This is an oral presentation which is accompanied by slides. Investors are urged to review our SEC filings.

This presentation contains certain forward-looking statements regarding various oil and gas discoveries, oil

and gas exploration, development and production activities, anticipated and potential production and flow

rates; anticipated revenues; the economic potential of properties and estimated exploration costs. Accuracy

of the projections depends on assumptions about events that change over time and is thus susceptible to

periodic

change

based

on

actual

experience

and

new

developments.

Endeavour

cautions

readers

that

it

assumes no obligation to update or publicly release any revisions to the projections in this presentation and,

except

to

the

extent

required

by

applicable

law,

does

not

intend

to

update

or

otherwise

revise

the

projections.

Important

factors

that

might

cause

future

results

to

differ

from

these

projections

include:

variations

in

the

market prices of oil and natural gas; drilling results; access to equipment and oilfield services; unanticipated

fluctuations in flow rates of producing wells related to mechanical, reservoir or facilities performance; oil and

natural

gas

reserves

expectations;

the

ability

to

satisfy

future

cash

obligations

and

environmental

costs;

and

general exploration and development risks and hazards.

The Securities and Exchange Commission permits oil and gas companies in their filings with the SEC to

disclose

only

proved

reserves

that

a

company

has

demonstrated

by

actual

production

or

conclusive

formation

tests to be economically and legally producible under existing economic and operating conditions. SEC

guidelines

prohibit

the

use

in

filings

of

terms

such

as

“probable,”

“possible,”

P2

or

P3

and

“non-proved”

reserves, reserves “potential”

or “upside”

or other descriptions of volumes of reserves potentially recoverable

through additional drilling or recovery techniques. These estimates are by their nature more speculative than

estimates of proved reserves and accordingly are subject to greater risk of being actually realized by the

company.

Certain

statements

should

be

regarded

as

“forward-looking”

statements

within

the

meaning

of

the

securities laws. These statements speak only as of the date made. Such statements are subject to

assumptions, risk and uncertainty. Actual results or events may vary materially. The estimates of recoverable

resources per well and completed well costs included herein are based upon other typical results in these

shale plays and may not be indicative of actual results.

Disclosures

Exhibit 99.1

Corporate Strategy

Bill Transier, Chief Executive Officer

UK Operations

March 13, 2012

UK Business Unit

and Strategy

March 13, 2012

3

UK Business Unit and Strategy

The Four Key Questions

•

Why the UK North Sea?

•

What is the UK business unit 

comprised of today?

•

What comes next?

•

How will we get there?

4

Why the North Sea?

A mature proven, active petroleum system

•

24 billion barrels of oil and gas still left to be produced

•

Further exploration opportunities through License Rounds

and Farm-ins

Business Development

•

Opportunity rich environment

•

Most Majors are re-evaluating their portfolios

•

ConocoPhillips acquisition demonstrates potential upside

Markets

•

Strong commodity prices with long term forecast stability

•

Brent Oil $124;  NBP Gas $9.80

Intellectual Capacity

•

Deep talent pool of experienced personnel with a  huge

amount of intellectual knowledge across the basin,

particularly in the Central North Sea area

Political Landscape

•

Strong signs of improved fiscal stability and recognition of

the importance of the oil industry to UK economy

5

The

UK

Business

Unit

Today

-

Building

on

Past

Success

The UK Business –

Brief History

•

Starting in 2004, built a stable platform of production

with significant reserves increases

•

Active value driven portfolio management with

acquisitions, exploration success, divestments

•

Acknowledged, experienced offshore operator and

asset developer

•

Evolved a focus on the UK Central North Sea

•

Built a strong and experienced team able to manage

full cycle E&P activity

Vision

•

To be the fastest growing Independent E&P company

in the North Sea

Current Production

Development Projects

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Rochelle

Renee

Rubie

Ivanhoe /

RobRoy

London Office

Aberdeen Operations Center

6

UK

Business

Unit

–

Growth

Strategy

Key Business Focus Areas in 2012

•

Deliver on key development projects

•

Rochelle

•

Bacchus

•

Close on the ConocoPhillips acquisition

•

Assume operatorship of MacCulloch FPSO

•

Success in bidding for additional blocks in

the 27

th

Licensing Round

Future Objectives

•

Sustained reserves and production growth

will come from a balanced strategy of:

•

Low risk exploration and appraisal

•

Acquisitions

•

Realizing existing portfolio upside potential

•

Funded from internally generated cash

flows

7

Illustration of Growth Potential

8

66%

34%

Significant UK Production Growth Through Near-Term Projects

Pro forma Production with

Bacchus on-line and the

acquisition of North Sea Assets

UK Oil

UK Gas

Pro forma Production

with Rochelle on-line

17,000 –

24,500 boepd

11,000 –

17,000 boepd

9

Expected 2012 Exit Position of Endeavour

10

UK

Business

Unit

–

How

Will

We

Realize

Our

Strategy?

Strong Leadership team with an average of 25 years UK and International

experience with a proven track record of bringing developments on-line

Core technical competencies retained in-house.  Internal technical capability covers

the full cycle of E&P activity

•

Subsurface -

Exploration / Development Geology / Reservoir Engineering

•

Development Engineering / Drilling and Production Operations / Commercial

Today’s UK Presenters

•

Carl Grenz –

EVP International

•

36 years UK and International experience, formerly Chief of Global production for BHP Billiton. 

