Exhibit 99.3

October 5, 2006 Investor Supplement

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 The following presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created thereby. You can identify our forward-looking statements by words such as "anticipates," "expects," "intends," "plans," "projects," "believes," "estimates," and similar expressions. Forward-looking statements relating to ConocoPhillips' operations are based on our management's expectations, estimates and projections about ConocoPhillips and the petroleum industry in general on the date these presentations were given. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Further, certain forward-looking statements are based upon assumptions as to future events that may not prove to be accurate. Therefore, actual outcomes and results may differ materially from what is expressed or forecast in such forward-looking statements. Factors that could cause actual results or events to differ materially include, but are not limited to, the ability of the parties to successfully negotiate and execute final definitive agreements, each party's ability to successfully operate and finance the proposed joint ventures, crude oil and natural gas prices; refining and marketing margins; potential failure to achieve, and potential delays in achieving expected reserves or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas; unsuccessful exploratory drilling activities; lack of exploration success; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying company manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; international monetary conditions and exchange controls; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; general domestic and international economic and political conditions, as well as changes in tax and other laws applicable to each party's business. Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting ConocoPhillips' business generally as set forth in ConocoPhillips' filings with the Securities and Exchange Commission (SEC), including their Form 10-K for the year ending December 31, 2005, as updated by subsequent periodic reports on Form 10-Q and Form 8-K. ConocoPhillips is under no obligation (and expressly disclaims any such obligation) to update or alter its forward-looking statements, whether as a result of new information, future events or otherwise. Cautionary Note to U.S. Investors - The U.S. 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. We use certain terms in this presentation such as "recoverable resources," "recoverable oil resources," "recoverable bitumen," "Syncrude," "oilsands," and/or "heavy oil" that the SEC's guidelines strictly prohibit ConocoPhillips from including in its filings with the SEC. U.S. investors are urged to consider closely the oil and gas disclosures in ConocoPhillips' Form 10-K for the year ended December 31, 2005. This presentation (Slides 20, 21, and 22) contains an illustrative example calculating a measure, "EBITDA," that is not calculated in accordance with U.S. generally accepted accounting principles (GAAP). The example demonstrates a scenario for just one of the many that were evaluated in the evaluation process, and is an estimate of how costs, and resulting margins, could possibly perform at a given West Texas Intermediate (WTI) oil price. The example estimates the various costs (field operating, natural gas, diluent, transportation) at a $50 WTI example, and then estimates the resulting EBITDA margin that would result from this scenario. EBITDA consists of earnings before interest expense, income tax expense, and depreciation, depletion and amortization. EBITDA should not be considered as an alternative to any measure of operating results as promulgated under GAAP, nor should it be considered as an indicator of overall financial performance. We have included this non-GAAP financial measure because, in management's opinion, it most closely portrays a cash margin, which management believes will be an important measure in an analysis of cash flow consideration for the proposed joint ventures. Since the use of EBITDA is in the context of an illustrative example, a reconciliation to the most comparable GAAP measure (cash flow from operations) is not possible, as the GAAP components excluded from EBITDA were not estimated for purposes of such example.

Transaction Overview Strategic Rationale Impact to ConocoPhillips Metrics Financial Agenda

Transaction Summary Venture comprised of two 50/50 Partnerships: Upstream Partnership EnCana's Foster Creek and Christina Lake projects Downstream Partnership ConocoPhillips' Wood River and Borger refineries Partnerships of equivalent value Planned effective date: January 2, 2007 EnCana and ConocoPhillips are creating a long-term integrated North American heavy oil business Borger Wood River Christina Lake Foster Creek

Transaction Structure Downstream Partnership Upstream Partnership COP US (OPERATOR) ECA US 50% interest* 50% interest* 100% Wood River Borger Downstream Partnership *Subject to Borger 2 year Disproportionate interest 100% Foster Creek Christina Lake ECA Canada (OPERATOR) COP Canada 50% interest Upstream Partnership 50% interest Contribution Obligation $7.5 B Over 10 years Contribution Obligation $7.5 B Over 10 years

