Exhibit 99.1
 

Investor Presentation January 2008

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.

History and Strategy

Endeavour at a Glance Proved reserves of 9.1 mmboe1 Proved + probable reserves of 30 mmboe1 Proved + probable + possible reserves of 68 mmboe1 Significant resource potential of 1.1 bboe net unrisked 2007 production in excess of 9,000 boepd (an increase of over 300% from 2006) Acreage - 2.3 mm gross and 0.7 mm net2 Strong financial position YTD September Discretionary cash flow $79 million EBITDA of $92 million Debt to capital approximately 50% Successful executive team with significant North Sea experience Endeavour Acreage 100 km Endeavour Production Endeavour Developments Endeavour Stranded Gas Discoveries 2Includes 500,000 acres to be awarded from the 2007 APA 1Independent determination by Netherland, Sewell & Associates as of 1 July 2007

Company History NSNV founded Transier and Seitz started private company Acquired MegaSurvey 3D seismic data from PGS Creation of Endeavour Merged with publicly-traded CSOR Management team and strategy focused in the North Sea Acquired producing properties in Norway Awarded 9 UK licenses Awarded 13 production licenses 11 in the UK and 2 in Norway Launched exploratory drilling program Acquired interest in Enoch Field Acquired asset package from Talisman 7 oil and gas producing fields and 1 undeveloped field in the UK Awarded 13 production licenses 8 in the UK and 5 in Norway Exploration successes at Cygnus and Columbus Produced in excess of 9,000 boepd (an increase of over 300% from 2006) Generated sufficient cash flow to fund capital program and reduce debt by $40mm Successfully appraised Columbus discovery Announced strategic investment from Smedvig family 2003 2004 2005 2006 2007

North Sea Focused Strategy Word.Picture.8 Balance from all four strategic components

Executive and Technical Teams Executive Team 130 years combined experience Excellent reputation and track record of creating value Committed to excellence Technical Team Experienced - over 20 years average experience Balance of talent/skills - 21 geoscientists and 9 engineers Predominantly located in the UK and Norway

Executive Team Executive Team Executive Team Bruce H. Stover Executive Vice President, Operations and Business Development 35 years global energy experience Founding member of Endeavour management team Anadarko - 23 years Amoco - 8 years B.S. Petroleum Engineering William L. Transier Chairman, President and Chief Executive Officer 30 years global energy experience Co-founder of Endeavour Ocean Energy - 4 years Seagull Energy - 3 years KPMG - 20 years B.B.A. Accounting, M.B.A.

Executive Team, continued John G. Williams Executive Vice President, Exploration 30 years global and North Sea exploration experience Conoco and ConocoPhillips - 26 years Exxon - 4 years (USA focus) B.S. and M.S. Geology J. Michael Kirksey Executive Vice President, Chief Financial Officer 30 years global energy experience Keystone International - 8 Years Metals USA - 5 Years Ion Geophysical - 2 Years Sirva - 2 Years Arthur Andersen - 13 Years B.S. Accounting

Why the North Sea

North Sea Attributes Prolific, world class hydrocarbon basins Large resource potential Significant discoveries still being made Extensive infrastructure with capacity Effective recycling of acreage Support of host governments - reliable fiscal systems Space exists for Endeavour to compete North Sea opportunities for Endeavour Opportunity rich, business friendly environment

Prolific, World-Class Hydrocarbon Basins BBB+ AAA BBB AAA AA- AAA B+ A AAA AA BB- NR BB- AAA NR AA- BB- NR AA- BB+ BBB- Key Global hydrocarbon producing countries Key OECD hydrocarbon producing countries Source: Lambert Energy Advisors using BP Statistical Review 2007, Fitch's Standard & Poor's Sovereign Rating

Large Resource Potential Large Resource Potential Large Resource Potential Large Resource Potential Large Resource Potential Reserves Legend Produced 2P Remaining Yet to find Source: Lambert Energy Advisory using DEA, DTI, MEA, NPD Remaining Potential 52 bn boe Remaining Potential 23 bn boe Remaining Potential 2 bn boe Remaining Potential 11 bn boe

Significant Discoveries Still Being Made Exploration success continues Majority of discoveries proximal to producing fields Emerging core areas are also near discoveries and producing fields Industry discoveries tend to be in the 10 to 100 mmboe range Average discovery is around 40 mmboe in the UK, slightly larger in Norway

