2014
ANNUAL
REPORT
FINANCIAL HIGHLIGHTS ( doll ars in millions )
Revenue
$ 2,815
$
2,920
$
2,987
2014
2013
2012
DIAMOND OFFSHORE DRILLING, INC.
Depreciation & Amortization
Operating Expenses
456
2,242
Earnings Before Interest, Taxes, Depreciation & Amortization ( EBITDA )
1,139
Net Income
387
Capital Expenditures
2,033
388
2,119
1,190
549
958
Cash and Investments
$
250
$
2,097
$
Drilling & Other Property & Equipment, Net
Total Assets
Long - term Debt
Shareholders’ Equity
6,946
8,021
2,244
4,451
5,467
8,391
2,494
4,637
393
2,024
1,418
720
702
1,486
4,865
7,235
1,496
4,576
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 38 offshore drilling rigs, including two rigs under
construction. Diamond Offshore's fleet consists of 27 semisubmersibles, one of which is under
construction, five dynamically positioned drillships, one of which is under construction, and six 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 5,200 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 BlackHawk is shown working in the U.S. Gulf of Mexico.
72811rrdD1R1.indd 1
3/25/15 8:10 AM
2014
ANNUAL
REPORT
FINANCIAL HIGHLIGHTS ( doll ars in millions )
Revenue
$ 2,815
$
2,920
$
2,987
2014
2013
2012
DIAMOND OFFSHORE DRILLING, INC.
Depreciation & Amortization
Operating Expenses
456
2,242
Earnings Before Interest, Taxes, Depreciation & Amortization ( EBITDA )
1,139
Net Income
387
Capital Expenditures
2,033
388
2,119
1,190
549
958
Cash and Investments
$
250
$
2,097
$
Drilling & Other Property & Equipment, Net
Total Assets
Long - term Debt
Shareholders’ Equity
6,946
8,021
2,244
4,451
5,467
8,391
2,494
4,637
393
2,024
1,418
720
702
1,486
4,865
7,235
1,496
4,576
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 38 offshore drilling rigs, including two rigs under
construction. Diamond Offshore's fleet consists of 27 semisubmersibles, one of which is under
construction, five dynamically positioned drillships, one of which is under construction, and six 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 5,200 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 BlackHawk is shown working in the U.S. Gulf of Mexico.
72811rrdD1R1.indd 1
3/25/15 8:10 AM
Our Fleet (as of February 9, 2015)
DRILLSHIPS
Ultra-deepwater Rigs (7,500+ Ft.)
¬
¬
¬
¬
Ocean
BlackLion
12,000 Ft.
DP; 7R; 15K; 5M
South Korea
Ocean
BlackRhino
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
BlackHornet
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
BlackHawk
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
Clipper
7,875 Ft.
DP; 15K; 5R
Brazil
Under
Construction
SEMISUBMERSIBLE RIGS
Ultra-deepwater Rigs (7,500+ Ft.)
JACK-UP RIGS
SEMISUBMERSIBLE RIGS
DRILLSHIPS
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B
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k
R
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J
J
J
J
J
J
J
Ocean
GreatWhite
10,000 Ft.
DP; 6R; 15K; 4M
South Korea
Ocean
Valor
10,000 Ft.
DP; 6R; 15K; 4M
Brazil
Ocean
Courage
10,000 Ft.
DP; 6R; 15K; 4M
Brazil
Ocean
Confidence
10,000 Ft.
DP; 6R; 15K; 4M
Canary Islands
Ocean
Monarch
10,000 Ft.
VC; 5R; 15K; 4M
Malaysia
Ocean
Endeavor
10,000 Ft.
VC; 5R; 15K; 4M
Black Sea
Ocean
Rover
8,000 Ft.
VC; 5R; 15K; 4M
Malaysia
Ocean
Baroness
8,000 Ft.
VC; 4R; 15K; 4M
Brazil
MID-WATER RIGS
(400 – 5,000 Ft.)
Under
Construction
Deepwater Rigs (5,000 – 7,500 Ft.)
l
Ocean
Apex
6,000 Ft.
VC; 5R; 15K; 4M
Vietnam
l
Ocean
Onyx
6,000 Ft.
VC; 15K; 4M
GOM
l
Ocean
Victory
5,5 00 Ft.
VC; 15K
GOM
l
Ocean
America
5,500 Ft.
SP; 15K
Australia
Mid-water Rigs (400 – 5,000 Ft.)
J
Ocean
Worker
4,000 Ft.
GOM
(Cold stacked)
J
Ocean
Saratoga
2,200 Ft.
GOM
(Cold stacked)
J
Ocean
Quest
4,000 Ft.
15K
Vietnam
J
Ocean
Guardian
1,500 Ft.
15K
UK
J
Ocean
Patriot
3,000 Ft.
15K
UK
J
Ocean
Princess
1,500 Ft.
15K
UK
J
Ocean
General
3,000 Ft.
Malaysia
(Cold stacked)
J
Ocean
Vanguard
1,500 Ft.
15K
UK
(Cold stacked)
Actively
Marketing
l
Ocean
Valiant
5,500 Ft.
SP; 15K
UK
J
Ocean
Yorktown
2,850 Ft.
Mexico
J
Ocean
Nomad
1,200 Ft.
UK
l
Ocean
Star
5,500 Ft.
VC; 15K
GOM
l
Ocean
Alliance
5,250 Ft.
DP; 15K
Brazil
J
Ocean
Lexington
2,200 Ft.
Trinidad and
Tobago
J
Ocean
Ambassador
1,100 Ft.
Mexico
JACK-UP RIGS
K
Ocean
Scepter
350 Ft.
IC; 15K; 3M
Mexico
Key
K
K
Ocean
Titan
350 Ft.
IC; 3M
GOM
(Cold stacked)
Ocean
King
300 Ft.
IC; 3M
GOM
(Cold stacked)
K
Ocean
Nugget
300 Ft.
IC
Mexico
K
Ocean
Summit
300 Ft.
IC
Mexico
K
Ocean
Spur
300 Ft.
IC
Ecuador
IC Independent-Leg Cantilevered Rig
Ì DP Dynamically Positioned
Ì
Ì GOM U.S. Gulf of Mexico
Ì VC Victory Class
Ì SP Self Propelled
7R Seven Ram Blowout Preventer
Ì 6R Six Ram Blowout Preventer
Ì
Ì 4M Four Mud Pumps
Ì 5M Five Mud Pumps
Ì
15K 15,000 PSI Well Control System
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.
BOARD OF DIRECTORS
Gary T. Krenek
James S. Tisch
Chairman of the Board,
Diamond Offshore Drilling, Inc.
President & Chief Executive Officer,
Loews Corporation
Marc Edwards
President & Chief Executive Officer,
Diamond Offshore Drilling, Inc.
John R. Bolton
Senior Fellow,
American Enterprise Institute
Charles L. Fabrikant
Executive Chairman,
SEACOR Holdings, Inc.
Paul G. Gaffney II
President Emeritus,
Monmouth University
Edward Grebow
Managing Director,
Morgan Joseph TriArtisan LLC
Herbert C. Hofmann
Retired Senior Vice President,
Loews Corporation
Kenneth I. Siegel
Senior Vice President,
Loews Corporation
Clifford M. Sobel
Managing Partner,
Valor Capital Group LLC
Andrew H. Tisch
Co-Chairman of the Board,
Loews Corporation
Raymond S. Troubh
Financial Consultant
EXECUTIVE OFFICERS
Marc Edwards
President & Chief Executive Officer
John M. Vecchio
Executive Vice President
Lyndol L. Dew
Senior Vice President,
Worldwide Operations
Senior Vice President &
Chief Financial Officer
Ronald Woll
Senior Vice President &
Chief Commercial Officer
David L. Roland
Senior Vice President,
Steven A. Nelson
Vice President,
Operations
Jon L. Richards
Vice President,
Operations
Terence W. Waldorf
Vice President, Deputy General Counsel
General Counsel & Secretary
& Assistant Secretary
Beth G. Gordon
Controller
Scott L. Kornblau
Treasurer
SENIOR MANAGEMENT
CORPORATE INFORMATION
Mark F. Baudoin
Senior Vice President,
Administration
Stephen G. Elwood
Senior Vice President,
Tax
Karl S. Sellers
Senior Vice President,
Technical Services
Duane Beair
Vice President,
Purchasing & Materials Control
Aaron Sobel
Vice President,
Human Resources
Neil Hall
Vice President,
Health, Safety & Environment
Tri Le
Vice President,
Subsea
Kane Liddelow
Vice President,
Contracts & Marketing
Richard L. Male
Vice President,
Contracts & Marketing
Diamond Offshore Drilling (UK) Limited
Jimmy R. Moore
Vice President,
Operations
Corporate Headquarters
15415 Katy Freeway
Houston, TX 77094
(281) 492-5300
www.diamondoffshore.com
Investor Relations
Darren Daugherty
Director, Investor Relations
15415 Katy Freeway
Houston, TX 77094
(281) 492-5370
Notice of Annual Meeting
The Annual Meeting of Stockholders will
be held on Tuesday, May 19, 2015, at
8:30 am at the offices of Loews Corporation,
667 Madison Avenue, New York, NY 10065.
Transfer Agent & Registrar
Computershare
PO Box 30170
College Station, TX 77842
(877) 812-4207
www.computershare.com/investor
Stock Exchange Listing
New York Stock Exchange
Trading Symbol “DO”
Independent Auditors
Deloitte & Touche LLP
Design / Rigsby Hull, Houston
Printing / RR Donnelley
Photography / Drew Donovan
72811rrdD1R1.indd 2
3/24/15 5:05 PM
Our Fleet (as of February 9, 2015)
DRILLSHIPS
Ultra-deepwater Rigs (7,500+ Ft.)
¬
¬
¬
¬
Ocean
BlackLion
12,000 Ft.
DP; 7R; 15K; 5M
South Korea
Ocean
BlackRhino
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
BlackHornet
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
BlackHawk
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
Clipper
7,875 Ft.
DP; 15K; 5R
Brazil
Under
Construction
SEMISUBMERSIBLE RIGS
Ultra-deepwater Rigs (7,500+ Ft.)
JACK-UP RIGS
SEMISUBMERSIBLE RIGS
DRILLSHIPS
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B
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a
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k
R
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N
J
J
J
J
J
J
J
Ocean
GreatWhite
10,000 Ft.
DP; 6R; 15K; 4M
South Korea
Ocean
Valor
10,000 Ft.
DP; 6R; 15K; 4M
Brazil
Ocean
Courage
10,000 Ft.
DP; 6R; 15K; 4M
Brazil
Ocean
Confidence
10,000 Ft.
DP; 6R; 15K; 4M
Canary Islands
Ocean
Monarch
10,000 Ft.
VC; 5R; 15K; 4M
Malaysia
Ocean
Endeavor
10,000 Ft.
VC; 5R; 15K; 4M
Black Sea
Ocean
Rover
8,000 Ft.
VC; 5R; 15K; 4M
Malaysia
Ocean
Baroness
8,000 Ft.
VC; 4R; 15K; 4M
Brazil
MID-WATER RIGS
(400 – 5,000 Ft.)
Under
Construction
Deepwater Rigs (5,000 – 7,500 Ft.)
l
Ocean
Apex
6,000 Ft.
VC; 5R; 15K; 4M
Vietnam
l
Ocean
Onyx
6,000 Ft.
VC; 15K; 4M
GOM
l
Ocean
Victory
5,5 00 Ft.
VC; 15K
GOM
l
Ocean
America
5,500 Ft.
SP; 15K
Australia
Mid-water Rigs (400 – 5,000 Ft.)
J
Ocean
Worker
4,000 Ft.
GOM
(Cold stacked)
J
Ocean
Saratoga
2,200 Ft.
GOM
(Cold stacked)
J
Ocean
Quest
4,000 Ft.
15K
Vietnam
J
Ocean
Guardian
1,500 Ft.
15K
UK
J
Ocean
Patriot
3,000 Ft.
15K
UK
J
Ocean
Princess
1,500 Ft.
15K
UK
J
Ocean
General
3,000 Ft.
Malaysia
(Cold stacked)
J
Ocean
Vanguard
1,500 Ft.
15K
UK
(Cold stacked)
Actively
Marketing
l
Ocean
Valiant
5,500 Ft.
SP; 15K
UK
J
Ocean
Yorktown
2,850 Ft.
Mexico
J
Ocean
Nomad
1,200 Ft.
UK
l
Ocean
Star
5,500 Ft.
VC; 15K
GOM
l
Ocean
Alliance
5,250 Ft.
DP; 15K
Brazil
J
Ocean
Lexington
2,200 Ft.
Trinidad and
Tobago
J
Ocean
Ambassador
1,100 Ft.
Mexico
JACK-UP RIGS
K
Ocean
Scepter
350 Ft.
IC; 15K; 3M
Mexico
Key
K
K
Ocean
Titan
350 Ft.
IC; 3M
GOM
(Cold stacked)
Ocean
King
300 Ft.
IC; 3M
GOM
(Cold stacked)
K
Ocean
Nugget
300 Ft.
IC
Mexico
K
Ocean
Summit
300 Ft.
IC
Mexico
K
Ocean
Spur
300 Ft.
IC
Ecuador
IC Independent-Leg Cantilevered Rig
Ì DP Dynamically Positioned
Ì
Ì GOM U.S. Gulf of Mexico
Ì VC Victory Class
Ì SP Self Propelled
7R Seven Ram Blowout Preventer
Ì 6R Six Ram Blowout Preventer
Ì
Ì 4M Four Mud Pumps
Ì 5M Five Mud Pumps
Ì
15K 15,000 PSI Well Control System
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.
BOARD OF DIRECTORS
Gary T. Krenek
James S. Tisch
Chairman of the Board,
Diamond Offshore Drilling, Inc.
President & Chief Executive Officer,
Loews Corporation
Marc Edwards
President & Chief Executive Officer,
Diamond Offshore Drilling, Inc.
John R. Bolton
Senior Fellow,
American Enterprise Institute
Charles L. Fabrikant
Executive Chairman,
SEACOR Holdings, Inc.
Paul G. Gaffney II
President Emeritus,
Monmouth University
Edward Grebow
Managing Director,
Morgan Joseph TriArtisan LLC
Herbert C. Hofmann
Retired Senior Vice President,
Loews Corporation
Kenneth I. Siegel
Senior Vice President,
Loews Corporation
Clifford M. Sobel
Managing Partner,
Valor Capital Group LLC
Andrew H. Tisch
Co-Chairman of the Board,
Loews Corporation
Raymond S. Troubh
Financial Consultant
EXECUTIVE OFFICERS
Marc Edwards
President & Chief Executive Officer
John M. Vecchio
Executive Vice President
Lyndol L. Dew
Senior Vice President,
Worldwide Operations
Senior Vice President &
Chief Financial Officer
Ronald Woll
Senior Vice President &
Chief Commercial Officer
David L. Roland
Senior Vice President,
Steven A. Nelson
Vice President,
Operations
Jon L. Richards
Vice President,
Operations
Terence W. Waldorf
Vice President, Deputy General Counsel
General Counsel & Secretary
& Assistant Secretary
Beth G. Gordon
Controller
Scott L. Kornblau
Treasurer
SENIOR MANAGEMENT
CORPORATE INFORMATION
Mark F. Baudoin
Senior Vice President,
Administration
Stephen G. Elwood
Senior Vice President,
Tax
Karl S. Sellers
Senior Vice President,
Technical Services
Duane Beair
Vice President,
Purchasing & Materials Control
Aaron Sobel
Vice President,
Human Resources
Neil Hall
Vice President,
Health, Safety & Environment
Tri Le
Vice President,
Subsea
Kane Liddelow
Vice President,
Contracts & Marketing
Richard L. Male
Vice President,
Contracts & Marketing
Diamond Offshore Drilling (UK) Limited
Jimmy R. Moore
Vice President,
Operations
Corporate Headquarters
15415 Katy Freeway
Houston, TX 77094
(281) 492-5300
www.diamondoffshore.com
Investor Relations
Darren Daugherty
Director, Investor Relations
15415 Katy Freeway
Houston, TX 77094
(281) 492-5370
Notice of Annual Meeting
The Annual Meeting of Stockholders will
be held on Tuesday, May 19, 2015, at
8:30 am at the offices of Loews Corporation,
667 Madison Avenue, New York, NY 10065.
Transfer Agent & Registrar
Computershare
PO Box 30170
College Station, TX 77842
(877) 812-4207
www.computershare.com/investor
Stock Exchange Listing
New York Stock Exchange
Trading Symbol “DO”
Independent Auditors
Deloitte & Touche LLP
Design / Rigsby Hull, Houston
Printing / RR Donnelley
Photography / Drew Donovan
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Over the past several years, the offshore
drilling market has enjoyed tremendous
growth, benefiting from high oil prices and
oil companies’ willingness to devote
substantial resources to exploring new
deepwater prospects. However, in cyclical
industries such as ours, demand for our
services rises and falls with the price of
hydrocarbons, and in 2014, a number of
industry issues converged to create a
challenging market.
First, over the past several years,
offshore drilling companies ordered a large
number of drilling units in anticipation of
ever-increasing demand, which subsequently
has yet to materialize. Then, as the units
were delivered, oil companies reprioritized
their capital efficiency plans and announced
reductions to their capital spending budgets
and delayed or canceled many of the projects
expected to employ these new vessels.
Marc Edwards
President and Chief Executive Officer
LETTER TO
SHAREHOLDERS
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Finally, over the summer of 2014 oil prices
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began to fall—benchmark pricing for oil fell
more than 50% throughout the year—and
operators responded by further reducing
their exploration and development budgets.
All of these factors have led to a dramatic
shortage of contracting opportunities
for newly delivered units, and we expect
many more rigs across the industry to go
idle during 2015 as they complete their
existing contracts without the prospect for
extensions or new work.
At Diamond Offshore, we have long
memories, and we understand the cyclical
nature of our industry. While we certainly
took advantage of the cycle by growing
our fleet, we did so at a measured pace
that allowed us to maintain a healthy
balance sheet and pass our earnings on
to shareholders through dividends.
Since January of 2006, when Diamond
Offshore began paying a special dividend
to shareholders, we have paid total
dividends of approximately $5.7 billion, or
over $41 per share. This includes $3.50 per
share paid by the Company in 2014.
In light of current market conditions, our
Board of Directors chose not to declare a
special dividend in February 2015, but
maintained a regular quarterly dividend of
$0.125 per share. Given the weakness in
industry fundamentals, we believe it is
prudent to retain cash. Not paying a special
dividend frees up $400 million per year that
we can use to maximize capital flexibility
and, if opportunities present themselves, to
acquire assets at attractive values in this
distressed market. Diamond Offshore
design
ODECO ENHANCED
VICTORY CLASS
year entered service
2014
location
US GOM
availability
Q4 2015
water depths
6,000 FT
drilling depth
30,000 FT
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OCEAN
ONYX
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remains committed to generating
shareholder value and, as exemplified by our
actions, views strategic capital allocation as
a key component of fulfilling that goal.
PRUDENTLY GROWING OUR FLEET
Diamond Offshore took delivery of three
newbuild drillships and two
semisubmersible rigs in 2014, all of which
had drilling contracts in place upon
delivery. Our first newbuild drillship,
the Ocean BlackHawk, began operating in
the Gulf of Mexico in May 2014, and since
then the rig’s crew has delivered best-in-class
operating metrics for a “6th Generation”
rig. In December, we took delivery of
our second and third drillships, the
Ocean BlackHornet and Ocean BlackRhino,
which are now heading towards the
Gulf of Mexico to commence their contracts.
We plan to take delivery of our fourth
and final newbuild drillship, the Ocean
BlackLion, during the first quarter of 2015,
and the rig should also begin working in
the Gulf of Mexico later this year.
It will be particularly advantageous for
us to have all four of these units working
in the same region, close to our corporate
headquarters in Houston, Texas.
The Gulf of Mexico is one of the
lowest-cost offshore drilling markets in
the world, and we are positioned to gain
even greater economies of scale by having
our personnel, spare parts and support
infrastructure for the drillships centrally
located here on the Gulf Coast.
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OCEAN
BLACKHAWK
design
GUSTO P10,000 DW
year entered service
2014
location
US GOM
availability
Q2 2019
water depths
12,000 FT
drilling depth
40,000 FT
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OCEAN
BLACKHORNET
design
GUSTO P10,000 DW
year entered service
2014
location
US GOM
availability
Q2 2020
water depths
12,000 FT
drilling depth
40,000 FT
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The recently delivered deepwater
semisubmersible Ocean Onyx began its
inaugural one-year contract in February
2014, and the rig is now on its way to its
next job in Trinidad. In December, we took
delivery of another deepwater semi-
submersible, the Ocean Apex, which has
begun an assignment in Vietnam.
Additionally, our newbuild harsh
environment semisubmersible, the
Ocean GreatWhite, is scheduled for delivery
in 2016, with its initial contract consisting
of a three-year term off South Australia.
Across the industry, a number of
competitors’ newbuild rigs are being
delivered without immediate prospects
for work. For Diamond Offshore, however,
all of our newbuild units are contracted at
attractive rates into 2019 and beyond.
