##### 



U.S. SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 40-F (Check One) oRegistration statement pursuant to Section 12 of the Securities Exchange Act of 1934 or þ
Annual report pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934 For the fiscal year ended December 31, 2004 Commission file number 1-15226 ENCANA CORPORATION  Canada
(Province or other
jurisdiction of
incorporation or organization)
    
    1311
(Primary Standard Industrial
Classification Code Number(if
applicable))
    
    Not applicable
(I.R.S. Employer
Identification Number (if
Applicable))
 1800-855 2nd Street, S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5
(403) 645-2000
(Address and Telephone Number of Registrants Principal Executive Offices) CT Corporation System,
111 8th Avenue, New York, NY 10011
(212) 894-8940
(Name, Address (Including Zip Code) and Telephone Number
(Including Area Code) of Agent For Service in the United States) Securities registered or to be registered pursuant to Section 12(b) of the Act. Title of each class
    
    Name of each exchange on which registeredCommon Shares
    
    New York Stock Exchange
 Securities registered or to be registered pursuant to Section 12(g) of the Act. None Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. Debt Securities For annual reports, indicate by check mark the information filed with this Form: þ Annual Information Form
    
    þ Audited Annual Financial Statements
 Indicate the number of outstanding shares of each of the issuers classes of capital or common
stock as of the close of the period covered by the annual report: 449,997,384 Indicate by check mark whether the registrant by filing the information contained in this Form
is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the
Securities Exchange Act of 1934 (the Exchange Act). If Yes is marked, indicate the file number
assigned to the registrant in connection with such rule. Yes o No þ Indicate by check mark whether the registrant: (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports); and (2) has been subject to such
filing requirements for the past 90 days. Yes þ No o The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as
applicable, each of the registrants Registration Statements under the Securities Act of 1933:
Form S-8 (File Nos. 333-13956 and 333-85598) and Form F-9 (File Nos. 333-113732 and
333-118737).




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FORM 40-F Principal Documents The following documents have been filed as part of this Annual Report on Form 40-F, beginning on
the following page: (a)
    
    Annual Information Form for the fiscal year ended December 31, 2004;(b)
    
    Managements Discussion and Analysis of Financial Condition and Results of
Operations for the fiscal year ended December 31, 2004; and(c)
    
    Consolidated Financial Statements for the fiscal year ended December 31, 2004 (Note 20 to the
Consolidated Financial Statements relates to United States Accounting Principles and Reporting
(U.S. GAAP)).
 40-F1




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ANNUAL INFORMATION FORM


February 25, 2005




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TABLE OF CONTENTS


|                                                                                               |                                                |                                                             |    |    |    | 
|---------------------------------------------------------------------------------------------- | ---------------------------------------------- | ----------------------------------------------------------- | -- | -- | -- | 
|                                                                                               |                                                | Page                                                        |   
|                                                                                               |                                                |                                                             |   
|INTRODUCTORY INFORMATION                                                                       |                                                |                                                             | 1  |   
|NOTE REGARDING FORWARD-LOOKING
    STATEMENTS                                                  |                                                |                                                             | 2  |   
|NOTE REGARDING RESERVES DATA AND OTHER OIL
    AND GAS INFORMATION                             |                                                |                                                             | 3  |   
|CORPORATE STRUCTURE                                                                            |                                                |                                                             | 4  |   
|                                                                                               | Name and Incorporation                         |                                                             |    | 4  |   
|                                                                                               | Intercorporate Relationships                   |                                                             |    | 4  |   
|GENERAL DEVELOPMENT OF THE BUSINESS                                                            |                                                |                                                             | 5  |   
|                                                                                               | Upstream                                       |                                                             |    | 5  |   
|                                                                                               | Midstream & Marketing                          |                                                             |    | 6  |   
|NARRATIVE DESCRIPTION OF THE BUSINESS                                                          |                                                |                                                             | 8  |   
|                                                                                               | UPSTREAM                                       |                                                             |    | 9  |   
|                                                                                               |                                                | Canada                                                      |    |    | 9  | 
|                                                                                               |                                                | United States                                               |    |    | 14 | 
|                                                                                               |                                                | International New Ventures Exploration                      |    |    | 16 | 
|                                                                                               |                                                | Ecuador                                                     |    |    | 17 | 
|                                                                                               | MIDSTREAM & MARKETING                          |                                                             |    | 18 |   
|                                                                                               |                                                | Midstream                                                   |    |    | 18 | 
|                                                                                               |                                                | Marketing                                                   |    |    | 20 | 
|                                                                                               | RESERVES AND OTHER OIL AND GAS
    INFORMATION |                                                             |    | 22 |   
|                                                                                               |                                                | Reserve Quantities Information                              |    |    | 22 | 
|                                                                                               |                                                | Other Disclosures About Oil and Gas
    Activities          |    |    | 24 | 
|                                                                                               |                                                | Daily Sales Volumes, Royalty Rates and
    Per-Unit Results |    |    | 28 | 
|                                                                                               |                                                | Drilling Activity                                           |    |    | 39 | 
|                                                                                               |                                                | Location of Wells                                           |    |    | 41 | 
|                                                                                               |                                                | Interest in Material Properties                             |    |    | 42 | 
|                                                                                               |                                                | Acquisitions, Dispositions and Capital
    Expenditures     |    |    | 44 | 
|                                                                                               |                                                | Delivery Commitments                                        |    |    | 45 | 
|                                                                                               | GENERAL                                        |                                                             |    | 45 |   
|                                                                                               |                                                | Competitive Conditions                                      |    |    | 45 | 
|                                                                                               |                                                | Environmental Protection                                    |    |    | 45 | 
|                                                                                               |                                                | Social and Environmental Policies                           |    |    | 45 | 
|                                                                                               |                                                | Employees                                                   |    |    | 46 | 
|                                                                                               |                                                | Foreign Operations                                          |    |    | 46 | 
|                                                                                               |                                                | Reorganizations                                             |    |    | 46 | 
|DIRECTORS AND OFFICERS                                                                         |                                                |                                                             | 47 |   
|AUDIT COMMITTEE INFORMATION                                                                    |                                                |                                                             | 49 |   
|DESCRIPTION OF SHARE CAPITAL                                                                   |                                                |                                                             | 51 |   
|CREDIT RATINGS                                                                                 |                                                |                                                             | 52 |   
|MARKET FOR SECURITIES                                                                          |                                                |                                                             | 53 |   
|DIVIDENDS                                                                                      |                                                |                                                             | 54 |   
|LEGAL PROCEEDINGS                                                                              |                                                |                                                             | 54 |   
|RISK FACTORS                                                                                   |                                                |                                                             | 54 |   
|TRANSFER AGENTS AND REGISTRARS                                                                 |                                                |                                                             | 59 |   
|INTERESTS OF EXPERTS                                                                           |                                                |                                                             | 59 |   
|ADDITIONAL INFORMATION                                                                         |                                                |                                                             | 59 |   
|APPENDIX A  Report on
    Reserves Data by Independent Qualified Reserves Evaluators          |                                                |                                                             | 60 |   
|APPENDIX B  Report of
    Management and Directors on Reserves Data and Other
    Information |                                                |                                                             | 62 |   
|APPENDIX C  Audit Committee
    Mandate                                                       |                                                |                                                             | 63 |   



i



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INTRODUCTORY INFORMATION


Business Corporations Act








Unless otherwise specified, all dollar amounts are expressed
in United States dollars and all references to
dollars or $ are to United States
dollars and all references to C$ are to Canadian
dollars.


1



---



##### 






NOTE REGARDING FORWARD-LOOKING STATEMENTS






2



---



##### 






NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS
INFORMATION












3



---



##### 






CORPORATE STRUCTURE





Name and Incorporation


Canada Business
Corporations Act .







Intercorporate Relationships




|                                             |  |            |     |                 |              |            
|-------------------------------------------- |  | ---------- | --- | --------------- | ------------ | -----------
|                                             |  |            |     | Jurisdiction of
|                                             |  |            |     | Incorporation, 
|                                             |  | Percentage |     |                 | Continuance 
|Subsidiaries & Partnerships                  |  | Owned(1)   |     |                 | or Formation
|                                            
|EnCana West Ltd.                             |  |            | 100 |                 |              | Alberta    
|EnCana Oil & Gas Partnership                 |  |            | 100 |                 |              | Alberta    
|EnCana USA Holdings                          |  |            | 100 |                 |              | Delaware   
|3080763 Nova Scotia Company                  |  |            | 100 |                 |              | Nova Scotia
|Alenco Inc.                                  |  |            | 100 |                 |              | Delaware   
|EnCana Oil & Gas (USA) Inc.                  |  |            | 100 |                 |              | Delaware   
|EnCana Marketing (USA) Inc.                  |  |            | 100 |                 |              | Delaware   
|McMurry Oil
    Company(2)                   |  |            | 100 |                 |              | Wyoming    
|Plaza Acquisition I
    Corp.(2)             |  |            | 100 |                 |              | Delaware   
|Tom Brown,
    Inc.(2)                       |  |            | 100 |                 |              | Delaware   
|EnCana Midstream & Marketing (Holdings) Inc. |  |            | 100 |                 |              | Canada     
|EnCana Midstream & Marketing                 |  |            | 100 |                 |              | Alberta    
|                                            





|    |                                                                                                                      
|--- | ---------------------------------------------------------------------------------------------------------------------
|(1) | Includes indirect ownership.                                                                                         
|(2) | Merged with EnCana Oil & Gas (USA) Inc. on January 1,
    2005. EnCana Oil & Gas (USA) Inc. is the continuing entity.



4



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GENERAL DEVELOPMENT OF THE BUSINESS









Upstream






2004 Acquisitions:




|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In the first quarter of 2004, a subsidiary of EnCana completed
    the purchase, through two separate transactions, of additional
    interests in the U.K. central North Sea, for net cash
    consideration of approximately $131 million.                                                                                                                                                                                                                                                           
| 
| | In May 2004, a subsidiary of EnCana completed the acquisition of
    Tom Brown, Inc. (Tom Brown) for total consideration
    of approximately $2.7 billion, including debt of
    approximately $406 million. Tom Brown was a resource play
    focused, natural gas exploration and production company
    headquartered in Denver, Colorado. The Tom Brown assets are
    located in the Piceance, Green River, Wind River, Paradox, East
    Texas, Permian and Western Canada Sedimentary basins.
| 
| | In December 2004, a subsidiary of EnCana purchased natural gas
    assets in north Texas for approximately $251 million,
    subject to post-closing adjustments.                                                                                                                                                                                                                                                                                                                                      

2004 Dispositions:




|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In February 2004, EnCana sold its 53.3 percent interest in
    Petrovera Resources (Petrovera), an Alberta
    partnership that produces heavy oil in western Canada, for net
    cash consideration of approximately $287 million.                                                                                                                                                                                                                                                                                                                                                        
| 
| | In July 2004, a subsidiary of EnCana sold assets in New Mexico
    for approximately $228 million.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| 
| | In August 2004, EnCana sold conventional natural gas properties
    in northeast Alberta for approximately $225 million,
    subject to post-closing adjustments.                                                                                                                                                                                                                                                                                                                                                                                                                            
| 
| | In September 2004, the Corporation sold conventional oil and gas
    assets for approximately $388 million, subject to
    post-closing adjustments. This transaction included properties
    in east central and southern Alberta producing predominantly
    medium and heavy oil.                                                                                                                                                                                                                                                                                                         
| 
| | In December 2004, a subsidiary of EnCana closed the sale of all
    of its U.K. central North Sea assets for approximately
    $2.1 billion. These interests included a 43.2 percent
    interest in the Buzzard oil field, a 41.0 and 54.3 percent
    interest, respectively, in the Scott and Telford oil fields,
    other satellite discoveries, plus interests in exploration
    licences covering more than 740,000 net acres in the North Sea.
    As a result of this disposition, the U.K. Region is now treated
    as a discontinued operation for financial reporting purposes.



