UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of report (date of earliest event reported): September 2, 2014

 

 

PARAGON OFFSHORE plc

(Exact name of Registrant as specified in its charter)

 

England and Wales   001-36465   98-1146017

(State or other jurisdiction of

incorporation or organization)

 

(Commission

file number)

 

(I.R.S. employer

identification number)

 

3151 Briarpark Drive, Suite 700

Houston, Texas

  77042
(Address of principal executive offices)   (Zip code)

Registrant’s telephone number, including area code: +44 20 330 2300

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 


Item 7.01 Regulation FD Disclosure

Investor Presentation

On September 3, 2014, Randall D. Stilley, President, Chief Executive Officer and Director of Paragon Offshore plc (“Paragon”), will deliver a presentation at the Barclays Capital CEO Energy-Power Conference in New York City, New York, beginning at 3:45 p.m. U.S. Eastern Daylight Time. A live webcast and presentation slides will be available at the time of the presentation on Paragon’s website at www.paragonoffshore.com, under “Events & Presentations” in the “Investor Relations” section of the website. The presentation slides are also included as Exhibit 99.1 to this Current Report on Form 8-K and are incorporated herein by reference.

The information presented in Item 7.01 to this Current Report on Form 8-K is being furnished in accordance with Rule 101(e)(1) under Regulation FD and shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated by reference.

2014 Guidance

Paragon is also providing the following guidance for each of the three month periods ended September 30, 2014 and December 31, 2014:

 

    

Three Months Ended
September 30, 2014

(USD in millions)

  

Three Months Ended
December 31, 2014

(USD in millions)

Operating Expense

   $225 - $235    $228 - $238

Depreciation

   $100 - $105    $100 - $105

SG&A

   $15 - $18    $15 - $17

Interest Expense

   $23 - $26    $24 - $27

Effective Tax Rate

   48% - 52%    40% - 44%

Capital Expenditures

   $100 - $110    $100 - $110

Paragon’s effective tax rate will be higher subsequent to its spin-off from Noble Corporation plc primarily for the following reasons. First, certain aspects of Paragon’s business were restructured in order to carve-out Paragon’s business and effect the spin-off. This restructuring resulted in significant tax inefficiencies for Paragon’s business and operations, including the inability for Paragon to deduct interest expense with respect to borrowings under Paragon’s debt obligations and ownership of certain of Paragon’s assets in structures subject to higher tax rates than prior to the restructuring. In addition, in July 2014, legislation was enacted in the U.K. that will restrict deductions on certain related party transactions, such as those relating to the bareboat charter agreements used in connection with Paragon’s U.K. continental shelf operations.

Forward Looking Statements

The statements described in this Current Report on Form 8-K that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements which could be made include, but are not limited to, Paragon’s tax rate, cost guidance, the effects of Paragon’s spin-off from Noble Corporation plc, the impact of U.K. tax legislation, and Paragon’s future operational or financial results. Factors impacting these forward-looking statements include but are not limited to the ability to consummate any future restructurings, operating hazards and delays, risks associated with operations outside the U.S., actions by regulatory authorities, customers, joint venture partners, contractors, lenders and other third parties, legislation and regulations affecting offshore drilling operations, costs and difficulties relating to the establishment of Paragon as a stand-alone business, factors affecting the level of activity in the oil and gas industry, supply and demand of drilling rigs, factors affecting the duration of contracts, the actual amount of downtime, factors that reduce applicable dayrates, violations of anti-corruption laws, hurricanes and other weather conditions and the future price of oil and gas and other factors,


including those discussed in the “Risk Factors” section of Paragon’s registration statement on Form 10 as filed with the Securities and Exchange Commission (the “SEC”) on July 14, 2014 and in Paragon’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014, and in Paragon’s other filings with the SEC, which are available free of charge on the SEC’s website at www.sec.gov. Should one or more of these risks or uncertainties materialize (or the other consequences of such a development worsen), or should underlying assumptions prove incorrect, actual results may vary materially from those indicated or expressed or implied by such forward-looking statements including, without limitation, Paragon’s guidance on future costs and expenses. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and Paragon undertakes no obligation to publicly update or revise any forward-looking statements.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