OCEAN
BLACKRHINO
design
GUSTO P10,000 DW
year entered service
2014
location
US GOM
availability
Q2 2020
water depths
12,000 FT
drilling depth
40,000 FT
CHALLENGES FOR THE MID-WATER FLEET
While we have been able to secure term
backlog for our newest rigs, we believe that
prospects will be far more challenging for our
mid-water fleet. The decline in the price of oil
has contributed to a dearth of opportunities
for mid-water rigs across all geographic
regions, and we expect newer rigs to compete
aggressively against lower-spec units. As a
result, several mid-water rigs in our fleet and
across the industry may be cold stacked
during 2015. Last year, we made the decision
to retire and scrap six of these rigs, which had
an average age of 37 years. Rig retirements
such as these across the industry are one
of several factors that should lead to a firming
of the rig charter market in the future.
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OCEAN
APEX
design
ODECO ENHANCED
VICTORY CLASS
year entered service
2014
location
VIETNAM
availability
Q2 2015
water depths
6,000 FT
drilling depth
30,000 FT
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POSITIONING OUR FLEET FOR THE FUTURE
Since 2009, Diamond Offshore has
purchased, upgraded, built or ordered seven
ultra-deepwater and two deepwater units,
at a cost of more than $5 billion.
These projects represent our ongoing
process of fleet renewal and enhancement.
We will continue to look for other
opportunities to generate long-term value
for shareholders, which in the current down
cycle may take the form of distressed asset
purchases, especially as we expect the
weakness in our industry to persist.
While we cannot predict the timing of a
market recovery, we firmly believe that
offshore drilling is necessary to meet the
growing worldwide demand for
hydrocarbons. Eventually, supply and
demand will find equilibrium as our clients
return to prioritizing production and
reserve replacement. 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.
Marc Edwards
President and Chief Executive Officer
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
È A N N U A L R E P O R T P U R S U A N T T O S E C T I O N 1 3 O R 1 5 ( d )
O F T H E SE C U R I T I E S E X C H A N G E A C T O F 1 9 3 4
For the fiscal year ended December 31, 2014
OR
‘ T R A N S I T I O N R E P O R T PU R S U A N T T O S E C T I O N 1 3 O R 1 5 ( d )
O F T H E SE C U R I T I E S E X C H A N G E A C T O F 1 9 3 4
F o r t h e t r a n s i t i o n p e r i o d f r o m
t o
Commission file number 1-13926
DIAMOND OFFSHORE DRILLING, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
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
Name of each exchange on which registered
Common Stock, $0.01 par value per share
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 Í 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 Í
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 Í 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 Í 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. ‘
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 Í Accelerated filer ‘
Smaller reporting company ‘
Non-accelerated filer ‘
(Do not check if a 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 Í
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, 2014
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest
$3,327,258,180
practicable date.
As of February 16, 2015 Common Stock, $0.01 par value per share
137,147,899 shares
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement relating to the 2015 Annual Meeting of Stockholders of Diamond Offshore
Drilling, Inc., which will be filed within 120 days of December 31, 2014, are incorporated by reference in Part III of
this report.
DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2014
TABLE OF CONTENTS
Cover Page . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Document Table of Contents
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part I
Item 1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4.
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part II
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . .
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . .
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 III
Item 15.
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part IV
Page No.
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PART I
Item 1. Business.
General
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 38 offshore drilling rigs, excluding three mid-water semisubmersible rigs that we
plan to retire and scrap. Our fleet consists of 27 semisubmersibles, including the Ocean GreatWhite, which is under
construction, six jack-ups and five dynamically positioned drillships, including the Ocean BlackLion which is also under
construction. See “— Our Fleet — Fleet Enhancements and Additions” and “— Our Fleet — 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. We were incorporated in Delaware in 1989.
Our Fleet
Our diverse fleet enables us to offer a broad range of services worldwide in both the floater market (ultra-deepwater,
deepwater and mid-water) and the non-floater, or jack-up, market.
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 which 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 either an anchoring system or 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
Rated
Water Depth (a)
(in feet)
Number of Units in Our Fleet
Ultra-Deepwater . . . . . . . . . . .
7,501 to 12,000
Deepwater . . . . . . . . . . . . . . . . .
Mid-Water . . . . . . . . . . . . . . . . .
5,000 to 7,500
400 to 4,999
13 (b)
7
12
(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).
(b) Includes one drillship and one harsh environment semisubmersible rig under construction.
See “— Fleet Enhancements and Additions” for further discussion of our rigs under construction.
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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.
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 late 2014, we took delivery of two ultra-deepwater drillships, the Ocean BlackHornet and Ocean BlackRhino.
Contract preparation work is underway for both rigs, which are expected to commence drilling operations in the U.S. Gulf
of Mexico, or GOM, in the second quarter of 2015. Construction of the Ocean Apex was completed late in the fourth
quarter of 2014, and the rig is currently operating under a one-well contract in Vietnam. We also have two other
construction projects underway.
The following is a summary of our ongoing rig construction projects as of the date of this report:
Rig Name
Rig Type
Estimated
Cost
(In millions)
Expected
Completion
Contract Status
Customer
Location
Ocean BlackLion . . . . . . . . . . . . . . Ultra-deepwater drillship
Ocean GreatWhite . . . . . . . . . . . . Ultra-deepwater semisubmersible
$655
$764
Q1 2015 Hess Corporation GOM
Q1 2016 BP
Australia
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.
See “— Fleet Status” for more detailed information about our drilling fleet.
Fleet Status
The following table presents additional information regarding our floater fleet at February 9, 2015 (with certain
subsequent developments described in the footnotes below):
Rig Type and Name
ULTRA-DEEPWATER:
Semisubmersibles (8):
Rated
Water Depth
(in feet)
Attributes
Year Built/
Redelivered (a)
Current
Location (b)
Customer (c)
Ocean GreatWhite . . . . . . . . . . . . .
10,000
DP; 6R; 15K
Q1 2016
South Korea
Under construction/BP (d)
Ocean Valor . . . . . . . . . . . . . . . . . . .
10,000
DP; 6R; 15K
Ocean Courage . . . . . . . . . . . . . . . .
10,000
DP; 6R; 15K
2009
2009
Brazil
Brazil
Petrobras
Petrobras
Ocean Confidence . . . . . . . . . . . . .
10,000
DP; 6R; 15K
2001/Q1 2015 Canary Islands
Life-extension project/Actively
Ocean Monarch . . . . . . . . . . . . . . . .
10,000
Ocean Endeavor . . . . . . . . . . . . . . .
10,000
Ocean Rover . . . . . . . . . . . . . . . . . . .
Ocean Baroness . . . . . . . . . . . . . . . .
8,000
8,000
15K
15K
15K
15K
Drillships (5):
2008
2007
2003
2002
Malaysia
Romania
Malaysia
Brazil
marketing
Standby/Apache
ExxonMobil
Murphy Exploration
Petrobras (e)
Ocean BlackLion . . . . . . . . . . . . . . .
12,000
DP; 7R; 15K
Q1 2015
South Korea
Under construction/Hess
Corporation (d)
Ocean BlackRhino . . . . . . . . . . . . .
12,000
DP; 7R; 15K
2014
Canary Islands/GOM Contract preparation/Murphy
Ocean BlackHornet
. . . . . . . . . . . .
12,000
DP; 7R; 15K
2014
GOM
Contract preparation/
Exploration
Ocean BlackHawk . . . . . . . . . . . . . .
12,000
DP; 7R; 15K
Ocean Clipper . . . . . . . . . . . . . . . . .
7,875
DP; 15K
2014
1997
GOM
Brazil
Anadarko
Anadarko
Petrobras
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DEEPWATER:
Semisubmersibles (7):
Ocean Apex . . . . . . . . . . . . . . . . . . .
Ocean Onyx . . . . . . . . . . . . . . . . . . .
Ocean Victory . . . . . . . . . . . . . . . . .
Ocean America . . . . . . . . . . . . . . . .
Ocean Valiant . . . . . . . . . . . . . . . . .
Ocean Star . . . . . . . . . . . . . . . . . . . .
Ocean Alliance . . . . . . . . . . . . . . . . .
MID-WATER:
Semisubmersibles (12) (f):
Ocean Worker . . . . . . . . . . . . . . . . .
Ocean Quest
. . . . . . . . . . . . . . . . . .
Ocean Patriot . . . . . . . . . . . . . . . . . .
Ocean General . . . . . . . . . . . . . . . . .
Ocean Yorktown . . . . . . . . . . . . . . .
Ocean Lexington . . . . . . . . . . . . . . .
Ocean Saratoga . . . . . . . . . . . . . . . .
Ocean Guardian . . . . . . . . . . . . . . .
Ocean Princess . . . . . . . . . . . . . . . .
Ocean Vanguard . . . . . . . . . . . . . . .
Ocean Nomad . . . . . . . . . . . . . . . . .
Ocean Ambassador . . . . . . . . . . . . .
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
4,000
3,000
3,000
2,850
2,200
2,200
1,500
1,500
1,500
1,200
1,100
2014
2013
1997
1988
1988
1997
1988
1982
1973
1983
1976
1976
1976
1976
1985
1975
1982
1975
1975
Vietnam
GOM
GOM
ExxonMobil
Apache
Contract preparation/BP
Australia
Chevron
North Sea/U.K.
Contract preparation/Premier
GOM
Brazil
Oil
Actively marketing
Petrobras
In transit to GOM
Preparation for cold stacking
Vietnam
PVEP POC
North Sea/U.K.
Apache
Malaysia
Mexico
Cold stacked
PEMEX
Trinidad and Tobago BG International
GOM
Cold stacked
North Sea/U.K.
Shell
North Sea/U.K.
EnQuest
North Sea/U.K.
Cold stacked/Actively
Marketing
North Sea/U.K.
Dana Petroleum (g)
Mexico
PEMEX (h)
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Attributes
DP = Dynamically Positioned/Self-Propelled
7R = 2 Seven ram blow out preventers
6R = Six ram blow out preventer
15K
= 15,000 psi well control system
(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 commissioning.
(e) Petrobras recently notified us that it has a right to terminate the drilling contract on the Ocean Baroness and has
verbally informed us that it does not intend to continue to use the rig. We are currently in discussions with Petrobras
regarding the rig.
(f) Excludes three mid-water semisubmersible rigs that we plan to retire and scrap. We have entered into a purchase and
sales agreement for the scrapping of the Ocean Yatzy, which we expect to complete in the first quarter of 2015. The
Ocean Epoch is currently cold stacked in Malaysia and the Ocean Winner is currently operating for Petrobras offshore
Brazil until March 2015.
(g) On February 12, 2015, our subsidiary received notice of termination of its drilling contract from Dana Petroleum
(E&P) Limited, the customer for the Ocean Nomad. The drilling contract was estimated to conclude in accordance
with its terms in August 2015. We do not believe that Dana had a valid basis for terminating the contract, and we
intend to defend our rights under the contract.
(h) On February 20, 2015, a representative of PEMEX verbally informed us of PEMEX’s intention to exercise its
contractual right to terminate its drilling contracts on the Ocean Ambassador, the Ocean Nugget and the
Ocean Summit, and to cancel its drilling contract on the Ocean Lexington. As of the date of this report, we have
not received written notice of termination or cancellation. We are in discussions with PEMEX regarding the rigs.
The following table presents additional information regarding our jack-up fleet, all of which are independent-leg,
cantilevered units, at February 9, 2015 (with certain subsequent developments described in the footnotes below):
Rig Type and Name
Jack-ups (6):
Rated
Water Depth (a)
(in feet)
Year Built
Current Location (b)
Customer (c)
Ocean Scepter (d) . . . . . . . . . . . . . . . . .
Ocean Titan (d) . . . . . . . . . . . . . . . . . . .
Ocean King . . . . . . . . . . . . . . . . . . . . . .
Ocean Nugget . . . . . . . . . . . . . . . . . . .
Ocean Summit . . . . . . . . . . . . . . . . . . .
Ocean Spur . . . . . . . . . . . . . . . . . . . . .
350
350
300
300
300
300
2008
1974
1973
1976
1972
1981
Mexico
GOM
GOM
Mexico
Mexico
Ecuador
PEMEX
Preparation for cold stacking
Preparation for cold stacking
PEMEX(e)
PEMEX(e)
Saipem (f)
(a) Rated water depth reflects the operating water depth capability for each drilling unit.
(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 has a 15,000 psi well control system.
(e) On February 20, 2015, a representative of PEMEX verbally informed us of PEMEX’s intention to exercise its
contractual right to terminate its drilling contracts on the Ocean Ambassador, the Ocean Nugget and the
Ocean Summit, and to cancel its drilling contract on the Ocean Lexington. As of the date of this report, we have
not received written notice of termination or cancellation. We are in discussions with PEMEX regarding the rigs.
(f) Rig is currently under a bareboat charter until the second quarter of 2015.
Markets
The principal markets for our offshore contract drilling services are the following:
(cid:129) South America, principally offshore Brazil, and Trinidad and Tobago;
(cid:129) Australia and Southeast Asia, including Malaysia, Indonesia and Vietnam;
(cid:129) the Middle East;
(cid:129) Europe, principally in the United Kingdom, or U.K., and Norway;
(cid:129) East and West Africa;
(cid:129) the Mediterranean; and
(cid:129) the Gulf of Mexico, including the U.S. and Mexico.
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We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the
world. See Note 16 “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 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. See “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 — The terms of our drilling contracts may limit our ability to attain profitability in a
declining market or to benefit from increasing dayrates in an improving market,” “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.
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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 2014, 2013 and 2012, we performed services for 35, 39 and 35 different
customers, respectively. During 2014, 2013 and 2012, 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 32%, 34%
and 33% of our annual total consolidated revenues, respectively. OGX Petróleo e Gás Ltda., or OGX (a privately owned
Brazilian oil and natural gas company that filed for bankruptcy in October 2013), accounted for 2% and 12% of our annual
total consolidated revenues for the years ended December 31, 2013 and 2012, respectively. We did not perform any
contract drilling services for OGX in 2014. No other customer accounted for 10% or more of our annual total consolidated
revenues during 2014, 2013 or 2012. 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.
We have six rigs currently contracted offshore Brazil and all four of our newbuild drillships are currently operating, or
expected to begin drilling operations, during 2015 in the GOM. Our contract backlog attributable to our expected
operations offshore Brazil is $607.0 million, $395.0 million, $332.0 million and $159.0 million for the years 2015, 2016, 2017
and 2018, respectively. Our contract backlog attributable to our expected operations in the GOM is $505.0 million, $523.0
million and $653.0 million for the years 2015, 2016 and 2017, respectively, and $1.2 billion in the aggregate for the years
2018 to 2020 attributable to four 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. We compete with offshore drilling contractors that together
have approximately 800 mobile drilling rigs, including approximately 300 floater rigs, marketed worldwide.
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 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 85%, 89% and 94% of our total consolidated revenues
for the years ended December 31, 2014, 2013 and 2012, 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
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report, which are incorporated herein by reference.
Employees
As of December 31, 2014, we had approximately 5,200 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
Age as of
January 31, 2015
Position
Marc Edwards . . . . . . . . . . . . . . . . . . . . . .
John M. Vecchio . . . . . . . . . . . . . . . . . . . .
Lyndol L. Dew . . . . . . . . . . . . . . . . . . . . . .
Gary T. Krenek . . . . . . . . . . . . . . . . . . . . .
David L. Roland . . . . . . . . . . . . . . . . . . . .
Ronald Woll
. . . . . . . . . . . . . . . . . . . . . . .
Beth G. Gordon . . . . . . . . . . . . . . . . . . . .
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64
60
56
53
47
59
President and Chief Executive Officer and Director
Executive Vice President
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.
John M. Vecchio has served as our Executive Vice President since August 2009. Mr. Vecchio previously served as our
Senior Vice President — Technical Services from April 2002 to July 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.
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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 information contained on our website, or on other websites linked to
our website, is not part of 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 significantly declined as a result of the decline in oil prices during
the second half of 2014.
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. Oil prices declined precipitously during the second half of 2014, which caused a
decline in the demand for offshore drilling services. Any prolonged substantial reduction in oil and gas prices would
adversely affect demand for the services we provide. A prolonged substantial reduction in demand for our drilling services
as a result of a decline in oil prices could have a material adverse effect 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:129) worldwide supply and demand for oil and gas;
(cid:129) the level of economic activity in energy-consuming markets;
(cid:129) the worldwide economic environment or economic trends, such as recessions;
(cid:129) the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain production levels and
pricing;
(cid:129) the level of production in non-OPEC countries;
(cid:129) 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, Russia, other oil-
producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;
(cid:129) the cost of exploring for, developing, producing and delivering oil and gas;
(cid:129) the discovery rate of new oil and gas reserves;
(cid:129) the rate of decline of existing and new oil and gas reserves and production;
(cid:129) available pipeline and other oil and gas transportation and refining capacity;
(cid:129) the ability of oil and gas companies to raise capital;
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(cid:129) weather conditions, including hurricanes, which can affect oil and gas operations over a wide area;
(cid:129) natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills;
(cid:129) the policies of various governments regarding exploration and development of their oil and gas reserves;
(cid:129) technological advances affecting energy consumption, including development and exploitation of alternative fuels
or energy sources;
(cid:129) laws and regulations relating to environmental or energy security matters, including those purporting to address
global climate change;
(cid:129) domestic and foreign tax policy; and
(cid:129) advances in exploration and development technology.
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, 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 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 may also be adversely
affected if 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
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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. 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 asset impairments and/or rig retirements as a result of declining demand for certain offshore drilling rigs.”
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 2015 and 2016. 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 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 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 term 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 or, in some cases, due
to other events beyond the control of either party. 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. In some cases, because of depressed market conditions or
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. 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.
Generally, 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 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
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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.
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 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, as well as established rigs coming off contract
during 2014, have contributed to the current decline in rig utilization, intensifying price competition. Additional newbuild
rigs entering the market are expected to further negatively impact rig utilization and intensify price competition as
scheduled delivery dates occur. See “Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Market Overview — Impact of Newbuild Rigs and Other Challenges of the Offshore Drilling Industry “ in
Item 7 of this report.
In Brazil, Petrobras has announced plans to construct locally 29 new ultra-deepwater drilling rigs to be delivered
beginning in 2015. These new drilling rigs, if built, would increase rig supply and could intensify price competition in
Brazil as well as other markets as they are placed in service, would compete with, and could displace, both our deepwater
and ultra-deepwater floaters coming off contract as well as our newbuilds coming to market and could materially
adversely affect our utilization rates, particularly in Brazil.
We provide offshore drilling services to a customer base that includes major and independent oil and gas companies
and government-owned oil companies. During 2014, one of our customers in Brazil, Petrobras, and our five largest
customers in the aggregate accounted for 32% and 61%, 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. 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 may incur asset impairments and/or rig retirements as a result of declining demand for certain offshore
drilling rigs.
Periods of excess rig supply intensify the competition in the industry and often result in rigs being idled and in some
cases retired and/or scrapped. Presently, there are numerous recently constructed ultra-deepwater vessels and high-
specification jackups that have entered the market and additional units are contracted for delivery over the next several
years. The entry into service of these new units will continue to increase rig supply. The deepwater market has recently
seen a decrease in marketed utilization. Any further increases in construction of new units will increase the negative
impact on utilization. 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,
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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. 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.
Although we have paid cash dividends in the past, we will not pay a special dividend in the first quarter of 2015,
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. In February 2015, our Board of Directors declared a
regular quarterly dividend of $0.125 per share, but chose not to declare a special dividend. If in the future our Board
continues to decide not to pay any special cash dividends or pay special cash dividends less frequently or in smaller
amounts, it could have a negative effect on the market price of our common stock. 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 factors 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.
The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit
from increasing dayrates in an improving market.
The duration of offshore drilling contracts is generally determined by customer requirements and, to a lesser extent,
the respective management strategies of the offshore drilling contractors. 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. Conversely, in periods of rising demand for offshore rigs, contractors may prefer shorter contracts that
allow them to more quickly profit from increasing dayrates, while customers with reasonably definite drilling programs
may prefer longer term contracts to maintain dayrate prices at a consistent level. We may be exposed to decreasing
dayrates if any of our rigs are working under short-term contracts during a declining market. Likewise, if any of our rigs
are committed under long-term contracts during an improving market, we may be unable to enjoy the benefit of rising
dayrates for the duration of those contracts. Exposure to falling dayrates in a declining market or the inability to fully
benefit from increasing dayrates in an improving market through shorter term contracts may limit our profitability.
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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 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
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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 licensing, taxation, equipment
specifications, 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.
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, 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 ultra-deepwater drillship, Ocean BlackLion, and our harsh environment, ultra-deepwater
semisubmersible rig, Ocean GreatWhite, both 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
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following:
(cid:129) shortages of equipment, materials or skilled labor;
(cid:129) work stoppages;
(cid:129) unscheduled delays in the delivery of ordered materials and equipment;
(cid:129) unanticipated cost increases or change orders;
(cid:129) weather interferences or storm damage;
(cid:129) difficulties in obtaining necessary permits or in meeting permit conditions;
(cid:129) design and engineering problems;
(cid:129) disputes with shipyards or suppliers;
(cid:129) availability of suppliers to recertify equipment for enhanced regulations;
(cid:129) customer acceptance delays;
(cid:129) shipyard failures or unavailability; and
(cid:129) 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.