Transaction Highlights EnCana contributes 100% of their working interest in Foster Creek and Christina Lake oilsands projects Independent estimated recoverable bitumen of >6.5 billion bbls* Planned increase in current bitumen production from 50,000 bpd to 400,000 bpd by 2015 Markets bitumen blend at major Alberta trading hubs ConocoPhillips contributes 100% of Wood River and Borger refineries Planned increase in total refining capacity* from ~450,000 to ~600,000 bpd by 2015 Heavy oil capacity increasing from ~60,000 bpd to ~550,000 bpd by 2015 Bitumen capacity increasing from ~30,000 bpd to ~275,000 bpd by 2015 Further expand capacity in Alberta or the U.S. as warranted ConocoPhillips retains two year disproportionate interest in Borger 85/15 in 2007; 65/35 in 2008; 50/50 thereafter Purchases and transports feedstock and sells refined products Downstream Partnership (50/50) Upstream Partnership (50/50) *Notes: Recoverable bitumen estimate provided by McDaniel & Associates Consultants Ltd. ; All numbers shown are after royalty numbers for 100% interest. Capacity numbers are for Wood River and Borger only, and do not include NGL capacity at Borger.

Strategic Rationale Access to large North American resource base: Partners with leading SAGD producer with best-in-class assets Repositions 10% of U.S. downstream into upstream resources > 3 billion barrels net estimated recoverable bitumen* Stable source of ongoing resource additions Complements large North American natural gas & refining positions Enhances certainty of value creation through integrated approach Stable, long-term refinery supply Enhances near and long-term production growth Leverages capabilities and technologies *Note: Recoverable bitumen estimate provided by McDaniel & Associates Consultants Ltd.; represents net after royalty estimate for 50% interest.

Corporate and Operating Governance 50/50 upstream and downstream partnerships Management committee for each partnership Equal number of representatives 50/50 voting rights Unanimity required for strategic/major decisions Supported by multi-disciplined Operating sub-committee Upstream partnership EnCana is the operator and managing partner Downstream partnership ConocoPhillips is the operator and managing partner Capital, costs, revenues shared 50/50 Day 1 Disproportionate interest in Borger in 2007 and 2008 Equal Representation and Rights

Canadian Oilsands Largest North American Supply Source Overview Largest remaining unconventional supply source in the world Approximately 175 B bbls of recoverable bitumen Only approximately 3% produced Long life resource (+50 years) Low political risk Attractive integrated economics enabling rapid development of resource base Majority of future projects will utilize in-situ (SAGD) technology U.K. Norway Brazil Mexico China U.S.A. Nigeria Libya Russia/FSU UAE Kuwait Iraq Iran Canada Saudi Arabia Venezuela East 4.5 9.7 11.2 14.8 17.1 29.4 35.3 39.1 72.3 97.8 99 115 132.5 14.9 262.7 47.2 Bituminous 175.1 300 North 45.9 46.9 45 43.9 Global Crude Oil Supply Sources by country (Bbbls) 4.5 9.7 11.2 14.8 17.1 29.4 35.3 39.1 72.3 97.8 99.0 115.0 132.5 190.1 347.2 Source: International Energy Agency; Energy Information; OPEC; BP Statistical Review of World Energy, 2005 262.7

Chevron Total Nexen Husky Imperial Shell Petro-Can Suncor CNRL EnCana COP Iraq Iran Canada Saudi Arabia Venezuela In Situ 118 142 294 414 426 346 507 516 885 1228 1672 115 132.5 14.9 262.7 47.2 Mining 16 87 29 0 151 256 99 208 181 0 15 175.1 300 Canadian Oilsands - Pro Forma Position Canadian Oilsands Relative Land Positions (Net Sections) Notes: COP includes addition of 50% of ECA Foster Creek & Christina Lake acreage; and ECA is reduced by same amount; Includes ECA option lands with right-to-lease. Includes only land associated with the Athabasca Oil Sands Deposit. Source: Alberta Energy and Utilities Board; and Company reports. Syncrude AOSP Horizo n Josly n Millennium/ Voyageur Firebag McKa y River Sunrise Lewis Fort Hills Gregoire Lake Long Lake Meadow Creek Paramoun t Total Christina Lake Foster Creek Jackfish Borealis AOSP Northern Lights Kearl Saleski CL L CL L Steep bank Aurora Surmont Ipiatik Thornbury Clyden SURMONT THORNBURY Area CLYDEN Area 100 Miles FOSTER CREEK CHRISTINA LAKE SYNCRUDE COP and ECA are both post-transaction positions

