Exhibit 99.1

Building the Leading North Sea Independent June 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.

Definitions P1 or Proved Reserves: SEC 1978- Current Definition, Code of Federal Regulations, 17 CFR 210.4-10 (Regulation S-X) "Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and cost as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. " P2 or Probable Reserves: Society of Petroleum Engineers / WPC Definitions for Oil and Gas Reserves "Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves." P3 or Possible Reserves: Society of Petroleum Engineers / WPC Definitions for Oil and Gas Reserves "Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves."

Recent Developments Announced Acquisition of Talisman assets Closed Acquisition of Enoch interest Cygnus Gas Discovery

Building the Leading North Sea Independent OER Enoch Cygnus Talisman License Rounds Farm-ins Acquisitions Swaps

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 5,500 Alba 2.25% Chevron Oil 3.2 1,240 Bittern 2.38% Shell Oil/Gas 2.4 1,030 Ivanhoe, Rob Roy, Hamish 23.46% Hess Oil 1.2 820 Rubie 40.78% Endeavour Oil 1.4 400 Renee 77.50% Endeavour Oil 0.6 210 Rochelle 55.62% Endeavour Oil 2.7 - Total 18.0 9,200 $414 million purchase price with January 1, 2006 effective date Closing expected before year end 2006 (1) (2) (1) END estimates - independent reserve report in process (2) May 2006 actual

Transaction Impact Immediate critical mass in North Sea 10,000+ boepd total company production at closing 25+ mmboe proved & probable reserves Diversification across 10 producing fields 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 $19 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-$135 ^$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)

Endeavour Assets - Central North Sea

Goldeneye: Block 20/4b Central North Sea First Production: Q4 2004 Producing Horizon: Lower Cretaceous Captain sandstone @ 8300 ft Drive Mechanism: Combination gas expansion with water drive Facilities: Producing from 4 piled steel 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: Talisman - 7.5%; Shell (Operator) - 49.0% Water Depth: 400 ft Current Production: 5,500 boepd net Est. Abandonment: 2016 Est. Future Capex: None Goldeneye Reservoir Type Log (Well 14/29A-3) Source: Goldeneye Field Development Plan January 2002

Alba Field: Block 16/26 Central North Sea D10 212ft MD D-10 Horizontal Log Alba Sandstone First Production: 1994 Producing Horizon: Eocene Alba sandstone @ 6200 ft Drive Mechanism: Volumetric with pressure support from water injection Facilities: Alba North Steel Platform - 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: Talisman - 2.25%; Chevron (operator) - 21.2% Water Depth: 460 ft Current Production: 1,240 boepd net Est. Abandonment: 2022 Est. Future Capex: $7MM net

Bittern: Block 29/1b Central North Sea First Production: 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: Talisman - 2.4%; Shell (operator) - 39.6% Water Depth: 300 ft Current Production: 1,030 boepd net Est. Abandonment: 2016 Est. Future Capex: None 29/1b-5 Log Bittern Sandstone

Ivanhoe, RobRoy, Hamish, Renee, Rubie & Rochelle Fields - Blocks 15/27 & 28 Central North Sea IVRRH Stratigraphic Section First Production: IVRR 1989, H 1990, Renee 1999, Rubie 1999, Rochelle - undeveloped discovery Producing Horizon: IVRRH - Upper Jurassic Piper @ 7800'; Renee/Rubie - Upper Jurassic Piper/Scott sandstone; Rubie - Paleocene Andrew sandstone @ 6200'; Rochelle - Discovery in Lwr. Cret Britannia sandstone @ 10,000' Drive Mechanism: IVRRH - volumetric depletion with pressure support via water injection; Renee/Rubie - water drive Facilities: Production from subsea tiebacks to AH00I Floating Production Unit (FPU) Wells: IVRRH wells: 7 producers & 3 water injectors; Renee/Rubie wells: 2 producers Sales: Production processed at the AH00I and transported via pipeline to the Claymore platform on to the Flotta terminal for sales Ownership: IVRRH Talisman - 23.5%, Amerada Hess (operator) -76.5% Talisman (operator) - Renee 77.5%, Rubie 40.8% and Rochelle 55.6% Water Depth: 475 ft Current Production: IVRRH: 820 BOPD net RR: 610 BOPD net Est. Abandonment: 2013 Est. Future Capex: $35MM net