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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, 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. Moreover,
insurance costs across the industry have increased following the Macondo incident and, in the future, certain insurance
coverage may become more costly and less available or not available at all. 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.
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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 85%, 89% and 94% of our total consolidated
revenues for 2014, 2013 and 2012, respectively, and include operations in South America, Australia and Southeast Asia, the
Middle East, 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 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:
(cid:129) political and economic instability;
(cid:129) piracy, terrorism or other assaults on property or personnel;
(cid:129) kidnapping of personnel;
(cid:129) seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of
property or equipment;
(cid:129) renegotiation or nullification of existing contracts;
(cid:129) disputes and legal proceedings in international jurisdictions;
(cid:129) changing social, political and economic conditions;
(cid:129) enactment of additional or stricter U.S. government or international sanctions;
(cid:129) imposition of wage and price controls, trade barriers or import-export quotas;
(cid:129) restrictive foreign and domestic monetary policies;
(cid:129) the inability to repatriate income or capital;
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(cid:129) difficulties in collecting accounts receivable and longer collection periods;
(cid:129) fluctuations in currency exchange rates and restrictions on currency exchange;
(cid:129) regulatory or financial requirements to comply with foreign bureaucratic actions;
(cid:129) restriction or disruption of business activities;
(cid:129) limitation of our access to markets for periods of time;
(cid:129) travel limitations or operational problems caused by public health threats;
(cid:129) difficulties in supplying, repairing or replacing equipment or transporting personnel in remote locations;
(cid:129) difficulties in obtaining visas or work permits for our employees on a timely basis; and
(cid:129) 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:
(cid:129) the equipping and operation of drilling rigs;
(cid:129) import-export quotas or other trade barriers;
(cid:129) repatriation of foreign earnings or capital;
(cid:129) oil and gas exploration and development;
(cid:129) local content requirements;
(cid:129) taxation of offshore earnings and earnings of expatriate personnel; and
(cid:129) 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 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.
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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 following
the Macondo well blowout and other events 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
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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.
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 Offshore International
Limited, or DOIL, a Cayman Islands subsidiary that we own. It is our intention to indefinitely reinvest future earnings of
DOIL and its foreign subsidiaries to finance foreign activities. We do not expect to provide for U.S. taxes on any future
earnings generated by DOIL, 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. We can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency
fluctuation losses that may arise.
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, we have one new ultra-deepwater drillship and one
ultra-deepwater, semisubmersible rig under construction. These rigs are not yet fully crewed as of the date of this report
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. The heightened competition for skilled personnel could
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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.
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, 2014, we had approximately $2.3 billion in senior debt maturing at various times from July 2015
through 2043. We also had $1.5 billion of availability under our revolving credit facility as of that date. 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:129) we may have difficulty satisfying our obligations with respect to our outstanding debt;
(cid:129) we may have difficulty obtaining financing in the future for working capital, capital expenditures, acquisitions or
other purposes;
(cid:129) 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;
(cid:129) our vulnerability to general economic downturns and adverse industry conditions could increase;
(cid:129) our flexibility in planning for, or reacting to, changes in our business and in our industry in general could be
limited;
(cid:129) 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;
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(cid:129) our customers may react adversely to our significant debt level and seek alternative service providers; and
(cid:129) 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.
In addition, approximately $750.0 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 the third quarter of 2014, Standard & Poor’s Ratings Services, or S&P, revised its
outlook on us to negative and, in December 2014, S&P lowered our long-term corporate credit and unsecured debt rating
from A to A-. 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.
We may also issue commercial paper to meet our short-term liquidity needs. 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.
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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 52.5% of our outstanding shares of
common stock as of February 16, 2015, 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 53% 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 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.
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Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
PART II
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.
2014
Common Stock
High
Low
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$56.71
$43.91
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
54.61
50.13
39.60
45.88
34.27
29.37
2013
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$76.48
$67.45
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
72.84
72.65
64.63
64.42
62.13
55.39
As of February 13, 2015 there were approximately 165 holders of record of our common stock. This number
represents registered stockholders and does not include stockholders who hold their shares institutionally.
Dividend Policy
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. In 2013, we paid regular cash dividends of $0.125 and special cash
dividends of $0.75 per share of our common stock on March 1, June 3, September 3 and December 2.
On February 6, 2015, we declared a regular cash dividend of $0.125 per share of our common stock payable on
March 2, 2015 to stockholders of record on February 20, 2015.
Our Board of Directors 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 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 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 will not pay a special dividend in the first quarter of
2015, 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.
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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, 2014.
Comparison of 2010 — 2014 Cumulative Total Return (1)
Diamond Offshore
S&P 500
Dow Jones U.S. Oil
Equipment & Services
S
R
A
L
L
O
D
300
250
200
150
100
50
0
2009
2010
2011
2012
2013
2014
Diamond Offshore
S&P 500
Dow Jones U.S. Oil Equipment & Services
Dec. 31,
2009
Dec. 31,
2010
Dec. 31,
2011
Dec. 31,
2012
Dec. 31,
2013
Dec. 31,
2014
100
100
100
73
115
126
63
117
110
82
136
109
72
180
138
51
205
112
(1) Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2009 in our common
stock and the two published indices.
Our dividend history for the periods reported above is as follows:
Year
Regular
Special
Regular
Special
Regular
Special
Regular
Special
Q1
Q2
Q3
Q4
2014 . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . .
$0.125
$0.125
$0.125
$0.125
$0.125
$ 0.75
$ 0.75
$ 0.75
$ 0.75
$1.875
$0.125
$0.125
$0.125
$0.125
$0.125
$ 0.75
$ 0.75
$ 0.75
$ 0.75
$1.375
$0.125
$0.125
$0.125
$0.125
$0.125
$0.75
$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
$0.75
2
6
2
0
1
4
A
N
N
U
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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.
As of and for the Year Ended December 31,
2014
2013
2012
2011
2010
(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,814,671
$2,920,421 $2,986,508 $3,322,419 $3,322,974
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
572,562 (1)
801,606
962,378
1,255,414
1,425,374
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
387,011
548,686
720,477
962,542
955,457
Net income per share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.82
2.81
3.95
3.95
5.18
5.18
6.92
6.92
6.87
6.87
Balance Sheet Data:
Drilling and other property and equipment, net . . . . . . . . $6,945,953 (2) $5,467,227 $4,864,972 $4,667,469 $4,283,792
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,021,289
8,391,434
7,235,286
6,964,157
6,726,984
Long-term debt (excluding current maturities) (3) . . . . . . . .
1,994,526
2,244,189
1,496,066
1,495,823
1,495,593
Other Financial Data:
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,032,764 (2) $ 957,598 $ 702,041 $ 774,756 $ 434,262
Cash dividends declared per share . . . . . . . . . . . . . . . . . . . .
Ratio of earnings to fixed charges (4) . . . . . . . . . . . . . . . . . . .
3.50
4.64x
3.50
7.79x
3.50
11.11x
3.50
14.40x
5.25
15.35x
(1)
In the third quarter of 2014, we recorded an impairment loss of $109.5 million to write down the aggregate net book
value of six of our mid-water semisubmersibles 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, 2014, 2013 and 2012 — Overview — 2014 Compared to 2013 — Asset Impairments and Note 2
“Impairment of Assets” to our Consolidated Financial Statements included in Item 8 of this report for a discussion of
the 2014 asset impairment.
(2) 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.
(3) See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and
Capital Resources — Credit Agreement, Senior Notes and Commercial Paper Program” 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.
(4) 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.
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 38 offshore drilling rigs, excluding three mid-water semisubmersible rigs that we plan to retire and scrap. In late
2014, we took delivery of two ultra-deepwater drillships, the Ocean BlackHornet and Ocean BlackRhino. Contract
preparation work is underway for both rigs, which are expected to commence drilling operations in the GOM in the
second quarter of 2015. Construction of the Ocean Apex was completed late in the fourth quarter of 2014, and the rig is
currently operating under a one-well contract in Vietnam.
During the first quarter of 2015, we expect to take delivery of our remaining ultra-deepwater drillship Ocean
BlackLion and to complete the service-life-extension project for the ultra-deepwater Ocean Confidence. We expect the
harsh environment, ultra-deepwater semisubmersible Ocean GreatWhite to be delivered in the first quarter of 2016.
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Market Overview
Market fundamentals in the oil and gas industry continued to deteriorate in the fourth quarter of 2014 and into 2015.
The dramatic decline in oil prices since the summer of 2014 has led many of our customers or potential customers to
announce significant cutbacks to their 2015 capital spending plans. These adverse market conditions have resulted in
reduced demand for offshore drilling rigs by our customers and an oversupply of rigs available for charter. Based on these
factors, industry analysts predict dayrates to decline further as competition to keep rigs active continues to intensify. As of
February 9, 2015, eight of our rigs were not subject to a drilling contract with a customer, including six rigs that have been
cold stacked or are in the process of being cold stacked.
In declining markets, rig tenders by our customers may be for shorter terms or on a well-to-well basis and increased
competition for the tenders may drive down contract dayrates. It is also not unusual for adverse market conditions to
result in the migration of some ultra-deepwater rigs to work in deepwater and, likewise, some deepwater rigs to compete
against mid-water units, or even ultra-deepwater rigs to work in some mid-water markets. This has had and could
continue to have an adverse impact on our fleet, and particularly our lower specification mid-water rigs, as indicated by
the retirement of six of our mid-water semisubmersible rigs during 2014, three of which have since been scrapped as of
the date of this report.
Another characteristic of the depressed market conditions in the offshore drilling industry is that certain customers
may attempt to renegotiate or terminate drilling contracts. Some of our drilling contracts, particularly contracts with
national oil companies or government-controlled entities, permit the customer to terminate the contract 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 may be more motivated to utilize such contract clauses to seek to renegotiate or terminate a drilling contract.
In addition, in depressed conditions certain customers may be motivated to 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. 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 adversely impacted. See “— Contract Drilling
Backlog” below.
On February 20, 2015, a representative of PEMEX — Exploracio´n y Produccio´n, or PEMEX, verbally informed us of
PEMEX’s intention to exercise its contractual right to terminate its drilling contracts on the Ocean Ambassador, the Ocean
Nugget and the Ocean Summit, and to cancel its drilling contract on the Ocean Lexington, which contract was scheduled
to begin in September 2015. As of the date of this report, we have not received written notice of termination or
cancellation. We are in discussions with PEMEX regarding the rigs.
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In addition, Petro´leo Brasileiro S.A., or Petrobras, recently notified us that it has a right to terminate the drilling
contract on the Ocean Baroness and has verbally informed us that it does not intend to continue to use the rig. We are
currently in discussions with Petrobras regarding the rig.
The impact of the depressed market conditions in the offshore drilling industry has materially impacted our results of
operations and cash flows in 2014. We currently expect that these adverse conditions will continue through 2015 and
likely into 2016 or even longer. The continuation of these conditions could result in more of our rigs being without
contracts and/or cold stacked and could further materially and adversely affect our financial condition, results of
operations and cash flows. When we cold stack a rig, we evaluate the rig for impairment. See “Risk Factors — We may
incur asset impairments and/or rig retirements as a result of declining demand for certain offshore drilling rigs” in Item 1A
of this report, which is incorporated herein by reference.
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
weaken. The continuing oversupply of rigs, combined with diminished demand, has resulted in further decline in
dayrates and the stacking of rigs in all asset classes, and industry reports expect offshore drillers to continue to scrap
older, lower specification rigs. During 2014, there were few bidding opportunities, and the outlook for 2015 is pessimistic.
Competition for a limited number of jobs has been intense, with numerous offshore drillers vying for the same
opportunities, including some competitors bidding multiple rigs on the same bid, and operators attempting to sublet
previously contracted rigs for which capital spending programs have been delayed and/or canceled.
The influx of newbuilds into the market, combined with established rigs that came off contract in 2014 or are
expected to complete contracts during 2015 and 2016, is expected to contribute to the further weakening of the ultra-
deepwater and deepwater floater markets. As of the date of this report, based on industry data, there are approximately 59
competitive, or non-owner-operated, newbuild floaters on order, and an estimated 29 additional rigs potentially to be
built on behalf of Petrobras, which is currently our largest single customer based on annual consolidated revenues. Based
on industry reports, of the competitive rigs, 16 of the 31 newbuilds scheduled for delivery in 2015, as well as nine of the 14
newbuilds scheduled for delivery in 2016, are not yet contracted for future work.
Mid-Water Floaters. Conditions in the mid-water market have varied by region, but have generally been adversely
impacted by lower demand, the waterfall effect of declining dayrates in the ultra-deepwater and deepwater markets, the
challenges experienced by lower specification units in this segment as a result of growing regulatory demands and more
complex customer specifications, and the intensified competition resulting from the migration of some deepwater and
ultra-deepwater units to compete against mid-water units. As higher specification rigs take the place of lower
specification units, some lower specification rigs are expected to be cold stacked or ultimately scrapped.
See “— Contract Drilling Backlog” for future commitments of our rigs during 2015 through 2020.
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of February 9, 2015, October 21, 2014 (the date reported in
our Quarterly Report on Form 10-Q for the quarter ended September 30, 2014), and February 5, 2014 (the date reported in
our Annual Report on Form 10-K for the year ended December 31, 2013). 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 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
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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 9,
2015
October 21,
2014
February 5,
2014
(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater (1)(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$5,390,000
$6,090,000
$4,111,000
Deepwater (3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
748,000
773,000
794,000
Mid-Water (4)(5)(6)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
611,000
1,149,000
1,744,000
Total Floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,749,000
8,012,000
6,649,000
Jack-ups (7)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91,000
180,000
180,000
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$6,840,000
$8,192,000
$6,829,000
(1) Contract drilling backlog as of February 9, 2015 for our ultra-deepwater floaters includes (i) $1.3 billion attributable to
our contracted operations offshore Brazil for the years 2015 to 2018; (ii) $584.0 million for the years 2015 to 2019
attributable to future work for the Ocean BlackLion, which is under construction; and (iii) $641.0 million for the years
2016 to 2019 attributable to future work for the semisubmersible Ocean GreatWhite, which is under construction.
(2) Contract drilling backlog as of February 9, 2015 for our ultra-deepwater floaters excludes $408.4 million attributable
to the Ocean Baroness contracted to Petrobras. See discussion under “Market Overview” above.
(3) Contract drilling backlog as of February 9, 2015 for our deepwater floaters includes $196.0 million attributable to our
contracted operations offshore Brazil for the years 2015 to 2016.
(4) Contract drilling backlog reported as of October 21, 2014 for our mid-water floaters excludes $107.0 million in
backlog attributable to contracted work for the Ocean Vanguard that is included in the February 5, 2014 backlog. As
previously reported, in the second quarter of 2014, Statoil ASA, the customer for the Ocean Vanguard, terminated its
drilling contract, which was estimated to conclude in accordance with its terms in February 2015. We do not believe
that Statoil had a valid basis for terminating the contract, and we have filed a lawsuit against Statoil in Norway to
collect damages resulting from the unlawful termination.
(5) Contract drilling backlog as of February 9, 2015 for our mid-water floaters (i) includes $21.0 million attributable to our
contracted operations offshore Brazil for the year 2015 and (ii) excludes $52.8 million from 2015 that was originally
attributable to contracted work for the Ocean Nomad and previously reported as backlog for 2015. On February 12,
2015, our subsidiary received notice of termination of its drilling contract from Dana Petroleum (E&P) Limited, the
customer for the Ocean Nomad. The drilling contract provides for a dayrate of approximately $330,000 and was
estimated to conclude in accordance with its terms in August 2015. We do not believe that Dana had a valid basis for
terminating the contract and we intend to defend our rights under the contract.
(6) Contract drilling backlog as of February 9, 2015 for our mid-water floaters excludes $208.8 million attributable to the
Ocean Ambassador and the Ocean Lexington. See discussion under “Market Overview” above.
(7) Contract drilling backlog as of February 9, 2015 for our jack-ups excludes $49.0 million attributable to the Ocean
Nugget and the Ocean Summit. See discussion under “Market Overview” above.
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The following table reflects the amount of our contract drilling backlog by year as of February 9, 2015.
For the Years Ending December 31,
Total
2015 (1)
2016
2017
2018 - 2020
(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater (2) (3)
. . . . . . . . . . . . . . . . . . . . . . . . . .
$5,390,000
$1,397,000
$1,095,000
$1,199,000
$1,699,000
Deepwater (4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Water (5) (6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
748,000
611,000
492,000
343,000
208,000
147,000
48,000
121,000
—
Total Floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,749,000
2,232,000
1,450,000
1,368,000
1,699,000
Jack-ups (7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91,000
81,000
10,000
—
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$6,840,000
$2,313,000
$1,460,000
$1,368,000
$1,699,000
(1) Represents the twelve-month period beginning January 1, 2015.
(2) Contract drilling backlog as of February 9, 2015 for our ultra-deepwater floaters includes (i) $452.0 million, $333.0
million, $332.0 million, and $159.0 million for the years 2015, 2016, 2017 and 2018, respectively, attributable to our
contracted operations offshore Brazil; (ii) $25.0 million, $146.0 million and $146.0 million for the years 2015, 2016 and
2017, respectively, and $267.0 million in the aggregate for the years 2018 to 2019 attributable to future work for the
Ocean BlackLion, which is under construction; and (iii) $90.0 million for the year 2016, $214.0 million for the year
2017 and $337.0 million in the aggregate for the years 2018 to 2019 attributable to future work for the Ocean
GreatWhite, which is under construction.
(3) Contract drilling backlog as of February 9, 2015 for our ultra-deepwater floaters excludes $76.7 million, $113.5
million, $113.1 million, and $105.1 million for the years 2015, 2016, 2017 and 2018, respectively, attributable to the
Ocean Baroness contracted to Petrobras. See discussion under “Market Overview” above.
(4) Contract drilling backlog as of February 9, 2015 for our deepwater floaters includes $134.0 million and $62.0 million
for the years 2015 and 2016, respectively, attributable to our contracted operations offshore Brazil.
(5) Contract drilling backlog as of February 9, 2015 for our mid-water floaters (i) includes $21.0 million for the year 2015
attributable to our contracted operations offshore Brazil and (ii) excludes $52.8 million for the year 2015 that was
originally attributable to contracted work for the Ocean Nomad and previously reported as backlog for 2015. On
February 12, 2015, our subsidiary received notice of termination of its drilling contract from Dana Petroleum (E&P)
Limited, the customer for the Ocean Nomad. The drilling contract provides for a dayrate of approximately $330,000
and was estimated to conclude in accordance with its terms in August 2015. We do not believe that Dana had a valid
basis for terminating the contract, and we intend to defend our rights under the contract.
(6) Contract drilling backlog as of February 9, 2015 for our mid-water floaters excludes $69.6 million, $66.6 million, $58.4
million, and $14.2 million for the years 2015, 2016, 2017 and 2018, respectively, attributable to the Ocean Ambassador
and the Ocean Lexington. See discussion under “Market Overview” above.
(7) Contract drilling backlog as of February 9, 2015 for our jack-ups excludes $26.9 million and $22.1 million for the years
2015 and 2016, respectively, attributable to the Ocean Nugget and the Ocean Summit. See discussion under “Market
Overview” above.
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The following table reflects the percentage of rig days committed by year as of February 9, 2015. 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 dates for the Ocean
BlackLion and Ocean GreatWhite, both of which are under construction.
For the Years Ending December 31,
2015 (1)
2016
2017
2018 - 2020
Rig Days Committed (2)(3)
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
85% 63% 54%
25%
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55% 21% 5%
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
40% 11% 9%
All Floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63% 37% 28%
Jack-ups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32%
3% —
—
—
11%
—
(1) Represents the twelve-month period beginning January 1, 2015.
(2) As of February 9, 2015, includes approximately 1,100 and 560 currently known, scheduled shipyard days for rig
commissioning, contract preparation, surveys and extended maintenance projects, as well as rig mobilization days,
for the years 2015 and 2016, respectively.
(3) Excludes previously reported rig days attributable to the Ocean Baroness contracted to Petrobras and the Ocean
Ambassador, the Ocean Nugget, the Ocean Summit and the Ocean Lexington contracted to PEMEX. See discussion
under “Market Overview” above.
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.
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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 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 U.K. and Norwegian
sectors of the North Sea.
During 2015, two of our rigs will require 5-year surveys, which we expect to result in approximately 120 days of
downtime in the aggregate. We also expect to spend an additional approximately 980 days for intermediate surveys, the
mobilization of rigs, contract acceptance testing and extended maintenance projects, including days associated with
mobilization and acceptance testing for the recently delivered Ocean BlackHornet and Ocean BlackRhino (approximately
195 days in the aggregate) and the Ocean BlackLion (approximately 240 days), which is under construction and expected
to be delivered late in the first quarter of 2015. We expect the Ocean Confidence to be unavailable through the first quarter
of 2015 (approximately 90 days) as it completes its service-life-extension project. 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.”
