety performance in 2015 in
the company’s history, achieving
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a 34 percent improvement on our
normalized safety stats over the
prior year. We have not yet achieved
our target of an injury free work-
place, but the accomplishments of
2015 represent important progress.
Along with working more safely,
we delivered 97 percent operational
efficiency across the entire fleet in
the fourth quarter—which we define
as the percentage of time that
equipment was available to work
without unanticipated downtime.
We continue to look for
innovative ways to further reduce
costs and drive efficiencies for
the benefit of our clients and our
shareholders. This philosophy
is what led to an important
announcement of the industry’s
first subsea Pressure Control by
the Hour™ construct.
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Diamond Offshore has
announced an industry
“first-of-its-kind”
performance-based
service and maintenance
arrangement with
GE for the provision of
pressure control.
GE Oil & Gas, as the original
equipment manufacturer, will now
be a key stakeholder in improving
the availability and performance
of the blowout preventers on
Diamond Offshore’s 6th-generation,
ultra-deepwater drillships—the
Ocean BlackHawk, Ocean
BlackHornet, Ocean BlackRhino
and Ocean BlackLion.
While the cost of deepwater
drilling has come down, we believe
that all stakeholders in the offshore
drilling industry must improve
efficiency. To improve the health of
our industry, we have to help our
clients lower both costs and cycle
times. One of the largest impediments
to delivering the required economic
returns for deepwater projects
today relates to the poor uptime
availability of the BOP.
The new service model, which we
refer to as the Pressure Control
by the Hour model, transfers full
responsibility for maintenance
service, management and supply of
spare parts, equipment upgrades,
continuous certification and data
monitoring back to the original
equipment manufacturer. Under
the arrangement, Diamond Offshore
will pay a dayrate, similar to how
we are paid by our own customers.
If downtime occurs because of the
BOP, GE will not be paid and will
therefore feel the financial impact—
similar to the way the driller and
the operator are affected today.
Under our ten-year agreement,
GE employees will be permanently
stationed on our rigs, but Diamond
will retain operation and control
of the BOP itself. Not only will GE
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maintain the equipment, but they
will buy back Diamond Offshore’s
BOP systems aboard our four
drillships for a total of $210 million.
These performance incentives
will drive further improvement
in deepwater drilling efficiencies by
motivating all parties to prioritize
availability. GE, as the original
equipment manufacturer, will be in
a performance-based alliance that
leverages the scale of their data,
predictive analytics including
condition based monitoring and
maintenance that will proactively
improve the availability of our BOPs.
We will continue to
look for opportunities
to generate long-term
value for shareholders.
In the current down cycle, and the
resulting competitive environment,
we will continue to pursue ways to
differentiate our Company amongst
our peers. Pressure Control by
the Hour is just one example of the
Diamond Difference—a new way of
thinking that will drive continuous
improvement in offshore drilling
and further differentiate Diamond
Offshore’s 6th-generation assets
from the rest of the pack.
While we cannot predict the
timing of market recovery, we do
know with certainty that we are
in a cyclical business and eventually
our clients’ priorities will shift
from reducing spending to growing
deepwater production and reserve
replacement. The industry may look
different in the future, but supply
and demand will eventually come
back into balance. With our
conservative capitalization and
strong liquidity position, we are
confident that the Company will be
able to weather this downturn
and emerge well positioned for the
inevitable rebound. We will
continue to focus on conducting
safe operations, delivering quality
performance for our clients,
rationalizing costs, and utilizing
our capital efficiently.
Marc Edwards
President and Chief Executive Officer
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ..................... to ............................
Commission file number 1-13926
DIAMOND OFFSHORE DRILLING, INC.
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization)
Delaware
76-0321760
(I.R.S. Employer Identification No.)
15415 Katy Freeway
Houston, Texas 77094
(Address and zip code of principal executive offices)
(281) 492-5300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $0.01 par value per share
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes [ (cid:151) ] No[ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of
the Act. Yes [ ] No[ (cid:151) ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90
days.
Yes [ (cid:151) ] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T
during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files).Yes [ (cid:151) ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [(cid:151)]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [(cid:151) ]
Accelerated filer [ ]
Non-accelerated filer [ ]
(Do not check if a smaller reporting company)
Smaller reporting company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [ (cid:151) ]
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by
reference to the price at which the common equity was last sold as of the last business day of the registrant’s most
recently completed second fiscal quarter.
As of June 30, 2015
$1,658,817,269
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest
practicable date.
As of February 16, 2016
Common Stock, $0.01 par value per share
137,158,706 shares
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement relating to the 2016 Annual Meeting of Stockholders of
Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2015, are
incorporated by reference in Part III of this report.
1
DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2015
TABLE OF CONTENTS
Cover Page ............................................................................................................................................................ 1
Document Table of Contents ............................................................................................................................... 2
Page No.
Part I
Item 1. Business ............................................................................................................................................... 3
Item 1A. Risk Factors ........................................................................................................................................ 8
Item 1B. Unresolved Staff Comments ............................................................................................................ 21
Item 2.
Properties .......................................................................................................................................... 21
Item 3. Legal Proceedings ............................................................................................................................. 21
Item 4. Mine Safety Disclosures ................................................................................................................... 21
Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities ............................................................................................. 21
Item 6.
Selected Financial Data .................................................................................................................... 23
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ..... 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ..................................................... 44
Item 8.
Financial Statements and Supplementary Data ............................................................................. 46
Consolidated Financial Statements ..................................................................................................... 48
Notes to Consolidated Financial Statements ...................................................................................... 53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .... 84
Item 9A. Controls and Procedures ................................................................................................................. 84
Item 9B. Other Information ............................................................................................................................ 85
Part III
Certain information called for by Part III Items 10, 11, 12, 13 and 14 has been
omitted as the Registrant intends to file with the Securities and Exchange
Commission not later than 120 days after the end of its fiscal year a definitive Proxy
Statement pursuant to Regulation 14A.
Part IV
Item 15. Exhibits and Financial Statement Schedules ................................................................................. 85
Signatures............................................................................................................................................................ 86
Exhibit Index ...................................................................................................................................................... 88
2
Item 1. Business.
General
PART I
Diamond Offshore Drilling, Inc. is a leader in offshore drilling, providing contract drilling services to the
energy industry around the globe with a fleet of 32 offshore drilling rigs, which includes four jack-up rigs that we
are marketing for sale. Our fleet consists of 23 semisubmersibles, including the Ocean GreatWhite, which is
under construction, five jack-ups and four dynamically positioned drillships, including the Ocean BlackLion
which was delivered in the second quarter of 2015. See “– Our Fleet – Fleet Enhancements and Additions” and “–
Our Fleet – Floater Fleet Status.”
Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our”
mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. Diamond Offshore Drilling, Inc. was
incorporated in Delaware in 1989.
Our Fleet
Our diverse fleet enables us to offer a broad range of services worldwide, primarily in the floater market
(ultra-deepwater, deepwater and mid-water).
Floaters. A floater rig is a type of mobile offshore drilling unit that floats and does not rest on the seafloor.
This asset class includes self-propelled drillships and semisubmersible rigs. Semisubmersible rigs consist of an
upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in
a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately
55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles
hold position while drilling by use of a series of small propulsion units or thrusters that provide dynamic
positioning, or DP, to keep the rig on location, or with anchors tethered to the sea bed. Although DP
semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats.
Non-DP, or moored, semisubmersibles require tug boats or the use of a heavy lift vessel to move between
locations.
A drillship is an adaptation of a maritime vessel that is designed and constructed to carry out drilling
operations by means of a substructure with a moon pool centrally located in the hull. Drillships are typically self-
propelled and are positioned over a drillsite through the use of a DP system similar to those used on
semisubmersible rigs.
Our floater fleet (semisubmersibles and drillships) can be further categorized based on the nominal water
depth for each class of rig as follows:
Category
Ultra-Deepwater
Deepwater
Mid-Water
Rated Water Depth (a)
(in feet)
7,501 to 12,000
5,000 to 7,500
400 to 4,999
Number of Units in Our Fleet
12 (b)
7
8
(a) Rated water depth for semisubmersibles and drillships reflects the maximum water depth in which a
floating rig has been designed to operate. However, individual rigs are capable of drilling, or have
drilled, in marginally greater water depths depending on various conditions (such as salinity of the ocean,
weather and sea conditions).
Includes the Ocean GreatWhite, a harsh environment semisubmersible rig under construction.
(b)
See “ – Fleet Enhancements and Additions” for further discussion of our rig under construction.
3
Floater Fleet Status
The following table presents additional information regarding our floater fleet at February 16, 2016:
Rig Type and Name
ULTRA-DEEPWATER:
Semisubmersibles (8):
Ocean GreatWhite
Ocean Valor
Ocean Courage
Ocean Confidence
Ocean Monarch
Ocean Endeavor
Ocean Rover
Ocean Baroness
Drillships (4):
Ocean BlackLion
Rated Water
Depth
(in feet)
Attributes
Year Built/
Redelivered (a)
Current Location (b)
Customer (c)
10,000
10,000
10,000
10,000
10,000
10,000
8,000
8,000
DP; 6R; 15K
DP; 6R; 15K
DP; 6R; 15K
DP; 6R; 15K
15K
15K
15K
15K
Q2 2016
2009
2009
2001/Q2 2015
2008
2007
2003
2002
South Korea
Brazil
Brazil
Canary Islands
Australia
Romania
Malaysia
GOM
Under construction/BP (d)
Petrobras
Petrobras
Cold stacked
Quadrant Energy
Demobilizing/Actively Marketing
Murphy Exploration
Cold Stacked
12,000
DP; 7R; 15K
Q2 2015
GOM
Ocean BlackRhino
12,000
DP; 7R; 15K
Ocean BlackHornet
Ocean BlackHawk
DEEPWATER:
Semisubmersibles (7):
Ocean Apex
Ocean Onyx
Ocean Victory
Ocean America
Ocean Valiant
Ocean Star
Ocean Alliance
MID-WATER:
Semisubmersibles (8):
Ocean Quest
Ocean Patriot
Ocean General
Ocean Guardian
Ocean Princess
Ocean Vanguard
Ocean Nomad
Ocean Ambassador
12,000
12,000
DP; 7R; 15K
DP; 7R; 15K
15K
15K
15K
15K
15K
15K
DP; 15K
15K
15K
15K
15K
15K
6,000
6,000
5,500
5,500
5,500
5,500
5,250
4,000
3,000
3,000
1,500
1,500
1,500
1,200
1,100
2014
2014
2014
2014
2013
1997
1988
1988
1997
1988
1973
1983
1976
1985
1975
1982
1975
1975
GOM
GOM
GOM
Customer acceptance/Hess
Corporation
Contract preparation/Hess
Corporation
Anadarko
Anadarko
Malaysia
GOM
Trinidad & Tobago
Malaysia
North Sea/U.K.
GOM
GOM
Warm Stacked/Woodside
Cold Stacked
BP Trinidad
Cold Stacked
Premier Oil
Cold Stacked
Cold Stacked
Malaysia
North Sea/U.K.
Malaysia
North Sea/U.K.
North Sea/U.K.
North Sea/U.K.
North Sea/U.K.
Mexico
Cold Stacked
Shell
Cold Stacked
Warm Stacked/Dana
Cold Stacked
Cold stacked
Cold Stacked
PEMEX
DP
6R
= Dynamically Positioned/Self-Propelled 7R =
2 Seven ram blow out preventers
= Six ram blow out preventer
15K =
15,000 psi well control system
Attributes
(a) Represents year rig was (or is expected to be) built and originally placed in service or year rig was (or is
expected to be) redelivered with significant enhancements that enabled the rig to be classified within a different
floater category than originally constructed.
(b) GOM means U.S. Gulf of Mexico.
(c) For ease of presentation in this table, customer names have been shortened or abbreviated.
(d) Rig is contracted for future work upon completion of construction and commissioning.
Jack-ups. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the
ocean floor. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit in
which a particular rig is able to operate is principally determined by the length of the rig’s legs. The rig hull
includes the drilling equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for
bulk and liquid materials, heliport and other related equipment. A jack-up rig is towed to the drillsite with its hull
riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the
seabed and jacking continues with the legs penetrating the seabed until they are firm and stable, and resistance is
sufficient to elevate the hull above the surface of the water. After completion of drilling operations, the hull is
lowered until it rests in the water and then the legs are retracted for relocation to another drillsite. All of our jack-
up rigs are equipped with a cantilever system that enables the rig to cantilever or extend its drilling package over
the aft end of the rig.
4
As of February 16, 2016, the Ocean Scepter, a 350-foot jack-up drilling rig built in 2008, was operating
offshore Mexico for PEMEX (cid:16) Exploración y Producción, or PEMEX, under a long-term contract. In addition,
we have four other jack-up rigs, which we are currently marketing for sale.
Fleet Enhancements and Additions. Our long-term strategy is to upgrade our fleet to meet customer demand
for advanced, efficient and high-tech rigs by acquiring or building new rigs when possible to do so at attractive
prices, and otherwise by enhancing the capabilities of our existing rigs at a lower cost and shortened construction
period than newbuild construction would require. Since 2009, commencing with the acquisition of two newbuild,
ultra-deepwater semisubmersible rigs, the Ocean Courage and Ocean Valor, we have committed over $5.0 billion
towards upgrading our fleet. In mid-2015, we took delivery of the Ocean BlackLion, the last of four ultra-
deepwater drillships constructed in South Korea during our most recent fleet enhancement cycle. The Ocean
GreatWhite remains under construction in South Korea with delivery of the new rig expected to occur in mid-
2016. Upon completion of acceptance testing, the rig is expected to commence drilling operations offshore
Australia later this year.
We will evaluate further rig acquisition and enhancement opportunities as they arise. However, we can
provide no assurance whether, or to what extent, we will continue to make rig acquisitions or enhancements to our
fleet. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cash
Flow and Capital Expenditures” in Item 7 of this report.
Pressure Control by the Hour. In February 2016, we entered into a ten-year agreement with GE Oil & Gas,
or GE, to provide services with respect to certain blowout preventer and related well control equipment on our
four newbuild drillships. Such services include management of maintenance, certification and reliability with
respect to such equipment. In connection with the services agreement with GE, we will sell the equipment to a
GE affiliate and will lease back such equipment over separate ten-year operating leases.
Markets
The principal markets for our offshore contract drilling services are the following:
the Middle East;
(cid:120) South America, principally offshore Brazil, and Trinidad and Tobago;
(cid:120) Australia and Southeast Asia, including Malaysia, Indonesia and Vietnam;
(cid:120)
(cid:120) Europe, principally in the United Kingdom, or U.K., and Norway;
(cid:120) East and West Africa;
(cid:120)
the Mediterranean; and
(cid:120)
the Gulf of Mexico, including the U.S. and Mexico.
We actively market our rigs worldwide. From time to time our fleet operates in various other markets
throughout the world. See Note 17 “Segments and Geographic Area Analysis” to our Consolidated Financial
Statements in Item 8 of this report.
Offshore Contract Drilling Services
Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our
contracts through a competitive bid process, although it is not unusual for us to be awarded drilling contracts
following direct negotiations. Our drilling contracts generally provide for a basic fixed dayrate regardless of
whether or not such drilling results in a productive well. Drilling contracts may also provide for reductions in
rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by
equipment breakdowns, adverse weather conditions or other circumstances. Under dayrate contracts, we
generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically,
dayrate contracts have accounted for the majority of our revenues. In addition, from time to time, our dayrate
contracts may also provide for the ability to earn an incentive bonus from our customer based upon performance.
The duration of a dayrate drilling contract is generally tied to the time required to drill a single well or a
group of wells, in what we refer to as a well-to-well contract, or a fixed period of time, in what we refer to as a
term contract. Many drilling contracts may be terminated by the customer in the event the drilling unit is
destroyed or lost, or if drilling operations are suspended for an extended period of time as a result of a breakdown
of equipment or, in some cases, due to events beyond the control of either party to the contract. Certain of our
contracts also permit the customer to terminate the contract early by giving notice; in most circumstances this
5
requires the payment of an early termination fee by the customer. The contract term in many instances may also
be extended by the customer exercising options for the drilling of additional wells or for an additional length of
time, generally at competitive market rates and mutually agreeable terms at the time of the extension. In periods
of decreasing demand for offshore rigs, drilling contractors may prefer longer term contracts to preserve dayrates
at existing levels and ensure utilization, while customers may prefer shorter contracts that allow them to more
quickly obtain the benefit of declining dayrates. Moreover, drilling contractors may accept lower dayrates in a
declining market in order to obtain longer-term contracts and add backlog. See “Risk Factors – We may not be
able to renew or replace expiring contracts for our rigs,” “Risk Factors – Our business involves numerous
operating hazards that could expose us to significant losses and significant damage claims. We are not fully
insured against all of these risks and our contractual indemnity provisions may not fully protect us,” “Risk
Factors – We can provide no assurance that our drilling contracts will not be terminated early or that our current
backlog of contract drilling revenue will be ultimately realized,” “Risk Factors – We may enter into drilling
contracts that expose us to greater risks than we normally assume” and “Risk Factors – We self-insure for
physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico” in Item 1A of
this report, which are incorporated herein by reference. For a discussion of our contract backlog, see
“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Overview –
Contract Drilling Backlog” in Item 7 of this report, which is incorporated herein by reference.
Customers
We provide offshore drilling services to a customer base that includes major and independent oil and gas
companies and government-owned oil companies. During 2015, 2014 and 2013, we performed services for 19, 35
and 39 different customers, respectively. During 2015, 2014 and 2013, one of our customers in Brazil, Petróleo
Brasileiro S.A., or Petrobras (a Brazilian multinational energy company that is majority-owned by the Brazilian
government), accounted for 24%, 32% and 34% of our annual total consolidated revenues, respectively. During
2015, ExxonMobil and Anadarko each accounted for 12% of our annual consolidated revenues. No other
customer accounted for 10% or more of our annual total consolidated revenues during 2015, 2014 or 2013. See
“Risk Factors — Our industry is highly competitive, with oversupply and intense price competition” in Item 1A of
this report, which is incorporated herein by reference.
As of February 8, 2016, our contract backlog was $5.2 billion attributable to 11 customers. All four of our
drillships are currently contracted to work in the GOM. As of February 8, 2016, contract backlog attributable to
our expected operations in the GOM was $510.0 million, $653.0 million and $653.0 million for the years 2016,
2017 and 2018, respectively, and $626.0 million in the aggregate for the years 2019 to 2020 attributable to three
customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Market Overview – Contract Drilling Backlog” in Item 7 of this report. See “Risk Factors — We can provide no
assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling
revenue will be ultimately realized” in Item 1A of this report, which is incorporated herein by reference.
Competition
Despite consolidation in previous years, the offshore contract drilling industry remains highly competitive
with numerous industry participants, none of which at the present time has a dominant market share. The industry
may also experience additional consolidation in the future, which could create other large competitors. Some of
our competitors may have greater financial or other resources than we do. Based on industry data, as of the date
of this report, there are approximately 840 mobile drilling rigs in service worldwide, including approximately 300
floater rigs.
The offshore contract drilling industry is influenced by a number of factors, including global economies and
demand for oil and natural gas, current and anticipated prices of oil and natural gas, expenditures by oil and gas
companies for exploration and development of oil and natural gas and the availability of drilling rigs.
Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in
determining which qualified contractor is awarded a job. Customers may also consider rig availability and
location, a drilling contractor’s operational and safety performance record, and condition and suitability of
equipment. We believe we compete favorably with respect to these factors.
We compete on a worldwide basis, but competition may vary significantly by region at any particular time.
See “—Markets.” Competition for offshore rigs generally takes place on a global basis, as these rigs are highly
mobile and may be moved, at a cost that may be substantial, from one region to another. It is characteristic of the
6
offshore contract drilling industry to move rigs from areas of low utilization and dayrates to areas of greater
activity and relatively higher dayrates. Significant new rig construction and upgrades of existing drilling units
could also intensify price competition. See “Risk Factors – Our industry is highly competitive, with oversupply
and intense price competition” in Item 1A of this report, which is incorporated herein by reference.
Governmental Regulation
Our operations are subject to numerous international, foreign, U.S., state and local laws and regulations that
relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the
environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of
the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy
use. See “Risk Factors – Governmental laws and regulations, both domestic and international, may add to our
costs or limit our drilling activity” and “Risk Factors – Compliance with or breach of environmental laws can be
costly and could limit our operations” in Item 1A of this report, which are incorporated herein by reference.
Operations Outside the United States
Our operations outside the U.S. accounted for approximately 79%, 85% and 89% of our total consolidated
revenues for the years ended December 31, 2015, 2014 and 2013, respectively. See “Risk Factors – Significant
portions of our operations are conducted outside the United States and involve additional risks not associated
with United States domestic operations,” “Risk Factors – We may enter into drilling contracts that expose us to
greater risks than we normally assume,” “Risk Factors – We may be required to accrue additional tax liability on
certain of our foreign earnings” and “Risk Factors – Fluctuations in exchange rates and nonconvertibility of
currencies could result in losses to us” in Item 1A of this report, which are incorporated herein by reference.
Employees
As of December 31, 2015, we had approximately 3,400 workers, including international crew personnel
furnished through independent labor contractors.
Executive Officers of the Registrant
We have included information on our executive officers in Part I of this report in reliance on General
Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors to serve
until the next annual meeting of our Board of Directors, or until their successors are duly elected and qualified, or
until their earlier death, resignation, disqualification or removal from office. Information with respect to our
executive officers is set forth below.
Name
Marc Edwards
Lyndol L. Dew
Gary T. Krenek
David L. Roland
Ronald Woll
Beth G. Gordon
Age as of
January 31, 2016
55
61
57
54
48
60
Position
President and Chief Executive Officer and Director
Senior Vice President – Worldwide Operations
Senior Vice President and Chief Financial Officer
Senior Vice President, General Counsel and Secretary
Senior Vice President and Chief Commercial Officer
Controller and Chief Accounting Officer
Marc Edwards has served as our President and Chief Executive Officer and as a Director since March 2014.
Mr. Edwards previously served as a member of the Executive Committee and as Senior Vice President of the
Completion and Production Division at Halliburton Company, a global diversified oilfield services company,
from January 2010 to February 2014. Mr. Edwards also served as Vice President for Production Enhancement of
Halliburton Company from January 2008 through December 2009.
Lyndol L. Dew has served as our Senior Vice President – Worldwide Operations since September 2006.
Previously, Mr. Dew served as our Vice President – International Operations from January 2006 to August 2006
and as our Vice President – North American Operations from January 2003 to December 2005.
Gary T. Krenek has served as our Senior Vice President and our Chief Financial Officer since October 2006.
From March 1998 to 2006, Mr. Krenek served as our Vice President and Chief Financial Officer.
7
David L. Roland has served as our Senior Vice President, General Counsel and Secretary since September
2014. From April 2004 until joining us in 2014, Mr. Roland served as Senior Vice President, General Counsel
and Corporate Secretary of ION Geophysical Corporation, a NYSE-listed geophysical company.
Ronald Woll has served as our Senior Vice President and Chief Commercial Officer since June 2014. Mr.
Woll previously served as Senior Vice President Supply Chain at Halliburton Company, a global diversified
oilfield services company, from January 2011 through June 2014. From January 2010 through December 2011,
Mr. Woll served as Vice President, Procurement at Halliburton Company.
Beth G. Gordon has served as our Controller and Chief Accounting Officer since April 2000.
Access to Company Filings
We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the
Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy
statements and other information with the United States Securities and Exchange Commission, or SEC. You may
read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 100
F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the
operation of the public reference room. Our SEC filings are also available to the public from the SEC’s Internet
site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to
a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably
practicable after we have electronically filed such material with, or furnished it to, the SEC. The preceding
Internet addresses and all other Internet addresses referenced in this report are for information purposes only and
are not intended to be a hyperlink. Accordingly, no information found or provided at such Internet addresses or at
our website in general (or at other websites linked to our website) is intended or deemed to be incorporated by
reference in this report.
Item 1A. Risk Factors.
Our business is subject to a variety of risks, including the risks described below. You should carefully
consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the
only ones facing our company. We are also subject to a variety of risks that affect many other companies
generally, as well as additional risks and uncertainties not known to us or that, as of the date of this report, we
believe are not as significant as the risks described below. If any of the following risks actually occur, our
business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be
materially and adversely affected.
The worldwide demand for drilling services has declined significantly as a result of the decline in oil prices,
which commenced during the second half of 2014 and has continued into 2016.
Demand for our drilling services depends in large part upon oil and natural gas industry offshore exploration
and production activity and expenditure levels, which are directly affected by oil and gas prices and market
expectations of potential changes in oil and gas prices. Commencing in the second half of 2014, oil prices have
declined precipitously and recently fell to a 12-year low of less than $30 per barrel. The dramatic reduction in
commodity prices has caused a sharp decline in the demand for offshore drilling services, including services that
we provide and adversely affected our results of operations and cash flows in 2015. A prolonged period of low oil
prices would have a material adverse effect on many of our customers and, therefore, on our financial condition,
results of operations and cash flows.
Oil prices have been, and are expected to continue to be, volatile and are affected by numerous factors beyond
our control, including:
(cid:120) worldwide supply and demand for oil and gas;
(cid:120)
(cid:120)
(cid:120)
the level of economic activity in energy-consuming markets;
the worldwide economic environment or economic trends, such as recessions;
the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain
production levels and pricing;
the level of production in non-OPEC countries;
civil unrest and the worldwide political and military environment, including uncertainty or instability
resulting from an escalation or additional outbreak of armed hostilities involving the Middle East,
(cid:120)
(cid:120)
8
Russia, other oil-producing regions or other geographic areas or further acts of terrorism in the United
States or elsewhere;
the cost of exploring for, developing, producing and delivering oil and gas;
the discovery rate of new oil and gas reserves;
the rate of decline of existing and new oil and gas reserves and production;
available pipeline and other oil and gas transportation and refining capacity;
the ability of oil and gas companies to raise capital;
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120) weather conditions, including hurricanes, which can affect oil and gas operations over a wide area;
(cid:120)
natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil
spills;
the policies of various governments regarding exploration and development of their oil and gas
reserves;
technological advances affecting energy consumption, including development and exploitation of
alternative fuels or energy sources;
laws and regulations relating to environmental or energy security matters, including those purporting
to address global climate change;
domestic and foreign tax policy; and
advances in exploration and development technology.
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
An increase in commodity demand and prices will not necessarily result in an immediate increase in offshore
drilling activity since our customers’ project development times, reserve replacement needs and expectations of
future commodity demand, prices and supply of available competing rigs all combine to affect demand for our
rigs.
Our business depends on the level of activity in the offshore oil and gas industry, which has been cyclical and
is significantly affected by many factors outside of our control.
Demand for our drilling services depends upon the level of offshore oil and gas exploration, development and
production in markets worldwide, and those activities depend in large part on oil and gas prices, worldwide
demand for oil and gas and a variety of political and economic factors. The level of offshore drilling activity is
also adversely affected when operators reduce or defer new investment in offshore projects, reduce or suspend
their drilling budgets or reallocate their drilling budgets away from offshore drilling in favor of other priorities,
such as shale or other land-based projects, which could reduce demand for our rigs and newbuilds. As a result,
our business and the oil and gas industry in general are subject to cyclical fluctuations.
As a result of the cyclical fluctuations in the market, there have been periods of lower demand, excess rig
supply and lower dayrates, followed by periods of higher demand, shorter rig supply and higher dayrates. We
cannot predict the timing or duration of such fluctuations. Periods of lower demand or excess rig supply intensify
the competition in the industry and often result in periods of lower utilization and lower dayrates. During these
periods, our rigs may not obtain contracts for future work and may be idle for long periods of time or may be able
to obtain work only under contracts with lower dayrates or less favorable terms, which could have a material
adverse effect on our financial condition, results of operations and cash flows during these periods. Additionally,
prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on
certain of our drilling rigs if future cash flow estimates, based upon information available to management at the
time, indicate that the carrying value of these rigs may not be recoverable. See “–We may incur additional asset
impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.”
Our industry is highly competitive, with oversupply and intense price competition.
The offshore contract drilling industry is highly competitive with numerous industry participants. Some of
our competitors may be larger companies, have larger or more technologically advanced fleets and have greater
financial or other resources than we do. The drilling industry has experienced consolidation in the past and may
experience additional consolidation, which could create additional large competitors. Drilling contracts are
traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which
qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record
and the quality and technical capability of service and equipment may also be considered.
Recent new rig construction and upgrades of existing drilling rigs, cancelation or termination of contracts, as
well as established rigs coming off contract during 2015, have contributed to the current oversupply of drilling
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rigs, intensifying price competition. Additional newbuild rigs entering the market are expected to further
negatively impact rig utilization and intensify price competition as rigs are delivered. See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations – Market Overview -- Floater
Markets” in Item 7 of this report.
We provide offshore drilling services to a customer base that includes major and independent oil and gas
companies and government-owned oil companies. During 2015, one of our customers in Brazil, Petrobras, and
our five largest customers in the aggregate accounted for 24% and 65%, respectively, of our annual total
consolidated revenues. The loss of a significant customer could have a material adverse impact on our financial
condition, results of operations and cash flows, especially in a declining market where the number of our working
drilling rigs is declining along with the number of our active customers. In addition, if a significant customer
experiences liquidity constraints or other financial difficulties, it could materially adversely affect our utilization
rates in the affected market and also displace demand for our other drilling rigs and newbuilds as the resulting
excess supply enters the market. While it is normal for our customer base to change over time as work programs
are completed, the loss of, or a significant reduction in the number of rigs contracted with, any major customer
may have a material adverse effect on our financial condition, results of operations and cash flows. See
“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Overview –
Contract Drilling Backlog” in Item 7 of this report.
We can provide no assurance that our drilling contracts will not be terminated early or that our current
backlog of contract drilling revenue will be ultimately realized.
Generally, our customers may terminate our drilling contracts under certain circumstances, such as if the
drilling rig is destroyed or lost, if we suspend drilling operations for a specified period of time as a result of a
breakdown of major equipment, excessive downtime for repairs, failure to meet minimum performance criteria
(including customer acceptance testing) or, in some cases, due to other events beyond the control of either party.
Our drilling contract for the Ocean BlackLion, for example, requires us to successfully complete certain testing
procedures for the rig’s equipment, including the blowout preventers and well control systems. We are currently
undergoing the required testing. If these tests are not successfully completed, our customer may have the right to
terminate the drilling contract or may request a renegotiation of the terms of the contract.
In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice
periods, often by tendering contractually specified termination amounts, which may not fully compensate us for
the loss of the contract. During depressed market conditions, certain customers have utilized such contract clauses
to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling
contracts in order to avoid their obligations to us under circumstances where we believe we are in compliance
with the contracts. Additionally, because of depressed commodity prices, restricted credit markets, economic
downturns, changes in priorities or strategy or other factors beyond our control, a customer may no longer want or
need a rig that is currently under contract or may be able to obtain a comparable rig at a lower dayrate. For these
reasons, customers may seek to renegotiate the terms of our existing drilling contracts, terminate our contracts
without justification or repudiate or otherwise fail to perform their obligations under our contracts. Such
renegotiations could include requests to lower the contract dayrate, lowering of a dayrate in exchange for
additional contract term, shortening the term on one contracted rig in exchange for additional term on another rig,
early termination of a contract in exchange for a lump sum margin payout and many other possibilities. Our
contract backlog may be adversely impacted as a result of such contract renegotiations.
When a customer terminates our contract prior to the contract’s scheduled expiration, our contract backlog is
adversely impacted, and we might not recover any compensation for the termination or any recovery we might
obtain may not fully compensate us for the loss of the contract. In any case, the early termination of a contract
may result in our rig being idle for an extended period of time. Each of these results could have a material adverse
effect on our financial condition, results of operations and cash flows. In addition, if our customer cancels our
contract or if we elect to terminate a contract due to the customer’s nonperformance and in either case we are
unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is disputed or
suspended for an extended period of time or if a contract is renegotiated, it could materially and adversely affect
our financial condition, results of operations and cash flows.
Currently, our contract backlog only includes future revenues under firm commitments; however, from time
to time, we may report anticipated commitments for which definitive agreements have not yet been, but are
expected to be, executed. We can provide no assurance that in such cases we will be able to ultimately execute a
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definitive agreement. In addition, for the reasons described above, we can provide no assurance that our
customers will be willing or able to fulfill their contractual commitments to us.