5



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##### 









2003 Acquisitions:




|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In January 2003, EnCana acquired reserves and production in
    Ecuador from Vintage Petroleum, Inc. for net cash consideration
    of approximately $116 million.                                                                                                                                                                                                                                                                                                                                                                 
| 
| | In September 2003, EnCana completed the acquisition of
    approximately 500,000 net acres of prospective natural gas
    development lands in Cutbank Ridge, which is located in the
    foothills of British Columbia and Alberta. EnCana purchased a
    majority interest in 39 parcels of land totalling roughly
    350,000 net acres for approximately $270 million. The
    Corporation had previously acquired about 150,000 net acres
    through purchases and land swaps with other companies and Crown
    land sales.
| 
| | In October 2003, EnCana Oil & Gas (USA) Inc. acquired
    natural gas and associated NGLs production, reserves and acreage
    from Mesa Hydrocarbons LLC for net cash consideration of
    approximately $100 million. The principal producing
    properties acquired are in the Piceance Basin of northwest
    Colorado.                                                                                                                                                                                                       
| 
| | In October 2003, a subsidiary of EnCana exchanged its
    non-operated interest in the Llano discovery in the Gulf of
    Mexico for an additional 14 percent interest in each of the
    Scott and Telford fields in the U.K. central North Sea, which
    were received by another subsidiary of EnCana.                                                                                                                                                                                                                         

2003 Dispositions:




|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In February 2003, EnCana sold a 10 percent interest in the
    Syncrude Joint Venture (Syncrude) for net cash
    consideration of approximately $690 million. In July 2003,
    EnCana sold its remaining 3.75 percent interest in Syncrude
    and an overriding royalty for net cash consideration of
    approximately $309 million. Both of these transactions are
    subject to post-closing adjustments. Syncrude operates a
    facility in northeast Alberta which produces crude oil from
    oilsands.

2002 Acquisitions:




|  |                                                                                                                                                                                                                                                                                             
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In May 2002, wholly owned subsidiaries of EnCana Oil & Gas
    (USA) Inc. acquired natural gas and associated NGLs production,
    reserves and acreage located in the Piceance Basin of northwest
    Colorado from subsidiaries of El Paso Corporation for
    approximately $275 million.
| 
| | In July 2002, EnCana Oil & Gas (USA) Inc. acquired natural
    gas and associated NGLs production, reserves and acreage located
    in the Jonah natural gas field in southwest Wyoming from a
    subsidiary of The Williams Companies for approximately
    $350 million.                 






Midstream & Marketing




6



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##### 





2004 Projects:




|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In March 2004, a 10 billion cubic feet expansion was
    completed at the Wild Goose natural gas storage facility in
    northern California. The expansion increased the total working
    gas capacity to approximately 24 billion cubic feet.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
| 
| | In June 2004, following successful completion of its open
    season, Entrega Gas Pipeline Inc. (Entrega), an
    affiliate of EnCana Oil & Gas (USA) Inc., announced
    that it is proceeding with its proposed natural gas pipeline
    project. Entrega filed its certificate application with the
    U.S. Federal Energy Regulatory Commission
    (FERC) in September 2004 for construction of the
    pipeline from Colorados Piceance Basin, through Wamsutter,
    Wyoming, to the Cheyenne natural gas trading hub in northeast
    Colorado. The pace of construction will be dependent upon FERC
    certification. If approved, the first segment of the pipeline to
    Wamsutter, Wyoming is expected to be on stream in late 2005,
    with an initial capacity of approximately 700 million cubic
    feet per day.
| 
| | In November 2004, EnCana Midstream & Marketing, a wholly
    owned partnership of EnCana, signed a memorandum of
    understanding with The Premcor Refining Group Inc., an indirect
    wholly owned subsidiary of U.S. independent oil refiner
    Premcor Inc., to conduct a preliminary design and engineering
    study of the modifications necessary to upgrade Premcors
    existing refinery at Lima, Ohio to process an estimated 200,000
    barrels per day of blended EnCana heavy oil supplied under a
    proposed long-term sales contract. The memorandum contemplates
    the establishment of a 50-50 joint venture which would own and
    operate the upgraded refinery.                                                                                                                                            

2004 Dispositions:




|  |                                                                                                                                                                                                                                                                                                                                          
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In December 2004, EnCana sold its 25 percent non-operated
    partnership interest in the Kingston CoGen Limited Partnership
    (Kingston CoGen) for net cash consideration of
    approximately $25 million, subject to post-closing
    adjustments. Kingston CoGen owns a 110 megawatt cogeneration
    plant in Kingston, Ontario.
| 
| | In December 2004, EnCana disposed of its interest in the Alberta
    Ethane Gathering System joint venture for approximately
    $108 million, subject to post-closing adjustments.                                                                                                                                                      

2003 Projects:




|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In October 2003, the first phase of the Countess natural gas
    storage facility came online, adding 10 billion cubic feet
    of capacity. The facility is located east of Calgary. The
    completion of plant facilities at Countess increased capacity to
    approximately 30 billion cubic feet in 2004. Utilization of
    the full design capacity of 40 billion cubic feet is
    expected in 2005, upon approval to operate at increased
    pressures in the reservoir.                                                                                                                                                                                             
| 
| | In October 2003, plans to develop a new natural gas storage
    facility at Starks, in southwest Louisiana, were announced by a
    subsidiary of EnCana. An open season for capacity was held in
    early 2004. In October 2004, an application was filed with the
    FERC requesting regulatory approval. Subject to regulatory
    approvals and a satisfactory second open season in February
    2005, the facility is expected to be in service during the third
    quarter of 2006 with approximately 9 billion cubic feet of
    initial storage capacity. Full future capacity of the Starks
    facility is expected to be approximately 19 billion cubic
    feet.

2003 Dispositions:




|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | In January 2003, EnCana completed the sale of its indirect
    70 percent interest in the Cold Lake Pipeline System for
    approximately $270 million. Also in January 2003, EnCana
    completed the sale of its indirect 100 percent interest in
    the Express Pipeline System (Express) for
    approximately $778 million, which included the assumption
    of approximately $385 million in debt by the purchaser.
    EnCana retained crude oil transportation capacity on both
    pipelines through its existing long-term commercial contracts.

2002 Dispositions:




|  |                                                                                                         
|- | --------------------------------------------------------------------------------------------------------
| | All Houston-based merchant energy trading operations were
    discontinued following the Merger in 2002.

7



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NARRATIVE DESCRIPTION OF THE BUSINESS







8



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UPSTREAM









Canada






Canadian Plains Region








|                      |  |           |       |  |             |  |       |               |  |  |                 |  |  |       |       |  |     |  |        |          |  |  |        |  |  |  |     |  
|--------------------- |  | --------- | ----- |  | ----------- |  | ----- | ------------- |  |  | --------------- |  |  | ----- | ----- |  | --- |  | ------ | -------- |  |  | ------ |  |  |  | --- | -
|                      |  | Developed |       |  | Undeveloped |  |       |               |  | 
|Landholdings          |  | Acreage   |       |  | Acreage     |  |       | Total Acreage |  |  | Average Working | 
|(thousands of acres)  |  | Gross     |       |  | Net         |  |       | Gross         |  |  | Net             |  |  | Gross |       |  | Net |  |        | Interest | 
|                     
|Suffield              |  |           | 942   |  |             |  | 930   |               |  |  | 275             |  |  |       | 271   |  |     |  | 1,217  |          |  |  | 1,201  |  |  |  | 99  | %
|Brooks                |  |           | 1,232 |  |             |  | 1,206 |               |  |  | 183             |  |  |       | 170   |  |     |  | 1,415  |          |  |  | 1,376  |  |  |  | 97  | %
|Chinook               |  |           | 1,344 |  |             |  | 1,317 |               |  |  | 300             |  |  |       | 279   |  |     |  | 1,644  |          |  |  | 1,596  |  |  |  | 97  | %
|Foster Creek          |  |           | 6     |  |             |  | 6     |               |  |  | 52              |  |  |       | 52    |  |     |  | 58     |          |  |  | 58     |  |  |  | 100 | %
|Christina Lake        |  |           | 4     |  |             |  | 4     |               |  |  | 68              |  |  |       | 62    |  |     |  | 72     |          |  |  | 66     |  |  |  | 92  | %
|Weyburn               |  |           | 73    |  |             |  | 64    |               |  |  | 460             |  |  |       | 449   |  |     |  | 533    |          |  |  | 513    |  |  |  | 96  | %
|Other                 |  |           | 2,873 |  |             |  | 2,452 |               |  |  | 5,890           |  |  |       | 5,502 |  |     |  | 8,763  |          |  |  | 7,954  |  |  |  | 91  | %
|                     
|Canadian Plains Total |  |           | 6,474 |  |             |  | 5,979 |               |  |  | 7,228           |  |  |       | 6,785 |  |     |  | 13,702 |          |  |  | 12,764 |  |  |  | 93  | %
|                     

9



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|                      |  |             |       |  |                    |  |       |                  |  |  |                  |  |  |      |         |  |      |  |       |      |  |  |       |  |  |  |         |  |  |  |         | 
|--------------------- |  | ----------- | ----- |  | ------------------ |  | ----- | ---------------- |  |  | ---------------- |  |  | ---- | ------- |  | ---- |  | ----- | ---- |  |  | ----- |  |  |  | ------- |  |  |  | ------- | 
|                      |  | Natural Gas |       |  | Crude Oil and NGLs |  |       | Total Production |  |  | Total Production | 
|Production            |  | (MMcf/d)    |       |  | (bbls/d)           |  |       | (MMcfe/d)        |  |  | (BOE/d)          | 
|(annual average)      |  | 2004        |       |  | 2003               |  |       | 2004             |  |  | 2003             |  |  | 2004 |         |  | 2003 |  |       | 2004 |  |  | 2003  | 
|                      | 
|Suffield              |  |             | 241   |  |                    |  | 230   |                  |  |  | 26,706           |  |  |      | 26,945  |  |      |  | 401   |      |  |  | 391   |  |  |  | 66,873  |  |  |  | 65,279  | 
|Brooks                |  |             | 474   |  |                    |  | 434   |                  |  |  | 15,542           |  |  |      | 15,295  |  |      |  | 568   |      |  |  | 526   |  |  |  | 94,542  |  |  |  | 87,628  | 
|Chinook               |  |             | 356   |  |                    |  | 329   |                  |  |  | 7,150            |  |  |      | 7,342   |  |      |  | 399   |      |  |  | 373   |  |  |  | 66,483  |  |  |  | 62,175  | 
|Foster Creek          |  |             |      |  |                    |  |      |                  |  |  | 28,774           |  |  |      | 21,823  |  |      |  | 173   |      |  |  | 131   |  |  |  | 28,774  |  |  |  | 21,823  | 
|Christina Lake        |  |             |      |  |                    |  |      |                  |  |  | 4,364            |  |  |      | 3,806   |  |      |  | 26    |      |  |  | 23    |  |  |  | 4,364   |  |  |  | 3,806   | 
|Weyburn               |  |             |      |  |                    |  |      |                  |  |  | 14,200           |  |  |      | 10,846  |  |      |  | 85    |      |  |  | 65    |  |  |  | 14,200  |  |  |  | 10,846  | 
|Other                 |  |             | 203   |  |                    |  | 188   |                  |  |  | 30,184           |  |  |      | 44,171  |  |      |  | 384   |      |  |  | 453   |  |  |  | 64,017  |  |  |  | 75,504  | 
|                     
|Canadian Plains Total |  |             | 1,274 |  |                    |  | 1,181 |                  |  |  | 126,920          |  |  |      | 130,228 |  |      |  | 2,036 |      |  |  | 1,962 |  |  |  | 339,253 |  |  |  | 327,061 | 
|                     