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 that expires on May 1, 2015, 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, 2014, we capitalized interest of $60.6 million on qualifying expenditures, primarily related to
the construction of our four new drillships, the Ocean GreatWhite and the Ocean Apex. We will continue capitalizing
interest on qualifying expenditures during 2015, which will no longer include expenditures related to the Ocean
BlackHawk, Ocean BlackHornet, Ocean BlackRhino and Ocean Onyx, which were completed in 2014, and will include
a limited interest capitalization period for the Ocean BlackLion, which is expected to be completed in the first quarter
of 2015.
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
3
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A
U
N
N
A
4
1
0
2
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F
F
O
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N
O
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A
D
I
operations and cash flows.
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. Maintenance and
routine repairs are charged to income currently while replacements and betterments, including associated inspection and
recertification costs, which 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, 2014 and 2013, we capitalized
$546.0 million and $302.0 million, respectively, in replacements and betterments of our drilling fleet, resulting from
numerous projects ranging from $25,000 to $160 million per project.
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 cold stacking a rig, the expectation of cold stacking a rig in
the near term, 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:129) dayrate by rig;
(cid:129) utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);
(cid:129) the per day operating cost for each rig if active, warm stacked or cold stacked;
(cid:129) the estimated annual cost for rig replacements and/or enhancement programs;
(cid:129) the estimated maintenance, inspection or other costs associated with a rig returning to work;
(cid:129) salvage value for each rig; and
3
4
2
0
1
4
A
N
N
U
A
L
R
E
P
O
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T
I
D
A
M
O
N
D
O
F
F
S
H
O
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E
(cid:129) estimated proceeds that may be received on disposition of the rig.
Based on these assumptions and estimates, we develop a matrix using several different utilization/dayrate scenarios,
to each of which we have assigned a probability of occurrence. The sum of our utilization scenarios (which include active,
warm stacked and cold stacked) and probability of occurrence scenarios both equal 100% in the aggregate. We reevaluate
these rigs annually, by updating the matrices for each rig and modifying our assumptions, giving consideration to the
length of time the rig has been cold stacked, the current and expected market for the type of rig and expectations of future
oil and gas prices.
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, or the Retirement Group, which included
three rigs that were initially impaired in 2012. Of the Retirement Group, two of the rigs were scrapped in December 2014,
and one additional rig was scrapped in February 2015. We have entered into a sales agreement to scrap a fourth rig in the
Retirement Group, which we expect to close in the first quarter of 2015. We did not recognize an asset impairment in
2013. During 2012, we recognized an impairment loss of $62.4 million. See “— Results of Operations — Years Ended
December 31, 2014, 2013 and 2012 — Overview — 2014 Compared to 2013 — Impairment of Assets,” “— Results of
Operations — Years Ended December 31, 2014, 2013 and 2012 — Overview — 2013 Compared to 2012 — Impairment of
Assets” and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.
Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different
assumptions could produce results that differ from those reported.
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:129) claim emergence, or the delay between occurrence and recording of claims;
(cid:129) settlement patterns, or the rates at which claims are closed;
(cid:129) development patterns, or the rate at which known cases develop to their ultimate level;
(cid:129) average, potential frequency and severity of claims; and
(cid:129) 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:129) the severity of personal injuries claimed;
(cid:129) significant changes in the volume of personal injury claims;
(cid:129) the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
5
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A
U
N
N
A
4
1
0
2
E
R
O
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F
F
O
D
N
O
M
A
D
I
(cid:129) inconsistent court decisions; and
(cid:129) 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.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International
Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. It is our intention to indefinitely reinvest future
earnings of DOIL and its foreign subsidiaries to finance foreign activities. Accordingly, we have not made a provision for
U.S. income taxes on approximately $2.4 billion of undistributed foreign earnings and profits. Although we do not intend
to repatriate the earnings of DOIL 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.
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.
3
6
2
0
1
4
A
N
N
U
A
L
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E
P
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A
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O
N
D
O
F
F
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Key performance indicators by equipment type are listed below.
REVENUE EARNING DAYS (1)
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Jack-ups (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,151
1,206
3,969
1,845
2,392
1,530
4,186
1,949
2,475
1,605
4,639
1,753
Year Ended December 31,
2014
2013
2012
UTILIZATION (3)
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Jack-ups (4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
65%
55%
61%
78%
82%
84%
64%
76%
85%
88%
68%
53%
AVERAGE DAILY REVENUE (5)
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$459,100
$357,300
$364,700
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
409,800
403,300
372,400
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
271,300
286,200
274,900
Jack-ups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
96,700
89,300
91,500
(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) Revenue earning days for the year ended December 31, 2012 included approximately 87 days earned by certain of our
jack-up rigs during the period prior to being sold in 2012.
(3) 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,
2014, six of our mid-water semisubmersible drilling rigs were cold stacked, three of which we plan to scrap.
(4) Utilization for our jack-up rigs would have been 87% for the year ended December 31, 2012, excluding revenue
earning days and total calendar days associated with rigs that we sold in 2012.
(5) Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per revenue
earning day.
7
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F
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A
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Comparative data relating to our revenues and operating expenses by equipment type are listed below.
Years Ended December 31, 2014, 2013 and 2012
Year Ended December 31,
2014
2013
2012
(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 987,565
494,247
1,076,842
$ 854,515
617,080
1,197,934
$ 902,793
597,694
1,275,068
Total Floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Jack-ups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,558,654
178,472
2,669,529
174,055
2,775,555
160,511
Total Contract Drilling Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,737,126
$ 2,843,584
$ 2,936,066
REVENUES RELATED TO REIMBURSABLE EXPENSES . . . . . . . . . . . . . . . . . . . . . . .
CONTRACT DRILLING EXPENSE
$
77,545
$
76,837
$
50,442
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 536,615
292,050
535,080
$ 538,765
267,820
604,492
$ 545,590
253,176
602,351
Total Floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Jack-ups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,363,745
111,204
48,674
1,411,077
115,078
46,370
1,401,117
106,510
29,597
Total Contract Drilling Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,523,623
$ 1,572,525
$ 1,537,224
REIMBURSABLE EXPENSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OPERATING INCOME
$
76,091
$
74,967
$
48,778
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 450,950
202,197
541,762
$ 315,750
349,260
593,442
$ 357,203
344,518
672,717
Total Floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Jack-ups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reimbursable expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt (expense) recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on disposition of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,194,909
67,268
(48,674)
1,454
(456,483)
(109,462)
(81,832)
—
5,382
1,258,452
58,977
(46,370)
1,870
(388,092)
—
(64,788)
(22,513)
4,070
1,374,438
54,001
(29,597)
1,664
(392,913)
(62,437)
(64,640)
1,018
80,844
Total Operating Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 572,562
$ 801,606
$ 962,378
Other income (expense):
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign currency transaction gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net
801
(62,053)
3,199
682
701
(24,843)
(4,915)
1,691
4,910
(46,216)
(1,999)
(992)
Income before income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
515,191
(128,180)
774,240
(225,554)
918,081
(197,604)
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 387,011
$ 548,686
$ 720,477
3
8
2
0
1
4
A
N
N
U
A
L
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The following is a summary of the most significant transfers of our rigs during 2012, 2013 and 2014 between the
geographic areas in which we operate:
Rig
F l o a t e r s ( 1 ):
Rig Type
Relocation Details
Date
Ocean Monarch . . . . . . . . . . Ultra-Deepwater Vietnam to Singapore (shipyard survey)
Ocean Confidence . . . . . . . . Ultra-Deepwater Congo to Angola
Ocean Confidence . . . . . . . . Ultra-Deepwater Angola to Cameroon
Ocean BlackHawk . . . . . . . Ultra-Deepwater
South Korea to GOM (initial mobilization)
August 2012
January 2013
February 2014
February 2014
Ocean Confidence . . . . . . . . Ultra-Deepwater Cameroon to Canary Islands (life-extension project) April 2014
Ocean Clipper . . . . . . . . . . . Ultra-Deepwater Brazil to Colombia
Ocean Monarch . . . . . . . . . . Ultra-Deepwater
Indonesia to Malaysia (shipyard project)
Ocean Clipper . . . . . . . . . . . Ultra-Deepwater Colombia to Brazil
Ocean BlackHornet . . . . . . . Ultra-Deepwater
South Korea to GOM (initial mobilization)
Ocean BlackRhino . . . . . . . Ultra-Deepwater
South Korea to GOM (initial mobilization)
June 2014
September 2014
December 2014
December 2014
December 2014
Ocean America . . . . . . . . . . Deepwater
Australia to Singapore (shipyard survey)
July 2013
Ocean Valiant . . . . . . . . . . . Deepwater
Cameroon to Canary Islands (shipyard survey)
October 2013
Ocean America . . . . . . . . . . Deepwater
Singapore to Australia
Ocean Onyx . . . . . . . . . . . . . Deepwater
Placed in service (GOM)
Ocean Star . . . . . . . . . . . . . . Deepwater
Brazil to GOM
Ocean Apex . . . . . . . . . . . . . Deepwater
Singapore to Vietnam
Ocean Guardian . . . . . . . . . Mid-Water
Falkland Islands to U.K.
Ocean Saratoga . . . . . . . . . . Mid-Water
GOM to Guyana
Ocean Saratoga . . . . . . . . . . Mid-Water
Guyana to GOM
Ocean Whittington . . . . . . . Mid-Water
Brazil to GOM
Ocean Apex . . . . . . . . . . . . . Mid-Water
Singapore shipyard
Ocean Ambassador . . . . . . . Mid-Water
Brazil to GOM
Ocean Lexington . . . . . . . . . Mid-Water
Brazil to Trinidad
Ocean Patriot
. . . . . . . . . . . Mid-Water
Vietnam to Philippines
Ocean Saratoga . . . . . . . . . . Mid-Water
GOM to Nicaragua
Ocean Quest . . . . . . . . . . . . . Mid-Water
Brazil to Malaysia
Ocean Patriot
. . . . . . . . . . . Mid-Water
Philippines to Singapore (shipyard upgrade)
November 2013
January 2014
September 2014
December 2014
January 2012
January 2012
May 2012
May 2012
September 2012
October 2012
March 2013
May 2013
August 2013
November 2013
November 2013
Ocean Saratoga . . . . . . . . . . Mid-Water
Nicaragua to GOM (cold stacked October 2014)
December 2013
Ocean General . . . . . . . . . . . Mid-Water
Vietnam to Indonesia
Ocean Quest . . . . . . . . . . . . . Mid-Water
Malaysia to Vietnam
Ocean Patriot
. . . . . . . . . . . Mid-Water
Singapore to U.K.
Ocean Vanguard . . . . . . . . . Mid-Water
Norway to U.K. (cold stacked July 2014)
March 2014
May 2014
June 2014
June 2014
Ocean General . . . . . . . . . . . Mid-Water
Indonesia to Malaysia (cold stacked October 2014)
September 2014
Jack-ups (2):
Ocean Spur . . . . . . . . . . . . . Jack-up
Egypt to Ecuador; two year bareboat charter
August 2012
Ocean Spartan . . . . . . . . . . Jack-up
GOM
Ocean King . . . . . . . . . . . . . Jack-up
Montenegro to GOM
Ocean Titan . . . . . . . . . . . . . Jack-up
Mexico to GOM
December 2012
December 2012
June 2014
(1) We scrapped two mid-water semisubmersible rigs, the Ocean New Era and Ocean Whittington in November 2014.
(2) We sold the Ocean Columbia, Ocean Heritage, Ocean Drake, Ocean Champion, Ocean Crusader and Ocean Sovereign
in 2012. The Ocean Spartan was sold in June 2014.
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Overview
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 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 reflect 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 a $22.5 million charge for an uncollectible receivable incurred in the prior year.
Contract drilling revenue for our deepwater and mid-water fleets decreased $122.8 million and $121.1 million,
respectively, during 2014, compared to the prior year, 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 the
aggregate. 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.
In general, the comparability of contract drilling expenses between years is impacted by significant events or changes
in our rig fleet, including but not limited to the relocation of rigs between geographic locations and related changes in
operating cost structures which differ between regions, the cost to mobilize such rigs, the number and extent of shipyard
surveys and related repairs, contract preparation activities, the stacking of rigs and rising labor costs. Total contract
drilling expense for our rig fleet during 2014 decreased by $48.9 million, or 3%, compared to the prior year, primarily due
to the cold stacking or scrapping of rigs, contract preparation work and lower repairs and maintenance expenses, partially
offset by increases in 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. Three of these rigs were initially impaired
in 2012. See “— 2013 Compared to 2012 — Impairments of Assets.”
Bad Debt Expense (Recovery). 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., or OGX, and our expectations 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 they owed us at June 30, 2013. Four of our rigs remained under contract to Niko and OGX in
the second half of 2013, working an aggregate of 337 revenue earning days for which we did not recognize revenue due to
our assessment that collection of the amounts due was not reasonably assured.
In December 2013, we entered into a settlement agreement with Niko, which we refer to as the Settlement
Agreement, 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 Settlement
Agreement, aggregating $80.0 million, and subject to its other conditions. In accordance with the terms of the Settlement
Agreement, 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. We plan to recognize future payments from Niko in revenue as they are
received due to the uncertainty regarding their timing and collection.
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In 2014, the creditors of OGX, including us, agreed to a settlement whereby the creditors would receive 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.
No additional provisions for bad debts were deemed necessary in 2014.
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 $1.0 billion in senior unsecured notes that we issued in
November 2013, partially offset by a reduction in interest expense related to $250.0 million in senior debt that we repaid
in 2014, combined with a decrease in capitalized interest of $13.6 million as a result of rig construction projects completed
in 2014. The increase in interest expense was also partially offset by the reversal of $6.2 million of interest 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 period 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 $54.5 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 the 2013 period, 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.
2013 Compared to 2012
Operating Income. Operating income decreased $160.8 million, or 17%, in 2013, compared to 2012, primarily due to a
$92.5 million, or 3%, reduction in contract drilling revenue, a $35.3 million increase in contract drilling expense and
recognition of $22.5 million of bad debt expense in 2013, combined with the absence of an aggregate $76.5 million pre-tax
gain on the sale of six of our jack-up rigs during 2012. These negative contributors to operating income were partially
offset by the absence of a $62.4 million impairment loss recognized in the fourth quarter of 2012.
Contract drilling revenue for our ultra-deepwater and mid-water fleets decreased a combined $125.4 million during
2013, compared to 2012, while revenue earned by our deepwater floaters and jack-up rigs increased an aggregate $32.9
million. Revenue earning days for our drilling fleet decreased an aggregate 415 days in 2013, compared to 2012, including
337 fewer revenue earning days for the Ocean Monarch, Ocean Star, Ocean Lexington and Ocean Quest in the second half
of 2013, during which these rigs were contracted to Niko or OGX, and 87 fewer days attributable to the jack-up rigs that we
sold in 2012.
Total contract drilling expense for our rig fleet during 2013 increased by $35.3 million, compared to 2012, reflecting
higher labor and personnel-related costs ($38.1 million), primarily related to mid-2013 pay increases and costs associated
with additional crews for the Ocean Onyx and Ocean BlackHawk and for our new rigs expected to be delivered in 2014,
repair and maintenance costs ($23.7 million) and inspection costs ($10.1 million). The impact of these 2013 cost increases
was partially offset by decreased costs associated with the mobilization of rigs ($21.9 million), freight ($11.5 million) and
other rig operating costs ($3.3 million).
Impairment of Assets. In late 2012, our management adopted a plan to actively market for sale three of our mid-water
semisubmersibles, the Ocean Epoch, the Ocean New Era and the Ocean Whittington, and the jack-up rig Ocean Spartan.
As a result of this decision, we recognized an impairment loss of $62.4 million in the fourth quarter of 2012 to write down
the aggregate net book value of these rigs to their estimated recoverable amounts.
Interest Expense. Interest expense decreased $21.4 million in 2013, compared to 2012, primarily due to a $36.6 million
increase in interest capitalized on eligible construction projects during 2013, partially offset by incremental interest
expense of $7.0 million for the senior unsecured notes that we issued in 2013 and an increase of $7.7 million in interest
expense associated with uncertain tax positions, primarily in the Mexico tax jurisdiction.
Income Tax Expense Our effective tax rate for 2013 was 29.1%, compared to a 21.5% effective tax rate for 2012. The
higher effective tax rate in 2013 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. Income tax expense for 2013 was also
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.
As our rigs frequently operate in different tax jurisdictions as they move from contract to contract, our effective tax
rate can fluctuate substantially and our historical effective tax rates may not be sustainable and could increase materially.
See “Risk Factors – Changes in tax laws, effective income tax rates or adverse outcomes resulting from examination of our
tax returns could adversely affect our financial results” in Item 1A of this report.
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Contract Drilling Revenue and Expense by Equipment Type
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 the prior year
period, 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 the prior year, 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 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
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 the
prior year, 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 ($8.8 million). These
2014 cost increases were partially offset by reductions in costs for international shorebase locations ($9.7 million), labor
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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), as a result of lower rig utilization compared to the prior year and
relocation of rigs.
Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $121.1 million during 2014, compared to
the prior year, 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 the prior year, 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 North Sea rigs.
Contract drilling expense for our mid-water fleet decreased $69.4 million during 2014, compared to 2013, primarily
due to reductions in costs for our currently cold stacked rigs and other mid-water rigs scrapped during the year or other
non-working rigs designated for scrapping at the end of 2014 ($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 the prior year,
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 the prior
year, 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).
2013 Compared to 2012
Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters decreased $48.3 million in 2013,
compared to 2012, primarily due to lower average daily revenue earned ($17.7 million) and 83 fewer revenue earning days
($30.6 million). Average daily revenue decreased in 2013, compared to 2012, primarily due to a contract extension for the
Ocean Rover during the second quarter of 2012 at a significantly lower dayrate than previously earned, lower revenue
earned by the Ocean Clipper as a result of incremental revenue earning days at a reduced performance rate, equipment
penalties assessed against revenue and the absence of additional revenue associated with the rig working outside its
normal operating zone and a $17.9 million decrease in amortized mobilization revenue. However, average daily revenue
for 2013 was favorably impacted by $25.0 million in revenue recognized in connection with the Settlement Agreement.
Total revenue earning days for our ultra-deepwater floaters decreased during 2013, compared to 2012, primarily due to
incremental unplanned downtime (225 additional days), partially offset by a reduction in downtime for shipyard projects
and inspections (128 fewer days) and mobilization of rigs (21 fewer days).
Contract drilling expense incurred by our ultra-deepwater floaters decreased $6.8 million during 2013, compared to
2012, primarily due to lower amortized mobilization costs ($21.8 million) and freight costs ($8.8 million), partially offset
by higher costs associated with rig personnel ($18.8 million) and repairs and maintenance ($5.1 million).
Deepwater Floaters. Revenue generated by our deepwater floaters increased $19.4 million during 2013, compared to
2012, as a result of higher average daily revenue earned ($47.3 million), partially offset by 75 fewer revenue earning days
($27.9 million). Average daily revenue earned by our deepwater floaters during 2013 increased primarily due to both the
Ocean Valiant and Ocean Victory working at significantly higher dayrates than those earned in 2012, partially offset by
lower amortized mobilization revenue ($5.4 million) during 2013. In contrast, total revenue earning days for our
deepwater floaters declined in 2013 due to incremental unscheduled downtime for repairs (32 additional days), scheduled
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shipyard projects (26 additional days) and mobilization of the Ocean America (14 days). Contract drilling expense
increased $14.6 million in 2013, compared to 2012, reflecting higher labor and other personnel-related costs ($8.4
million), shorebase support costs and overheads ($5.2 million), and repair and maintenance costs ($2.1 million), partially
offset by lower costs associated with the mobilization of rigs ($4.0 million).
Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $77.1 million during 2013, compared to
2012, primarily as a result of 453 fewer revenue earning days ($124.4 million), partially offset by the effect of higher
average daily revenue earned ($47.3 million). The decrease in revenue earning days during 2013 was primarily due to an
increase in planned downtime for shipyard inspections and projects (322 additional days), non-revenue earning days
associated with the Niko and OGX contracts (136 days) and additional non-operating days for the Ocean Whittington (102
additional days), offset by fewer days for the mobilization of rigs (114 fewer days). Average daily revenue increased in
2013, compared to 2012, primarily due to new contracts or contract renewals for the Ocean General, Ocean Patriot, Ocean
Nomad and Ocean Vanguard at higher dayrates than previously earned.
Contract drilling expense remained relatively consistent in 2013 compared to 2012, increasing only $2.1 million.
During 2013, our mid-water floaters benefited from cost reductions associated with the cold stacking of the Ocean
Whittington and return of the Ocean Ambassador to the GOM ($47.4 million), combined with the absence of costs
associated with the 2012 demobilization of the Ocean Guardian from the Falkland Islands ($12.1 million) and repair and
maintenance activities after arriving in the U.K. ($7.2 million). However, cost reductions were offset by higher contract
drilling expenses for the remainder of our mid-water fleet, primarily for labor and other personnel-related costs ($8.7
million), repairs and maintenance ($18.8 million), inspections ($13.0 million) and mobilization of rigs ($21.6 million).