Our inability to perform under our contractual obligations or to execute definitive agreements, or our
customers’ inability or unwillingness to fulfill their contractual commitments to us, may have a material adverse
effect on our financial condition, results of operations and cash flows. See “– Our industry is highly competitive,
with oversupply and intense price competition” and “Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Market Overview – Contract Drilling Backlog” in Item 7 of this report.
We may not be able to renew or replace expiring contracts for our rigs.
We have a number of customer contracts that will expire in 2016 and 2017. Our ability to renew or replace
expiring contracts or obtain new contracts, and the terms of any such contracts, will depend on various factors,
including market conditions and the specific needs of our customers. Given the highly competitive and historically
cyclical nature of our industry, we may not be able to renew or replace the contracts or we may be required to
renew or replace expiring contracts or obtain new contracts at dayrates that are below, and potentially
substantially below, existing dayrates, or that have terms that are less favorable to us than our existing contracts or
we may be unable to secure contracts for these rigs. This could have a material adverse effect on our financial
condition, results of operations and cash flows.
We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain
offshore drilling rigs.
The current oversupply of drilling rigs in the offshore drilling market has resulted in numerous rigs being
idled and in some cases retired and/or scrapped. We evaluate our property and equipment for impairment
whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable, and we
could incur impairment charges related to the carrying value of our drilling rigs. Impairment write-offs could
result if, for example, any of our rigs become obsolete or commercially less desirable or their carrying values
become excessive due to the condition of the rig, cold stacking the rig, the expectation of cold stacking the rig in
the near future, a decision to retire or scrap the rig, changes in technology, market demand or market expectations,
or excess spending over budget on a new-build construction project or major rig upgrade. We utilize an
undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment, reflecting
management’s assumptions and estimates regarding the appropriate risk-adjusted dayrate by rig, future industry
conditions and operations and other factors. Asset impairment evaluations are, by their nature, highly subjective.
The use of different estimates and assumptions could result in materially different carrying values of our assets,
which could impact the need to record an impairment charge and the amount of any charge taken. Since 2012, we
have retired and sold 12 drilling rigs and recorded impairment losses aggregating $1.0 billion, including $860.4
million recognized in 2015. See “Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Market Overview – Critical Accounting Estimates – Property, Plant and Equipment” in Item 7 of
this report and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.
We can provide no assurance that our assumptions and estimates used in our asset impairment evaluations
will ultimately be realized or that the current carrying value of our property and equipment, including rigs
designated as held for sale, will ultimately be realized.
Our contract drilling expense includes fixed costs that will not decline in proportion to decreases in rig
utilization and dayrates.
Our contract drilling expense includes all direct and indirect costs associated with the operation, maintenance
and support of our drilling equipment, which is often not affected by changes in dayrates and utilization. During
periods of reduced revenue and/or activity, certain of our fixed costs will not decline and often we may incur
additional operating costs, such as fuel and catering costs, for which we are generally reimbursed by the customer
when a rig is under contract. During times of reduced utilization, reductions in costs may not be immediate as we
may incur additional costs associated with cold stacking a rig (particularly if we cold stack a newer rig, such as a
drillship, for which cold-stacking costs are typically substantially higher than for a jack-up rig or an older floater
rig), or we may not be able to fully reduce the cost of our support operations in a particular geographic region due
to the need to support the remaining drilling rigs in that region. A decline in revenue due to lower dayrates and/or
utilization may not be offset by a corresponding decrease in contract drilling expense and could have a material
adverse effect on our financial condition, results of operations and cash flows.
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Although we have paid cash dividends in the past, we may not pay regular or special cash dividends in the
future and we can give no assurance as to the amount or timing of the payment of any future regular or special
cash dividends.
We pay dividends at the discretion of our Board of Directors, or Board. In recent years, we have paid both
regular quarterly and special cash dividends, although we did not pay special cash dividends in 2015. In February
2016, we announced that we had discontinued our regular quarterly cash dividend. Our Board has adopted a
policy of considering regular and special cash dividends, in amounts to be determined, on a quarterly basis. Any
determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on
the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on
current and future market conditions and business needs and other factors that our Board considers relevant at that
time. The Board’s dividend policy may change from time to time, but there can be no assurance that we will
declare any cash dividends at all or in any particular amounts. See “Market for the Registrant’s Common Equity,
Related Stockholder Matters and Issuer Purchases of Equity Securities – Dividend Policy” in Item 5 of this report
and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and
Capital Resources” in Item 7 of this report.
We may enter into drilling contracts that expose us to greater risks than we normally assume.
From time to time, we may enter into drilling contracts with national oil companies, government-controlled
entities or others that expose us to greater risks than we normally assume, such as exposure to greater
environmental or other liability and more onerous termination provisions giving the customer a right to terminate
without cause or upon little or no notice. Upon termination, these contracts may not result in a payment to us, or
if a termination payment is required, it may not fully compensate us for the loss of a contract. In addition, the
early termination of a contract may result in a rig being idle for an extended period of time, which could adversely
affect our financial condition, results of operations and cash flows. While we believe that the financial terms of
these contracts and our operating safeguards in place may partially mitigate these risks, we can provide no
assurance that the increased risk exposure will not have a material negative impact on our future operations or
financial results.
Changes in tax laws, effective income tax rates or adverse outcomes resulting from examination of our tax
returns could adversely affect our financial results.
Tax laws and regulations are highly complex and subject to interpretation and disputes. We conduct our
worldwide operations through various subsidiaries in a number of countries throughout the world. As a result, we
are subject to highly complex tax laws, regulations and income tax treaties within and between the countries in
which we operate as well as countries in which we may be resident, which may change and are subject to
interpretation. We determine our income tax expense based on our interpretation of the applicable tax laws and
regulations in effect in each jurisdiction for the period during which we operate and earn income. Our overall
effective tax rate could be adversely and suddenly affected by lower than anticipated earnings in countries where
we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory
rates, by changes in the valuation of our deferred tax assets and liabilities or by changes in tax law, tax treaties,
regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In
addition, changes in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may
put us at risk for future tax assessments and liabilities which could be substantial and could have a material
adverse effect on our financial condition, results of operations and cash flows.
Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax
positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax
authority successfully challenges any tax position taken or intercompany pricing policies, or if the terms of certain
income tax treaties are interpreted in a manner that is adverse to us or our operations, or if we lose a material tax
dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our
earnings and cash flows from operations could be materially adversely affected.
Governmental laws and regulations, both domestic and international, may add to our costs or limit our drilling
activity.
Our operations are affected from time to time in varying degrees by governmental laws and regulations. In
addition to the specific regulatory risks discussed elsewhere in this Item 1A. “Risk Factors” section, our
operations are subject to other laws, regulations and government policies worldwide. Certain countries are subject
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to restrictions, sanctions and embargoes imposed by the United States government or other governmental or
international authorities. These restrictions, sanctions and embargoes may prohibit or limit us from participating in
certain business activities in those countries. Our operations are also subject to numerous local, state and federal
laws and regulations in the United States and in foreign jurisdictions concerning the containment and disposal of
hazardous materials, the remediation of contaminated properties and the protection of the environment. The
offshore drilling industry is dependent on demand for services from the oil and gas exploration industry and,
accordingly, can be affected by changes in tax and other laws relating to the energy business generally. We may
be required to make significant expenditures for additional capital equipment or inspections and recertifications
thereof to comply with existing or new governmental laws and regulations. It is also possible that these laws and
regulations may in the future add significantly to our operating costs or result in a reduction in revenues associated
with downtime required to install such equipment or may otherwise significantly limit drilling activity.
In addition, our operating income is negatively impacted when we perform certain regulatory inspections,
which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. These
special surveys are generally performed in a shipyard and require scheduled downtime, which can negatively
impact operating revenue. Operating expenses increase as a result of these special surveys due to the cost to
mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and
maintenance activities may result from the special survey or may have been previously planned to take place
during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as
well as from quarter to quarter. Operating income may also be negatively impacted by intermediate surveys,
which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive
in duration and scope than a 5-year survey. Although an intermediate survey normally does not require shipyard
time, the survey may require some downtime for the rig. We can provide no assurance as to the exact timing
and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard
projects.
In the aftermath of the 2010 Macondo well blowout and subsequent investigation into the causes of the event,
new rules were implemented for oil and gas operations in the GOM and in many of the international locations in
which we operate, including new standards for well design, casing and cementing and well control procedures,
equipment inspection and certifications, as well as rules requiring operators to systematically identify risks and
establish safeguards against those risks through a comprehensive safety and environmental management system,
or SEMS. New regulations may continue to be announced, including rules regarding drilling systems and
equipment, such as blowout preventer and well control systems and lifesaving systems, as well as rules regarding
employee training, engaging personnel in safety management and requiring third party audits of SEMS programs.
Such new regulations could require modifications or enhancements to existing systems and equipment, or require
new equipment, and could increase our operating costs and cause downtime for our rigs if we are required to take
any of them out of service between scheduled surveys or inspections, or if we are required to extend scheduled
surveys or inspections, to meet any such new requirements. We are not able to predict the likelihood, nature or
extent of additional rulemaking, and we are not able to predict the future impact of these events on our operations.
Additional governmental regulations concerning
training
requirements or other matters could increase the costs of our operations, and enhanced permitting requirements, as
well as escalating costs borne by our customers, could reduce exploration activity in the GOM and therefore
demand for our services.
taxation, equipment specifications,
licensing,
Governments in some countries are increasingly active in regulating and controlling the ownership of
concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of
existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental
drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our
operations by limiting drilling opportunities.
Governments around the world are also increasingly considering and adopting laws and regulations to address
climate change issues. Lawmakers and regulators in the United States and other jurisdictions where we operate
have focused increasingly on restricting the emission of carbon dioxide, methane and other “greenhouse” gases.
This may result in new environmental regulations that may unfavorably impact us, our suppliers and our
customers. We may be exposed to risks related to new laws, regulations, treaties or international agreements
pertaining to climate change, greenhouse gases, carbon emissions or energy use that could decrease the use of oil
or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also
pass laws or regulations incentivizing or mandating the use of alternative energy sources, such as wind power and
solar energy, which may reduce demand for oil and natural gas and our drilling services. Such laws, regulations,
treaties or international agreements could result in increased compliance costs or additional operating restrictions,
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which may have a negative impact on our business, and could adversely affect our operations by limiting drilling
opportunities.
Contracts for our drilling rigs are generally fixed dayrate contracts, and increases in our operating costs could
adversely affect our profitability on those contracts.
Our contracts for our drilling rigs generally provide for the payment of a fixed dayrate per rig operating day,
although some contracts do provide for a limited escalation in dayrate due to increased operating costs we incur
on the project. Many of our operating costs, such as labor costs, are unpredictable and fluctuate based on events
beyond our control. In addition, equipment repair and maintenance expenses fluctuate depending on the type of
activity the rig is performing, the age and condition of the equipment and general market factors impacting
relevant parts, components and services. The gross margin that we realize on these fixed dayrate contracts will
fluctuate based on variations in our operating costs over the terms of the contracts. In addition, for contracts with
dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers.
Our inability to recover these increased or unforeseen costs from our customers could materially and adversely
affect our financial condition, results of operations and cash flows.
Rig conversions, upgrades or new-builds may be subject to delays and cost overruns.
From time to time, we add new capacity through conversions or upgrades to our existing rigs or through new
construction, such as our harsh environment, ultra-deepwater semisubmersible rig, Ocean GreatWhite, which is
currently under construction. Projects of this type are subject to risks of delay or cost overruns inherent in any
large construction project resulting from numerous factors, including the following:
shortages of equipment, materials or skilled labor;
unscheduled delays in the delivery of ordered materials and equipment;
unanticipated cost increases or change orders;
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difficulties in obtaining necessary permits or in meeting permit conditions;
design and engineering problems;
disputes with shipyards or suppliers;
availability of suppliers to recertify equipment for enhanced regulations;
customer acceptance delays;
shipyard failures or unavailability; and
failure or delay of third party service providers, civil unrest and labor disputes.
Failure to complete a rig upgrade or new construction on time, or failure to complete a rig conversion or new
construction in accordance with its design specifications may, in some circumstances, result in the delay,
renegotiation or cancellation of a drilling contract, resulting in a loss of contract drilling backlog and revenue to
us. If a drilling contract is terminated under these circumstances, we may not be able to secure a replacement
contract or, if we do secure a replacement contract, it may not contain equally favorable terms. In addition,
impairment write-offs could result if a rig’s carrying value becomes excessive due to spending over budget on a
newbuild construction project or major rig upgrade.
Our business involves numerous operating hazards that could expose us to significant losses and significant
damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may
not fully protect us.
Our operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as
blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and
natural disasters such as hurricanes. The occurrence of any of these types of events could result in the suspension of
drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage
to producing or potentially productive oil and gas formations, and oil spillage, oil leaks, well blowouts and extensive
uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling
operations are subject to marine hazards, including capsizing, grounding, collision and loss or damage from severe
weather. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure
of suppliers or subcontractors to perform or supply goods or services or personnel shortages. Any of the foregoing
events could result in significant damage or loss to our properties and assets or the properties and assets of others,
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injury or death to rig personnel or others, significant loss of revenues and significant damage claims against us,
which could have a material adverse effect on our results of operations, financial condition and cash flows.
Our drilling contracts with our customers provide for varying levels of indemnity and allocation of liabilities
between our customers and us with respect to the hazards and risks inherent in, and damages or losses arising out of,
our operations, and we may not be fully protected. Our contracts with our customers generally provide that we and
our customers each assume liability for our respective personnel and property. Our contracts also generally provide
that our customers assume most of the responsibility for and indemnify us against loss, damage or other liability
resulting from, among other hazards and risks, pollution originating from the well and subsurface damage or loss,
while we typically retain responsibility for and indemnify our customers against pollution originating from the rig.
However, in certain drilling contracts we may not be fully indemnified by our customers for damage to their
property and/or the property of their other contractors. In certain contracts we may assume liability for losses or
damages (including punitive damages) resulting from pollution or contamination caused by negligent or willful
acts of commission or omission by us, our suppliers and/or subcontractors, generally subject to negotiated caps on a
per occurrence basis and/or on an aggregate basis for the term of the contract. In some cases, suppliers or
subcontractors who provide equipment or services to us may seek to limit their liability resulting from pollution or
contamination. Our contracts are individually negotiated, and the levels of indemnity and allocation of liabilities in
them can vary from contract to contract depending on market conditions, particular customer requirements and
other factors existing at the time a contract is negotiated.
Additionally, the enforceability of indemnification provisions in our contracts may be limited or prohibited by
applicable law or may not be enforced by courts having jurisdiction, and we could be held liable for substantial
losses or damages and for fines and penalties imposed by regulatory authorities. The indemnification provisions
of our contracts may be subject to differing interpretations, and the laws or courts of certain jurisdictions may
enforce such provisions while other laws or courts may find them to be unenforceable, void or limited by public
policy considerations, including when the cause of the underlying loss or damage is our gross negligence or
willful misconduct, when punitive damages are attributable to us or when fines or penalties are imposed directly
against us. The law with respect to the enforceability of indemnities varies from jurisdiction to jurisdiction and is
unsettled under certain laws that are applicable to our contracts. Current or future litigation in particular
jurisdictions, whether or not we are a party, may impact the interpretation and enforceability of indemnification
provisions in our contracts. There can be no assurance that our contracts with our customers, suppliers and
subcontractors will fully protect us against all hazards and risks inherent in our operations. There can also be no
assurance that those parties with contractual obligations to indemnify us will be financially able to do so or will
otherwise honor their contractual obligations.
We maintain liability insurance, which includes coverage for environmental damage; however, because of
contractual provisions and policy limits, our insurance coverage may not adequately cover our losses and claim
costs. In addition, certain risks such as pollution, reservoir damage and environmental risks are generally not fully
insurable. Also, we do not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to
work. Accordingly, it is possible that our losses from the hazards we face could have a material adverse effect on
our results of operations, financial condition and cash flows.
We believe that the policy limit under our marine liability insurance is within the range that is customary for
companies of our size in the offshore drilling industry and is appropriate for our business. However, if an accident or
other event occurs that exceeds our coverage limits or is not an insurable event under our insurance policies, or is not
fully covered by contractual indemnity, it could have a material adverse effect on our results of operations, financial
condition and cash flows. There can be no assurance that we will continue to carry the insurance we currently
maintain, that our insurance will cover all types of losses or that we will be able to maintain adequate insurance in the
future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks.
Accordingly, the occurrence of any of the hazards we face could have a material adverse effect on our results
of operations, financial condition and cash flows.
Significant portions of our operations are conducted outside the United States and involve additional risks not
associated with United States domestic operations.
Our operations outside the United States accounted for approximately 79%, 85% and 89% of our total
consolidated revenues for 2015, 2014 and 2013, respectively, and include operations in South America, Australia
and Southeast Asia, Europe, East and West Africa, the Mediterranean and Mexico. Because we operate in various
regions throughout the world, we are exposed to risks of war, political disruption, civil disturbance, acts of
15
terrorism, political corruption, possible economic and legal sanctions (such as possible restrictions against
countries that the U.S. government may consider to be state sponsors of terrorism) and changes in global trade
policies. We may not have insurance coverage for these risks, or we may not be able to obtain adequate insurance
coverage for such events at reasonable rates. Our operations may become restricted, disrupted or prohibited in
any country in which any of the foregoing risks occur. In particular, the occurrence of any of these risks or any of
the following events could materially and adversely impact our results of operations:
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political and economic instability;
piracy, terrorism or other assaults on property or personnel;
kidnapping of personnel;
seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or
use of property or equipment;
renegotiation or nullification of existing contracts;
disputes and legal proceedings in international jurisdictions;
changing social, political and economic conditions;
enactment of additional or stricter U.S. government or international sanctions;
imposition of wage and price controls, trade barriers or import-export quotas;
restrictive foreign and domestic monetary policies;
the inability to repatriate income or capital;
difficulties in collecting accounts receivable and longer collection periods;
fluctuations in currency exchange rates and restrictions on currency exchange;
regulatory or financial requirements to comply with foreign bureaucratic actions;
restriction or disruption of business activities;
limitation of our access to markets for periods of time;
travel limitations or operational problems caused by public health threats;
difficulties in supplying, repairing or replacing equipment or transporting personnel in remote
locations;
difficulties in obtaining visas or work permits for our employees on a timely basis; and
changing taxation policies and confiscatory or discriminatory taxation.
We are also subject to the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws
and regulations governing our international operations in addition to worldwide anti-bribery laws. In addition,
international contract drilling operations are subject to various laws and regulations in countries in which we
operate, including laws and regulations relating to:
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the equipping and operation of drilling rigs;
import-export quotas or other trade barriers;
repatriation of foreign earnings or capital;
oil and gas exploration and development;
local content requirements;
taxation of offshore earnings and earnings of expatriate personnel; and
use and compensation of local employees and suppliers by foreign contractors.
Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors,
require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a
particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult
to predict what governmental regulations may be enacted in the future that could adversely affect the international
offshore drilling industry. The actions of foreign governments may materially and adversely affect our ability to
compete.
In addition, the shipment of goods, including the movement of a drilling rig across international borders,
subjects us to extensive trade laws and regulations. Our import activities are governed by unique customs laws
and regulations that differ in each of the countries in which we operate and often impose record keeping and
reporting obligations. The laws and regulations concerning import/export activity and record keeping and
reporting requirements are complex and change frequently. These laws and regulations may be enacted, amended,
enforced and/or interpreted in a manner that could materially and adversely impact our operations. Shipments can
be delayed and denied export or entry for a variety of reasons, some of which may be outside of our control.
Shipping delays or denials could cause unscheduled downtime for our rigs. Failure to comply with these laws and
16
regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the
contractual withholding of monies owed to us, among other things.
Compliance with or breach of environmental laws can be costly and could limit our operations.
In the United States and in many of the international locations in which we operate, laws and regulations
controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may
harm the environment or otherwise relating to the protection of the environment apply to some of our operations.
For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some
offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those
operations. Laws and regulations protecting the environment have become increasingly stringent, and may in
some cases impose “strict liability,” rendering a person liable for environmental damage without regard to
negligence or fault on the part of that person. These laws and regulations may expose us to liability for the
conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time
they were performed.
U.S. federal and state, foreign and international laws and regulations address oil spill prevention and control
and impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting
from such spills. Some of these laws and regulations have significantly expanded liability exposure across all
segments of the oil and gas industry. For example, the United States Oil Pollution Act of 1990 imposes strict and,
with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety
of public and private damages. Failure to comply with such laws and regulations could subject us to civil or
criminal enforcement action, for which we may not receive contractual indemnification or have insurance
coverage, and could result in the issuance of injunctions restricting some or all of our activities in the affected
areas. In addition, legislative and regulatory developments may occur that could substantially increase our
exposure to liabilities that might arise in connection with our operations.
The application of these laws and regulations or the adoption of new laws and regulations could have a
material adverse effect on our financial condition, results of operations and cash flows.
We may be subject to litigation and disputes that could have a material adverse effect on us.
We are, from time to time, involved in litigation and disputes. These matters may include, among other
things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic
tort claims, employment and tax matters and other litigation that arises in the ordinary course of our business.
Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of
any dispute, claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any
litigation. We may not have insurance for litigation or claims that may arise, or if we do have insurance coverage
it may not be sufficient, insurers may not remain solvent, other claims may exhaust some or all of the insurance
available to us or insurers may interpret our insurance policies such that they do not cover losses for which we
make claims or may otherwise dispute claims made. Litigation may have a material adverse effect on us because
of potential adverse outcomes, defense costs, the diversion of our management’s resources and other factors.
We self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of
Mexico.
Because the amount of insurance coverage available to us is limited, and the cost for such coverage is
substantial, we self-insure for physical damage to rigs and equipment caused by named windstorms in the
GOM. This results in a higher risk of losses, which could be material, that are not covered by third party
insurance contracts. If one or more named windstorms in the GOM cause significant damage to our rigs or
equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows.
In addition, certain of our shore-based facilities are located in geographic regions that are susceptible to
damage or disruption from hurricanes and other weather events. Future hurricanes or similar natural disasters that
impact our facilities, our personnel located at those facilities or our ongoing operations may negatively affect our
financial position and operating results for those periods. These negative effects may include reduced or lost sales
and revenues; costs associated with interruption in operations and with resuming operations; reduced demand for
our services from customers that were similarly affected by these events; lost market share; late deliveries;
uninsured property losses; inadequate business interruption insurance; employee evacuations; and an inability to
retain necessary staff.
17
We may be required to accrue additional tax liability on certain of our foreign earnings.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset
Company, or DFAC, a Cayman Islands subsidiary that we own. It is our intention to indefinitely reinvest future
earnings of DFAC and its foreign subsidiaries to finance foreign activities. We do not expect to provide for U.S.
taxes on any future earnings generated by DFAC and its foreign subsidiaries, except to the extent that these
earnings are immediately subjected to U.S. federal income tax. Should a future distribution be made from any
unremitted earnings of this subsidiary, we may be required to record additional U.S. income taxes that, if material,
could have a material adverse effect on our financial condition, results of operations and cash flows.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
Due to our international operations, we have experienced currency exchange losses where revenues are
received and expenses are paid in nonconvertible currencies or where we do not effectively hedge an exposure to
a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage
of convertible currency available to the country of operation, controls over currency exchange or controls over the
repatriation of income or capital.
Acts of terrorism and other political and military events could adversely affect the markets for our drilling
services.
Terrorist attacks and the continued threat of terrorism in the U.S. and abroad, the continuation or escalation of
existing armed hostilities or the outbreak of additional hostilities could lead to increased political, economic and
financial market instability and a downturn in the economies of the U.S. and other countries. A lower level of
economic activity could result in a decline in energy consumption or an increase in the volatility of energy prices,
either of which could materially and adversely affect the market for our offshore drilling services, our dayrates or
utilization and, accordingly, our financial condition, results of operations and cash flows. While we take steps that
we believe are appropriately designed to secure our energy assets, there is no assurance that we can completely
secure these assets, completely protect them against a terrorist attack or other political and military events or
obtain adequate insurance coverage for such events at reasonable rates.
Failure to obtain and retain highly skilled personnel could hurt our operations.
We require highly skilled personnel to operate and provide technical services and support for our business. A
well-trained, motivated and adequately-staffed work force has a positive impact on our ability to attract and retain
business. As a result, our future success depends on our continuing ability to identify, hire, develop, motivate and
retain skilled personnel for all areas of our organization. To the extent that demand for drilling services and/or the
size of the worldwide industry fleet increases (including due to the impact of newly constructed rigs), shortages of
qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our
rigs, which could adversely affect our results of operations. As of the date of this report, the Ocean GreatWhite,
our ultra-deepwater, semisubmersible rig, is under construction. This rig is not yet fully crewed and will require
additional skilled personnel to operate. Additional new capacity in the offshore drilling market could also cause
further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise
in the offshore drilling industry. Our continued ability to compete effectively depends on our ability to attract
new employees and to retain and motivate our existing employees. Heightened competition for skilled personnel
could materially and adversely impact our financial condition, results of operations and cash flows by limiting our
operations and further increasing our costs.
We rely on third-party suppliers, manufacturers and service providers to secure equipment, components and
parts used in rig operations, conversions, upgrades and construction.
Our reliance on third-party suppliers, manufacturers and service providers to provide equipment and services
exposes us to volatility in the quality, price and availability of such items. Certain components, parts and
equipment that we use in our operations may be available only from a small number of suppliers, manufacturers
or service providers. The failure of one or more third-party suppliers, manufacturers or service providers to
provide equipment, components, parts or services, whether due to capacity constraints, production or delivery
disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment,
is beyond our control and could materially disrupt our operations or result in the delay, renegotiation or
cancellation of drilling contracts, thereby causing a loss of contract drilling backlog and/or revenue to us, as well
as an increase in operating costs.
18
Additionally, our suppliers, manufacturers and service providers could be negatively impacted by current
industry conditions or global economic conditions. If certain of our suppliers, manufacturers or service providers
were to experience significant cash flow issues, become insolvent or otherwise curtail or discontinue their
business as a result of such conditions, it could result in a reduction or interruption in supplies or equipment
available to us and/or a significant increase in the price of such supplies and equipment, which could adversely
impact our results of operations and cash flows.
Our debt levels may limit our liquidity and flexibility in obtaining additional financing and in pursuing other
business opportunities.
As of December 31, 2015, we had approximately $0.3 million and $2.0 billion in short-term borrowings and
senior debt, respectively, maturing at various times from 2019 through 2043. As of February 16, 2016, we had
$305.0 million in Eurodollar loans outstanding and an additional $1.2 billion of availability under our revolving
credit facility. We may incur additional indebtedness in the future, including indebtedness under our commercial
paper program, and we may borrow from time to time under our revolving credit facility to fund working capital
or other needs, subject to compliance with its covenants.
Our ability to meet our debt service obligations is dependent upon our future performance, which is subject to
general economic conditions, industry cycles and financial, business and other factors affecting our operations,
many of which are beyond our control. High levels of indebtedness could have negative consequences to us,
including:
(cid:120) we may have difficulty satisfying our obligations with respect to our outstanding debt;
(cid:120) we may have difficulty obtaining financing in the future for working capital, capital expenditures,
acquisitions or other purposes;
(cid:120)
(cid:120)
(cid:120) we may need to use a substantial portion of our available cash flow from operations to pay interest
and principal on our debt, which would reduce the amount of money available to fund working capital
requirements, capital expenditures, the payment of dividends and other general corporate or business
activities;
our vulnerability to general economic downturns and adverse industry conditions could increase;
our flexibility in planning for, or reacting to, changes in our business and in our industry in general
could be limited;
our amount of debt and the amount we must pay to service our debt obligations could place us at a
competitive disadvantage compared to our competitors that have less debt;
our customers may react adversely to our significant debt level and seek alternative service providers;
and
our failure to comply with the restrictive covenants in our debt instruments that, among other things,
require us to maintain a specified ratio of our consolidated indebtedness to total capitalization and
limit the ability of our subsidiaries to incur debt, could result in an event of default that, if not cured
or waived, could have a material adverse effect on our business or prospects.
(cid:120)
(cid:120)
(cid:120)
In addition, approximately $500.0 million of our long-term debt will mature over the next five years and will
need to be paid or refinanced. We may not be able to refinance our maturing debt upon commercially reasonable
terms, or at all, depending on numerous factors, including our financial condition and prospects at the time and the
then current state of the bank and capital markets in the U.S. Further, our liquidity may be adversely affected if we
are unable to replace our revolving credit facility upon acceptable terms when it matures.
Our overall debt level and/or market conditions could lead credit rating agencies to lower our long-term
and/or short-term corporate credit ratings. In January 2016, Moody’s Investor Services announced that it would
be reviewing our long-term corporate credit and unsecured debt rating and short-term credit rating for commercial
paper, which are currently Baa2 and Prime-2, respectively, for possible downgrade. Our current corporate credit
rating is BBB+ and our short-term credit rating is A2 for Standard & Poor's Ratings Services.
Downgrades in our corporate credit ratings could impact our ability to issue additional debt by raising the cost
of issuing new debt. As a consequence, we may not be able to issue additional debt in amounts and/or with terms
that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other
business opportunities.
19
In addition, our credit ratings are important to our ability to issue commercial paper at favorable rates of
interest. A downgrade in our credit rating could increase the cost of borrowing or make the commercial paper
market unavailable to us, which could increase our cost of capital. In addition, our access to funds under our
commercial paper program is dependent on investor demand for our commercial paper. Disruptions and volatility
in the global credit markets could limit the demand for our commercial paper or result in the need to offer higher
interest rates to investors, which would result in increased expense and could adversely impact our liquidity.
Our revolving credit facility bears interest at variable rates. If market interest rates increase, debt service
requirements on amounts outstanding under our revolving credit facility will increase. This would have an adverse
effect on our results of operations and cash flows. Although we may employ hedging strategies such that a portion
of the aggregate principal amount outstanding under this credit facility carries a fixed rate of interest, any hedging
arrangement put in place may not offer complete protection from this risk.
Any significant cyber attack or other interruption in network security or the operation of critical computer
systems could materially disrupt our operations and adversely affect our business.
Our business has become increasingly dependent upon information technologies, systems and networks to
conduct day-to-day operations, and we are placing greater reliance on technology to help support our operations
and increase efficiency in our business functions. We are dependent upon our information technology and
infrastructure, including operational and financial computer systems to process the data necessary to conduct
almost all aspects of our business. Computer and other business facilities and systems could become unavailable
or impaired from a variety of causes including, among others, storms and other natural disasters, terrorist attacks,
utility outages, theft, design defects, human error or complications encountered as existing systems are
maintained, repaired, replaced or upgraded. It has also been reported that unknown entities or groups have
mounted so-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer
systems, disrupt operations and, in some cases, steal data. A breach or failure of our computer systems or
networks, or those of our customers, vendors or others with whom we do business, could materially disrupt our
business operations and could result in the alteration, loss, theft or corruption of data or unauthorized release of
confidential, proprietary or sensitive data concerning our company, business activities, employees, customers or
vendors. Any such breach or failure could have a material adverse effect on our operations, business or reputation.
Unionization efforts and labor regulations in some of the countries in which we operate could materially
increase our costs or limit our flexibility.
Some of our employees in non-U.S. markets are represented by labor unions and work under collective
bargaining or similar agreements which are subject to periodic renegotiation. These negotiations could result in
higher personnel expenses, other increased costs or increased operational restrictions. Efforts have been made
from time to time to unionize other portions of our workforce. In addition, we may be subjected to strikes or work
stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective
bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our
flexibility.
We are controlled by a single stockholder, which could result in potential conflicts of interest.
Loews Corporation, which we refer to as Loews, beneficially owned approximately 53% of our outstanding
shares of common stock as of February 16, 2016, and is in a position to control actions that require the consent of
stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any
merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors.
One of those, James S. Tisch, the Chairman of the Board of our company, is also the Chief Executive Officer and a
director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews,
and we may in the future enter into other agreements with Loews.