 

EXHIBIT
NUMBER

       

DESCRIPTION

99.1       Slide presentation of Paragon to be used at the Barclays CEO Energy-Power Conference on September 3, 2014.


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

    Paragon Offshore plc, a public limited company incorporated under the laws of England and Wales

 

Date: September 2, 2014

 

    By:   /s/ Steven A. Manz
    Name:   Steven A. Manz
    Title:   Senior Vice President and Chief Financial Officer

 


INDEX TO EXHIBITS

 

EXHIBIT
NUMBER

       

DESCRIPTION

99.1       Slide presentation of Paragon to be used at the Barclays CEO Energy-Power Conference on September 3, 2014.


Barclays CEO Energy-Power Conference
www.paragonoffshore.com
September 2-4, 2014
New York City
Exhibit 99.1


Disclosure
www.paragonoffshore.com
2
This
material
contains
statements
that
are
“forward-looking
statements”
about
Paragon’s business and financial performance. These statements can be
identified by the fact that they do relate strictly to current or historical facts.
Each future projection is a forward-looking statement that involves certain
risks, uncertainties and assumptions. These include but are not limited to
operational risks, actions by regulatory authorities or other third parties, costs
and difficulties related to the separation, market conditions, financial results
and performance, ability to repay debt and timing thereof, actions by customers
and
other
third
parties,
factors
affecting
the
level
of
activity
in
the
oil
and
gas
industry, supply and demand of drilling rigs, factors affecting the duration of
contracts, the actual amount of downtime, factors that reduce applicable
dayrates,
violations
of
anticorruption
laws,
the
future
price
of
oil
and
gas
and
other factors including those detailed in Paragon’s filings with the Securities
and Exchange Commission. Should one or more of these risks or uncertainties
materialize, or should underlying assumptions prove incorrect, actual results
may vary materially from those indicated. Paragon disclaims any duty to
update the information presented here.


Agenda
Introducing Paragon Offshore
Challenges and Paragon’s
Strategy
2014 Guidance
Conclusion
www.paragonoffshore.com
3
Paragon C461


Overview of Paragon Offshore
www.paragonoffshore.com
4
Business Overview
Worldwide Offshore Presence
Offshore contract drilling services provider
operating standard specification rigs
Spin-off from Noble Corporation completed 1
August 2014
Headquartered in Houston, TX and
incorporated in the United Kingdom
NYSE:  PGN
6/30/2014 Estimated EBITDA* by Region
Operating* Fleet Composition
Jackups:
33
Drillships:
4
Semisubmersibles:
2
Total:
39
*
See
Appendix
for
reconciliation
to
EBITDA.
Map
and
Operating
Fleet
do
not
include
“cold”
stacked
rigs,
which
includes
two
floaters,
one
jackup,
and
one FPSO.
North Sea
33%
Mexico
19%
Middle
East
16%
Brazil
18%
West Africa
8%
India / Asia
6%
North Sea
Canada
Mexico
West Africa
Brazil
Middle East
India/Asia
Hibernia
Platform
Operations
Semis: 1
Jackups: 7
Jackups: 11
Jackups: 4
Jackups: 9
Drillships: 3
Semis: 1
Drillships: 1
Jackups: 2


Paragon’s Strategy
Deliver reliable, safe, cost-efficient
operations
Match our assets to customers in fit-
for-purpose applications while
maintaining industry-leading
utilization
Manage our costs to preserve
flexibility in changing dayrate
environments
Practice disciplined capital allocation
in terms of fleet maintenance, fleet
growth and returns to shareholders
www.paragonoffshore.com
5
Confidential
Paragon DPDS2


Significant Contract Backlog with Global
Customers
www.paragonoffshore.com
6
Backlog by Customer
as of 6/30/2014
~2/3  of Backlog with NOCs
Source: Company
$ 561
$ 508
$ 99
$ 2
$292
$443
$255
$111
$ 0
$ 250
$ 500
$ 750
2014E Remaining
2015E
2016E
2017E
$ in millions
Jackups: 52%
Floaters:  48%
$2.3 Bn of Backlog
As of 6/30/2014
Petrobras
42%
Pemex
14%
Total
7%
ADMA-
OPCO
5%
Nexen
4%
Other
28%