Jack-ups. Contract drilling revenue and expense for our jack-up rigs increased $13.5 million and $8.6 million,
respectively, in 2013, compared to 2012. The Ocean King, which was warm stacked in Montenegro in 2010, returned to the
GOM in early 2013 and commenced operations in the second quarter. During 2013, the Ocean King earned revenue and
incurred incremental contract drilling expense of $26.2 million and $14.1 million, respectively, compared to 2012. The
increase in both contract drilling revenue and expense for our jack-up fleet during 2013 was partially offset by the absence
of $5.4 million in revenue and $8.4 million in costs attributable to our six jack-up rigs that we sold in 2012. Revenues in
2013 were further reduced as a result of 81 incremental days of scheduled downtime for repairs for the Ocean Scepter and
Ocean Nugget ($9.5 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. In addition, we currently have available a syndicated 5-Year Revolving Agreement, or
Credit Agreement, to meet our short-term and long-term liquidity needs. See “— Credit Agreement, Senior Notes and
Commercial Paper Program.” At the date of this report, our contract drilling backlog was $6.8 billion, of which $2.3 billion
is expected to be realized in 2015.
At December 31, 2014, 2013 and 2012, we had cash available for current operations as follows:
December 31,
2014
2013
2012
(In thousands)
Cash and equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$233,623
$ 347,011
$ 335,432
Marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16,033
1,750,053
1,150,158
Total cash available for current operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$249,656
$2,097,064
$1,485,590
A substantial portion of our cash flows has been and is expected to continue to be invested in the enhancement of
our drilling fleet. 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.
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Certain of our international rigs are owned and operated, directly or indirectly, by DOIL, and, as a result of our
intention to indefinitely reinvest the earnings of DOIL 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.” We expect to utilize the operating cash flows generated by and cash reserves of
DOIL 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. However, in light of the significant cash
requirements of our capital expansion program in 2015 and 2016, we may also make use of our credit facility or
commercial paper program to finance our capital expenditures and working capital requirements. In addition, we will
make periodic assessments of our capital spending programs based on industry conditions and make adjustments thereto
if required. See “— Cash Flow and Capital Expenditures — Contractual Cash Obligations — Rig Construction” and
“—Credit Agreement, Senior Notes and Commercial Paper Program — $1.5 Billion Revolving Credit Agreement.”
We pay dividends at the discretion of our Board of Directors, or Board, and, in recent years, we have paid both regular
quarterly and special cash dividends. 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. During the three-year period ended
December 31, 2014, we paid regular cash dividends totaling $207.8 million and special cash dividends totaling $1.2 billion.
Our Board has adopted a policy of considering paying 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 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 6, 2015, we declared a regular cash dividend of $0.125 per share of our common stock payable on
March 2, 2015 to stockholders of record on February 20, 2015. See “Risk Factors — Although we have paid cash dividends
in the past, we will not pay a special dividend in the first quarter of 2015, 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 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 2013
or 2012. 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 year ended December 31, 2014, Loews
purchased 1,879,600 shares of our common stock. Loews did not purchase any shares of our outstanding common stock
during 2013 or 2012.
During the three-year period ended December 31, 2014, our primary source of cash was an aggregate $3.4 billion
generated from operating activities, $987.8 million net proceeds from the issuance of senior notes in 2013, $148.4 million
received from the sale of drillings rig in 2012 and 2014 and $885.7 million net proceeds from the maturity of marketable
securities, net of purchases. Cash usage during the same period was primarily for capital expenditures ($3.7 billion),
payment of dividends and anti-dilution payments to stock plan participants ($1.5 billion), repayment of long-term debt
($250.0 million) and the acquisition of treasury stock ($87.8 million).
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 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.
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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, 2014 were as follows:
Year Ended December 31,
2014
2013
2012
(In thousands)
Cash flow from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 992,831
$1,065,988
$1,311,269
Capital expenditures:
Drillship construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,318,271
$ 130,268
$ 248,346
Construction of deepwater floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
168,045
Construction of ultra-deepwater floater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ocean Patriot enhancement programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ocean Confidence service-life-extension project
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rig equipment and replacement programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18,223
107,181
134,871
286,173
396,584
195,578
29,948
—
153,529
—
—
—
205,220
300,166
Total capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,032,764
$ 957,598
$ 702,041
Cash Flow. 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 our $1.0 billion in debt issued in November 2013 and an early interest
payment for our 4.875% senior notes due July 1, 2015, or 2015 Notes. 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).
Cash flow from operations decreased approximately $245.3 million during 2013, compared to 2012, primarily due to a
$165.3 million decrease in cash receipts from contract drilling services and higher cash payments for contract drilling
expenses of $83.2 million, partially offset by lower cash income taxes paid, net of refunds, of $3.3 million.
See “— Results of Operations — Years Ended December 31, 2014, 2013 and 2012.”
Capital Expenditures.
As of the date of this report, we expect capital expenditures for 2015 to aggregate approximately $944.0 million, of
which we expect to spend approximately $602.0 million on our current rig construction projects, including the Ocean
Confidence service-life-extension project and an estimated $342.0 million for our ongoing capital maintenance and
replacement programs. See “— Contractual Cash Obligations — Rig Construction.” We expect to fund our 2015 capital
spending from the operating cash flows generated by and cash reserves of DOIL 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 two rigs under construction in Ulsan, South Korea and are obligated under
separate construction agreements with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of these two
rigs. See Note 12 “Commitments and Contingencies” to our Consolidated Financial Statements included in Item 8 of this
report for further discussion of these projects.
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The following is a summary of our construction projects as of December 31, 2014:
Project
New Rig Construction:
Drillship:
Expected
Delivery (1)
Total
Project
Cost (2)
Project
Expenditures (3)
Capitalized
Interest
2015 (4)
Actual Inception-to-Date
(In millions)
Ocean BlackLion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Q1 2015
$ 655
$199
$27
$456(5)
Ultra-Deepwater Floater:
Ocean GreatWhite . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Q1 2016
764
$1,419
197
$396
17
$44
46
$502
(1) Represents expected delivery date of vessel from shipyard and does not include additional non-operating days for
commissioning, contract preparation and mobilization to initial area of operation, which will occur prior to the rig
being placed in service.
(2) Total project costs include contractual payments for shipyard construction, commissioning, capital spares and
project management costs; amount does not include capitalized interest.
(3) Represents total project expenditures, including accrued expenditures, from inception of project, to December 31,
2014 excluding project-to-date capitalized interest.
(4) Estimated expenditures for 2015, including construction milestone payments, are based on current expected delivery
dates for the rigs under construction, and exclude expected capitalized interest costs.
(5) Construction milestone payment to Hyundai of approximately $395 million is expected to be paid in the first quarter
of 2015 upon delivery of the Ocean BlackLion.
Credit Agreement, Senior Notes and Commercial Paper Program
$1.5 Billion Revolving Credit Agreement. Our Credit Agreement provides for a $1.5 billion senior unsecured revolving
credit facility, for general corporate purposes, which matures on October 22, 2019, except for $40 million of commitments
that mature on March 17, 2019. 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 up to two additional one-year extensions 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. As of
December 31, 2014, there were no loans or letters of credit outstanding under the Credit Agreement.
Commercial Paper Program. In February 2015, we established a commercial paper program with three 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. 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. Our Credit Agreement provides liquidity for our payment obligations in respect of the
notes issued under the commercial paper program, and unless we change the terms of the program, the aggregate
amount of notes outstanding at any time will not exceed the amount available under the Credit Agreement. As of the date
of this report, we had no commercial paper notes outstanding.
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Senior Notes.
Our senior notes are comprised of the following:
Debt Issue
Principal
Amount
(In millions)
Maturity Date
Stated
Interest
Rate
Semiannual
Interest Payment
Dates
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 . . . . . . . . . . . . . . . . . . . .
$250.0
$500.0
$250.0
$500.0
$750.0
July 1, 2015
May 1, 2019
November 1, 2023
October 15, 2039
November 1, 2043
January 1 and July 1
4.875%
5.875% May 1 and November 1
3.45% May 1 and November 1
5.70% April 15 and October 15
4.875% May 1 and November 1
Our 4.875% Senior Notes, due 2015, in the aggregate principal amount of $250.0 million, will mature on July 1, 2015.
See Note 10 “Credit Agreement and Senior Notes” to our Consolidated Financial Statements in Item 8 of this report.
Credit Ratings. During the third quarter of 2014, S&P revised its outlook on us to negative and, in December 2014,
lowered our corporate credit and unsecured debt rating to A- from A. In February 2015, Moody’s Investors Services, or
Moody’s, and S&P assigned short-term credit ratings of Prime-2 and A2, respectively, to our commercial paper
program. Concurrently, Moody’s and S&P affirmed our
long-term corporate credit
rating of A3 and A-,
respectively. 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 impact our cost of issuing additional debt and the amount of
additional debt that we could issue. A series of downgrades or a substantial downgrade could restrict our access to 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, 2014.
Contractual
Obligations (1) (2)
Payments Due By Period
Total
Less than 1 year
1-3 years
4-5 years
After 5 years
(In thousands)
Long-term debt (principal and interest) . . . . . . . . . . . . . . . .
Construction contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,238,754
868,805
3,677
$359,192
428,843
1,342
$206,126
439,962
1,919
$691,438
—
416
$2,981,998
—
—
Total obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$5,111,236
$789,377
$648,007
$691,854
$2,981,998
(1) The above table excludes foreign currency forward exchange, or FOREX, contracts in the aggregate notional amount
of $70.2 million outstanding at December 31, 2014. See further information regarding these contracts in “Quantitative
and Qualitative Disclosures About Market Risk — Foreign Exchange Risk” in Item 7A of this report and Note 7
“Derivative Financial Instruments” to our Consolidated Financial Statements in Item 8 of this report.
(2) The above table excludes $50.5 million of unrecognized tax benefits related to uncertain tax positions as of
December 31, 2014 and an additional $37.6 million and $7.5 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, 2014, except for those
related to our direct rig operations, which arise during the normal course of business.
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Other Commercial Commitments — Letters of Credit
We were contingently liable as of December 31, 2014 in the amount of $99.6 million under certain performance, bid,
supersedeas and customs bonds and letters of credit. Agreements relating to approximately $92.0 million of performance,
security, supersedeas and customs bonds can require collateral at any time. As of December 31, 2014, 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.
For the Years Ending December 31,
Total
2015
2016
2017
2018
(In thousands)
Other Commercial Commitments
Performance bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$87,272
$23,680
$8,170
$36,297
$19,125
Supersedeas bond . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,189
3,141
9,189
3,141
—
—
—
—
—
—
Total obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$99,602
$36,010
$8,170
$36,297
$19,125
Off-Balance Sheet Arrangements
At December 31, 2014 and 2013, we had no off-balance sheet debt or other 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. When possible, we 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.
To the extent that we are not able to cover our local currency operating costs with customer payments in the local
currency, we may also utilize FOREX contracts to reduce our currency exchange risk. Our FOREX contracts may obligate
us to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specific
dates or 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 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 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,
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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:129) market conditions and the effect of such conditions on our future results of operations;
(cid:129) sources and uses of and requirements for financial resources;
(cid:129) interest rate and foreign exchange risk;
(cid:129) contractual obligations;
(cid:129) operations outside the United States;
(cid:129) business strategy;
(cid:129) growth opportunities;
(cid:129) competitive position;
(cid:129) expected financial position;
(cid:129) cash flows and contract backlog;
(cid:129) declaration and payment of regular or special dividends;
(cid:129) financing plans;
(cid:129) market outlook;
(cid:129) tax planning;
(cid:129) debt levels and the impact of changes in the credit markets and credit ratings for our debt;
(cid:129) budgets for capital and other expenditures;
(cid:129) timing and duration of required regulatory inspections for our drilling rigs;
(cid:129) timing and cost of completion of rig upgrades, construction projects and other capital projects;
(cid:129) delivery dates and drilling contracts related to rig conversion or upgrade projects, construction projects, other
capital projects or rig acquisitions;
(cid:129) plans and objectives of management;
(cid:129) idling drilling rigs or reactivating stacked rigs;
(cid:129) scrapping retired rigs;
(cid:129) assets held for sale;
(cid:129) asset impairments and impairment evaluations;
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(cid:129) effective date and performance of contracts;
(cid:129) outcomes of legal proceedings;
(cid:129) compliance with applicable laws; and
(cid:129) availability, limits and adequacy of insurance or indemnification.
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:129) those described under “Risk Factors” in Item 1A;
(cid:129) general economic and business conditions;
(cid:129) worldwide supply and demand for oil and natural gas;
(cid:129) changes in foreign and domestic oil and gas exploration, development and production activity;
(cid:129) oil and natural gas price fluctuations and related market expectations;
(cid:129) 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;
(cid:129) policies of various governments regarding exploration and development of oil and gas reserves;
(cid:129) our inability to obtain contracts for our rigs that do not have contracts;
(cid:129) the cancellation of contracts included in our reported contract backlog;
(cid:129) advances in exploration and development technology;
(cid:129) 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;
(cid:129) casualty losses;
(cid:129) operating hazards inherent in drilling for oil and gas offshore;
(cid:129) the risk that future regular and special dividends may not be declared or paid;
(cid:129) the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico;
(cid:129) industry fleet capacity, including, without limitation, construction of new drilling rig capacity in Brazil;
(cid:129) market conditions in the offshore contract drilling industry, including, without limitation, dayrates and utilization
levels;
(cid:129) competition;
(cid:129) changes in foreign, political, social and economic conditions;
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(cid:129) 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;
(cid:129) risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;
(cid:129) customer or supplier bankruptcy or liquidation;
(cid:129) the ability of customers and suppliers to meet their obligations to us and our subsidiaries;
(cid:129) collection of receivables;
(cid:129) the risk that a letter of intent may not result in a definitive agreement;
(cid:129) foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;
(cid:129) risks of war, military operations, other armed hostilities, terrorist acts and embargoes;
(cid:129) changes in offshore drilling technology, which could require significant capital expenditures in order to maintain
competitiveness;
(cid:129) regulatory initiatives and compliance with governmental regulations including, without limitation, regulations
pertaining to climate change, greenhouse gases, carbon emissions or energy use;
(cid:129) compliance with and liability under environmental laws and regulations;
(cid:129) 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;
(cid:129) development and exploitation of alternative fuels;
(cid:129) customer preferences;
(cid:129) effects of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury
verdicts;
(cid:129) cost, availability, limits and adequacy of insurance;
(cid:129) invalidity of assumptions used in the design of our controls and procedures;
(cid:129) the results of financing efforts;
(cid:129) adequacy and availability of our sources of liquidity;
(cid:129) risks resulting from our indebtedness;
(cid:129) public health threats;
(cid:129) negative publicity;
(cid:129) impairments of assets;
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(cid:129) the availability of qualified personnel to operate and service our drilling rigs; and
(cid:129) various other matters, many of which are beyond our control.
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.
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, 2014 and 2013,
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, 2014 and 2013, 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, 2014 and 2013, 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 $176.8 million and $221.5
million as of December 31, 2014 and 2013, respectively. A 100-basis point decrease would result in an increase in market
value of $210.6 million and $264.5 million as of December 31, 2014 and 2013, respectively.
3
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Foreign Exchange Risk
Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will 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, 2014, we had FOREX contracts outstanding in the aggregate notional amount of $70.2 million,
consisting of $8.2 million in Australian dollars, $15.9 million in Brazilian reais, $31.3 million in British pounds sterling and
$14.8 million in Mexican pesos. These contracts generally settle monthly through September 2015. 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. We have presented the fair value of our
outstanding FOREX contracts at December 31, 2013, as a current asset of $1.6 million in “Prepaid expenses and other
current assets” and a current liability of $(1.1) 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):
Interest rate:
Fair Value Asset (Liability)
December 31,
Market Risk
December 31,
2014
2013
2014
2013
(In thousands)
Marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$16,000 (a) $1,750,100 (a) $
(600) (b) $ (2,200) (b)
Foreign Exchange:
Forward exchange contracts — receivable positions . . . . . . . . . . . . . . .
— (c)
1,600 (c)
— (d)
(4,200) (d)
Forward exchange contracts — liability positions . . . . . . . . . . . . . . . . .
(5,400) (c)
(1,100) (c)
(12,100) (d)
(16,000) (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, 2014 and 2013.
(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, 2014 and 2013.
(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 and 2013.
(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 and 2013, with all other variables held
constant.
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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, 2014 and 2013, and the related consolidated statements of operations,
comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31,
2014. 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, 2014 and 2013, and the results of their operations and
their cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, 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 23, 2015, expressed an unqualified opinion on the Company’s internal control
over financial reporting.
Houston, Texas
February 23, 2015
/s/ Deloitte & Touche LLP
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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, 2014, 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, 2014, 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 balance sheets of the Company as of and for the year ended December 31, 2014 and our report
dated February 23, 2015 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Houston, Texas
February 23, 2015
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
December 31,
2014
2013
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 233,623
$ 347,011
Marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16,033
1,750,053
Accounts receivable, net of allowance for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
463,862
185,541
—
469,355
143,997
7,694
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
899,059
2,718,110
Drilling and other property and equipment, net of accumulated depreciation . . . . . . . . . . . . . . .
6,945,953
5,467,227
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
176,277
206,097
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$8,021,289
$8,391,434
Current liabilities:
LIABILITIES AND STOCKHOLDERS’ EQUITY
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 138,444
$
94,151
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
426,592
370,671
Taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
41,648
30,806
Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
249,962
249,954
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
856,646
745,582
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,994,526
2,244,189
Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
530,394
188,160
525,541
238,864
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,569,726
3,754,176
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; 143,960,260 shares issued
and 137,147,899 shares outstanding at December 31, 2014; 143,952,248 shares issued and
139,035,448 shares outstanding at December 31, 2013) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,440
1,440
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,993,898
1,988,720
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,661,999
2,761,161
Accumulated other comprehensive gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(3,605)
350
Treasury stock, at cost (6,812,361 and 4,916,800 shares of common stock at December 31,
2014 and 2013, respectively) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(202,169)
(114,413)
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,451,563
4,637,258
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$8,021,289
$8,391,434
The accompanying notes are an integral part of the consolidated financial statements.
7
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Year Ended December 31,
2014
2013
2012
Revenues:
Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,737,126
$2,843,584
$2,936,066
Revenues related to reimbursable expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
77,545
76,837
50,442
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,814,671
2,920,421
2,986,508
Operating expenses:
Contract drilling, excluding depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,523,623
1,572,525
1,537,224
Reimbursable expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
76,091
74,967
48,778
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
456,483
388,092
392,913
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
81,832
64,788
Impairment of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
109,462
—
Bad debt expense (recovery) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
22,513
64,640
62,437
(1,018)
Gain on disposition of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(5,382)
(4,070)
(80,844)
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,242,109
2,118,815
2,024,130
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
572,562
801,606
962,378
Other income (expense):
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
801
701
4,910
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(62,053)
(24,843)
(46,216)
Foreign currency transaction gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,199
682
(4,915)
1,691
(1,999)
(992)
Income before income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
515,191
774,240
918,081
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(128,180)
(225,554)
(197,604)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 387,011
$ 548,686
$ 720,477
Earnings per share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2.82
2.81
$
$
3.95
3.95
$
$
5.18
5.18
Weighted-average shares outstanding:
Shares of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
137,473
139,035
139,029
Dilutive potential shares of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
29
19
Total weighted-average shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . .
137,523
139,064
139,048
Cash dividends declared per share of common stock . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3.50
$
3.50
$
3.50
The accompanying notes are an integral part of the consolidated financial statements.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31,
2014
2013
2012
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$387,011
$548,686
$720,477
Other comprehensive gains (losses), net of tax:
Derivative financial instruments:
Unrealized holding (loss) gain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustment for (gain) loss included in net income . . . . . . . . . . . . . . .
(1,482)
(2,379)
(6,833)
4,840
4,237
2,733
Investments in marketable securities:
Unrealized holding (loss) gain on investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustment for (gain) loss included in net income . . . . . . . . . . . . . . .
(69)
(25)
(6)
(147)
124
44
Total other comprehensive (loss) gain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(3,955)
(2,146)
7,138
Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$383,056
$546,540
$727,615
The accompanying notes are an integral part of the consolidated financial statements
9
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except number of shares)
Common Stock
Shares
Amount
Additional
Paid-In
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Gains (Losses)
Treasury Stock
Shares
Amount
Total
Stockholders’
Equity
January 1, 2012 . . . . . . . . . . . . . . . . 143,944,009 1,439 1,978,369 2,472,310
(4,642)
4,916,800 (114,413) 4,333,063
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 gain on derivative financial
instruments . . . . . . . . . . . . . . . . .
Net gain on investments . . . . . . . .