|                      |  |                     |        |  |                     |       |        |                 |  |  |       |  |  |       |       |  |     |  |        |  |  |  |        | 
|--------------------- |  | ------------------- | ------ |  | ------------------- | ----- | ------ | --------------- |  |  | ----- |  |  | ----- | ----- |  | --- |  | ------ |  |  |  | ------ | 
|                      |  |                     |        |  |                     | Total |       
|Producing Wells       |  | Producing Gas Wells |        |  | Producing Oil Wells |       |        | Producing Wells | 
|(number of wells)     |  | Gross               |        |  | Net                 |       |        | Gross           |  |  | Net   |  |  | Gross |       |  | Net | 
|                      | 
|Suffield              |  |                     | 7,603  |  |                     |       | 7,510  |                 |  |  | 641   |  |  |       | 639   |  |     |  | 8,244  |  |  |  | 8,149  | 
|Brooks                |  |                     | 9,622  |  |                     |       | 9,006  |                 |  |  | 699   |  |  |       | 573   |  |     |  | 10,321 |  |  |  | 9,579  | 
|Chinook               |  |                     | 3,134  |  |                     |       | 3,041  |                 |  |  | 139   |  |  |       | 133   |  |     |  | 3,273  |  |  |  | 3,174  | 
|Foster Creek          |  |                     |       |  |                     |       |       |                 |  |  | 36    |  |  |       | 36    |  |     |  | 36     |  |  |  | 36     | 
|Christina Lake        |  |                     |       |  |                     |       |       |                 |  |  | 3     |  |  |       | 3     |  |     |  | 3      |  |  |  | 3      | 
|Weyburn               |  |                     |       |  |                     |       |       |                 |  |  | 685   |  |  |       | 422   |  |     |  | 685    |  |  |  | 422    | 
|Other                 |  |                     | 1,888  |  |                     |       | 1,499  |                 |  |  | 1,322 |  |  |       | 937   |  |     |  | 3,210  |  |  |  | 2,436  | 
|                     
|Canadian Plains Total |  |                     | 22,247 |  |                     |       | 21,056 |                 |  |  | 3,525 |  |  |       | 2,743 |  |     |  | 25,772 |  |  |  | 23,799 | 
|                     



Suffield




Brooks




Chinook




10



---



##### 



Foster Creek








Christina Lake




Thermal Recovery Research and Development








Weyburn


2 2


11



---



##### 



Canadian Foothills & Frontier Region








|                                    |  |           |       |  |             |  |       |               |  |  |                 |  |  |       |        |  |     |  |        |          |  |  |        |  |  |  |     |  
|----------------------------------- |  | --------- | ----- |  | ----------- |  | ----- | ------------- |  |  | --------------- |  |  | ----- | ------ |  | --- |  | ------ | -------- |  |  | ------ |  |  |  | --- | -
|                                    |  | Developed |       |  | Undeveloped |  |       |               |  | 
|Landholdings                        |  | Acreage   |       |  | Acreage     |  |       | Total Acreage |  |  | Average Working | 
|(thousands of acres)                |  | Gross     |       |  | Net         |  |       | Gross         |  |  | Net             |  |  | Gross |        |  | Net |  |        | Interest | 
|                                   
|Greater Sierra                      |  |           | 464   |  |             |  | 397   |               |  |  | 2,780           |  |  |       | 2,424  |  |     |  | 3,244  |          |  |  | 2,821  |  |  |  | 87  | %
|Cutbank Ridge                       |  |           | 73    |  |             |  | 61    |               |  |  | 815             |  |  |       | 735    |  |     |  | 888    |          |  |  | 796    |  |  |  | 90  | %
|Pelican Lake                        |  |           | 83    |  |             |  | 83    |               |  |  | 135             |  |  |       | 135    |  |     |  | 218    |          |  |  | 218    |  |  |  | 100 | %
|Sexsmith/ Hythe/Saddle Hills        |  |           | 288   |  |             |  | 194   |               |  |  | 242             |  |  |       | 178    |  |     |  | 530    |          |  |  | 372    |  |  |  | 70  | %
|Cold Lake Air Weapons Range         |  |           | 386   |  |             |  | 365   |               |  |  | 473             |  |  |       | 469    |  |     |  | 859    |          |  |  | 834    |  |  |  | 97  | %
|East Coast of Canada                |  |           |      |  |             |  |      |               |  |  | 5,861           |  |  |       | 3,558  |  |     |  | 5,861  |          |  |  | 3,558  |  |  |  | 61  | %
|Mackenzie Delta                     |  |           |      |  |             |  |      |               |  |  | 529             |  |  |       | 198    |  |     |  | 529    |          |  |  | 198    |  |  |  | 37  | %
|Other                               |  |           | 1,330 |  |             |  | 1,074 |               |  |  | 5,195           |  |  |       | 3,447  |  |     |  | 6,525  |          |  |  | 4,521  |  |  |  | 69  | %
|                                   
|Canadian Foothills & Frontier Total |  |           | 2,624 |  |             |  | 2,174 |               |  |  | 16,030          |  |  |       | 11,144 |  |     |  | 18,654 |          |  |  | 13,318 |  |  |  | 71  | %
|                                   



|                                    |  |             |     |  |                    |  |     |                  |  |  |                  |  |  |      |        |  |      |  |       |      |  |  |      |  |  |  |         |  |  |  |         | 
|----------------------------------- |  | ----------- | --- |  | ------------------ |  | --- | ---------------- |  |  | ---------------- |  |  | ---- | ------ |  | ---- |  | ----- | ---- |  |  | ---- |  |  |  | ------- |  |  |  | ------- | 
|                                    |  | Natural Gas |     |  | Crude Oil and NGLs |  |     | Total Production |  |  | Total Production | 
|Production                          |  | (MMcf/d)    |     |  | (bbls/d)           |  |     | (MMcfe/d)        |  |  | (BOE/d)          | 
|(annual average)                    |  | 2004        |     |  | 2003               |  |     | 2004             |  |  | 2003             |  |  | 2004 |        |  | 2003 |  |       | 2004 |  |  | 2003 | 
|                                   
|Greater Sierra                      |  |             | 230 |  |                    |  | 143 |                  |  |  | 632              |  |  |      | 607    |  |      |  | 234   |      |  |  | 147  |  |  |  | 38,965  |  |  |  | 24,440  | 
|Cutbank Ridge                       |  |             | 40  |  |                    |  | 3   |                  |  |  |                 |  |  |      |       |  |      |  | 40    |      |  |  | 3    |  |  |  | 6,667   |  |  |  | 500     | 
|Pelican Lake                        |  |             | 7   |  |                    |  | 9   |                  |  |  | 18,900           |  |  |      | 15,944 |  |      |  | 120   |      |  |  | 105  |  |  |  | 20,067  |  |  |  | 17,444  | 
|Sexsmith/ Hythe/Saddle Hills        |  |             | 110 |  |                    |  | 114 |                  |  |  | 2,785            |  |  |      | 2,990  |  |      |  | 127   |      |  |  | 132  |  |  |  | 21,118  |  |  |  | 21,990  | 
|Cold Lake Air Weapons Range         |  |             | 163 |  |                    |  | 174 |                  |  |  |                 |  |  |      |       |  |      |  | 163   |      |  |  | 174  |  |  |  | 27,167  |  |  |  | 29,000  | 
|Other                               |  |             | 286 |  |                    |  | 323 |                  |  |  | 5,149            |  |  |      | 6,665  |  |      |  | 317   |      |  |  | 362  |  |  |  | 52,815  |  |  |  | 60,499  | 
|                                   
|Canadian Foothills & Frontier Total |  |             | 836 |  |                    |  | 766 |                  |  |  | 27,466           |  |  |      | 26,206 |  |      |  | 1,001 |      |  |  | 923  |  |  |  | 166,799 |  |  |  | 153,873 | 
|                                   



|                                    |  |                     |       |  |                     |       |       |                 |  |  |     |  |  |       |     |  |     |  |       |  |  |  |       | 
|----------------------------------- |  | ------------------- | ----- |  | ------------------- | ----- | ----- | --------------- |  |  | --- |  |  | ----- | --- |  | --- |  | ----- |  |  |  | ----- | 
|                                    |  |                     |       |  |                     | Total |      
|Producing Wells                     |  | Producing Gas Wells |       |  | Producing Oil Wells |       |       | Producing Wells | 
|(number of wells)                   |  | Gross               |       |  | Net                 |       |       | Gross           |  |  | Net |  |  | Gross |     |  | Net | 
|                                   
|Greater Sierra                      |  |                     | 559   |  |                     |       | 516   |                 |  |  | 2   |  |  |       | 2   |  |     |  | 561   |  |  |  | 518   | 
|Cutbank Ridge                       |  |                     | 69    |  |                     |       | 63    |                 |  |  |    |  |  |       |    |  |     |  | 69    |  |  |  | 63    | 
|Pelican Lake                        |  |                     | 15    |  |                     |       | 15    |                 |  |  | 514 |  |  |       | 514 |  |     |  | 529   |  |  |  | 529   | 
|Sexsmith/ Hythe/Saddle Hills        |  |                     | 317   |  |                     |       | 253   |                 |  |  | 61  |  |  |       | 47  |  |     |  | 378   |  |  |  | 300   | 
|Cold Lake Air Weapons Range         |  |                     | 608   |  |                     |       | 583   |                 |  |  |    |  |  |       |    |  |     |  | 608   |  |  |  | 583   | 
|Other                               |  |                     | 1,731 |  |                     |       | 1,539 |                 |  |  | 235 |  |  |       | 130 |  |     |  | 1,966 |  |  |  | 1,669 | 
|                                   
|Canadian Foothills & Frontier Total |  |                     | 3,299 |  |                     |       | 2,969 |                 |  |  | 812 |  |  |       | 693 |  |     |  | 4,111 |  |  |  | 3,662 | 
|                                   