Extensive Infrastructure with Capacity Except for Norwegian gas, all production is declining Pipeline systems in place with growing ullage All "hub" facilities and infrastructure remain in place Source: Lambert Energy Advisors using BP Stats, Petroleum Economist, Wood Mackenzie, LEA Estimates UK

Effective Recycling of Acreage Endeavour Acreage 100 km Endeavour Production Endeavour Developments Endeavour Stranded Gas Discoveries White area is open acreage Held acreage is grey and in the productive areas Around 40 fallow discoveries in the UK in 2007 with reserves typically 1 to 5 mmboe Columbus discovery is on a formerly fallow block relinquished by a major company Feedstock for portfolio replenishment

Support of Host Governments - Reliable Fiscal Systems Production Sharing Contract Royalty & Tax OECD Tax & Royalty systems tend to take lower proportions than non- OECD PSC regimes Source: Lambert Energy Advisors Operating in stable economic environment

Space Exists for Endeavour to Compete Positioned to be a leading player Percent in North Sea

North Sea Competitive Landscape Source: Hannon Westwood, UKCS Review October 2007 Endeavour

North Sea Opportunities For Endeavour Exploration - license rounds and fallow acreage Fallow discoveries Farm-ins - trades Development and Exploitation Production acquisitions Corporate consolidation A world class hydrocarbon system - opportunity rich

Assets and Operations Overview

Competent Person's Report - Summary Required for the London Stock Exchange listing Independent determination by Netherland, Sewell & Associates as of 1 July 2007 Confirms internal estimates of reserves & potential resources Validates prospectivity in portfolio Strong reserve base and excellent resource potential

2007 Reserve and Resource Summary Strong reserve base and excellent resource potential

Future Organic Growth Potential Cygnus development and appraisal Columbus development and nearby exploration R-blocks exploitation, development and exploration Agat exploration and development New exploration drilling Endeavour's North Sea focus has solid near term growth potential

Potential Production Growth Existing opportunities have potential to deliver strong production Production - Net BOEPD 2007 2012 R - Blocks Columbus Njord Gas Blowdown Cygnus FB I R-Blocks Phase II 2008 Risked Exploration 2009 Risked Exploration Cygnus Phase II Base

UK Producing Assets

Renee IVRRH Rubie Alba Goldeneye Enoch Bittern United Kingdom Norway Central North Sea

Alba Field: Block 16/26 Central North Sea D10 212ft MD D-10 Horizontal Log Alba SS Alba Field 16/26 A59 location Legend Producing wells Water injector wells 1 Km AXS platform ANP platform Development locations Endeavour acreage Operator: Chevron First Production: January 1994 Producing Horizon: Eocene Alba sandstone @ 6200 ft Drive Mechanism: Volumetric with pressure support from water injection Facilities: Alba North Steel Platform (ANP) - processing, drilling and accommodations + subsea template Wells: 37 producers & 7 water injectors Sales: Crude stored on floating storage unit (FSU) 3 km west of fixed steel platform, crude sold from FSU via tanker loading. Gas export to Britannia for fuel use Ownership: Endeavour - 2.25%; Chevron - 23.37%; Conoco Phillips - 23.43% Statoil - 17%; BP 13.30%; Total - 12.65%; Cieco Energy 8.8% Water Depth: 460 ft Est. Abandonment: 2019

Bittern: Block 29/1b Central North Sea Operator: Shell First Production: April 2000 Producing Horizon: Eocene Forties sandstone @ 6700 ft Drive Mechanism: Limited natural water drive with pressure support via water injection Facilities: 2 Subsea Manifolds tied back to Triton floating production, storage and offloading (FPSO) unit for crude & gas processing Wells: 4 producers & 2 water injectors Sales: Crude sold from Triton FPSO via shuttle tankers, gas sales & NGLs exported via Fulmar gas line to St. Fergus terminal for processing Ownership: Endeavour - 2.4%; Shell - 39.4%; Hess - 29.1% Esso 24.3% Petro Canada - 4.8% Water Depth: 300 ft Est. Abandonment: 2013 29/1b-5 Log Bittern Sandstone Bittern Field 29/1b B2 B1 A3 A2 B3 A1 OWC GOC A B B4 Producing wells Water injector wells Platform Legend 1 Km Endeavour acreage