—
—
—
4,361
—
—
—
—
—
—
—
—
—
—
— 720,477
— (486,603)
—
148
(3,269)
—
5,440
—
—
—
—
—
—
—
—
—
—
6,970
168
—
—
—
—
—
—
—
— 720,477
— (486,603)
—
—
—
—
—
(3,269)
148
5,440
6,970
168
December 31, 2012 . . . . . . . . . . . . 143,948,370 1,439 1,983,957 2,702,915
2,496
4,916,800 (114,413) 4,576,394
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
—
—
—
— 548,686
— (486,620)
—
109
(3,820)
—
4,654
—
—
—
—
—
—
—
—
—
—
(1,993)
(153)
—
—
—
—
—
—
—
— 548,686
— (486,620)
—
—
—
—
—
(3,820)
110
4,654
(1,993)
(153)
December 31, 2013 . . . . . . . . . . . . 143,952,248 1,440 1,988,720 2,761,161
350
4,916,800 (114,413) 4,637,258
Net income . . . . . . . . . . . . . . . . . . .
Dividends to stockholders
($3.50 per share) . . . . . . . . . . . . .
Treasury stock purchase . . . . . . . .
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 . . . . . . . . .
—
—
—
—
8,012
—
—
—
—
—
—
—
—
—
—
—
— 387,011
—
—
— 387,011
— (481,642)
—
—
—
—
— 1,895,561
— (481,642)
(87,756)
(87,756)
—
213
(4,531)
—
4,965
—
—
—
—
—
—
—
—
(3,861)
(94)
—
—
—
—
—
—
—
—
—
—
(4,531)
213
4,965
(3,861)
(94)
December 31, 2014 . . . . . . . . . . . . 143,960,260 $1,440 $1,993,898 $2,661,999
$(3,605)
6,812,361 $(202,169)$4,451,563
The accompanying notes are an integral part of the consolidated financial statements.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on impairment of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on disposition of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt expense (recovery) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Gain) loss on foreign currency forward exchange contracts . . . . . . . . . . . . . .
Deferred tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discounts on marketable securities . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term employee remuneration programs . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets, noncurrent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities, noncurrent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from (payments of) settlement of foreign currency forward exchange
contracts designated as accounting hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2014
2013
2012
$
387,011
$
548,686
$
720,477
456,483
109,462
(5,382)
—
(3,275)
1,532
(277)
3,507
60,061
(82,814)
1,195
2,881
(3,979)
3,275
5,520
2,200
5,269
(2,791)
27,463
25,490
388,092
—
(4,070)
22,513
6,501
34,101
(707)
3,573
(54,274)
25,604
8,966
(4,922)
(5,296)
(6,501)
(12,741)
1,954
7,905
10,066
46,752
49,786
392,913
62,437
(80,844)
(1,018)
4,302
(51,472)
4,622
4,357
1,767
67,824
7,611
(2,794)
3,614
(4,302)
—
1,258
65,074
(8,960)
10,354
114,049
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
992,831
1,065,988
1,311,269
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(2,032,764)
18,318
8,000,057
(6,265,846)
(957,598)
4,900
4,650,085
(5,249,462)
(702,041)
138,495
2,725,118
(2,977,290)
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(280,235)
(1,552,075)
(815,718)
Financing activities:
Repayment of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuance of senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs and arrangement fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(250,000)
—
(2,249)
(486,240)
(87,756)
261
—
997,805
(9,973)
(490,331)
—
165
—
—
(3,838)
(490,245)
—
199
Net cash used in financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(825,984)
497,666
(493,884)
Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . .
(113,388)
347,011
11,579
335,432
1,667
333,765
Cash and cash equivalents, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
233,623
$
347,011
$
335,432
The accompanying notes are an integral part of the consolidated financial statements.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1 . G e n e r a l In f o r m a t i o n
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 38 offshore drilling rigs, excluding three mid-water semisubmersible rigs which
we plan to retire and scrap. Our current fleet, excluding the retired units, consists of 27 semisubmersibles, one of which is
under construction, six jack-ups and five dynamically positioned drillships, one of which is under construction. 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, 2015, Loews Corporation, or Loews, owned 52.5% 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. We had bank deposits
denominated in Egyptian pounds totaling $7.3 million and $14.3 million at December 31, 2014 and 2013,
respectively. However, the local currency is not readily convertible into U.S. dollars or other currencies at this time. We
expect to use a portion of these amounts to fund local obligations in Egyptian pounds in the short term and have reported
$7.2 million and $12.7 million, representing the excess of total bank deposits over our estimated local currency
requirements for the next twelve months, as “Other assets” in our Consolidated Balance Sheets at December 31, 2014 and
2013, respectively.
The effect of exchange rate changes on cash balances held in foreign currencies was not material for the years ended
December 31, 2014, 2013 and 2012.
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.”
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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.
Derivative Financial Instruments
Our derivative financial instruments consist primarily 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.
Asset Held For Sale
At December 31, 2013, we reported the $7.7 million carrying value of our jack-up rig, the Ocean Spartan, as “Asset
held for sale” in our Consolidated Balance Sheets. The Ocean Spartan was sold in June 2014 for an aggregate selling price
of $16.5 million, and we recognized a net gain of $8.5 million on the transaction.
Drilling and Other Property and Equipment
We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to
income currently while replacements and betterments, including associated inspection and recertification costs, which
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, 2014 and 2013, we capitalized $546.0 million and $302.0 million,
respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from
$25,000 to $160 million per project.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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, 2014, we capitalized interest on qualifying expenditures, primarily related to our rig construction projects.
See Note 9.
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 . . . . . . . . . .
$122,656
$ 99,080
$ 83,890
Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(60,603)
(74,237)
(37,674)
Total interest expense as reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 62,053
$ 24,843
$ 46,216
For the Year Ended December 31,
2014
2013
2012
(In thousands)
Impairment of Long-Lived Assets
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 cold stacking a rig, the expectation of cold stacking a rig in
the near term, 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:129) dayrate by rig;
(cid:129) utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);
(cid:129) the per day operating cost for each rig if active, warm stacked or cold stacked;
(cid:129) the estimated annual cost for rig replacements and/or enhancement programs;
(cid:129) the estimated maintenance, inspection or other costs associated with a rig returning to work;
(cid:129) salvage value for each rig; and
(cid:129) estimated proceeds that may be received on disposition of the rig.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Based on these assumptions and estimates, we develop a matrix using several different utilization/dayrate scenarios,
to each of which we have assigned a probability of occurrence. The sum of our utilization scenarios (which include active,
warm stacked and cold stacked) and probability of occurrence scenarios both equal 100% in the aggregate. We reevaluate
these rigs annually, by updating the matrices for each rig and modifying our assumptions, giving consideration to the
length of time the rig has been cold stacked, the current and expected market for the type of rig and expectations of future
oil and gas prices. See Note 2.
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 in “Other assets” and are amortized over the
respective terms of the related debt.
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 14.
Treasury Stock
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 2013 or 2012.
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, 2014, 2013 and 2012 includes net income
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(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, 2014, 2013 and 2012,
we recognized aggregate net foreign currency gains (losses) of $3.2 million, $(4.9) million and $(2.0) 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 Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or 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
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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. ASU 2014-09 is effective for annual
reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and may be
adopted using a retrospective or modified retrospective approach. Early adoption is not permitted. We are currently
evaluating the provisions of ASU 2014-09 and have not yet determined its impact on our financial position, results of
operations or cash flows.
2 . A s s e t Im p a i r m e n t s
During the third quarter of 2014, we initiated a plan to retire and scrap the Ocean New Era, the Ocean Epoch and the
Ocean Whittington, all three of which were cold stacked and initially impaired in 2012, as well as the Ocean Concord and
the Ocean Yatzy, which were idle in Brazil. We also initiated a plan to retire and scrap the Ocean Winner upon completion
of its contract term in Brazil.
Using the undiscounted probability-weighted cash flow analysis described in Note 1, we determined that the carrying
values of the six rigs to be retired and scrapped, or the Retirement Group, were impaired. The fair values of the five non-
working rigs in the Retirement Group were determined based on discussions with and a quote received from a rig broker
to scrap two of the rigs. We consider this to be a Level 3 fair value measurement due to the nonbinding nature of the
quote, the significant level of estimation involved and the lack of transparency as to the inputs used. The fair value of the
sixth rig in the Retirement Group, the Ocean Winner (which is under contract through March 2015) was determined using
an income approach, which utilized significant unobservable inputs, representative of a Level 3 fair value measurement,
including assumptions related to estimated dayrate revenue, rig utilization and anticipated costs for the remainder of the
current contract, as well as the aforementioned scrap value quote. As a result of our valuations, we recognized an
impairment loss aggregating $109.5 million during the third quarter of 2014. See Note 8.
During the fourth quarter of 2014, two of the rigs in the Retirement Group were scrapped. The aggregate book value
of the remaining rigs in the Retirement Group was $9.4 million at December 31, 2014 and is reported in “Drilling and
other property and equipment, net of accumulated depreciation” in our Consolidated Balance Sheets.
At December 31, 2014, we had six rigs, in addition to the Retirement Group, which met our criteria for impairment
evaluation, and we performed an impairment analysis for each of these rigs using the methodology described in Note 1.
Based on our analyses, we concluded that these rigs were not impaired at December 31, 2014.
We did not record any impairment for the year ended December 31, 2013.
During the year ended December 31, 2012, we recognized an impairment loss of $62.4 million in connection with
management’s decision at that time to market for sale four of our then cold stacked rigs. One of these rigs was sold to a
third party in 2014 and the remaining three rigs were evaluated for impairment as part of the Retirement Group in 2014.
See Note 1.
Management’s assumptions are an inherent part of our asset impairment evaluation, and the use of different
assumptions could produce results that differ from those reported.
7
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
3 . S u p p l e m e n t a l F i n a n c i a l I n f o r m a t i o n
Consolidated Balance Sheet Information
Accounts receivable, net of allowance for bad debts, consists of the following:
December 31,
2014
2013
(In thousands)
Trade receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$437,017
$473,013
Value added tax receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts held in escrow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Related party receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24,853
6,450
19,407
3,066
317
339
610
7
587
615
469,586
496,695
Allowance for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(5,724)
(27,340)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$463,862
$469,355
An analysis of the changes in our provision for bad debts for each of the three years ended December 31, 2014, 2013
and 2012, is as follows:
For the Year Ended December 31,
2014
2013
2012
(In thousands)
Allowance for bad debts, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 27,340
$ 5,458
$ 6,867
Bad debt expense:
Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recovery of bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total bad debt expense (recovery) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
Write off of uncollectible accounts against reserve . . . . . . . . . . . . . . . . . . . .
(21,148)
Other (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(468)
22,513
—
—
(1,018)
22,513
(1,018)
(509)
(122)
(391)
—
Allowance for bad debts, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 5,724
$27,340
$ 5,458
(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.
6
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A
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N
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Prepaid expenses and other current assets consist of the following:
December 31,
2014
2013
(In thousands)
Rig spare parts and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 56,315
$ 52,439
Deferred mobilization costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FOREX contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53,206
12,163
15,612
44,085
—
4,160
20,274
12,503
10,221
42,058
1,562
4,940
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$185,541
$143,997
Accrued liabilities consist of the following:
December 31,
2014
2013
(In thousands)
Rig operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 85,897
$ 87,307
Payroll and benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
131,664
121,387
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63,209
Accrued capital project/upgrade costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
103,123
Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18,365
Personal injury and other claims . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FOREX contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,570
5,439
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,325
26,975
86,274
28,324
9,687
1,143
9,574
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$426,592
$370,671
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:
December 31,
2014
2013
2012
(In thousands)
Accrued but unpaid capital expenditures at period end . . . . . . . . . . . . . . . . . . .
$103,123
$86,274
$56,595
Income tax benefits related to exercise of stock options . . . . . . . . . . . . . . . . . . .
1,458
Cash interest payments (1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
133,784
Cash income taxes paid, net of refunds:
U.S. federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
92,049
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(18)
1,081
82,938
1,083
83,125
62,000
78,041
190
71,000
72,249
243
(1)
Interest payments, net of amounts capitalized, were $73.2 million, $16.5 million and $46.2 million for the years ended
December 31, 2014, 2013 and 2012, respectively.
(2)
Interest paid on Internal Revenue Service assessments was $0.2 million during the year ended December 31, 2012.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
4 . S t o c k - B a s e d Co m p e n s a t i o n
In March 2014, our Board of Directors adopted our Equity Incentive Compensation Plan, or Equity Plan, which
amended and restated our Second Amended and Restated 2000 Stock Option Plan. The Equity Plan was approved by our
stockholders in May 2014.
Awards that may be granted under the Equity Plan include time-vested awards and performance-based awards,
which are earned on the achievement of certain performance criteria. The following types of awards may be granted
under the Equity Plan:
(cid:129) Stock options (including incentive stock options and nonqualified stock options);
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(cid:129) Stock appreciation rights, or SARs;
(cid:129) Restricted stock;
(cid:129) Restricted stock units, or RSUs;
(cid:129) Performance shares or units; and
(cid:129) 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.
Time-Vested Awards. Stock options and 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 stock options and SARs awarded under the Equity Plan may
not be less than the fair market value of our common stock on the date of grant.
Total compensation cost recognized for time-vested awards under the Equity Plan (or its predecessor), consisting
solely of awards of SARs, for the years ended December 31, 2014, 2013 and 2012 was $4.1 million, $3.9 million and $4.7
million, respectively. Tax benefits recognized for the years ended December 31, 2014, 2013 and 2012 related thereto were
$1.4 million, $1.3 million and $1.6 million, respectively.
The fair value of SARs granted under the Equity Plan (or its predecessor) during each of the years ended
December 31, 2014, 2013 and 2012 was estimated using the Black Scholes pricing model.
The following are the weighted average assumptions used in estimating the fair value of our SARs:
Expected life of SARs (in years) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7
7
6
Expected volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21.68% 18.24% 33.45%
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.10%
.75%
Risk free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.08% 1.61%
.78%
.89%
Year Ended December 31,
2014
2013
2012
7
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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.
A summary of stock option and SARs activity under the Equity Plan as of December 31, 2014 and changes during the
year then ended is as follows:
Number of
Awards
Weighted-Average
Exercise Price
Weighted-Average
Remaining
Contractual
Term
(Years)
Aggregate Intrinsic
Value
(In Thousands)
Awards outstanding at January 1,
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,392,659
Granted . . . . . . . . . . . . . . . . . . . . . . . . . .
288,675
Exercised . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . .
Expired . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,377
12,696
71,931
$78.22
$47.09
$28.28
$61.77
$77.21
Awards outstanding at December 31,
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,587,330
$73.03
Awards exercisable at December 31,
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,188,938
$78.62
6.3
5.5
$160
$ 36
The weighted-average grant date fair values per share of awards granted during the years ended December 31, 2014,
2013 and 2012 were $10.40, $13.74 and $19.01, respectively. The total intrinsic value of awards exercised during the years
ended December 31, 2014, 2013 and 2012 was $169,000, $162,000 and $147,000, respectively. The total fair value of awards
vested during the years ended December 31, 2014, 2013 and 2012 was $4.5 million, $4.1 million and $5.2 million,
respectively. As of December 31, 2014 there was $3.9 million of total unrecognized compensation cost related to
nonvested SARs granted under the Equity Plan which we expect to recognize over a weighted average period of two years.
Performance-Based Awards. In March 2014, we awarded 52,581 targeted performance RSUs, with a volume weighted
average price of our common stock preceding the grant date of $47.52 per share, to our Chief Executive Officer, or CEO, in
connection with his commencement of service with us on March 3, 2014. RSUs are contractual rights to receive shares of
our common stock in the future if the applicable vesting conditions are met. Targeted RSUs will become earned RSUs
upon achievement of certain performance goals as set forth in the award certificate. In January 2015, the compensation
committee of our Board of Directors determined that our CEO had satisfied all performance criteria required for the
52,581 target performance RSUs to become earned by him. Earned RSUs granted to our CEO will vest in one-third
increments annually, over three years, commencing on the first anniversary of his hire date, with the first year being
prorated for the portion of 2014 during which he was employed. As of December 31, 2014, none of the RSUs granted to
our CEO had vested.
Because the stock-based compensation awarded to our CEO is a fixed monetary amount at the date of grant (the
target value of $3.0 million on a prorated basis) with variances based on actual achievement of a performance goal, the
award is being recorded as a share-based liability. Compensation cost will be recognized over the requisite service period
as specified in the award. In connection with the targeted RSUs granted in March 2014, we recognized $0.9 million in
compensation expense for the year ended December 31, 2014. “Accrued liabilities” at December 31, 2014 included $0.9
million for share-based liabilities.
1
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
5 . E a r n i n g s P e r S h a r e
A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:
Year Ended December 31,
2014
2013
2012
(In thousands, except per share data)
Net income — basic and diluted (numerator): . . . . . . . . . . . . . . . . . . . . .
$ 387,011
$548,686
$ 720,477
Weighted-average shares — basic (denominator):
. . . . . . . . . . . . . . . . .
137,473
139,035
139,029
Dilutive effect of stock-based awards . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
29
19
Weighted-average shares including conversions — diluted
(denominator):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
137,523
139,064
139,048
Earnings per share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2.82
2.81
$
$
3.95
3.95
$
$
5.18
5.18
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:
Year Ended December 31,
2014
2013
2012
(In thousands)
Employee and director:
Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SARs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
37
1,488
18
956
18
853
6 . M a r k e t a b l e S e c u r i t i e s
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.
Our investments in marketable securities are classified as available for sale and are summarized as follows:
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
16,003
Mortgage-backed securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
130
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
16,133
$
$
(104)
$
15,899
4
134
(100)
$
16,033
December 31, 2014
Amortized
Cost
Unrealized
Gain (Loss)
Market
Value
(In thousands)
U.S. Treasury Bills and Notes (due within one year) . . . . . . . . . . . . . . . . .
$1,749,879
Mortgage-backed securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
188
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,750,067
$
$
(22)
$1,749,857
8
196
(14)
$1,750,053
December 31, 2013
Amortized
Cost
Unrealized
Gain (Loss)
Market
Value
(In thousands)
7
2
2
0
1
4
A
N
N
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R
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Proceeds from maturities and sales of marketable securities and gross realized gains and losses are summarized as
follows:
Year Ended December 31,
2014
2013
2012
(In thousands)
Proceeds from maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$8,000,000
$4,650,000
$2,575,000
Proceeds from sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross realized gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross realized losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
57
—
(1)
85
—
(1)
150,118
—
(6)
As of December 31, 2014, the majority of our marketable securities had matured. Our level of investment activity is
dependent on our working capital and other capital requirements during the year, as well as a response to actual or
anticipated events or conditions in the securities markets.
7 . D e r i v a t i v e F i n a n c i a l In s t r u m e n t s
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. 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
(i.e., Australian dollars, Brazilian reais, British pounds sterling and Mexican pesos). These forward contracts are
derivatives as defined by GAAP.
During the years ended December 31, 2014, 2013 and 2012, we settled FOREX contracts with aggregate notional
values of approximately $304.7 million, $307.4 million and $305.6 million, respectively, of which the entire aggregate
amounts were designated as an accounting hedge. During the years ended December 31, 2014, 2013 and 2012, we did not
enter into or settle any FOREX contracts that were not designated as accounting hedges.
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, 2014,
2013 and 2012.
Location of Gain (Loss) Recognized in Income
Amount of Gain (Loss) Recognized in Income
For the Years Ended December 31,
2014
2013
2012
(In thousands)
Contract drilling expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,275
$(6,501)
$(4,302)
As of December 31, 2014, we had FOREX contracts outstanding in the aggregate notional amount of $70.2 million,
consisting of $8.2 million in Australian dollars, $15.9 million in Brazilian reais, $31.3 million in British pounds sterling and
3
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
$14.8 million in Mexican pesos. These contracts generally settle monthly through September 2015. As of December 31,
2014, all outstanding derivative contracts had been designated as cash flow hedges.
We have International Swap Dealers Association, or ISDA, contracts, which are standardized master legal
arrangements that establish key terms and conditions, which govern certain derivative transactions. As of December 31,
2014, our FOREX contracts were with two counterparties and were governed under such ISDA agreements. There are no
requirements to post collateral under these contracts; however, they do contain credit-risk related contingent provisions
including credit
support provisions and the net
settlement of amounts owed in the event of early
terminations. Additionally, should our credit ratings fall below a specified rating immediately following the merger of
Diamond Offshore Drilling, Inc. with another entity, the counterparty may require all outstanding derivatives under the
ISDA contract to be settled immediately at current market value. Our ISDA arrangements also include master netting
agreements to further manage counterparty credit risk associated with our FOREX contracts. We have elected not to offset
the fair value amounts recorded for our derivative contracts under these agreements in our Consolidated Balance Sheets
as of December 31, 2014 and 2013; however, there would have been no significant differences in our Consolidated
Balance Sheets if the estimated fair values were presented on a net basis for these periods.
The following table presents the fair values of our derivative FOREX contracts designated as hedging instruments at
December 31, 2014 and 2013.
Balance Sheet Location
Fair Value
Balance Sheet Location
Fair Value
December 31,
2014
December 31,
2013
(In thousands)
December 31,
2014
December 31,
2013
(In thousands)
Prepaid expenses and other
current assets . . . . . . . . . . . .