12



---



##### 





Greater Sierra




Cutbank Ridge




Pelican Lake




Sexsmith/ Hythe/Saddle Hills




Cold Lake Air Weapons Range




East Coast of Canada








13



---



##### 



Mackenzie Delta







United States








|                     |  |                   |     |  |                     |  |     |               |  |  |                 |  |  |       |       |  |     |  |       |          |  |  |       |  |  |  |    |  
|-------------------- |  | ----------------- | --- |  | ------------------- |  | --- | ------------- |  |  | --------------- |  |  | ----- | ----- |  | --- |  | ----- | -------- |  |  | ----- |  |  |  | -- | -
|Landholdings         |  | Developed Acreage |     |  | Undeveloped Acreage |  |     | Total Acreage |  |  | Average Working | 
|(thousands of acres) |  | Gross             |     |  | Net                 |  |     | Gross         |  |  | Net             |  |  | Gross |       |  | Net |  |       | Interest | 
|                    
|Jonah                |  |                   | 12  |  |                     |  | 10  |               |  |  | 48              |  |  |       | 47    |  |     |  | 60    |          |  |  | 57    |  |  |  | 95 | %
|Piceance             |  |                   | 241 |  |                     |  | 216 |               |  |  | 860             |  |  |       | 796   |  |     |  | 1,101 |          |  |  | 1,012 |  |  |  | 92 | %
|East Texas           |  |                   | 68  |  |                     |  | 40  |               |  |  | 167             |  |  |       | 142   |  |     |  | 235   |          |  |  | 182   |  |  |  | 77 | %
|Fort Worth           |  |                   | 36  |  |                     |  | 33  |               |  |  | 127             |  |  |       | 127   |  |     |  | 163   |          |  |  | 160   |  |  |  | 98 | %
|Gulf of Mexico       |  |                   |    |  |                     |  |    |               |  |  | 1,371           |  |  |       | 557   |  |     |  | 1,371 |          |  |  | 557   |  |  |  | 41 | %
|Alaska               |  |                   |    |  |                     |  |    |               |  |  | 1,337           |  |  |       | 531   |  |     |  | 1,337 |          |  |  | 531   |  |  |  | 40 | %
|Other                |  |                   | 351 |  |                     |  | 208 |               |  |  | 2,615           |  |  |       | 2,140 |  |     |  | 2,966 |          |  |  | 2,348 |  |  |  | 79 | %
|                    
|United States Total  |  |                   | 708 |  |                     |  | 507 |               |  |  | 6,525           |  |  |       | 4,340 |  |     |  | 7,233 |          |  |  | 4,847 |  |  |  | 67 | %
|                    



|                    |  |             |     |  |                    |  |     |                  |  |  |                  |  |  |      |       |  |      |  |     |      |  |  |      |  |  |  |         |  |  |  |         | 
|------------------- |  | ----------- | --- |  | ------------------ |  | --- | ---------------- |  |  | ---------------- |  |  | ---- | ----- |  | ---- |  | --- | ---- |  |  | ---- |  |  |  | ------- |  |  |  | ------- | 
|                    |  | Natural Gas |     |  | Crude Oil and NGLs |  |     | Total Production |  |  | Total Production | 
|Production          |  | (MMcf/d)    |     |  | (bbls/d)           |  |     | (MMcfe/d)        |  |  | (BOE/d)          | 
|(annual average)    |  | 2004        |     |  | 2003               |  |     | 2004             |  |  | 2003             |  |  | 2004 |       |  | 2003 |  |     | 2004 |  |  | 2003 | 
|                   
|Jonah               |  |             | 389 |  |                    |  | 374 |                  |  |  | 3,294            |  |  |      | 3,348 |  |      |  | 409 |      |  |  | 394  |  |  |  | 68,127  |  |  |  | 65,681  | 
|Piceance            |  |             | 261 |  |                    |  | 151 |                  |  |  | 3,074            |  |  |      | 2,473 |  |      |  | 279 |      |  |  | 166  |  |  |  | 46,574  |  |  |  | 27,640  | 
|East Texas          |  |             | 50  |  |                    |  |    |                  |  |  | 167              |  |  |      |      |  |      |  | 51  |      |  |  |     |  |  |  | 8,500   |  |  |  |        | 
|Fort Worth          |  |             | 27  |  |                    |  | 7   |                  |  |  | 233              |  |  |      | 136   |  |      |  | 28  |      |  |  | 8    |  |  |  | 4,733   |  |  |  | 1,303   | 
|Other               |  |             | 142 |  |                    |  | 56  |                  |  |  | 6,037            |  |  |      | 3,504 |  |      |  | 179 |      |  |  | 77   |  |  |  | 29,704  |  |  |  | 12,837  | 
|                   
|United States Total |  |             | 869 |  |                    |  | 588 |                  |  |  | 12,805           |  |  |      | 9,461 |  |      |  | 946 |      |  |  | 645  |  |  |  | 157,638 |  |  |  | 107,461 | 
|                   



|                    |  |                     |       |  |                     |       |       |                 |  |  |     |  |  |       |    |  |     |  |       |  |  |  |       | 
|------------------- |  | ------------------- | ----- |  | ------------------- | ----- | ----- | --------------- |  |  | --- |  |  | ----- | -- |  | --- |  | ----- |  |  |  | ----- | 
|                    |  |                     |       |  |                     | Total |      
|Producing Wells     |  | Producing Gas Wells |       |  | Producing Oil Wells |       |       | Producing Wells | 
|(number of wells)   |  | Gross               |       |  | Net                 |       |       | Gross           |  |  | Net |  |  | Gross |    |  | Net | 
|                   
|Jonah               |  |                     | 386   |  |                     |       | 343   |                 |  |  |    |  |  |       |   |  |     |  | 386   |  |  |  | 343   | 
|Piceance            |  |                     | 2,486 |  |                     |       | 2,065 |                 |  |  |    |  |  |       |   |  |     |  | 2,486 |  |  |  | 2,065 | 
|East Texas          |  |                     | 458   |  |                     |       | 263   |                 |  |  |    |  |  |       |   |  |     |  | 458   |  |  |  | 263   | 
|Fort Worth          |  |                     | 399   |  |                     |       | 366   |                 |  |  |    |  |  |       |   |  |     |  | 399   |  |  |  | 366   | 
|Other               |  |                     | 2,062 |  |                     |       | 1,224 |                 |  |  | 30  |  |  |       | 12 |  |     |  | 2,092 |  |  |  | 1,236 | 
|                   
|United States Total |  |                     | 5,791 |  |                     |       | 4,261 |                 |  |  | 30  |  |  |       | 12 |  |     |  | 5,821 |  |  |  | 4,273 | 
|                   

14



---



##### 





Jonah




Piceance




East Texas




Fort Worth




Gulf of Mexico






Alaska




Gathering & Processing Facilities




15



---



##### 










International New Ventures Exploration




Central and West Africa






Brazil






Middle East










16



---



##### 



Greenland







Ecuador










17



---



##### 






MIDSTREAM & MARKETING





Midstream




Natural Gas Storage






AECO
HUBTM


tm tm


Suffield
Gas Storage Facility


tm


Hythe
Gas Storage Facility




Countess
Gas Storage Facility




18



---



##### 



Wild Goose Gas Storage Facility




Salt Plains Gas Storage Facility




Starks Project




Leased Storage Capacity




Natural Gas Liquids










Power




19



---



##### 



Pipelines









Marketing




Natural Gas Marketing










Crude Oil Marketing








20



---



##### 







NGLs Marketing




21



---



##### 






RESERVES AND OTHER OIL AND GAS INFORMATION













Reserve Quantities Information








22



---



##### 



Net Proved Reserves (EnCana
Share After
Royalties) (1,2)


