EX-99.1

Confidential

Subject to FRE 408

Endeavour at a Glance

Distinctive Portfolio

Exceptional operating margins from three core U.K. assets

Brent crude oil and European natural gas exposure

Developing U.S. resource plays at very low cost

Strong Production Growth

All three U.K. developments on-line

•

Rochelle –

Gas with associated condensate

•

Alba –

Brent priced oil

•

Bacchus –

Brent priced oil

2013

Adjusted

EBITDA

increased

$203.3

million

–

57%

increase

year-over-year

2Q’14

average

daily

physical

production

12,879

boe/d

(1)

Positive Operating Momentum

Developed Rochelle field and transferred operations to Nexen

Identified Rossini field opportunity

Positive results in Colorado

Formed JV with partner to develop Marcellus

________________________________________________

(1)

Company filings.

2013 physical production volumes increased to 9,922 boe/d – a 26% increase year-over-year

Consolidated offices and staff - $15-20 million annual cash savings

Confidential

Subject to FRE 408

Historical Financials Summary

(boe/d)

Revenue

($ in millions)

Adjusted EBITDA

($ in millions)

Capital Expenditures

($ in millions)

________________________________________________

Source: Company filings.

LTM

$100

$200

$300

$400

2010

2011

2012

2013

Q1 2014

Q2 2014

$50

$100

$150

$200

$250

$300

2010

2011

2012

2013

Q1 2014

Q2 2014

2,000

4,000

6,000

8,000

10,000

12,000

2010

2011

2012

2013

Q1 2014

Q2 2014

$50

$100

$150

$200

$250

$300

2010

2011

2012

2013

Q1 2014

Q2 2014

Average Daily Physical Production

Confidential

Subject to FRE 408

Attractive Operating Margins on Major U.K. Assets

________________________________________________

Source: April 8, 2014 IPAA OGIS Presentation, Q1’14 earnings call.

Note: Alba operating expense does not incorporate future improvements from water handling; prices reflect management view of 12-month forward pricing curve.

Alba

($/boe)

Bacchus

($/boe)

Rochelle

($/mcfe)

Cash Operating Expense

Operating Cash Flow

$28.00

$78.00

73.6%

Brent

$106.00

Cash Operating Expense

Operating Cash Flow

$9.00

$97.00

91.5%

Brent

$106.00

Cash Operating Expense

Operating Cash Flow

$1.50

$9.50

86.4%

NBP and

Brent

$11.00

Confidential

Subject to FRE 408

Growing Production

Production volume up significantly year-over-year

Increasing production in higher valued U.K. commodity markets

2012 Production Volumes

Full Year = 7,873 boe/d

Full Year = 9,922 boe/d

U.K. oil and gas together now represent 93%

of total production.

2013 Production Volumes

________________________________________________

Source: Internal company numbers.

Q2 2014 Production Volumes

Full Quarter = 12,879 boe/d

U.S. Gas

30%

U.K. Gas

U.K. Oil

69%

U.S. Gas

12%

U.K. Gas

U.K. Oil

83%

U.S. Gas

U.K. Gas

30%

U.K. Oil

63%

Confidential

Subject to FRE 408

________________________________________________

Source: Bloomberg, Capital IQ.

Brent and U.K. NBP prices averaged 15% and 140% premium versus WTI and Henry Hub, respectively, since 2011

Production Sold into Higher-Valued European Markets

Crude Oil

Natural Gas

Endeavour’s

U.K.

footprint

enables

sell

into

higher

priced

commodity

markets.

$/boe

$/mcfe

$75

$85

$95

$105

$115

$125

8/30/12

10/30/12

12/30/12

2/28/13

4/30/13

6/30/13

8/31/13

10/31/13

12/31/13

2/28/14

4/30/14

6/30/14

WTI

Brent

$11

$14

8/30/12

10/30/12

12/30/12

2/28/13

4/30/13

6/30/13

8/31/13

10/31/13

12/31/13

2/28/14

4/30/14

6/30/14

Henry Hub

NBP

Confidential

Subject to FRE 408

Reserve Report Summary

2013 Year-End Reserve Report Summary

________________________________________________

Source: Audited year-end 2013 reserve report, except contingent resources, which is an internal engineer estimate.

Note: PV10 amounts are prior to PRT, Corporate Taxes, Supplementary Corporate Taxes, and other local taxes.

Country

Net

(mboe)

PV10

($ 000s)

Net

(mboe)

PV10

($ 000s)

Net

(mboe)

PV10

($ 000s)

U.K. Total

21,573

$757,654

38,149

$1,515,771

55,759

$2,292,183

U.S. Total

1,965

$15,497

1,965

$15,497

3,588

$17,475

Total

23,538

$773,151

40,114

$1,531,268

59,347

$2,309,658

Contingent

Resources

428mm boe

(unrisked)

Confidential

Subject to FRE 408

Favorable Tax Attributes

________________________________________________

Source: Endeavour 2013 10K pages 56-58.