Enoch: UKCS Block 16/13a & NCS 15/5g South Viking Graben Operator: Talisman First Production: May 31, 2007 Producing Horizon: Eocene Flugga Sandstone Fluid Type: Oil and gas cap Development Plan: Commenced mid 2005. Single horizontal producer to spud mid-July 2006, sub sea tie-back to Marathon's Brae A platform and associated topside work completed in May 2007 Wells: One horizontal producer Ownership: Endeavour 8%;Talisman 25.2%; Bow Valley Petroleum 12%; Roc Oil 12%; Dana Petroleum 8.8%; Altinex 4.3%; Statoil 11.8%; Dyas 14%; DONG Norge 1.9%; DNO 2% Water Depth: 380 ft Est. Abandonment: 2013 Flugga Sandstone: Eocene 16_13a3 Well Enoch Field Enoch 16/13 U.K. Norway 16/13a-7 1 Km Producing well Legend Endeavour acreage

Goldeneye: Block 20/4b Central North Sea Operator: Shell First Production: October 2004 Producing Horizon: Lower Cretaceous Captain sandstone @ 8300 ft Drive Mechanism: Combination gas expansion with water drive Facilities: Producing from 4-leg piled platform, multiphase flow via 65 mi. 20" gas line to Segal terminal at St. Fergus onshore for liquids processing Wells: 5 producing gas wells Sales: All gas, condensate and NGLs sold at the Segal terminal Ownership: Endeavour 7.0%; Shell 49.0%; ESSO 39%; Centrica 5.0% Water Depth: 400 ft Est. Abandonment: 2013 Goldeneye Reservoir Type Log (Well 14/29A-3) Goldeneye Field Determination Area 20/3 14/28 14/29 20/4 1Km FWL Goldeneye Field 14/29a-3 14/29a-5 20/4b-7 20/4b-6 1Km Producing wells Legend Endeavour acreage

IVRRH - Blocks 15/27 & 28 Central North Sea IVRRH Stratigraphic Section Operator: Amerada Hess First Production: July 1989 Producing Horizon: Ivanhoe, RobRoy, & Hamish - Upper Jurassic Piper @ 7800' Drive Mechanism: Volumetric depletion with pressure support via water injection Facilities: Production from subsea tiebacks to AH00I Floating Production Unit (FPU) Wells: IVRRH wells: 7 producers & 3 water injectors Sales: Production processed at the AH00I and transported via pipeline to the Claymore platform on to the Flotta terminal for sales Ownership: Endeavour 23.5%, Hess 76.5% Water Depth: 475 ft Est. Abandonment: 2014 IVRRH Field Ivanhoe RobRoy Hamish 15/21 407 21 25 16 29 12a 11 17 19 8 28 3 32 58 Legend Producing wells 1 Km Endeavour acreage

Renee Field - Blocks 15/27 & 28 Central North Sea Operator: Endeavour First Production: February 1999 Producing Horizon: Upper Jurassic Piper/Scott sandstone Drive Mechanism: Water drive Facilities: Production from subsea tieback to AH00I Floating Production Unit (FPU) Wells: One producer (currently shut-in due to pipeline constraints) and one idle water injection well Sales: Production processed at the AH00I and transported via pipeline to the Claymore platform on to the Flotta terminal for sales Ownership: Endeavour 77.5%; Hess 14.0%; Marubeni 8.5% Water Depth: 475 ft Est. Abandonment: 2014 Renee Scott 15/27 15/27-6 15/27-8 15/27-7 15/27-2 15/27-1 Potential horizontal location Wells logged with pay not-producing Legend 1 Km Potential horizontal sidetrack location Water Injector Well Dry hole Endeavour acreage

Rubie Field - Blocks 15/27 & 28 Central North Sea Operator: Endeavour First Production: May 1999 Producing Horizon: Upper Jurassic Piper/Scott sandstone Drive Mechanism: Water drive Facilities: Production from subsea tieback to AH00I Floating Production Unit (FPU) Wells: One producer Sales: Production processed at the AH00I and transported via pipeline to the Claymore platform on to the Flotta terminal for sales Ownership: Endeavour 40.8%; Hess 19.2%; Marubeni 40.0% Water Depth: 475 ft Est. Abandonment: 2014 Rubie Sele 15/28b Discovery Well 15/28b-7 15/28b-4 Potential dual horizontal locations Legend Wells logged with pay not-producing Legend Potential horizontal sidetrack location Dry hole 1 Km Endeavour acreage