Constant Pricing


|                                     |  |                          |        |   |                                   |  |       |         |  |        |       |   |  |       |        |   |        |  |        |        |  |  |         |       |  |         |      |     |       |  |       |       |  |  |        |   |  |  |      |   |  |  |        |  
|------------------------------------ |  | ------------------------ | ------ | - | --------------------------------- |  | ----- | ------- |  | ------ | ----- | - |  | ----- | ------ | - | ------ |  | ------ | ------ |  |  | ------- | ----- |  | ------- | ---- | --- | ----- |  | ----- | ----- |  |  | ------ | - |  |  | ---- | - |  |  | ------ | -
|                                     |  | Natural Gas              |        |   | Crude Oil and Natural Gas Liquids | 
|                                     |  | (billions of cubic feet) |        |   | (millions of barrels)             | 
|                                     | 
|                                     |  | United                   |        |   | United                            |  |       |         |  | United |       |   |  |       | United |   |        | 
|                                     |  | Canada                   |        |   | States                            |  |       | Kingdom |  |        | Other |   |  | Total |        |   | Canada |  |        | States |  |  | Ecuador |       |  | Kingdom |      |     | Other |  |       | Total | 
|                                     | 
|2002                                 |  |                          |        |   |                                   |  |       |         |  |        |       |   |  |       |        |   |        |  |        |        |  |  |         |       |  |         |      |     |       |  |       |       |  |  |        |   |  |  |      |   |  |  |        |  
|Beginning of year                    |  |                          | 3,504  |   |                                   |  | 236   |         |  |        | 7     |   |  |       |       |   |        |  | 3,747  |        |  |  | 286.6   |       |  |         | 19.6 |     |       |  |      |       |  |  | 21.6   |   |  |  |     |   |  |  | 327.8  |  
|Purchase of AEC reserves in place    |  |                          | 2,686  |   |                                   |  | 944   |         |  |        |      |   |  |       |       |   |        |  | 3,630  |        |  |  | 233.7   |       |  |         | 6.5  |     |       |  | 168.4 |       |  |  |       |   |  |  |     |   |  |  | 408.6  |  
|Revisions and improved recovery      |  |                          | (1,140 | ) |                                   |  | 731   |         |  |        | 7     |   |  |       |       |   |        |  | (402   | )      |  |  | (15.5   | )     |  |         | 4.6  |     |       |  | (33.5 | )     |  |  | (9.1   | ) |  |  |     |   |  |  | (53.5  | )
|Extensions and discoveries           |  |                          | 726    |   |                                   |  | 319   |         |  |        | 10    |   |  |       |       |   |        |  | 1,055  |        |  |  | 96.9    |       |  |         | 3.3  |     |       |  | 31.1  |       |  |  | 89.2   |   |  |  |     |   |  |  | 220.5  |  
|Purchase of reserves in place        |  |                          | 30     |   |                                   |  | 530   |         |  |        |      |   |  |       |       |   |        |  | 560    |        |  |  | 4.9     |       |  |         | 9.9  |     |       |  |      |       |  |  |       |   |  |  |     |   |  |  | 14.8   |  
|Sale of reserves in place            |  |                          | (129   | ) |                                   |  | (73   | )       |  |        |      |   |  |       |       |   |        |  | (202   | )      |  |  | (18.2   | )     |  |         | (0.7 | )   |       |  |      |       |  |  |       |   |  |  |     |   |  |  | (18.9  | )
|Production                           |  |                          | (604   | ) |                                   |  | (114  | )       |  |        | (4    | ) |  |       |       |   |        |  | (722   | )      |  |  | (46.5   | )     |  |         | (2.3 | )   |       |  | (10.2 | )     |  |  | (4.1   | ) |  |  |     |   |  |  | (63.1  | )
|                                    
|End of year                          |  |                          | 5,073  |   |                                   |  | 2,573 |         |  |        | 20    |   |  |       |       |   |        |  | 7,666  |        |  |  | 541.9   |       |  |         | 40.9 |     |       |  | 155.8 |       |  |  | 97.6   |   |  |  |     |   |  |  | 836.2  |  
|                                    
|Developed                            |  |                          | 4,139  |   |                                   |  | 1,446 |         |  |        | 9     |   |  |       |       |   |        |  | 5,594  |        |  |  | 299.2   |       |  |         | 21.9 |     |       |  | 104.6 |       |  |  | 8.3    |   |  |  |     |   |  |  | 434.0  |  
|Undeveloped                          |  |                          | 934    |   |                                   |  | 1,127 |         |  |        | 11    |   |  |       |       |   |        |  | 2,072  |        |  |  | 242.7   |       |  |         | 19.0 |     |       |  | 51.2  |       |  |  | 89.3   |   |  |  |     |   |  |  | 402.2  |  
|                                    
|Total                                |  |                          | 5,073  |   |                                   |  | 2,573 |         |  |        | 20    |   |  |       |       |   |        |  | 7,666  |        |  |  | 541.9   |       |  |         | 40.9 |     |       |  | 155.8 |       |  |  | 97.6   |   |  |  |     |   |  |  | 836.2  |  
|                                    
|2003                                 |  |                          |        |   |                                   |  |       |         |  |        |       |   |  |       |        |   |        |  |        |        |  |  |         |       |  |         |      |     |       |  |       |       |  |  |        |   |  |  |      |   |  |  |        |  
|Beginning of year                    |  |                          | 5,073  |   |                                   |  | 2,573 |         |  |        | 20    |   |  |       |       |   |        |  | 7,666  |        |  |  | 541.9   |       |  |         | 40.9 |     |       |  | 155.8 |       |  |  | 97.6   |   |  |  |     |   |  |  | 836.2  |  
|Revisions and improved recovery      |  |                          | 73     |   |                                   |  | 1     |         |  |        | 3     |   |  |       |       |   |        |  | 77     |        |  |  | 32.3    |       |  |         | 0.5  |     |       |  | 0.4   |       |  |  | 23.5   |   |  |  |     |   |  |  | 56.7   |  
|Extensions and discoveries           |  |                          | 867    |   |                                   |  | 706   |         |  |        |      |   |  |       | 90     |   |        |  | 1,663  |        |  |  | 110.9   |       |  |         | 7.4  |     |       |  | 11.9  |       |  |  |       |   |  |  | 0.9  |   |  |  | 131.1  |  
|Purchase of reserves in place        |  |                          | 9      |   |                                   |  | 152   |         |  |        | 8     |   |  |       |       |   |        |  | 169    |        |  |  | 1.3     |       |  |         | 0.9  |     |       |  | 17.3  |       |  |  | 7.1    |   |  |  |     |   |  |  | 26.6   |  
|Sale of reserves in place            |  |                          | (60    | ) |                                   |  | (88   | )       |  |        |      |   |  |       | (90    | ) |        |  | (238   | )      |  |  | (0.2    | )     |  |         | (4.7 | )   |       |  | (5.1  | )     |  |  |       |   |  |  | (0.9 | ) |  |  | (10.9  | )
|Production                           |  |                          | (706   | ) |                                   |  | (215  | )       |  |        | (5    | ) |  |       |       |   |        |  | (926   | )      |  |  | (56.8   | )     |  |         | (3.4 | )   |       |  | (18.6 | )     |  |  | (3.7   | ) |  |  |     |   |  |  | (82.5  | )
|                                    
|End of year                          |  |                          | 5,256  |   |                                   |  | 3,129 |         |  |        | 26    |   |  |       |       |   |        |  | 8,411  |        |  |  | 629.4   |       |  |         | 41.6 |     |       |  | 161.7 |       |  |  | 124.5  |   |  |  |     |   |  |  | 957.2  |  
|                                    
|Developed                            |  |                          | 3,984  |   |                                   |  | 1,833 |         |  |        | 13    |   |  |       |       |   |        |  | 5,830  |        |  |  | 306.1   |       |  |         | 26.3 |     |       |  | 115.0 |       |  |  | 16.7   |   |  |  |     |   |  |  | 464.1  |  
|Undeveloped                          |  |                          | 1,272  |   |                                   |  | 1,296 |         |  |        | 13    |   |  |       |       |   |        |  | 2,581  |        |  |  | 323.3   |       |  |         | 15.3 |     |       |  | 46.7  |       |  |  | 107.8  |   |  |  |     |   |  |  | 493.1  |  
|                                    
|Total                                |  |                          | 5,256  |   |                                   |  | 3,129 |         |  |        | 26    |   |  |       |       |   |        |  | 8,411  |        |  |  | 629.4   |       |  |         | 41.6 |     |       |  | 161.7 |       |  |  | 124.5  |   |  |  |     |   |  |  | 957.2  |  
|                                    
|2004                                 |  |                          |        |   |                                   |  |       |         |  |        |       |   |  |       |        |   |        |  |        |        |  |  |         |       |  |         |      |     |       |  |       |       |  |  |        |   |  |  |      |   |  |  |        |  
|Beginning of year                    |  |                          | 5,256  |   |                                   |  | 3,129 |         |  |        | 26    |   |  |       |       |   |        |  | 8,411  |        |  |  | 629.4   |       |  |         | 41.6 |     |       |  | 161.7 |       |  |  | 124.5  |   |  |  |     |   |  |  | 957.2  |  
|Revisions and improved recovery      |  |                          | 67     |   |                                   |  | (252  | )       |  |        |      |   |  |       |       |   |        |  | (185   | )      |  |  | 31.1    | (3)   |  |         | 0.2  |     |       |  | (11.5 | )     |  |  |       |   |  |  |     |   |  |  | 19.8   |  
|Extensions and discoveries           |  |                          | 1,422  |   |                                   |  | 1,009 |         |  |        |      |   |  |       |       |   |        |  | 2,431  |        |  |  | 93.6    | (3)   |  |         | 47.6 |     |       |  | 21.2  |       |  |  |       |   |  |  |     |   |  |  | 162.4  |  
|Purchase of reserves in place        |  |                          | 65     |   |                                   |  | 1,150 |         |  |        | 10    |   |  |       |       |   |        |  | 1,225  |        |  |  | 29.4    |       |  |         | 11.7 |     |       |  |      |       |  |  | 10.1   |   |  |  |     |   |  |  | 51.2   |  
|Sale of reserves in place            |  |                          | (215   | ) |                                   |  | (82   | )       |  |        | (25   | ) |  |       |       |   |        |  | (322   | )      |  |  | (97.3   | )     |  |         | (5.4 | )   |       |  |      |       |  |  | (128.4 | ) |  |  |     |   |  |  | (231.1 | )
|Production                           |  |                          | (771   | ) |                                   |  | (318  | )       |  |        | (11   | ) |  |       |       |   |        |  | (1,100 | )      |  |  | (56.6   | )     |  |         | (4.7 | )   |       |  | (28.1 | )     |  |  | (6.2   | ) |  |  |     |   |  |  | (95.6  | )
|                                    
|End of year before bitumen revisions |  |                          | 5,824  |   |                                   |  | 4,636 |         |  |        |      |   |  |       |       |   |        |  | 10,460 |        |  |  | 629.6   |       |  |         | 91.0 |     |       |  | 143.3 |       |  |  |       |   |  |  |     |   |  |  | 863.9  |  
|                                    
|Revisions due to bitumen price       |  |                          |       |   |                                   |  |      |         |  |        |      |   |  |       |       |   |        |  |       |        |  |  | (362.7  | ) (4) |  |         |     |     |       |  |      |       |  |  |       |   |  |  |     |   |  |  | (362.7 | )
|                                    
|End of year                          |  |                          | 5,824  |   |                                   |  | 4,636 | (5)     |  |        |      |   |  |       |       |   |        |  | 10,460 |        |  |  | 266.9   |       |  |         | 91.0 | (5) |       |  | 143.3 | (6)   |  |  |       |   |  |  |     |   |  |  | 501.2  |  
|                                    
|Developed                            |  |                          | 4,406  |   |                                   |  | 2,496 |         |  |        |      |   |  |       |       |   |        |  | 6,902  |        |  |  | 210.2   |       |  |         | 31.5 |     |       |  | 122.5 |       |  |  |       |   |  |  |     |   |  |  | 364.2  |  
|Undeveloped                          |  |                          | 1,418  |   |                                   |  | 2,140 |         |  |        |      |   |  |       |       |   |        |  | 3,558  |        |  |  | 56.7    |       |  |         | 59.5 |     |       |  | 20.8  |       |  |  |       |   |  |  |     |   |  |  | 137.0  |  
|                                    
|Total                                |  |                          | 5,824  |   |                                   |  | 4,636 |         |  |        |      |   |  |       |       |   |        |  | 10,460 |        |  |  | 266.9   |       |  |         | 91.0 |     |       |  | 143.3 |       |  |  |       |   |  |  |     |   |  |  | 501.2  |  
|                                    





|    |             
|--- | ------------
|(1) | Definitions:



| |    |                                                                                                                                                                                                                                                                                                                                                        
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | a. | Net reserves are the remaining reserves of EnCana,
    after deduction of estimated royalties and including royalty
    interests.                                                                                                                                                                                                                   
|
| | b. | Proved reserves are the estimated quantities of
    crude oil, natural gas and NGLs 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 costs as of the date
    the estimate is made.
|
| | c. | Proved Developed reserves are reserves that can be
    expected to be recovered through existing wells with existing
    equipment and operating methods.                                                                                                                                                                                            
|
| | d. | Proved Undeveloped reserves are reserves that are
    expected to be recovered from new wells on undrilled acreage, or
    from existing wells where a relatively major expenditure is
    required for recompletion.                                                                                                                                



|    |                                                                                                                                                                                                                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | EnCana does not file any estimates of total net proved crude oil
    or natural gas reserves with any U.S. federal authority or
    agency other than the SEC.                                                                                                                                                                     
|   
|(3) | An aggregate of approximately of 75.8 million barrels of
    proved reserves in the Foster Creek area are subject to the
    revisions due to bitumen price, including approximately
    5.4 million barrels under revisions and improved recovery
    and approximately 70.4 million barrels under extensions and
    discoveries.
|   
|(4) | Removal of the Corporations Foster Creek proved bitumen
    reserves as described under Reserve Quantities
    Information.                                                                                                                                                                                                     
|   
|(5) | Includes approximately 14 billion cubic feet of natural gas
    and approximately 38.8 million barrels of crude oil and
    NGLs reserves attributable to the Corporations Gulf of
    Mexico assets, which EnCana plans to dispose of in 2005.                                                                                   
|   
|(6) | The Corporation plans to dispose of its Ecuadorian operations in
    2005. Accordingly, Ecuador is treated as a discontinued
    operation for financial reporting purposes.                                                                                                                                                       

23



---



##### 






Other Disclosures About Oil and Gas Activities




Standardized Measure of Discounted Future Net Cash Flows
and Changes Therein






Standardized Measure of Discounted Future Net Cash Flows


Relating to Proved Oil and Gas Reserves


|                                                 |  |              |        |  |               |  |        |         |  |  |        |  |  |      |        |  |      |  |        |      |  |  |       |  |  |      |       |  |  |  |       |  |  |  |       | 
|------------------------------------------------ |  | ------------ | ------ |  | ------------- |  | ------ | ------- |  |  | ------ |  |  | ---- | ------ |  | ---- |  | ------ | ---- |  |  | ----- |  |  | ---- | ----- |  |  |  | ----- |  |  |  | ----- | 
|                                                 |  | Canada       |        |  | United States |  |        | Ecuador | 
|                                                 |  |              |        |  |               |  |        |         | 
|                                                 |  | 2004         |        |  | 2003          |  |        | 2002    |  |  | 2004   |  |  | 2003 |        |  | 2002 |  |        | 2004 |  |  | 2003  |  |  | 2002 |      
|                                                 | 
|                                                 |  | ($ millions)
|Future cash inflows                              |  |              | 37,791 |  |               |  | 35,126 |         |  |  | 29,890 |  |  |      | 27,063 |  |      |  | 17,472 |      |  |  | 9,398 |  |  |      | 3,317 |  |  |  | 3,533 |  |  |  | 3,368 | 
|Future production costs                          |  |              | 7,760  |  |               |  | 9,630  |         |  |  | 5,873  |  |  |      | 2,462  |  |      |  | 1,456  |      |  |  | 2,090 |  |  |      | 1,136 |  |  |  | 738   |  |  |  | 635   | 
|Future development costs                         |  |              | 4,906  |  |               |  | 4,388  |         |  |  | 2,813  |  |  |      | 3,406  |  |      |  | 1,433  |      |  |  | 1,270 |  |  |      | 220   |  |  |  | 249   |  |  |  | 273   | 
|                                                
|Undiscounted pre-tax cash flows                  |  |              | 25,125 |  |               |  | 21,108 |         |  |  | 21,204 |  |  |      | 21,195 |  |      |  | 14,583 |      |  |  | 6,038 |  |  |      | 1,961 |  |  |  | 2,546 |  |  |  | 2,460 | 
|Future income taxes                              |  |              | 6,279  |  |               |  | 5,874  |         |  |  | 6,353  |  |  |      | 7,021  |  |      |  | 4,960  |      |  |  | 1,504 |  |  |      | 342   |  |  |  | 536   |  |  |  | 585   | 
|                                                
|Future net cash flows                            |  |              | 18,846 |  |               |  | 15,234 |         |  |  | 14,851 |  |  |      | 14,174 |  |      |  | 9,623  |      |  |  | 4,534 |  |  |      | 1,619 |  |  |  | 2,010 |  |  |  | 1,875 | 
|Less discount of net cash flows using a 10% rate |  |              | 6,668  |  |               |  | 5,219  |         |  |  | 6,018  |  |  |      | 6,686  |  |      |  | 4,735  |      |  |  | 2,383 |  |  |      | 417   |  |  |  | 643   |  |  |  | 617   | 
|                                                
|Discounted future net cash flows                 |  |              | 12,178 |  |               |  | 10,015 |         |  |  | 8,833  |  |  |      | 7,488  |  |      |  | 4,888  |      |  |  | 2,151 |  |  |      | 1,202 |  |  |  | 1,367 |  |  |  | 1,258 | 
|                                                