Commodity Prices 2007 2008 2009 2010 2011 2011 Assumed Prices Assumed Prices Assumed Prices Oil ($/bbl) Oil ($/bbl) Oil ($/bbl) 65.00 65.00 65.00 65.00 65.00 65.00 Gas ($/mcf) Gas ($/mcf) Gas ($/mcf) 10.00 10.00 10.00 7.50 7.50 7.50 Hedges In Place Hedges In Place Hedges In Place Oil Swap Volume (bbl) Volume (bbl) 350,100 355,500 378,408 278,808 Price ($/bbl) Price ($/bbl) 69.80 69.80 69.80 69.80 Swaption Volume (bbl) Volume (bbl) 390,435 247,658 86,280 Price ($/bbl) Price ($/bbl) 65.00 65.00 65.00 Gas1 Swap Volume (mcf) Volume (mcf) 446,050 1,002,404 1,018,850 1,024,750 626,625 626,625 Price ($/mcf) Price ($/mcf) 11.54 10.82 10.36 9.92 9.51 9.51 1 UK Gas hedge contracts denominated in £/therm. Conversion made at 10 therm/mcf and 1.85 $/£.

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 8. 2007 preferred dividends paid in shares of common stock. (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

Enoch - UKCS and Norway Location: UKCS block 16/13a & NCS 15/5g Regional Setting: South Viking Graben Water Depth: 380 ft Fluid Type: Oil and gas cap Endeavour WI: 8% Partners: Talisman 25.2% (operator), 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% Development Plan: Commenced mid 2005. Single horizontal producer to be spud mid-July. Subsea tie-back to Brae A platform to be completed in November '06. Topsides construction at Brae to be completed by December '06. Production: First production anticipated late 4Q 2006 at approx. 1,000 boe/d (net) Acquisition cost: $12 MM Est. Future Capex: $11 MM net Stratigraphic closure OWC -6935 ft GOC -6837 ft 16/13a 15/5 Top Sele structure map in ft TVDSS. C.I. 20 ft. Enoch Field Structure Median Line Flugga Sandstone: Eocene 16_13a3 Well

Cygnus Discovery: Preliminary Full Field Development - Discovery Fault Block + 2 Adjacent Fault Blocks (44/11 & 12 Southern Gas Basin) 44/11 & 12 Mapped fault blocks at Top Leman Sandstone. IIa IIb III IV 44/12-2 Discovery Well TD 11600 ft WD 65 ft I 2 Km Reserves - Risked Net (BCF) P50 Cygnus - Fault Block (FB) I 23 2 Adjacent Fault Blocks - FB IIa & IIb 17 Total 40 Discovery: Q2 - 2006 Development Sanction: Q1 - 2007 Wells: 3 - FBI 9 - FB I + FBIIa + FBIIb Est. Future Capex- Risked Net 1 ($MM) Total Cygnus - FB I 34 2 Adjacent Fault Blocks (FB IIa & IIb) 22 Total 56 1 Based on Endeavour Preliminary Development Plan - Final development plan pending operator technical study and partnership approval 44/12-1 Well Ownership Ownership Gaz de France Gaz de France 25% Endeavour Endeavour 12.5% ( ) ( )

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.)

Pro Forma Financial Metrics 2007 Base 2.2 Upside 1.7 2007 Base 0.61 Upside 0.53 2007 Base 165 Upside 193 2007 Base 0.99 Upside 1.16 Assumptions: - Permanent capital structure as described on page 8. - Discretionary Cash Flow defined as cash flow from operations before changes in working capital. - 2007 preferred dividends paid in shares of common stock. - Operating costs of approximately $11/boe. 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 reserves and for Talisman assets P3 reserves

Peer Valuation Comparison Current Year Multiples for Peers, Pro Forma 2007 for Endeavour 1 ALX DNO LUPE TLW PMO DNX Revus VPC END East 7.2 5 4.9 4.4 4 3.3 3.2 2.7 3.6 DNO BVX ALX OIL Revus LUPE PMO TLW DNX VPC END 16.1 12.2 11.5 9.6 9.4 7.8 7.2 5.3 4.6 2.7 1.7 BBG EAC FST THX ATP HAWK EPEX END 5.8 4.4 4 3.8 3.6 3.5 3.2 1.7 BBG EAC FST THX HAWK ATP EPEX END East 5.9 5.8 5.4 4.6 4.1 4 3.9 3.4 North Sea Peers North American Peers Median 8.6x Median 4.2x Median 3.8x Median 4.6x As of June 9, 2006 Source: Thomson Financial, except for END 1 Midpoint of range from page 19

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