8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  October 5, 2006

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation) 001-32395
(Commission
File Number) 01-0562944
(I.R.S. Employer
Identification No.)

600 North Dairy Ashford
Houston, Texas 77079

(Address of principal executive offices and zip code)

Registrant’s telephone number, including area code:  (281) 293-1000

n/a

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS

	Item 7.01. Regulation FD Disclosure
	Item 9.01 Financial Statements and Exhibits
SIGNATURES
EXHIBIT INDEX
Press Release
Slide Presentation
Investor Supplement

Item 7.01. Regulation FD Disclosure

     On October 5, 2006, ConocoPhillips announced two planned joint ventures with EnCana Corporation (EnCana). A copy of ConocoPhillips’ press release is furnished as Exhibit 99.1. ConocoPhillips is also furnishing a joint slide presentation to be used by certain executive officers of ConocoPhillips and EnCana when they speak to various members of the financial and investing community on October 5, 2006. Also furnished is an investor supplement to be used by certain executive officers of ConocoPhillips when they speak to various members of the financial and investing community. These presentations are filed as Exhibits 99.2 and 99.3 to this Current Report on Form 8-K.

     The information in Item 7.01 and Exhibits 99.1, 99.2, and 99.3 of Item 9.01 is being furnished, not filed. Accordingly, the information in this Item 7.01 and Exhibits 99.1, 99.2, and 99.3 of Item 9.01 will not be incorporated by reference into any registration statement filed by ConocoPhillips under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference. The furnishing of the information in this report is not intended to, and does not, constitute a determination or admission by ConocoPhillips that (i) the information in this report is material or complete or (ii) investors should consider this information before making an investment decision with respect to any security of ConocoPhillips or any of its affiliates.

Item 9.01 Financial Statements and Exhibits

     (c) Exhibits

99.1	— Press Release dated October 5, 2006
99.2	— Slide presentation given by certain executive officers of ConocoPhillips on October 5, 2006
99.3	— Investor Supplement

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	CONOCOPHILLIPS
	/s/ Stephen F. Gates
October 5, 2006	Stephen F. Gates
	Senior Vice President and General Counsel

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press Release dated October 5, 2006.
99.2	Slide presentation given by certain executive officers of ConocoPhillips on October 5, 2006
99.3	Investor Supplement

EX-99.1

Exhibit 99.1

600 North Dairy Ashford (77079-1175)
P. O. Box 2197
Houston, TX 77252-2197
Phone 281.293.1000
www.conocophillips.com

NEWS RELEASE

ConocoPhillips and EnCana to Create Integrated
North American Heavy Oil Business

Production from Foster Creek and Christina Lake expected to reach 400,000 BPD by 2015; Heavy
oil processing capacity at Wood River and Borger refineries to be expanded to 550,000 BPD by 2015

HOUSTON, Oct. 5, 2006 — ConocoPhillips [NYSE:COP] and EnCana Corporation [TSX/NYSE:ECA] have entered into an agreement to create an integrated, North American heavy oil business consisting of strong upstream and downstream assets.

The venture will be comprised of two 50/50 operating partnerships, one Canadian upstream partnership and one U.S. downstream partnership, with both companies contributing equally valued assets and equity for future capital expenditures.

The upstream partnership will consist of EnCana’s Foster Creek and Christina Lake projects, both located in the prolific eastern flank of the Athabasca oilsands in northeast Alberta. The assets hold independently estimated recoverable bitumen of more than 6.5 billion barrels, and the partnership’s goal is to increase production from the current 50,000 barrels per day (BPD) to 400,000 BPD of bitumen by 2015. The partnership plans to transport and sell the bitumen blend (an approximate 50/50 blend of bitumen and synthetic oil) at major Alberta trading hubs. ConocoPhillips and EnCana will each own 50 percent of the partnership. EnCana will be the operator and managing partner of the upstream partnership, which will be headquartered in Calgary.

The downstream partnership will consist of ConocoPhillips’ Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively. The partnership plans to expand heavy oil processing capacity at these facilities from approximately 60,000 BPD to 550,000 BPD (30,000 BPD to 275,000 BPD of bitumen handling capacity) by 2015. Total throughput at the two facilities is expected to increase from the current 450,000 BPD to 600,000 BPD over the same time period. The partnership may further expand heavy oil processing capacity at these locations or in Alberta to match bitumen production. ConocoPhillips and EnCana will each own 50 percent of the partnership; however, ConocoPhillips will hold a disproportionate economic interest in Borger for two years: 85 percent in 2007 and 65 percent in 2008. The partnership plans to purchase and transport all feedstocks for the refineries and sell the refined products. ConocoPhillips will be the operator and managing partner of the downstream partnership, which will be headquartered in Houston.