Strong History of Utilization
Speaks to Quality of Operations & Assets
www.paragonoffshore.com
7
Source:  IHS Petrodata 08.21.14
Marketed fleet utilization for non-US rigs 15 years old and older since
January 1, 2011
Percentage
Percentage
70
75
80
85
90
95
100
Paragon
Rest of
Industry
Jackup Utilization
70
75
80
85
90
95
100
Paragon
Rest of
Industry
Floater Utilization


Industry-Leading Safety and Quality Performance
Customers recognize our commitment to
safety and performance
~50% lower TRIR
1
than International
Association of Drilling Contractors (IADC)
in 2013
2
Continued improvement and
outperformance as compared to IADC
Promotes strong relationships with key
stakeholders such as employees,
customers, and the local communities in
which we operate
We believe that our excellent safety
record contributes to lower downtime and
lower costs
www.paragonoffshore.com
8
Commitment to Safety and Quality
Strong Safety Record
FY2012
1. TRIR
defined
as
the
number
of
recordable
injuries
and
illnesses
incurred
in
the
period
multiplied
by
200,000
and
then
divided
by
the
total
number
of
employee
hours
worked.
A
lower
TRIR
is
better.
2. Includes both offshore and onshore contract drillers
FY2013
1
st
Half
2014
0.61
0.81
0.74
0.50
0.41
0.49
0.00
0.25
0.50
0.75
1.00
IADC
Paragon


Key Challenges
Jackup market capacity additions
and potential impact on the
market
Some customers focusing on
more challenging wells (e.g.,
wells requiring higher
specification rigs)
Petrobras rollover of current
floater contracts
Capital structure and future
capital allocation strategy
www.paragonoffshore.com
9
Paragon DPDS3


Newbuild Jackup Orders According to IHS
22 August 2014
Source:  IHS Petrodata 08.21.14
www.paragonoffshore.com
10
*
Preferred designs for
established drilling contractors
138
16
27
95
54
29
12
0
40
80
120
160
Total Newbuilds
Contracted Rigs
Rigs on Order-
No Contract
Rigs Under
Construction-No
Contract
China
Singapore
Other (USA,
UAE, India,
Indonesia, Qatar)
138 Anticipated Jackup Deliveries
27
21
20
18
11
8
7
5
23
Rig by Design
0
10
20
30
40
50
60
70
80
2014
2015
2016
2017
Forecasted Deliveries by Year
Other
UAE
Singapore
China
Contracted
19
64
46
9
16
70
38
5
9
JU2000E*
Gusto CJ-46
Keppel B Class
LeT Super 116E
PPL Pacific 400
Keppel Super B*
Gusto CJ-50*
Gusto CJ-70*
Other


Considerations for the Jackup Markets
Large jackup orderbook may be cause for concern, but more nuanced analysis of the market is
required. Consider:
www.paragonoffshore.com
11
Will all newbuilds actually be
delivered?  If so, will they be on time?
Are some designs targeted at non-
competitive markets (China, Iran, etc.)
or less interesting for potential buyers?
Will there be quality issues with some
yards?
How will speculators market, crew and
operate these rigs?
What break-even cash (operating +
financing costs) dayrate is required?
Do
all
customers
need
newbuild
jackups
to
execute
their
programs?
What true efficiencies do newbuilds offer customers?
What is the price elasticity of different customers?
Will Paragon’s customers maintain spending and activity
levels?
Are all standard assets of the same quality?
At what pace will we see retirements/stacking?
Whose assets are likely to be stacked/retired first?
Newbuilds
Customer Behavior
Standard Fleet