$—
$1,562
Accrued liabilities
$(5,439)
$(1,143)
Treasury Lock Agreements
In connection with the offering of our senior unsecured notes in 2013, we entered into two treasury lock agreements
in October 2013 for notional amounts totaling $500 million and designated such contracts as cash flow hedges of interest
rate risk. The agreements were settled in November 2013 upon the completion of the offering of the senior notes for a net
gain of $26,728, before tax. The gain has been recorded as a component of AOCGL and is being amortized to interest
expense over the terms of the respective senior unsecured notes. See Note 10.
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N
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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, 2014, 2013 and 2012.
For the Year Ended December 31,
2014
2013
(In thousands)
2012
FOREX contracts:
Amount of (loss) gain recognized in AOCGL on derivative
(effective portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(2,281)
$
(10,542)
$
6,519
Location of (loss) gain reclassified from AOCGL into income
Contract drilling,
Contract drilling,
Contract drilling,
(effective portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
excluding
excluding
excluding
depreciation
depreciation
depreciation
Amount of (loss) gain reclassified from AOCGL into income
(effective portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3,650
$
(7,449)
$
(4,205)
Location of loss recognized in income on derivative
Foreign currency
Foreign currency
Foreign currency
(ineffective portion and amount excluded from
transaction gain
transaction gain
transaction gain
effectiveness testing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(loss)
(loss)
(loss)
Amount of loss recognized in income on derivative
(ineffective portion and amount excluded from
effectiveness testing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(31)
$
(104)
Treasury lock agreements:
Amount of gain recognized in AOCGL on derivative (effective
portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
27
Location of gain reclassified from AOCGL into income
$
$
(17)
—
(effective portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense
Interest expense
Interest expense
Amount of gain reclassified from AOCGL into income
(effective portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
8
$
1
$
—
As of December 31, 2014, the estimated amount of net unrealized gains (losses) associated with our FOREX contracts
and treasury lock agreements that will be reclassified to earnings during the next twelve months was $(5.4) million and
$8,000, respectively. The net unrealized gains (losses) associated with these derivative financial instruments will be
reclassified to contract drilling expense and interest expense, respectively, to the extent fully effective. During the years
ended December 31, 2014, 2013 and 2012 we did not reclassify any amounts from AOCGL due to the probability of an
underlying forecasted transaction not occurring.
8 . F i n a n c i a l In s t r u m e n t s a n d F a i r V a l u e D i s c l o s u r e s
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 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.
5
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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. During 2014
and 2013, our largest customer in Brazil, Petróleo Brasileiro S.A., or Petrobras, (a Brazilian multinational energy company
that is majority-owned by the Brazilian government), accounted for $123.3 million and $154.5 million, or 29% and 35%,
respectively, of our total consolidated net trade accounts receivable balance.
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. 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 would receive 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.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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, 2014 consisted of cash held in money market funds of $197.5 million and time deposits
of $20.3 million. Our Level 1 assets at December 31, 2013 consisted of cash held in money market
funds of $281.3 million, time deposits of $30.0 million and investments in U.S. Treasury securities of
$1,749.9 million.
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, 2014 consisted of nonrecurring measurements of four mid-water
semisubmersible rigs for which we recorded an impairment loss during the third quarter of 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, 2014 and 2013.
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
7
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
related to six mid-water semisubmersible rigs, which were measured at fair value on a nonrecurring basis in the third
quarter of 2014, of $109.5 million and have presented the loss in “Impairment of assets” in our Consolidated Statements
of Operations for the year ended December 31, 2014. We did not record any such impairment charges during the year
ended December 31, 2013. See Notes 1 and 2.
December 31, 2014
Fair Value Measurements Using
Level 1
Level 2
Level 3
Assets at Fair
Value
Total Losses
for Year
Ended
(In thousands)
Recurring fair value measurements:
Assets:
Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . .
$217,789
$ — $ —
$217,789
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities . . . . . . . . . . . . . . . . . . . . .
—
—
15,899
134
—
—
15,899
134
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$217,789
$16,033
$ —
$233,822
Liabilities:
FOREX contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $ (5,439)
$ —
$ (5,439)
Nonrecurring fair value measurements:
Assets:
Impaired assets (1)(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $ — $9,421
$
9,421
$109,462
(1) Represents the book value as of December 31, 2014 of four of our mid-water semisubmersible rigs, which were
written down to their estimated recoverable amounts in September 2014 and had not yet been scrapped.
(2)
Includes depreciation expense of $6.6 million recognized in the fourth quarter of 2014 for the Ocean Winner, which is
still under contract through March 2015 and was written down to its estimated fair value using an income approach
in September 2014 and excludes the fair values of the Ocean New Era and Ocean Whittington, which were included in
the September 2014 write-down, but were subsequently sold for scrap in the fourth quarter of 2014.
December 31, 2013
Fair Value Measurements Using
Level 1
Level 2
Level 3
Assets at
Fair Value
(In thousands)
Recurring fair value measurements:
Assets:
Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,061,154
$ —
FOREX contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
1,562
197
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,061,154
$ 1,759
$—
—
—
$—
$2,061,154
1,562
197
$2,062,913
Liabilities:
FOREX contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $(1,143)
$—
$
(1,143)
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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:129) Cash and cash equivalents — The carrying amounts approximate fair value because of the short maturity of these
instruments.
(cid:129) Accounts receivable and accounts payable — The carrying amounts approximate fair value based on the nature of
the 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, 2014 and 2013. 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 (see Note 10) of our senior notes are shown below.
December 31, 2014
December 31, 2013
Fair Value
Carrying Value
Fair Value
Carrying Value
(In millions)
5.15% Senior Notes due 2014 . . . . . . . . . . . . . . . . . . . . . . . .
$ —
$ —
$257.4
$250.0
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 . . . . . . . . . . . . . . . . . . . . . . .
255.0
544.9
232.0
478.5
638.9
250.0
499.6
249.1
497.0
748.8
265.7
578.1
241.4
543.1
736.1
249.9
499.6
249.0
496.9
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 assurance can be
given that the estimated values are indicative of the amounts that would be realized in a free market exchange.
9
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
9 . D r i l l i n g a n d O t h e r P r o p e r t y a n d E q u i p m e n t
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
December 31,
2014
2013
(In thousands)
Drilling rigs and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10,555,314
$ 7,412,066
Construction work-in-progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
439,206
1,668,211
Land and buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Office equipment and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
66,989
70,591
65,627
65,799
Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,132,100
9,211,703
Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(4,186,147)
(3,744,476)
Drilling and other property and equipment, net
. . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 6,945,953
$ 5,467,227
Construction work-in-progress, including capitalized interest, at December 31, 2014 and 2013 is summarized as
follows:
December 31,
2014
2013
(In thousands)
Ultra-deepwater drillships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$225,405
$ 868,908
Ultra-deepwater semisubmersible:
Ocean GreatWhite . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
213,801
195,578
Deepwater semisubmersibles:
Ocean Onyx . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ocean Apex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
339,129
264,596
Total construction work-in-progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$439,206
$1,668,211
At December 31, 2013, construction work-in-progress included an aggregate $1.3 billion for the deepwater
semisubmersibles Ocean Onyx and Ocean Apex and the ultra-deepwater drillships Ocean BlackHawk, Ocean BlackHornet
and Ocean BlackRhino, which were placed in service at various times during 2014, and are no longer reported as
construction work-in-progress at December 31, 2014. Construction work-in-progress at December 31, 2014 represents
costs associated with the construction of our final drillship, the Ocean BlackLion, and the semisubmersible Ocean
GreatWhite. See Note 12.
10 . Cr e dit Agr eement a nd S en io r No te s
Credit Agreement
We have a syndicated 5-Year Revolving Credit Agreement, or Credit Agreement, with Wells Fargo Bank, National
Association, as administrative agent and swingline lender. Effective October 22, 2014, we entered into a commitment
increase and extension agreement and third amendment to the Credit Agreement which, among other things, increased
the aggregate commitment under the Credit Agreement from $1.0 billion to $1.5 billion and provided for an
approximately seven-month extension of the maturity date for most of the lenders. In addition, pursuant to such
amendment, subject to the conditions specified in the Credit Agreement, we 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
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2
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
additional commitments from new or existing lenders, and to request up to two additional one-year extensions of the
maturity date. As so amended, the Credit Agreement provides for a $1.5 billion senior unsecured revolving credit facility
for general corporate purposes, maturing on October 22, 2019, except for $40 million of commitments that mature on
March 17, 2019. 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.
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 varies from 0% to
0.25%. The applicable interest margin for Eurodollar loans varies between 0.75% and 1.25%.
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. 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.
At December 31, 2014 and 2013, there were no amounts outstanding under the Credit Agreement.
Senior Notes
At December 31, 2014, our senior notes were comprised of the following debt issues:
Debt Issue
(In millions)
Maturity Date
Coupon
Effective
Principal Amount
Interest Rate
Semiannual
Interest Payment
Dates
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 . . . . . . . .
$250.0
$500.0
$250.0
$500.0
$750.0
July 1, 2015
4.875% 4.90%
January 1 and July 1
May 1, 2019
5.875% 5.89% May 1 and November 1
November 1, 2023
3.45% 3.50% May 1 and November 1
October 15, 2039
5.70% 5.75% April 15 and October 15
November 1, 2043
4.875% 4.89% May 1 and November 1
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
At December 31, 2014 and 2013, the carrying value of our senior notes was as follows:
December 31,
2014
2013
(In thousands)
5.15% Senior Notes due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $ 249,954
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
249,962
499,626
249,077
496,973
748,850
249,898
499,551
248,988
496,919
748,833
Total senior notes, net of unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,244,488
$2,494,143
Less: Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
249,962
249,954
Total Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,994,526
$2,244,189
As of December 31, 2014, the aggregate annual maturity of our senior notes was as follows:
Aggregate
Principal
Amount
(In thousands)
Year Ending December 31,
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 250,000
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
500,000
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,500,000
Total maturities of senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,250,000
Less: unamortized discounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(5,512)
Total maturities of senior notes, net of unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,244,488
2013 Debt Issues. 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 New Notes, 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 New Notes 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
New 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
a make-whole redemption price specified in the governing indenture (if applicable) plus accrued and unpaid interest to,
but excluding, the date of redemption.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Other Debt. Our 2015 Notes, 5.875% Senior Notes due 2019 and 5.70% Senior Notes due 2039 are all 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.
Our 2015 Notes, in the aggregate principal amount of $250.0 million, will mature on July 1, 2015. Accordingly, the
aggregate $249.9 million accreted value of our 2015 Notes has been presented as “Current portion of long-term debt” in
our Consolidated Balance Sheets at December 31, 2014. In September 2014, we repaid $250.0 million in aggregate
principal amount of our 5.15% Senior Notes due September 1, 2014. These were presented as “Current portion of long-
term debt” in our Consolidated Balance Sheets at December 31, 2013.
1 1 . O t h e r Co m p r e h e n s i v e In c o m e ( L o s s )
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, 2014 and the cumulative balances in AOCGL by component at
December 31, 2014, 2013 and 2012.
Balance at January 1, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in other comprehensive gain (loss) before reclassifications, after
tax of $(2,282) and $(28) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustments for items included in Net Income, after tax
of $(1,472) and $(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in other comprehensive gain (loss) before reclassifications, after
tax of $3,682 and $18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustments for items included in Net Income, after tax
Unrealized (Loss) Gain on
Derivative
Financial
Instruments
Marketable
Securities
Total
AOCGL
(In thousands)
$(4,620)
$ (22)
$(4,642)
4,237
2,733
6,970
2,350
124
44
168
146
4,361
2,777
7,138
2,496
(6,833)
(6)
(6,839)
of $(2,608) and $18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,840
Total other comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
(1,993)
Balance at December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in other comprehensive gain (loss) before reclassifications, after
tax of $799 and $(15) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustments for items included in Net Income, after tax
(147)
(153)
(7)
4,693
(2,146)
350
357
(1,482)
(69)
(1,551)
of $1,279 and $7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(2,379)
Total other comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
(3,861)
(25)
(94)
(2,404)
(3,955)
Balance at December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(3,504)
$(101)
$(3,605)
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table presents the line items in our Consolidated Statements of Operations affected by reclassification
adjustments out of AOCGL.
Major Components of AOCGL
Derivative financial instruments:
Year Ended December 31,
2014
2013
(In thousands)
2012
Consolidated Statements of
Operations Line Items
Unrealized loss (gain) on FOREX contracts . . . . . . . . . . . . . . $ 3,650 $(7,449)$(4,205)
Unrealized loss (gain) on Treasury Lock Agreements . . . . . .
8
Contract drilling, excluding
depreciation
— Interest expense
1,472 Income tax expense
1
(1,279) 2,608
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$ 2,379 $(4,840)$(2,733)Net of tax
Marketable securities:
Unrealized loss (gain) on marketable securities . . . . . . . . . . $
32 $
(7)
165 $
(18)
(45)Other, net
1 Income tax expense
$
25 $
147 $
(44)Net of tax
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
1 2 . Co m m i t m e n t s a n d Co n t i n g e n c i e s
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 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 and Louisiana 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. Trial of this
declaratory judgment action is scheduled to commence in 2015. 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.
We have been named in various other lawsuits or threatened actions that are incidental to the ordinary course of our
business. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate
outcome or effect of these lawsuits and actions cannot be predicted with certainty. As a result, there can be no assurance
as to the ultimate outcome of these lawsuits. 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.
Brazilian Withholding Contingency. In July 2014, Petrobras notified us, along with other industry participants, that it
is challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs
for its operations in Brazil during the years 2008 and 2009. Petrobras has also notified us that, if Petrobras is ultimately
assessed and must pay such withholding taxes, it will seek reimbursement from us for the portion allocable to our drilling
rigs. We dispute any basis for Petrobras to obtain such reimbursement, and we have notified Petrobras of our position. If
necessary, we intend to defend any reimbursement claims against us vigorously. We are currently unable to estimate the
range of loss, if any, that we would incur if Petrobras is ultimately assessed such taxes and if it is determined that
Petrobras is entitled to obtain reimbursement from us. If Petrobras is assessed such taxes and we are ultimately required
to pay such reimbursement, the amount of such reimbursement could be substantial and could have a material adverse
effect on our financial condition, results of operations and 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
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
due to us under the NPI was received in 2013. However, the customer who 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. Several lienholders filed
motions in the bankruptcy contending that their liens have priority and seeking disgorgement of payments made to us
after the bankruptcy was filed. We believe that the payments at issue are superior to these liens and expect the bankruptcy
proceedings to be concluded with no further impact to us.
Personal Injury Claims. Under our current insurance policies that expire on May 1, 2015, 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 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, 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. At December 31, 2013, our estimated liability for personal injury claims was $35.5 million, of
which $9.5 million and $26.0 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:129) the severity of personal injuries claimed;
(cid:129) significant changes in the volume of personal injury claims;
(cid:129) the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
(cid:129) inconsistent court decisions; and
(cid:129) the risks and lack of predictability inherent in personal injury litigation.
Purchase Obligations.
Ultra-Deepwater Floater Construction. 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, customer-requested equipment, capital spares, commissioning, project management and
shipyard supervision. The contracted price to Hyundai Heavy Industries Co., Ltd., or Hyundai, totaling $628.5 million is
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 the first quarter of 2016.
Drillship Construction. At December 31, 2014, we had one remaining ultra-deepwater drillship, the Ocean BlackLion,
under construction by Hyundai for an estimated cost of $655 million, including shipyard costs, commissioning, capital
spares and project management costs. The contracted price of the drillship is payable to Hyundai in two installments,
with final payment due on delivery of the drillship. We have paid the first installment of $169.3 million. We expect the
Ocean BlackLion to be delivered in the first quarter of 2015, at which time approximately $395 million will be payable to
Hyundai.
At December 31, 2014 and 2013, 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 $10.6 million, $13.5 million and $10.8
million for the years ended December 31, 2014, 2013 and 2012, respectively. Future minimum rental payments under
leases are approximately $1.3 million and $1.1 million for the years 2015 and 2016, respectively, and $1.2 million in the
aggregate for the years 2017 to 2018. 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, 2014 in the amount of $99.6 million under
certain performance, bid, supersedeas and custom bonds and letters of credit. Agreements relating to approximately
$92.0 million of performance, security, supersedeas and customs bonds can require collateral at any time. As of
December 31, 2014, 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.
1 3 . R e l a t e d - P a r t y T r a n s a c t i o n s
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 $1.1 million, $1.0 million and $0.8 million by Loews for these support functions during the years ended
December 31, 2014, 2013 and 2012, 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 $0.8 million, $0.1 million and $0.1 million for the hire of such vessels
and such services during the years ended December 31, 2014, 2013 and 2012, respectively.
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 years
ended December 31, 2013 and 2012, we made payments to E&Y of $1.6 million and $1.0 million, respectively.
1 4 . In c o m e Ta x e s
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 indirectly by Diamond Offshore International Limited, or DOIL, a foreign subsidiary which we wholly own. It is
our intention to indefinitely reinvest future earnings of DOIL and its foreign subsidiaries to finance foreign activities.
Accordingly, we have not made a provision for U.S. income taxes on approximately $2.4 billion of undistributed foreign
earnings and profits. Although we do not intend to repatriate the earnings of DOIL, 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,
2014
2013
2012
(In thousands)
Federal — current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 66,843
$ 40,045
$173,061
State — current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(121)
69
267
Foreign — current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
59,926
151,339
75,748
Total current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
126,648
191,453
249,076
Federal — deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(6,699)
46,767
(51,852)
Foreign — deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,231
(12,666)
380
Total deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,532
34,101
(51,472)
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$128,180
$225,554
$197,604
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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:
Year Ended December 31,
2014
2013
2012
(In thousands)
Income before income tax expense:
U.S. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$288,080
$ 537,635
$ 512,733
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
227,111
236,605
405,348
Worldwide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$515,191
$ 774,240
$ 918,081
Expected income tax expense at federal statutory rate . . . . . . . . . . . . . . . . .
$180,317
$ 270,984
$ 321,328
Foreign earnings of foreign subsidiaries (not taxed at the statutory
federal income tax rate) net of related foreign taxes . . . . . . . . . . . . . . . . .
(46,163)
(102,359)
(166,251)
Foreign earnings of foreign subsidiaries for which U.S. federal income
taxes have been provided . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,190
805
28,252
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 . . . . . . . . . . . . . . . . . . . . . .
38,358
(39,843)
(16,492)
—
45,428
(46,524)
(18,391)
(27,509)
Uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(47,964)
66,085
35,722
(45,824)
(11,764)
—
6,325
Amortization of deferred charges associated with intercompany rig sales
to other tax jurisdictions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
44,301
30,894
31,276
Net expense (benefit) in connection with resolutions of tax issues and
adjustments relating to prior years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,775
701
4,804
1,337
(2,152)
692
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$128,180
$ 225,554
$ 197,604
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Deferred Income Taxes. Significant components of our deferred income tax assets and liabilities are as follows:
December 31,
2014
2013
(In thousands)
Deferred tax assets:
Net operating loss carryforwards, or NOLs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 20,277
$ 12,038
Foreign tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Worker’s compensation and other current accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bareboat charter deductions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disputed receivables reserved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign contribution taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonqualified stock options and SARs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred deductions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest -Uncertain Tax Positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17,962
19,155
21,898
2,438
14,409
5,345
—
10,316
12,196
1,011
2,555
Total deferred tax assets (1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
127,562
Valuation allowance for NOLs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(20,277)
Valuation allowance for foreign tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(516)
Valuation allowance for other deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(27,243)
—
17,269
—
3,516
14,020
5,749
1,673
9,584
8,577
1,008
1,714
75,148
(7,321)
—
—
Net deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
79,526
67,827
Deferred tax liabilities:
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(577,103)
(578,742)
Mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unbilled revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Undistributed earnings of foreign subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(10,655)
(6,518)
(24)
(8)
—
(4,371)
(24)
(9)
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(594,308)
(583,146)
Net deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(514,782)
$(515,319)
(1) $15.6 million and $10.2 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance
Sheets at December 31, 2014 and 2013, respectively. See Note 3.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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,
2014
2013
2012
(In thousands)
Valuation allowance as of January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 7,321
$ 22,876
$26,353
Establishment of valuation allowances:
Net operating losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15,677
Foreign tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
516
Other deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
27,243
25
—
—
946
—
—
Releases of valuation allowances in various jurisdictions . . . . . . . . . . . . . . . . . .
(2,721)
(15,580)
(4,423)
Valuation allowance as of December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$48,036
$ 7,321
$22,876
Net Operating Loss Carryforwards — As of December 31, 2014, we had recorded a deferred tax asset of $20.3 million
for the benefit of NOL carryforwards related to our international operations. Approximately $18.5 million of this deferred
tax asset relates to NOL carryforwards that have an indefinite life. The remaining $1.8 million relates to NOL
carryforwards of our Mexican and Hungarian entities. Unless utilized, the tax benefits of these NOL carryforwards will
expire between 2021 and 2025 as follows:
Year Expiring
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax Benefit of
NOL
Carryforwards
(In millions)
$0.2
0.2
0.8
0.6
$1.8
As of December 31, 2014, a valuation allowance for $20.3 million has been recorded for our NOLs as none of the
deferred tax asset is more likely than not to be realized.