“With this strategic alliance, ConocoPhillips strengthens its presence in North America by repositioning 10 percent of its U.S. downstream business to access a large upstream resource base. The upstream partnership also will provide a secure and stable source of oil supplies that can be refined into gasoline, diesel and other petroleum products needed by U.S. consumers, as well as a significant market for Canada’s abundant oilsands resources,” said Jim Mulva, ConocoPhillips’ chairman and chief executive officer. “This venture builds on our current and planned heavy-oil expansion work at both Wood River and Borger, and provides a stable, long-term supply to our U.S. refineries. The venture also enables ConocoPhillips’ participation in two best-in-class Canadian oilsands projects, and provides the opportunity to leverage our existing downstream capabilities. The transaction is expected to enhance ConocoPhillips’ near- and long-term production growth, providing a steady, stable source of resource additions. We look forward to working closely with EnCana and learning from their experiences as a leader in heavy-oil development and SAGD technology.”

“During the past year, we undertook a process to identify the best industry partners for maximizing the value recognition of our sizeable in-situ oilsands resources. These innovative partnerships achieve this objective by strategically aligning about two-thirds of our industry-leading oilsands projects with an industry-leading refiner. ConocoPhillips brings a wealth of heavy oil refining expertise and widely-adopted coking technology to our integrated heavy oil business,” said Randy Eresman, EnCana’s president and chief executive officer. “These partnerships provide greater certainty of execution for our oilsands projects by reducing cost and price risk and increasing confidence in our ability to achieve economic returns. They also give EnCana immediate participation in the North American refining industry and provide options for future upgrader development.”

Each partnership will have a management committee composed of three ConocoPhillips and three EnCana representatives, with each company holding equal voting rights. ConocoPhillips and EnCana personnel associated with the partnerships will remain employees of their current respective employers.

Both ConocoPhillips and EnCana are committed to being leaders in the area of health, safety and environmental stewardship. Specifically, the companies expect to jointly fund and pursue research and technology development efforts aimed at minimizing the environmental footprint of the partnerships’ upstream and downstream operations.

The transaction, which is subject to the execution of final definitive agreements and regulatory approval, is expected to close January 2, 2007. Both companies’ boards of directors have approved the transaction.

JP Morgan acted as advisor to ConocoPhillips on this transaction, and Credit Suisse acted as advisor to EnCana.

ConocoPhillips
ConocoPhillips is an integrated petroleum company with interests around the world. Headquartered in Houston, the company had approximately 38,000 employees, $162 billion of assets, and $188 billion of annualized revenues as of June 30, 2006. For more information, go to www.conocophillips.com.

EnCana Corporation
With an enterprise value of approximately US$45 billion, EnCana is one of North America’s leading natural gas producers, is among the largest holders of gas and oil resource lands onshore North America and is a technical and cost leader in the in-situ recovery of oilsands bitumen. For more information, go to www.encana.com.

- # # # -

ConocoPhillips will hold a conference call and webcast at 9 a.m. Eastern today. To listen
to the conference call and to view related presentation materials, go to
www.conocophillips.com and click on the “ConocoPhillips-EnCana Transaction” link.

EnCana will hold a conference call 10 a.m. Eastern today. For information on how to
join the conference call and to view related presentation materials, go to
www.encana.com.

Contacts:
ConocoPhillips		EnCana
Gary Russell (investors)	212-207-1996	Sheila McIntosh (investors)	403-645-2194
Becky Johnson (media)	281-293-6743	Paul Gagne (investors)	403-645-4737
		Ryder McRitchie (investors)	403-645-2007
		Alan Boras (media)	403-645-4747

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995

This press release 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, the ability of the parties to obtain necessary regulatory approvals, 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 press release such as “oilsands,” “recoverable bitumen,” “oilsands resources,” “heavy oil,” and/or “resource additions,” 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.

EX-99.2

EXHIBIT 99.2

October 5, 2006 Creating an Integrated North American Heavy Oil Business

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 11 and 12) 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 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 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 Maximizes oilsands value creation and recognition: Partners with leading refiner with top tier assets Demonstrates commitment to oilsands growth strategy Enhances visibility of development plans Eliminates exposure to light/heavy differentials Reduces project execution risk Accelerates timeframe for downstream integration Captures full refined product margin on bitumen production Leverages capabilities and technologies

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.