Loews is a holding company. In addition to us, its principal subsidiaries are CNA Financial Corporation, a 90%
owned subsidiary engaged in commercial property and casualty insurance; Boardwalk Pipeline Partners, LP, a 51%
owned subsidiary engaged in transportation and storage of natural gas and natural gas liquids and gathering and
processing of natural gas; and Loews Hotels Holding Corporation, a wholly-owned subsidiary engaged in the
operation of a chain of hotels. It is possible that Loews may in some circumstances be in direct or indirect
competition with us, including competition with respect to certain business strategies and transactions that we may
propose to undertake. In addition, potential conflicts of interest exist or could arise in the future for our directors
who are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of
20
Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to
registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our
interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders,
the presence of potential or actual conflicts could affect the process or outcome of Board deliberations. We cannot
assure you that these conflicts of interest will not materially adversely affect us.
Item 1B. Unresolved Staff Comments.
Not applicable.
Item 2. Properties.
We own an office building in Houston, Texas, where our corporate headquarters are located. We also own
offices and other facilities in New Iberia, Louisiana, Aberdeen, Scotland, Macae, Brazil and Ciudad del Carmen,
Mexico. Additionally, we currently lease various office, warehouse and storage facilities in Australia, Egypt,
Indonesia, Louisiana, Malaysia, Romania, Singapore, Thailand, Trinidad and Tobago, the U.K. and Vietnam to
support our offshore drilling operations.
Item 3. Legal Proceedings.
See information with respect to legal proceedings in Note 12 “Commitments and Contingencies” to our
Consolidated Financial Statements in Item 8 of this report.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.
Price Range of Common Stock
Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol “DO.” The
following table sets forth, for the calendar quarters indicated, the high and low closing prices of our common
stock as reported by the NYSE.
Common Stock
High
Low
2015
First Quarter ............................................
Second Quarter ........................................
Third Quarter ...........................................
Fourth Quarter .........................................
2014
First Quarter ............................................
Second Quarter ........................................
Third Quarter ...........................................
Fourth Quarter .........................................
$ 37.23
34.81
25.45
23.50
$ 56.71
54.61
50.13
39.60
$ 26.49
25.81
17.30
16.81
$ 43.91
45.88
34.27
29.37
As of February 16, 2016, there were approximately158 holders of record of our common stock. This number
represents registered stockholders and does not include stockholders who hold their shares institutionally.
21
Dividend Policy
In 2015, we paid regular cash dividends of $0.125 per share of our common stock on March 2, June 1,
September 1 and December 1. In 2014, we paid regular cash dividends of $0.125 and special cash dividends of
$0.75 per share of our common stock on March 3, June 2, September 2 and December 1.
On February 8, 2016, we announced that we were discontinuing our regular cash dividend.
Our Board has adopted a policy of considering paying regular and special cash dividends, in amounts to be
determined, on a quarterly basis. Any determination to declare a regular or special dividend, as well as the
amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position,
earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business
needs and other factors that our Board considers relevant at that time. Our dividend policy may change from time
to time, and there can be no assurance that we will continue to declare any regular or special cash dividends at all
or in any particular amounts. See “Risk Factors – Although we have paid cash dividends in the past, we may not
pay regular or special cash dividends in the future and we can give no assurance as to the amount or timing of the
payment of any future regular or special cash dividends” in Item 1A of this report, which is incorporated herein
by reference.
CUMULATIVE TOTAL STOCKHOLDER RETURN
The following graph shows the cumulative total stockholder return for our common stock, the Standard &
Poor's 500 Index and the Dow Jones U.S. Oil Equipment & Services index over the five year period ended
December 31, 2015.
Comparison of 2011 – 2015 Cumulative Total Return (1)
$300
$250
$200
$150
$100
$50
$0
2010
2011
2012
2013
2014
2015
Diamond Offshore
S&P 500
Dow Jones U.S. Oil Equipment & Services
Dec. 31,
2010
100
Diamond Offshore
100
S&P 500
Dow Jones U.S. Oil Equipment & Services 100
____________
Dec. 31,
2011
87
102
87
Dec. 31,
2012
112
118
86
Dec. 31,
2013
99
157
109
Dec. 31,
2014
70
178
89
Dec. 31,
2015
41
181
67
(1) Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2010 in our
common stock and the two published indices.
22
Our dividend history for the periods reported above is as follows:
Q1
Q2
Q3
Q4
Year Regular Special Regular Special Regular Special Regular Special
2015
2014
2013
2012
2011
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ --
$ 0.75
$ 0.75
$ 0.75
$ 0.75
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ --
$ 0.75
$ 0.75
$ 0.75
$ 0.75
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ --
$ 0.75
$ 0.75
$ 0.75
$ 0.75
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ 0.125
$ --
$ 0.75
$ 0.75
$ 0.75
$ 0.75
Item 6. Selected Financial Data.
The following table sets forth certain historical consolidated financial data relating to Diamond Offshore. We
prepared the selected consolidated financial data from our consolidated financial statements as of and for the
periods presented. The selected consolidated financial data below should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 and our
Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
2015
As of and for the Year Ended December 31,
2012
2014
2013
2011
Income Statement Data:
Total revenues ....................................... $ 2,419,393
Operating (loss) income .......................
Net (loss) income ..................................
Net (loss) income per share:
Basic ...................................................
Diluted ................................................
(2.00)
(2.00)
(294,074) (1)
(274,285)
Balance Sheet Data:
Drilling and other property and
equipment, net ..................................... $ 6,378,814 (1)
Total assets ...........................................
Long-term debt (excluding current
maturities) (4) .......................................
1,994,773
7,164,889
(In thousands, except per share and ratio data)
$2,814,671
572,562 (2)
387,011
$2,920,421
801,606
548,686
$2,986,508
962,378
720,477
$3,322,419
1,255,414
962,542
2.82
2.81
3.95
3.95
5.18
5.18
6.92
6.92
$6,945,953 (2)(3) $5,467,227
8,391,434
8,021,289
$4,864,972
7,235,286
$4,667,469
6,964,157
1,994,526
2,244,189
1,496,066
1,495,823
Other Financial Data:
Capital expenditures ............................. $
Cash dividends declared per share .......
Ratio of earnings to fixed charges (5) .....
__________
830,655
$2,032,764 (3) $ 957,598
3.50
0.50
3.50
(2.45)x (6) 4.64x
7.79x
$ 702,041
$ 774,756
3.50
11.11x
3.50
14.40x
(1) During 2015, we recorded an aggregate impairment loss of $860.4 million to write down certain of our drilling rigs with
indicators of impairment to their estimated recoverable amounts. See “Management’s Discussion and Analysis of Financial
Condition and Results of Operations (cid:16)(cid:16) Results of Operations--Years Ended December 31, 2015, 2014 and 2013--Overview--
2015 Compared to 2014-- Impairment of Assets and Note 2 “Asset Impairments” to our Consolidated Financial Statements
included in Item 8 of this report for a discussion of the 2015 asset impairment.
(2)
In the third quarter of 2014, we recorded an impairment loss of $109.5 million to write down six of our mid-water
semisubmersibles with indicators of impairment to their estimated recoverable amounts. See “Management’s Discussion and
Analysis of Financial Condition and Results of Operations -- Results of Operations--Years Ended December 31, 2015, 2014 and
2013--Overview--2014 Compared to 2013--Impairment of Assets and Note 2 “Asset Impairments” to our Consolidated Financial
Statements included in Item 8 of this report for a discussion of the 2014 asset impairment.
(3) During 2014, we took delivery of three ultra-deepwater drillships and two deepwater semisubmersible rigs. The aggregate net
book value of these newly constructed rigs was $2.7 billion at December 31, 2014, of which $1.3 billion was reported in
construction work-in-progress at December 31, 2013. See Note 9 “Drilling and Other Property and Equipment” to our
Consolidated Financial Statements included in Item 8 of this report for a discussion of the components of our drilling and other
property and equipment.
(4)
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources
-- Credit Agreement, Commercial Paper Program and Senior Notes” in Item 7 and Note 10 “Credit Agreement and Senior Notes”
to our Consolidated Financial Statements included in Item 8 of this report for a discussion of changes to our long-term debt.
23
(5)
(6)
For all periods presented, the ratio of earnings to fixed charges has been computed on a total enterprise basis. Earnings represent
pre-tax income from continuing operations plus fixed charges. Fixed charges include (i) interest, whether expensed or capitalized,
(ii) amortization of debt issuance costs, whether expensed or capitalized, and (iii) a portion of rent expense, which we believe
represents the interest factor attributable to rent.
The deficiency in our earnings available for fixed charges for the year ended December 31, 2015 was $388.9 million.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion should be read in conjunction with our Consolidated Financial Statements
(including the Notes thereto) in Item 8 of this report.
We are a leader in offshore drilling, providing contract drilling services to the energy industry around the
globe with a fleet of 32 offshore drilling rigs that includes four jack-up rigs which we are marketing for sale. Our
fleet consists of 23 semisubmersibles, including the Ocean GreatWhite, which is under construction, five jack-up
rigs and four dynamically positioned drillships, including the last of our four newbuild drillships, the Ocean
BlackLion, which was delivered in the second quarter of 2015. We expect our harsh environment, ultra-deepwater
semisubmersible rig, the Ocean GreatWhite, to be delivered in mid-2016.
Market Overview
Market fundamentals in the oil and gas industry deteriorated further in the fourth quarter of 2015 and have
continued to decline in 2016. In early January 2016, oil prices fell to a 12-year low below $30 per barrel, with
some industry analysts predicting even lower commodity prices before any market recovery. Oil markets continue
to be volatile due to a number of geopolitical and economic factors. These factors, combined with significant
operating losses incurred during the fourth quarter of 2015 by some independent and national oil companies and
exploration and production companies, have caused most of these companies to announce additional cuts to their
already reduced 2016 capital spending plans, reflecting delays in planned drilling or exploration projects, and, in
some cases, termination of projects altogether. Rig tenders are infrequent and have generally been limited to short-
term or well-to-well work not commencing until 2017 or later. There have been very few rig tenders thus far in
2016.
The offshore floater market is currently faced with an oversupply of drilling rigs, which thus far has only been
slightly abated by the cold stacking and retirement of rigs. The number of available rigs continues to grow as
contracted rigs come off contract and newbuilds are delivered, increasing competition. Competition for the limited
number of drilling jobs continues to be intense with some operators bidding multiple rigs on the same job, in some
cases, bidding rigs of both higher and lower specifications. Operators are also continuing to attempt to sublet
previously contracted rigs for which capital spending programs have been delayed or canceled. Industry analysts
have predicted that the offshore contract drilling market may remain depressed with further declines in dayrates and
utilization likely in 2016 and 2017.
As a result of the depressed market conditions and continued pessimistic outlook for the near term, certain of
our customers, as well as those of our competitors, have attempted to renegotiate or terminate existing drilling
contracts. Such renegotiations could include requests to lower the contract dayrate, lowering of a dayrate in
exchange for additional contract term, shortening the term on one contracted rig in exchange for additional term
on another rig, early termination of a contract in exchange for a lump sum margin payout and many other
possibilities. In addition to the potential for renegotiations, some of our drilling contracts permit the customer to
terminate the contract early after specified notice periods, sometimes resulting in no payment to us or sometimes
resulting in a contractually specified termination amount, which may not fully compensate us for the loss of the
contract. During depressed market conditions, certain customers have utilized such contract clauses to seek to
renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in
order to avoid their obligations to us under circumstances where we believe we are in compliance with the
contracts. Particularly during depressed market conditions, the early termination of a contract may result in a rig
being idle for an extended period of time, which could adversely affect our financial condition, results of
operations and cash flows. When a customer terminates our contract prior to the contract’s scheduled expiration,
our contract backlog is also adversely impacted. See “Risk Factors (cid:16) We can provide no assurance that our
drilling contracts will not be terminated early or that our current backlog of contract drilling revenue will be
ultimately realized” and “–Contract Drilling Backlog” below.
Our results of operations and cash flows for the year ended December 31, 2015 have been materially impacted
by depressed market conditions in the offshore drilling industry. We currently expect that these adverse market
24
conditions will continue for the foreseeable future. The continuation of these conditions for an extended period could
result in more of our rigs being without contracts and/or cold stacked or scrapped and could further materially and
adversely affect our financial condition, results of operations and cash flows. When we cold stack or elect to scrap a
rig, we evaluate the rig for impairment. During 2015, we recognized an aggregate impairment loss of $860.4
million, including an impairment loss of $499.4 million recognized in the fourth quarter of 2015. See “-- Results
of Operations--Years Ended December 31, 2015, 2014 and 2013--Overview--2015 Compared to 2014--
Impairment of Assets,” “Risk Factors — We may incur additional asset impairments and/or rig retirements as a
result of reduced demand for certain offshore drilling rigs” in Item 1A of this report and Note 2 “Asset
Impairments” to our Consolidated Financial Statements in Item 8 of this report
As of February 16, 2016, 17 of our rigs were not subject to a drilling contract with a customer, including 14
rigs that have been cold stacked. Of the cold-stacked rigs, four jack-up rigs are currently being marketed for sale.
The previously cold-stacked jack-up rig Ocean Titan was sold in February 2016. See “– Contract Drilling
Backlog” for future commitments of our rigs during 2016 through 2020.
Although these general market conditions impact all segments of the offshore drilling market, the following
discussion addresses market conditions within segments of the floater market.
Floater Markets
Ultra-Deepwater and Deepwater Floaters. Globally, the ultra-deepwater and deepwater floater markets
continue to be depressed. Diminished or nonexistent demand, combined with an oversupply of rigs has caused
floater dayrates to decline significantly. Offshore drilling contractors have been approached by customers with
binding contracts, who have sought to and have successfully renegotiated such contracts at lower rates to obtain
some financial relief in the current market, and, in some cases, have terminated contracts with and without
compensation to the associated drilling contractor. Industry analysts expect offshore drillers to continue to scrap
older, lower specification rigs; however, newer and higher specification rigs have not been immune to the
recycling trend. In addition, industry analysts predict that the number of uncontracted floaters may more than
double by the end of 2016.
Newbuild rig deliveries and established rigs coming off contract continue to fuel an oversupply of floaters in
both the ultra-deepwater and deepwater markets. In an effort to manage the oversupply of rigs and potentially
avoid the cost of cold stacking newly-built rigs, which, in the case of dynamically-positioned rigs, can be
significant, several drilling contractors have exercised options to delay the delivery of rigs by the shipyard or have
exercised their right to cancel orders due to the late delivery of rigs. As of the date of this report, based on
industry data, there are approximately 54 competitive, or non-owner-operated, newbuild floaters on order, 32 of
which are not yet contracted for future work. In addition, based on industry reports, there are currently 20
newbuild floaters scheduled for delivery in 2016, of which only four rigs have been contracted for future work;
however, industry analysts predict that delivery dates may shift as newbuild owners negotiate with their respective
shipyards.
Mid-Water Floaters. While conditions in the mid-water market vary slightly by region, mid-water rigs have
been adversely impacted by (i) lower demand, (ii) declining dayrates, (iii) increased regulatory requirements,
including more stringent design requirements for well control equipment, which could significantly increase the
capital needed to comply with design requirements that would permit such rigs to work in U.S. waters, (iv) the
challenges experienced by lower specification units in this segment as a result of more complex customer
specifications, and (v) the intensified competition resulting from the migration of some deepwater and ultra-
deepwater units to compete against mid-water units. To date, the mid-water market has seen the highest number of
cold-stacked and scrapped rigs. Since 2012, we have sold 12 of our mid-water rigs for scrap. As market
conditions remain challenging, we expect higher specification rigs to take the place of lower specification units,
where possible, leading to additional lower specification rigs being cold stacked or ultimately scrapped.
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of February 16, 2016 (based on contract
information known at that time), October 1, 2015 (the date reported in our Quarterly Report on Form 10-Q for the
quarter ended September 30, 2015), and February 9, 2015 (the date reported in our Annual Report on Form 10-K
for the year ended December 31, 2014). Contract drilling backlog as presented below includes only firm
commitments (typically represented by signed contracts) and is calculated by multiplying the contracted operating
dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation
25
also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and
survey days); however, the amount of actual revenue earned and the actual periods during which revenues are
earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization
rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due
to various operating factors including, but not limited to, weather conditions and unscheduled repairs and
maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation
and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys.
Changes in our contract drilling backlog between periods are generally a function of the performance of work on
term contracts, as well as the extension or modification of existing term contracts and the execution of additional
contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our
contracts. See “Risk Factors — We can provide no assurance that our drilling contracts will not be terminated
early or that our current backlog of contract drilling revenue will be ultimately realized” in Item 1A of this report,
which is incorporated herein by reference.
February 16,
2016
October 1,
2015
(In thousands)
February 9,
2015
Contract Drilling Backlog
Floaters:
Ultra-Deepwater (1) .........................................................
Deepwater ......................................................................
Mid-Water ......................................................................
Total Floaters .............................................................
$
4,415,000
375,000
356,000
5,146,000
$
Jack-ups ................................................................................
Total ...........................................................................
$
49,000
5,195,000
$
4,851,000
439,000
401,000
5,691,000
18,000
5,709,000
$
$
5,390,000
748,000
611,000
6,749,000
91,000
6,840,000
(1) Contract drilling backlog as of February 16, 2016 for our ultra-deepwater floaters includes $641.0
million for the years 2016 to 2019 attributable to future work for the semisubmersible Ocean
GreatWhite, which is under construction.
The following table reflects the amount of our contract drilling backlog by year as of February 16, 2016.
Contract Drilling Backlog
Floaters:
Total
For the Years Ending December 31,
2016 (1)
2017
2018
2019 - 2020
(In thousands)
Ultra-Deepwater (2) ....................... $ 4,415,000
375,000
Deepwater ....................................
Mid-Water ....................................
356,000
5,146,000
Total Floaters ...........................
$ 1,106,000
238,000
222,000
1,566,000
$ 1,201,000
137,000
134,000
1,472,000
$ 1,142,000
--
--
1,142,000
$
966,000
--
--
966,000
Jack-ups ..............................................
49,000
Total ......................................... $ 5,195,000
42,000
$ 1,608,000
7,000
$ 1,479,000
--
$ 1,142,000
--
966,000
$
(1) Represents the twelve-month period beginning January 1, 2016.
(2) Contract drilling backlog as of February 16, 2016 for our ultra-deepwater floaters includes $90.0 million
for the year 2016, $214.0 million for each of the years 2017 and 2018, and $123.0 million for the year
2019 attributable to future work for the Ocean GreatWhite, which is under construction.
The following table reflects the percentage of rig days committed by year as of February 16, 2016. The
percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as
scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs
multiplied by the number of days in a particular year). Total available days have been calculated based on the
expected final commissioning date for the Ocean GreatWhite, which is under construction.
26
For the Years Ending December 31,
2016 (1)
2017
2018
2019 - 2020
Rig Days Committed (2)
Floaters:
Ultra-Deepwater ............................................................
Deepwater ......................................................................
Mid-Water ......................................................................
All Floaters ....................................................................
Jack-ups ................................................................................
67%
30%
28%
45%
19%
58%
17%
12%
34%
3%
57%
--
--
25%
--
25%
--
--
11%
--
(1) Represents the twelve-month period beginning January 1, 2016.
(2) As of February 16, 2016, includes approximately 535 currently known, scheduled shipyard days for rig
commissioning, contract preparation, surveys and extended maintenance projects, as well as rig
mobilization days, for the year 2016.
Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows
Operating Income. Our operating income is primarily a function of contract drilling revenue earned less
contract drilling expenses incurred or recognized. The two most significant variables affecting our contract
drilling revenue are the dayrates earned and utilization rates achieved by our rigs, each of which is a function of rig
supply and demand in the marketplace. These factors are not within our control and are difficult to predict. We
generally recognize revenue from dayrate drilling contracts as services are performed. Consequently, when a rig is
idle, no dayrate is earned and revenue will decrease as a result.
Revenue is also affected by the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard
projects. In connection with certain drilling contracts, we may receive fees for the mobilization of equipment. In
addition, some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet
customer requirements for which we may or may not be compensated. We earn these fees as services are
performed over the initial term of the related drilling contracts. We defer mobilization and contract preparation
fees received (on either a lump-sum or dayrate basis), as well as direct and incremental costs associated with the
mobilization of equipment and contract preparation activities, and amortize each, on a straight-line basis, over the
term of the related drilling contracts. Absent a contract, mobilization costs are recognized currently.
Operating income also fluctuates due to varying levels of contract drilling expenses. Our operating expenses
represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment,
which generally are not affected by changes in dayrates and short-term reductions in utilization. For instance, if a
rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is
typically maintained in a prepared or “warm stacked” state with a full crew. In addition, when a rig is idle, we are
responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the
operator when a rig is under contract. However, if a rig is expected to be idle for an extended period of time, we
may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially
offsets the impact on operating income. The cost of cold stacking a rig can vary depending on the type of rig.
The cost of cold stacking a drillship, for example, is typically substantially higher than the cost of cold stacking a
jack-up rig or an older floater rig.
The principal components of our operating costs are, among other things, direct and indirect costs of labor
and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance.
Labor and repair and maintenance costs represent the most significant components of our operating expenses. In
general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs
associated with labor regulations in the geographic regions in which our rigs operate. In addition, the costs
associated with training new and seasoned employees can be significant. Costs to repair and maintain our
equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and
condition of the equipment and the regions in which our rigs are working.
Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform
certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five
years for each of our rigs. Operating revenue decreases because these special surveys are generally performed
27
during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to
the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs, which are
recognized as incurred. Repair and maintenance activities may result from the special survey or may have been
previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year
survey will vary from year to year, as well as from quarter to quarter.
In addition, operating income may also be negatively impacted by intermediate surveys, which are performed
at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and
scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it
normally does not require dry-docking or shipyard time, except for rigs generally older than 15 years that are
located in the United Kingdom sector of the North Sea.
During 2016, we expect to spend approximately 535 days for the mobilization of rigs and contract acceptance
testing, including days associated with mobilization and acceptance testing for the Ocean GreatWhite
(approximately 90 days), which is under construction and expected to be delivered in mid-2016 and rig
modifications and acceptance testing for the Ocean BlackRhino, which is scheduled to begin operating under a
new contract in January 2017 (approximately 155 days). We expect the Ocean Endeavor to be unavailable
through mid-2016 (approximately 135 days) as it demobilizes out of the Black Sea. We can provide no assurance
as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig
mobilizations and other shipyard projects. See “ – Contract Drilling Backlog.”
In April 2015, the Bureau of Safety and Environmental Enforcement (an agency established by the U.S.
Department of the Interior that governs the offshore drilling industry on the Outer Continental Shelf) announced
proposed rules that, when enacted, will include more stringent design requirements for well control equipment
used in offshore drilling operations. Based on our assessment of the proposed rules, we believe that we may need
to incur significant capital costs to comply with the additional design requirements to enable our cold-stacked
mid-water semisubmersibles to return to work in U.S. waters.
Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and
equipment caused by named windstorms in the GOM. If a named windstorm in the GOM causes significant
damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of
operations and cash flows. Under our insurance policy, we carry physical damage insurance for certain losses other
than those caused by named windstorms in the GOM for which our deductible for physical damage is $25.0 million
per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.
In addition, under our current insurance policy, we carry marine liability insurance covering certain legal
liabilities, including coverage for certain personal injury claims, and generally covering liabilities arising out of or
relating to pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is
within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for
our business. Our deductibles for marine liability coverage, including for personal injury claims, are $25.0 million
for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain
thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of
claims that might arise during the policy year.
Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of
qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period
of interest capitalization covers the duration of the activities required to make the asset ready for its intended use,
and the capitalization period ends when the asset is substantially complete and ready for its intended use, which is
expected to continue after delivery of the rigs from the shipyard and until the user acceptance phase of each
project is completed. For the year ended December 31, 2015, we capitalized interest of $16.3 million on
qualifying expenditures related to the construction of the Ocean GreatWhite and the Ocean BlackLion, until it was
placed in service in June 2015. We will continue capitalizing interest on qualifying expenditures during 2016 for
the Ocean GreatWhite, which is expected to be completed in mid-2016.
Impact of Changes in Tax Laws or Their Interpretation. We operate through our various subsidiaries in a
number of countries throughout the world. As a result, we are subject to highly complex tax laws, treaties and
regulations in the jurisdictions in which we operate, which may change and are subject to interpretation. Changes
in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may put us at risk for
future tax assessments and liabilities which could be substantial and could have a material adverse effect on our
financial condition, results of operations and cash flows.
28
Critical Accounting Estimates
Our significant accounting policies are included in Note 1 “General Information” to our Consolidated
Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are
inherent in the preparation of our financial statements and the application of our significant accounting policies.
We believe that our most critical accounting estimates are as follows:
Property, Plant and Equipment. We carry our drilling and other property and equipment at cost, less
accumulated depreciation. Maintenance and routine repairs are charged to income currently while replacements
and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend
the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be
required in determining whether or not such replacements and betterments meet the criteria for capitalization and
in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and
estimates could produce results that differ from those reported. Historically, the amount of capital additions
requiring significant judgments, assumptions or estimates has not been significant. During the years ended
December 31, 2015 and 2014, we capitalized $262.4 million and $546.0 million, respectively, in replacements and
betterments of our drilling fleet.
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the
carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the
expectation of cold stacking a rig in the near term, contracted backlog of less than one year for a rig, a decision to
retire or scrap a rig, or excess spending over budget on a newbuild, construction project or major rig upgrade).
We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment.
Our assumptions and estimates underlying this analysis include the following:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
dayrate by rig;
utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of
time per year that the rig would be used at certain dayrates);
the per day operating cost for each rig if active, warm stacked or cold stacked;
the estimated annual cost for rig replacements and/or enhancement programs;
the estimated maintenance, inspection or other costs associated with a rig returning to work;
salvage value for each rig; and
estimated proceeds that may be received on disposition of each rig.
Based on these assumptions, we develop a matrix for each rig under evaluation using multiple
utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a
projected probability-weighted cash flow for each rig based on the respective matrix and compare such amount to
the carrying value of the asset to assess recoverability.
The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are
developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water
depth and other attributes and then assesses its future marketability in light of the current and projected market
environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs,
are estimated using historical data adjusted for known developments and future events that are anticipated by
management at the time of the assessment.
Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment
evaluation, and the use of different assumptions could produce results that differ from those reported. Our
methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value
measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes
from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s
assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events,
and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to
these assumptions could materially alter our analysis in testing an asset for potential impairment. For example,
changes in market conditions that exist at the measurement date or that are projected by management could affect
our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not
limited to, a further sustained decline in oil and gas prices, cancelations of our drilling contracts or contracts of our
competitors, contract modifications, costs to comply with new governmental regulations, growth in the global
oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market
29
conditions in the future vary significantly from market conditions used in our projections, our assessment of
impairment would likely be different.
During 2015, in response to pending regulatory requirements in the GOM, as well as the continued
deterioration of the market fundamentals in the oil and gas industry, including the dramatic decline in oil prices,
significant cutbacks in customer capital spending plans and contract cancelations by customers, we evaluated 25
of our drilling rigs with indications that their carrying amounts may not be recoverable and recorded an aggregate
impairment loss of $860.4 million related to 17 drilling rigs, consisting of two ultra-deepwater, one deepwater and
nine mid-water floaters and five jack-up rigs. In the third quarter of 2014, we recognized an impairment loss of
$109.5 million in connection with our management’s decision to retire and scrap six mid-water semisubmersible
rigs. See “ – Results of Operations –Years Ended December 31, 2015, 2014 and 2013 – Overview – 2015
Compared to 2014 – Impairment of Assets,” “ – Results of Operations –Years Ended December 31, 2015, 2014
and 2013 – Overview – 2014 Compared to 2013 – Impairment of Assets” and Note 2 “Asset Impairments” to our
Consolidated Financial Statements in Item 8 of this report.
Personal Injury Claims. Our deductibles for liability coverage for personal injury claims, which primarily
result from Jones Act liability in the Gulf of Mexico, are currently $25.0 million for the first occurrence, with no
aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain
thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency
of claims which might arise during the policy year. The Jones Act is a federal law that permits seamen to seek
compensation for certain injuries during the course of their employment on a vessel and governs the liability of
vessel operators and marine employers for the work-related injury or death of an employee. We engage outside
consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical
losses and utilizing various actuarial models.
The models used in estimating our aggregate reserve for personal injury claims include actuarial assumptions
such as:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
claim emergence, or the delay between occurrence and recording of claims;
settlement patterns, or the rates at which claims are closed;
development patterns, or the rate at which known cases develop to their ultimate level;
average, potential frequency and severity of claims; and
effect of re-opened claims.
The eventual settlement or adjudication of these claims could differ materially from our estimated amounts
due to uncertainties such as:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
the severity of personal injuries claimed;
significant changes in the volume of personal injury claims;
the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
inconsistent court decisions; and
the risks and lack of predictability inherent in personal injury litigation.
Income Taxes. We account for income taxes in accordance with accounting standards that require the
recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in
recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been
currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current
tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred
tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards.
Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax
benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach.
We do not establish deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely reinvest to
finance foreign activities. However, if these earnings become subject to U.S. federal tax, any required provision
could have a material adverse impact on our financial results. We make judgments regarding future events and
related estimates especially as they pertain to the forecasting of our effective tax rate, the potential realization of
deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance of items deducted on
tax returns upon audit.
30
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset
Company, or DFAC, a Cayman Islands subsidiary that we own. It is our intention to indefinitely reinvest future
earnings of DFAC and its foreign subsidiaries to finance foreign activities. Accordingly, we have not made a
provision for U.S. income taxes on approximately $2.0 billion of undistributed foreign earnings and profits.
Although we do not intend to repatriate the earnings of DFAC and have not provided U.S. income taxes for such
earnings, except to the extent that such earnings were immediately subject to U.S. income taxes, these earnings
could become subject to U.S. income tax if remitted, or if deemed remitted as a dividend; however, it is not
practicable to estimate this potential liability.
In several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter
into agreements with other of our wholly-owned subsidiaries to provide specialized services and equipment in
support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be
charged for providing the services and equipment, and utilize outside consultants to assist us in the development
of such transfer pricing methodologies. In most cases, there are alternative transfer pricing methodologies that
could be applied to these transactions and, if applied, could result in different chargeable amounts.
31
Results of Operations
Although we perform contract drilling services with different types of drilling rigs and in many geographic
locations, there is a similarity of economic characteristics due to the nature of the revenue earning process as it
relates to the offshore drilling industry, over the operating lives of our drilling rigs. We believe that the
combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with
applicable accounting standards on segment reporting. However, for purposes of this discussion and analysis of
our results of operations, we provide greater detail with respect to the types of rigs in our fleet to enhance the
reader’s understanding of our financial condition, changes in financial condition and results of operations.
Key performance indicators by equipment type are listed below.
REVENUE EARNING DAYS (1)
Floaters:
Ultra-Deepwater ..........................................
Deepwater ...................................................
Mid-Water ...................................................
Jack-ups ........................................................
UTILIZATION (2)
Floaters:
Ultra-Deepwater ..........................................
Deepwater (3) ...............................................
Mid-Water ...................................................
Jack-ups ........................................................
AVERAGE DAILY REVENUE (4)
Floaters:
Ultra-Deepwater ..........................................
Deepwater ...................................................
Mid-Water ...................................................
Jack-ups ........................................................
Year Ended December 31,
2014
2013
2015
2,690
1,339
1,433
909
2,151
1,206
3,969
1,845
2,392
1,530
4,186
1,949
64%
52%
36%
42%
65%
55%
61%
78%
82%
84%
64%
76%
$
497,700
409,800
270,500
93,400
$
459,100
409,800
271,300
96,700
$
357,300
403,300
286,200
89,300
(1) A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after
commencement of operations and excludes mobilization, demobilization and contract preparation
days.
(2) Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar
days in the period for all specified rigs in our fleet (including cold-stacked rigs, but excluding rigs
under construction). As of December 31, 2015, our cold stacked rigs consisted of one ultra-
deepwater, two deepwater and four mid-water semisubmersible rigs. In addition, we had five
cold-stacked jack-up rigs which are being marketed for sale. As of December 31, 2014, six of our
mid-water semisubmersible drilling rigs were cold stacked, all of which were sold for scrap in
2015.
(3) Utilization for our deepwater floaters in 2015 included 365 total calendar days for the Ocean Apex,
which was placed in service in December 2014.
(4) Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in
our fleet per revenue earning day.
32
Comparative data relating to our revenues and operating expenses by equipment type are listed below.
Years Ended December 31, 2015, 2014 and 2013
Year Ended December 31,
2015
2014
2013
(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater .......................................................... $ 1,339,059
548,667
Deepwater ...................................................................