NORWAY Producing Assets

Brage Njord Norway Norwegian North Sea

Brage Field: Block 31/4 North Sea Operator: Norsk Hydro First Production: October 1993 Producing Horizon: Jurassic sandstone; Statfjord @ 7 680 ft, Fensfjord @ 6 970 ft, Sognefjord @ 6 920 ft Drive Mechanism: Water injection and natural depletion Facilities: Fixed integrated production, drilling and accommodation facility with a steel jacket. Wells: 22 producers & 8 water injectors (40 slots) Sales: A oil pipeline to Oseberg and on through the pipeline in the Oseberg Transport System (OTS) to the Sture terminal. Sold at outlet flange on Sture. A gas pipeline is tied back to Statpipe. Sold at outlet flange on Karsto Ownership: Endeavour 4.44%; Norsk Hydro 20%; Talisman 34.26%; Petoro 13.4%; Statoil 12.7%; Altinex 12.62%; Revus 2.57% Water Depth: 460 ft Est. Abandonment: 2019 Statfjord 70 ft Brage Field 30/6 31/4 Brage Unit STATFJORD SOGNEFJORD FENSFJORD BRENT A-35 location A-28 location Knockandoo location A-18 location Development locations Producing wells 1 Km Legend Endeavour acreage

Njord Field: Block 6407/10 and 6407/7 North Sea Ile 105 ft Tilje 415 ft Tilje Well A-16H Operator: Norsk Hydro First Production: September 1997 Producing Horizon: Middle Jurassic sandstone; Ile @ 9100 ft, Tilje @ 9700 ft Drive Mechanism: Gas injection and natural depletion Facilities: Steel semi-submersible drilling, accommodation and production facility (Njord A), oil offloaded from a storage vessel (Njord B) Wells: 8 producers & 4 gas injectors (18 slots) Sales: Crude stored on vessel 2.5 km northeast of semi-submersible platform, crude sold from storage vessel via tanker loading Ownership: Endeavour 2.5%; Norsk Hydro 20%; EON Ruhrgas 30%; Gaz de France 20%; Exxon 20%; Petoro 7.5% Water Depth: 1000 ft Est. Abandonment: 2018 Njord Field 4 12 17 6407/7a 6407/10a 5 6 7 8 9 10 11 13 14 16 18 T2 drilling location T5 drilling location Legend Producing Wells Gas Injector Wells Platform 2.5 Km Development locations Endeavour acreage

UK Developments

Rochelle Columbus Discovery United Kingdom Norway Cygnus Discovery Central North Sea

Columbus Discovery 23/16f - UK Asset Summary UK Norway Netherlands Columbus Basin: Central Graben Interest: Serica (Op) 50% 50% Endeavour 25% 25% EOG 25% 25% Reservoir: Forties sandstone Estimated reserves: 112 bcfe Discovery results: Flowed 17.5 mmcfpd+1mbcpd Flowed 17.5 mmcfpd+1mbcpd Flowed 17.5 mmcfpd+1mbcpd Appraisal wells: 23/16f-12 40' pay sands 23/16f-12 40' pay sands 23/16f-12 40' pay sands 23/16f-12z 70' pay sands 23/16f-12z 70' pay sands 23/16f-12z 70' pay sands 2008 work program: 1) Secure host platform, com------mercial agreements 2) Procure long-lead materials 1) Secure host platform, com------mercial agreements 2) Procure long-lead materials First production: 2009/2010 2009/2010 Columbus Discovery Well 23/16f-11 23/16f Columbus Appraisal Wells 23/16f-12 & 23/16f-12z Discovery wells Legend 1 Km END acreage