Paragon’s Contract Coverage
4 August 2014 Fleet Status
www.paragonoffshore.com
12
Rig Name
Region
DPDS3 (NRE)
Brazil
DPDS2 (NLS)
Brazil
M1162 (NRR)
Arabian Gulf
B301 (NJH)
Mexico
B391 (NJR)
North Sea
L1113 (NJS)
Mexico
M842 (NEP)
Mexico
L1115 (NHD)
Arabian Gulf
M825 (NEN)
West Africa
C20051 (NAW)
North Sea
B152 (NDF)
Arabian Gulf
MDS1 (NDU)
India
MSS2 (NTM)
Brazil
Dhabi II
Arabian Gulf
HZ1 (NGS)
North Sea
DPDS1 (NPH)
Brazil
M824 (NTJ)
Mexico
L785 (NGM)
Malaysia
M531 (NLJ)
Mexico
C461 (NLB)
North Sea
L1112 (NEH)
India
L782 (NPJ)
West Africa
C20052 (NBW)
North Sea
M841 (NBJ)
Mexico
C462 (NPvE)
North Sea
C463 (NRH)
North Sea
MSS1 (NTvL)
North Sea
L784 (NJP)
Arabian Gulf
M826 (NLN)
West Africa
L781 (NRB)
Mexico
L1114  (NSN)
Mexico
L783 (NTC)
West Africa
M823 (NEF)
Mexico
M821 (NCN)
Mexico
L1116 (NGR)
Mexico
L1111 (NGA)
Arabian Gulf
M1161 (NCY)
Arabian Gulf
L786 (NKD)
Arabian Gulf
M822 (NCS)
Arabian Gulf
O
N
D
2017
A
M
J
J
A
S
2016
2015
2014
J
F
M
J
A
S
O
N
D
J
F
M
A
M
J
J
J
A
S
O
N
D
J
A
S
O
N
D
J
F
M
A
M
J
Jackup
Floater
Source:  IHS Petrodata 08.21.14
2015 Committed Days
~33% of jackup
~50% of floater


Mexico Reform Likely to Continue to Provide
Opportunities
Mexican Energy Reform Underway
Round 0:  Pemex received 100%
of 2P and 67% of Prospective
Reserve requests including
current shallow water areas
Round “0.5”
expected:  Tandem
with Round 1, allows Pemex to
partner with foreign firms to
develop areas from Round 0
Round 1:  169 blocks across
deepwater, shallow water, and
onshore to be placed on offer for
a total of 3.9 Bn barrels of 2P
reserves.  Assignment of
contracts planned for May-
September 2015
www.paragonoffshore.com
13
46 jackups currently drilling
22 < 15 years old;   Avg. Dayrate*: $147k
24 > 15 years old;  Avg. Dayrate*:   $ 94k
Paragon is the international contractor
who currently provides the greatest
number of rigs to PEMEX
*
Average dayrates for rigs where dayrate is known
Sources:  IHS Petrodata, PEMEX
PEMEX to retain:
5% (8.9 bn boe)
PEMEX to retain:
59% (9.5 bn boe)
PEMEX to retain:
93% (8 bn boe)
PEMEX to retain:
29% (8.1 bn boe)


Four of Paragon’s floaters operate in the post-
salt Campos Basin where decline rates are
estimated to exceed 10% per year
Capex budget for Petrobras has increased by
~4.6%
Rigs under construction in Brazil likely to be
delayed and over budget (potentially >$ 1 Bn
per unit)
Brazil is one of Paragon’s centers of Subsea
Excellence
Paragon also provides operational and
shorebase support for Noble Corporation’s
floaters in Brazil
Two of Paragon’s floaters come off contract in
2015
www.paragonoffshore.com
14
DPDS3
DPDS2
MSS2
DPDS1
Paragon’s Position in Brazil


www.paragonoffshore.com
15
Capital Structure Overview
30 June 2014 Pro-forma Cash Balance
Revolving Credit Facility, Matures 2019
Undrawn
LIBOR + 2.00%
Secured Term Loan, Matures 2021
LIBOR + 2.75%, 1% Floor
1% annual repayment
6.75% Senior Unsecured Notes due 2022
Non-call for 4 years
7.25% Senior Unsecured Notes due 2024
Non-call for 5 years
In Millions
$1,730
Million
$73
$800
$650
$500
$580