Mid-Water ...................................................................
387,549
Total Floaters ............................................................ 2,275,275
Jack-ups ........................................................................
84,909
Total Contract Drilling Revenue ................................ $ 2,360,184
$
987,565
494,247
1,076,842
2,558,654
178,472
$ 2,737,126
$
854,515
617,080
1,197,934
2,669,529
174,055
$ 2,843,584
REVENUES RELATED TO REIMBURSABLE
EXPENSES .................................................................. $
59,209
$
77,545
$
76,837
CONTRACT DRILLING EXPENSE
Floaters:
Ultra-Deepwater .......................................................... $
620,122
Deepwater ...................................................................
277,779
Mid-Water ...................................................................
230,606
Total Floaters ............................................................
1,128,507
Jack-ups
65,699
33,658
Other .............................................................................
Total Contract Drilling Expense .................................. $ 1,227,864
$
536,615
292,050
535,080
1,363,745
111,204
48,674
$ 1,523,623
$
538,765
267,820
604,492
1,411,077
115,078
46,370
$ 1,572,525
REIMBURSABLE EXPENSES ................................... $
58,050
$
76,091
$
74,967
OPERATING INCOME
Floaters:
718,937
Ultra-Deepwater .......................................................... $
270,888
Deepwater ...................................................................
156,943
Mid-Water ...................................................................
1,146,768
Total Floaters ............................................................
19,210
Jack-ups ........................................................................
(33,658)
Other .............................................................................
1,159
Reimbursable expenses, net ..........................................
(493,162)
Depreciation ..................................................................
(66,462)
General and administrative expense ..............................
--
Bad debt expense ..........................................................
(860,441)
Impairment of assets .....................................................
(9,778)
Restructuring and separation costs ................................
Gain on disposition of assets .........................................
2,290
Total Operating (Loss) Income .................................. $ (294,074)
$
450,950
202,197
541,762
1,194,909
67,268
(48,674)
1,454
(456,483)
(81,832)
--
(109,462)
--
5,382
$ 572,562
$
315,750
349,260
593,442
1,258,452
58,977
(46,370)
1,870
(388,092)
(64,788)
(22,513)
--
--
4,070
$ 801,606
Other income (expense):
Interest income ..............................................................
Interest expense .............................................................
Foreign currency transaction gain (loss) .......................
Other, net.......................................................................
(Loss) income before income tax benefit (expense) ........
Income tax benefit (expense) ..........................................
3,322
(93,934)
2,465
873
(381,348)
107,063
801
(62,053)
3,199
682
515,191
(128,180)
701
(24,843)
(4,915)
1,691
774,240
(225,554)
NET (LOSS) INCOME ................................................. $ (274,285)
$ 387,011
$ 548,686
33
Overview
2015 Compared to 2014
Operating (Loss) Income. We incurred an operating loss of $294.1 million in 2015 compared to operating
income of $572.6 million in 2014. Our operating results for 2015 reflected an aggregate impairment loss of $860.4
million, $9.8 million in restructuring and severance costs, and a $96.2 million net reduction in rig operating results
for our combined floater fleet and jack-up rigs, compared to 2014. Depreciation expense increased $36.7 million in
2015, compared to 2014, due to a higher depreciable asset base in 2015, including the Ocean Apex and two newbuild
drillships, which were placed in service in December 2014, partially offset by the absence of depreciation for certain
of our rigs that were impaired or sold during late 2014 and in 2015.
Total contract drilling revenue declined $376.9 million, or 14%, during 2015 compared to 2014, primarily due to
a $782.9 million decrease in revenue earned by our combined mid-water and jack-up fleets, partially offset by an
aggregate $405.9 million increase in revenue earned by our ultra-deepwater and deepwater floaters. Our results
for 2015 reflected an aggregate 2,800 fewer revenue earning days, compared to 2014, primarily, due to the cold
stacking of additional rigs, rig sales and incremental downtime between contracts, partially offset by incremental
revenue generating days for our newly constructed and upgraded or enhanced rigs.
Total contract drilling expense for 2015 decreased $295.8 million, or 19%, compared to the prior year, primarily
due to lower rig utilization, combined with our efforts to control costs. Contract drilling expense for 2015, compared
to 2014, reflected lower costs for labor and personnel ($165.8 million), repairs and maintenance ($70.1 million),
inspections ($17.2 million), freight ($17.9 million), rig insurance ($9.7 million) and a net decrease in other rig
operating costs, including costs associated with our international shorebases, overhead costs and revenue-based
agency fees ($72.6 million), partially offset by higher rig mobilization expense ($57.6 million).
Impairment of Assets. During the third quarter of 2014, our management adopted a plan to scrap six of our
mid-water semisubmersible rigs, all of which were sold by the end of 2015. As a result of this decision, we
recognized an impairment loss of $109.5 million during 2014 to write down the aggregate net book value of these
rigs to their estimated recoverable amounts. During 2015, in response to pending regulatory requirements in the
GOM, as well as the continued deterioration of the market fundamentals in the oil and gas industry, we
determined that the carrying value of 17 of our rigs, consisting of two ultra-deepwater, one deepwater and nine
mid-water floaters and five jack-up rigs were impaired and, therefore, recorded an aggregate impairment loss of
$860.4 million for the year ended December 31, 2015. See “ --Critical Accounting Estimates - Property, Plant
and Equipment” and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this
report.
Restructuring and Separation Costs. In response to the continued decline in the offshore drilling market, we
have reviewed our cost and organization structure. As a result, our management approved and initiated a reduction
in workforce at our onshore bases and corporate facilities. During the year ended December 31, 2015, we recognized
$9.8 million in restructuring and employee separation related costs on behalf of separated employees.
Interest Expense, Net of Amounts Capitalized. Interest expense increased $31.9 million during 2015,
compared to 2014, primarily as a result of less interest capitalized during 2015 ($44.3 million) due to the
completion of five qualifying construction projects in 2014 and 2015. This increase was partially offset by a
$12.3 million reduction in interest expense for 2015, primarily due to the repayment of two tranches of our senior
notes in September 2014 and July 2015, reduced by additional interest expense on short-term borrowings during
2015.
Income Tax Expense. Our effective tax rate for 2015 was 28.1%, compared to a 24.9% effective tax rate for
2014. The higher effective tax rate in 2015 was due to differences in the mix of our domestic and international
pre-tax earnings and losses, including asset impairments taken during both 2015 and 2014 in various jurisdictions,
with differing tax consequences. The 2014 period also included the reversal of $55.4 million of reserves for
uncertain tax positions in various foreign jurisdictions which were settled in our favor or for which the statute of
limitations had expired, compared to a similar reversal of $9.5 million in 2015.
2014 Compared to 2013
Operating Income. Operating income decreased $229.0 million, or 29%, during 2014, compared to 2013,
primarily due to a $106.5 million, or 4%, reduction in contract drilling revenue combined with the negative effects of
34
a $109.5 million impairment loss recognized in the third quarter of 2014, higher depreciation ($68.4 million) and
higher general and administrative expenses ($17.0 million). During 2014, we recognized incremental depreciation
expense on a higher depreciable asset base, compared to 2013, which included the following newly constructed rigs
placed in service during 2014: Ocean Onyx (January 2014), Ocean BlackHawk (February 2014) and Ocean
BlackHornet, Ocean BlackRhino and Ocean Apex (December 2014). General and administrative costs for 2014
reflected higher employee compensation and professional fees than those incurred in the prior year, primarily related
to compensation of and termination benefits paid to certain of our current and former key executives. These negative
effects were partially offset by a $48.9 million reduction in contract drilling expense and the absence of a $22.5
million charge for an uncollectible receivable incurred in 2013.
Contract drilling revenue for our deepwater and mid-water fleets decreased $122.8 million and $121.1
million, respectively, during 2014, compared to 2013, primarily as a result of 324 and 217 fewer revenue earning
days, respectively, combined with the effect of a lower average daily revenue earned by our mid-water floater
fleet. In contrast, contract drilling revenue earned by our ultra-deepwater floaters and jack-up rigs increased
$133.1 million and $4.4 million, respectively, during 2014, compared to 2013, primarily due to higher average
daily revenue earned by both our ultra-deepwater and jack-up fleets despite an aggregate 345-day reduction in
revenue earning days during 2014.
Total contract drilling expense during 2014 decreased by $48.9 million, or 3%, compared to 2013, primarily due
to the cold stacking or scrapping of rigs, contract preparation work and lower repairs and maintenance expenses,
partially offset by increased costs associated with the operation of the Ocean BlackHawk and Ocean Onyx beginning
in the first quarter of 2014.
Impairment of Assets. During the third quarter of 2014, our management adopted a plan to scrap six of our mid-
water semisubmersibles. As a result of this decision, we recognized an impairment loss of $109.5 million to write
down the aggregate net book value of these rigs to their estimated recoverable amounts.
Bad Debt Expense. During 2013, based on our assessment of the financial condition of two of our customers,
Niko Resources Ltd. and OGX Petróleo e Gás Ltda., and our expectations regarding the probability of collection
of amounts due to us from them, we recorded $22.5 million in bad debt expense
Interest Expense. Interest expense increased $37.2 million during 2014, compared to 2013, primarily due to
incremental interest expense of $34.4 million, primarily related to the issuance of $1.0 billion in senior unsecured
notes in November 2013 and a $13.6 million decrease in capitalized interest as a result of rig construction projects
completed in 2014, partially offset by reduced interest expense related to $250.0 million in senior debt that we
repaid in 2014. The increase in interest expense was also partially offset by the reversal of $6.2 million of
expense in 2014 associated with changes in uncertain tax positions in the Brazil and Mexico tax jurisdictions,
combined with the absence of $5.9 million of interest expense recognized in the prior year associated with
uncertain tax positions in the Mexico tax jurisdiction.
Income Tax Expense. Our effective tax rate for 2014 was 24.9%, compared to a 29.1% effective tax rate for
2013. The lower effective tax rate in 2014 was due to differences in the mix of our domestic and international
pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operated. The lower
effective tax rate in the current period was also due to the reversal of $55.4 million of reserves for uncertain tax
positions in various foreign jurisdictions which were settled in our favor or for which the statute of limitations had
expired. During 2013, our effective tax rate was negatively impacted by a provision of $56.9 million related to an
uncertain tax position in Egypt, partially offset by the recognition of the impact of The American Taxpayer Relief
Act of 2012, which reduced 2013 income tax expense by $27.5 million.
Contract Drilling Revenue and Expense by Equipment Type
2015 Compared to 2014
Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $351.5 million
during 2015, compared to 2014, primarily as a result of 539 incremental revenue earning days ($247.6 million),
combined with higher average daily revenue earned ($103.9 million). Total revenue earning days increased in
2015, primarily due to incremental revenue earning days for our newbuild drillships (621 additional days), the
Ocean Endeavor offshore Romania (149 additional days) and the Ocean Monarch offshore Australia (105
additional days), partially offset by fewer revenue earning days for our other ultra-deepwater floaters (336 fewer
days), including the early termination of drilling contracts for the Ocean Baroness and Ocean Clipper. Average
35
daily revenue increased in 2015, compared to 2014, primarily due to revenue associated with the operation of
three additional drillships in 2015 and the Ocean Endeavor, including higher amortized mobilization and contract
preparation revenue, and a favorable dayrate adjustment for the Ocean Courage.
Contract drilling expense for our ultra-deepwater floaters increased $83.5 million during 2015, compared to
2014, reflecting incremental costs for our newbuild drillships ($153.4 million), partially offset by lower aggregate
costs for our other ultra-deepwater floaters ($69.9 million). The decrease in contract drilling expense in 2015 for
our other ultra-deepwater floaters reflected lower costs for labor and personnel ($42.6 million), repairs and
maintenance ($11.5 million), rig mobilization and inspections ($2.3 million) and other rig operating costs ($13.5
million).
Deepwater Floaters. Revenue generated by our deepwater floaters increased $54.4 million in 2015,
compared to 2014, primarily due to 133 incremental revenue earning days ($54.5 million). The increase in
revenue earning days during 2015 resulted from incremental operating days for four of our deepwater floaters
after prolonged periods of nonproductive time for planned upgrades and surveys, as well as warm-stacking
between contracts (501 incremental days), partially offset by fewer revenue earning days due to the cold stacking
of the Ocean Star (233 days) and additional non-revenue earning days for rig mobilization and repairs (135
additional days).
Contract drilling expense for our deepwater floaters decreased an aggregate $14.3 million in 2015, compared
to 2014, reflecting lower labor and personnel related costs ($10.0 million), repairs and maintenance ($17.0
million) and other rig operating costs ($7.5 million). These reductions in contract drilling expense in 2015,
compared to 2014, were partially offset by higher amortized rig mobilization expense ($20.2 million), primarily
related to drilling rigs that returned to service in 2015.
Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $689.3 million in 2015,
compared to 2014, primarily due to 2,536 fewer revenue earning days ($688.1 million) combined with lower
average daily revenue earned ($1.2 million). The reduction in revenue earning days during 2015 resulted from the
cold stacking or retirement of twelve mid-water rigs (2,638 fewer days) and the idling of the Ocean Guardian and
Ocean Quest, between contracts (288 fewer days), partially offset by incremental revenue earning days for the
upgraded Ocean Patriot operating in the North Sea (296 additional days) and the Ocean Ambassador, which is
expected to complete its contract offshore Mexico in the first quarter of 2016 (94 additional days).
Contract drilling expense for our mid-water floaters decreased $304.5 million in 2015, compared to 2015,
primarily due to reduced operating costs for our idled, cold-stacked and retired mid-water rigs ($344.1 million),
partially offset by incremental operating costs for the Ocean Patriot ($36.9 million).
Jack-ups. Contract drilling revenue and expense for our jack-up fleet decreased $93.6 million and $45.5
million, respectively, during 2015, compared to 2014, primarily due to reduced utilization for five rigs that were
under contract in 2014, but were cold stacked and marketed for sale at the end of 2015. Contract drilling revenue
for 2015 was also negatively impacted by a negotiated dayrate reduction for our remaining actively marketed
jack-up rig, the Ocean Scepter.
2014 Compared to 2013
Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $133.1 million
during 2014, compared to 2013, primarily due to higher average daily revenue earned ($219.0 million), partially
offset by the unfavorable effect of 241 fewer revenue earning days ($85.9 million). Average daily revenue
increased primarily due to several of our ultra-deepwater floaters earning higher dayrates during 2014, compared
to those earned in 2013, as well as incremental amortization of $50.6 million in mobilization and contract
preparation fees, including amounts recognized in connection with contracts for the Ocean Monarch in Indonesia
($11.3 million), the Ocean Endeavor in Romania ($22.4 million) and the Ocean Clipper in Colombia ($8.8
million). Revenue earning days decreased during 2014, compared to 2013, primarily due to incremental downtime
for planned inspections and shipyard projects (366 additional days), including the Ocean Confidence life-
extension project, non-revenue earning days between contracts (241 additional days) and rig mobilizations (95
additional days), partially offset by a reduction in unscheduled downtime for repairs (273 fewer days) and 189
revenue earning days for the Ocean BlackHawk, which was placed in service in 2014.
Contract drilling expense for our ultra-deepwater fleet decreased $2.1 million in 2014, compared to 2013, as
incremental operating costs for the Ocean BlackHawk ($44.8 million) were mostly offset by lower operating costs
36
for the Ocean Confidence ($48.3 million) as a result of the rig’s life-extension project, which began in the second
quarter of 2014.
Deepwater Floaters. Revenue generated by our deepwater floaters decreased $122.8 million during 2014
compared to 2013, primarily due to 324 fewer revenue earning days ($130.6 million), partially offset by higher
average daily revenue earned ($7.8 million), which reflected an increase in amortized mobilization and contract
preparation revenue associated with the Ocean America’s Australia contract. Revenue earning days decreased
primarily due to unplanned downtime attributable to the warm stacking of rigs between contracts (533 additional
days) and incremental downtime for planned surveys and shipyard projects (85 additional days) and rig
mobilizations (46 additional days), partially offset by 333 incremental revenue earning days for the Ocean Onyx
during 2014.
Contract drilling expense incurred by our deepwater floaters increased $24.2 million during 2014, compared
to 2013, primarily due to incremental operating costs for the Ocean Onyx ($31.5 million), costs associated with a
five-year survey for the Ocean Alliance ($18.2 million) and the mobilization of the Ocean Star to the GOM,
where it is currently cold stacked ($8.8 million). The increase in contract drilling expense in 2014 was partially
offset by a reduction in costs for international shorebase locations ($9.7 million), labor and personnel ($6.0
million), repairs and maintenance ($9.2 million), inspections ($4.0 million), agency fees ($1.8 million), and other
rig-related costs ($3.5 million), primarily as a result of lower rig utilization compared to 2013.
Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $121.1 million during 2014,
compared to 2013, primarily as a result of 217 fewer revenue earning days ($62.2 million) and lower average
daily revenue earned ($58.9 million). The decline in revenue earning days for 2014 reflected a 652-day increase
in unplanned downtime, primarily due to the cold stacking of rigs, unpaid equipment repairs and downtime
between contracts, partially offset by a 435-day reduction in planned downtime for shipyard projects and
regulatory inspections. Average daily revenue earned during 2014 decreased, compared to 2013, primarily due to
lower amortized mobilization and contract preparation revenue ($35.9 million) and a significantly lower dayrate
earned by the Ocean Quest operating in Vietnam, partially offset by higher dayrates earned by our rigs operating
in the North Sea during 2014.
Contract drilling expense for our mid-water fleet decreased $69.4 million during 2014, compared to 2013,
primarily due to reduced costs for cold stacked rigs and retired rigs ($46.3 million) and the Ocean Patriot, which
was out of service until the fourth quarter of 2014 for an enhancement project and contract preparation activities
($9.6 million). In addition, contract drilling expense incurred by our actively-marketed mid-water fleet in 2014,
compared to 2013, reflected lower aggregate costs for shipyard projects and regulatory inspections ($24.4 million)
and mobilization of rigs ($14.5 million), partially offset by higher labor and personnel costs ($23.4 million).
Jack-ups. Contract drilling revenue for our jack-up fleet increased $4.4 million during 2014, compared to
2013, primarily due to an increase in average daily revenue earned ($13.7 million), as a result of higher dayrates
earned by several of our jack-up rigs during 2014, partially offset by 104 fewer revenue earning days compared to
2013 ($9.3 million). Contract drilling expense decreased $3.9 million in 2014, compared to 2013, primarily due
to lower costs associated the mobilization of rigs ($6.6 million), partially offset by higher labor and personnel-
related costs ($3.4 million).
Liquidity and Capital Resources
We have historically relied principally on our cash flows from operations and cash reserves to meet liquidity
needs and fund our cash requirements. However, in 2015, we also utilized short-term borrowings under our $1.5
billion syndicated revolving credit agreement, or Credit Agreement, and issued commercial paper under our
commercial paper program to meet our short-term liquidity needs. At February 16, 2016, we had $305.0 million
in Eurodollar loans outstanding under the Credit Agreement[, which will mature on February 29, 2016]. See “ –
Credit Agreement, Commercial Paper Program and Senior Notes.”
Based on our cash available for current operations and contractual backlog of $5.2 billion, as of February 8,
2016, of which $1.6 billion is expected to be realized in 2016, we believe future capital spending, including the
final installment due on the Ocean GreatWhite and debt service requirements, will be funded from our cash and
cash equivalents, future operating cash flows and borrowings under our Credit Agreement and/or the issuance of
commercial paper. See “– Cash Flow and Capital Expenditures – Contractual Cash Obligations – Rig
Construction” and “Risk Factors (cid:16) We can provide no assurance that our drilling contracts will not be terminated
early or that our current backlog of contract drilling revenue will be ultimately realized.”
37
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset
Company, or DFAC, and, as a result of our intention to indefinitely reinvest the earnings of DFAC and its foreign
subsidiaries to finance our foreign activities, we do not expect such earnings to be available for distribution to our
stockholders or to finance our domestic activities. See “ – Market Overview – Critical Accounting Estimates –
Income Taxes.” To the extent available, we expect to utilize the operating cash flows generated by and cash
reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc.,
or DODI, to meet each entity’s respective working capital requirements and capital commitments.
At December 31, 2015, 2014 and 2013, we had cash available for current operations, including cash reserves
of DFAC, as follows:
Cash and equivalents ...................................................
Marketable securities ...................................................
Total cash available for current operations ............
$
119,028
11,518
$ 130,546
2015
December 31,
2014
(In thousands)
233,623
16,033
$ 249,656
$
2013
$
347,011
1,750,053
$ 2,097,064
A substantial portion of our cash flows has been invested in the enhancement of our drilling fleet, including
$3.8 billion since 2013 for the construction of five newbuild rigs, the major upgrade of two semisubmersible rigs
and other capital enhancement projects. We determine the amount of cash required to meet our capital
commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer
requirements and our ongoing rig equipment enhancement/replacement programs. We also make periodic
assessments of our capital spending programs based on current and expected industry conditions and make
adjustments thereto if required. See “– Cash Flow and Capital Expenditures – Contractual Cash Obligations – Rig
Construction.” We pay dividends at the discretion of our Board of Directors, or Board. During the three-year
period ended December 31, 2015, we paid regular and special cash dividends totaling $206.9 million and $829.9
million, respectively. Our Board has adopted a policy of considering paying cash dividends, in amounts to be
determined, on a quarterly basis. Any determination to declare a dividend, as well as the amount of any dividend
that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings
outlook, capital spending plans, outlook on current and future market conditions and business needs and other
factors that our Board of Directors considers relevant at that time. Our dividend policy may change from time to
time, and there can be no assurance that we will continue to declare any cash dividends at all or in any particular
amounts.
On February 8, 2016, we announced that we were discontinuing our quarterly regular cash dividend. See
“Risk Factors – Although we have paid cash dividends in the past, we may not pay regular or special cash
dividends in the future and we can give no assurance as to the amount or timing of the payment of any future
regular or special cash dividends” in Item 1A of this report, which is incorporated herein by reference.
Depending on market conditions, we may, from time to time, purchase shares of our common stock in the
open market or otherwise. During 2014, we repurchased 1,895,561 shares of our outstanding common stock at a
cost of $87.8 million. In addition, Loews has informed us that, depending on market and other conditions, it may,
from time to time, purchase shares of our common stock in the open market or otherwise. During the years ended
December 31, 2015, 2014 and 2013, Loews purchased 1,134,827, 1,879,600 and 0, shares of our common stock,
respectively.
During the three-year period ended December 31, 2015, our primary source of cash was an aggregate $2.8
billion generated from operating activities, $1.1 billion net proceeds from the sale or maturity of marketable
securities in 2014 and 2013, net of purchases, $987.8 million net proceeds from the issuance of senior notes in
2013, $286.6 million net proceeds/repayments from the issuance of commercial paper in 2015 and an aggregate
$25.7 million from the sale of 12 drilling rigs during 2015 and 2014. Cash usage during the same period was
primarily for capital expenditures ($3.8 billion), payment of dividends and anti-dilution payments to stock plan
participants ($1.0 billion), long-term debt maturities ($250.0 million in each of 2015 and 2014) and the acquisition
of treasury stock ($87.8 million) in 2014.
We may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital
expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the
38
capital markets by issuing debt or equity securities will be dependent on our results of operations, our current
financial condition, current credit ratings, current market conditions and other factors beyond our control.
Cash Flow and Capital Expenditures
Our cash flow from operations and capital expenditures for each of the years in the three-year period ended
December 31, 2015 were as follows:
Cash flow from operations ...........................................
$
736,427 $
$ 1,065,988
2015
Year Ended December 31,
2014
(In thousands)
992,831
2013
Capital expenditures:
Drillship construction ...............................................
Major upgrade of deepwater floaters ........................
Construction of ultra-deepwater floater ....................
Ocean Patriot enhancement program .......................
Ocean Confidence service-life-extension project .....
Rig equipment and replacement program .................
Total capital expenditures .....................................
$ 454,093
34,723
55,805
2,669
72,124
211,241
830,655
$
$ 1,318,271
168,045
18,223
107,181
134,871
286,173
$ 2,032,764
$
$
130,268
396,584
195,578
29,948
--
205,220
957,598
Cash Flow. Cash flow from operations decreased approximately $256.4 million during 2015, compared to
2014, primarily due to lower cash receipts from contract drilling services ($444.8 million), partially offset by a
$144.4 million net decrease in cash payments for contract drilling and general and administrative expenses,
including personnel-related, maintenance, mobilization and other rig operating costs and lower income taxes paid,
net of refunds ($44.0 million). The decline in cash receipts from and cash payments related to contract drilling
services both reflect an aggregate decline in our contract drilling operations, as well as our efforts to control costs.
Cash flow from operations decreased approximately $73.2 million during 2014, compared to 2013, primarily
due to higher cash payments for contract drilling expenses ($77.0 million) and higher interest paid on our senior
notes ($50.8 million) related to interest paid on $1.0 billion in debt issued in November 2013 and an early interest
payment for our 4.875% senior notes due July 1, 2015. The increase in cash outflows for 2014 was partially
offset by lower income taxes paid, in the U.S. federal jurisdiction, net of refunds, and a slight increase in cash
receipts from contract drilling services ($6.5 million).
See “--Results of Operations--Years Ended December 31, 2015, 2014 and 2013.”
Capital Expenditures. As of the date of this report, we expect capital expenditures for 2016 to aggregate
approximately $675.0 million, of which we expect to spend approximately $525.0 million to complete
construction of the Ocean GreatWhite and an estimated $150.0 million for our ongoing capital maintenance and
replacement programs. See “ -- Contractual Cash Obligations -- Rig Construction.” We expect to fund our 2016
capital spending from the operating cash flows generated by and cash reserves of DFAC and the operating cash
flows available to and cash reserves of DODI, as well as borrowings under our Credit Agreement or issuance of
commercial paper.
Contractual Cash Obligations - Rig Construction. As of the date of this report, we have one rig, the Ocean
GreatWhite, under construction in Ulsan, South Korea, for which we are obligated under a construction agreement
with Hyundai Heavy Industries Co., Ltd. Construction of the Ocean GreatWhite continues with delivery expected
in mid-2016. The estimated total project cost, including shipyard costs, capital spares, commissioning, project
management and shipyard supervision, but excluding capitalized interest, is $764.0 million, of which $241.5
million has been incurred as of December 31, 2015. See Note 12 “Commitments and Contingencies” to our
Consolidated Financial Statements included in Item 8 of this report for more information about this project.
We had no other purchase obligations for major rig upgrades or any other significant obligations at December
31, 2015, except for those related to our direct rig operations, which arise during the normal course of business.
Credit Agreement, Commercial Paper Program and Senior Notes
Our Credit Agreement provides for a $1.5 billion senior unsecured revolving credit facility for general corporate
39
purposes maturing on October 22, 2020, except for $40 million of commitments that mature on March 17, 2019 and
$60 million of commitments that mature on October 22, 2019. As of December 31, 2015, there were no loans or
letters of credit outstanding under the Credit Agreement, and we were in compliance with all covenant requirements
under the Credit Agreement.
Our Credit Agreement also provides liquidity for our payment obligations in respect of notes issued under our
commercial paper program. Under our commercial paper program, we may issue, on a private placement basis,
unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5
billion,and, unless we change the terms of the program, the aggregate amount of commercial paper notes and total
loans and letters of credit outstanding under the Credit Agreement at any time will not exceed $1.5 billion. At
December 31, 2015, we had $286.6 million in commercial paper notes outstanding with a weighted average interest
rate of 0.86% and a weighted average remaining term of 5.8 days that were repaid in January 2016. As of February
16, 2016, we had no commercial paper notes outstanding.
During February 2016, we borrowed $305.0 million in Eurodollar loans under our Credit Agreement, which
bear interest at 1.565% and mature on February 29, 2016. As of February 16, 2016, we had an additional $1.2 billion
available under the Credit Agreement.
As of December 31, 2015, we had an aggregate $2.0 billion in long-term, unsecured senior notes outstanding, of
which $500.0 million will mature in 2019 and the remainder will mature at various times beginning in 2023.
See Note 10 “Credit Agreement and Senior Notes” to our Consolidated Financial Statements in Item 8 of this
report.
Credit Ratings. In January 2016, Moody’s Investor Services announced that it would be reviewing our long-
term corporate credit and unsecured debt rating and short-term credit rating for commercial paper, which are
currently Baa2 and Prime-2, respectively, for possible downgrade. Our current corporate credit rating is BBB+
and our short-term credit rating is A2 for Standard & Poor's Ratings Services. Market conditions and other
factors, many of which are outside of our control, could cause our credit ratings to be lowered. A downgrade in
our credit ratings could adversely impact our cost of issuing additional debt and the amount of additional debt that
we could issue, and could restrict our access to our commercial paper program and capital markets and our ability
to raise additional debt or rollover existing maturities. As a consequence, we may not be able to issue additional
debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit
our ability to pursue other business opportunities.
Contractual Cash Obligations
The following table sets forth our contractual cash obligations at December 31, 2015.
Payments Due By Period
Contractual Obligations(1)
Total
Less than
1 year
Long-term debt (principal and interest) .......... $ 3,879,563
439,962
Construction contract ....................................
Operating leases ............................................. 4,565
Total obligations ............................................. $ 4,324,090
$ 103,063
439,962
2,673
$ 545,698
1 – 3 years
(In thousands)
$ 206,125
--
1,705
$ 207,830
4 – 5 years
After 5
years
$ 662,063
--
103
$ 662,166
$ 2,908,312
--
84
$ 2,908,396
(1) The above table excludes $49.4 million of unrecognized tax benefits related to uncertain tax positions as
of December 31, 2015 and an additional $39.9 million and $2.7 million for potential penalties and
interest, respectively, related to such uncertain tax positions. Due to the high degree of uncertainty
regarding the timing of future cash outflows associated with the liabilities recognized in these balances,
we are unable to make reasonably reliable estimates of the period of cash settlement with the respective
taxing authorities.
Except for the construction contracts discussed above and referred to in the preceding table, we had no other
purchase obligations for major rig upgrades or any other significant obligations at December 31, 2015, except for
those related to our direct rig operations, which arise during the normal course of business.
40
In February 2016, we entered into a ten-year agreement with GE Oil & Gas, or GE, to provide services with
respect to certain blowout preventer and related well control equipment on our four newbuild drillships. Such
services include management of maintenance, certification and reliability with respect to such equipment. In
connection with the services agreement with GE, we will sell the equipment to a GE affiliate for an aggregate
$210.0 million and will lease back such equipment over separate ten-year operating leases. We do not expect to
realize any gain or loss on these sale and leaseback transactions. Future commitments for the full term under the
services agreement and leases are estimated to aggregate approximately $650.0 million.
Other Commercial Commitments - Letters of Credit
We were contingently liable as of December 31, 2015 in the amount of $71.6 million under certain
performance, supersedeas, bid, tax and customs bonds and letters of credit. Agreements relating to approximately
$64.0 million of performance, tax, supersedeas, court and customs bonds can require collateral at any time. As of
December 31, 2015, we had not been required to make any collateral deposits with respect to these agreements.
The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit
on our behalf securing certain of these bonds. The table below provides a list of these obligations in U.S. dollar
equivalents and their time to expiration.
Total
For the Years Ending December 31,
2018
2017
2016
(In thousands)
Other Commercial Commitments
Performance bonds ......................... $
Supersedeas bond ............................
Bid bonds
.....................................
Tax bond
Other ................................................
Total obligations ................................. $
51,357 $
9,189
2,470
5,865
6,122
9,189
2,470
5,865
2,669
71,550 $
2,345
25,991
$
26,110 $
--
19,125
--
--
--
--
$
26,110 $
--
--
324
19,449
Off-Balance Sheet Arrangements
At December 31, 2015 and 2014, we had no off-balance sheet debt or other off-balance sheet arrangements.
Other
Currency Risk. Some of our subsidiaries conduct a portion of their operations in the local currency of the
country where they conduct operations. Currency environments in which we have significant business operations
include Brazil, the U.K., Australia and Mexico. We may, if possible, attempt to minimize our currency exchange
risk by seeking international contracts payable to us in local currency in amounts equal to our estimated operating
costs payable in local currency, with the balance of the contract payable in U.S. dollars. At present, however,
only a limited number of our contracts are payable both in U.S. dollars and the local currency.