Cygnus Discovery 44/11 & 12 - UK Asset Summary UK Norway Netherlands Cygnus Basin: Southern Gas Basin Interest: GdF (Op) 25% Endeavour 12.5% Tullow 35% E. ON Ruhrgas 27.5% Reservoir: Leman and Carboniferous ss Estimated reserves: FB1 165 bcf 2008 work program: 1) Secure host platform, ----commercial agreement 2) Procure long-lead facilities -----materials 3) Drill FB1 producing well 1) Secure host platform, ----commercial agreement 2) Procure long-lead facilities -----materials 3) Drill FB1 producing well First production 2009 44/12-1 44/12-2 Leman Sst Carboniferous GWC - 11313' NNW SSE III IV IIa IIb I Va Vb Vc 44/11 44/12 Potential horizontal location FBIIb Exploration location Legend 1 Km Discovery wells Exploration location Potential horizontal sidetrack location Endeavour acreage

Rochelle 15/27 - UK Asset Summary UK Norway Netherlands Rochelle Basin: Moray Firth Interest: Endeavour (Op) 55.6% Nexen 44.4% Reservoir: Britannia ss Estimated reserves: Proprietary 2008 work program: 1) Evaluate development/timing ----of discovered 4-way 2) Drill exploration well to test ------stratigraphic trap 3) Develop fast-track ----------------commercialization scenarios 1) Evaluate development/timing ----of discovered 4-way 2) Drill exploration well to test ------stratigraphic trap 3) Develop fast-track ----------------commercialization scenarios First production: 2010

Rig & Services - Costs Rigs and related services market will remain tight Cost have escalated by 300% since 2003 Endeavour and partners have rig commitments well into 2009 Crude prices up 400% Margins have increased for companies with production

North Sea Semisubmersibles Dayrates Utilization Source: Credit Suisse using ODS Petrodata

North Sea Jackups Dayrates Utilization Source: Credit Suisse using ODS Petrodata

Exploration Overview

2008 Exploration Work Program Planned participation is five wells in 2008 Cygnus Fault Block IIb (Cygnus Focus Area) Rochelle Stratigraphic Trap (R Block Focus Area) Jade (Agat Focus Area) Tesla (Columbus Focus Area) Brage Exploration Tail Four additional 2008 wells possible Noatun C (Njord Field Area) Galtvort (Njord Field Area) Mon Aegis Four emergent focus areas R Blocks Rubie, Renee, Rochelle, and 2008 Exploration Columbus Successful appraisal and 2008 Exploration Cygnus Fault Block 1 Development and 2008 Appraisal Agat Two gas discoveries and 2008 Exploration Contingency for sidetracks Accelerates reservoir characterization and appraisal Reduces cycle time Saves rig mobilization costs

2.2 2.5 SW NE 10 km 11a 12a IIb 2 km III IV IIa IIb I Va Vb Vc I I CYGNUS FAULT BLOCK IIb Operator: Gaz de France 25% Partners: Endeavour 12.5% Tullow Oil 35% E.ON Ruhrgas 27.5% Well Timing: 3rd Quarter Rig Type: Jack-Up Low risk appraisal well designed to find incremental gas reserves in a fault block adjacent to the discovery in fault block I that is a planned phase one Cygnus development project and focus area. Tyne North Hawkley Tyne West Tyne South Gordon Cygnus Fault Block IIb Appraisal - UK 44/11a & 12a Munro

Rochelle Stratigraphic Upside - UK 15/27-2 SE N 2.0 2.5 2 km S NW ROCHELLE STRATIGRAPHIC TRAP Operator: Endeavour 55.6% Partner: Nexen 44.4% Well Timing: 3rd Quarter Rig Type: Semisubmersible (Nexen) A well designed to test incremental hydrocarbons up-dip from the Rochelle oil and gas discovery, a four way structure containing commercial volumes in the R Block focus area.

Jade (Agat Area) - Norway 35/3 SE NW 35/3-2 Jade Karneol 2.5 2.7 10 km 1 km Karneol Jade JADE Operator: Endeavour 65% Partners: RWE Dea 15% VNG 20% Well Timing: 3rd Quarter Rig Type: Bredford Dolphin Semisubmersible A well designed to find incremental gas to existing discoveries in the Agat focus area to move the block toward development. The block contains an additional ten prospects that could provide additional follow-on drilling. 35/3-4