(1)

The calculation of the Petroleum Revenue Tax relates to a six month look-back at production followed by a half-year true up for actual production.

The Company’s current income tax expense relates primarily to its U.K. operations

Endeavour faces multiple tiers of taxation on its U.K. oil and gas production:

•

U.K. corporate tax of 30%

•

Supplementary charge on profits from North Sea production of 32%

•

Petroleum

Revenue

Tax

(“PRT”)

only

the

Alba

field

(1)

2013 income tax expense relates only to PRT taxation

The following outlines an overview of the Company’s operating loss position.

Endeavour International Net Operating Loss Summary (as of 12/31/13)

($ in millions)

NOL

Applicable

Years of

Balance

Rate

Expiration

U.K.

Corporate Tax

$638.5

30.0%

Indefinite

Supplemental Corp. Tax

455.3

32.0%

Indefinite

U.S.

Corporate Tax

$232.7

35.0%

2023-2033

State Income Tax

83.6

Various

Indefinite

Capital Gains Tax

1.8

Various

2015

Confidential

Subject to FRE 408

Endeavour Interest Burden

($ in millions)

Status Quo Cash Flow

2014

2015

2016

UK Unlevered FCF

$123.8

$125.4

$144.0

UK Interest

(32.4)

UK Levered FCF

$91.4

$93.0

$111.6

US Unlevered FCF

(20.7)

(27.5)

(20.8)

US Interest

(76.9)

US Levered FCF

($97.6)

($104.4)

($97.7)

Total Levered FCF

($6.1)

($11.4)

$13.8

Status Quo Interest

Face

Rate

Cost

UK Creditors

MPPs

150.00

9.77%

$ 14.7

Term Loan

125.0

L + 700

10.3

LC Facility ($90mm)

L + 700

7.4

UK Total

$ 275.0

$ 32.4

US Creditors

Sec. First Priority Notes

$ 404.0

12.00%

$ 48.5

Sec. Second Priority Notes

150.0

12.00%

18.0

Convert. Unsec. Notes (5.5%)

135.0

5.50%

7.4

Convert. Unsec. Bonds (6.5%)

17.5

6.50%

1.1

Convert. Unsec. Bonds (7.5% PIK)

82.9

7.50%

Preferred Equity (Series B & C)

40.9

4.50%

1.8

US Total

$ 830.4

$ 76.9

Total

$ 1,105.4

$ 109.3

Confidential

Subject to FRE 408

Overview of Endeavour’s U.K. Assets

Working

Interest

Operating Partners

Alba

25.7%

Chevron (Operator, 23.37%)

Statoil (17%)

Mitsui (13%)

Centrica (12.65%)

EnQuest (8%)

Rochelle

44.0%

Nexen (Operator, 41%)

Premier Oil (15%)

Bacchus

30.0%

Apache (Operator, 50%)

First

Oil

(20%)

Columbus

25.0%

Serica (Operator, 50%)

EOG (25%)

Bittern

2.4%

Shell (Operator, 39.63%)

Dana Petroleum (32.948%)

ExxonMobil (25%)

Field

________________________________________________

Source: Company presentation (April 8, 2014), partner filings, and press releases.

Confidential

Subject to FRE 408

Rochelle Overview –

Blocks 15/26b, 15/26c and 15/27

Endeavour WI:

44%

Operator:

Nexen (41% WI)

Partner:

Premier Oil (15% WI)

Online:

October 2013

The field is a Lower Cretaceous reservoir at 9,900 ft

•

Good quality Britannia Kopervik turbidite sands

•

3-way stratigraphic trap

Flowing gas with associated condensate

•

Both wells have produced at rates of over

million cubic feet of gas per day, with an

additional ~3,000 boe/d of liquids

Production from the wells will exceed the allocated

capacity at the Scott Platform

Rochelle

Jurassic

discovery

–

Rossini

•

P50 reserves potential of 35–80 mmboe

________________________________________________

Source: Company presentation (April 8, 2014), partner filings, and press releases.