Disciplined Capital Allocation
The Focus for Paragon Offshore
www.paragonoffshore.com
16
Free Cash Flow
Free Cash Flow
Fleet
Maintenance
Fleet Growth
Return to
Shareholders
Debt
Retirement
Disciplined maintenance
of existing fleet
Upgrades where
appropriate or required
by customers
Estimated annual spend:
$180 MM
Maintenance
$120-150 MM
Discretionary
Significant number of
standard specification
rigs potentially available
for acquisition
Interested in rigs that
have backlog and are
well-maintained
Be opportunistic as we
consider access to
newbuilds
$1.73 Bn in debt
Term loan at attractive
rates
Bonds are no-call 4 (8
year) and 5 (10 year)
However, permissible to
acquire bonds in the
open market
Both dividends and
share buybacks possible
Paragon’s board is
considering a dividend
to commence in 4Q with
magnitude yet to be
determined
Focus on maximizing return on
capital employed (ROCE)


Acquisitions:  A Balancing Act
Given our fleet age profile of 35 years (~19 rebuilt), our acquisition strategy must consider both near
and longer term horizons
www.paragonoffshore.com
17
Near Term
Longer Term
Many potential acquisition targets available
Considerations
Good condition
Backlog
Capabilities
Geography
Remaining useful life
Value—target purchase price in the ~3.0x
EV/EBITDA range with at least mid-teen
returns
Many targets may provide short-term returns, but may not
substantially improve the long-term character of the fleet
Must eventually renew the fleet
A prolonged downturn may limit our resources to pursue
new rigs in future years, but current prices may not be the
lowest
Many jackup opportunities
Adding high specification units may require developing
different skill-sets unless part of the acquisition
Considerations
Design
Shipyard
Potential for contract—customer and
geography
Value
Must consider potential cannibalization of our existing
business
Balance
the
potential
to
act
quickly
on
attractive
opportunities
with
desire
to
be
patient
to
ensure we are not limited in the future


2014 Guidance
www.paragonoffshore.com
18


Near Term (3Q) Financial Challenges “Post-
Spin”
3Q financial report will not be representative:
Includes
the
July
financial
results
as
a
part
of
Noble
(“Predecessor”
financials)
August and September financial results will be completely separate of Noble (“Pro
forma”)
“Predecessor”
results includes three rigs retained by Noble, plus corporate
“allocations/adjustments”
as described in our Form 10
Revenues and rig operating expenses will be transparent
SG&A and some shorebase costs before Aug 1 were based on Noble’s allocations
The effective tax rate (“ETR”) for Paragon will be significantly higher than it was as a
subsidiary of Noble   
www.paragonoffshore.com
19


The Paragon ETR will be >40% “Post-Spin”
The increased effective tax rate (“ETR”) is a function of several factors:
A recent UK tax law (adopted in July but retroactive to 1 April 2014) affects all of the offshore
drillers and will significantly increase 3Q tax rates
-
3Q financial
statements
will
include
a
retroactive
tax
charge
for
2Q
of
approximately
$6.0
-
8.0 MM
The
current
structure
of
the
term
loan
and
senior
notes
severely
limits
our
ability
to
deduct
the
annual interest expense (approx. $100 million/year)
In connection with the spin-off restructuring, much of Paragon’s income was shifted from a low-
tax structure to a high-tax structure
Anticipate 3Q ETR to be 48-52%, including the 2Q retroactive tax charge
Anticipate 4Q ETR to be 40-44%
We are actively evaluating restructuring opportunities to address tax
inefficiencies resulting from the spin-off
www.paragonoffshore.com
20


Moderate Leverage and Strong Liquidity
Provides Financial Stability and Flexibility
Net Debt/EBITDA ratio of approximately 1.9x and a Debt/Capitalization of
approximately of 57% based on 1
st
Half 2014 pro-forma results
Large backlog through 2015
Approximately $120 million in cash and ample working capital balance as of 1
August 2014
$800 million revolver capacity
Current liquidity provides the Company the ability to pay sustainable
dividends 
Long term sustaining Capex <$200 million/year
www.paragonoffshore.com
21