Benefits of Integration Leader in oilsands development and SAGD technology Leader in heavy oil refining and coking technology Enhances certainty of integrated margin on investments Reduces cash-flow volatility due to swings in light/heavy differentials Facilitates significant expansion of oilsands projects and refineries Leverages existing infrastructure and economies of scope and scale Provides long-term supply to attractive North American product markets Expands demand for bitumen and synthetic crude Combines outstanding track records in terms of safety, environmental and business performance Partnership Benefits

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 Over 10 years Contribution Obligation Over 10 years

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

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 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)*

Industry Transportation Initiatives Expanding Market Access

EnCana's Leading SAGD Position Partnership Resource Opportunity ~900,000 net acres contributed (leased or option to lease) Estimated 44.5 billion bbls bitumen in place* Estimated >6.5 billion bbls recoverable bitumen* Estimated 400,000 bpd by 2015 Premium SAGD reservoirs Low SOR High gravity Advantaged proximity to markets Christina Lake Foster Creek 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018+ Foster Creek 66 97 110 144 151 159 187 210 210 210 210 210 Christina Lake 7 12 26 59 89 116 151 190 190 190 190 190 Mbpd of bitumen *Note: Recoverable bitumen (after royalty) and bitumen in place (gross before royalty) estimates provided by McDaniel & Associates Consultants Ltd. - represent 100% interest. Calgary Edmonton ALBERTA

COP's Expanding Refining Capacity 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018+ Foster Creek 48 60 90 120 150 168 186 204 222 240 258 278 278 Christina Lake 7 10 10 40 70 100 130 190 190 220 250 280 310 Bitumen refining capacity 32.4 32.4 51.3 143 143 143 183.4 278.7 278.7 278.7 278.7 278.7 278.7 Heavy Processing Capacity 0 32.4 51.3 143 143 143 183.4 278.7 278.7 278.7 278.7 278.7 278.7 Sweet refining capacity 450 417.6 406 276.5 276.5 276.5 252.3 50.3 50.3 50.3 50.3 50.3 50.3 Light capacity Bitumen capacity Wood River and Borger expansions underway Partnership enables accelerated growth compared to previously announced plans Total Throughput - MBPD Total Throughput - MBPD Bitumen Capacity - MBPD Bitumen Capacity - MBPD Clean product yield - % Clean product yield - % Current Planned Current Planned Current Planned Wood River 306 400 30 200 77 87 Borger* 146 200 0 75 90 90 Total Heavy Processing capacity *Note: Capacity numbers for Borger do not include NGL capacity of ~50,000 bpd. Mbpd of total throughout capacity

Bitumen Volume Match Foster Creek & Christina Lake vs. Wood River & Borger Mbbls/d 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018+ Bitumen production 55 74 109 136 203 240 275 338 400 400 400 405 405 Christina Lake Total bitumen refining capacity 32.4 32.4 51.3 143 143 143 183.4 278.7 278.7 278.7 278.7 278.7 278.7 Borger Future upgrading solution 0 0 0 0 60 97 92 59 121 121 229 279 309 Further expansion of capacity in Alberta or U.S. as warranted Bitumen Production Total Bitumen Refining Capacity Future Upgrading Solution

Fully-integrated oilsands solution World-class projects in both Upstream and Downstream Access to capital, people, and best technologies Certainty of margin Integrated approach captures value from reservoir to refined product Certainty of project execution through integrated approach Field development and production growth with refinery access Expanded heavy refining capacity with long-term supply Outstanding industry track record in terms of safety, environmental and business performance Estimated 400,000 bpd of bitumen supply by 2015 to attractive North American destinations Transaction Benefits

Asset Appendix Upstream Assets

Foster Creek Overview Overview Located in the southeastern corner of Canada's oilsands region First commercial scale SAGD project Pilot phase began in 1997 Commercial development began in 2001 Consistently among the best commercial and technical SAGD projects Cumulative production of over 30 mmbbls Steam/oil ratio among lowest of all SAGD projects Currently producing 43,000 bpd of bitumen Expansion underway to reach 60,000 bpd by early 2007 Two additional 30,000 bpd expansions expected to be on stream in late 2008 and 2009 respectively Christina Lake Foster Creek Calgary Edmonton ALBERTA

Foster Creek Project Project details ~200,000 + net acres leased Option to lease 500,000 net acres Estimated 29 billion barrels of bitumen in place* Estimated 2.4 billion barrels of recoverable bitumen* Estimated capital costs of $3.1 billion through 2015* Forecast production estimate of 210,000 bpd of bitumen by 2015 Bitumen API Gravity of 10o Estimated resource life of > 30 years Estimated steam/oil ratio of 2.0-2.5 over life of the project Bitumen Production (bbl/d) 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 EnCana updated 48000 66000 97000 110000 144000 151000 159000 187000 210000 210000 Capital Expenditures ($ Millions)* 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 EnCana updated 928 523 379 280 492 507 185 292 146 294 *Note: Recoverable bitumen (after royalty) and bitumen in place (gross before royalty) estimates provided by McDaniel & Associates Consultants Ltd. - represent 100% interest. Capital expenditures are in 2006$ terms, and are for 100% expenditures. Source: Company estimates (Production and Capital estimates per ECA).