Historically, to the extent that we have not been able to cover our local currency operating costs with
customer payments in the local currency, we have also utilized foreign currency forward exchange, or FOREX,
contracts to reduce our currency exchange risk. We currently have no outstanding FOREX contracts.
We record currency transaction gains and losses as “Foreign currency transaction gain (loss)” in our
Consolidated Statements of Operations. Gains and losses arising from the settlement of our FOREX contracts that
have been designated as cash flow hedges are reported as a component of “Contract drilling, excluding
depreciation” expense in our Consolidated Statements of Operations.
Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise,
make or incorporate by reference certain written or oral statements that are “forward-looking statements” within
the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of
the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of
historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include,
without limitation, any statement that may project, indicate or imply future results, events, performance or
41
achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,”
“estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,”
“project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial
performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies
or prospects, and possible actions taken by or against us, which may be provided by management, are also
forward-looking statements as so defined. Statements made by us in this report that contain forward-looking
statements may include, but are not limited to, information concerning our possible or assumed future results of
operations and statements about the following subjects:
(cid:120) market conditions and the effect of such conditions on our future results of operations;
(cid:120)
sources and uses of and requirements for financial resources and sources of liquidity;
(cid:120)
interest rate and foreign exchange risk;
(cid:120)
contractual obligations and future contract negotiations;
(cid:120)
operations outside the United States;
(cid:120)
business strategy;
(cid:120)
growth opportunities;
(cid:120)
competitive position, including without limitation, competitive rigs entering the market;
(cid:120)
expected financial position;
(cid:120)
cash flows and contract backlog;
(cid:120)
declaration and payment of regular or special dividends;
(cid:120)
financing plans;
(cid:120) market outlook;
(cid:120)
tax planning;
(cid:120)
debt levels and the impact of changes in the credit markets and credit ratings for our debt;
(cid:120)
budgets for capital and other expenditures;
(cid:120)
timing and duration of required regulatory inspections for our drilling rigs;
(cid:120)
timing and cost of completion of rig upgrades, construction projects and other capital projects;
(cid:120)
delivery dates and drilling contracts related to rig conversion or upgrade projects, construction
projects, other capital projects or rig acquisitions;
plans and objectives of management;
idling drilling rigs or reactivating stacked rigs;
scrapping retired rigs;
assets held for sale;
asset impairments and impairment evaluations;
effective date and performance of contracts;
outcomes of legal proceedings;
purchases of our securities;
compliance with applicable laws; and
availability, limits and adequacy of insurance or indemnification.
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
These types of statements are based on current expectations about future events and inherently are subject to a
variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual
results to differ materially from those expected, projected or expressed in forward-looking statements. These risks
and uncertainties include, among others, the following:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
those described under “Risk Factors” in Item 1A;
general economic and business conditions;
worldwide supply and demand for oil and natural gas;
changes in foreign and domestic oil and gas exploration, development and production activity;
oil and natural gas price fluctuations and related market expectations;
the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain
production levels and pricing, and the level of production in non-OPEC countries;
policies of various governments regarding exploration and development of oil and gas reserves;
inability to obtain contracts for our rigs that do not have contracts;
the cancellation of contracts included in our reported contract backlog;
advances in exploration and development technology;
the worldwide political and military environment, including, for example, in oil-producing regions
and locations where our rigs are operating or where we have rigs under construction;
42
(cid:120)
(cid:120)
(cid:120)
(cid:120)
casualty losses;
operating hazards inherent in drilling for oil and gas offshore;
the risk that future regular and special dividends may not be declared or paid;
the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of
Mexico;
industry fleet capacity;
(cid:120)
(cid:120) market conditions in the offshore contract drilling industry, including, without limitation, dayrates
and utilization levels;
competition;
changes in foreign, political, social and economic conditions;
risks of international operations, compliance with foreign laws and taxation policies and seizure,
expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of
equipment and assets;
risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time
to time;
customer or supplier bankruptcy, liquidation or other financial difficulties;
the ability of customers and suppliers to meet their obligations to us and our subsidiaries;
collection of receivables;
the risk that a letter of intent may not result in a definitive agreement;
foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or
capital;
risks of war, military operations, other armed hostilities, terrorist acts and embargoes;
changes in offshore drilling technology, which could require significant capital expenditures in order
to maintain competitiveness;
regulatory initiatives and compliance with governmental regulations including, without limitation,
regulations pertaining to climate change, greenhouse gases, carbon emissions or energy use;
compliance with and liability under environmental laws and regulations;
potential changes in accounting policies by the Financial Accounting Standards Board, the Securities
and Exchange Commission, or SEC, or regulatory agencies for our industry which may cause us to
revise our financial accounting and/or disclosures in the future, and which may change the way
analysts measure our business or financial performance;
development and exploitation of alternative fuels;
customer preferences;
effects of litigation, tax audits and contingencies and the impact of compliance with judicial rulings
and jury verdicts;
cost, availability, limits and adequacy of insurance;
invalidity of assumptions used in the design of our controls and procedures;
the results of financing efforts;
adequacy and availability of our sources of liquidity;
risks resulting from our indebtedness;
public health threats;
negative publicity;
impairments of assets;
the availability of qualified personnel to operate and service our drilling rigs; and
various other matters, many of which are beyond our control.
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
The risks and uncertainties included here are not exhaustive. Other sections of this report and our other
filings with the SEC include additional factors that could adversely affect our business, results of operations and
financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-
looking statements. Forward-looking statements included in this report speak only as of the date of this report.
We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-
looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change
in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain
places in this report, we may refer to reports published by third parties that purport to describe trends or
developments in energy production or drilling and exploration activity. We do so for the convenience of our
investors and potential investors and in an effort to provide information available in the market intended to lead to
a better understanding of the market environment in which we operate. We specifically disclaim any responsibility
for the accuracy and completeness of such information and undertake no obligation to update such information.
43
New Accounting Pronouncements
For a discussion of recent accounting pronouncements, which are not yet effective, and their effect on our
financial position, results of operations and cash flows, see Note 1 “General Information - Recent Accounting
Pronouncements” to our Consolidated Financial Statements in Item 8 of this report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The information included in this Item 7A is considered to constitute “forward-looking statements” for
purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the
Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Forward-Looking Statements” in Item 7 of this report.
Our measure of market risk exposure represents an estimate of the change in fair value of our financial
instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31,
2015 and 2014, assuming immediate adverse market movements of the magnitude described below. We believe
that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically
assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future
earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse
conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is
subject to change based on our portfolio management strategy as well as in response to changes in the market,
these estimates are not necessarily indicative of the actual results that may occur.
Exposure to market risk is managed and monitored by our senior management. Senior management approves
the overall investment strategy that we employ and has responsibility to ensure that the investment positions are
consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling
instruments or entering into offsetting positions.
Interest Rate Risk
We have exposure to interest rate risk arising from changes in the level or volatility of interest rates. Our
investments in marketable securities are primarily in fixed maturity securities. We monitor our sensitivity to
interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in
interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying
magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded
market value of our investments and the resulting effect on stockholders’ equity. The analysis presents the
sensitivity of the market value of our financial instruments to selected changes in market rates and prices which
we believe are reasonably possible over a one-year period.
The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities
that were held on December 31, 2015 and 2014, due to instantaneous parallel shifts in the yield curve of 100 basis
points, with all other variables held constant.
The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market
interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis
may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of
changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not
contemplate any actions we could undertake in response to changes in interest rates.
Our long-term debt, as of December 31, 2015 and 2014, is denominated in U.S. dollars. Our existing debt has
been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact
of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of
$112.7 million and $176.8 million as of December 31, 2015 and 2014, respectively. A 100-basis point decrease
would result in an increase in market value of $131.3 million and $210.6 million as of December 31, 2015 and
2014, respectively.
Foreign Exchange Risk
Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will
44
impact the value of financial instruments. It is customary for us to enter into FOREX contracts in the normal
course of business. These contracts generally require us to net settle the spread between the contracted foreign
currency exchange rate and the spot rate on the contract settlement date, which for most of our contracts is the
average spot rate for the contract period. As of December 31, 2015, we had no FOREX contracts outstanding. At
December 31, 2014, we have presented the fair value of our outstanding FOREX contracts as a current liability of
$(5.4) million in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of this report.
The following table presents our exposure to market risk by category (interest rates and foreign currency
exchange rates):
Fair Value Asset (Liability)
December 31,
2015
2014
Market Risk
December 31,
2015
2014
(In thousands)
Interest rate:
Marketable securities ................... $ 11,500 (a) $
16,000 (a)
$
(300) (b) $
(600) (b)
Foreign Exchange:
Forward exchange contracts –
liability positions ..........................
--
(5,400) (c)
--
(12,100) (d)
(a) The fair market value of our investment in marketable securities, excluding repurchase agreements, is
based on the quoted closing market prices on December 31, 2015 and 2014.
(b) The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying
reference price or index of an increase in interest rates of 100 basis points at December 31, 2015 and
2014.
(c) The fair value of our foreign currency forward exchange contracts is based on both quoted market prices
and valuations derived from pricing models on December 31, 2014.
(d) The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign
currency exchange rates versus the U.S. dollar from their values at December 31, 2014, with all other
variables held constant.
45
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Diamond Offshore Drilling, Inc. and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and
subsidiaries (the "Company") as of December 31, 2015 and 2014, and the related consolidated statements of
income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position
of Diamond Offshore Drilling, Inc. and subsidiaries at December 31, 2015 and 2014, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity
with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the Company's internal control over financial reporting as of December 31, 2015, based on the
criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 19, 2016 expressed an unqualified
opinion on the Company's internal control over financial reporting.
/s/ Deloitte & Touche LLP
Houston, Texas
February 19, 2016
46
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Diamond
Offshore Drilling, Inc. and Subsidiaries Houston, Texas
We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries
(the "Company") as of December 31, 2015, based on criteria established in Internal Control — Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The
Company's management is responsible for maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item
9A of this Form 10-K under the heading “Management’s Annual Report on Internal Control Over Financial
Reporting.” Our responsibility is to express an opinion on the Company's internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the
company's principal executive and principal financial officers, or persons performing similar functions, and
effected by the company's board of directors, management, and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company's internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of
collusion or improper management override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal
control over financial reporting to future periods are subject to the risk that the controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2015, based on the criteria established in Internal Control — Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated financial statements as of and for the year ended December 31, 2015 of the
Company and our report dated February 19, 2016 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Houston, Texas
February 19, 2016
47
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
December 31,
2015
2014
Current assets:
ASSETS
Cash and cash equivalents .......................................................................... $
Marketable securities ..................................................................................
Accounts receivable, net of allowance for bad debts ..................................
Prepaid expenses and other current assets ..................................................
Assets held for sale .....................................................................................
Total current assets .............................................................................
Drilling and other property and equipment, net of
accumulated depreciation ........................................................................
Other assets .................................................................................................
Total assets ......................................................................................... $
119,028 $
11,518
405,370
119,479
14,200
669,595
233,623
16,033
463,862
185,541
--
899,059
6,378,814
116,480
7,164,889 $
6,945,953
176,277
8,021,289
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable ....................................................................................... $
Accrued liabilities ......................................................................................
Taxes payable .............................................................................................
Short-term borrowings ...............................................................................
Current portion of long-term debt ..............................................................
Total current liabilities .......................................................................
Long-term debt ...........................................................................................
Deferred tax liability ..................................................................................
Other liabilities ...........................................................................................
Total liabilities....................................................................................
70,272 $
253,769
15,093
286,589
--
625,723
1,994,773
276,529
155,094
3,052,119
138,444
426,592
41,648
--
249,962
856,646
1,994,526
530,394
188,160
3,569,726
Commitments and contingencies (Note 12)
Stockholders’ equity:
Preferred stock (par value $0.01, 25,000,000 shares authorized, none
issued and outstanding) ..........................................................................
Common stock (par value $0.01, 500,000,000 shares authorized;
143,978,877 shares issued and 137,158,706 shares outstanding at
December 31, 2015; 143,960,260 shares issued and 137,147,899 shares
outstanding at December 31, 2014) .........................................................
Additional paid-in capital ...........................................................................
Retained earnings .......................................................................................
Accumulated other comprehensive gain (loss) ..........................................
Treasury stock, at cost (6,820,171 and 6,812,361 shares of common stock
at December 31, 2015 and 2014, respectively) .......................................
Total stockholders’ equity ..................................................................
Total liabilities and stockholders’ equity ............................................ $
--
--
1,440
1,999,634
2,319,136
(5,035)
(202,405)
4,112,770
7,164,889 $
1,440
1,993,898
2,661,999
(3,605)
(202,169)
4,451,563
8,021,289
The accompanying notes are an integral part of the consolidated financial statements.
48
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Year Ended December 31,
2015
2014
2013
Revenues:
Contract drilling ....................................................... $
Revenues related to reimbursable expenses .............
Total revenues ................................................
$
2,360,184
59,209
2,419,393
2,737,126 $
77,545
2,814,671
2,843,584
76,837
2,920,421
Operating expenses:
Contract drilling, excluding depreciation .................
Reimbursable expenses ............................................
Depreciation .............................................................
General and administrative ......................................
Impairment of assets ................................................
Bad debt expense .....................................................
Restructuring and separation costs ...........................
Gain on disposition of assets ....................................
Total operating expenses ................................
1,227,864
58,050
493,162
66,462
860,441
--
9,778
(2,290)
2,713,467
1,523,623
76,091
456,483
81,832
109,462
--
--
(5,382)
2,242,109
1,572,525
74,967
388,092
64,788
--
22,513
--
(4,070)
2,118,815
Operating (loss) income ....................................................
(294,074)
572,562
801,606
Other income (expense):
Interest income .........................................................
Interest expense, net of amounts capitalized ............
Foreign currency transaction gain (loss) ..................
Other, net .................................................................
(Loss) income before income tax benefit (expense) ....... .
3,322
(93,934)
2,465
873
(381,348)
801
(62,053)
3,199
682
515,191
701
(24,843)
(4,915)
1,691
774,240
Income tax benefit (expense) ............................................
107,063
(128,180)
(225,554)
Net (loss) income ...............................................................
$
(274,285)
$
387,011
$
548,686
(Loss) earnings per share:
Basic .............................................................................. $
Diluted ........................................................................... $
(2.00) $
(2.00) $
2.82 $
2.81 $
3.95
3.95
Weighted-average shares outstanding:
Shares of common stock ..........................................
Dilutive potential shares of common stock ..............
Total weighted-average shares outstanding .........
137,157
--
137,157
137,473
50
137,523
139,035
29
139,064
Cash dividends declared per share of common stock .......... $ 0.50
$
3.50 $
3.50
The accompanying notes are an integral part of the consolidated financial statements.
49
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME OR LOSS
(In thousands)
Year Ended December 31,
2014
2013
2015
Net (loss) income ......................................................................... $
(274,285) $
387,011
$
548,686
Other comprehensive (losses) gains, net of tax:
Derivative financial instruments:
Unrealized holding loss .......................................................
Reclassification adjustment for loss (gain) included in net
income .............................................................................
(1,574)
5,084
(1,482)
(2,379)
(6,833)
4,840
Investments in marketable securities:
Unrealized holding loss on investments ..............................
Reclassification adjustment for gain included in net
income .............................................................................
Total other comprehensive loss ..........................................
(4,940)
(69)
(6)
--
(1,430)
(25)
(3,955)
383,056
(147)
(2,146)
$ 546,540
Comprehensive (loss) income .................................................... $ (275,715) $
The accompanying notes are an integral part of the consolidated financial statements.
50
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except number of shares)
January 1, 2013 ..................... 143,948,370
1,439
Common Stock
Shares
Amount
Additional
Paid-In
Capital
1,983,957
Net income ..............................
Dividends to stockholders
($3.50 per share) .....................
Anti-dilution adjustment
paid to stock plan
participants ($3.00 per
share) .......................................
Stock options exercised ..........
Stock-based compensation,
net of tax .................................
Net loss on derivative
financial instruments ............
Net loss on investments ..........
--
--
--
3,878
--
--
--
--
--
--
1
--
--
--
--
--
--
109
4,654
--
--
December 31, 2013 ................ 143,952,248
1,440
1,988,720
Net income ..............................
Dividends to stockholders
($3.50 per share) .....................
Anti-dilution adjustment
paid to stock plan
participants ($3.00 per
share) .......................................
Treasury stock purchase .........
--
--
--
--
Stock options exercised ..........
8,012
Stock-based compensation,
net of tax .................................
Net loss on derivative
financial instruments ..............
Net loss on investments ..........
--
--
--
--
--
--
--
--
--
--
--
--
--
213
4,965
--
Retained
Earnings
2,702,915
548,686
(486,620)
(3,820)
--
--
--
--
2,761,161
387,011
(481,642)
(4,531)
--
--
--
--
Accumulated
Other
Comprehensive
Gains (Losses)
2,496
--
--
--
--
--
(1,993)
(153)
Shares
4,916,800
--
--
--
--
--
--
--
Treasury Stock
Total
Stockholders’
Equity
4,576,394
Amount
(114,413)
--
--
--
--
--
--
--
548,686
(486,620)
(3,820)
110
4,654
(1,993)
(153)
350
4,916,800
(114,413)
4,637,258
--
--
--
--
--
--
(3,861)
--
--
--
--
--
--
--
--
--
1,895,561
(87,756)
--
--
--
--
--
--
--
--
6,812,361
(202,169)
--
--
--
--
387,011
(481,642)
(4,531)
(87,756)
213
4,965
(3,861)
(94)
4,451,563
(274,285)
(68,578)
7,810
(236)
5,500
3,510
(4,940)
--
--
--
--
3,510
(4,940)
--
December 31, 2014 ................ 143,960,260
--
1,440
--
1,993,898
--
2,661,999
(94)
(3,605)
Net loss....................................
Dividends to stockholders
($0.50 per share) .....................
Stock-based compensation,
net of tax .................................
Net gain on derivative
financial instruments ..............
Net loss on investments ..........
--
--
18,617
--
--
--
--
--
--
--
--
--
5,736
--
--
(274,285)
(68,578)
--
--
--
December 31, 2015 ................ 143,978,877
$
1,440 $ 1,999,634 $ 2,319,136
$
(5,035)
6,820,171 $ (202,405) $ 4,112,770
The accompanying notes are an integral part of the consolidated financial statements.
51
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
2015
2014
2013
(274,285)
$
387,011
$
548,686
Operating activities:
Net (loss) income ................................................................................. $
Adjustments to reconcile net (loss) income to net cash
provided by operating activities:
Depreciation ......................................................................................
Loss on impairment of assets ............................................................
Gain on disposition of assets .............................................................
Bad debt expense ..............................................................................
Loss (gain) on foreign currency forward exchange contracts ............
Deferred tax provision .....................................................................
Stock-based compensation expense ..................................................
Deferred income, net .........................................................................
Deferred expenses, net ......................................................................
Long-term employee remuneration programs ...................................
Other assets, noncurrent ....................................................................
Other liabilities, noncurrent ..............................................................
(Payments of) proceeds from settlement of foreign currency forward
exchange contracts designated as accounting hedges .........................
493,162
860,441
(2,290)
--
8,364
(242,034)
4,856
(45,383)
(26,405)
(1,838)
2,483
(3,890)
(8,364)
1,069
1,627
Bank deposits denominated in nonconvertible currencies....................
Other ....................................................................................................
Changes in operating assets and liabilities:
Accounts receivable ..........................................................................
Prepaid expenses and other current assets .........................................
Accounts payable and accrued liabilities ..........................................
Taxes payable ...................................................................................
Net cash provided by operating activities .......................................
Investing activities:
Capital expenditures (including rig construction) .............................
Proceeds from disposition of assets, net of disposal costs .................
Proceeds from sale and maturities of marketable securities ..............
Purchases of marketable securities ....................................................
Net cash used in investing activities ...............................................
Financing activities:
Repayment of long-term debt............................................................
Issuance of senior notes ....................................................................
Proceeds from short-term borrowings, net of repayments .................
Debt issuance costs and arrangement fees ........................................
Payment of dividends and anti-dilution payments ............................
Purchase of treasury stock .................................................................
Other .................................................................................................
Net cash (used in) provided by financing activities ........................
Net change in cash and cash equivalents ............................................
Cash and cash equivalents, beginning of year ...................................
Cash and cash equivalents, end of year ............................................. $
58,872
19,195
(180,872)
71,719
736,427
(830,655)
13,049
51
--
(817,555)
(250,000)
--
286,589
(624)
(69,432)
--
--
(33,467)
(114,595)
233,623
119,028
456,483
109,462
(5,382)
--
(3,275)
1,532
3,507
60,061
(82,814)
1,195
2,881
(3,979)
388,092
--
(4,070)
22,513
6,501
34,101
3,573
(54,274)
25,604
8,966
(4,922)
(5,296)
3,275
5,520
1,923
(6,501)
(12,741)
1,247
5,269
(2,791)
27,463
25,490
992,831
(2,032,764)
18,318
8,000,057
(6,265,846)
(280,235)
7,905
10,066
46,752
49,786
1,065,988
(957,598)
4,900
4,650,085
(5,249,462)
(1,552,075)
(250,000)
--
--
(2,249)
(486,240)
(87,756)
261
(825,984)
(113,388)
347,011
233,623
$
--
997,805
--
(9,973)
(490,331)
--
165
497,666
11,579
335,432
347,011
$
The accompanying notes are an integral part of the consolidated financial statements.
52
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General Information
Diamond Offshore Drilling, Inc. is a leader in offshore drilling, providing contract drilling services to the
energy industry around the globe with a fleet of 32 offshore drilling rigs, consisting of eight ultra-deepwater,
seven deepwater and eight mid-water semisubmersibles, four dynamically positioned drillships and five jack-ups.
Unless the context otherwise requires, references in these Notes to “Diamond Offshore,” “we,” “us” or “our”
mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in
1989.
As of February 16, 2016, Loews Corporation, or Loews, owned 53% of the outstanding shares of our
common stock.
Principles of Consolidation
Our consolidated financial statements include the accounts of Diamond Offshore Drilling, Inc. and our
subsidiaries after elimination of intercompany transactions and balances.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the
United States, or U.S., or GAAP, requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amount of revenues and expenses during the reporting period. Actual results could
differ from those estimated.
Cash and Cash Equivalents
We consider short-term, highly liquid investments that have an original maturity of three months or less and
deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.
The effect of exchange rate changes on cash balances held in foreign currencies was not material for the years
ended December 31, 2015, 2014 and 2013.
Marketable Securities
We classify our investments in marketable securities as available for sale and they are stated at fair value in
our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our
Consolidated Balance Sheets in “Accumulated other comprehensive gain (loss)” until realized. The cost of debt
securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments
are included in our Consolidated Statements of Operations in “Interest income.” The sale and purchase of
securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific
identification method. Realized gains or losses, as well as any declines in value that are judged to be other than
temporary, are reported in our Consolidated Statements of Operations in “Other income (expense) – Other, net.”
See Note 6.
Provision for Bad Debts
We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a
customer receivable may not be collectible. In establishing these reserves, we consider historical and other factors
that predict collectability, including write-offs, recoveries and the monitoring of credit quality. Such provision is
reported as a component of “Operating expense” in our Consolidated Statements of Operations. See Note 3.
53
Derivative Financial Instruments
Our derivative financial instruments have primarily consisted of foreign currency forward exchange, or
FOREX, contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative
contract is stated in the balance sheet at its fair value with gains and losses reflected in the income statement
except that, to the extent the derivative qualifies for and is designated as an accounting hedge, the gains and losses
are reflected in income in the same period as offsetting gains and losses on the qualifying hedged positions.
Designated hedges are expected to be highly effective, and therefore, adjustments to record the carrying value of
the effective portion of our derivative financial instruments to their fair value are recorded as a component of
“Accumulated other comprehensive gain (loss),” or AOCGL, in our Consolidated Balance Sheets. The effective
portion of the cash flow hedge will remain in AOCGL until it is reclassified into earnings in the period or periods
during which the hedged transaction affects earnings or it is determined that the hedged transaction will not occur.
We report such realized gains and losses as a component of “Contract drilling, excluding depreciation” expense in
our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our
expenditures in local foreign currencies in the countries in which we operate.
Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to
fair value and realized gains or losses upon settlement of derivative contracts not designated as cash flow hedges
are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. See
Notes 7 and 8.
Assets Held For Sale
At December 31, 2015, we reported the $14.2 million carrying value of five of our jack-up rigs as “Assets
held for sale” in our Consolidated Balance Sheets. One of these rigs was subsequently sold for $8.0 million in
February 2016. See Notes 2 and 9.
Drilling and Other Property and Equipment
We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance
and routine repairs are charged to income currently while replacements and betterments that upgrade or increase
the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are
capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not
such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage
values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ
from those reported. During the years ended December 31, 2015 and 2014, we capitalized $262.4 million and
$546.0 million, respectively, in replacements and betterments of our drilling fleet.
Costs incurred for major rig upgrades and/or the construction of rigs are accumulated in construction work-in-
progress, with no depreciation recorded on the additions, until the month the upgrade or newbuild is completed
and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are
removed from the respective accounts and any gains or losses are included in our results of operations as “Gain on
disposition of assets.” Depreciation is recognized up to applicable salvage values by applying the straight-line
method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and
equipment are depreciated over their estimated useful lives ranging from 3 to 30 years.
Capitalized Interest
We capitalize interest cost for qualifying construction and upgrade projects. During the three years ended
December 31, 2015, we capitalized interest on qualifying expenditures, primarily related to our rig construction
projects. See Note 9.
54
A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of
Operations is as follows:
Total interest cost including amortization of debt issuance costs ................
Capitalized interest .....................................................................................
Total interest expense as reported ...........................................................
Impairment of Long-Lived Assets
For the Year Ended December 31,
2014
2015
(In thousands)
$ 122,656
(60,603)
$ 62,053
$ 110,242
(16,308)
$ 93,934
$ 99,080
(74,237)
$ 24,843
2013
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the
carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the
expectation of cold stacking a rig in the near term, contracted backlog of less than one year for a rig, a decision to
retire or scrap a rig, or excess spending over budget on a newbuild, construction project or major rig upgrade).
We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment.
Our assumptions and estimates underlying this analysis include the following:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
dayrate by rig;
utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of
time per year that the rig would be used at certain dayrates);
the per day operating cost for each rig if active, warm stacked or cold stacked;
the estimated annual cost for rig replacements and/or enhancement programs;
the estimated maintenance, inspection or other costs associated with a rig returning to work;
salvage value for each rig; and
estimated proceeds that may be received on disposition of each rig.
Based on these assumptions, we develop a matrix for each rig under evaluation using multiple
utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a
projected probability- weighted cash flow for each rig based on the respective matrix and compare such amount to
the carrying value of the asset to assess recoverability.
The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are
developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water
depth and other attributes and then assesses its future marketability in light of the current and projected market
environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs,
are estimated using historical data adjusted for known developments and future events that are anticipated by
management at the time of the assessment.
Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment
evaluation, and the use of different assumptions could produce results that differ from those reported. Our
methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value
measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes
from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s
assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events,
and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to
these assumptions could materially alter our analysis in testing an asset for potential impairment. For example,
changes in market conditions that exist at the measurement date or that are projected by management could affect
our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not
limited to, a further sustained decline in oil and gas prices, cancelations of our drilling contracts or contracts of our
competitors, contract modifications, costs to comply with new governmental regulations, growth in the global
oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market
conditions in the future vary significantly from market conditions used in our projections, our assessment of
impairment would likely be different. See Note 2.
55
Fair Value of Financial Instruments
We believe that the carrying amount of our current financial instruments approximates fair value because of
the short maturity of these instruments. See Note 8.
Debt Issuance Costs
Debt issuance costs are included in our Consolidated Balance Sheets at December 31, 2015 and 2014 in
“Other assets” and are amortized over the respective terms of the related debt. In April 2015, the Financial
Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2015-03, Interest -
Imputation of Interest (Subtopic 835-30); Simplifying the Presentation of Debt Issuance Costs, or ASU 2015-03,
which requires debt issuance costs associated with our senior notes (See Note 10) to be presented in the balance
sheet as a direct deduction from the carrying amount of the related senior note. This change is effective for fiscal
years beginning after December 15, 2015, with early adoption permitted. We will be adopting the provisions of
ASU 2015-03 in the first quarter of 2016, which will affect only the presentation of such amounts in our
Consolidated Balance Sheets.
Income Taxes
We account for income taxes in accordance with accounting standards that require the recognition of the amount
of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of
deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our
financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the
estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the
estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced
by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on
available evidence, are not expected to be realized under a “more likely than not” approach. We make judgments
regarding future events and related estimates especially as they pertain to the forecasting of our effective tax rate, the
potential realization of deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance
of items deducted on tax returns upon audit.
We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties
associated with uncertain tax positions in our tax expense. See Note 15.
Current GAAP requires a reporting entity to separate deferred income tax liabilities and assets into current
and noncurrent amounts in a classified statement of financial position based on the underlying assets and liabilities
to which such deferred income taxes relate. To simplify the presentation of deferred income taxes, the FASB
issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, or ASU 2015-17, in November 2015,
which requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of
financial position. ASU 2015-17 is effective for annual and interim reporting periods beginning after December
15, 2016 with earlier application permitted. We have elected to early adopt ASU 2015-17 and are prospectively
applying the classification requirements as of the beginning of 2015. Our Consolidated Balance Sheet at
December 31, 2014 has not been retrospectively adjusted. See Note 15.
Treasury Stock
In connection with the vesting of restricted stock units held by our chief executive officer, or CEO, in 2015,
we acquired 7,810 shares of our common stock (valued at $0.2 million) in satisfaction of tax withholding
obligations that were incurred on the vesting date. See Note 3.
Depending on market conditions, we may, from time to time, purchase shares of our common stock in the
open market or otherwise. We account for the purchase of treasury stock using the cost method, which reports the
cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated
Balance Sheets. During the year ended December 31, 2014, we repurchased 1,895,561 shares of our outstanding
common stock at a cost of $87.8 million. We did not repurchase any shares of our outstanding common stock
during 2015 or 2013.
56
Comprehensive Income (Loss)
Comprehensive income (loss) is the change in equity of a business enterprise during a period from
transactions and other events and circumstances except those transactions resulting from investments by owners
and distributions to owners. Comprehensive income (loss) for the three years ended December 31, 2015, 2014
and 2013 includes net income (loss) and unrealized holding gains and losses on marketable securities and
financial derivatives designated as cash flow accounting hedges. See Note 11.
Foreign Currency
Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses are reported as
“Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations and include, when
applicable, unrealized gains and losses to record the carrying value of our FOREX contracts not designated as
accounting hedges, as well as realized gains and losses from the settlement of such contracts. For the years ended
December 31, 2015, 2014 and 2013, we recognized aggregate net foreign currency gains (losses) of $2.5 million,
$3.2 million and $(4.9) million, respectively. See Note 7.
Revenue Recognition
We recognize revenue from dayrate drilling contracts as services are performed. In connection with such
drilling contracts, we may receive fees (on either a lump-sum or dayrate basis) for the mobilization of equipment.
We earn these fees as services are performed over the initial term of the related drilling contracts. We defer
mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a
straight-line basis, over the term of the related drilling contracts (which is the period we estimate to be benefited
from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the
term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing
of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are
recognized currently. Upon completion of a drilling contract, we recognize in earnings any demobilization fees
received and costs incurred.
Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet
customer requirements. At times, we may be compensated by the customer for such work (on either a lump-sum
or dayrate basis). These fees are generally earned as services are performed over the initial term of the related
drilling contracts. We defer contract preparation fees received, as well as direct and incremental costs associated
with the contract preparation activities and amortize each, on a straight-line basis, over the term of the related
drilling contracts (which we estimate to be benefited from the contract preparation activity).
From time to time, we may receive fees from our customers for capital improvements to our rigs (on either a
lump-sum or dayrate basis). We defer such fees received in “Accrued liabilities” and “Other liabilities” in our
Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the
related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the
estimated useful life of the improvement.
We record reimbursements received for the purchase of supplies, equipment, personnel services and other
services provided at the request of our customers in accordance with a contract or agreement, for the gross amount
billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of
Operations.