SOR Average Well Rate Nexen Long Lake 6.72 312.03 CNRL Primrose & Wolf Lake 5.63 109.58 Shell Peace River 4.2 149.2 IMO Cold Lake 3.51 57.27 Conoco Surmont 3.74 247.94 Suncor Firebag 3.28 1581.65 Shell Peace River 4.2 149.2 JACOS Hangingstone 3.17 561.84 PetroCan McKay 2.76 768.67 EnCana Foster Crk & Christina Lake 2.36 862.45 Source: EUB Public Domain Data, Jan. 2006 - June 2006 EnCana's Oilsands Projects A Performance Leader versus Industry Steam Oil Ratio (SOR) API 11° 8° 7° 8° 10.5° 9° 8° ECA has highest quality SAGD Projects: Low SOR, high per well production, and high API gravity 10° / 9° Oil Rate Indicator: SAGD Cyclic Steam Stimulation (CSS)

EnCana Oilsands Assets Foster Creek: First commercial SAGD project in region Current production of ~43,000 bpd 2015 estimated rate = ~210,000 bpd Estimated recoverable bitumen* = 2.4 billion bbls ~600 million bbls currently booked as proved reserves for ECA Cumulative production of >30 million bbls at one of the lowest steam-oil ratios Consistently benchmarked as one of the best commercial and technical SAGD operations *Notes: Recoverable bitumen estimate provided by McDaniel & Associates Consultants Ltd. . Represents after royalty estimates for 100% interest.

EnCana Oilsands Assets Christina Lake: Current production of ~7,000 BPD 2015 rate = ~190,000 bpd Estimated recoverable bitumen* = 4.2 billion bbls Phase I initiated in 2002 Cumulative production ~3.5 million barrels at the lowest steam-oil ratio of any SAGD project in the region *Notes: Recoverable bitumen estimate provided by McDaniel & Associates Consultants Ltd. . Represents after royalty estimates for 100% interest.

Stable Supply of Future Resources E&P R&M Lukoil Other 63 37 2 0.2 Current COP reserves YE 20051 11.4 BBOE Recoverable Bitumen Potential2 ~3.0 - 3.5 BBOE 1 YE2005 pro-forma for COP and BR, excludes Syncrude. 2 Recoverable bitumen estimate for Foster Creek and Christina Lake provided by McDaniel & Associates Consultants Ltd.; Represents COP's 50% interest, after royalty. Non-OECD 37% OECD 63% FC FC proved CL Other 2.4 0.6 3.6 0.2 Christina Lake ~1.8BBO Foster Creek ~1.5BBO Access to large resource base and stable supply of ongoing resource additions

Estimated Long-term Production Growth COP's 50% interest in Partnership (Net after royalty) Note: Estimated production attributed to Foster Creek and Christina Lake development; numbers are 50% interest, after royalty Source: EnCana estimates of bitumen production rates. 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018+ Foster Creek 33 48 55 72 75 80 94 108 108 215 215 215 Christina Lake 3.5 6 13 30 45 58 75 95 95 190 190 190 Mbpd of bitumen

2005 2006 2007 2008 Base COP 1808 2360 2423 2473 2662 + ECA 246 32 49 79 BR 0 377 0 GR Supports COP Long-term Production Growth Note: 2006 represents 9 months of Burlington. Production includes equity affiliates and Syncrude. CAGR ~3%

Upstream Transaction ROCE 20% Differential 25% Differential 30% Differential Upstream 0.15 0.12 0.09 10 Year Average Return on Capital Employed Notes: Assumes strip WTI and Nat Gas pricing for 2007-2009, and differentials of 33% for 2007, 30% for 2008, and 27% for 2009. For 2010+, in real $, $50 WTI and 8:1 conversion WTI to AECO.