Experienced in delivery  of new developments and the management of E&P operations

•

Derek Neilson –

Director, Subsurface Engineering

•

28 years UK and International development and reservoir management experience, formerly Chief

Reservoir Engineer, Total UK

•

Nick Ritchie –

Director, Facilities Engineering

•

15 years experience,  Rochelle project director.  Extensive project and operations experience of

UKCS / deepwater FPSOs.  Formerly Talisman and CNR

•

Nick Terrell –

Director, Exploration

•

Talented

geoscientist

leading

the

highly

experienced

Exploration

team.

With

Endeavour,

since

the

Company entered North Sea, proven track record of exploration success.

UK

Producing

Assets

March 13, 2012

12

Overview of the UK Assets (Post Acquisition)

Project

Operator

END

WI%

Production

Status

International

Alba

(1)

26%

Producing

Infill Drilling

Bittern

2%

Producing

Enoch

8%

Producing

Bacchus

30%

First production

expected 1Q2012

MacCulloch

(1)

40%

Producing

Nicol

(1)

18%

Producing

Rochelle

44%

First production

expected 4Q2012

Columbus

25%

In Development

R Block Redev.

52%

In Progress

Notes:

(1) 23.43% Alba, MacCulloch (+Operatorship) and Nicol pending completion of CoP Acquisition

Current Production

Development Projects

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Renee

Rubie

Ivanhoe /

RobRoy

Rochelle

13

Alba Field -

Overview

Block 16/26a, 450ft water depth

Discovered 1984, first production 1994

Late Eocene reservoir at ~6,200ft

•

Massive homogeneous unconsolidated sands

with excellent quality

•

92% Net-Gross / ~35% porosity / ~3,000mD

permeability

•

Oil-in-place ~1033 MMbbls

•

19°

API, 7 to 10 cP viscosity, GOR 330 scf/stb

Facilities

•

ANP platform, with 31 slots

•

25 platform producers / 6 water injectors

•

12 slot AXS manifold

•

10 subsea producers / 2 water injectors

•

Seawater and produced water re-injection

•

Oil exported by tanker, gas to Britannia

Company

Equity (%)

Endeavour

25.68*

Chevron (Operator)

23.37

Statoil

17.00

BP

13.30

Total

12.65

CIECO / Itochu

8.00

*Pro Forma including CoP Acquisition

Alba

MacCulloch

Nicol

Britannia

14

Alba Field -

Metrics

Large, high quality North Sea oil asset

with strong upside development and

reserves potential

A specific target due to strong

performance metrics

•

2P Reserves 23.6 MMboe at YE2011

•

2P NPV10 > $1,000mm

Oil trades at low differential to Brent

•

Average 2011 differential of -

$3.50

Low operating costs

Low future CAPEX exposure

•

Majority for development drilling campaign

with high return and short payback

~20 year remaining field life

Based

on

YE2012

2P

Audited

Reserves

Report

15

Alba Field -

Future Development

Sustain current production and increase

reserves through continued development

drilling

Current production rate

•

25,000 –

30,000 bopd gross

Cumulative production to date

•

~373 MMbbls gross

Infill drilling since 2009 has largely

sustained production

Continuation of Infill drilling program

•

2012 campaign extended from 6 to 9 months

•

Continuation of drilling included in Operator’s

business plan

•

Large basket of further drilling opportunities

identified

•

Addition to current reserves

•

Low economic threshold

•

Short payback time

Central North Sea Assets

Current Production

Development Projects

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Renee

Rubie

Ivanhoe /

RobRoy

Rochelle

Bittern

Field

-

Overview

Block 29/1b, 305ft water depth

Discovered 1996, first production 2000

Eocene reservoir at ~6,750ft

•

Good quality Rogaland and Forties channel

sands

•

85% NTG / ~33% porosity / ~1,000mD perm

•

Oil-in-place ~256 MMbbls with 77 Bcf Gas cap

•

39°

API, 0.34 cP viscosity, GOR 1250 scf/stb

Facilities

•

Triton FPSO

•

Oil offload to tanker, gas export to Fulmar

pipeline to St. Fergus

•

2 subsea drill centers

•

5 subsea producers / 2 water injectors

•

Dual production flowlines + test line

•

Water injection and gas lift lines

Company

Equity (%)

Shell (Operator)

39.63

Hess

28.28

ExxonMobil

25.00

Dana

4.67

Endeavour*

2.42

*Plus 1.62% equity in Triton FPSO

Triton FPSO

Bittern

16

Bittern

Field

-

Status

Production increase and reserves added

in 2010 and 2011 through 2 infill wells

Current production rate

•

15,000 to 20,000 bopd gross

Cumulative production to date

•

130 MMbbls Gross

Recently announced change of Triton

Operator (Dana)

•

Increase production efficiency on Triton

vessel

•

Open infill wells to full potential to further

increase production and add reserves

•

Evaluate potential for future infill drilling

17

Central North Sea Assets

Current Production

Development Projects

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Renee

Rubie

Ivanhoe /

RobRoy

Rochelle

Enoch

Enoch

Field

-

Overview

Company

Equity (%)

Talisman (Operator)