Tesla - UK 22/24c & 25c 10 km 3.5 4.0 E W Tesla 2 km 24c 25c Tesla TESLA Operator: Gaz de France 25% Partner: Endeavour 25% Partner: E.ON Ruhrgas 25% Partner: RWE 25% Well Timing: 3rd Quarter Rig Type: High End Jack-Up A well designed to test for hydrocarbons in a large prospect in a high temperature, high pressure environment in the Columbus focus area. Skua Skjia Fiddich Arkwright Brechin Marnock Mirren Turnstone Monan Mungo Seagull Heron

Brage North Exploration Tail - Norway 31/4 BRAGE NORTH Operator: StatoilHydro 32.7% Partners: Endeavour 4.44% Talisman 34.26% Noreco 12.62% Revus 2.57% Petoro 13.4% Well Timing: 3rd Quarter Rig Type: Platform Brage North is an exploration tail of a production well. The tail is designed to test for oil in two prospects in the northern part of the Brage field, the Knockandoo Brent reservoir and the Talisker Statfjord reservoir. Production Target Exploration Target Exploration Target 2.0 2.3 1 Km PL 053 PL 055 Fensfjord Talisker Statfjord Knockandoo Brent Sognefjord Statfjord

NOATUN C Operator: StatoilHydro 20% Partners: Endeavour 2.5% Gaz de France 20% E.ON Ruhrgas 30% ExxonMobil 20% Petoro 7.5% Well Timing: 2nd Quarter Rig Type: Semisubmersible Near field well designed to find incremental gas in a seismically well defined three way tilted fault block that if successful, would tie to Njord infrastructure. Noatun C - Norway 6407/7 E W Noatun C Noatun D Onyx Ile Fm (top reservoir) Tilje Fm Are Fm (base reservoir) 10 km 1 km 3.7 4.0 Garn West Draugen ? Njord

Galtvort - Norway 6407/8 & 9 2.0 2.5 Draugen Galtvort Galtvort S Gygrid Flat seismic event at prospect Gygrid 10 km 2 km W E GALTVORT Operator: StatoilHydro 30% Partners: Endeavour 7.5% Gaz de France 20% E.ON Ruhrgas 17.5% Petoro 7.5% Noreco 17.5% Well Timing: 4th Quarter Rig Type: Semisubmersible A near field well designed to test for oil in a four way dip structure with "seismic amplitude support" located northeast of Njord field. Other prospects exist in acreage that could be considered for drilling given success at Galtvort. Garn West ? ? Njord

Mon - Norway 25/5 2008 2.0 2.3 NW SE Mon Prospect Monster Mon Frigg sst Hermod sst 5 km 2 km MON Operator: Lundin 60% Partner: Endeavour 40% Well Timing: 4th Quarter Rig Type: Semisubmersible A near field well designed to find oil reserves in "seismic amplitude supported" Eocene and Paleocene stratigraphic traps in a neighbourhood of past successes. The well could slip to a 2009 spud date. If the Mon well is successful, there is a follow-on prospect to the southeast called Monster. Lille Froy Froy Vale Vilje

Aegis - Norway 25/10 Aegis Buhund Grane Balder 2.0 2.5 Aegis 25/10-7s 25/10-2 Eoc. Mrkr A Balder Mrkr 10 km 2 km E SW NE W 25/10 AEGIS Operator: Lundin 50% Partner: Endeavour 20% Aker 30% Well Timing: 4rd Quarter Rig Type: Aker Barents Semisubmersible A well designed to test for oil in a stratigraphic prospect defined by weak seismic amplitudes but having a good chance of sandstone reservoirs based on excellent regional sedimentologic studies of the Eocene and Paleocene reservoirs. The commitment well could carry out to 2009. Endeavour and Lundin announced a farmdown to Aker in December 2007 subject to government approval. Hanz Hanna

Drilling Schedule - 2008 / 2009 Exploration will add reserves and value full-cycle

Critical Factors In Value Added E & P Source: Rose & Associates, LLP using Carragher, 1997 Strategic framework & business metrics Accurate resource & chance estimates Portfolio management Continuous process improvement

Source: Rose & Associates, LLP Chance of finding at least the Minimum Commercial Field Size (MCFS) Fields > MCFS generate PV > 0 when burdened only with the cost of completing, connecting and operating the well, i.e., treating all prior investments as "sunk". Pc = Pg x PMCFS MCFS PMCFS Concept: Threshold Probability of Commercial Success (Pc)

