Endeavour International 8-K Regulation FD Disclosure

Exhibit 99.1

Canaccord Adams August 9, 2006

Cautionary Statement 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 has generally permitted 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 substantially 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.

Goal To become the leading North Sea Independent Exploration and Production Company

Strategy Experienced Management + Talented, Experienced Explorationists + Extensive Regional 3D Seismic Database + Equity Incentives Shareholder Value

Why the North Sea? Large Resource Potential UK: DTI estimates 16 bboe yet-to-be discovered Norway: NPD estimates 24 bboe yet-to-be discovered >250 new fields with more than 25 mmboe each to be discovered High value fields with existing and available infrastructure Effective recycling of acreage Support for exploration companies by host governments

North Sea - A Major Hydrocarbon Province... Source: EIA, RBS, NPD, BP Statistics, Wood Mackenzie With Substantial Exploration Potential 2005 Results U.K. - 57 E&A Wells found 732 mmboe 1 Norway - 12 Expl. Wells found 1.0 bboe 2 Netherlands - 5 significant gas discoveries 3 (1) Hannon Westwood (2) NPD (3) TNO Norway UK Holland GOM 4.3 3.2 1.2 2.7 Norway UK Holland GOM 23.7 8.9 8 7.3 North Sea North Sea

Technical Team Geologists Geophysicists Engineers John N. Seitz Ronald A. Bain, Ph.D. Bruce H. Stover J.W. Munns David J. Griffiths Clint Smith Tord Pedersen Michael Neese Chris Hopper, Ph.D. Idar Kjorlaug David Rhodes J. Felix Acree Robert Fitzpatrick Fiona Goodfellow, Ph.D. Jan Olimstad Debbie Ware David Ellis Bjorn Bernsten Patricia Helen Naylor, Ph.D. David W. Thomas, Ph.D. Brady Rogers Andrew Hopkins Terje Endresen Anne Eriksen Deborah M. Jones Martin Gundem Tore Granheim Alyson M. Harding Andy Hopkins, Ph.D. Odd Senneseth Ridvan Karpuz, Ph.D.

Endeavour North Sea Data Location: Offshore UK, Norway, and The Netherlands Data Sets: • MegaSurvey (104,200 km2) • Digital Atlas • Regional structural mapping on 11 horizons • Pressure data (573 wells) • Well database (more than 1,500 wells) • Biostratigraphic database (600 wells) • 2D long offset Current • Seismic mapping Operations: • Seismic analysis • Geologic analysis and mapping • Reservoir characterization • Petrophysical studies • Rock physics modeling • 3D seismic reprocessing (proprietary PSDM, AVO) • 3D acquisition (scheduled Fall 2006)

Endeavour North Sea MegaSurvey Database Overlaid on Gulf of Mexico PGS MegaSurveys .. Central North Sea - 4,800 km2 Southern North Sea - 22,000 km2 Norwegian Norh Sea - 12,400 km2 Dutch North Sea - 15,250 km2 Total - 104,450 km2 Relative to Gulf of Mexico Represents 104,450 km2 of MegaSurvey

Talisman Transaction Overview Acquisition of high quality North Sea producing assets Acquisition of high quality North Sea producing assets Acquisition of high quality North Sea producing assets Acquisition of high quality North Sea producing assets Acquisition of high quality North Sea producing assets Acquisition of high quality North Sea producing assets Acquisition of high quality North Sea producing assets Acquisition of high quality North Sea producing assets Interest Operator Hydrocarbon Proved & Probable Reserves MMBOE Current Production boepd Goldeneye 7.50% Shell Gas/Condensate 6.5 5,700 Alba 2.25% Chevron Oil 3.2 1,200 Bittern 2.38% Shell Oil/Gas 2.4 850 Ivanhoe, Rob Roy, Hamish 23.46% Hess Oil 1.2 820 Rubie 40.78% Endeavour Oil 1.4 350 Renee 77.50% Endeavour Oil 0.6 180 Rochelle 55.62% Endeavour Oil 2.7 - Total 18.0 9,100 Closing expected before year end 2006 with January 1, 2006 effective date. (1) (2) (1) END estimates - independent reserve report in process (2) July 2006 actual