25.2

Dana

20.8

Dyas

14.0

RocOil

12.0

Statoil

11.8

Endeavour

8.0

Noreco

4.4

Dong

2.0

Noil

1.9

* Cross UK / Norway border 80 / 20 split

18

Enoch Field -

Status

19

Central North Sea Assets

Current Production

Development Projects

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Renee

Rubie

Ivanhoe /

RobRoy

Rochelle

20

MacCulloch

Field

-

Overview

ConocoPhillips currently operates the field,

Endeavour seeking transfer of Operatorship

Block 15/24b, 490ft water depth

Discovered in 1990

First  production August 1997

Paleocene reservoir at ~6,200ft

•

Channelized turbidite sands of good quality

•

40

–

90%

NTG

/

~28%

porosity

/

200

–

2000

mD

•

Oil-in-place ~241 MMbbl

•

32-37°

API, 0.85 cP viscosity, GOR 410 scf/stb

Facilities

•

Converted FPSO North Sea Producer (NSP)

•

Oil and Gas export to Piper “B”

•

Subsea production drill centers (11 wells)

•

Subsea water injection flowbase, never

commissioned

Company

Equity (%)

Endeavour (Operator**)

40.00*

Eni

40.00

Noble Energy

14.00

Talisman

6.00

*

Pro Forma including CoP Acquisition

**Pending assignment of Operatorship

MacCulloch

Field

-

Status

Control in future Operated Asset with

upside potential

Current production rate

•

7,000 bopd gross

Cumulative production to date

•

114 MMbbl gross

Plan to assume Operatorship from

ConocoPhillips on completion of

acquisition

•

Plans to perform a detailed asset

performance review:

•

Evaluation of infill / near field potential

•

Opportunity to return shut-in wells to

production

•

Optimization of gas lift rates and distribution

•

Debottlenecking, improvement to compressor

performance and availability

•

Improve operational efficiency

•

Manage offshore duty holder (NSPC) to

implement operational improvements

21

UK

Development

Assets

March 13, 2012

Central North Sea Assets

Current Production

Development Projects

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Renee

Rubie

Ivanhoe /

RobRoy

Rochelle

Rochelle

Field

-

Overview

* Unit interests following Unitisation

Company

Equity (%)

Endeavour (Operator)

44.0

Nexen

41.0

Premier

15.0

23

24

Rochelle

Field

-

Organic

Reserve

Additions

Bringing a stranded discovery to first

production

Rochelle discovered in 2000 by 15/27-9

well

Acquired in 2006 from Talisman

•

Undeveloped stranded discovery with ~4

MMboe contingent resources

Technically unlocked by Endeavour

•

Reprocessed seismic to identify stratigraphic

potential

•

Leveraged the regional knowledge of the

Kopervik gained through Goldeneye Field

•

15/27-11 (East Rochelle) appraisal in 2009

•

Evaluated development and upside potential

•

Appraisal well drilled in 2011 proved West

Rochelle

•

Field Development Plan (FDP) approved with        

31 MMboe 2P Reserves

15/27-9

Discovery

East Rochelle

15/27-11 DST

42 MMcsf/d

25

ER dev. well

WR dev. well

Rochelle

Field

-

Reservoir

Development

Reservoir Description

•

3 way stratigraphic trap in Kopervik fairway

•

Lower Cretaceous Kopervik turbidite sands

of good quality

•

50%

NTG

/

~21%

porosity

/

~100

–

1,000mD

perm

•

Regionally extensive active aquifer

Reservoir Development

•

2 x 500m horizontal development wells

•

High potential wells at100 MMscf/d per well

•

Gravel pack with pre-drilled liner

•

5 ½”

completion with permanent downhole

pressure / temperature gauges

•

Potential reserve additions through

production post water breakthrough

15/26

East Rochelle

West Rochelle

GOLDENEYE

Rochelle

Field

-

Application

of

Proven

Technology

Optimized and added value to the

development

•

Ocean Bottom Cable (OBC) seismic to image

sands within the gross Britannia package

•

Use of seismic attributes / simultaneous inversion

to aid mapping and evaluate uncertainties

•

Regional aquifer knowledge / modelling

•

Schlumberger Periscope deep reading resistivity

planned to optimize geo-steering for delivery of

successful development wells

•

‘Pipe in Pipe’

development solution

ER OBC inversion through East Rochelle

Geosteering producers through the

Rochelle reservoir -

forward modelling

RXT Vikland

OBC vessel

26

Rochelle

Field

-

Development

Rochelle

Field

-

Surface

Development

Greenfield Installation

•

Individual well metering

•

Manifolds at East and West

•

7.8km long 10/14”

Pipe-in-pipe (West)

•

30km long 10/14”

Pipe-in-pipe (East)

•

New subsea safety valve at Scott

•

New umbilical and flexible risers on Scott

Brownfield modifications (Scott)

•

Re-wheel compressors

•

New 2-phase vertical separator

•

Modifications to chemical system

•

Piping tie-ins

•

Subsea control system upgrade

Designed for upside and future

expansion

Separation

Controls

Flexible

riser

Methanol Injection

& Storage

Chemical

Injection

28

Rochelle

Field

-

Development

Status

29

30

Rochelle

Field

-

March

2012

Above:

Rochelle

Christmas

Tree

Right:

Manufactured

sections

of

14”

pipe

in

Evanton

spoolbase

Below:

New

methanol

tank

for

Rochelle,

quayside

and

installed

Central North Sea Assets

Current Production

Development Projects

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Renee

Rubie

Ivanhoe /

RobRoy

Rochelle

31

Bacchus

Field

-

Overview

Company

Equity (%)

Apache (Operator)

50.0

Endeavour*

30.0

First Oil

20.0

*Endeavour equity increased from 10% through purchase

of Shell interest in February 2011

Bacchus

Bacchus

Field

-

Subsurface

Development

Plan

3 well development

•

Horizontal wells

•

Maximize productivity

•

Drilled through faults

•

Mitigate seal risk

Phase 1

•

Depletion from 3 wells

Phase 2

•

Commence water injection in southern well

•

Increase reserves through secondary recovery

32

Bacchus

Field

-

Development

Subsea development to Forties Alpha

•

4 slot subsea production and injection manifold

•

Tied-back to Forties Alpha via a 6.7 km bundle and

new riser caisson attached to jacket

•

Forties Alpha topsides facilities

•

Pig launcher and receivers, multi-phase flow meter

•

HIPS valves, methanol tanks & pumps

•

Connections from gas lift manifold and produced water

injection pumps

•

Control and chemical injection systems

6.7 km subsea bundle

2 x 6”

production

2 x 4”

water

4”

gas lift

3”

scale squeeze line

2”

methanol line

Power, control and

hydraulic lines.

Riser

Caisson

Topsides Pipework

33

34

Bacchus

Field

-

Development

Status

SSIV Towhead

UK

Exploration

March 13, 2012

UK North Sea Exploration

UK Exploration and Appraisal Drilling

Forecast 2012-2015

Sources:

The

Oil

&

Gas

UK

2011

Economic

Report,

DECC,

Hannon

&

Westwood,

WoodMac,

company

information

36

Exploration Overview

Centurion South

Ravel

Buffalo

Hoylake

Rye

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Rochelle

Renee

Rubie

Ivanhoe /

RobRoy

Current Production

Development Projects

Prospects / Discoveries

37

38

Centurion

-

Focus

Area

Bittern

Centurion

Extension of Centurion discovery

•

29/6a-3 well flowed 5,200 bopd

Centurion South well –

Q3 2012

•

Endeavour equity

33.3%

High quality Fulmar reservoir, oil-prone block

Strategy is to appraise Centurion South first

Attractive 27

th

Round acreage nearby

Centurion South

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Rochelle

Renee

Rubie

Ivanhoe /

RobRoy

Current Production

Development Projects

Prospects / Discoveries

West Curlew

CENTURION

CENTURION SOUTH

29/6a-CS

29/6a-3

Centurion South

Ravel

Buffalo

Hoylake

Rye

39

Ravel Prospect

•

Low risk oil prospect

•

Strong seismic anomaly with flat spot

•

Drill Ravel prospect to add contingent resources

Close to other R-Block assets

•

Oil developments/discoveries/prospects

•

Optimize future R-Block development

•

Other prospectivity on held acreage

Future Growth

•

Attractive 27

th

Round acreage near-by

•

Farm-in opportunities identified

R-Block

-

Focus

Area

Rochelle

Renee

Rubie

Ivanhoe/RobRoy

Buffalo

Hoylake

Ravel

Centurion South

Ravel

Buffalo

Hoylake

Rye

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Rochelle

Renee

Rubie

Ivanhoe /

RobRoy

Current Production

Development Projects

Prospects / Discoveries

Top Forties depth map (TVDSS)

Ravel

40

Buffalo and Hoylake

•

Rochelle look-alikes on Kopervik Fairway

•

Discovered hydrocarbons (Hoylake)

•

Excellent quality reservoirs

•

Extensive regional knowledge

Close to Rochelle development

•

Gas condensate tie-backs to Rochelle

Future Growth

•

Attractive 27

th

Round acreage available 

near-by

•

Farm-in opportunities identified

West Rochelle

East Rochelle

Buffalo

Hoylake

Rochelle

-

Focus

Area

Rochelle

Renee

Rubie

Ivanhoe/RobRoy

Buffalo

Hoylake

Ravel

Centurion South

Ravel

Buffalo

Hoylake

Rye

Bacchus

Enoch

Columbus

Bittern

Alba

MacCulloch

Nicol

Rochelle

Renee

Rubie

Ivanhoe /

RobRoy

Current Production

Development Projects

Prospects / Discoveries

27

th

Licensing Round

Bid deadline 1

st

May 2012

•

More than 8 million acres available in Central

North Sea

•

2

nd

Round Licence extension expiries

Focus on Central North Sea core area

•

Region is prolific generator of discoveries

•

Jurassic, Cretaceous and Tertiary play focus

•

Focus on high quality acreage close to

infrastructure

•

Building on existing focus areas

•

Rochelle / R-Block and Centurion

•

New Focus Areas

•

MacCulloch (ConocoPhillips) / Rye (Block 21/11)

27

th

Round

acreage

Endeavour acreage

Licensed acreage

Pending award

41

US Assets and

New Ventures Strategy

March 13, 2012

US Management Team

(prior companies)

Jim Emme –

Executive (Anadarko, Elk)