Upstream Net Income Build Up 20% Differential 25% Differential 30% Differential COP Portfolio Net Income 12.27 9.04 5.81 13.25 Tax 5.01 3.69 2.37 12.26 DD&A 5.26 5.26 5.26 9 Op Cost 9.28 9.28 9.28 8.29 Revenue $32 $27 $23 Op Cost 9 9 9 DD&A 5 5 5 Tax 5 4 2 Net Income $12 $9 $6 $ per BOE Note: Assumes $50 WTI, $8 HHUB, and $6 AECO. Differential is based on blended product.

Historical Differential Volatility 1/31/2000 2/29/2000 3/31/2000 4/28/2000 5/31/2000 6/30/2000 7/31/2000 8/31/2000 9/29/2000 10/31/2000 11/30/2000 12/29/2000 1/31/2001 2/28/2001 3/30/2001 4/30/2001 5/31/2001 6/29/2001 7/31/2001 8/31/2001 9/28/2001 10/31/2001 11/30/2001 12/31/2001 1/31/2002 2/28/2002 3/29/2002 4/30/2002 5/31/2002 6/28/2002 7/31/2002 8/30/2002 9/30/2002 10/31/2002 11/29/2002 12/31/2002 1/31/2003 2/28/2003 3 /31/2003 4/30/2003 5/30/2003 6/30/2003 7/31/2003 8/29/2003 9/30/2003 10/31/2003 11/28/2003 12/31/2003 1/30/2004 2/27/2004 3/31/2004 4/30/2004 5/31/2004 6/30/2004 7/30/2004 8/31/2004 9/30/2004 10/29/2004 11/30/2004 12/31/2004 1/31/2005 2/28/2005 3/31/2005 4/29/2005 5/31/2005 6/30/2005 7/29/2005 8/31/2005 9/30/2005 10/31/2005 11/30/2005 12/30/2005 1/31/2006 2/28/2006 3/31/2006 4/28/2006 5/31/2006 6/30/2006 7/31/2006 East 0.224 0.199 0.239 0.209 0.209 0.231 0.176 0.214 0.112 0.229 0.29 0.388 0.367 0.386 0.399 0.416 0.413 0.389 0.313 0.324 0.375 0.415 0.468 0.437 0.45 0.398 0.214 0.139 0.149 0.145 0.144 0.131 0.321 0.362 0.365 0.282 0.263 0.241 0.284 0.343 0.233 0.295 0.258 0.25 0.27 0.272 0.26 0.244 0.312 0.29 0.291 0.28 0.267 0.281 0.247 0.366 0.2 97 0.376 0.448 0.403 0.409 0.381 0.438 0.452 0.307 0.247 0.28 0.319 0.374 0.454 0.469 0.489 0.516 0.4 0.275 0.195 0.259 0.236 0.251 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 Increased Downstream Margin Increased Upstream Margin *Note: Light/heavy differential based on Lloyd Blend (LLB) at Hardisty and WTI; Defined as: (WTI - LLB)/WTI Historical differential (%)* Integration reduces exposure to light / heavy differentials

Illustrative Integrated Cost / Margin Analysis* Heavy Oil (synbit) Synthetic (assumed diluent) Bitumen 0.55 BBL 0.45 BBL Refinery Gas cost Op. Cost Transport cost ~$3/bbl Cost of Synthetic (~WTI) Op. Cost $4/bbl Upstream Partnership Downstream Partnership ~$9/bbl = ~$5 for .55 bbl 1 BBL Value of Products $54/bbl of throughput Delivered Feedstock Costs ($/bbl)= $5 Bitumen Costs $3 Transport Cost $22 Synthetic Cost Value of Products $54 less Delivered Feedstock Costs ~($30) less Refinery Op. Cost ~($4) Integrated EBITDA Margin $20 ~$50/bbl = ~$22 for .45 bbl *Note: Amounts are ranges based on $50 real WTI, GC crack of ~$5, and AECO gas price of ~$6; all 2006 $ terms and excluding royalty.