Mostyn

Ravel

Rossini

Rochelle

Confidential

Subject to FRE 408

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 production potential with up to 100

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

Confidential

Subject to FRE 408

Rochelle –

Debottlenecking

Opportunity to increase Scott compression capacity

•

Rochelle December 2013 TOCM

Current Capacity is ca 165–170 mmscfd

Possible to debottleneck to ca 207 mmscfd

Contract allows for 60 mmscfd with ‘best

endeavours’

to 100 mmscfd

Available ullageis dependent on Scott and Telford

gas rates

Modifications could increase Rochelle capacity to

100 mmscfd

Proposed Modifications:

•

New Glycol Contactor Demister, Distributor,

Structured Packing and Inlet Device

•

Change out of Stripping Column Pall Rings for

Nutter Rings

•

Change out of Fiscal Metering Orifice Plates

•

Upgrade of load sharing control design

Estimated cost £2.5 million

•

Early long lead items

Target 2014 TAR

Gas Plant Debottlenecking

Confidential

Subject to FRE 408

Bacchus Field Overview

Equity

50.0%

30.0%

20.0%

Block 22/6a North, 290ft water depth

Discovered 2005, first production April 2012

Jurassic Fulmar reservoir at ~12,100ft SS

•

Overpressured and relatively high temperature

–

9474 psi and 290°F

•

Fulmar shoreface sandstones of variable quality

–

~70% NTG / ~19% porosity / 0.1–80 mD

permeability

STOIIP 75 to 100 MMbbls

•

35°

API, 0.68 cP viscosity, GOR 320 scf/stb

•

1.9MMB production to date

Facilities

•

3 well subsea bundle tieback to Forties Alpha

platform

•

Gas lift and produced water re-injection from

Forties

•

Oil export to Forties Pipeline System (FPS), no gas

sales

Future development drilling

Company

Apache (Operator)

Endeavour

First Oil

Confidential

Subject to FRE 408

Bacchus Performance

Field Start-up from B3Y well April 2012

B2 start-up August 2012

•

Maintained ~10,000 bopd through 2012/2013

Drilling break to review and optimise 3rd well

location. Moved to Bacchus West

B1 Start-up August 2013

•

Field production rate increased to 18,000 bopd

Field performance on depletion better than

expectations

1P reserves restricted to depletion case only as

water injection is not “Proved”

under SEC rules

Field performance and reserves under evaluation

post B1 drilling results

3D seismic survey completed to evaluate future

development opportunities

•

B3Y turnround to injection

•

Additional water injection well

•

Additional production well

Confidential

Subject to FRE 408

Bacchus –

Future Development Options

3D seismic shot over Bacchus, processing just completed

Assessment of field performance and history matching ongoing

•

Plan to turn B3Y to water injection

Evaluation of additional development opportunities

•

Additional West water injection well

•

Far East production well

–

Close to original FDP location with pressure support from B3Y when turned to injection

Confidential

Subject to FRE 408

Alba Field Overview –

Block 16/26a

Endeavour WI:

25.68%

Operator:

Chevron (23.37% WI)

Partner:

Statoil (17% WI)

Mitsui (13% WI)

Centrica (12.65% WI)

Enquest (8% WI)

Discovered / 1st Production

1984/1994

Late Eocene reservoir at ~6,200 ft depth

450 ft water depth

35 Platform and subsea wells

Oil exported by tanker

Annual infield drilling campaign of 2–4 wells

•

First well completed in March and the second

well is expected to be on line in the summer

________________________________________________

Source: Company presentation (April 8, 2014), partner filings, and press releases.

Britannia

Alba

Confidential

Subject to FRE 408

A69 (current well) Pre-drill Data

Objectives:

Unswept oil adjacent to A41 wells on east side of Main Alba

Channel

Cum.

oil

from

A41

A41T

0.4MMbbls

2001/2003

–

screen

failures in both

Maximise stand-off to water

Obtain oil sample to refine viscosity (up to 10% impact

EUR)

Target(s):

Tests sand presence beyond Min Sand Boundary

Upper flank of local structural high

Key Uncertainties:

POWC elevation relative to wellbore –

2008 4D contact and

modelled rise

Net sand length –

shale presence

Edge volumes

Cum oil:

•

P90–1.5, P50–2.4, P10–3.4 MMbbls

Designed to test upside potential beyond the Min Sand

Boundary

Planned to maximise stand-off across target area

•

Entry point planned at A41 elevation

•

Shallow hunting angle (88°) enables upside to be tested

Pilot tests the full length of A41 structure and is anticipated

to exit into shale

Confidential

Subject to FRE 408

A69 Results

Uncertainty

Low Case

Base Case

High Case

Actual

Standoff

25 ft

60 ft

75 ft

70–100 ft stand-off

In Place Volume North of AJH

Oil in place reduced by 3 mmbls

Oil in place reduced by 1.8 mmbbls

Oil in place as modelled

Well Elevation –

Standoff

-6370 (15 ft deep to avoid shales)

-6355 ft (Avg Elevation A41T)