Dave Davenport –

Land (Marathon, Orion, Encana, Elk, EXCO)

Eric Kolstad –

Drilling/Ops (Texaco, UPR/APC, Williams, Newfield)

Corey Meyer –

Reservoir Engineering (Chevron, Cimarex)

Chip Oakes –

Geosciences (Sun/Oryx, Forest)

Richard Rowe –

Engineering (Amoco, Anadarko, Stonegate)

Our Experienced Management Team

2

3

US Shale Oil and Gas Resource Systems

Jarvie 2010

Play Types

Oil

Gas

Oil and Gas

Biogenic Gas

4

New Ventures Criteria

Proven petroleum systems

Underutilized technologies

Acceptable entry cost

Competitive niche

Operational control or influence

Market access

Manageable regulatory environment

Reasonable cycle time to production

Attractive returns

5

Overview of Endeavour’s US Assets

Heath

Shale

Oil

Play

-

MT

Marcellus Play -

PA

Haynesville

Play

–

LA/

E.

TX

Cretaceous

Plays

-

CO

US 2011 Year-End Totals

582,000 gross / 159,000 net acres

20 MMCFe/D net production (exit rate)

61 BCFe Proved / 89 BCFe 2P reserves

Heath

Shale

‘Tight

Oil’

Play

in

Central

Montana

25% joint venture with two independent

Montana producers

430,000+ gross acres primarily in Garfield

and Rosebud Counties (94,000 net to END)

Four well vertical pilot drilling program

completed

•

Evaluating extensive core/log data

•

Indentifying future horizontal re-entry targets

(likely Q3/Q4 2012 horizontal testing program)

6

‘Bakken-like’

play, but shallower       

(4000-

5500 ft. depth)

A proven petroleum system ~ 137 MMBO

cumulative production (Heath Shale is the

primary source rock)

Rich, oil-prone source rock, up to 20%

total organic carbon content, light oil

Heath Play Attributes

END

CMR

Cirque

Cabot          Fidelity             Heath sourced oil fields

Heath Play, END Activity

Heath Fairway outline

Heath Shale -

Geological Setting

Heath Shale Cox Ranch Member 10-16% TOC (MBMG, 1985)

Tyler Creek photo by Great Northern Gas Co, 2009

7

Primary

Objective

Historical

Type

Log

-

Sumatra

Field  

Exeter 8-36 Kincheloe well (ne ne sec. 36 11N 31E)

Gamma Ray

Resistivity

Heath Formation

Organic-rich shales; 

Limestone and

dolomite inter-beds

Tyler Sandstone

Conventional reservoir

8

9

Heath Shale Petroleum System

DST 1700’

clean oil

IP 73 BOPD, 35.3 API

Key components:

Middle

Carbonate

Member

(up

to

40’

thick)

•

Thin limestones and dolomites

•

Porosity developed in places (up to13%, 5% avg)

•

Possible ‘carrier’

beds; tested oil

•

Over 100 mbo produced from Sumatra well

Cox Ranch Member (“Hot”

Shale)

•

10

to

60

feet

thick

(4

–

20%

porosity,

11%

avg)

•

High organic content

•

Thermally mature to volatile oil window

•

Tested

30

–

35.5

API

gravity

oil

NE 26-11N-32E

Middle

Carbonate

Cox Ranch

‘Hot’

Shale

Top Heath Formation

10

Tyler/Heath Type Well Log

Middle

Carbonate

Cox Ranch

Top Heath

18%   10%   2%

Gamma Ray

Resistivity

Porosity

Oil stained, porous Tyler Sandstone

Possible local trap configuration

High TOC black Cox Ranch Oil shale

Potentially porous, Middle carbonate

11

Oil-stained, porous

Tyler Sandstone

Oil-stained, calcareous

intervals interbedded

with oil-prone Heath

source shales

Tyler/Heath

Core

Photos

–

Multiple,

Stacked

Objectives

12

Reflector that contains oil-stained Tyler thickens off structure and develops amplitude

Seismic line courtesy of Seismic Exchange, Inc.

Sub-Play:  Potential Tyler Sand Stratigraphic Trap

13

Highly Active,

Competitive

Niobrara Oil Fields

Niobrara Gas Fields

Abbreviations denote Rocky Mtn Basins

S. Sonnenberg, CSM 2011

END focused on less active,

emerging areas

•

Targeting stacked, proven

Cretaceous petroleum systems,

including Niobrara

•

Oil and gas with liquids

potential

•

Significant land positions are

still available

•

Lower cost of entry

•

Forming 20,000 acre federal

unit for first optional test well

Niobrara-Mancos Shale Oil and Gas Productive Areas

14

Cretaceous

Outcrop

-

Subsurface

Reservoir

Analog

15

50% joint venture with JW-Operating in 

15,600 gross acres (7,100 net to END)

120 + future horizontal drilling locations

being held by current production

Drilling successful to date

•

2 year participation in 24 successful

Haynesville and 3 successful Cotton

Valley Sand horizontal producing wells

•

January 2012 record production rates of 

18-20 MMCF/D net (77-88 MMCF/D

gross)

Haynesville Shale and Cotton Valley Sand Plays

16

Bull Bayou Gas Rate vs. Cumulative Production Comparison

Restricted Rate Strategy is Working

17

50% joint venture with JW-Operating in 38,000

gross acres (18,400 net to END)

•

200+ potential horizontal drilling locations

END prospects are well situated

•

Proximity to East Coast markets yields price

premiums, steady demand for production

Initial horizontal drilling at Daniel Prospect in

Cameron County

•

Results consistent with reported industry results

•

Requires only two horizontal wells per year to

hold key Daniel Pardee block

Pennsylvania Marcellus Shale Gas Play 

18

2

3

Ohio

PA

NY

Pennsylvania

Shale

Fairways

–

END’s

Strategic

Position

Daniel

(Marcellus

and dry Utica)

NE Potter

(Geneseo)

Clarion

(dry Utica)

2

1

3

1

19

Solid well results in adjacent areas

on trend with Cameron County

•

Seneca –

Elk Co.