Transaction Impact Immediate critical mass in North Sea Diversification across 10 producing fields (10,000+ boepd) Balanced exposure to oil and gas Cash flow to support an exploration drilling program of 4-8 wells per year Portfolio balanced between exploration and production Exploration fuels organic growth in reserves, production and cash flow Production funds exploration with pre-tax cash flow Accelerates value creation of an expanding exploration portfolio without serial equity issuance Continuing to build exploration position - UK 24th License Round applications submitted June 15th Enhances strategic position through size and financial capability Anchors core area in UK North Sea Central Graben with strategic production hubs Supports longer-term rig commitments Enables aggressive approach to farm-ins Increases status as "partner-of-choice" Assures a Sustainable Business Model with cash flow from production to support expanded exploration and development activity

Sources and Uses of Funds Sources Permanent Capital Structure Target Sources Permanent Capital Structure Target Uses Net Cash Flow From Jan. 1, 2006 ^ $40 Acquisition Price $414 Cash on Hand $14 Hedging Costs $10 Convertible Preferred Stock $125-250 Net Working Capital ^ $10 Senior Bank Facility $150-$200 Fees & Expenses $35 Other Debt or Equity $0-$140 ^$469 ^ $469 Bridge Commitments Term Loan Facility $300 Convertible Preferred Stock $250 $550 Convertible Preferred Stock Terms: Dividend: 8%, payable in cash or stock at company option Dividend: 8%, payable in cash or stock at company option Conversion Price: $3.40 Conversion Price: $3.40 Investors include the Principal Strategies Group of Goldman Sachs, Eton Park, HBK, Kings Road Investments and Magnetar Capital (1) Assumes September 30, 2006 closing and includes assumed interest paid on acquisition purchase price from January 1, 2006 through September 30, 2006 (2) North Sea Reserve Based Loans typically bear interest at LIBOR + 1% to 3% (3) Bridge Term Loan facility, if drawn, bears interest at LIBOR + 4% (4) Subject to adjustment upon occurrence of certain events Investors include the Principal Strategies Group of Goldman Sachs, Eton Park, HBK, Kings Road Investments and Magnetar Capital (1) Assumes September 30, 2006 closing and includes assumed interest paid on acquisition purchase price from January 1, 2006 through September 30, 2006 (2) North Sea Reserve Based Loans typically bear interest at LIBOR + 1% to 3% (3) Bridge Term Loan facility, if drawn, bears interest at LIBOR + 4% (4) Subject to adjustment upon occurrence of certain events (1) (2) (3) (4) (4)

Reinvestment of Pre Tax Cash Flow from Acquisition of Talisman Assets 1 Income before income tax, after Petroleum Royalty Tax (PRT) and capital expenditures associated with the acquired assets, and after interest expense and dividends associated with acquiring the assets, assuming the capital structure on page 12. 2007 preferred dividends paid in shares of common stock. Excludes any required principal payments. (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. 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.) Exploration and development capital immediately deductible against taxable income UK Tax Rate on Oil and Gas income is 50% Endeavour plans to reinvest pre tax cash flow from the acquisition into its business model - including exploration (4 to 8 wells per year), development and further acquisitions Opportunity to utilize existing UK tax losses against taxable income - $50MM at December 31, 2005 Base case: management's estimate of most likely production outcome, including P1+P2 reserves. Upside case: management's estimate of potential production outcome, including P1+P2+P3 reserves. 2007 2008 2009 2010 Base 71 85 113 76 Upside 98 113 138 94

North Sea Exploration Drilling Program 2006 Schedule 44/12 (Cygnus) - gas discovery! 23/16f (Columbus) Endeavour Oper. (GSF 140) Pending Farmins - outside operators 2007 Drilling Prospects Endeavour operated 48/17 (Emu) (GSF 140) - Southern Gas Basin 30/23 (Balgownie) - Central North Sea - UK 23/16f (Magellan) - Central Graben 31/21b (Newburgh) - Central Graben 12/27 (Delgany) - Inner Moray Firth 18/1a (Carne) - Inner Moray Firth Outside operated 44/12b (Cygnus II) - Southern Gas Basin PL270 (Agat) - Northern North Sea - Norway PL304 (Aegis) - Central North Sea - Norway 48/1a (Platypus) - Southern Gas Basin 15/12a (Harburn) - Central Graben PL363 (Gorilla) - Central North Sea - Norway (1) (1) Not a comprehensive list