Cost Guidance
2     Half of 2014 as of 2 September 2014
22
3Q14
4Q14
Operating Expense
$
225MM
-
$
235MM
$
228MM
-
$238MM
Depreciation
$ 100MM
-
$
105MM
$
100MM
-
$
105MM
SG&A
$ 15MM
-
$
18MM
$ 15MM
-
$
17MM
Interest Expense
$
23MM
-
$
26MM
$ 24MM
-
$
27MM
Tax Rate
48 –
52%
40 –
44%
Capital Expenditures
$
100MM
-
$
110MM
$ 100MM
-
$
110MM
www.paragonoffshore.com
nd
This material contains various future guidance items that are “forward-looking statements”
about the Company’s business and financial performance. These statements
can be identified by the fact that they do relate strictly to current or historical facts. Each future projection is a forward-looking statement that involves certain risks,
uncertainties and assumptions. These include but are not limited
to operational risks, actions by regulatory authorities or other
third parties, costs and difficulties related to
our separation and subsequent spin-off from Noble Corporation plc, risks associated with non-U.S. operations, market conditions, financial results and performance, ability to
repay debt and timing thereof, actions by customers and other third parties, factors affecting the level of activity in the oil and gas industry, supply and demand of drilling rigs,
factors affecting the duration of contracts, the actual amount of downtime, factors that reduce applicable dayrates, violations of anti-corruption laws, hurricanes and other
weather conditions, the future price of oil and gas and other factors detailed in the Company’s most recent filings with the Securities and Exchange Commission. Should one
or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated. The Company
disclaims any duty to update the information presented here.


Conclusion
www.paragonoffshore.com
23


Why Paragon Offshore?
www.paragonoffshore.com
24
Significant Scale, Size and Expertise
Low-cost Driller with Proven Record of
Excellence
Strong Backlog and Established
Diverse Customer Base
Well-Maintained “Workhorse”
Fleet of Rigs
Natural Consolidator
Total Investment Return Vehicle
Paragon C20051


Appendix
25
www.paragonoffshore.com


Management Team with More Than 180 Years of
Experience in the Industry
www.paragonoffshore.com
26
Randy Stilley
President and CEO
38 years experience
Steve Manz
Senior VP and CFO
25 years experience
Lee Ahlstrom
Senior VP –
Investor
Relations, Strategy and
Planning
23 years experience
Andrew Tietz
Senior VP –
Marketing and
Contracts
23 years experience
Charlie Yester
Senior VP -
Operations
40 years experience
Todd Strickler
Vice President and General
Counsel
12 years experience
Luis Jimenez
Vice President –
Human
Resources
25 years experience


Reconciliation to EBITDA
www.paragonoffshore.com
27
Predecessor Historical
Paragon Offshore Pro Forma
Year Ended December 31,
Year Ended
December 31,
Six Months
2011
2012
2013
2013
6/30/2014
Net Income
$104,823
$126,237
$360,305
$172,387
$135,172
Add:
Depreciation and amortization expense
$348,834
$367,837
$413,305
$367,304
$200,838
Interest expense, net of amount capitalized
1,986
3,746
5,938
105,641
54,044
Interest income and other, net
59
(1,959)
1,897
2,306
(525)
Income tax provision
30,079
48,688
85,605
71,243
38,871
EBITDA
1
$485,781
$544,549
$867,050
$546,494
$428,400
Loss on impairment
$12,719
$0
$43,688
$40,103
$0
Gain on disposal of assets, net
-
-
(35,646)
-
-
Gain on contract settlements/extinguishments, net
(19,846)
(4,869)
(24,373)
(16,182)
-
Operating Income
$136,947
$176,712
$453,745
$351,577
$227,562
Add:
Depreciation and amortization expense
348,834
367,837
413,305
367,304
200,838
EBITDA
1
$485,781
$544,549
$867,050
$718,881
$428,400
Loss on impairment
$12,719
$0
$43,688
$40,103
-
Gain on disposal of assets, net
-
-
(35,646)
-
-
Gain on contract settlements/extinguishments, net
(19,846)
(4,869)
(24,373)
(16,182)
-
Source:  Company’s Form 10 filed 14 July 2014, Company’s Quarterly Report on Form 10-Q for the three and six months ended 30 June 2014