Reported EUR’s of 3 -

5 BCF

•

EOG/Seneca –

N. Clearfield Co.

Recent IP’s 7 -

9+ MMCF/D with

“High Rate Frac Technology”

•

PGE/Exxon –

SE McKean Co.

5000’

–

7600’

laterals

IP rates of 6-9 MMCF/D

Multi-pay Upside

•

Seneca –

Central Potter Co.

Geneseo Shale IP’s of 2-4.5 MMCF/D

•

Seneca –

McKean Co.

Utica Shale test well “encouraging”

with

400’

gross reservoir at 10,000’

depth

END               EOG             Seneca            Ultra      

PGE/Exxon

Seneca Geneseo

Seneca Utica well

Ultra long laterals

Seneca 3-5 Bcf

EOG

PGE long laterals

7000+’

5000+’

Daniel

Commercial Marcellus Activity Continues on Trend  

20

Size of the Cameron Prize

•

21,000 gross / 10,600 net acres

to END’s interest (50% WI)

•

180 -

200 locations

•

3 -

5 BCF/well EUR

•

540 –

1,000 BCFG recoverable

•

Potential to add 35 -

50k acres

via leasing, trades, deals

•

1 -

2 TCFG ultimate potential

Planned Activities 2012

•

Expand gathering infrastructure

•

Pardee C14H and C20H

drilled/cased, waiting on completion

•

Evaluate new 3D seismic

•

Drill two lease obligation wells Q4

2012 (prior to March 2013)

•

Negotiate access to un-leased

State Forest Lands minerals

Pardee C-4V

Pardee C-10H

Pardee C-7H

Pardee C-9H

Pardee C-5V

Pardee C-12H

Pardee C-13H

Pardee C-14H

Pardee C-20H

Daniel

Project

Update

–

Cameron

County,

PA

Shale Gas Play Economics vs. Wellhead Gas Prices*

*Henry Hub wellhead gas prices, net of local price differentials, gathering, treating or marketing fees

21

Reserves

March 13, 2012

2

Corporate Reserves Growth

Sustained 1P and 2P Reserves Growth since company inception

•

Even accounting for sale of assets to realize best value in portfolio management process

•

2009 Norway -

$150mm

•

2010 Cygnus -

$110mm

3

Reserves and Production Growth (Pro Forma CoP)

Step change in reserves and

production post acquisition

•

Addition of 19.5  / 31.0 MMboe

1P /2P reserves respectively

•

~10,000 boe/d production

•

Entering the North Sea mid-cap

peer group

Further increase in production

and proved reserves with

Bacchus and Rochelle

developments on production

•

Proved Undeveloped (PUD)

reserves move to Proved

Developed Producing (PDP)

•

2P reserves move to 1P with

reduction of uncertainty post

development and start-up

4

Reserves Breakdown

Balanced reserves portfolio post

ConocoPhillips acquisition

•

By Class

•

Good

balance

of

developed

vs

.

undeveloped

reserves due to:

•

UK Alba and MacCulloch mainly developed

producing

•

UK Rochelle, Bacchus and Columbus

undeveloped

•

US large volume of Haynesville PUDs

•

By Country

•

Growth in US reserves due to active drilling

program in Haynesville

•

Growth in UK reserves due to ConocoPhillips

acquisition

•

Lower relative US value due to depressed US gas

prices

•

By Fluid

•

Good balance of oil and gas exposure, portfolio

previously weighted more heavily towards gas

25.4, 33%

50.5, 67%

2P by Class

Dev

Undev

32.1, 76%

10.2, 24%

1P by Country

UK

US

61.2, 81%

14.8, 19%

2P by Country

UK

US

1,273,079

, 96%

49,759 ,

4%

1P NPV10 By Country

UK

US

2,417,478

, 98%

55,075 ,

2%

2P NPV

10

By Country

UK

US

23.4 ,

55%

0.0 , 0%

18.9 ,

45%

1P by Fluid

OIL

NGL

GAS

45.0 ,

59%

0.0 , 0%

30.9 ,

41%

2P by Fluid

OIL

NGL

GAS

19.0, 45%

23.2, 55%

1P by Class

Dev

Undev

5

Reserves Growth

Growth in 1P and PDP reserves through maturation of large 2P reserves base

56% of 2P reserves are Proved

•

Execution of developments and drilling program will

•

Move PUD reserves to PDP reserves

•

Reduce uncertainty and move 2P to 1P reserves

•

Additional production history (no additional CAPEX)