44/12-1 44/12-2 Leman Sst Carboniferous GWC -11313' NNW SSE Basin: Southern North Sea Partners: Endeavour 12.5% GdF (op) 25% Tullow 35% EOn 27.5% Reserves: FBI 170 bcf FBIIa 120 bcf FBIIb 100 bcf Well cost: £18.6 million (44/12-2) Est spud: 2007 Analogue field: Markham (230 bcf) Cygnus I IIa III IV V IIb 44/12-1 Schematic cross section 44/12-2 Discovery Well TD 11600 ft WD 65 ft 44/12 Cygnus Cygnus Complex Including FBIIa and FBIIb, updip and adjacent to Cygnus FBI drilled by 44/12-2 in Feb '06 that confirmed gas in Leman and Carboniferous sandstones.

23/16f Columbus (stratigraphic pinchout with DHI downdip from Magellan Prospect) Basin: Central Graben Partners: Endeavour 50% Serica (op) 50% Reserves: 85 bcf + condensate Est. well cost: $18 million (DHC) Est. spud: 2006 Analogue field: Everest (1.2 Tcf) Everest Monan Fiddich Montrose Arbroath Howe Mungo 7/7-2 Columbus Depth of Anomaly 23/16a-2 23/16a-2 Britoil 1988 P & A Flowed oil on test Calculated column in Forties and Andrew sandstones Min amp extraction at Top Forties. Far offset coloured inversion data Columbus Magellan 0 2 km Columbus

30/23b Balgownie (inverted rim syncline) Basin: Central Graben Partners: Endeavour (op) 65% Reservoir: Fulmar sand Reserves: 40 mmboe Est. well cost: £12.3 million (DHC) Est. spud: 2007 Analogue field: Janice (70mmbl) NE SW BCU ROT Fulmar

48/1a Emu (large horst block with shows in adjacent wells) Top Leman Depth m 48/1-2a Amerada 1993 Suspended with gas shows in Carboniferous. Leman Sst 10562-10867ft TVDSS. Westphalian A Low gas saturations calculated in Carboniferous sandstones. Ravenspurn Neptune Babbage Hyde West Sole Hoton Newsham Mercury Apollo Minerva Johnston Cleeton Emu line 238 - PSDM Emu D E P T H Top Rotliegend Top Zechstein Bunter Shale Bunter Sandstone Keuper Proposed 48/1a-D well location 2 km Basin: Southern North Sea Partners: Endeavour 30% CalEnergy (op) 70% Reservoir: Leman sandstone Reserves: 170 bcf Est. well cost: £14 million (DHC) Est. spud: 2007 Analogue field: Johnston (195 bcf) 48/1a-3 Amerada 1998 P&A Gas shows Leman Sst 10307-10660ft TVDSS Westphalian B

48/1a Platypus (low relief fault-bounded closure) Top Leman Depth m Ravenspurn Neptune Babbage Hyde West Sole Hoton Newsham Mercury Apollo Minerva Johnston Cleeton Platypus D E P T H Bunter Sand Top Zechstein Top Rotliegend Platypus SW NE PSDM Line 210 2 km Basin: Southern North Sea Partners: Endeavour 15% CalEnergy 15% Centrica (op) 70% Reservoir: Leman sandstone Reserves: 50 bcf Est. well cost: £ 18 million (DHC) Est. spud: 2007 Analogue field: Hoton (80bcf)

31/21b Newburgh (downthrown fault closures at Rotliegend and Fulmar) Newburgh Base Cretaceous Depth Map (m) Basin: Central Graben Partners: Endeavour (op) 40% Hunt 30% Acorn 30% Reserves: 20 mmboe Est. well cost: £13.3 million (DHC) Est. spud: 2007 Analogue field: Ardmore (82 mmbl)

Inner Moray Firth (tilted fault blocks) Basin: Inner Moray Firth Partners: Endeavour (op) 33.3% Hunt 33.3% Palace 33.3% Reservoir: Mid Jurassic Beatrice sandstones Upper Jurassic Volgian sandstones Reserves: 400 - 800 bcf Est. well cost: £9.1 million (DHC) Est. spud: 2007 Analogue (structural) field: Beatrice (173 mmbo) 12/26a-3 12/26a-2 12/26a-4 12/27-3 12/27-2 12/27-1 12/26a-1 18/1a 18/2a 12/26b 17/5b Beatrice field 5 km 11/30b-6 12/27 Carne Delgany Southerndown Wenvoe Cruit Cruit Carne Line 1 Line 1 Cruit Carne Line 2 Line 2 Tested 9.5 mmcfpd