|                                                 |  |                |   |  |       |  |       |      |  |  |       |  |  |      |        |  |      |  |        |  |  |  |        | 
|------------------------------------------------ |  | -------------- | - |  | ----- |  | ----- | ---- |  |  | ----- |  |  | ---- | ------ |  | ---- |  | ------ |  |  |  | ------ | 
|                                                 |  | United Kingdom |   |  | Total | 
|                                                 |  |                |   |  |       | 
|                                                 |  | 2004           |   |  | 2003  |  |       | 2002 |  |  | 2004  |  |  | 2003 |        |  | 2002 | 
|                                                 | 
|                                                 |  | ($ millions)  
|Future cash inflows                              |  |                |  |  |       |  | 3,483 |      |  |  | 2,565 |  |  |      | 68,171 |  |      |  | 59,614 |  |  |  | 45,221 | 
|Future production costs                          |  |                |  |  |       |  | 961   |      |  |  | 397   |  |  |      | 11,358 |  |      |  | 12,785 |  |  |  | 8,995  | 
|Future development costs                         |  |                |  |  |       |  | 1,008 |      |  |  | 836   |  |  |      | 8,532  |  |      |  | 7,078  |  |  |  | 5,192  | 
|                                                
|Undiscounted pre-tax cash flows                  |  |                |  |  |       |  | 1,514 |      |  |  | 1,332 |  |  |      | 48,281 |  |      |  | 39,751 |  |  |  | 31,034 | 
|Future income taxes                              |  |                |  |  |       |  | 456   |      |  |  | 483   |  |  |      | 13,642 |  |      |  | 11,826 |  |  |  | 8,925  | 
|                                                
|Future net cash flows                            |  |                |  |  |       |  | 1,058 |      |  |  | 849   |  |  |      | 34,639 |  |      |  | 27,925 |  |  |  | 22,109 | 
|Less discount of net cash flows using a 10% rate |  |                |  |  |       |  | 493   |      |  |  | 438   |  |  |      | 13,771 |  |      |  | 11,090 |  |  |  | 9,456  | 
|                                                
|Discounted future net cash flows                 |  |                |  |  |       |  | 565   |      |  |  | 411   |  |  |      | 20,868 |  |      |  | 16,835 |  |  |  | 12,653 | 
|                                                

24



---



##### 



Changes in Standardized Measure of Discounted Future Net Cash
Flows


Relating to Proved Oil and Gas Reserves


|                           |                                                                                               |              |        |        |               |  |        |         |   |  |        |        |   |      |        |        |      |  |        |       |   |  |       |       |   |      |       |      |   |  |       |      |   |  |       |       |  
|-------------------------- | --------------------------------------------------------------------------------------------- | ------------ | ------ | ------ | ------------- |  | ------ | ------- | - |  | ------ | ------ | - | ---- | ------ | ------ | ---- |  | ------ | ----- | - |  | ----- | ----- | - | ---- | ----- | ---- | - |  | ----- | ---- | - |  | ----- | ----- | -
|                           |                                                                                               | Canada       |        |        | United States |  |        | Ecuador |  
|                           |                                                                                               |              |        |        |               |  |        |         |  
|                           |                                                                                               | 2004         |        |        | 2003          |  |        | 2002    |   |  | 2004   |        |   | 2003 |        |        | 2002 |  |        | 2004  |   |  | 2003  |       |   | 2002 |      
|                           |                                                                                              
|                           |                                                                                               | ($ millions)
|Balance, beginning of year |                                                                                               |              | 10,015 |        |               |  | 8,833  |         |   |  | 3,060  |        |   |      | 4,888  |        |      |  | 2,151  |       |   |  | 300   |       |   |      | 1,367 |      |   |  | 1,258 |      |   |  |      |      
|Changes resulting from:    |                                                                                               |              |        |        |               |  |        |         |   |  |        |        |   |      |        |        |      |  |        |       |   |  |       |       |   |      |       |      |   |  |       |      |   |  |       |      
|                           | Sales of oil and gas produced during the period                                               |              |        | (3,965 | )             |  |        | (3,429  | ) |  |        | (2,092 | ) |      |        | (1,474 | )    |  |        | (889  | ) |  |       | (329  | ) |      |       | (264 | ) |  |       | (258 | ) |  |       | (157  | )
|                           | Discoveries and extensions, net of related costs                                              |              |        | 3,562  |               |  |        | 1,272   |   |  |        | 1,293  |   |      |        | 2,436  |      |  |        | 1,381 |   |  |       | 293   |   |      |       | 236  |   |  |       | 126  |   |  |       | 330   |  
|                           | Purchases of proved AEC reserves in place                                                     |              |        |       |               |  |        |        |   |  |        | 6,810  |   |      |        |       |      |  |        |      |   |  |       | 1,044 |   |      |       |     |   |  |       |     |   |  |       | 1,830 |  
|                           | Purchases of proved reserves in place                                                         |              |        | 531    |               |  |        | 26      |   |  |        | 93     |   |      |        | 2,786  |      |  |        | 340   |   |  |       | 613   |   |      |       |     |   |  |       | 93   |   |  |       |      |  
|                           | Sales of proved reserves in place                                                             |              |        | (1,579 | )             |  |        | (95     | ) |  |        | (371   | ) |      |        | (271   | )    |  |        | (108  | ) |  |       | (72   | ) |      |       |     |   |  |       | (54  | ) |  |       |      |  
|                           | Net change in prices and production costs                                                     |              |        | 2,264  |               |  |        | 242     |   |  |        | 3,358  |   |      |        | 143    |      |  |        | 2,751 |   |  |       | 194   |   |      |       | (294 | ) |  |       | (47  | ) |  |       |      |  
|                           | Revisions to quantity estimates                                                               |              |        | 546    |               |  |        | 416     |   |  |        | (1,345 | ) |      |        | (542   | )    |  |        | 4     |   |  |       | 667   |   |      |       | (125 | ) |  |       | 4    |   |  |       | (354  | )
|                           | Accretion of discount                                                                         |              |        | 1,349  |               |  |        | 1,636   |   |  |        | 455    |   |      |        | 725    |      |  |        | 304   |   |  |       | 56    |   |      |       | 176  |   |  |       | 182  |   |  |       |      |  
|                           | Previously estimated development costs incurred net of change in
    future development costs |              |        | 57     |               |  |        | 340     |   |  |        | 101    |   |      |        | 22     |      |  |        | 534   |   |  |       | 54    |   |      |       | 15   |   |  |       | 89   |   |  |       |      |  
|                           | Other                                                                                         |              |        | 32     |               |  |        | 470     |   |  |        | (67    | ) |      |        | (49    | )    |  |        | 157   |   |  |       | (51   | ) |      |       | (29  | ) |  |       | (27  | ) |  |       |      |  
|Net change in income taxes |                                                                                               |              | (634   | )      |               |  | 304    |         |   |  | (2,462 | )      |   |      | (1,176 | )      |      |  | (1,737 | )     |   |  | (618  | )     |   |      | 120   |      |   |  | 1     |      |   |  | (391  | )    
|                          
|Balance, end of year       |                                                                                               |              | 12,178 |        |               |  | 10,015 |         |   |  | 8,833  |        |   |      | 7,488  |        |      |  | 4,888  |       |   |  | 2,151 |       |   |      | 1,202 |      |   |  | 1,367 |      |   |  | 1,258 |      
|                          

|                           |                                                                                               |                |     |      |       |  |     |      |   |  |      |     |   |      |        |        |      |  |        |        |   |  |        |        |  
|-------------------------- | --------------------------------------------------------------------------------------------- | -------------- | --- | ---- | ----- |  | --- | ---- | - |  | ---- | --- | - | ---- | ------ | ------ | ---- |  | ------ | ------ | - |  | ------ | ------ | -
|                           |                                                                                               | United Kingdom |     |      | Total | 
|                           |                                                                                               |                |     |      |       | 
|                           |                                                                                               | 2004           |     |      | 2003  |  |     | 2002 |   |  | 2004 |     |   | 2003 |        |        | 2002 | 
|                           |                                                                                              
|                           |                                                                                               | ($ millions)  
|Balance, beginning of year |                                                                                               |                | 565 |      |       |  | 411 |      |   |  | 140  |     |   |      | 16,835 |        |      |  | 12,653 |        |   |  | 3,500  |       
|Changes resulting from:    |                                                                                               |                |     |      |       |  |     |      |   |  |      |     |   |      |        |        |      |  |        |        |   |  |        |       
|                           | Sales of oil and gas produced during the period                                               |                |     | (78  | )     |  |     | (83  | ) |  |      | (81 | ) |      |        | (5,781 | )    |  |        | (4,659 | ) |  |        | (2,659 | )
|                           | Discoveries and extensions, net of related costs                                              |                |     |     |       |  |     |     |   |  |      | 594 |   |      |        | 6,234  |      |  |        | 2,779  |   |  |        | 2,510  |  
|                           | Purchases of proved AEC reserves in place                                                     |                |     |     |       |  |     |     |   |  |      |    |   |      |        |       |      |  |        |       |   |  |        | 9,684  |  
|                           | Purchases of proved reserves in place                                                         |                |     | 77   |       |  |     | 57   |   |  |      |    |   |      |        | 3,394  |      |  |        | 516    |   |  |        | 706    |  
|                           | Sales of proved reserves in place                                                             |                |     | (899 | )     |  |     |     |   |  |      |    |   |      |        | (2,749 | )    |  |        | (257   | ) |  |        | (443   | )
|                           | Net change in prices and production costs                                                     |                |     |     |       |  |     | (119 | ) |  |      | (1  | ) |      |        | 2,113  |      |  |        | 2,827  |   |  |        | 3,551  |  
|                           | Revisions to quantity estimates                                                               |                |     |     |       |  |     | 157  |   |  |      | (53 | ) |      |        | (121   | )    |  |        | 581    |   |  |        | (1,085 | )
|                           | Accretion of discount                                                                         |                |     | 82   |       |  |     | 91   |   |  |      | 14  |   |      |        | 2,332  |      |  |        | 2,213  |   |  |        | 525    |  
|                           | Previously estimated development costs incurred net of change in
    future development costs |                |     |     |       |  |     | 108  |   |  |      | 3   |   |      |        | 94     |      |  |        | 1,071  |   |  |        | 158    |  
|                           | Other                                                                                         |                |     |     |       |  |     | (38  | ) |  |      | (8  | ) |      |        | (46    | )    |  |        | 562    |   |  |        | (126   | )
|Net change in income taxes |                                                                                               |                | 253 |      |       |  | (19 | )    |   |  | (197 | )   |   |      | (1,437 | )      |      |  | (1,451 | )      |   |  | (3,668 | )     
|                          
|Balance, end of year       |                                                                                               |                |    |      |       |  | 565 |      |   |  | 411  |     |   |      | 20,868 |        |      |  | 16,835 |        |   |  | 12,653 |       
|                          