-6340 ft (Avg Elevation A41)

6350 ft ss

Net Sand Length

400 ft (similar to A41x)

600 ft (similar to A41T)

800 ft (Upside sand at heel)

963 ft

A69 well results

No sand in edge target

Average elevation 5 ft TVD high to P50

prognosis

1035 ft gross / 963 ft net pay, 93% N:G

Stand-off above Eclipse modelled POWC

–

min 70ft (heel), max 100ft (toe)

No fluid sample obtained

Formation Tops

Prognosed

Actual

Difference

Horizons

MDBRT (ft)

TVDSS (ft)

MDBRT (ft)

TVDSS (ft)

MDBRT (ft)

TVDSS (ft)

Alba Top Reservoir (si99 surface)

16’699

-6’334

Alba Top Reservoir (si99 impedance)

16’774

-6’337

16832

6340

+58ft

+3ft

Poss. Exit (1) Alba Top Reservoir

17’235

-6’344

17162

6345

-73ft

+1ft

Poss. Re-entry (1) Alba Top Reservoir

17’489

-6’347

17207

6346

-282ft

-1ft

Poss. Exit (3) Alba Top Reservoir

17’606

-6’349

–

Exit Alba Top Reservoir

17’670

-6’349

17863

6356

+193ft

+7ft

Confidential

Subject to FRE 408

Alba –

Further Opportunities

Categories

Opportunity

Estimated Incremental Recovery

(Provisional) (mmbbls)

Drilling Infill

Wells

New wells reference plan

BP 15

New wells non-reference plan

BP 15

New wells beyond non-reference plan

4–10

Reservoir

Performance

Injector realignment

5.0–12.5

cEOR

20–50

Topside

Improvements

Field life extension of base well stock

5–15

High water cut well management

5–15

Opportunity Catalogue for Vision 500

Confidential

Subject to FRE 408

Columbus Field Overview

Company

(1)

Equity

Serica (Operator)

50%

Endeavour

25%

EOG

25%

Blocks 23/16f & 23/21, 275ft water depth

Discovered 2006, first production 2014

Palaeocene reservoir at ~9,800ft SS

•

Stratigraphic trap in submarine fan

–

50% NTG / ~19% porosity / ~1 to 50mD

permeability

GIIP ~170 Bcf

•

Gas condensate with CGR ~40 bbl/MMscf

Proposed Facilities

•

Subsea development

–

2 horizontal production wells, depletion

•

Evaluating development / offtake solutions

Field Development Plan draft pending agreement on

host solution

DECC agreed 2 year Licence extension to December

2015

________________________________________________

(1)

Block 23/16f only, extension into block 23/21.

Confidential

Subject to FRE 408

Bittern Field –

Overview

Equity

39.63%

32.95%

25.00%

2.42%

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

Further 4D seismic planned for potential infill well /

recompletion opportunities

________________________________________________

(1)

Plus 1.62% equity in Triton FPSO.

Company

Shell (Operator)

Dana Petroleum

ExxonMobil

Endeavour

(1)

Confidential

Subject to FRE 408

High Quality Exploration in Core Central North Sea Area

Net Unrisked Contingent Prospective Resources:

428

mmboe

28 Licenses (12 Endeavour operated)

Own 105 kilometers of 3D seismic in this core area

History of successful bidding in the Licensing Rounds

with a focus on high quality acreage close to

infrastructure

•

28th Licensing Round in April 2014

Select Prospects:

Upper Jurassic (Galley Sst) –

Rossini

•

Oil prospect

Upper

Jurassic

(Galley

Sst)

–

Mabry

•

Oil prospect

Ravel & Mostyn prospects

•

Low risk R-Block area oil prospects

Buffalo prospect

•

Rochelle analogue

Prospects, Discoveries and Licenses

________________________________________________

Source: Company presentation (April 8, 2014), partner filings, and press releases.

Oil Field

Gas / Condensate Field

END acreage

Other held acreage

Prospects / Discoveries

Development / Producing

Rogers (WI 100%)

Ravel (WI 55.6%)

Buffalo (WI 20–40%)

Rochelle Jurassic (WI 44–100%)

Bittern

Rochelle

Buffalo

Mostyn

Mabry

Enoch

Columbus

Bacchus

Alba

Ravel

Rossini

Exploration Portfolio in Core Central North Sea Area

Confidential

Subject to FRE 408

R–Block

Exploration

Opportunities

–

Rossini

Blocks:

15/26a, 15/26c, 15/27

Reservoir:

Upper Jurassic Gallery Sandstone

Expected Fluid Type:

Oil Prone

Working Interest

50%

–

100%

Rossini was discovered by Endeavour in 2012

•

A large majority of the prospect sits in

block

15/26a, where Endeavour has a 100%

working interest and is the operator

•

P50 reserves potential of 35–80 mmboe

Field lies close to existing infrastructure, but may be

large enough for stand-alone development

Plan to drill in the first half of 2015

460 ft water depth and normally pressured

Significant upside and prospectively in adjacent

Endeavour operated acreage

________________________________________________

Source: Company presentation (April 8, 2014).