Recent Accounting Pronouncements
In May 2014, the FASB, issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or
ASU 2014-09. The new standard supersedes the industry-specific standards that currently exist under GAAP and
provides a framework to address revenue recognition issues comprehensively for all contracts with customers
regardless of industry-specific or transaction-specific fact patterns. Under the new guidance, companies recognize
revenue to depict the transfer of promised goods or services to customers in an amount that reflects the
consideration to which the company expects to be entitled in exchange for those goods or services. ASU 2014-09
also provides for additional disclosure requirements. In July 2015, the FASB issued ASU 2015-14, which
deferred the effective date of ASU 2014-09. The guidance of ASU 2014-09 is now effective for annual reporting
periods beginning after December 15, 2017, including interim periods within that reporting period, and may be
adopted using a retrospective or modified retrospective approach.
57
2. Asset Impairments
2015 Impairments - During 2015, in response to a continued deterioration of the market fundamentals in the
oil and gas industry, including the dramatic decline in oil prices, significant cutbacks in customer capital spending
plans and contract cancelations by customers, as well as pending regulatory requirements in the U.S. Gulf of
Mexico, or GOM, we evaluated 25 of our drilling rigs with indications that their carrying amounts may not be
recoverable (See Note 1). Using an undiscounted, projected probability-weighted cash flow analysis as described
in Note 1, we determined that the carrying value of 17 of these rigs, consisting of two ultra-deepwater, one
deepwater and nine mid-water floaters and five jack-up rigs, were impaired (collectively referred to as the 2015
Impaired Rigs).
We estimated the fair value of 16 of the 2015 Impaired Rigs utilizing a market approach, which required us to
estimate the value that would be received for each rig in the principal or most advantageous market for that rig in
an orderly transaction between market participants. Such estimates were based on various inputs, including
historical contracted sales prices for similar rigs in our fleet, nonbinding quotes from rig brokers and/or indicative
bids, where applicable. We estimated the fair value of the one remaining 2015 Impaired Rig using an income
approach, as we determined that the most likely use for this rig would be to cold stack the rig and reintroduce it
into the market at a later date. The fair value of this rig was estimated based on a calculation of the rig’s
discounted future net cash flows over its remaining economic life, which utilized significant unobservable inputs,
including, but not limited to, assumptions related to estimated dayrate revenue, rig utilization, estimated
equipment upgrade and regulatory survey costs, as well as estimated proceeds that may be received on ultimate
disposition of the rig. Our fair value estimates are representative of Level 3 fair value measurements due to the
significant level of estimation involved and the lack of transparency as to the inputs used.
During the first, third and fourth quarters of 2015, we recognized impairment losses of $358.5 million, $2.6
million and $499.4 million, respectively, for an aggregate impairment loss of $860.4 million for the year ended
December 31, 2015. Of the 2015 Impaired Rigs, five mid-water rigs were sold during 2015. We are actively
marketing for sale the five jack-up rigs in the impairment group and have presented the $14.2 million aggregate
carrying value of these rigs as “Assets Held for Sale” in our Consolidated Balance Sheets at December 31, 2015.
Six of the 2015 Impaired Rigs were cold stacked at the end of 2015, and the remaining impaired rig is expected to
be sold for scrap after completion of its contract in 2016. We have reported the $175.4 million aggregate carrying
value of these rigs in “Drilling and other property and equipment, net of accumulated depreciation” in our
Consolidated Balance Sheets at December 31, 2015, as they did not qualify for reporting as assets held for sale.
In February 2016, we sold one of our marketed-for-sale jack-up rigs for $8.0 million.
If market fundamentals in the oil and gas industry deteriorate further or if we are unable to secure new or
extend contracts for our current, actively-marketed drilling fleet or reactivate any of our cold stacked rigs or if we
experience unfavorable changes to our actual dayrates and rig utilization, we may be required to recognize
additional impairment losses in future periods, if we are unable to recover the carrying value of any of our drilling
rigs.
2014 Impairments - During the third quarter of 2014, we initiated a plan to retire and scrap six mid-water
drilling rigs. Using an undiscounted, projected probability-weighted cash flow analysis as described in Note 1, we
determined that the carrying values of these six rigs were impaired, collectively referred to as the 2014 Impaired
Rigs. We determined the fair value of the 2014 Impaired Rigs by applying a combination of income and market
approaches which were representative of Level 3 fair value measurements due to the significant level of
estimation involved and the lack of transparency as to the inputs used. As a result of our valuations, we
recognized an impairment loss aggregating $109.5 million during the third quarter of 2014.
At December 31, 2014, we had six additional rigs with indications that their carrying amounts may not be
recoverable. We performed an impairment analysis for each of these rigs using the methodology described in
Note 1 and concluded that these rigs were not impaired at December 31, 2014.
During the fourth quarter of 2014, two of the 2014 Impaired Rigs were sold for scrap. The $9.4 million
aggregate book value of the four remaining 2014 Impaired Rigs was reported in “Drilling and other property and
equipment, net of accumulated depreciation” in our Consolidated Balance Sheets at December 31, 2014. The
remaining 2014 Impaired Rigs were sold in 2015.
We did not record an impairment loss during the year ended December 31, 2013.
58
See Notes 1 and 9.
3. Supplemental Financial Information
Consolidated Balance Sheet Information
Accounts receivable, net of allowance for bad debts, consists of the following:
Trade receivables ....................................................................................
Value added tax receivables ....................................................................
Amounts held in escrow ..........................................................................
Interest receivable ...................................................................................
Related party receivables ........................................................................
Other .......................................................................................................
Allowance for bad debts .........................................................................
Total ..............................................................................................
December 31,
2015
2014
(In thousands)
$
390,429
14,475
4,966
336
167
721
411,094
(5,724)
405,370
$
$
437,017
24,853
6,450
317
339
610
469,586
(5,724)
463,862
$
An analysis of the changes in our provision for bad debts for each of the three years ended December 31, 2015,
2014 and 2013, is as follows:
2015
For the Year Ended December 31,
2014
(In thousands)
2013
Allowance for bad debts, beginning of year ...................
Bad debt expense:
Provision for bad debts ..........................................
Recovery of bad debts ...........................................
Total bad debt expense (recovery) ....................
Write off of uncollectible accounts against reserve.....
Other (1) .......................................................................
Allowance for bad debts, end of year .............................
$
5,724
$
27,340
$
5,458
--
--
--
--
--
5,724
$
--
--
--
(21,148)
(468)
5,724
22,513
--
22,513
(509)
(122)
27,340
$
$
(1) Includes revaluation adjustments for non-U.S. dollar denominated receivables, which have been recorded
as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.
See Note 8 for a discussion of our provision for bad debts and write off of uncollectible accounts against the
reserve.
59
Prepaid expenses and other current assets consist of the following:
December 31,
2015
2014
(In thousands)
Rig spare parts and supplies ..................................................................
Deferred mobilization costs ..................................................................
Prepaid insurance ..................................................................................
Deferred tax assets (1) ............................................................................
Prepaid taxes .........................................................................................
Other .....................................................................................................
Total ............................................................................................
$
42,804
52,965
4,483
--
14,969
4,258
119,479
$
$
56,315
53,206
12,163
15,612
44,085
4,160
185,541
$
(1) We have elected to early adopt the provisions of ASU 2015-17 and are prospectively applying the
classification requirements as of the beginning of 2015. Our Consolidated Balance Sheet at December 31,
2014 has not been retrospectively adjusted. See Notes 1 and 15.
Accrued liabilities consist of the following:
December 31,
2015
2014
(In thousands)
Rig operating expenses .........................................................................
Payroll and benefits ..............................................................................
Deferred revenue...................................................................................
Accrued capital project/upgrade costs ..................................................
Interest payable .....................................................................................
Personal injury and other claims ...........................................................
FOREX contracts ..................................................................................
Other .....................................................................................................
Total ............................................................................................
$
47,426
59,787
31,542
84,146
18,365
8,320
--
4,183
253,769
$
$
85,897
131,664
63,209
103,123
18,365
8,570
5,439
10,325
426,592
$
Consolidated Statement of Cash Flows Information
Noncash investing activities excluded from the Consolidated Statements of Cash Flows and other supplemental
cash flow information is as follows:
Accrued but unpaid capital expenditures at period end ........... $
Income tax benefits related to exercise of stock options .........
Common stock withheld for payroll tax obligations (1) ...........
Cash interest payments (2) ........................................................
Cash income taxes paid (refunded), net:
U.S. federal ........................................................................
Foreign ...............................................................................
State ...................................................................................
2015
84,146
--
236
110,412
(21,751)
69,697
58
December 31,
2014
(In thousands)
103,123
$
1,458
--
133,784
2013
$
86,274
1,081
--
82,938
--
92,049
(18)
62,000
78,041
190
(1) Represents the cost of 7,810 shares of common stock withheld to satisfy the payroll tax obligation incurred as
a result of the vesting of restricted stock units in the first quarter of 2015. This cost is presented as a
deduction from stockholders’ equity in “Treasury stock” in our Consolidated Balance Sheets at December 31,
2015.
Interest payments, net of amounts capitalized, were $94.7 million, $73.2 million and $16.5 million for the
years ended December 31, 2015, 2014 and 2013, respectively.
(2)
60
4. Stock-Based Compensation
We have an Equity Incentive Compensation Plan, or Equity Plan, for our (a) employees, (b) independent
contractors and (c) non-employee directors, which is designed to encourage stock ownership by such persons,
thereby aligning their interests with those of our stockholders and to permit the payment of performance-based
compensation as defined by the Internal Revenue Code of 1986, as amended, or the Code. Under the Equity Plan,
we may grant both time-vesting and performance-vesting awards, which are earned on the achievement of certain
performance criteria. The following types of awards may be granted under the Equity Plan:
(cid:120) Stock options (including incentive stock options and nonqualified stock options);
(cid:120) Stock appreciation rights, or SARs;
(cid:120) Restricted stock;
(cid:120) Restricted stock units, or RSUs;
(cid:120) Performance shares or units; and
(cid:120) Other stock-based awards (including dividend equivalents).
A maximum of 7,500,000 shares of our common stock is available for the grant or settlement of awards under
the Equity Plan, subject to adjustment for certain business transactions and changes in capital structure. Vesting
conditions and other terms and conditions of awards under the Equity Plan are determined by our Board of
Directors or the compensation committee of our Board of Directors, subject to the terms of the Equity Plan. RSUs
may be issued with performance-vesting or time-vesting features. Except for RSUs issued to our CEO, RSUs are
not participating securities, and the holders of such awards have no right to receive regular dividends if or when
declared.
Total compensation cost recognized for all awards under the Equity Plan (or its predecessor) for the years
ended December 31, 2015, 2014 and 2013 was $5.7 million, $5.0 million and $3.9 million, respectively. Tax
benefits recognized for the years ended December 31, 2015, 2014 and 2013 related thereto were $1.9 million, $1.4
million and $1.3 million, respectively. As of December 31, 2015 there was $9.3 million of total unrecognized
compensation cost related to nonvested awards under the Equity Plan, which we expect to recognize over a
weighted average period of two years.
Time-Vesting Awards
SARs. SARs awarded under the Equity Plan generally vest ratably over a four-year period and expire in ten
years. The exercise price per share of SARs awarded under the Equity Plan may not be less than the fair market
value of our common stock on the date of grant.
The fair value of SARs granted under the Equity Plan (or its predecessor) during each of the years ended
December 31, 2015, 2014 and 2013 was estimated using the Black Scholes pricing model with the following
weighted average assumptions:
Expected life of SARs (in years) .............................
Expected volatility ..................................................
Dividend yield .........................................................
Risk free interest rate ..............................................
Year Ended December 31,
2014
7
2013
7
18.24%
.75%
1.61%
21.68%
1.10%
2.08%
2015
6
55.12%
1.70%
1.66%
The expected life of SARs is based on historical data as is the expected volatility. The dividend yield is based
on the current approved regular dividend rate in effect and the current market price at the time of grant. Risk free
interest rates are determined using the U.S. Treasury yield curve at time of grant with a term equal to the expected
life of the SARs.
61
A summary of SARs activity under the Equity Plan as of December 31, 2015 and changes during the year
then ended is as follows:
Awards outstanding at January 1, 2015 ........
Granted ................................................
Exercised .............................................
Forfeited ..............................................
Expired ................................................
Awards outstanding at December 31, 2015 ..
Number of
Awards
1,587,330
124,250
--
42,901
127,248
1,541,431
Weighted-
Average
Exercise Price
$ 73.03
$ 31.67
$ --
$ 52.17
$ 72.07
$ 70.36
Awards exercisable at December 31, 2015 ...
1,316,849
$ 73.52
Weighted-Average
Remaining
Contractual Term
(Years)
Aggregate
Intrinsic Value
(In Thousands)
5.6
5.2
$
$
58
58
The weighted-average grant date fair values per share of awards granted during the years ended December 31,
2015, 2014 and 2013 were $14.44, $10.40 and $13.74, respectively. The total intrinsic value of awards exercised
during the years ended December 31, 2015, 2014 and 2013 was $0, $169,000 and $162,000, respectively. The
total fair value of awards vested during the years ended December 31, 2015, 2014 and 2013 was $3.6 million, $4.5
million and $4.1 million, respectively.
Restricted Stock Units. RSUs are contractual rights to receive shares of our common stock in the future if the
applicable vesting conditions are met. In April 2015, we granted 153,493 time-vesting RSUs, one half of which
will vest on April 1, 2017 and the remaining 50% of which will vest on April 1, 2018, conditioned upon continued
employment through the applicable vesting date. The fair value of time-vesting RSUs granted under the Equity Plan
in 2015 was estimated based on the fair market value of our common stock on the date of grant, discounted at a
three-year risk-free interest rate of 1.48%, as consideration of the non-participative rights of the awards.
A summary of activity for time-vesting RSUs under the Equity Plan as of December 31, 2015 and changes
during the year then ended is as follows:
Nonvested awards at January 1, 2015 ...........
Granted ................................................
Vested ..................................................
Forfeited ..............................................
Nonvested awards at December 31, 2015 .....
Number of
Awards
--
153,493
--
3,879
149,614
Weighted-
Average
Grant Date
Fair Value
Per Share
--
$
$ 25.09
$
$ 25.21
$ 25.09
--
No time-vesting RSUs vested during the year ended December 31, 2015.
Performance-Vesting Awards
Restricted Stock Units. In April 2015, we granted an aggregate 169,312 in performance-vesting RSUs, which
will vest upon achievement of certain performance goals as set forth in the individual award agreements over the
performance period from January 1, 2015 to December 31, 2017. The shares of our common stock to be received
upon the vesting of the performance-vesting RSUs will be delivered no later than March 15, 2018. The fair value of
performance-vesting RSUs granted under the Equity Plan to employees other than our CEO was estimated based on
the fair market value of our common stock on the date of grant, discounted at a three-year risk-free interest rate of
1.48%. The fair value of performance-vesting RSUs granted to our CEO in 2015 was not discounted as such awards
are participating securities.
In 2014, we awarded 55,661 targeted performance RSUs, with a volume weighted average price of our
common stock preceding the grant date of $46.99 per share, including 3,080 in RSUs credited upon payment of
cash dividends in 2014, to our CEO in connection with his commencement of service with us in March 2014. The
62
RSUs awarded to our CEO in 2014 will vest in one-third increments annually, over three years, commencing on
the first anniversary of his hire date, conditioned upon continued employment through the applicable vesting date.
A summary of activity for performance-vesting RSUs under the Equity Plan as of December 31, 2015 and
changes during the year then ended is as follows:
Nonvested awards at January 1, 2015 ...........
Granted ................................................
Vested ..................................................
Forfeited ..............................................
Nonvested awards at December 31, 2015 .....
Weighted-
Average Grant
Date Fair
Value Per
Share
$ 46.99
$ 26.19
$ 46.94
$ --
$ 29.93
Number of
Awards
55,661
169,312
18,617
--
206,356
The total grant date fair value of the performance-vesting RSUs that vested during the years ended December
31, 2015 and 2014 was $0.6 million and $0, respectively.
5. Earnings Per Share
A reconciliation of the numerators and the denominators of the basic and diluted per-share computations
follows:
Year Ended December 31,
2015
2013
2014
(In thousands, except per share data)
Net (loss) income – basic and diluted (numerator):
$ (274,285) $ 387,011
$ 548,686
Weighted-average shares – basic (denominator):
137,157 137,473 139,035
Dilutive effect of stock-based awards ...................................
Weighted-average shares including conversions – diluted
-- 50 29
(denominator):
(Loss) earnings per share:
137,157
137,523
139,064
Basic ........................................................................................
Diluted ....................................................................................
$ (2.00)
$ (2.00)
$ 2.82
$ 2.81
$ 3.95
$ 3.95
The following table sets forth the share effects of stock-based awards excluded from our computations of
diluted earnings per share, or EPS, as the inclusion of such potentially dilutive shares would have been
antidilutive for the periods presented:
Employee and director:
Stock options............................................................
SARs ........................................................................
RSUs ........................................................................
6. Marketable Securities
2015
Year Ended December 31,
2014
(In thousands)
2013
26
1,553
278
37
1,488
--
18
956
--
We report our investments in marketable securities as current assets in our Consolidated Balance Sheets in
“Marketable securities,” representing the investment of cash available for current operations. See Note 8.
63
Our investments in marketable securities are classified as available for sale and are summarized as follows:
Amortized
Cost
December 31, 2015
Unrealized
Gain (Loss)
(In thousands)
Market
Value
Corporate bonds ........................................................................
Mortgage-backed securities ......................................................
Total ..................................................................................
$ 16,480
77
16,557
$
$ (5,042)
3
$ (5,039)
$
$
11,438
80
11,518
Amortized
Cost
December 31, 2014
Unrealized
Gain (Loss)
(In thousands)
Market
Value
Corporate bonds .......................................................................
Mortgage-backed securities .....................................................
Total ..................................................................................
$ 16,003
130
16,133
$
$ (104)
4
$ (100)
$
$
15,899
134
16,033
Based on current facts and circumstances, we believe that the unrealized losses on our investments in
corporate bonds presented in the tables above are not indicative of the ultimate collectability of these investments,
but are primarily related to the financial market’s perception of the current downturn in the bond issuer’s industry
(oil and gas market and contract drilling industry). We have no current intent to sell these securities, nor is it
more likely than not that we will be required to sell these investments prior to their maturity. Therefore, we do
not consider the unrealized losses at December 31, 2015 and 2014 associated with our investments in corporate
bonds to be other than temporary.
Proceeds from maturities and sales of marketable securities and gross realized gains and losses are
summarized as follows:
Year Ended December 31,
2015
2014
2013
(In thousands)
Proceeds from maturities ................................................. $
Proceeds from sales .........................................................
--
51
$ 8,000,000
57
$ 4,650,000
85
Gross realized gains and losses from the sale of marketable securities for each of the three years ended
December 31, 2015, 2014 and 2013 were not significant.
7. Derivative Financial Instruments
Foreign Currency Forward Exchange Contracts
Our international operations expose us to foreign exchange risk associated with our costs payable in foreign
currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. From
time to time, we may utilize FOREX contracts to manage our foreign exchange risk. Our FOREX contracts
generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot
rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract
period.
We enter into FOREX contracts when we believe market conditions are favorable to purchase contracts for
future settlement with the expectation that such contracts, when settled, will reduce our exposure to foreign
currency gains and losses on future foreign currency expenditures. The amount and duration of such contracts is
based on our monthly forecast of expenditures in the significant currencies in which we do business and for which
there is a financial market. Historically we have entered into FOREX contracts for future delivery of Australian
dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner. These forward contracts
are derivatives as defined by GAAP.
64
During the years ended December 31, 2015, 2014 and 2013, we settled FOREX contracts with aggregate
notional values of approximately $91.6 million, $304.7 million and $307.4 million, respectively, of which the
entire aggregate amounts were designated as an accounting hedge. During the years ended December 31, 2015,
2014 and 2013, we did not enter into or settle any FOREX contracts that were not designated as accounting
hedges. There were no FOREX contracts outstanding at December 31, 2015.
The following table presents the aggregate amount of gain or loss recognized in our Consolidated Statements
of Operations related to our FOREX contracts designated as hedging instruments for the years ended December
31, 2015, 2014 and 2013.
Location of Gain (Loss) Recognized in Income
Amount of Gain (Loss) Recognized in Income
For the Years Ended December 31,
2014
2015
(In thousands)
2013
Contract drilling expense .........................................................
$ (8,364) $ 3,275 $
(6,501)
The following table presents the fair values of our derivative FOREX contracts designated as hedging
instruments at December 31, 2015 and 2014.
Balance Sheet Location
Fair Value
Balance Sheet Location
Fair Value
December 31,
2015
December 31,
2014
(In thousands)
December 31,
2015
December 31,
2014
(In thousands)
Prepaid expenses and
other current assets
$ --
$
--
Accrued liabilities
$
--
$
(5,439)
The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated
Statements of Operations related to our derivative financial instruments designated as cash flow hedges for the
years ended December 31, 2015, 2014 and 2013.
2015
For the Year Ended December 31,
2014
(In thousands)
2013
FOREX contracts:
Amount of (loss) gain recognized in AOCGL on
derivative (effective portion) ......................................
Location of (loss) gain reclassified from AOCGL
into income (effective portion) ...................................
Amount of (loss) gain reclassified from AOCGL into
income (effective portion) ...........................................
Location of loss recognized in income on derivative
(ineffective portion and amount excluded from
effectiveness testing) ...................................................
Amount of loss recognized in income on derivative
(ineffective portion and amount excluded from
effectiveness testing) ...................................................
$
(2,420)
Contract drilling,
excluding
depreciation
$
(2,281)
Contract drilling,
excluding
depreciation
(10,542)
$
Contract drilling,
excluding
depreciation
$
(7,829)
$
3,650 $
(7,449)
Foreign currency
transaction gain
(loss)
Foreign currency
transaction gain
(loss)
Foreign currency
transaction gain
(loss)
$
(1)
$
(31)
$
(104)
During the years ended December 31, 2015, 2014 and 2013, we did not reclassify any amounts from AOCGL
due to the probability of an underlying forecasted transaction not occurring.
8. Financial Instruments and Fair Value Disclosures
Concentrations of Credit and Market Risk
Financial instruments that potentially subject us to significant concentrations of credit or market risk consist
primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt
65
securities, including mortgage-backed securities. We generally place our excess cash investments in U.S.
government backed short-term money market instruments through several financial institutions. At times, such
investments may be in excess of the insurable limit. We periodically evaluate the relative credit standing of these
financial institutions as part of our investment strategy.
Most of our investments in debt securities are securitized corporate bonds whereby our credit risk is mitigated
by the collateral. However, we are exposed to market risk due to price volatility associated with interest rate
fluctuations.
Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the
entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this
customer base consists primarily of major and independent oil and gas companies and government-owned oil
companies. Based on our current customer base and the geographic areas in which we operate, as well as the
number of rigs currently working in a geographic area, we do not believe that we have any significant
concentrations of credit risk at December 31, 2015.
In general, before working for a customer with whom we have not had a prior business relationship and/or
whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that
analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements.
We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer
receivable may not be collectible and, historically, losses on our trade receivables have been infrequent
occurrences.
During 2013, based on our assessment of the financial condition of two of our customers, Niko Resources
Ltd., or Niko, and OGX Petróleo e Gás Ltda. (a privately owned Brazilian oil and natural gas company that filed
for bankruptcy in October 2013), or OGX, and our expectations at the time regarding the probability of collection
of amounts due to us from them, we recorded $22.5 million in bad debt expense to fully reserve all outstanding
receivables owed to us.
In December 2013, we entered into a settlement agreement with Niko, or the Niko Settlement, whereby Niko
will be released from certain obligations under the dayrate contracts for the Ocean Monarch and Ocean
Lexington, subject to and effective upon the full payment of amounts owed to us under the Niko Settlement and
subject to its other conditions. In accordance with the terms of the Niko Settlement, we received cash payments
of $20.3 million during 2014 and $25.0 million in the fourth quarter of 2013, which we recognized as revenue
against invoices due us. Niko is further obligated to make future periodic payments to us pursuant to the Niko
Settlement totaling an aggregate of $34.8 million, payable at various times through December 2016. In 2015,
Niko failed to make required payments and perform certain other obligations under the settlement agreement, so
we filed suit seeking payment of the overdue amounts and requiring Niko to perform its other contractual
obligations. We plan to recognize these amounts in revenue as they are received due to the uncertainty regarding
their timing and collection.
In 2014, the creditors of OGX, including us, agreed to a settlement whereby the creditors granted us shares of
the reorganized OGX company in full settlement of obligations owed to them by OGX. As a result of the
settlement, we have written off $21.2 million in receivables due us from OGX against the associated allowance
for bad debts, which was set up in 2013. See Note 3.
Fair Values
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability
(an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction
between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an
entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair
value. There are three levels of inputs that may be used to measure fair value:
Level 1 Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments
such as money market funds, U.S. Treasury Bills and Treasury notes. Our Level 1 assets at December
31, 2015 consisted of cash held in money market funds of $85.2 million and time deposits of $20.4
million. Our Level 1 assets at December 31, 2014 consisted of cash held in money market funds of
$197.5 million and time deposits of $20.3 million.
66
Level 2 Quoted market prices for similar instruments in active markets; quoted prices for identical or similar
instruments in markets that are not active; and model-derived valuations in which all significant inputs
and significant value drivers are observable in active markets. Level 2 assets and liabilities include
residential mortgage-backed securities, corporate bonds purchased in a private placement offering and
over-the-counter FOREX contracts. Our residential mortgage-backed securities and corporate bonds
were valued using a model-derived valuation technique based on the quoted closing market prices
received from a financial institution. Our FOREX contracts were valued based on quoted market prices,
which are derived from observable inputs including current spot and forward rates, less the contract rate
multiplied by the notional amount. The inputs used in our valuation are obtained from a Bloomberg
curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected
floating rate cash flows can be calculated. The valuation techniques underlying the models are widely
accepted in the financial services industry and do not involve significant judgment.
Level 3 Valuations derived from valuation techniques in which one or more significant inputs or significant value
drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose
value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as
well as instruments for which the determination of fair value requires significant management judgment
or estimation or for which there is a lack of transparency as to the inputs used. Our Level 3 assets at
December 31, 2015 and 2014 consisted of nonrecurring measurements of certain of our drilling rigs for
which we recorded an impairment loss during the years ended December 31, 2015 and 2014. See Notes
1 and 2.
Market conditions could cause an instrument to be reclassified among Levels 1, 2 and 3. Our policy
regarding fair value measurements of financial instruments transferred into and out of levels is to reflect the
transfers as having occurred at the beginning of the reporting period. There were no transfers between fair value
levels during the years ended December 31, 2015 and 2014.
Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in
accordance with GAAP. In addition, certain assets and liabilities may be recorded at fair value on a nonrecurring
basis. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. We
recorded impairment charges related to our 2015 Impaired Rigs and our 2014 Impaired Rigs, which were
measured at fair value on a nonrecurring basis in 2015 and 2014, respectively, and have presented the aggregate
loss in “Impairment of assets” in our Consolidated Statements of Operations for the years ended December 31,
2015 and 2014.
Fair Value Measurements Using
December 31, 2015
Level 1
Level 2
Level 3
(In thousands)
Assets at Fair
Value
Total Losses
for Year
Ended (1)
Recurring fair value
measurements:
Assets:
Short-term investments ............. $ 105,659
--
Corporate bonds .......................
--
Mortgage-backed securities ......
105,659
Total assets .......................... $
Nonrecurring fair value
measurements:
Assets:
-- $
11,438
80
11,518
$
--
--
--
--
$ 105,659
11,438
80
117,177
$
Impaired assets (2)(3) .................. $ -- $ --
$
189,600
$
189,600
$
860,441
(1) Represents the aggregate impairment loss recognized for the year ended December 31, 2015 related to our
2015 Impaired Rigs.
(2) Represents the book value of our 2015 Impaired Rigs, which were written down to their estimated
recoverable amounts during 2015, of which $14.2 million and $175.4 million were reported as “Assets Held
for Sale” and “Drilling and other property and equipment, net of accumulated depreciation,” respectively, in
our Consolidated Balance Sheets at December 31, 2015.
67
(3) Excludes five rigs with an aggregate fair value of $2.4 million, which were impaired in 2015, but were
subsequently sold for scrap during the year.
Fair Value Measurements Using
December 31, 2014
Level 1
Level 2
Level 3
(In thousands)
Assets at Fair
Value
Total Losses
for Year
Ended
Recurring fair value
measurements:
Assets:
Short-term investments ............. $ 217,789
--
Corporate bonds .......................
--
Mortgage-backed securities ......
Total assets .......................... $
$ --
$
15,899
134
217,789 $ 16,033
$
--
--
--
--
$
217,789
15,899
134
233,822
$
Liabilities:
FOREX contracts...................... $ -- $ (5,439) $
--
$
(5,439)
Nonrecurring fair value
measurements:
Assets:
Impaired assets (1) ..................... $ -- $ --
$
9,421
$ 9,421 $109,462
(1) Represents the book value as of December 31, 2014 of four of our 2014 Impaired Rigs, which were written
down to their estimated recoverable amounts in September 2014 and had not yet been scrapped. All of these
rigs were sold during 2015.
We believe that the carrying amounts of our other financial assets and liabilities (excluding long-term debt),
which are not measured at fair value in our Consolidated Balance Sheets, approximate fair value based on the
following assumptions:
(cid:120)
(cid:120)
(cid:120)
Cash and cash equivalents -- The carrying amounts approximate fair value because of the short
maturity of these instruments.
Accounts receivable and accounts payable -- The carrying amounts approximate fair value based on
the nature of the instruments.
Commercial paper -- The carrying amounts approximate fair value because of the short maturity of
these instruments.
We consider our senior notes, including current maturities, to be Level 2 liabilities under the GAAP fair
value hierarchy and, accordingly, the fair value of our senior notes was derived using a third-party pricing service
at December 31, 2015 and 2014. We perform control procedures over information we obtain from pricing
services and brokers to test whether prices received represent a reasonable estimate of fair value. These
procedures include the review of pricing service or broker pricing methodologies and comparing fair value
estimates to actual trade activity executed in the market for these instruments occurring generally within a 10-day
window of the report date. Fair values and related carrying values of our senior notes (see Note 10) are shown
below.
December 31, 2015
December 31, 2014
Fair Value
Carrying Value
Fair Value
Carrying Value
(In millions)
4.875% Senior Notes due 2015 ........
5.875% Senior Notes due 2019 ........
3.45% Senior Notes due 2023 ..........
5.70% Senior Notes due 2039 ..........
4.875% Senior Notes due 2043 ........
$
--
506.8
208.0
360.0
455.3
$
--
499.7
249.2
497.0
748.9
$
255.0
544.9
232.0
478.5
638.9
$
250.0
499.6
249.1
497.0
748.8
We have estimated the fair value amounts by using appropriate valuation methodologies and information
available to management. Considerable judgment is required in developing these estimates, and accordingly, no
68
assurance can be given that the estimated values are indicative of the amounts that would be realized in a free
market exchange.
9. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
December 31,
2015
2014
(In thousands)
Drilling rigs and equipment ..............................................................
Construction work-in-progress .........................................................
Land and buildings ............................................................................
Office equipment and other...............................................................
Cost .........................................................................................
Less accumulated depreciation .........................................................
Drilling and other property and equipment, net ......................
$
$
9,345,484
269,605
64,775
71,537
9,751,401
(3,372,587)
6,378,814
$
$
10,555,314
439,206
66,989
70,591
11,132,100
(4,186,147)
6,945,953
During the year ended December 31, 2015, we recognized an impairment loss of $860.4 million and
transferred $14.2 million net book value of five of our non-working jack-up rigs to “Assets held for sale” in our
Consolidated Balance Sheet at December 31, 2015. In addition, we sold nine rigs with an aggregate net book
value of $5.2 million and recognized an aggregate gain on disposition of $3.5 million. See Notes 1 and 2.
Construction work-in-progress, including capitalized interest, at December 31, 2015 and 2014 is summarized
as follows:
Ultra-deepwater drillships - Ocean BlackLion ..................................
Ultra-deepwater semisubmersible - Ocean GreatWhite ....................
Total construction work-in-progress .........................................
$
$
--
269,605
269,605
$
$
225,405
213,801
439,206
The Ocean BlackLion was placed in service in June 2015 and is no longer reported as construction work-in-
December 31,
2015
2014
(In thousands)
progress at December 31, 2015. See Note 12.