25



---



##### 



Results of Operations, Capitalized Costs and Costs
Incurred


Results of Operations


|                                                                                                 |  |              |       |  |               |  |       |         |  |  |       |  |  |      |       |  |      |  |       |      |  |  |      |  |  |      |     |   |  |  |     |  |  |  |     | 
|------------------------------------------------------------------------------------------------ |  | ------------ | ----- |  | ------------- |  | ----- | ------- |  |  | ----- |  |  | ---- | ----- |  | ---- |  | ----- | ---- |  |  | ---- |  |  | ---- | --- | - |  |  | --- |  |  |  | --- | 
|                                                                                                 |  | Canada       |       |  | United States |  |       | Ecuador | 
|                                                                                                 |  |              |       |  |               |  |       |         | 
|                                                                                                 |  | 2004         |       |  | 2003          |  |       | 2002    |  |  | 2004  |  |  | 2003 |       |  | 2002 |  |       | 2004 |  |  | 2003 |  |  | 2002 |    
|                                                                                                 | 
|                                                                                                 |  | ($ millions)
|Oil and gas revenues, net of royalties, transportation and
    selling costs                     |  |              | 4,787 |  |               |  | 4,189 |         |  |  | 2,630 |  |  |      | 1,861 |  |      |  | 1,091 |      |  |  | 406  |  |  |      | 451 |   |  |  | 367 |  |  |  | 224 | 
|Operating costs, production and mineral taxes, and accretion of
    asset retirement obligations |  |              | 822   |  |               |  | 760   |         |  |  | 538   |  |  |      | 387   |  |      |  | 202   |      |  |  | 77   |  |  |      | 187 |   |  |  | 109 |  |  |  | 67  | 
|Depreciation, depletion and amortization                                                         |  |              | 1,752 |  |               |  | 1,511 |         |  |  | 871   |  |  |      | 487   |  |      |  | 297   |      |  |  | 206  |  |  |      | 263 |   |  |  | 159 |  |  |  | 79  | 
|                                                                                                
|Operating income (loss)                                                                          |  |              | 2,213 |  |               |  | 1,918 |         |  |  | 1,221 |  |  |      | 987   |  |      |  | 592   |      |  |  | 123  |  |  |      | 1   |   |  |  | 99  |  |  |  | 78  | 
|Income taxes                                                                                     |  |              | 841   |  |               |  | 218   |         |  |  | 456   |  |  |      | 375   |  |      |  | 219   |      |  |  | 47   |  |  |      | 5   |   |  |  | 17  |  |  |  | 28  | 
|                                                                                                
|Results of operations                                                                            |  |              | 1,372 |  |               |  | 1,700 |         |  |  | 765   |  |  |      | 612   |  |      |  | 373   |      |  |  | 76   |  |  |      | (4  | ) |  |  | 82  |  |  |  | 50  | 
|                                                                                                

|                                                                                                 |  |                |     |   |       |  |     |       |  |  |      |  |  |      |     |   |      |  |      |      |  |  |      |   |  |      |       |  |  |  |       |  |  |  |       | 
|------------------------------------------------------------------------------------------------ |  | -------------- | --- | - | ----- |  | --- | ----- |  |  | ---- |  |  | ---- | --- | - | ---- |  | ---- | ---- |  |  | ---- | - |  | ---- | ----- |  |  |  | ----- |  |  |  | ----- | 
|                                                                                                 |  | United Kingdom |     |   | Other |  |     | Total | 
|                                                                                                 |  |                |     |   |       |  |     |       | 
|                                                                                                 |  | 2004           |     |   | 2003  |  |     | 2002  |  |  | 2004 |  |  | 2003 |     |   | 2002 |  |      | 2004 |  |  | 2003 |   |  | 2002 |      
|                                                                                                 | 
|                                                                                                 |  | ($ millions)  
|Oil and gas revenues, net of royalties, transportation and
    selling costs                     |  |                | 117 |   |       |  | 102 |       |  |  | 92   |  |  |      |    |   |      |  |     |      |  |  |     |   |  |      | 7,216 |  |  |  | 5,749 |  |  |  | 3,352 | 
|Operating costs, production and mineral taxes, and accretion of
    asset retirement obligations |  |                | 39  |   |       |  | 19  |       |  |  | 11   |  |  |      | 4   |   |      |  | 20   |      |  |  | 29   |   |  |      | 1,439 |  |  |  | 1,110 |  |  |  | 722   | 
|Depreciation, depletion and amortization                                                         |  |                | 118 |   |       |  | 74  |       |  |  | 39   |  |  |      | 25  |   |      |  | 83   |      |  |  | 35   |   |  |      | 2,645 |  |  |  | 2,124 |  |  |  | 1,230 | 
|                                                                                                
|Operating income (loss)                                                                          |  |                | (40 | ) |       |  | 9   |       |  |  | 42   |  |  |      | (29 | ) |      |  | (103 | )    |  |  | (64  | ) |  |      | 3,132 |  |  |  | 2,515 |  |  |  | 1,400 | 
|Income taxes                                                                                     |  |                | (15 | ) |       |  | 17  |       |  |  | 17   |  |  |      |    |   |      |  | (4   | )    |  |  |     |   |  |      | 1,206 |  |  |  | 467   |  |  |  | 548   | 
|                                                                                                
|Results of operations                                                                            |  |                | (25 | ) |       |  | (8  | )     |  |  | 25   |  |  |      | (29 | ) |      |  | (99  | )    |  |  | (64  | ) |  |      | 1,926 |  |  |  | 2,048 |  |  |  | 852   | 
|                                                                                                

Capitalized Costs


|                                |  |              |        |  |               |  |        |         |  |  |        |  |  |      |       |  |      |  |       |      |  |  |       |  |  |      |       |  |  |  |       |  |  |  |       | 
|------------------------------- |  | ------------ | ------ |  | ------------- |  | ------ | ------- |  |  | ------ |  |  | ---- | ----- |  | ---- |  | ----- | ---- |  |  | ----- |  |  | ---- | ----- |  |  |  | ----- |  |  |  | ----- | 
|                                |  | Canada       |        |  | United States |  |        | Ecuador | 
|                                |  |              |        |  |               |  |        |         | 
|                                |  | 2004         |        |  | 2003          |  |        | 2002    |  |  | 2004   |  |  | 2003 |       |  | 2002 |  |       | 2004 |  |  | 2003  |  |  | 2002 |      
|                                | 
|                                |  | ($ millions)
|Proved oil and gas properties   |  |              | 22,455 |  |               |  | 18,549 |         |  |  | 12,504 |  |  |      | 7,552 |  |      |  | 3,485 |      |  |  | 2,769 |  |  |      | 1,784 |  |  |  | 1,372 |  |  |  | 1,000 | 
|Unproved oil and gas properties |  |              | 1,855  |  |               |  | 1,981  |         |  |  | 1,573  |  |  |      | 728   |  |      |  | 501   |      |  |  | 415   |  |  |      | 45    |  |  |  | 70    |  |  |  | 60    | 
|                               
|Total capital cost              |  |              | 24,310 |  |               |  | 20,530 |         |  |  | 14,077 |  |  |      | 8,280 |  |      |  | 3,986 |      |  |  | 3,184 |  |  |      | 1,829 |  |  |  | 1,442 |  |  |  | 1,060 | 
|Accumulated DD&A                |  |              | 9,770  |  |               |  | 7,498  |         |  |  | 4,770  |  |  |      | 1,046 |  |      |  | 516   |      |  |  | 262   |  |  |      | 534   |  |  |  | 188   |  |  |  | 73    | 
|                               
|Net capitalized costs           |  |              | 14,540 |  |               |  | 13,032 |         |  |  | 9,307  |  |  |      | 7,234 |  |      |  | 3,470 |      |  |  | 2,922 |  |  |      | 1,295 |  |  |  | 1,254 |  |  |  | 987   | 
|                               

|                                |  |                |   |  |       |  |     |       |  |  |      |  |  |      |     |  |      |  |     |      |  |  |      |  |  |      |        |  |  |  |        |  |  |  |        | 
|------------------------------- |  | -------------- | - |  | ----- |  | --- | ----- |  |  | ---- |  |  | ---- | --- |  | ---- |  | --- | ---- |  |  | ---- |  |  | ---- | ------ |  |  |  | ------ |  |  |  | ------ | 
|                                |  | United Kingdom |   |  | Other |  |     | Total | 
|                                |  |                |   |  |       |  |     |       | 
|                                |  | 2004           |   |  | 2003  |  |     | 2002  |  |  | 2004 |  |  | 2003 |     |  | 2002 |  |     | 2004 |  |  | 2003 |  |  | 2002 |       
|                                | 
|                                |  | ($ millions)  
|Proved oil and gas properties   |  |                |  |  |       |  | 675 |       |  |  | 445  |  |  |      |    |  |      |  |    |      |  |  |     |  |  |      | 31,791 |  |  |  | 24,081 |  |  |  | 16,718 | 
|Unproved oil and gas properties |  |                |  |  |       |  | 77  |       |  |  | 3    |  |  |      | 425 |  |      |  | 317 |      |  |  | 226  |  |  |      | 3,053  |  |  |  | 2,946  |  |  |  | 2,277  | 
|                               
|Total capital cost              |  |                |  |  |       |  | 752 |       |  |  | 448  |  |  |      | 425 |  |      |  | 317 |      |  |  | 226  |  |  |      | 34,844 |  |  |  | 27,027 |  |  |  | 18,995 | 
|Accumulated DD&A                |  |                |  |  |       |  | 230 |       |  |  | 136  |  |  |      | 247 |  |      |  | 206 |      |  |  | 98   |  |  |      | 11,597 |  |  |  | 8,638  |  |  |  | 5,339  | 
|                               
|Net capitalized costs           |  |                |  |  |       |  | 522 |       |  |  | 312  |  |  |      | 178 |  |      |  | 111 |      |  |  | 128  |  |  |      | 23,247 |  |  |  | 18,389 |  |  |  | 13,656 | 
|                               