•

Reduces uncertainty and moves 2P to 1P reserves

Mature Contingent and Prospective Resources

•

Exploration and appraisal drilling

Future Acquisitions

Financial Review

March 13, 2012

Capital Structure Vision and Goals

Mid-cap company consistently moving toward investment grade

Deleverage each year

High-yield term loan and borrowing base for short-term working

capital/letter of credit needs

Covenant-light emphasis

Debt/EBITDA of 2:1 or better

Maintain tax efficiency between US and UK

2

Capital Structure

3

Shares Outstanding - assuming all converted

Common Stock

36.0

Series C Preferred Stock, convertible @ $8.75

4.2

Convertible Bonds, 11.5%, due 2016 @ $16.52

3.8

Convertible Senior Notes, 5.5%, due 2016 @ $18.51

7.3

Options, warrants and stock-based compensation

0.1

51.4

($ mm)

December 31,

Notes Offering

and NS Asset

Acquisition

Adjusted

December 31,

2011

2011

Cash and Deposits

106.0

$          

(10.0)

$               

96.0

$            

Senior Term Loan, 12% plus 3% PIK, due 2013

240.3

(240.3)

-

Senior Notes, 12%, due 2018

-

500.0

500.0

Convertible Bonds, 11.5%, due 2016 @ $16.52

62.5

-

62.5

Convertible Senior Notes, 5.5%, due 2016 @ $18.51

135.0

-

135.0

Subordinated Notes, 12%, due 2014

32.0

-

32.0

Total Net Debt

363.8

$          

633.5

$          

Series C Preferred Stock, convertible @ $8.75

37.0

-

37.0

Stockholders' Equity

154.1

-

154.1

Equity Component

191.1

$          

191.1

$          

Capital Structure Evolution

Ideal capital structure includes a small revolver for short-term working

capital, high-yield bonds and equity

Always focused on covenant-light instruments

Consistently simplifying and de-risking capital structure

No maturities until 2016

4

($ mm)

2008

2009

2010

2011

2012

2012

As of December 31,

2007

Activity

2008

Activity

2009

Activity

2010

Activity

2011

Activity

Estimate

Debt Securities:

Senior Bank Facility, variable rate, due 2011

110.0

$          

113.0

$          

(60.0)

$  

49.9

$            

(49.9)

$  

Second Lien Term Loan, variable rate, due 2011

75.0

(75.0)

Senior Term Loan, 12% plus 3% PIK, due 2013

160.0

161.4

75.0

240.3

(240.3)

Senior Notes, 12%, due 2018

500.0

500.0

Subordinated Notes, 12%, due 2014

50.0

50.1

51.1

(20.0)

32.0

(32.0)

  Total

185.0

$          

113.0

$          

100.0

$          

212.5

$          

272.3

$          

500.0

$          

Equity-Based Securities:

Convertible Bonds, 11.5%, due 2016 @ $16.52

40.0

44.5

49.8

55.8

62.5

62.5

Convertible Senior Notes, 6%, due 2012 @ $35.14

81.3

81.3

81.3

81.3

(81.3)

-

Convertible Senior Notes, 5.5%, due 2016 @ $18.51

135.0

135.0

135.0

Series C Preferred Stock, convertible @ $8.75

125.0

125.0

(75.0)

50.0

(5.0)

45.0

(8.0)

37.0

37.0

Common Stock Issuance

118.4

118.4

118.4

  Total

206.3

$          

250.8

$          

181.1

$          

182.1

$          

352.9

$          

352.9

$          

Deleveraging Opportunities

Grow EBITDA and reserve base

Convert or repurchase/retire convertible securities and preferred stock

over time

Repay Subordinated Notes due 2014 ($32 mm at December 31, 2011-

callable now)

5

Our Growing Resource Base

(1) Proved and probable reserves after asset sales of 6.0mmboe in 2009.

(2) Proved and probable reserves after asset sales of 13.7mmboe in 2010; pro forma for acquisition of an additional 20% WI in Bacchus acquired February 2011.

(3) Pro forma for reserves of assets acquired in the North Sea.

Reserve Growth

6

$2,467

$1,288

$730

$624

$0

$500

$1,000

$1,500

$2,000

$2,500

2P PV-10

1P PV-10

Total Debt

Net Debt

7

Reserve Valuation

Net Asset Valuation

(1) Pre-tax PV-10 as of December 31, 2011 pro forma for the acquisition of assets in the North Sea per NSAI audited reserve reports for respective assets.

(2)

As

of

December

31,

2011

pro

forma

for

the

issuance

of

Senior

Notes.

(1)

(2)

(1)

(2)

Our Reserve Base Provides Significant Value

$0

$500

$1,000

$1,500

$2,000

$2,500

1P PV-10

1P PV-10

Over Time = 2P

Rochelle

Bacchus

Alba

Other

Reserves Value Make-Up and Migration

Reserves

Migrate

from

Probable

to

Proved

from

Known

Fields,

with

Little

Capital

Investment

8

9

Example: Goldeneye Reserve Migration

Natural Growth of Proved Reserves with Minimal Capital Expenditure

Significant

Production

Growth

–

Acquisition

and

Near-Term

Projects

3,500 –

4,500 boepd

13,000 –

18,000 boepd

Current Production

Pro forma Production -

Bacchus

and acquired North Sea Assets

UK Oil

US Gas

UK Gas

Pro forma Production -

Rochelle

20,000 –

28,500 boepd

10

30%

70%

82%

18%

57%

30%

13%

Minimal Capital to Maintain, Upside from US Heath and Gas

Net Debt / Production

Net Debt / EBITDA

Improving Credit Metrics

(1)

2012 and 2013 based on Wall Street research consensus estimates of $297.26 mm and $482.17 mm, respectively.  2014 and 2015 are Endeavour estimates.