Foreign Tax Credits. As of December 31, 2014, we had recorded a deferred tax asset of $17.5 million for the benefit of
foreign tax credits in the U.S. and a $0.5 million deferred tax asset for the benefit of foreign tax credits in the United
Kingdom, or U.K. Our excess foreign tax credits in the U.S. will be carried back to 2013 but otherwise will expire in 2024.
Our U.K. foreign tax credits, for which we recorded a valuation allowance, may be carried forward indefinitely.
Other Deferred Tax Assets. As of December 31, 2014, we had recorded a deferred tax asset of $21.9 million for the
benefit of disallowed bareboat charter deductions in the U.K. for which we recorded a valuation allowance and a deferred
tax asset of $5.3 million for foreign contribution taxes in Brazil for which we also recorded a valuation reserve.
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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, and is as follows:
For the Year Ended December 31,
2014
2013
2012
(In thousands)
Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(90,921)
$(67,150)
$(62,936)
Additions for current year tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(5,813)
(1,724)
Additions for prior year tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(292)
(31,264)
Reductions for prior year tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reductions related to statute of limitation expirations . . . . . . . . . . . . . . . . .
34,630
5,280
7,280
1,937
(3,837)
(5,136)
4,759
—
Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(57,116)
$(90,921)
$(67,150)
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. At December 31, 2013, $6.3 million and $82.6 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, 2014, 2013 and 2012, all $50.5 million, $76.3 million and $48.4 million, respectively, would
affect the effective tax rates if recognized.
The following table presents the amount of accrued interest and penalties at December 31, 2014 and 2013 related to
uncertain tax positions:
December 31,
2014
2013
(In thousands)
Uncertain tax positions net, excluding interest and penalties . . . . . . . . . . . . . . . . . . . . . . .
$(50,513)
$ (76,303)
Accrued interest on uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(7,503)
Accrued penalties on uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(37,622)
(12,786)
(59,797)
Uncertain tax positions net, including interest and penalties . . . . . . . . . . . . . . . . . . . . . . .
$(95,638)
$(148,886)
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, 2014 related to uncertain tax positions are as follows:
For the Year Ended December 31,
2014
2013
2012
(In thousands)
Net increase (decrease) in interest expense related to unrecognized
tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (5,283)
$ 5,758
$(1,902)
Net increase (decrease) in penalties related to unrecognized tax positions . . . .
(22,175)
38,136
(787)
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. 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 2009 tax year to expire in 2015 for one of our Mexican entities, and we
anticipate that the related unrecognized tax benefit will decrease by $10.7 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 2008 to
2014. 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.
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.
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 R$35.1 million (approximately equal to USD $13 million at December 31, 2014) 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 tax auditors have issued an assessment for tax year 2000 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. During the
second quarter of 2014, the Appeals Committee in Egypt issued a decision regarding this open item, with which we
disagree. We have filed an objection with the Egyptian courts and continue to dispute the matter. We have also 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 $50 million related to this issue for the 2006 through 2008 tax years as
of December 31, 2014.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Mexico Tax Jurisdiction. 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. However, the 2008 income
tax return of one of our other Mexican subsidiaries is under audit by the Mexican tax authorities.
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 at the end of June 2013, 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.
In addition, in August 2012, the Mexican tax authorities dismissed a claim against one of our Mexican subsidiaries
and the 2004 tax year for that subsidiary is now closed. Consequently, during the third quarter of 2012, we reversed our
$4.4 million accrual for this uncertain tax position, which included $0.2 million of penalty and $2.6 million of interest.
United Kingdom Tax Jurisdiction. The U.K. Finance Act of 2014, or the Finance Act, was enacted in July 2014 with an
effective date retroactive to April 1, 2014. Certain provisions of the Finance Act will limit the amount of tax deductions
available with respect to our rigs working in the U.K. under bareboat charter arrangements, which has caused our
expected tax expense for the full year of 2014 to increase by approximately $22 million.
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.
15. E mp l oy ee B e nefi t 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 Internal Revenue
Code of 1986, as amended, or 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, 2014, 2013 and 2012, we made a 4% profit-share contribution of participants’ defined
compensation and matched up to 6% of each employee’s compensation contributed to the 401k Plan. 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 the profit sharing contribution. For the years ended December 31, 2014, 2013 and 2012, our provision for
contributions was $34.1 million, $29.6 million and $25.9 million, respectively.
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AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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, 2014, 2013 and 2012, 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. For
each of the years ended December 31, 2014, 2013 and 2012, our contribution for U.K. nationals working in the Norwegian
sector of the North Sea was up to a maximum of 15%, of the employee’s defined compensation. Our provision for
contributions was $5.0 million, $3.5 million and $2.7 million for the years ended December 31, 2014, 2013 and 2012,
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, 2014, 2013 and 2012, we contributed 4% of participants’ defined
compensation and matched up to 6% of each employee’s compensation contributed to the International Savings Plan.
Our provision for contributions was $3.7 million, $3.1 million and $2.8 million for the years ended December 31, 2014,
2013 and 2012, 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, 2014, 2013 and 2012 was approximately $265,000, $261,000 and
$256,000, respectively.
16. S egments a nd 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,
2014
2013
2012
(In thousands)
Floaters:
Ultra-Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 987,565
$ 854,515
$ 902,793
Deepwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
494,247
617,080
597,694
Mid-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,076,842
1,197,934
1,275,068
Total Floaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,558,654
2,669,529
2,775,555
Jack-ups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
178,472
174,055
160,511
Total contract drilling revenues . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,737,126
2,843,584
2,936,066
Revenues related to reimbursable expenses . . . . . . . . . . . . . . . . . . . . . .
77,545
76,837
50,442
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,814,671
$2,920,421
$2,986,508
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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, 2014, our actively-marketed drilling rigs were en route to or located
offshore eight 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.
Year Ended December 31,
2014
2013
2012
(In thousands)
United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 418,095
$ 330,471
$ 173,961
International:
South America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,088,796
1,219,287
1,427,927
Europe/Africa/Mediterranean . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Australia/Asia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
558,367
503,814
245,599
731,888
438,814
199,961
662,995
524,957
196,668
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,814,671
$2,920,421
$2,986,508
2,396,576
2,589,950
2,812,547
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, 2014, 2013 and 2012, individual
countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.
Brazil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31.0% 38.3% 46.1%
United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.7%
Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Malaysia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8.7%
6.4%
5.5%
7.9%
6.9%
3.2%
2.9%
6.9%
6.6%
6.7%
4.0%
Year Ended December 31,
2014
2013
2012
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table presents our long-lived tangible assets by geographic location as of December 31, 2014, 2013 and
2012. 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.
December 31,
2014
2013
2012
(In thousands)
Drilling and other property and equipment, net:
United States (1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,637,621
$ 611,731
$ 444,984
International: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Australia/Asia/Middle East (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,460,841
2,078,348
1,474,999
South America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,445,832
1,690,976
1,827,247
Europe/Africa/Mediterranean . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,128,857
Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
272,802
793,097
293,075
799,194
318,548
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$6,945,953
$5,467,227
$4,864,972
4,308,332
4,855,496
4,419,988
(1) Long-lived tangible assets in the United States region as of December 31, 2014 include $1.9 billion related to three
drillships that were delivered in 2014, two of which are in transit thereto. Long-lived tangible assets in the United
States region as of December 31, 2013 and 2012 include $339.1 million and $167.4 million, respectively, in
construction work-in-progress for the Ocean Onyx, which was under construction in Brownsville, Texas.
(2) Long-lived tangible assets in the Australia/Asia/Middle East region include $439.2 million, $1,064.5 million and
$741.1 million in construction work-in-progress for rigs under construction in South Korea as of December 31, 2014,
2013 and 2012, respectively, and $400.8 million and $264.6 million for the recently completed Ocean Apex as of
December 31, 2014 and 2013, respectively.
The following table presents the countries in which material concentrations of our long-lived tangible assets were
located as of December 31, 2014, 2013 and 2012:
United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Brazil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Spain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vietnam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Malaysia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
South Korea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Angola . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Republic of Congo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Singapore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31,
2014
2013
2012
38.0%
20.3%
8.1%
6.9%
6.6%
6.3%
3.9%
—
—
—
—
11.2%
30.2%
1.2%
0.6%
4.3%
19.5%
5.4%
6.3%
5.2%
—
8.2%
9.1%
37.3%
—
1.4%
3.1%
15.2%
6.5%
—
6.8%
7.4%
1.8%
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AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
As of December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012 that contributed more than
10% of our total revenues are as follows:
Customer
Year Ended December 31,
2014
2013
2012
Petróleo Brasileiro S.A.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31.9% 33.6% 33.3%
OGX Petróleo e Gás Ltda.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
2.4% 12.5%
1 7 . U n a u d i t e d Q u a r t e r l y F i n a n c i a l D a t a
Unaudited summarized financial data by quarter for the years ended December 31, 2014 and 2013 is shown below.
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(In thousands, except per share data)
2014
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$709,424
$692,244
$737,682
$675,321
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income tax expense . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
186,277
167,679
145,810
133,766
112,603
89,713
90,416
81,639
52,645
162,103
153,270
98,843
Net income per share, basic and diluted . . . . . . . . . . . . . . . . . . .
$
1.05
$
0.65
$
0.38
$
0.72
2013
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$729,741
$758,018
$706,165
$726,497
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income tax expense . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
213,726
206,179
175,989
262,859
256,301
185,334
137,352
131,565
94,748
187,669
180,195
92,615
Net income per share, basic and diluted . . . . . . . . . . . . . . . . . . .
$
1.27
$
1.33
$
0.68
$
0.67
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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, 2014. Based on their participation in that evaluation, our CEO and CFO concluded that
our disclosure controls and procedures were effective as of December 31, 2014.
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, 2014.
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, 2014, 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 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 2014 that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
Item 9B. Other Information.
Not applicable.
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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 2015 Annual Meeting of Stockholders, which is incorporated herein by reference.
PART III
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
60
62
63
64
65
66
67
(2) Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
110
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.
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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 23, 2015.
SIGNATURES
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
President, Chief Executive Officer and
February 23, 2015
Marc Edwards
Director
(Principal Executive Officer)
/s/ GARY T. KRENEK
Senior Vice President and Chief Financial
February 23, 2015
Gary T. Krenek
Officer
(Principal Financial Officer)
/s/ BETH G. GORDON
Controller (Principal Accounting Officer)
February 23, 2015
Beth G. Gordon
/s/
JAMES S. TISCH
James S. Tisch
/s/
JOHN R. BOLTON
John R. Bolton
Chairman of the Board
February 23, 2015
Director
February 23, 2015
/s/ CHARLES L. FABRIKANT
Director
February 23, 2015
Charles L. Fabrikant
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Signature
Title
Date
/s/ PAUL G. GAFFNEY II
Paul G. Gaffney II
/s/ EDWARD GREBOW
Edward Grebow
Director
February 23, 2015
Director
February 23, 2015
/s/ HERBERT C. HOFMANN
Director
February 23, 2015
Herbert C. Hofmann
/s/ KENNETH I. SIEGEL
Kenneth I. Siegel
/s/ CLIFFORD M. SOBEL
Clifford M. Sobel
/s/ ANDREW H. TISCH
Andrew H. Tisch
Director
February 23, 2015
Director
February 23, 2015
Director
February 23, 2015
/s/ RAYMOND S. TROUBH
Director
February 23, 2015
Raymond S. Troubh
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Exhibit No.
EXHIBIT INDEX
Description
3.1
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).
3.2
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).
4.1
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).
4.2
Fifth Supplemental Indenture, dated as of June 14, 2005, 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
JPMorgan Chase Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.2 to our
Current Report on Form 8-K filed June 16, 2005) (SEC File No. 1-13926).
4.3
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).
4.4
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).
4.5
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).
10.1
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).
10.2
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).
10.3
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).
10.4+
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).
10.5+
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).
10.6+
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).
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Exhibit No.
Description
10.7+
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).
10.8+
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).
10.9+
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).
10.10+
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).
10.11+
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).
10.12+
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).
10.13+
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).
10.14+
Employment Agreement between Diamond Offshore Management Company and John M. Vecchio dated as
of December 15, 2006 (incorporated by reference to Exhibit 10.15 to our Annual Report on Form 10-K for the
fiscal year ended December 31, 2006) (SEC File No. 1-13926).
10.15+
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).
10.16+
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).
10.17
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).
10.18
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).
10.19
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 period ended March 31, 2014).
Exhibit No.
Description
10.20
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).
10.21+
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).
10.22+
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).
10.23+
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
5
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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 of the Exchange Act, and otherwise, not subject to
liability under these sections.
+ Management contracts or compensatory plans or arrangements.
[This page intentionally left blank]
Our Fleet (as of February 9, 2015)
DRILLSHIPS
Ultra-deepwater Rigs (7,500+ Ft.)
¬
¬
¬
¬
Ocean
BlackLion
12,000 Ft.
DP; 7R; 15K; 5M
South Korea
Ocean
BlackRhino
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
BlackHornet
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
BlackHawk
12,000 Ft.
DP; 7R; 15K; 5M
GOM
Ocean
Clipper
7,875 Ft.
DP; 15K; 5R
Brazil
Under
Construction
SEMISUBMERSIBLE RIGS
Ultra-deepwater Rigs (7,500+ Ft.)
JACK-UP RIGS
SEMISUBMERSIBLE RIGS
DRILLSHIPS
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Ocean
GreatWhite
10,000 Ft.
DP; 6R; 15K; 4M
South Korea
Ocean
Valor
10,000 Ft.
DP; 6R; 15K; 4M
Brazil
Ocean
Courage
10,000 Ft.
DP; 6R; 15K; 4M
Brazil
Ocean
Confidence
10,000 Ft.
DP; 6R; 15K; 4M
Canary Islands
Ocean
Monarch
10,000 Ft.
VC; 5R; 15K; 4M
Malaysia
Ocean
Endeavor
10,000 Ft.
VC; 5R; 15K; 4M
Black Sea
Ocean
Rover
8,000 Ft.
VC; 5R; 15K; 4M
Malaysia
Ocean
Baroness
8,000 Ft.
VC; 4R; 15K; 4M
Brazil
MID-WATER RIGS
(400 – 5,000 Ft.)
Under
Construction
Deepwater Rigs (5,000 – 7,500 Ft.)
l
Ocean
Apex
6,000 Ft.
VC; 5R; 15K; 4M
Vietnam
l
Ocean
Onyx
6,000 Ft.
VC; 15K; 4M
GOM
l
Ocean
Victory
5,5 00 Ft.
VC; 15K
GOM
l
Ocean
America
5,500 Ft.
SP; 15K
Australia
Mid-water Rigs (400 – 5,000 Ft.)
J
Ocean
Worker
4,000 Ft.
GOM
(Cold stacked)
J
Ocean
Saratoga
2,200 Ft.
GOM
(Cold stacked)
J
Ocean
Quest
4,000 Ft.
15K
Vietnam
J
Ocean
Guardian
1,500 Ft.
15K
UK
J
Ocean
Patriot
3,000 Ft.
15K
UK
J
Ocean
Princess
1,500 Ft.
15K
UK
J
Ocean
General
3,000 Ft.
Malaysia
(Cold stacked)
J
Ocean
Vanguard
1,500 Ft.
15K
UK
(Cold stacked)
Actively
Marketing
l
Ocean
Valiant
5,500 Ft.
SP; 15K
UK
J
Ocean
Yorktown
2,850 Ft.
Mexico
J
Ocean
Nomad
1,200 Ft.
UK
l
Ocean
Star
5,500 Ft.
VC; 15K
GOM
l
Ocean
Alliance
5,250 Ft.
DP; 15K
Brazil
J
Ocean
Lexington
2,200 Ft.
Trinidad and
Tobago
J
Ocean
Ambassador
1,100 Ft.
Mexico
JACK-UP RIGS
K
Ocean
Scepter
350 Ft.
IC; 15K; 3M
Mexico
Key
K
K
Ocean
Titan
350 Ft.
IC; 3M
GOM
(Cold stacked)
Ocean
King
300 Ft.
IC; 3M
GOM
(Cold stacked)
K
Ocean
Nugget
300 Ft.
IC
Mexico
K
Ocean
Summit
300 Ft.
IC
Mexico
K
Ocean
Spur
300 Ft.
IC
Ecuador
IC Independent-Leg Cantilevered Rig
Ì DP Dynamically Positioned
Ì
Ì GOM U.S. Gulf of Mexico
Ì VC Victory Class
Ì SP Self Propelled
7R Seven Ram Blowout Preventer
Ì 6R Six Ram Blowout Preventer
Ì
Ì 4M Four Mud Pumps
Ì 5M Five Mud Pumps
Ì
15K 15,000 PSI Well Control System
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.
BOARD OF DIRECTORS
Gary T. Krenek
James S. Tisch
Chairman of the Board,
Diamond Offshore Drilling, Inc.
President & Chief Executive Officer,
Loews Corporation
Marc Edwards
President & Chief Executive Officer,
Diamond Offshore Drilling, Inc.
John R. Bolton
Senior Fellow,
American Enterprise Institute
Charles L. Fabrikant
Executive Chairman,
SEACOR Holdings, Inc.
Paul G. Gaffney II
President Emeritus,
Monmouth University
Edward Grebow
Managing Director,
Morgan Joseph TriArtisan LLC
Herbert C. Hofmann
Retired Senior Vice President,
Loews Corporation
Kenneth I. Siegel
Senior Vice President,
Loews Corporation
Clifford M. Sobel
Managing Partner,
Valor Capital Group LLC
Andrew H. Tisch
Co-Chairman of the Board,
Loews Corporation
Raymond S. Troubh
Financial Consultant
EXECUTIVE OFFICERS
Marc Edwards
President & Chief Executive Officer
John M. Vecchio
Executive Vice President
Lyndol L. Dew
Senior Vice President,
Worldwide Operations
Senior Vice President &
Chief Financial Officer
Ronald Woll
Senior Vice President &
Chief Commercial Officer
David L. Roland
Senior Vice President,
Steven A. Nelson
Vice President,
Operations
Jon L. Richards
Vice President,
Operations
Terence W. Waldorf
Vice President, Deputy General Counsel
General Counsel & Secretary
& Assistant Secretary
Beth G. Gordon
Controller
Scott L. Kornblau
Treasurer
SENIOR MANAGEMENT
CORPORATE INFORMATION
Mark F. Baudoin
Senior Vice President,
Administration
Stephen G. Elwood
Senior Vice President,
Tax
Karl S. Sellers
Senior Vice President,
Technical Services
Duane Beair
Vice President,
Purchasing & Materials Control
Aaron Sobel
Vice President,
Human Resources
Neil Hall
Vice President,
Health, Safety & Environment
Tri Le
Vice President,
Subsea
Kane Liddelow
Vice President,
Contracts & Marketing
Richard L. Male
Vice President,
Contracts & Marketing
Diamond Offshore Drilling (UK) Limited
Jimmy R. Moore
Vice President,
Operations
Corporate Headquarters
15415 Katy Freeway
Houston, TX 77094
(281) 492-5300
www.diamondoffshore.com
Investor Relations
Darren Daugherty
Director, Investor Relations
15415 Katy Freeway
Houston, TX 77094
(281) 492-5370
Notice of Annual Meeting
The Annual Meeting of Stockholders will
be held on Tuesday, May 19, 2015, at
8:30 am at the offices of Loews Corporation,
667 Madison Avenue, New York, NY 10065.
Transfer Agent & Registrar
Computershare
PO Box 30170
College Station, TX 77842
(877) 812-4207
www.computershare.com/investor
Stock Exchange Listing
New York Stock Exchange
Trading Symbol “DO”
Independent Auditors
Deloitte & Touche LLP
Design / Rigsby Hull, Houston
Printing / RR Donnelley
Photography / Drew Donovan
72811rrdD1R1.indd 2
3/24/15 5:05 PM
2014
ANNUAL
REPORT
FINANCIAL HIGHLIGHTS ( doll ars in millions )
Revenue
$ 2,815
$
2,920
$
2,987
2014
2013
2012
DIAMOND OFFSHORE DRILLING, INC.
Depreciation & Amortization
Operating Expenses
456
2,242
Earnings Before Interest, Taxes, Depreciation & Amortization ( EBITDA )
1,139
Net Income
387
Capital Expenditures
2,033
388
2,119
1,190
549
958
Cash and Investments
$
250
$
2,097
$
Drilling & Other Property & Equipment, Net
Total Assets
Long - term Debt
Shareholders’ Equity
6,946
8,021
2,244
4,451
5,467
8,391
2,494
4,637
393
2,024
1,418
720
702
1,486
4,865
7,235
1,496
4,576
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 38 offshore drilling rigs, including two rigs under
construction. Diamond Offshore's fleet consists of 27 semisubmersibles, one of which is under
construction, five dynamically positioned drillships, one of which is under construction, and six 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 5,200 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 BlackHawk is shown working in the U.S. Gulf of Mexico.
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