Norway 2007 potential drilling locations Agat PL363 (Gorilla) 5 km PL304 250 m WD Lower Cretaceous target at ~3500 m TD at ~4200 m 60 days / $ 35 mm 150 m WD Lower Tertiary target at ~1950 m TD at ~2500 m 40 days / $ 23 mm 120 m WD Lower Tertiary target at ~1940 m TD at ~2500 m 40 days / $ 23 mm

Frigg Balder PL304 S N 25/10-2 25/10-7 9232 m W E Balder sst. Heimdal sst. 25/10-7 Aegis License period: Dec.12 2003 - Dec.12 2008 Aegis Prospect is a 57 mmbo Tertiary oil prospect. Upside reserve potential 113 mmbo at Aegis, with additional Tertiary prospects & leads on License. Nearby Balder Field provides good analogue for reservoir model Shallow depth (1950 m) with associated low drilling costs ($23 mm) Tie-back development to Balder Field yields good economics. License: PL304 Country: Norway Endeavour: 40% Partners: Lundin (Op) 60%

License: PL 363 (Part block 25/5) Country: Norway Endeavour equity: 40 % Partner: Lundin (Op., 60 %) Date granted: 6 Jan 2006 (APA 2005) Date valid to: 6 Jan 2011 Original area: 167.941 km2 Current area: 167.941 km2 Initial period 2+2+1 year initial period 15 year extension period Work program: Obtain 3D coverage (no new acquisition) Drill-or-drop-decision by 6 Jan 2008 Map FRIGG A B A B A B Drilling target: 1950 m

License: AGAT/PL270 (35/3) Country: Norway Endeavour 49% Partners: RWE-DEA (Op) Date granted: 27 April 2001 (NST 2000) Date valid to: 27 April 2035 Original area: 488.659 km2 Current area: 241.222 km2 Initial period 5 year 30 year extension period Work program: Drill an exploration well to at least 4000m. Fulfilled Wells 35/3-2 and 35/3-4 each tested approx. 25mmcfpd + condensate Seismic line PEON AGAT AGAT W E Well 2 Well 36/1-2 Well 4 Base Agat Well 2 AGAT Base Agat N S Log Top Agat Fm. 35/3-1 35/3-2 35/3-4 35/3-5 35/3-6 36/1-2 5 km Agat sst. Jurassic Drilling target: 3500 m

Growth in Key Metrics 2004 2005 2006 0 4 12 2004 2005 2006 0 18 35 2004 2005 2006 0 2 10 2004 2005 2006 8 20 60

Production Profile (P1+P2) 2004 2005 2006 2007 2008 2009 Njord & Brage 2038 1995 1861 1715 1767 2099 2341 1370 2456 2275 2098 2116 2038 1995 1900 1861 1704 1485 1537 1537 1537 1537 1537 1537 1537 1537 1534 1534 1534 1534 1534 1534 1604 1674 1744 1814 1884 1954 2024 2095 2165 2235 2305 2375 2406 2437 2469 2500 2531 2562 2594 2625 2656 2687 2719 2750 2753 2757 2760 2763 2767 2770 Alba 1349 1336 1323 1310 1297 1284 1270 1257 1244 1231 1218 1205 1191 1178 1165 1152 1139 1126 1112 1099 1086 1074 1062 1050 1038 1026 1015 1003 991 979 967 955 943 923 903 884 864 844 824 Bittern 765 755 744 733 722 712 701 690 683 676 669 662 655 648 640 633 626 619 612 605 600 595 589 584 579 574 568 563 558 553 547 542 538 534 529 525 521 517 513 Goldeneye 5003 5003 5003 4925 4810 4480 4371 4057 3952 3848 3565 3478 3390 3303 3228 2948 2873 2805 2736 2593 2531 2475 2418 2368 2326 2283 2281 2215 2173 2130 2088 2045 2003 1960 1918 1875 1833 1790 1590 Ivanhoe 1503 1490 1477 1464 1452 1439 1426 1413 1408 1403 1398 1393 1388 1383 1378 1373 1368 1363 1358 1353 1344 1335 1326 1317 1308 1299 1290 1281 1272 1263 1254 1245 1216 1187 1157 1128 1099 1070 1041 Enoch 1024 1024 1024 1024 1024 1024 960 896 832 768 704 640 623 607 590 573 557 540 523 507 490 473 457 440 427 413 400 387 373 360 347 333 320 307 293 280 Cygnus 675 1350 1387 1424 1460 1497 1534 1571 1607 1644 1681 1669 1658 1646 1634 1623 1611 Rochelle 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3373 3345 3318 3290 3263 3235 3208 3180 3180 3180 3180 3180 3180 3180 3180 Production Growth This profile represents management's estimate of future production. There are varying risks in estimating future production volumes. Actual production amounts and timing may differ significantly from the estimated volumes. (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. 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.)