Confidential

Subject to FRE 408

Block 14/28a Resources

Mabry Prospect

(1)

•

Upper Jurassic (Galley Sst) reservoir

Morton Prospect

•

Palaeocene (Andrew Sst) reservoir

Traditional License (4 years)

Work Program Summary

•

Drill or Drop (decision end year 2)

–

~1700m TVDSS depth or 50m into Middle Jurassic

•

Mabry Prospect Focus

–

Reprocess 3D seismic data (250 km²)

–

Obtain 2D seismic data (400 km)

–

Reprocess 2D Seismic and integrate with 3D seismic

–

Seismic inversion

–

Basin modelling and migration studies

–

Geological studies (including Biostrat and FIT)

•

Morton Prospect Focus

–

Rock physics modelling

–

Seismic inversion

Mabry

Morton

P5O Reserves

92.4

10.4

Gross Prospective Resources

(boe in millions)

________________________________________________

(1)

Premier Oil – 50% / Endeavour – 50%.

Confidential

Subject to FRE 408

U.K. Financial Forecast

________________________________________________

Note: Assumes that NOL balances offset CT / SCT taxes.

($ in millions, except volumes)

Historical

Forecast

2012

2013

2014

2015

2016

U.K. Oil/NGL Revenue

$206.5

$315.0

$267.3

$257.2

$251.9

U.K. Gas Revenue

0.7

14.3

52.5

119.8

Total U.K. Revenue

$207.2

$329.3

$319.7

$377.0

$371.7

Operating Expense

(51.7)

(98.1)

(86.5)

(83.8)

(84.3)

Gross Profit

$155.5

$231.2

$233.3

$293.2

$287.4

Gross G&A

($33.5)

($31.9)

($22.3)

($21.4)

Allocation to OpEx / Capitalized G&A

19.4

18.7

10.0

9.8

Net G&A

($14.1)

($13.2)

($12.3)

($11.6)

U.K. EBITDA

$141.4

$218.0

$221.0

$281.6

$275.8

PRT

($0.4)

($57.1)

$11.5

($28.1)

($48.7)

Corporate Taxes / SCT

–

U.K. Capex

(174.4)

(158.8)

(112.6)

(128.1)

(83.1)

Working Capital

–

4.0

–

U.K. Unlevered Free Cash Flow

($33.4)

$2.1

$123.8

$125.4

$144.0

Total U.K. Production (BOE/D)

5,489

8,810

9,664

12,734

12,551

Production (Barrels)

Oil/NGL Production (BOE)

1,993,852

3,016,700

2,683,872

2,720,034

2,666,994

Gas Production (MMCF)

91,490

1,194,000

5,079,818

11,585,134

11,580,644

Total U.K. Production (BOE)

2,009,100

3,215,700

3,530,508

4,650,889

4,597,101

Price

Oil/NGL ($/BBL)

$103.57

$104.42

$99.59

$94.56

$94.44

Gas ($/MMCF)

$7.65

$11.98

$10.33

$10.34

Memo:

Alba:

Water

injection

pipeline

resolution and new wells support

growth

Bacchus:

Well

depletion

results

lowered production but natural

declines partly offset by water

injection well s

Rochelle:

2015

production

forecasted to increase as Telford

production declines

Improvement in 2015 operating

margins due to increased volume

and resolution of Alba water

handling

G&A reduction following successful

consolidation of U.K. offices and

reduction of headcount

Production

Margins

Confidential

Subject to FRE 408

U.K. Capital Expenditure Detail

($ in millions)

2014

2015

2016

Non-Discretionary

Alba

($32.1)

($28.4)

($30.0)

Bacchus

(3.5)

(18.3)

(3.5)

Rochelle

(8.4)

(4.8)

(3.0)

U.K. Decomissioning

(59.8)

(56.4)

(37.9)

U.K. Exploration / Other

(3.5)

(5.0)

(3.8)

Total Non-Discretionary

($107.2)

($112.8)

($78.2)

Discretionary

Alba

$ –

Bacchus

–

Rochelle

–

U.K. Decomissioning

–

U.K. Exploration / Other

–

(10.4)

–

Total Discretionary

$ –

($10.4)

$ –

Total Direct U.K. CapEx

($107.2)

($123.2)