30 June 2014 Pro-forma Summary Balance Sheet
Assets
Cash
$72,688
Total Current Assets
$505,488
PPE, Net
$2,883,729
Total Assets
$3,484,679
Liabilities and Equity
Total Current Liabilities
$281,350
Long-term Debt
$1,726,750
Other Liabilities
$185,574
Total Liabilities
$2,193,674
Total Equity
$1,291,005
Total Liabilities and Equity
$3,484,679
www.paragonoffshore.com
28
Source:  Company’s Quarterly Report on Form 10-Q for the three and six months ended 30 June 2014


Jackup Overview: Rigs 15 Years and Older
Company
Number of ILC
Jackups 15 Years
and Older
Shelf Drilling
37
Paragon Offshore
34
Ensco
30
Rowan
10
National Drilling
10
Hercules Offshore
8
COSL
7
Nabors
6
ONGC
6
GSP
6
Diamond Offshore
5
Noble
5
Transocean
5
Other (50 companies with 5 rigs or
less incl. 41 with 1 or 2 rigs)
88
Total
257
Key Owners of Standard ILC Jackups
Number of Units
Regional Breakdown of Operating Units
Source:  IHS Petrodata as of 08.05.14
323
66
257
8
249
0
50
100
150
200
250
300
350
Total
Standard
Specification
Jackups
Mat and IC
Slot Rigs
ILC jackups
Cold
stacked/Out of
Service
Operating
UAE, 32
Saudia
Arabia, 29
Mexico, 27
India, 21
USA, 17
China, 12
Egypt, 12
UK, 11
Qatar, 9
Iran, 8
Other, 71


Jackup Overview: “Newer”
Standard Rigs Less
Than 15 Years Old
Company
Number of ILC
Jackups 14 Years
and Older
Seadrill
16
COSL
16
Ensco
8
CPOE
6
Maersk Drilling
6
Aban Offshore
5
National Drilling
5
Perforadora Central
4
UMW Standard Drilling
4
Rowan
4
Egyptian Drilling
4
Vantage Drilling
4
Other (21 companies with 3 rigs or
less incl. 6 with 1 rig)
41
Total
257
Source:  IHS Petrodata as of 08.05.14
Regional Breakdown of Operating Units
Breakdown by Design: 123 Total
Key Owners of Newer Standard Jackups
KFELS B
Class, 31
BMC 375,
27
LeTourneau
116, 26
KFLES Mod
V B types,
10
Mod V A, 2
Other, 8
Mexico, 16
Iran, 10
China, 10
Saudi
Arabia, 9
Malaysia, 9
Vietnam, 7
India, 7
Indonesia, 7
UAE, 6
Gabon, 5
Other, 37
L-780 Mod
II, 6
JU-2000, 2
CJ-50, 4
CJ-46, 7


Floater Overview
Drillships and Semisubmersibles 15 Years and Older
Company
Drillships
15 Years
and Older
Semisubs
15 Years
and Older
Total
Floaters 15
Years and
Older
Transocean
8
41
49
Diamond Offshore
1
29
30
Noble
1
9
10
Ensco
1
7
8
Paragon Offshore
5
3
8
COSL
6
6
Dolphin
6
6
Saipem
5
5
SOCAR
5
5
Other (26
companies with 4
rigs or less incl. 22
with 1 or 2 rigs)
11
33
44
Total
27
144
171
Key Owners of Standard Floaters
Number of Units 15 Years or Older
Regional Breakdown of Operating Units
Semisubs
Drillships
171
148
Source:  IHS Petrodata as of 08.05.14
Semisubs
Drillships
171
148
0
20
40
60
80
100
120
140
160
180
144
27
122
23
26
Total Standard
Specification Floaters
Cold stacked/Out of
Service
Operating
Brazil, 29
UK, 21
USA, 14
Norway, 12
Australia, 10
Malaysia, 10
Singapore, 9
India, 9
China, 6
Azerbaijan,
5
Other, 46