10. Credit Agreement and Senior Notes
Credit Agreement
We have a syndicated revolving credit agreement with Wells Fargo Bank, National Association, as
administrative agent and swingline lender, which provides for a $1.5 billion senior unsecured revolving credit facility
for general corporate purposes, or the Credit Agreement. Effective October 22, 2015, we entered into an extension
agreement and fourth amendment to our Credit Agreement, which, among other things, provided for a one-year
extension of the maturity date for most of the lenders. As so extended, our Credit Agreement matures on October 22,
2020, except for $40 million of commitments that mature on March 17, 2019 and $60 million of commitments that
mature on October 22, 2019. In addition, we also have the option to increase the revolving commitments under the
Credit Agreement by up to an additional $500 million from time to time, upon receipt of additional commitments
from new or existing lenders, and to request one additional one-year extension of the maturity date. The entire
amount of the facility is available, subject to its terms, for revolving loans. Up to $250 million of the facility may be
used for the issuance of performance or other standby letters of credit and up to $100 million may be used for
swingline loans. At December 31, 2015, 2014 and 2013, there were no amounts outstanding under the Credit
Agreement.
Revolving loans under the Credit Agreement bear interest, at our option, at a rate per annum based on either an
alternate base rate, or ABR, or a Eurodollar Rate, as defined in the Credit Agreement, plus the applicable interest
margin for an ABR loan or a Eurodollar loan. The ABR is the greatest of (i) the prime rate, (ii) the federal funds rate
plus 0.50% and (iii) the daily one-month Eurodollar Rate plus 1.00%. The applicable interest margin for ABR loans
69
varies from 0% to 0.25%. The applicable interest margin for Eurodollar loans varies between 0.75% and 1.25%.
Based on our current credit ratings, the applicable interest margin is 0.125% for ABR loans and 1.125% for
Eurodollar loans.
Swingline loans bear interest, at our option, at a rate per annum equal to (i) the ABR plus the applicable interest
margin for ABR loans or (ii) the daily one-month Eurodollar Rate plus the applicable interest margin for Eurodollar
loans.
Under our Credit Agreement, we also pay, based on our current long-term credit ratings, and as applicable, other
customary fees including, but not limited to, a commitment fee on the unused commitments under the Credit
Agreement, varying between 0.06% and 0.20% per annum, and a fronting fee to the issuing bank for each letter of
credit. Participation fees for letters of credit are dependent upon the type of letter of credit issued, varying between
0.375% and 0.625% per annum for performance letters of credit, and between 0.75% and 1.25% per annum for all
other letters of credit. Based on our current credit ratings, the applicable commitment fee is 0.15%, and the
participation fee for letters of credit is 0.5625%. Changes in credit ratings could lower or raise the fees that we pay
under the Credit Agreement.
The Credit Agreement contains customary covenants including, but not limited to, maintenance of a ratio of
consolidated indebtedness to total capitalization, as defined in the Credit Agreement, of not more than 60% at the end
of each fiscal quarter, as well as limitations on liens; mergers, consolidations, liquidation and dissolution; changes in
lines of business; swap agreements; transactions with affiliates; and subsidiary indebtedness. As of December 31,
2015, we were in compliance with all covenant requirements.
At December 31, 2015 and 2014, there were no amounts outstanding under the Credit Agreement. As of
February 16, 2016, we had $305.0 million in Eurodollar loans outstanding under the Credit Agreement and an
additional $1.2 billion available.
Commercial Paper
In 2015, we established a commercial paper program with four commercial paper dealers pursuant to which we
may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount
outstanding at any time of $1.5 billion and, unless we change the terms of the program, the aggregate amount of
commercial paper notes and total loans and letters of credit outstanding under the Credit Agreement at any time
will not exceed $1.5 billion. Proceeds from issuances under the commercial paper program may be used for general
corporate purposes. The maturities of the notes may vary, but may not exceed 397 days from the date of issuance.
The notes will be issued, at our option, either at a discounted price to their principal face value or will bear interest,
which may be at a fixed or floating rate, at rates that will vary based on market conditions and the ratings assigned by
credit rating agencies at the time of issuance. The notes are not redeemable or subject to voluntary prepayment by us
prior to maturity. Liquidity for our payment obligations in respect of the notes issued under the commercial paper
program is provided under our Credit Agreement, and the aggregate amount of notes outstanding at any time will not
exceed the amount available under the Credit Agreement.
As of December 31, 2015, we had $286.6 million in commercial paper notes outstanding with a weighted
average interest rate of 0.86% and a weighted average remaining term of 5.8 days. As of February 16, 2016, there
were no commercial paper notes outstanding.
Senior Notes
At December 31, 2015, our senior notes were comprised of the following debt issues:
Debt Issue
5.875% Senior Notes due 2019
3.45% Senior Notes due 2023
5.70% Senior Notes due 2039
Principal
Amount
(In millions)
$500.0
$250.0
$500.0
Maturity Date
May 1, 2019
November 1, 2023
October 15, 2039
Interest Rate
Coupon
5.875%
3.45%
5.70%
Effective
5.89%
3.50%
5.75%
Semiannual
Interest Payment
Dates
May 1 and November 1
May 1 and November 1
April 15 and October 15
4.875% Senior Notes due 2043
$750.0
November 1, 2043
4.875%
4.89%
May 1 and November 1
70
At December 31, 2015 and 2014, the carrying value of our senior notes was as follows:
4.875% Senior Notes due 2015 ...................................................
5.875% Senior Notes due 2019 ...................................................
3.45% Senior Notes due 2023 .....................................................
5.70% Senior Notes due 2039 .....................................................
4.875% Senior Notes due 2043 ...................................................
December 31,
2015
2014
$
(In thousands)
-- $
499,705
249,169
497,030
748,869
249,962
499,626
249,077
496,973
748,850
Total senior notes, net of unamortized discount ......................
$
1,994,773 $
2,244,488
Less: Current portion of long-term debt .....................................
Total Long-term debt ........................................................
--
$
1,994,773 $
249,962
1,994,526
As of December 31, 2015, the aggregate annual maturity of our senior notes was as follows:
Year Ending December 31,
Aggregate
Principal
Amount
(In thousands)
2016 ....................................................................................................................
2017 ....................................................................................................................
2018 .....................................................................................................................
2019 .....................................................................................................................
2020 .....................................................................................................................
Thereafter ............................................................................................................
$
Total maturities of senior notes ........................................................................
Less: unamortized discounts ...............................................................................
Total maturities of senior notes, net of unamortized discount ...........................
$
--
--
--
500,000
--
1,500,000
2,000,000
(5,227)
1,994,773
Senior Notes Due 2023 and 2043. In 2013, we issued $1.0 billion aggregate principal amount of senior notes
consisting of $250.0 million aggregate principal amount of 3.45% senior unsecured notes due 2023 and $750.0
million aggregate principal amount of 4.875% senior unsecured notes due 2043 or, collectively, the Senior Notes
Due 2023 and 2043, for general corporate purposes, including redemption, repurchase or retirement of our 5.15%
senior notes due September 1, 2014 and our 4.875% senior notes due July 1, 2015, or 2015 Notes. The
transaction resulted in net proceeds to us of $987.8 million after deducting underwriting discounts, commissions
and estimated expenses.
The Senior Notes Due 2023 and 2043 are unsecured and unsubordinated obligations of Diamond Offshore
Drilling, Inc., and rank equally in right of payment to all of its existing and future unsecured and unsubordinated
indebtedness, and are effectively subordinated to all existing and future obligations of our subsidiaries. We have
the right to redeem all or a portion of the Senior Notes Due 2023 and 2043 for cash at any time or from time to
time, on at least 15 days but not more than 60 days prior written notice, at a make-whole redemption price
specified in the governing indenture (if applicable) plus accrued and unpaid interest to, but excluding, the date of
redemption.
Senior Notes Due 2019 and 2039. Our 5.875% Senior Notes due 2019 and 5.70% Senior Notes due 2039 are
unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. and rank equally in right of
payment to its existing and future unsecured and unsubordinated indebtedness, and are effectively subordinated to
all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of these notes
for cash at any time or from time to time, on at least 15 days but not more than 60 days prior written notice, at the
redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.
2015 Maturities. On July 1, 2015, we repaid $250.0 million in aggregate principal amount of our 4.875%
Senior Notes due July 1, 2015, primarily with funds obtained through the issuance of commercial paper. These
notes were presented as “Current portion of long-term debt” in our Consolidated Balance Sheet at December 31,
2014.
71
11. Other Comprehensive Income (Loss)
The following table sets forth the components of “Other comprehensive income (loss)” and the related
income tax effects thereon for the three years ended December 31, 2015 and the cumulative balances in AOCGL
by component at December 31, 2015, 2014 and 2013.
Unrealized (Loss) Gain on
Derivative
Financial
Instruments
Marketable
Securities
(In thousands)
Total
AOCGL
Balance at January 1, 2013 ......................................................................... $
2,350 $
146
$
2,496
Change in other comprehensive (loss) gain before reclassifications,
after tax of $3,682 and $18 ...................................................................
Reclassification adjustments for items included in Net Income, after tax
of $(2,608) and $18 .............................................................................
Total other comprehensive (loss) income .............................................
Balance at December 31, 2013 ...................................................................
Change in other comprehensive (loss) gain before reclassifications,
after tax of $799 and $(15) ...................................................................
Reclassification adjustments for items included in Net Income, after tax
of $1,279 and $7 .................................................................................
Total other comprehensive (loss) income .............................................
Balance at December 31, 2014 ...................................................................
Change in other comprehensive (loss) gain before reclassifications,
after tax of $846 and $(1) .....................................................................
Reclassification adjustments for items included in Net Income, after tax
of $(2,737) and $0...............................................................................
(6,833)
(6)
(6,839)
4,840
(1,993)
357
(147)
(153)
(7)
4,693
(2,146)
350
(1,482)
(69)
(1,551)
(2,379)
(3,861)
(3,504)
(25)
(94)
(101)
(2,404)
(3,955)
(3,605)
(1,574)
(4,940)
(6,514)
5,084
--
5,084
Total other comprehensive income (loss) .............................................
3,510
(4,940)
(1,430)
Balance at December 31, 2015 ................................................................... $ 6
$
(5,041)
$
(5,035)
The following table presents the line items in our Consolidated Statements of Operations affected by
reclassification adjustments out of AOCGL.
Major Components of AOCGL
Year Ended December 31,
Consolidated Statements of
Operations Line Items
Derivative financial instruments:
Unrealized loss (gain) on FOREX contracts ........ $
Unrealized (gain) loss on Treasury Lock
Agreements ..........................................................
$
2015
2014
(In thousands)
2013
7,829
$
(3,650) $
7,449
Contract drilling, excluding
depreciation
(8)
(2,737)
$
5,084
(8)
1,279
(2,379) $
(1)
(2,608)
Interest expense
Income tax expense
4,840 Net of tax
Marketable securities:
Unrealized (gain) loss on marketable securities ... $
$
--
--
--
$
$
(32) $
7
(25) $
(165) Other, net
18
Income tax expense
(147) Net of tax
12. Commitments and Contingencies
Various claims have been filed against us in the ordinary course of business, including claims by offshore
workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in
accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When
72
we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined,
we record a liability for the amount of the estimated loss at the time that both of these criteria are met. Our
management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected
to result from these claims.
Asbestos Litigation. We are one of several unrelated defendants in lawsuits filed in Mississippi, Louisiana and
Missouri state courts alleging that defendants manufactured, distributed or utilized drilling mud containing
asbestos and, in our case, allowed such drilling mud to have been utilized aboard our offshore drilling rigs. The
plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. The
manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling
rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted and we expect to
receive complete defense and indemnity from Murphy Exploration & Production Company with respect to many
of the lawsuits pursuant to the terms of our 1992 asset purchase agreement with them. We also believe that we are
not liable for the damages asserted in the remaining lawsuits pursuant to the terms of our 1989 asset purchase
agreement with Diamond M Corporation, and we filed a declaratory judgment action in Texas state court against
NuStar Energy LP, or NuStar, and Kaneb Management Co., L.L.C., or Kaneb, the successors to Diamond M
Corporation, seeking a judicial determination that we did not assume liability for these claims. We are unable to
estimate our potential exposure, if any, to these lawsuits at this time but do not believe that our ultimate liability,
if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of
operations or cash flows.
Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are
incidental to the ordinary course of our business, including a claim by Petrobras that it will seek to recover from
its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities
for our applicable portion of withholding taxes related to Petrobras’ charter agreements with its contractors. We
intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate
outcome or effect of these claims, lawsuits and actions cannot be predicted with certainty. As a result, there can be
no assurance as to the ultimate outcome of these matters. Any claims against us, whether meritorious or not, could
cause us to incur costs and expenses, require significant amounts of management time and result in the diversion
of significant operational resources. In the opinion of our management, no pending or known threatened claims,
actions or proceedings against us are expected to have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
NPI Arrangement. We received customer payments measured by a percentage net profits interest (primarily
of 27%) under an overriding royalty interest in certain developmental oil-and-gas producing properties, or NPI,
which we believe is a real property interest. Our drilling program related to the NPI was completed in 2011, and
the balance of the amounts due to us under the NPI was received in 2013. However, the customer that conveyed
the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in August
2012. Certain parties (including the debtor) in the bankruptcy proceedings questioned whether our NPI, and
certain amounts we received under it since the filing of the bankruptcy, should be included in the debtor’s estate
under the bankruptcy proceeding. In 2013, we filed a declaratory judgment action in the bankruptcy court seeking
a declaration that our NPI, and payments that we received from it since the filing of the bankruptcy, are not part of
the bankruptcy estate. We agreed to a settlement with the company that purchased most of the debtor’s assets
(including the debtor’s claims against our NPI) whereby the nature of our NPI will not be challenged by that party
and our declaratory judgment action was dismissed. Following the settlement, the bankruptcy was converted to a
Chapter 7 liquidation proceeding. Several lienholders who had previously intervened in the declaratory judgment
action filed motions in the bankruptcy contending that their liens have priority and seeking disgorgement of $3.25
million of payments made to us after the bankruptcy was filed. We believe that our rights to the payments at issue
are superior to these liens, and we have filed appropriate motions to dismiss these claims. In addition, the
bankruptcy trustee filed counterclaims seeking disgorgement of a total of $30.0 million of pre- and post-
bankruptcy payments made to us under the original NPI. We have filed motions to dismiss these counterclaims
and still expect the bankruptcy proceedings to be concluded with no further material impact to us.
Personal Injury Claims. Under our current insurance policies, our deductibles for marine liability insurance
coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico,
are $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0
million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence,
depending on the nature, severity and frequency of claims that might arise during the policy year.
The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course
73
of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-
related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate
liability for personal injury claims based on our historical losses and utilizing various actuarial models. We
allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be
paid within the next twelve months with the residual recorded as “Other liabilities.” At December 31, 2015 our
estimated liability for personal injury claims was $40.4 million, of which $8.2 million and $32.2 million were
recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At
December 31, 2014, our estimated liability for personal injury claims was $39.4 million, of which $8.2 million
and $31.2 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated
Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our
estimated amounts due to uncertainties such as:
(cid:135)
(cid:135)
(cid:135)
(cid:135)
(cid:135)
the severity of personal injuries claimed;
significant changes in the volume of personal injury claims;
the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
inconsistent court decisions; and
the risks and lack of predictability inherent in personal injury litigation.
Purchase Obligations. The Ocean GreatWhite, a 10,000 foot dynamically positioned, harsh environment
semisubmersible drilling rig, is under construction in South Korea at an estimated cost of $764 million, including
shipyard costs, capital spares, commissioning, project management and shipyard supervision. The contracted
price to Hyundai Heavy Industries Co., Ltd. totaling $628.5 million is payable in two installments, of which the
first installment of $188.6 million has been paid. The final installment of $439.9 million is due upon delivery of
the rig, which is expected to occur in mid-2016.
At December 31, 2015, we had no other purchase obligations for major rig upgrades or any other significant
obligations, except for those related to our direct rig operations, which arise during the normal course of business.
Operating Leases. We lease office and yard facilities, housing, equipment and vehicles under operating
leases, which expire at various times through the year 2018. Total rent expense amounted to $7.8 million, $10.6
million and $13.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. Future minimum
rental payments under leases are approximately $2.7 million, $1.3 million and $0.4 million for the years 2016,
2017 and 2018, respectively. There are no minimum future rental payments under operating leases after 2018.
Letters of Credit and Other. We were contingently liable as of December 31, 2015 in the amount of $71.6
million under certain performance, supersedeas, bid, tax and customs bonds and letters of credit. Agreements
relating to approximately $64.0 million of performance, tax, supersedeas, court and customs bonds can require
collateral at any time. As of December 31, 2015, we had not been required to make any collateral deposits with
respect to these agreements. The remaining agreements cannot require collateral except in events of default. On
our behalf, banks have issued letters of credit securing certain of these bonds.
13. Related-Party Transactions
Transactions with Loews. We are party to a services agreement with Loews, or the Services Agreement,
pursuant to which Loews performs certain administrative and technical services on our behalf. Such services
include personnel, internal auditing, accounting, and cash management services, in addition to advice and
assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, we
are required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll
taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the
provision of such services. The Services Agreement may be terminated at our option upon 30 days’ notice to
Loews and at the option of Loews upon six months’ notice to us. In addition, we have agreed to indemnify Loews
for all claims and damages arising from the provision of services by Loews under the Services Agreement unless
due to the gross negligence or willful misconduct of Loews. We were charged $1.3 million, $1.1 million and $1.0
million by Loews for these support functions during the years ended December 31, 2015, 2014 and 2013,
respectively.
Transactions with Other Related Parties. We hire marine vessels and helicopter transportation services at the
prevailing market rate from subsidiaries of SEACOR Holdings Inc. and Era Group Inc. The Executive Chairman
of the Board of Directors of SEACOR Holdings Inc. and the Non-Executive Chairman of the Board of Directors
of Era Group Inc. is also a member of our Board of Directors. We paid $6.0 million, $0.8 million and $0.1
74
million for the hire of such vessels and such services during the years ended December 31, 2015, 2014 and 2013,
respectively.
The wife of our former President and Chief Executive Officer was an audit partner at Ernst & Young LLP, or
E&Y, during his term of service with us. For the year ended December 31, 2014, we made payments aggregating
$2.9 million to E&Y for tax and other consulting services; however, E&Y ceased to be a related party on March 3,
2014. For the year ended December 31, 2013, we made payments to E&Y of $1.6 million.
14. Restructuring and Separation Costs
During 2015, in response to the continuing decline in the offshore drilling market, we reviewed our cost and
organization structure, and, as a result, our management approved and initiated a reduction in workforce at our
onshore bases and corporate facilities, also referred to as the Corporate Reduction Plan. As of December 31, 2015,
appropriate communications had been made to substantially all impacted personnel, and we paid $9.8 million in
restructuring and employee separation related costs during 2015. There were no accrued costs associated with the
Corporate Reduction Plan as of December 31, 2015.
15. Income Taxes
Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or
losses, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs
are owned and operated, directly or indirectly, by Diamond Foreign Asset Company, or DFAC, a Cayman Islands
subsidiary that we own. It is our intention to indefinitely reinvest future earnings of DFAC and its foreign
subsidiaries to finance foreign activities. Accordingly, we have not made a provision for U.S. income taxes on
approximately $2.0 billion of undistributed foreign earnings and profits. Although we do not intend to repatriate
the earnings of our foreign subsidiary, and have not provided U.S. income taxes for such earnings, except to the
extent that such earnings were immediately subject to U.S. income taxes, these earnings could become subject to
U.S. income tax if remitted, or if deemed remitted as a dividend; however, it is not practical to estimate this
potential liability.
The components of income tax expense (benefit) are as follows:
Year Ended December 31,
2015
2014
2013
Federal – current .....................................................................
State – current .........................................................................
Foreign – current .....................................................................
Total current .................................................................
(In thousands)
$ 63,223 $ 66,843 $ 40,045
(121)
93
59,926 151,339
71,656
126,648
134,972
69
191,453
Federal – deferred ..................................................................
(245,045)
(6,699)
46,767
Foreign – deferred ...................................................................
3,010
8,231
(12,666)
Total deferred ...............................................................
Total ..............................................................................
(242,035)
$ (107,063)
$
1,532
128,180 $
34,101
225,554
75
The difference between actual income tax expense and the tax provision computed by applying the statutory
federal income tax rate to income before taxes is attributable to the following:
Income before income tax expense:
U.S. .....................................................................................
Foreign ................................................................................
Worldwide ..........................................................................
Expected income tax expense at federal statutory rate ............
Foreign earnings of foreign subsidiaries (not taxed at the
statutory federal income tax rate) net of related foreign
taxes ....................................................................................
Foreign earnings of foreign subsidiaries for which U.S.
federal income taxes have been provided ............................
Foreign taxes of domestic and foreign subsidiaries for which
U.S. federal income taxes have also been provided ............
Foreign tax credits ............................................ ……………..
Interest capitalized by foreign subsidiaries .............................
Impact of American Taxpayer Relief Act of 2012…………..
Uncertain tax positions ...........................................................
Amortization of deferred charges associated with
intercompany rig sales to other tax jurisdictions .................
Net expense (benefit) in connection with resolutions of tax
issues and adjustments relating to prior years .....................
Other .......................................................................................
Income tax expense .......................................................
Year Ended December 31,
2015
2014
(In thousands)
2013
$ (11,158)
(370,190)
$ (381,348)
$ (133,472)
$ 288,080
227,111
515,191
$
180,317
$
$ 537,635
236,605
774,240
$
270,984
$
(5,518)
(46,163)
(102,359)
9
7,190
805
27,193
(26,590)
(5,708)
--
1,169
38,358
(39,843)
(16,492)
--
(47,964)
45,428
(46,524)
(18,391)
(27,509)
66,085
38,466
44,301
30,894
(2,283)
(329)
$ (107,063)
$
7,775
701
128,180
$
4,804
1,337
225,554
Deferred Income Taxes. Significant components of our deferred income tax assets and liabilities are as follows:
Deferred tax assets:
Net operating loss carryforwards, or NOLs................
Foreign tax credits ......................................................
Worker’s compensation and other current accruals…
Bareboat charter deductions .......................................
UK depreciation deduction ........................................
Disputed receivables reserved ....................................
Deferred compensation ..............................................
Foreign contribution taxes ..........................................
Stock compensation awards .......................................
Deferred deductions ...................................................
Interest -Uncertain Tax Positions…………………...
Other .........................................................................
Total deferred tax assets (1) ......................................
Valuation allowance for NOLs ..................................
Valuation allowance for foreign tax credits ...............
Valuation allowance for other deferred tax assets ......
Net deferred tax assets ............................................
Deferred tax liabilities:
Depreciation ...............................................................
Mobilization ...............................................................
Unbilled revenue ........................................................
Undistributed earnings of foreign subsidiaries ...........
Other ..........................................................................
Total deferred tax liabilities ....................................
Net deferred tax liability ...................................
76
December 31,
2015
2014
(In thousands)
$ 143,231
33,699
19,888
32,469
17,358
3,109
5,362
3,630
11,294
14,185
1,153
2,089
287,467
(93,191)
--
(53,456)
140,820
20,277
$
17,962
19,155
21,898
--
2,438
14,409
5,345
10,627
12,196
1,011
2,244
127,562
(20,277)
(516)
(27,243)
79,526
(372,334)
(30,990)
(13,971)
(50)
(4)
(417,349)
(577,103)
(10,655)
(6,518)
(24)
(8)
(594,308)
$ (276,529) $ (514,782)
(1)
__________
In 2015, we adopted ASU 2015-17, as allowed by the standard. In order to reduce the complexity of
our financial statements we are no longer separating deferred income liabilities and assets into
current and noncurrent classifications. Prior periods were not retrospectively adjusted and
accordingly, at December 31, 2014, $15.6 million was reflected in “Prepaid expenses and other
current assets” in our Consolidated Balance Sheets. See Notes 1 and 3.
We record a valuation allowance to derecognize a portion of our deferred tax assets, which we do not expect
to be ultimately realized. A summary of changes in the valuation allowance is as follows:
For the Year Ended December 31,
2013
2014
2015
(In thousands)
Valuation allowance as of January 1 ............................................ $ 48,036
Establishment of valuation allowances:
Net operating losses ................................................................ 82,155
Foreign tax credits .................................................................. --
Other deferred tax assets ........................................................ 27,928
Releases of valuation allowances in various jurisdictions ............ (11,472)
Valuation allowance as of December 31 ...................................... $ 146,647
$
7,321 $ 22,876
15,677
516
27,243
(2,721)
$
48,036 $
25
--
--
(15,580)
7,321
Net Operating Loss Carryforwards – As of December 31, 2015, we had recorded a deferred tax asset of
$143.2 million for the benefit of NOL carryforwards; $49.3 million related to our U.S. losses and $93.9 million
related to our international operations. Approximately $28.6 million of this deferred tax asset relates to NOL
carryforwards that have an indefinite life. The remaining $114.6 million relates to NOL carryforwards of our
subsidiaries in Mexico, Hungary and the United States. Unless utilized, tax benefits of NOL carryforwards will
expire between 2020 and 2035 as follows:
Year Expiring
2020 ..........................................................................................
2021 .....................................................................................................
2022 .....................................................................................................
2023 ..........................................................................................
2024 ..........................................................................................
2025 .....................................................................................................
2035 ..........................................................................................
Total ........................................................................................
Tax Benefit of
NOL
Carryforwards
(In millions)
$
56.1
0.2
0.1
0.1
--
8.8
49.3
114.6
$
As of December 31, 2015, a valuation allowance for $93.2 million has been recorded for our NOLs for which
the deferred tax assets are not likely to be realized.
Foreign Tax Credits. As of December 31, 2015, we had recorded a deferred tax asset of $33.7 million for the
benefit of foreign tax credits in the U.S. Unless utilized, our excess foreign tax credits in the U.S. will expire in
2024 and 2025 as follows:
Foreign Tax
Credits
Year Expiring
2024 ..........................................................................................
2025 ..........................................................................................
Total ........................................................................................
$
(In millions)
4.8
28.9
33.7
$
As of December 31, 2015, no valuation allowance has been recorded for our foreign tax credits.
77
Valuation Allowances - Other Deferred Tax Assets. As of December 31, 2015, we recorded valuation
allowances for other deferred tax assets as follows:
Deferred Tax Asset
Bareboat charter deductions in the UK .....................................
Depreciation deduction in the UK ..................................................
Foreign contribution taxes in Brazil ..........................................
Total ........................................................................................
Valuation
Allowance
(In millions)
$
32.5
17.4
3.6
53.5
$
Unrecognized Tax Benefits. Our income tax returns are subject to review and examination in the various
jurisdictions in which we operate and we are currently contesting various tax assessments. We accrue for income
tax contingencies, or uncertain tax positions, that we believe are more likely than not exposures. A reconciliation
of the beginning and ending amount of unrecognized tax benefits, gross of tax carryforwards and excluding
interest and penalties, is as follows:
Balance, beginning of period .................................................... $
Additions for current year tax positions ..............................
Additions for prior year tax positions .................................
Reductions for prior year tax positions ...............................
Reductions related to statute of limitation expirations ........
Balance, end of period .............................................................. $
(57,116)
(7,013)
(82)
2,673
7,586
(53,952)
2015
2013
For the Year Ended December 31,
2014
(In thousands)
$
(90,921)
(5,813)
(292)
34,630
5,280
$ (57,116)
$
(67,150)
(1,724)
(31,264)
7,280
1,937
$ (90,921)
At December 31, 2015, $2.8 million, $1.9 million and $50.3 million of the net liability for uncertain tax
positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively. At
December 31, 2014, $4.9 million and $55.4 million of the net liability for uncertain tax positions were reflected in
“Other assets” and “Other liabilities,” respectively. Of the net unrecognized tax benefits at December 31, 2015,
2014 and 2013, all $49.4 million, $50.5 million and $76.3 million, respectively, would affect the effective tax
rates if recognized.
The following table presents the amount of accrued interest and penalties at December 31, 2015 and 2014
related to uncertain tax positions:
December 31,
2015
2014
(In thousands)
Uncertain tax positions net, excluding interest and penalties ........................
Accrued interest on uncertain tax positions .............................................
Accrued penalties on uncertain tax positions ...........................................
Uncertain tax positions net, including interest and penalties ........................
$ (49,380)
(2,743)
(39,924)
$ (92,047)
$
$
(50,513)
(7,503)
(37,622)
(95,638)
We record interest related to accrued uncertain tax positions in interest expense and recognize penalties
associated with uncertain tax positions in tax expense. Interest expense and penalties recognized during the three
years ended December 31, 2015 related to uncertain tax positions are as follows:
2015
For the Year Ended December 31,
2014
(In thousands)
2013
Net increase (decrease) in interest expense related to
unrecognized tax positions ..............................................
Net increase (decrease) in penalties related to unrecognized
tax positions ....................................................................
$ (4,761)
$
(5,283)
$
5,758
2,302
(22,175)
38,136
In several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter
into agreements with other of our wholly-owned subsidiaries to provide specialized services and equipment in
support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be
78
charged for providing the services and equipment. In most cases, there are alternative transfer pricing
methodologies that could be applied to these transactions and, if applied, could result in different chargeable
amounts. Taxing authorities in the various foreign locations in which we operate could apply one of the
alternative transfer pricing methodologies which could result in an increase to our income tax liabilities with
respect to tax returns that remain subject to examination.
We expect the statute of limitations for the 2010 tax year to expire in 2016 for one of our subsidiaries
operating in Mexico, and we anticipate that the related unrecognized tax benefit will decrease by $0.7 million at
that time.
Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state
jurisdictions and various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions
include years 2009 to 2015. We are currently under audit in several of these jurisdictions. We do not anticipate
that any adjustments resulting from the tax audit of any of these years will have a material impact on our
consolidated results of operations, financial condition or cash flows.
U.S. Jurisdiction. Our 2013 tax year is currently under audit by the U.S. Internal Revenue Service.
Brazil Tax Jurisdiction. In December 2009, we received an assessment of approximately $26.0 million for
the years 2004 and 2005, including interest and penalty. We contested the tax assessment in 2010 and, during the
third quarter of 2014, received a favorable court decision resulting in the closure of the 2004 and 2005 tax years.
As a consequence, we reversed our $14.0 million reserve for this uncertain tax position, of which $3.5 million was
interest and $4.4 million was penalty.
In March 2013, the Brazilian tax authorities began an audit of our income tax returns for the years 2009 and
2010. The tax audit is still ongoing.
In February 2012, the tax authorities concluded their audit of our income tax return for the 2007 tax year for
which we received an assessment of approximately $17.1 million for income tax, including interest and penalties.
We contested the assessment and a court in Brazil ruled to cancel the assessment. However, the Brazilian tax
authorities have appealed the ruling, and we are awaiting the outcome of the appeal. We have not accrued any tax
expense related to this assessment.
In addition, the Brazilian tax authorities have issued an assessment for the 2000 tax year of approximately
$1.5 million, including interest and penalty. We have appealed the tax assessment and are awaiting the outcome
of the appeal.
Egypt Tax Jurisdiction. During 2013, we were under audit by the Egyptian tax authorities for the tax years
2006 through 2010. In 2013, after receiving notification that the Egyptian government had concluded the income
tax audit for the period 2006 to 2008 and proposed a $1.2 billion increase to taxable income, we accrued an
additional $56.9 million of expense for uncertain tax positions in Egypt for all open years. During the first quarter
of 2014, we settled certain disputes for the years 2006 through 2008 with the Egyptian tax authorities, which
resulted in an aggregate $17.2 million reduction in tax expense, comprised of a $23.2 million reversal of uncertain
tax positions, partially offset by $6.0 million in current foreign income tax expense. One issue for the 2006
through 2008 period remains open, which we appealed. Our court case is scheduled to occur in the first quarter of
2016. We have sought assistance from an agency of the U.S. Treasury Department, pursuant to international tax
treaties, and continue to believe that our position will, more likely than not, be sustained. However, if our position
is not sustained, tax expense and related penalties would increase by approximately $53 million related to this
issue for the 2006 through 2008 tax years as of December 31, 2015.
We are currently also under audit by the Egyptian tax authorities for the tax years 2009 through 2012.
Malaysia Tax Jurisdiction. During the third quarter of 2014, we received final approval from the Malaysian
tax authorities for the settlement of tax liabilities and penalties for the years 2003 through 2008 resulting in the
reversal of a $14.2 million reserve for uncertain tax positions for these years, of which $5.3 million was penalty.
