Paragon Offshore (PGNPQ) 8-K Barclays CEO Energy-Power Conference

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