($78.2)

Capitalized G&A

(5.3)

(4.9)

Total U.K. Capital Expenditure

($112.6)

($128.1)

($83.1)

Alba

Bacchus

Rochelle

Exploration

2-4 new wells per year

Water injection pipeline repair 2H’14 / 1Q’15

Conversion of production well to water injection well

in 2014

Development of western area water injection well in

2015

General maintenance only in 2016

Completion of East Well in 2014

Enhancements to Scott platform to reduce

bottlenecking in 2015

Maintenance only in 2016

Rossini exploration well in 2015 (assumes partner

covers 66%

of costs)

Confidential

Subject to FRE 408

Overview of Endeavour’s U.S. Assets and Development Strategy

U.S. 4Q 2013 totals

________________________________________________

Note: Acreage as of 9/30/2013.

Source: Company presentation (April 8, 2014), partner filings, and press releases.

Heath

Hold acreage but delay development

Evaluate Statoil results

Marcellus

Advance

proof of

concept

Funded by

Partner

Haynesville

Defer dry gas development

Niobrara/Frontier

Wiley type curve highly promising

Seek partner to test acreage further

442,600 gross / 109,000 net acres

Average of 6 mmcfe/d net

production

Working

Interest

Operating Partners

Haynesville

50.0%

J-W (50%)

Marcellus

50.0%

JV Partner

Heath

25.0%

JV with Two Independent

Montana Producers (75%)

Others

75.0%

Retamco (25%)

Confidential

Subject to FRE 408

Endeavour –

NW Colorado Niobrara Opportunity

Pursuing liquids-rich, Stacked Niobrara / Frontier plays

in the Piceance Basin, NW Colorado

Play

Wiley

(3-5N

–

97W)

25,000 gross / 17,000 net acreage

Gas + liquids play via multi-stage fracs

Identified key wells with volatile oil maturity in

brittle, over-pressured rock

Captured lands just downdip into wet gas window

Play

Hunter/Garvey

(8S

–

100-101W)

15,000 gross / 11,000 net ac F/I

Volatile oil play

Targeted structure with open fractures

Frontier Ss ‘carrier bed’

to enhance production

Rangely

Niobrara

15 mmbo

Buck Peak Niobrara

trend

20–30 mmbo

WPX 16 mmcf/d

Niobrara well

Encana’s Orchard

Niobrara gas development

Wiley Prospect

Pilot drilled, cored 7/13

Hunter-Garvey Prospect

Cored pilot 9/13

Structure on top Rollins Ss, c.i. 500’

NBRR

Petroleum

System:

Proven

productive

areas

Oil window

Wet gas window

Dry gas window

Piceance

Basin

Colorado

________________________________________________

Source: Company presentation (April 8, 2014).

Confidential

Subject to FRE 408

Piceance Basin Niobrara

–

Industry Activity

Axia / Oxy

Mesa / WPX

Whiting

Encana

Black Hills

Endeavour Project Areas

Wiley (W) and Hunter / Garvey (H)

(Structure on top Rollins Ss, c.i. 500’)

________________________________________________

Source: Company presentation (April 8, 2014).

Area Participants

Buck Peak trend

20-30 mmbo

Winter Valley

80 mbo

WPX 16 mmcf/d

Niobrara well

Rangely

15 mmbo

Confidential

Subject to FRE 408

Marcellus Industry Activity in END Play Area

Reported Marcellus EURs 6–8+ Bcf

Seneca –

N. Cameron County

•

5500’

laterals, 37–stage fracs

•

IP’s 7–11 mmcf/d

•

EUR’s 6–8 bcf

•

Targeting < $6–7 million CWC’s (full pad

development)

EOG

Seneca

–

Northern

Clearfield

Co.

•

Recent IP’s 7–9+ mmcf/d

PGE / Exxon –

SE McKean County

•

5000’–7600’

laterals

•

IP’s 6–9 mmcf/d

END EOG Seneca Ultra PGE/Exxon

Seneca Geneseo

Seneca Utica well

EOG

PGE long laterals

7000+’

5000+’

Isopach of Marcellus Shale, c.i. = 50’

Seneca 6–8 bcf

________________________________________________

Source: Company presentation (April 8, 2014).

Confidential

Subject to FRE 408

Pennsylvania Marcellus Assets

In October 2013, closed a 50% sale / joint venture

with Samson Exploration, LLC

•

Provides development capital for Daniel Project

“proof of concept”

27,000 net acres (majority held by production), END-

operated

400–600+ bcfe net resource potential

1 tcf potential including adjacent state land

5 producing wells with 3 horizontal wells waiting on

completion

10 mmcf/d of take-away capacity on the EQT line

available by mid-year

________________________________________________

Source: Company presentation (April 8, 2014).