Why Endeavour? Growth in production and cash flow Sustainable exploration program supported by high quality producing assets Balanced portfolio Distinctive investment opportunity Only pure-play North Sea independent Experienced and accomplished team Solid base of production with significant exploration optionality

Appendix

PL 347 PL 348 Galtvort Date granted: 17 Dec 2004 (APA 2004) Date valid to: 17 Dec 2009 Original area: 207.727 km2 Current area: 207.727 km2 Initial period 2+2+1 year initial period 15 year extension period Work program: Reprocessing of 200 sq. km 3D and by 17 Dec 2006 Drill-or-drop-decision by 17 Dec 2006 Continue to prepare PDO or drop by 17 Dec 2008 Submit PDO-or-drop by 17 Dec 2009 Noatun Onyx Field: NJORD AREA License/Block: PL348 Country: Norway Endeavour: 7.5% Partners: Hydro(Op), Ruhrgas, GdF, Petoro,

NJORD DRAUGEN Field: NJORD AREA License/Block: PL107, PL132 Country: Norway Endeavour: 2.5% Partners: Seismic line Map (Geo-)seismic line Log BCu T.Tilje Njord field is heavly faulted & segmented The field has been developed using a semi-submersible drilling, livingquarter and production platform (Njord A), with oil being off- loaded into a Floating Storage Unit (Njord B) and exported with shuttle tankers. Produced gas is currently being re-injected into the reservoir with plans to commence gas export in 2007. The peak production was in 2000 with 3.92 MSm3 (67 500 bbl/d average). The cumulative production 31st Dec 2005 was 19.59 MSm3 (123 mill bbls). The main drive mechanism in the East flank is gas injection. The Central Area and Northern Area are produced by natural depletion. Currently there are 7 producers and 4 injectors at the field. The Ile EF reservoir on top of Tilje has been produced since April 2005. A 2nd Ile EF producer will come on stream in 2006. There are also plans to drill a gas injector in Ile EF during 2006 to increase recovery from the Ile reservoir. Prospects: Njord North-West Flank A-prospect. Penetrated with one well in 2000 with gas/condensate discovery in Tilje formation. A number of prospects in the vicinity of Njord, among them UJ5, UJ2 and Noatun.

The main drive mechanism in the Statfjord and Fensfjord formations is water injection. The Sognefjord formation is currently produced by two single producer and natural depletion. During drilling of a new Fensfjord producer Spring 2004 Brent formation was encountered on the north western part of the Fensfjord reservoir. The Brent formationhas been producing and is under evaluation for predicting volumes and extension. The Brage field is developed with a single platform standing at water depth of 137 m. The platform is an integrated processing, drilling and accomodation (PDQ) installation on a steel jacket. The platform has a total of 40 well slots and no subsea wells or satellite production. All well slots have been utilized. New wells will therefore be based on recovery of the slots for shut-in wells. Prospects: Bowmore structure NNE of Brage platform (Brent formation + Fensfjord formation). Penetrated by one well 31/4-11. Talisker prospect north of Brage Horst (Brent formation + Statfjord formation). Penetrated by one well, but outside closure, 31/4-2. Knockandu located between the Bowmore and the Talisker prospect. Map (Geo-)seismic line TROLL BRAGE B B Field: BRAGE License/Block: PL055,PL053,PL053B Country: Norway Endeavour: 4.442% Partners: Hydro (Op), Talisman, Altinex, Petoro, Statoil, Revus