(2)

Assumes theoretical reserve migration from probable to proved from existing reserve base.

EBITDA

Proved Reserves

Credit Ratings will Be Notched Up as Targets for Production & EBITDAX are Met and Reserve Migration

of Existing Reserve Base Occurs

11

Project Net Back Metrics

12

Alba

Bacchus

MacCulloch

Rochelle

Haynesville

$/bbl

$/bbl

$/bbl

$/mcfe

$/mcf

Revenue

125.0

$         

125.0

$         

125.0

$         

10.0

$           

3.0

$             

Operating Expense

(1)

15.2

7.7

39.7

1.4

1.1

Discretionary Cash Flow

109.8

117.3

85.3

8.6

1.9

Capital Expenditures

(1)

9.8

0.7

0.6

0.1

0.2

PRT

(2)

50.0

-

-

-

-

Net Cash Flow before

Corporate Income Tax

50.0

116.7

84.7

8.6

1.7

(1) Ongoing expenses at current run rate

(2) Alba is Endeavour's only field subject to PRT

Oil

Gas

2012

Capital

Plan

by

Project

-

$175mm

to

$200mm

2012 is About Turning On and Maintaining North Sea Production

(1)

Includes ongoing infill drilling at Alba for $20mm

Note: Capital Plan is pro forma for the North Sea Acquisition

13

Hedging Strategy

Protect against downside oil and gas price volatility

Ensure consistent cash flow to meet financial and strategic goals

Meet debt hedging requirements

Target 50-75% of volumes exposed to price risk

Utilize instruments with minimal up-front cash or margin requirements

14

Endeavour Tax Attributes

Total

NOL’s

($mm)

Pro Forma

UK

356

US

136

UK Net Operating Loss (NOL) buildup from 2009 is attributable to

Cygnus/Rochelle exploration expenditure with subsequent NOL’s primarily

from Bacchus/Rochelle development capital expenditure

US NOL buildup attributable to exploration and development capital

expenditure in onshore resource shale plays

UK includes ±

$100mm from the North Sea Acquisition

UK NOL has no expiration date, US NOL expires in 2032

Corporate structure enables cash to move tax efficiently from UK

to US

15

Theoretical UK Tax on a PRT Field

16

$/bbl

$/bbl

$/bbl

Oil revenue

75

100

125

Operating expense

(15)

(15)

(15)

Operating income

60

85

110

Capital expenditures

(10)

(10)

(10)

Net income per bbl before tax

50

75

100

PRT tax rate

50%

50%

50%

PRT tax expense

25

38

50

Net income less PRT tax expense

25

38

50

Note:  Alba is Endeavour's only field subject to PRT

North

Sea

Acquisition

-

Effective

Purchase

Price

Detail

($ mm)

Reserve Value

$275

Tax Benefit Allocation

55

Purchase Price

330

Interim Cash Flows

(95)

(1)

Net Purchase Price

$235

(1) Estimated as of March 31, 2012

Why Endeavour Likes This Deal

Significant free cash flow generation from proved developed producing reserves

Expands exposure to higher price North Sea liquids

Adds scope and scale, de-risking business model

Improves operating profile & credit metrics

Monetizes existing tax shields at high rates

MacCulloch will give Endeavour more operating exposure

Likely upside in reserves

17

Alba –

2.25% Interest Purchased Reserves in 2006

18

Endeavour Purchased Alba 2P Reserves in October 2006

Alba –

2.25% Interest Current Reserves

19

Alba Reserves Have Increased 35% Since Acquisition

Financial

Philosophy

–

Tactical

Approach

Exercise disciplined, conservative approach to capital

•

Allocate capital to optimize and grow our asset base

•

Make appropriate adjustments in anticipated  periods of lower commodity prices

•

Focus on assets that have controllable capex requirements and low cost

abandonment obligations

Rely minimally on institutional banks

•

Banking environment not reliable

•

Enter into revolver for working capital and liquidity purposes during 2012

Maintain covenant-light bias

Warehouse cash to use opportunistically to de-lever and grow

Tax structure keeps UK/US flexibility for cash

Continue non-speculative hedging policy to minimize cash flow volatility

•

Target 50%-75% of forecasted total production over 12-24 month period, subject to

market conditions

•

Focus on low cost solutions to protect against commodity volatility

20

Key Financial Highlights

2012 a transitional year for production and cash flow

•

North Sea assets will significantly increase production, cash flow and the oil weighting of our asset base

2012 and 2013  financial focus on deleveraging and simplifying

Continue to simplify and de-risk capital structure to set foundation for next growth

phase

Improving credit metrics each year

Maintain balanced business strategy based on North Sea and US conventional and

unconventional assets, invest when returns meet requirements

Continue to hedge and take advantage of high North Sea prices

Option on US gas and Heath oil upside to business model

21