Mexico Tax Jurisdiction. During the year ended December 31, 2015, the statute of limitations for the 2008
tax year related to an uncertain tax position expired and we reversed our $3.8 million tax accrual, of which $1.3
million was interest and $0.5 million was penalty. In addition, the statute of limitations for the 2009 tax year
79
related to an uncertain tax position expired, and we reversed our $10.7 million tax accrual, of which $3.6 million
was interest and $1.4 million was penalty.
In August 2015, the Mexican tax authorities completed an audit for the 2008 tax year for one of our
subsidiaries operating in Mexico and issued an assessment in the amount of $5.3 million, including interest and
penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal. We have not accrued
any tax expense related to this assessment. In June 2015, the Mexican tax authorities initiated an audit of the 2009
income tax return of one of our other subsidiaries operating in Mexico.
Due to the 2014 expiration of the statute of limitations in Mexico for the 2008 tax year for one of our
subsidiaries operating in Mexico, we reversed our $8.0 million accrual for an uncertain tax position, of which $2.7
million was interest and $1.1 million was penalty, during the year ended December 31, 2014.
The tax authorities in Mexico previously audited our income tax returns for the years 2004 and 2006 and had
issued assessments for tax years 2004 and 2006 of approximately $22.9 million and $24.4 million, respectively,
including interest and penalties, which we had appealed. In 2013 the Mexican tax authorities initiated a tax
amnesty program whereby income tax assessments, including penalties and interest, could be partially or
completely waived. Under the tax amnesty, we were able to settle our tax liabilities for the years 2004 and 2006
for a net cash cost of $3.7 million. As a result of increases in uncertain tax positions for later years, we recorded
an additional $13.2 million of expense, including $5.0 million of interest and $2.7 million of penalties, during the
year ended December 31, 2013.
Due to the expiration of the statute of limitations in Mexico for the 2007 tax year, during the second quarter
of 2013, we reversed our $4.3 million accrual for this uncertain tax position, of which $1.5 million was interest
and $0.6 million was penalty.
Australia Jurisdiction. We are currently under audit for tax years 2010 through 2013.
American Taxpayer Relief Act of 2012. The American Taxpayer Relief Act of 2012, or the Act, was signed
into law on January 2, 2013. The Act extended through 2013 several expired or expiring temporary business
provisions, commonly referred to as “extenders,” which were retroactively extended to the beginning of 2012. As
required by GAAP, the effects of new legislation are recognized when signed into law. Consequently, we reduced
our 2013 tax expense by $27.5 million as a result of recognizing the 2012 effect of the extenders.
16. Employee Benefit Plans
Defined Contribution Plans
We maintain defined contribution retirement plans for our U.S., U.K. and third-country national, or TCN,
employees. The plan for our U.S. employees, or the 401k Plan, is designed to qualify under Section 401(k) of the
Code. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible
earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings.
A participating employee may also elect to make after-tax contributions to the 401k Plan. During each of the
years ended December 31, 2015, 2014 and 2013, we matched up to 6% of each employee’s compensation
contributed to the 401k Plan. During the four months ended April 30, 2015 and the years ended December 31,
2014 and 2013, we made discretionary profit sharing contributions of 4% of a participant’s defined compensation
to the 401k Plan. We ceased making profit sharing contributions under the 401k Plan on May 1, 2015.
Participants are fully vested in the employer match immediately upon enrollment in the 401k Plan and subject to a
three-year cliff vesting period for any profit sharing contribution. For the years ended December 31, 2015, 2014
and 2013, our provision for contributions was $23.8 million, $34.1 million and $29.6 million, respectively.
The defined contribution retirement plan for our U.K. employees provides that we make annual contributions
in an amount equal to the employee's contributions generally up to a maximum percentage of the employee's
defined compensation per year. For each of the years ended December 31, 2015, 2014 and 2013, our contribution
for employees working in the U.K. sector of the North Sea was up to a maximum of 10%, of the employee's
defined compensation. Our provision for contributions was $3.4 million, $5.0 million and $3.5 million for the
years ended December 31, 2015, 2014 and 2013, respectively.
The defined contribution retirement plan for our TCN employees, or International Savings Plan, is similar to
the 401k Plan. During each of the years ended December 31, 2015, 2014 and 2013, we matched up to 6% of each
80
employee’s compensation contributed to the International Savings Plan. During the four months ended April 30,
2015 and the years ended December 31, 2014 and 2013, we made discretionary profit sharing contributions of 4%
of a participant’s defined compensation to the International Savings Plan. We ceased making profit sharing
contributions under this plan on May 1, 2015. Our provision for contributions was $2.2 million, $3.7 million and
$3.1 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Deferred Compensation and Supplemental Executive Retirement Plan
Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement
Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly compensated
employees to compensate such employees for any portion of our base salary contribution and/or matching
contribution under the 401k Plan that could not be contributed to that plan because of limitations within the Code.
Our provision for contributions to the Supplemental Plan for the years ended December 31, 2015, 2014 and 2013
was approximately $153,000, $265,000 and $261,000, respectively.
17. Segments and Geographic Area Analysis
Although we provide contract drilling services with different types of offshore drilling rigs and also provide
such services in many geographic locations, we have aggregated these operations into one reportable segment
based on the similarity of economic characteristics due to the nature of the revenue earning process as it relates to
the offshore drilling industry over the operating lives of our drilling rigs.
Revenues from contract drilling services by equipment-type are listed below:
Year Ended December 31,
2015
2014
2013
(In thousands)
Floaters:
Ultra-Deepwater .......................................... $ 1,339,059
548,667
Deepwater ...................................................
Mid-Water ...................................................
387,549
Total Floaters ............................................ 2,275,275
84,909
Jack-ups ........................................................
Total contract drilling revenues ............
2,360,184
59,209
Revenues related to reimbursable expenses ..
Total revenues ....................................... $ 2,419,393
$
987,565
494,247
1,076,842
2,558,654
178,472
2,737,126
77,545
$ 2,814,671
$
854,515
617,080
1,197,934
2,669,529
174,055
2,843,584
76,837
$ 2,920,421
Geographic Areas
Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to
market conditions or customer needs. At December 31, 2015, our actively-marketed drilling rigs were en route to
or located offshore seven countries in addition to the United States. Revenues by geographic area are presented
by attributing revenues to the individual country or areas where the services were performed.
United States .................................................
$
International:
South America ............................................
Europe/Africa/Mediterranean .....................
Australia/Asia .............................................
Mexico .......................................................
2015
Year Ended December 31,
2014
(In thousands)
418,095
$
$
513,605
812,271
532,824
415,033
145,660
1,905,788
1,088,796
558,367
503,814
245,599
2,396,576
2013
330,471
1,219,287
731,888
438,814
199,961
2,589,950
Total revenues .......................................
$ 2,419,393
$ 2,814,671
$ 2,920,421
81
An individual international country may, from time to time, comprise a material percentage of our total
contract drilling revenues from unaffiliated customers. For the years ended December 31, 2015, 2014 and 2013,
individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers
are listed below.
Year Ended December 31,
2014
2015
2013
Brazil ..............................................................
United Kingdom .............................................
Trinidad ..........................................................
Romania ..........................................................
Australia .........................................................
Malaysia .........................................................
Mexico ............................................................
23.1%
11.4%
9.8%
9.7%
7.0%
6.8%
6.0%
31.0%
10.7%
4.0%
3.9%
6.4%
5.5%
8.7%
38.3%
7.9%
1.7%
--
3.2%
2.9%
6.9%
The following table presents our long-lived tangible assets by geographic location as of December 31, 2015,
2014 and 2013. A substantial portion of our assets is comprised of rigs that are mobile, and therefore asset
locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings
generated by such assets during the periods and may vary from period to period due to the relocation of rigs. In
circumstances where our drilling rigs were in transit at the end of a calendar year, they have been presented in the
tables below within the geographic area in which they were expected to operate.
2015(1)
December 31,
2014
(In thousands)
2013
Drilling and other property and equipment, net:
United States(2) ..............................................
$ 3,292,474
$ 2,637,621
$ 611,731
International:
Australia/Asia/Middle East (3) ....................
South America ...........................................
Europe/Africa/Mediterranean .....................
Mexico ........................................................
1,224,089
1,051,283
664,520
146,448
3,086,340
1,460,841
1,445,832
1,128,857
272,802
4,308,332
2,078,348
1,690,976
793,097
293,075
4,855,496
Total ......................................................
$ 6,378,814
$ 6,945,953
$ 5,467,227
(1) During 2015, we recorded an aggregate impairment loss of $860.4 million to write down certain of
our drilling rigs with indicators of impairment to their estimated recoverable amounts.
(2) Long-lived tangible assets in the United States region as of December 31, 2015 and December 31,
2014 included $2.6 billion and $1.9 billion, respectively, related to our newbuild drillships, three
of which were located in GOM waters in 2014 and the fourth of which arrived in 2015.
(3) Long-lived tangible assets in the Australia/Asia/Middle East region include $270.0 million, $439.2
million and $1,064.5 million in construction work-in-progress for rigs under construction in South
Korea as of December 31, 2015, 2014 and 2013, respectively.
82
The following table presents the countries in which material concentrations of our long-lived tangible assets
were located as of December 31, 2015, 2014 and 2013:
United States .................................................
Brazil.............................................................
Malaysia ........................................................
South Korea ..................................................
Spain .............................................................
Mexico ..........................................................
Vietnam .........................................................
Singapore ......................................................
Angola...........................................................
Indonesia .......................................................
2015
December 31,
2014
2013
51.6%
15.3%
10.4%
4.2%
2.7%
2.3%
--
--
--
--
38.0%
20.3%
6.6%
6.3%
8.1%
3.9%
6.9%
--
--
--
11.2%
30.2%
4.3%
19.5%
1.2%
5.4%
0.6%
8.2%
6.3%
5.2%
As of December 31, 2015, 2014 and 2013, no other countries had more than a 5% concentration of our long-
lived tangible assets.
Major Customers
Our customer base includes major and independent oil and gas companies and government-owned oil
companies. Revenues from our major customers for the years ended December 31, 2015, 2014 and 2013 that
contributed more than 10% of our total revenues are as follows:
Customer
2015
2014
2013
Year Ended December 31,
Petróleo Brasileiro S.A. .....................................
ExxonMobil ........................................................
Anadarko ............................................................
24.1%
12.4%
12.4%
31.9%
5.0%
3.6%
33.6%
--
--
18. Unaudited Quarterly Financial Data
Unaudited summarized financial data by quarter for the years ended December 31, 2015 and 2014 is shown
below.
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(In thousands, except per share data)
2015
Revenues ...........................................................
Operating (loss) income (1) ................................
(Loss) income before income tax expense ........
Net (loss) income ..............................................
Net (loss) income per share, basic and diluted ..
2014
Revenues ...........................................................
Operating income ..............................................
Income before income tax expense ...................
Net income ........................................................
Net income per share, basic and diluted ............
$
620,056
(269,530)
(287,118)
(255,709)
$ (1.86)
$ 634,032
134,121
106,028
90,386
$ 0.66
$ 609,742
181,434
159,767
136,422
$ 555,563
(340,099)
(360,025)
(245,384)
$ 0.99 $ (1.79)
$ 709,424
186,277
167,679
145,810
$ 1.05
$ 692,244
133,766
112,603
89,713
$ 0.65
$ 737,682
90,416
81,639
52,645
$ 675,321
162,103
153,270
98,843
$ 0.38 $ 0.72
(1) During the first, third and fourth quarters of 2015, we recognized impairment losses of $358.5
million, $2.6 million and $499.4 million, respectively, aggregating $860.4 million for the year ended
December 31, 2015 to write down certain of our drilling rigs with indicators of impairment to their
estimated recoverable amounts. See Notes 1 and 2.
83
19. Subsequent Event
In February 2016, we entered into a ten-year agreement with GE Oil & Gas, or GE, to provide services with
respect to certain blowout preventer and related well control equipment on our four newbuild drillships. Such
services include management of maintenance, certification and reliability with respect to such equipment. In
connection with the services agreement with GE, we will sell the equipment to a GE affiliate for an aggregate
$210.0 million and will lease back such equipment over separate ten-year operating leases. We do not expect to
realize any gain or loss on these sale and leaseback transactions. Future commitments for the full term under the
services agreement and leases are estimated to aggregate approximately $650.0 million.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Not applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures which are designed to ensure that information
required to be disclosed by us in reports that we file or submit under the federal securities laws, including this
report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and
procedures include controls and procedures designed to ensure that information required to be disclosed by us
under the federal securities laws is accumulated and communicated to our management on a timely basis to allow
decisions regarding required disclosure.
Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by
our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules
13a-15(e) and 15d-15(e)) as of December 31, 2015. Based on their participation in that evaluation, our CEO and
CFO concluded that our disclosure controls and procedures were effective as of December 31, 2015.
Internal Control Over Financial Reporting
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Diamond Offshore Drilling, Inc. Our
internal control system was designed to provide reasonable assurance to our management and Board of Directors
regarding the preparation and fair presentation of published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including
the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a
control system must reflect the fact that there are resource constraints, and the benefits of controls must be
considered relative to their costs. Management must make judgments with respect to the relative cost and
expected benefits of any specific control measure. The design of a control system also is based in part upon
assumptions and judgments made by management about the likelihood of future events, and there can be no
assurance that a control will be effective under all potential future conditions. As a result, even an effective system
of internal controls can provide no more than reasonable assurance with respect to the fair presentation of
financial statements and the processes under which they were prepared.
Our management assessed the effectiveness of our internal control over financial reporting as of December
31, 2015. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based
on this assessment our management believes that, as of December 31, 2015, our internal control over financial
reporting was effective.
Deloitte & Touche LLP, the registered public accounting firm that audited our financial statements included
in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of our internal control
84
over financial reporting. The attestation report of Deloitte & Touche LLP is included at the beginning of Item 8 of
this Form 10-K.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting identified in connection with the
foregoing evaluation that occurred during our fourth fiscal quarter of 2015 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
Not applicable.
PART III
Reference is made to the information responsive to Items 10, 11, 12, 13 and 14 of this Part III contained in our
definitive proxy statement for our 2016 Annual Meeting of Stockholders, which is incorporated herein by reference.
Item 10. Directors, Executive Officers and Corporate Governance.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Item 14. Principal Accountant Fees and Services.
Item 15. Exhibits and Financial Statement Schedules.
PART IV
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements
Report of Independent Registered Public Accounting Firm ....................
Consolidated Balance Sheets ...................................................................
Consolidated Statements of Operations ...................................................
Consolidated Statements of Comprehensive Income ...............................
Consolidated Statements of Stockholders’ Equity ...................................
Consolidated Statements of Cash Flows ..................................................
Notes to Consolidated Financial Statements ............................................
(2) Exhibit Index
Page
46
48
49
50
51
52
53
88
See the Exhibit Index for a list of those exhibits filed herewith, which Exhibit Index also includes and identifies
management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by
Item 601 of Regulation S-K.
85
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 19,
2016.
DIAMOND OFFSHORE DRILLING, INC.
By: /s/ GARY T. KRENEK
Gary T. Krenek
Senior Vice President and Chief Financial Officer
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Gary T. Krenek and David L. Roland and
each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-
substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all
documents relating to this Annual Report on Form 10-K, including any and all amendments and supplements thereto,
and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and
Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform
each and every act and thing requisite and necessary to be done, as fully as to all intents and purposes as he or she
might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or their or his
or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ MARC EDWARDS
Marc Edwards
President, Chief Executive Officer and
Director (Principal Executive Officer)
February 19, 2016
/s/ GARY T. KRENEK
Gary T. Krenek
/s/ BETH G. GORDON
Beth G. Gordon
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
February 19, 2016
Controller (Principal Accounting Officer) February 19, 2016
/s/ JAMES S. TISCH
Chairman of the Board
February 19, 2016
James S. Tisch
/s/ JOHN R. BOLTON
John R. Bolton
Director
February 19, 2016
/s/ CHARLES L. FABRIKANT __
Director
February 19, 2016
Charles L. Fabrikant
/s/ PAUL G. GAFFNEY II
Paul G. Gaffney II
/s/ EDWARD GREBOW
Edward Grebow
Director
Director
February 19, 2016
February 19, 2016
/s/ HERBERT C. HOFMANN
Director
February 19, 2016
Herbert C. Hofmann
86
/s/ KENNETH I. SIEGEL
Kenneth I. Siegel
/s/ CLIFFORD M. SOBEL
Clifford M. Sobel
/s/ ANDREW H. TISCH
Andrew H. Tisch
/s/ RAYMOND S. TROUBH
Raymond S. Troubh
Director
Director
Director
Director
February 19, 2016
February 19, 2016
February 19, 2016
February 19, 2016
87
Exhibit No.
3.1
Description
Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by
reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30,
2003) (SEC File No. 1-13926).
EXHIBIT INDEX
3.2
4.1
4.2
4.3
4.4
10.1
10.2
10.3
10.4+
10.5+
10.6+
10.7+
10.8+
Amended and Restated By-laws (as amended through October 4, 2013) of Diamond Offshore Drilling,
Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 8, 2013).
Indenture, dated as of February 4, 1997, between Diamond Offshore Drilling, Inc. and The Bank of New
York Mellon Trust Company, N.A. (formerly known as The Bank of New York) (as successor to The
Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.1 to our Annual Report on
Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).
Sixth Supplemental Indenture, dated as of May 4, 2009, between Diamond Offshore Drilling, Inc. and
The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York
Mellon), as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed
May 4, 2009) (SEC File No. 1-13926).
Seventh Supplemental Indenture, dated as of October 8, 2009, between Diamond Offshore Drilling, Inc.
and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York
Mellon), as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed
October 8, 2009) (SEC File No. 1-13926).
Eighth Supplemental Indenture, dated as of November 5, 2013, between Diamond Offshore Drilling,
Inc. and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New
York Mellon), as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K
filed November 5, 2013).
Registration Rights Agreement (the “Registration Rights Agreement”) dated October 16, 1995 between
Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.1 to our Annual
Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).
Amendment to the Registration Rights Agreement, dated September 16, 1997, between Loews and
Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.2 to our Annual Report on
Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).
Services Agreement, dated October 16, 1995, between Loews and Diamond Offshore Drilling, Inc.
(incorporated by reference to Exhibit 10.3 to our Annual Report on Form 10-K for the fiscal year ended
December 31, 2001) (SEC File No. 1-13926).
Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement
Plan effective as of January 1, 2007 (incorporated by reference to Exhibit 10.4 to our Annual Report on
Form 10-K for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).
Diamond Offshore Management Bonus Program, as amended and restated, and dated as of December
31, 1997 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal
year ended December 31, 1997) (SEC File No. 1-13926).
Diamond Offshore Drilling, Inc. Equity Incentive Compensation Plan (incorporated by reference to
Exhibit B attached to our definitive proxy statement on Schedule 14A filed April 1, 2014).
Form of Stock Option Certificate for grants to executive officers, other employees and consultants
pursuant to the Equity Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to our
Current Report on Form 8-K filed October 1, 2004) (SEC File No. 1-13926).
Form of Stock Option Certificate for grants to non-employee directors pursuant to the Equity Incentive
Compensation Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed
October 1, 2004) (SEC File No. 1-13926).
88
10.9+
10.10+
10.11+
10.12+
10.13+
10.14+
10.15+
10.16+
10.17+
10.18+
10.19+
10.20
10.21
10.22
The Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (as Amended
and Restated as of March 28, 2014) (incorporated by reference to Exhibit A attached to our definitive
proxy statement on Schedule 14A filed April 1, 2014).
Form of Award Certificate for stock appreciation right grants to the Company’s executive officers, other
employees and consultants pursuant to the Equity Incentive Compensation Plan (incorporated by
reference to Exhibit 10.1 to our Current Report on Form 8-K filed April 28, 2006) (SEC File No. 1-
13926).
Form of Award Certificate for stock appreciation right grants to non-employee directors pursuant to the
Equity Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to our Quarterly Report
on Form 10-Q for the quarterly period ended March 31, 2007) (SEC File No. 1-13926).
Form of Award Certificate for grants of Performance Restricted Stock Units under the Equity Incentive
Compensation Plan (incorporated by reference to Exhibit 10.5 to our Quarterly Report Form 10-Q for
the quarterly period ended March 31, 2014).
Specimen Agreement for grants of restricted stock units to officers under the Equity Incentive
Compensation Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed
March 30, 2015).
Specimen Agreement for grants of restricted stock units to the Chief Executive Officer under the Equity
Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to our Current Report on 8-K
filed March 30, 2015).
Employment Agreement between Diamond Offshore Management Company and Gary T. Krenek dated
as of December 15, 2006 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K
filed December 21, 2006) (SEC File No. 1-13926).
Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew dated
as of December 15, 2006 (incorporated by reference to Exhibit 10.17 to our Annual Report on Form 10-
K for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).
Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon dated
as of January 3, 2007 (incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K
for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).
Amendment to Employment Agreement, dated April 1, 2015, between Diamond Offshore Management
Company and Beth G. Gordon (incorporated by reference to Exhibit 10.4 to our Quarterly Report on
Form 10-Q for the quarterly period ended March 31, 2015).
Separation Agreement and General Release, dated March 30, 2015, between Diamond Offshore
Management Company and John M. Vecchio (incorporated by reference to Exhibit 10.2 to our
Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015).
5-Year Revolving Credit Agreement, dated as of September 28, 2012, among Diamond Offshore
Drilling, Inc., Wells Fargo Bank, National Association, as administrative agent and swingline lender, the
issuing banks named therein and the lenders named therein (incorporated by reference to Exhibit 10.1 to
our Current Report on Form 8-K filed October 1, 2012).
Extension Agreement and Amendment No. 1 to Credit Agreement, dated as of December 9, 2013,
among Diamond Offshore Drilling, Inc., Wells Fargo Bank, National Association, as an issuing bank, as
swingline lender and as administrative agent for the lenders, and the lenders named therein
(incorporated by reference to Exhibit 10.20 to our Annual Report on Form 10-K for the fiscal year
ended December 31, 2013).
Commitment Increase and Amendment No. 2 to Credit Agreement, dated as of March 17, 2014, among
Diamond Offshore Drilling, Inc., Wells Fargo Bank, National Association, as an issuing bank, as
swingline lender and as administrative agent for the lenders, and the lenders named therein
(incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarterly
89
period ended March 31, 2014).
10.23
10.24
10.25
10.26+
10.27+
10.28+
Commitment Increase and Extension Agreement and Amendment No. 3 to Credit Agreement, dated as
of October 22, 2014, among Diamond Offshore Drilling, Inc., Wells Fargo Bank, National Association,
as administrative agent and swingline lender, the issuing banks named therein and the lenders named
therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed October 24,
2014).
Extension Agreement and Amendment No. 4 to Credit Agreement, dated as of October 22, 2015, among
Diamond Offshore Drilling, Inc., Wells Fargo Bank, National Association, as administrative agent and
swingline lender, the issuing banks named therein and the lenders named therein (incorporated by
reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 2015).
Form of Commercial Paper Dealer Agreement between Diamond Offshore Drilling, Inc. and the Dealer
party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on
February 12, 2015).
Retirement Agreement and General Release between Diamond Offshore Management Company and
Lawrence R. Dickerson dated September 23, 2013 (incorporated by reference to Exhibit 10.1 to our
Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013).
Employment Agreement, dated as of February 12, 2014, between Diamond Offshore Drilling, Inc., and
Marc Edwards (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the
quarterly period ended March 31, 2014).
Separation Agreement and General Release, dated June 11, 2014, between Diamond Offshore
Management Company and William C. Long (incorporated by reference to Exhibit 10.1 to our Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 2014).
12.1*
Statement re Computation of Ratios.
21.1*
List of Subsidiaries of Diamond Offshore Drilling, Inc.
23.1*
Consent of Deloitte & Touche LLP.
24.1*
Power of Attorney (set forth on the signature page hereof).
31.1*
Rule 13a-14(a) Certification of the Chief Executive Officer.
31.2*
Rule 13a-14(a) Certification of the Chief Financial Officer.
32.1*
Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.
101.INS**
XBRL Instance Document.
101.SCH** XBRL Taxonomy Extension Schema Document.
101.CAL** XBRL Taxonomy Calculation Linkbase Document.
101.LAB** XBRL Taxonomy Label Linkbase Document.
101.PRE** XBRL Presentation Linkbase Document.
101.DEF** XBRL Taxonomy Extension Definition.
* Filed or furnished herewith.
** The documents formatted in XBRL (Extensible Business Reporting Language) and attached as
Exhibit 101 to this report are deemed not filed or part of a registration statement or prospectus for
purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18
90
of the Exchange Act, and otherwise, not subject to liability under these sections.
+ Management contracts or compensatory plans or arrangements.
91
BOARD OF DIRECTORS
James S. Tisch
Chairman of the Board,
(cid:39)(cid:76)(cid:68)(cid:80)(cid:82)(cid:81)(cid:71)(cid:3)(cid:50)(cid:424)(cid:86)(cid:75)(cid:82)(cid:85)(cid:72)(cid:3)(cid:39)(cid:85)(cid:76)(cid:79)(cid:79)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)(cid:44)(cid:81)(cid:70)(cid:17)(cid:3)
(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:9)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:427)(cid:70)(cid:72)(cid:85)(cid:15)(cid:3)
(cid:47)(cid:82)(cid:72)(cid:90)(cid:86)(cid:3)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)
Marc Edwards
(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:9)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:427)(cid:70)(cid:72)(cid:85)(cid:15)(cid:3)
(cid:39)(cid:76)(cid:68)(cid:80)(cid:82)(cid:81)(cid:71)(cid:3)(cid:50)(cid:424)(cid:86)(cid:75)(cid:82)(cid:85)(cid:72)(cid:3)(cid:39)(cid:85)(cid:76)(cid:79)(cid:79)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)(cid:44)(cid:81)(cid:70)(cid:17)(cid:3)
John R. Bolton
Senior Fellow,
(cid:36)(cid:80)(cid:72)(cid:85)(cid:76)(cid:70)(cid:68)(cid:81)(cid:3)(cid:40)(cid:81)(cid:87)(cid:72)(cid:85)(cid:83)(cid:85)(cid:76)(cid:86)(cid:72)(cid:3)(cid:44)(cid:81)(cid:86)(cid:87)(cid:76)(cid:87)(cid:88)(cid:87)(cid:72)(cid:3)
Charles L. Fabrikant
Executive Chairman &
(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:427)(cid:70)(cid:72)(cid:85)(cid:15)(cid:3)
(cid:54)(cid:40)(cid:36)(cid:38)(cid:50)(cid:53)(cid:3)(cid:43)(cid:82)(cid:79)(cid:71)(cid:76)(cid:81)(cid:74)(cid:86)(cid:15)(cid:3)(cid:44)(cid:81)(cid:70)(cid:17)
(cid:51)(cid:68)(cid:88)(cid:79)(cid:3)(cid:42)(cid:17)(cid:3)(cid:42)(cid:68)(cid:424)(cid:81)(cid:72)(cid:92)(cid:3)(cid:44)(cid:44)(cid:3)
President Emeritus,
(cid:48)(cid:82)(cid:81)(cid:80)(cid:82)(cid:88)(cid:87)(cid:75)(cid:3)(cid:56)(cid:81)(cid:76)(cid:89)(cid:72)(cid:85)(cid:86)(cid:76)(cid:87)(cid:92)(cid:3)
Edward Grebow
Managing Director,
(cid:48)(cid:82)(cid:85)(cid:74)(cid:68)(cid:81)(cid:3)(cid:45)(cid:82)(cid:86)(cid:72)(cid:83)(cid:75)(cid:3)(cid:55)(cid:85)(cid:76)(cid:36)(cid:85)(cid:87)(cid:76)(cid:86)(cid:68)(cid:81)(cid:3)(cid:47)(cid:47)(cid:38)
Herbert C. Hofmann
Retired Senior Vice President,
(cid:47)(cid:82)(cid:72)(cid:90)(cid:86)(cid:3)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
(cid:46)(cid:72)(cid:81)(cid:81)(cid:72)(cid:87)(cid:75)(cid:3)(cid:44)(cid:17)(cid:3)(cid:54)(cid:76)(cid:72)(cid:74)(cid:72)(cid:79)
Senior Vice President,
(cid:47)(cid:82)(cid:72)(cid:90)(cid:86)(cid:3)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)
(cid:38)(cid:79)(cid:76)(cid:424)(cid:82)(cid:85)(cid:71)(cid:3)(cid:48)(cid:17)(cid:3)(cid:54)(cid:82)(cid:69)(cid:72)(cid:79)
Managing Partner,
(cid:57)(cid:68)(cid:79)(cid:82)(cid:85)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:42)(cid:85)(cid:82)(cid:88)(cid:83)(cid:3)(cid:47)(cid:47)(cid:38)
Andrew H. Tisch
Co-Chairman of the Board,
(cid:47)(cid:82)(cid:72)(cid:90)(cid:86)(cid:3)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)
(cid:53)(cid:68)(cid:92)(cid:80)(cid:82)(cid:81)(cid:71)(cid:3)(cid:54)(cid:17)(cid:3)(cid:55)(cid:85)(cid:82)(cid:88)(cid:69)(cid:75)(cid:3)
Financial Consultant
EXECUTIVE OFFICERS
Marc Edwards
President &
(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:427)(cid:70)(cid:72)(cid:85)
(cid:47)(cid:92)(cid:81)(cid:71)(cid:82)(cid:79)(cid:3)(cid:47)(cid:17)(cid:3)(cid:39)(cid:72)(cid:90)(cid:3)
Senior Vice President,
(cid:58)(cid:82)(cid:85)(cid:79)(cid:71)(cid:90)(cid:76)(cid:71)(cid:72)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)
(cid:42)(cid:68)(cid:85)(cid:92)(cid:3)(cid:55)(cid:17)(cid:3)(cid:46)(cid:85)(cid:72)(cid:81)(cid:72)(cid:78)(cid:3)
Senior Vice President &
(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:50)(cid:427)(cid:70)(cid:72)(cid:85)
(cid:39)(cid:68)(cid:89)(cid:76)(cid:71)(cid:3)(cid:47)(cid:17)(cid:3)(cid:53)(cid:82)(cid:79)(cid:68)(cid:81)(cid:71)(cid:3)
Senior Vice President,
Aaron Sobel
Vice President,
(cid:43)(cid:88)(cid:80)(cid:68)(cid:81)(cid:3)(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)
Terence W. Waldorf
Vice President, Deputy General Counsel
General Counsel & Secretary
(cid:9) Assistant Secretary
Ronald Woll
Senior Vice President &
(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:72)(cid:85)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:50)(cid:427)(cid:70)(cid:72)(cid:85)
Beth G. Gordon
Controller &
(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:50)(cid:427)(cid:70)(cid:72)(cid:85)
SENIOR MANAGEMENT
Mark F. Baudoin
Senior Vice President,
(cid:36)(cid:71)(cid:80)(cid:76)(cid:81)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)
Stephen G. Elwood
Senior Vice President,
(cid:55)(cid:68)(cid:91)(cid:3)
Karl S. Sellers
Senior Vice President,
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Neil Hall
Vice President,
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Tri Le
Vice President,
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Kane Liddelow
Vice President,
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Richard L. Male
Vice President,
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Vice President,
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Tim Osburn
CIO
Jon Richards
Vice President,
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Scott L. Kornblau
Treasurer
CORPORATE INFORMATION
Corporate Headquarters
15415 Katy Freeway
Houston, TX 77094
(281) 492-5300
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(cid:44)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:3)(cid:53)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)
Darren Daugherty
Director, Investor Relations
15415 Katy Freeway
Houston, TX 77094
(281) 492-5370
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The Annual Meeting of Stockholders will
be held on Tuesday, May 17, 2016, at
8:30 (cid:68)(cid:80)(cid:3)(cid:68)(cid:87)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:82)(cid:427)(cid:70)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:47)(cid:82)(cid:72)(cid:90)(cid:86)(cid:3)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)
667 Madison Avenue, New York, NY 10065.
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Computershare
PO Box 30170
College Station, TX 77842
(877) 812-4207
www.computershare.com/investor
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New York Stock Exchange
Trading Symbol “DO”
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Deloitte & Touche (cid:47)(cid:47)(cid:51)
Design / Rigsby Hull, Houston
Printing / RR Donnelley
Photography / Drew Donovan,
Jack Prather and Chris Shinn