Christina Lake Overview Overview Located in the southern portion of Canada's oilsands region Phase I was initiated in 2002 Cumulative production of over 3.5 mmbls Steam/oil ratio among lowest of all SAGD projects Current production of 7,000 bpd of bitumen from six SAGD well pairs Current expansion expected to take production to 18,000 bpd in the last half of 2008 Calgary Edmonton ALBERTA Christina Lake Foster Creek

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 EnCana 7000 7000 12000 26000 59000 89000 116000 151000 190000 190000 Christina Lake Project Bitumen Production (bbl/d) Capital Expenditures ($ Millions)* Project Details ~180,000+ net acres leased Estimated 15 billion barrels of bitumen in place* Estimated 4.2 billion barrels of recoverable bitumen* Estimated capital costs of $2.3 billion through 2015* Forecast production estimate of 190,000 bpd of bitumen by 2015 Bitumen API gravity of 9o Estimated resource life of > 60 years Estimated steam/oil ratio of 2.0-2.5 over life of the project 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 EnCana 243.7 288 334 226 244 305 340 273 93 162 *Note: Recoverable bitumen (after royalty) and bitumen in place (gross before royalty) estimates provided by McDaniel & Associates Consultants Ltd. - represent 100% interest. Capital expenditures are in 2006$ terms, and are for 100% expenditures. Source: Company estimates (Production and Capital estimates per ECA).

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)

Asset Appendix Downstream Assets

Wood River Overview Overview Located in Roxana, Illinois Largest ConocoPhillips Refinery (10th largest in the U.S.) 306,000 bpd throughput, multiple train refinery 30,000 bpd bitumen capacity Clean product yield 77% ~2,200 acres Multiple pipeline options for receiving Canadian crude Excellent access to markets in St. Louis and Chicago Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Pipeline and water Borger Wood River

Wood River Expansion Details Wood River Capacity (mbpd) 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Bitumen 32.4 32.4 32.4 102.5 102.5 102.5 102.5 197.8 197.8 197.8 197.8 197.8 197.8 Other refining capacity 291.8 291.8 291.8 275.6 275.6 275.6 275.6 168.9 168.9 168.9 168.9 168.9 168.9 Capital Expenditures ($ Millions)* Core Project (current expansion) 2009 completion Addition of estimated 70,000 bpd bitumen capacity Estimated $1.9 B capital cost New 65,000 bpd large coker facility Phase 2 Expansion Project 2013 completion Addition of estimated 100,000 bpd of bitumen capacity Crude unit and coker expansion to 375,000 - 400,000 bpd Enables 100% bitumen refining capacity Estimated $2.0 B capital cost 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Updated Mgmt presentation 268 637 985 430 422 1243 443 85 85 85 85 85 85 *Note: Capital expenditures are in 2006$ terms, and are for 100% expenditures. Source: Company estimates (Capacity and Capital estimates per COP).

Borger Overview Overview Located in Borger, Texas - - 50 miles northeast of Amarillo, TX 146,000 bpd crude; 50,000 bpd NGL capacity Nelson complexity: 13.3 Clean product yield: 90% Integrated with NGL production OSHA VPP Star site since 2002 ~2,600 acres Mid-continent, Denver and Midwest markets Excellent pipeline access Line O project: New pipeline capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger capacity from Cushing to Borger Borger Wood River

Phase 1 2007 completion New coker Addition of estimated 20,000 bpd bitumen capacity Estimated $0.5B capital cost Phase 2 2009 completion Debottleneck infrastructure to add incremental estimated 20,000 bpd bitumen capacity Estimated $0.3B capital cost Phase 3 2012 completion Expand Crude Rate to ~200,000 bpd with ~75,000 bpd bitumen capacity Estimated $0.6B capital cost Borger Expansion Details Borger Bitumen Capacity (mbpd) Capital Expenditures ($ Millions)* 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Updated Mgmt presentation 283 113 45 130 390 131 39 39 39 39 39 39 39 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Bitumen 0 0 18.9 40.5 40.5 40.5 80.9 80.9 80.9 80.9 80.9 80.9 80.9 Other refining capacity 158.2 158.2 165.5 143.9 143.9 143.9 160.1 160.1 160.1 160.1 160.1 160.1 160.1 *Note: Capital expenditures are in 2006$ terms, and are for 100% expenditures. Source: Company estimates (Capacity and Capital estimates per COP).

EX-99.3

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.