Confidential

Subject to FRE 408

U.S. Financial Forecast

________________________________________________

Note: Assumes that NOL balances offset taxes.

($ in millions, except volumes)

2014

2015

2016

U.S. Oil Revenue

$0.3

$4.0

$7.3

U.S. NGL Revenue

0.0

1.7

2.9

U.S. Gas Revenue

10.5

15.4

18.7

Total U.S. Revenue

$10.9

$21.1

$28.8

Operating Expense

(7.6)

(7.3)

(8.4)

Gross Profit

$3.4

$13.8

$20.5

Gross G&A

$ (12.3)

$ (12.1)

Allocation to OpEx / Capitalized G&A

10.3

10.1

Net G&A

$ (2.0)

U.S. EBITDA

$1.4

$11.8

$18.5

Corporate Taxes

–

U.S. CapEx

(22.0)

(39.3)

Working Capital

–

U.S. Unlevered Free Cash Flow

($20.7)

($27.5)

($20.8)

Total Production (BOE/D)

1,215

1,970

2,461

Production (Barrels)

Oil Production (BBL)

3,855

44,270

81,209

NGL Production (BOE)

701

25,513

42,468

Gas Production (MMCF)

2,639,811

3,887,652

4,660,862

Total US Production (BOE)

444,524

717,725

900,487

Price

Oil ($/BBL)

$90.27

$90.01

$90.00

NGL ($/BOE)

$67.50

Gas ($/MMCF)

$3.99

$3.96

$4.00

Memo:

Marcellus

–

Advance proof of concept through

Samson JV

Complete EQT pipeline in 2014

3 new wells per year in 2014 -2016

Production growth following new wells in 2014-

2016 developed through Samson JV

Piceance

–

Seek partner to test acreage

Complete Wiley and develop straight-hole at

Hunter Garvey

4 new wells in each of 2015, 2016

Production increases during forecast period

following further development

Haynesville

–

Defer dry gas development

No additional well development

Production declines throughout forecast period,

with 2016 production falling to 67% of 2015

production

Pricing/ Costs

Flat commodity pricing forecasted throughout

projection period

Confidential

Subject to FRE 408

U.S. Capital Expenditure Detail

($ in millions)

2014

2015

2016

Non-Discretionary

Marcellus

($5.9)

($14.8)

Piceance

(10.0)

(15.0)

Haynesville

(3.5)

Total Non-Discretionary

($15.9)

($33.3)

Discretionary

Marcellus

$ –

Piceance

(1.0)

Haynesville

–

Total Discretionary

($1.0)

Total Direct U.S. CapEx

($16.9)

($34.3)

Capitalized G&A

(5.2)

(5.0)

Total U.S. Capital Expenditure

($22.0)

($39.3)

Marcellus

3 new wells in 2014 with costs carried by Samson

3 new wells per year in 2015 and 2016 with costs shared

with Samson

Piceance

Complete Wiley and develop straight-hole at Hunter

Garvey (with partner) in 2014

4 new wells in each of 2015, 2016, developed with partner

paying 50%

Additional $1mm per year discretionary seismic CapEx

Haynesville

$3.5mm/year commitment to JW in 2015/2016 for re-

completions

Confidential

Subject to FRE 408

Key Business Highlights

Strong operating momentum on a go-forward basis:

Strong growth in production with proven operating margins

•

2013 production 9,922 boe/d represents a 26% year-over-year increase

•

Q2’14 physical production 12,879 boe/d

•

Brent crude oil and European natural gas exposure generate exceptional operating margins

Opportunities to further grow UK production

•

Potential to increase Scott platform capacity in the future

•

Promising future developments at Rossini and Mabry

•

Alba infield drilling opportunities and resolution of water injection issues provide steady cash flow

Future upside through US portfolio

•

Positive results in Colorado

•

JV partnership with Samson to develop Marcellus

Confidential

Subject to FRE 408

Existing Capital Structure

________________________________________________

Source: Company filings.

Note: Debt balances as of 9/30/14.

(1)

Term Loan, Procurement Agreement and 6.5% Convertible Bond mature October 2015 if 7.5% and 5.5% Convertible Bonds are not refinanced or extended.

(2)

Assumes LTM 1Q 2014 EBITDA of $217.3 million.

(3)

Libor floor of 1.25%.