Commercial Thresholds CALCULATIONS Trunc Pg*Pvalue P10 Mean MCFS 48.0% 43.2% 24.0% 13.2% 4.8% P90 P50 P72 P40 P80 P08 P22 Orig Pvalue Orig Chance vs Gross Potential Reserves 1.24 1.82 6.99 16.65 44.43 1 10 100 Commercial P90 P50 Trunc. Mean P10 Pg x Pvalue 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Gross Potential Reserves (mmboe) As size goes up, chance goes down! Pg = 0.6 Source: Rose & Associates, LLP

Economic Cases for Calculating Expected Value Source: Rose & Associates, LLP Drill ? Geological Success ? Commercial Success ? Commercial Failure ? 0.3 0.3 0.4 PV of: P10 resource P50 resource P90 resource Sub- commercial outcomes Dry hole Geological Failure ? When the PV / BOE varies across the prospect, the PV of the mean may not be very helpful. Instead, calculate the PV of various contributors to the mean, weighted by Swanson's approximation. In high P10/P90 exploration prospects, the P10 scenario can account for > 70% of the well's PV, and the P90 case is typically negative.

Implementation of Risk Analysis Source: Rose & Associates, LLP Key Steps Management commitment Professional staff Consistent system Central coordination Performance tracking

Exploration Direction Support emerging focus areas Manage Risk Replenish portfolio Manage exploration as a profitable business Exploration will add reserves and value full-cycle

Financial Overview

Production Statistics Attractive production levels compared to peer group

Results of Operations Metrics Cash flow supports strategy

Capital Structure Capital structure quiet and improving 1 Will be classified as debt for GAAP purposes

Crude Oil Prices Crude Oil Prices "The market would not react in this way if it was relaxed ... Why is it not relaxed? Because it is tight...When markets are that fragile, they react dramatically." Mr Ramsay, Deputy Executive Director IEA The long term oil price is expected to stay above $60 / bbl, reflecting increasing concerns over whether oil supply can meet oil demand Source: Lambert Energy Advisors Continued strong oil prices

UK Natural Gas Prices UK Gas Price affected by Cost of Supply, Continental Europe and US UK Gas Price affected by Cost of Supply, Continental Europe and US As more volumes from non-Norwegian and Dutch sources are imported UK gas price likely to be determined by the arbitrage between UK and Continental European, US and Asian markets Source: Lambert Energy Advisors Continued strong European gas prices

Hedge Position Hedges balance cash flow and market volatility

Acquisitions Show Excellent Returns Talisman 32%Return OER - Norway 33%Return $109mm $366mm $40mm $13mm

2008 Guidance

2008 Capital Budget Capital budget 25% higher than 2007

Key Results of Budget Provides capital to maximize production in 2008 and beyond Provides capital to facilitate development projects Columbus Cygnus Rochelle Funds participation in 5 - 9 exploration wells Balanced between exploration, exploitation, production and development

Value Comparison

Peer Comparisons 2P Reserves and Contingent Resources (mmboe) Production 2P Reserves (mmboe) 2P Reserves, Contingent and Risked Prospective Resources (mmboe) Source: Lambert Energy Advisors

North Sea Deals Since 2004 - Reserves Source: Lambert Energy Advisors North Sea prices have steadily risen since 2004

UK Deals - Reserves Source: Lambert Energy Advisors Currently about $25 / BOE

Corporate multiples may exceed asset multiples as an element of the purchase price is for contingent resources and exploration assets Latest Skarv unit prices exceed $17.5 / boe Source: Lambert Energy Advisors Norway Deals - Reserves Currently about $17.50 / BOE

North Sea Deals - Production Source: Lambert Energy Advisors Steady rise since 2004

Source: Lambert Energy Advisors UK Deals - Production Currently about $60k / boepd

$300k/boepd Average of some representative deals ~ $50k / boepd Source: Lambert Energy Advisors Norway Deals - Production Currently about $50k / boepd

Side by Side Peer Analysis Source: Lambert Energy Advisory Ltd

Conclusion

Conclusion Focused strategy with experienced team in place Strong continuing cash flow from existing assets to fund projects Solid and improving capital structure Multiple growth channels to organically grow company Development and exploitation of existing assets Exploration North Sea consolidation