*Note: Based on information after all project completions; 2006 $ terms; EBITDA Margin defined as: Revenues - Opex - Gas cost/Feedstock cost - Transport. Illustrative Integrated Margin $40/bbl WTI $50/bbl WTI $60/bbl WTI Cost of bitumen blend Upstream 4.37 5.78 7.18 Value shift2 1.61 2.1 2.51 Dowstream 7.22 9.38 11.37 Total Integrated Margin 15.95 20 25.23 Total 15.95 20 25.23 Downstream Upstream Downstream Upstream Downstream Upstream Varying Differential Decreasing Diff. Increases Upstream Margin Participation in both Partnerships provides more certainty in overall margin Increasing Diff. Increases Downstream Margin EBITDA margin ($/bbl)*

Downstream Margin Integrated Margin Integrated Margin = Downstream mgn + 55% of Upstream mgn Value through Integrated Margin 20% Differential 25% Differential 30% Differential Upstream 17.9 10.7 3.5 Downstream 4.25 8.75 13.25 Integrated 20.39 20.39 20.39 20% Differential 25% Differential 30% Differential Upstream 22.54 17.99 13.44 Downstream 4.25 8.75 13.25 Integrated 14.1 14.64 15.18 20% Differential 25% Differential 30% Differential Upstream 17.9 10.7 3.5 Downstream 8 10.5 13 Integrated 14.1 14.64 15.18 Upstream Margin EBITDA margins excluding royalty Note: Amounts are based on $50 real WTI, GC crack of ~$5, and AECO gas price of ~$6; all 2006 $ terms and excluding royalty

WR & B 350 MBPD WR & B 550 MBPD JV Case WR & B 350 MBPD WR & B 550 MBPD JV Case WR & B 350 MBPD WR & B 550 MBPD JV Case East 0.67 0.67 0.56 0 0.47 0.47 0.57 0 0.52 0.79 0.95 2011 2015 Impact on EPS* 2007 *Note: Assumes strip pricing for 2007 and, in real $, $50 WTI, $6 AECO, and $5 GC crack spread for 2011 and 2015. WR & B 350 MBPD - reflects COP keeping WR & B and expanding heavy oil capacity to 350 Mbpd. Note: This is COP plan prior to transaction. WR & B 550 MBPD - reflects COP keeping WR & B and expanding heavy oil capacity to 550 Mbpd. JV case - reflects COP EPS from partnerships where heavy oil capacity is expanded to 550 Mbpd.

Change in Capital Employed ($ MM) 2007 2008 2009 2010 2011 2012 2013 2014 2015 Upstream 876 1727 2507 3176 3850 4527 5108 5636 6115 Downstream -690 -1533 -2037 -2638 -3550 -3944 -3977 -3804 -3679 Overall 186 194 470 538 301 583 1131 1833 2436 Additional Upstream Capital Employed Reduced Downstream Capital Employed Slight Increase to Overall Capital Employed Q2 2006 Capital Employed for COP = ~$110B Creates very little change to overall corporate capital employed or ROCE

Price Sensitivities* $1/BBL Crude - Worldwide E&P 204 213 255 $MM $0.50/MCF Natural Gas - Worldwide E&P 484 480 457 2007 $0.25/BBL Refining Margins (97% Capacity Utilization) 136 122 122 With Transaction Sensitivities are annual and exclude impact of LUKOIL 2015 Current By 2015: Increases crude oil sensitivity by 25% Decreases natural gas sensitivity slightly (6%) Reduces exposure to refining margins by 10% *Note: Reflects changes in sensitivities due solely to this transaction.

Access to large North American source of supply > 3 billion barrels net estimated recoverable bitumen* Stable source of ongoing production replacement Accelerates expansion of heavy refining capacity with stable, long-term supply Repositions 10% of U.S. downstream into upstream resources Partners with leading SAGD producer with best-in-class assets Opportunity to leverage capabilities and technologies Reduces cash-flow volatility Mitigates impact of light/heavy differential swings through fully integrated approach Provides diversification to North American natural gas position Estimated 400,000 bpd of bitumen supply by 2015 to attractive N.A. destinations Transaction Benefits for COP *Note: Recoverable bitumen estimate provided by McDaniel & Associates Consultants Ltd.; represents net after royalty estimate for 50% interest.