($ in mm)

Book

Maturity

Interest Rate

Principal

EBITDA x

(2)

Term Loan

Nov-17 (Oct-15

(1)

)

L+700

(3)

$ 125.0

Monetary Production Payments

Various

9.8%

150.0

$90mm Procurement Agreement (Contingent)

Nov-17 (Oct-15

(1)

)

L+700

(3)

Total EEUK Debt and Claims

$ 275.0

1.3x

First Priority Notes

Mar-18

12.0%

404.0

Second Priority Notes

Jun-18

12.0%

150.0

Total Secured Debt

$ 829.0

3.8x

Convertible Unsecured Notes

Jul-16

5.5%

$ 135.0

Convertible Unsecured Bonds

Nov-17 (Oct-15

(1)

)

6.5%

17.5

Convertible Unsecured Bonds

Jan-16

7.5%

82.9

Total Debt

$ 1,064.4

4.9x

Series C Preferred

4.5%

$ 37.0

Series B Preferred

4.5%

3.9

Common Equity: $0.57 per share as of 09/04/14

28.5

Total Capitalization

$ 1,133.8

5.2x

Confidential

Subject to FRE 408

Endeavour Interest Burden

($ in millions)

Status Quo Cash Flow

2014

2015

2016

UK Unlevered FCF

$123.8

$125.4

$144.0

UK Interest

(32.4)

UK Levered FCF

$91.4

$93.0

$111.6

US Unlevered FCF

(20.7)

(27.5)

(20.8)

US Interest

(76.9)

US Levered FCF

($97.6)

($104.4)

($97.7)

Total Levered FCF

($6.1)

($11.4)

$13.8

Status Quo Interest

Face

Rate

Cost

UK Creditors

MPPs

150.00

9.77%

$ 14.7

Term Loan

125.0

L + 700

10.3

LC Facility ($90mm)

L + 700

7.4

UK Total

$ 275.0

$ 32.4

US Creditors

Sec. First Priority Notes

$ 404.0

12.00%

$ 48.5

Sec. Second Priority Notes

150.0

12.00%

18.0

Convert. Unsec. Notes (5.5%)

135.0

5.50%

7.4

Convert. Unsec. Bonds (6.5%)

17.5

6.50%

1.1

Convert. Unsec. Bonds (7.5% PIK)

82.9

7.50%

Preferred Equity (Series B & C)

40.9

4.50%

1.8

US Total

$ 830.4

$ 76.9

Total

$ 1,105.4

$ 109.3

Confidential

Subject to FRE 408

Corporate Structure

________________________________________________

Note: Dollar amounts represents face value as of 9/30/14 and excludes any accrued interest or OID.

(1)

EIC has issued secured guarantees of both the Cidoval MPP and the Sand Waves MPP. EOC has issued a secured guaranty of

only the Sand Waves MPP.

(2)

$125.0mm intercompany is guaranteed by EIC.

(3)

$500.0mm intercompany is subject to payment subordination in favor of Term Loan and LC Facility.

$40.9mm Series B & C Preferred

U.S. Issued Debt

$404.0mm March 2018 12% Notes

$150.0mm June 2018 12%Notes

$135.0mm 5.5% 2016 Converts

$82.9mm 7.5% 2016 Converts

Endeavour Energy U.K. Limited

(English/Welsh Corp.)

Endeavour International

Corporation (NV)

(2)

Endeavour North Sea Limited

(English/Welsh Corp.)

Endeavour Energy

Luxembourg S.à

r.l. (Lux. Corp.)

$125.0mm Term Loan

$90.0mm LC Facility

$150.0mm Monetary Production

Payments

European Issued Debt

Endeavour Energy North Sea,

L.P. (DE)

Intercompany

Note

($500.0mm)

(3)

Intercompany Note ($82.9mm)

Endeavour Operating

Corporation (DE)

(65% Pledge of Capital Stock)

Secured Issuer/Borrower

Unsecured Issuer/Borrower

Unsecured Guarantor

Lien

Claim Type

Equity

Secured Guarantor

Endeavour International

Holding B.V. (Netherlands)

Intercompany

Note

($125.0mm)

(2)

Endeavour Colorado Corp.

(DE)

$17.5mm 6.5% 2017 Converts

END Finco LLC (DE)

Endeavour Energy New

Ventures Inc. (DE)

END Management Company

(DE)

Endeavour Energy North Sea

LLC (DE)

Endeavour Energy Netherlands

B.V. (Netherlands)

99.9%

0.1%

(1)

Confidential

Subject to FRE 408

Monetary

Production

Payment

–

Repayment

Schedule

The following chart outlines the timing profile of the Company’s remaining MPP payments.

MPP Payments

($ in millions)

________________________________________________

Note: Includes both principal and interest payments.

$10

$55

$54

$12

$21

$10

$20

$30

$40

$50

$60

Apr-14

Jul-14

Oct-14

Jan-15

Apr-15

Jul-15

Oct-15

Jan-16