26



---



##### 



Costs Incurred


|                          |  |              |       |  |               |  |       |         |  |  |       |  |  |      |       |  |      |  |     |      |  |  |       |  |  |      |     |  |  |  |     |  |  |  |       | 
|------------------------- |  | ------------ | ----- |  | ------------- |  | ----- | ------- |  |  | ----- |  |  | ---- | ----- |  | ---- |  | --- | ---- |  |  | ----- |  |  | ---- | --- |  |  |  | --- |  |  |  | ----- | 
|                          |  | Canada       |       |  | United States |  |       | Ecuador | 
|                          |  |              |       |  |               |  |       |         | 
|                          |  | 2004         |       |  | 2003          |  |       | 2002    |  |  | 2004  |  |  | 2003 |       |  | 2002 |  |     | 2004 |  |  | 2003  |  |  | 2002 |    
|                          | 
|                          |  | ($ millions)
|Acquisitions              |  |              |       |  |               |  |       |         |  |  |       |  |  |      |       |  |      |  |     |      |  |  |       |  |  |      |     |  |  |  |     |  |  |  |       | 
| AEC unproved reserves   |  |              |      |  |               |  |      |         |  |  | 1,496 |  |  |      |      |  |      |  |    |      |  |  | 444   |  |  |      |    |  |  |  |    |  |  |  | 221   | 
| other unproved reserves |  |              | 42    |  |               |  | 47    |         |  |  | 12    |  |  |      | 954   |  |      |  | 21  |      |  |  | 202   |  |  |      |    |  |  |  | 80  |  |  |  |      | 
| AEC proved reserves     |  |              |      |  |               |  |      |         |  |  | 3,540 |  |  |      |      |  |      |  |    |      |  |  | 1,024 |  |  |      |    |  |  |  |    |  |  |  | 686   | 
| other proved reserves   |  |              | 204   |  |               |  | 207   |         |  |  | 78    |  |  |      | 2,051 |  |      |  | 115 |      |  |  | 457   |  |  |      |    |  |  |  | 59  |  |  |  |      | 
|                         
|Total acquisitions        |  |              | 246   |  |               |  | 254   |         |  |  | 5,126 |  |  |      | 3,005 |  |      |  | 136 |      |  |  | 2,127 |  |  |      |    |  |  |  | 139 |  |  |  | 907   | 
|Exploration               |  |              | 555   |  |               |  | 846   |         |  |  | 403   |  |  |      | 164   |  |      |  | 187 |      |  |  | 226   |  |  |      | 28  |  |  |  | 20  |  |  |  | 35    | 
|Development               |  |              | 2,669 |  |               |  | 2,131 |         |  |  | 902   |  |  |      | 1,103 |  |      |  | 651 |      |  |  | 282   |  |  |      | 213 |  |  |  | 111 |  |  |  | 133   | 
|                         
|Total costs incurred      |  |              | 3,470 |  |               |  | 3,231 |         |  |  | 6,431 |  |  |      | 4,272 |  |      |  | 974 |      |  |  | 2,635 |  |  |      | 241 |  |  |  | 270 |  |  |  | 1,075 | 
|                         

|                          |  |                |     |  |       |  |     |       |  |  |      |  |  |      |    |  |      |  |    |      |  |  |      |  |  |      |       |  |  |  |       |  |  |  |        | 
|------------------------- |  | -------------- | --- |  | ----- |  | --- | ----- |  |  | ---- |  |  | ---- | -- |  | ---- |  | -- | ---- |  |  | ---- |  |  | ---- | ----- |  |  |  | ----- |  |  |  | ------ | 
|                          |  | United Kingdom |     |  | Other |  |     | Total | 
|                          |  |                |     |  |       |  |     |       | 
|                          |  | 2004           |     |  | 2003  |  |     | 2002  |  |  | 2004 |  |  | 2003 |    |  | 2002 |  |    | 2004 |  |  | 2003 |  |  | 2002 |      
|                          | 
|                          |  | ($ millions)  
|Acquisitions              |  |                |     |  |       |  |     |       |  |  |      |  |  |      |    |  |      |  |    |      |  |  |      |  |  |      |       |  |  |  |       |  |  |  |        | 
| AEC unproved reserves   |  |                |    |  |       |  |    |       |  |  |     |  |  |      |   |  |      |  |   |      |  |  |     |  |  |      |      |  |  |  |      |  |  |  | 2,161  | 
| other unproved reserves |  |                |    |  |       |  | 16  |       |  |  |     |  |  |      |   |  |      |  |   |      |  |  |     |  |  |      | 996   |  |  |  | 164   |  |  |  | 214    | 
| AEC proved reserves     |  |                |    |  |       |  |    |       |  |  |     |  |  |      |   |  |      |  |   |      |  |  |     |  |  |      |      |  |  |  |      |  |  |  | 5,250  | 
| other proved reserves   |  |                | 130 |  |       |  | 95  |       |  |  |     |  |  |      |   |  |      |  |   |      |  |  |     |  |  |      | 2,385 |  |  |  | 476   |  |  |  | 535    | 
|                         
|Total acquisitions        |  |                | 130 |  |       |  | 111 |       |  |  |     |  |  |      |   |  |      |  |   |      |  |  |     |  |  |      | 3,381 |  |  |  | 640   |  |  |  | 8,160  | 
|Exploration               |  |                | 22  |  |       |  | 30  |       |  |  | 16   |  |  |      | 79 |  |      |  | 78 |      |  |  | 118  |  |  |      | 848   |  |  |  | 1,161 |  |  |  | 798    | 
|Development               |  |                | 364 |  |       |  | 96  |       |  |  | 66   |  |  |      |   |  |      |  |   |      |  |  |     |  |  |      | 4,349 |  |  |  | 2,989 |  |  |  | 1,383  | 
|                         
|Total costs incurred      |  |                | 516 |  |       |  | 237 |       |  |  | 82   |  |  |      | 79 |  |      |  | 78 |      |  |  | 118  |  |  |      | 8,578 |  |  |  | 4,790 |  |  |  | 10,341 | 
|                         

27



---



##### 






Daily Sales Volumes, Royalty Rates and Per-Unit Results


Daily Sales Volumes




|                                         |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        | 
|---------------------------------------- | ---------------------- | -------------------------------- | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | 
|                                         |                        | Daily Sales Volumes  2004       |              
|                                         |                        |                                  |              
|                                         |                        | Year                             |               |        | Q4     |        |         | Q3     |        |        | Q2      |        |        | Q1     |        
|                                         |                       
|SALES                                    |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                        
|Continuing Operations:                   |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                        
|Produced Gas (MMcf/d)                    |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                         | Canada                 |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                         |                        | Production                       |               |        | 2,105  |        |         |        | 2,106  |        |         |        | 2,138  |        |         |        | 2,177  |        |         |        | 2,000  |       
|                                         |                        | Inventory withdrawal/(injection) |               |        | (6     | )      |         |        | (26    | )      |         |        |       |        |         |        |       |        |         |        |       |       
|                                        
|                                         | Canada
    Sales(1)    |                                  |               | 2,099  |        |        |         | 2,080  |        |        |         | 2,138  |        |        |         | 2,177  |        |        |         | 2,000  |       
|                                         | United States          |                                  |               | 869    |        |        |         | 1,007  |        |        |         | 958    |        |        |         | 824    |        |        |         | 684    |       
|                                        
|Total Produced Gas                       |                        |                                  | 2,968         |        |        |        | 3,087   |        |        |        | 3,096   |        |        |        | 3,001   |        |        |        | 2,684   |       
|                                        
|Oil and Natural Gas Liquids (bbls/d)     |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                         | North America          |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                         |                        | Light and medium oil             |               |        | 56,215 |        |         |        | 52,725 |        |         |        | 52,824 |        |         |        | 64,448 |        |         |        | 54,940 |       
|                                         |                        | Heavy oil                        |               |        | 84,164 |        |         |        | 79,336 |        |         |        | 89,682 |        |         |        | 79,899 |        |         |        | 87,729 |       
|                                         |                        | Natural gas liquids              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |       
|                                         |                        |                                  | Canada        |        |        | 13,452 |         |        |        | 13,452 |         |        |        | 12,804 |         |        |        | 13,588 |         |        |        | 13,971 | 
|                                         |                        |                                  | United States |        |        | 12,586 |         |        |        | 13,957 |         |        |        | 14,363 |         |        |        | 12,752 |         |        |        | 9,237  | 
|                                        
|Total Oil and Natural Gas
    Liquids(2) |                        |                                  | 166,417       |        |        |        | 159,470 |        |        |        | 169,673 |        |        |        | 170,687 |        |        |        | 165,877 |       
|                                        
|Total Continuing Operations (MMcfe/d)    |                        |                                  | 3,966         |        |        |        | 4,044   |        |        |        | 4,114   |        |        |        | 4,025   |        |        |        | 3,679   |       
|                                        
|Total Continuing Operations (BOE/d)      |                        |                                  | 661,084       |        |        |        | 673,970 |        |        |        | 685,673 |        |        |        | 670,854 |        |        |        | 613,210 |       
|                                        
|                                        
|Discontinued Operations:                
|                                        
|                                         | Ecuador                |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                         |                        | Production(3)                    |               |        | 76,872 |        |         |        | 76,235 |        |         |        | 76,567 |        |         |        | 78,376 |        |         |        | 76,320 |       
|                                         |                        | Over/(under) lifting             |               |        | 1,121  |        |         |        | 1,641  |        |         |        | (1,721 | )      |         |        | (73    | )      |         |        | 4,662  |       
|                                        
|                                         | Ecuador Sales (bbls/d) |                                  |               | 77,993 |        |        |         | 77,876 |        |        |         | 74,846 |        |        |         | 78,303 |        |        |         | 80,982 |       
|                                        
|                                         | United Kingdom (BOE/d) |                                  |               | 20,973 |        |        |         | 13,927 |        |        |         | 20,222 |        |        |         | 26,728 |        |        |         | 22,755 |       
|                                        
|Total Discontinued Operations (MMcfe/d)  |                        |                                  | 594           |        |        |        | 551     |        |        |        | 570     |        |        |        | 630     |        |        |        | 623     |       
|                                        
|Total Discontinued Operations (BOE/d)    |                        |                                  | 98,966        |        |        |        | 91,803  |        |        |        | 95,068  |        |        |        | 105,031 |        |        |        | 103,737 |       
|                                        
|Total (MMcfe/d)                          |                        |                                  | 4,560         |        |        |        | 4,595   |        |        |        | 4,684   |        |        |        | 4,655   |        |        |        | 4,302   |       
|                                        
|Total (BOE/d)                            |                        |                                  | 760,050       |        |        |        | 765,773 |        |        |        | 780,741 |        |        |        | 775,885 |        |        |        | 716,947 |       
|                                        





|    |                                                                                 
|--- | --------------------------------------------------------------------------------
|(1) | Net dispositions total approximately 42 MMcf/day for the full
    year 2004.    
|   
|(2) | Net dispositions total approximately 15,500 bbls/day for the
    full year 2004.
|   
|(3) | 2004 includes approximately 31,000 bbls/day related to Block 15.                

28



---



##### 



|                                        |                        |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        | 
|--------------------------------------- | ---------------------- | ---------------------------------- | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | 
|                                        |                        | Daily Sales Volumes  2003         |              
|                                        |                        |                                    |              
|                                        |                        | Year                               |               |        | Q4     |        |         | Q3     |        |        | Q2      |        |        | Q1     |        
|                                        |                       
|SALES                                   |                        |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                       
|Continuing Operations:                  |                        |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                       
|Produced Gas (MMcf/d)                   |                        |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                        | Canada                 |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                        |                        | Production                         |               |        | 1,935  |        |         |        | 2,008  |        |         |        | 1,914  |        |         |        | 1,899  |        |         |        | 1,922  |       
|                                        |                        | Inventory withdrawal/(injection)   |               |        | 30     |        |         |        |       |        |         |        |       |        |         |        |       |        |         |        | 120    |       
|                                       
|                                        | Canada Sales           |                                    |               | 1,965  |        |        |         | 2,008  |        |        |         | 1,914  |        |        |         | 1,899  |        |        |         | 2,042  |       
|                                        | United States          |                                    |               | 588    |        |        |         | 654    |        |        |         | 604    |        |        |         | 558    |        |        |         | 534    |       
|                                       
|Total Produced Gas                      |                        |                                    | 2,553         |        |        |        | 2,662   |        |        |        | 2,518   |        |        |        | 2,457   |        |        |        | 2,576   |       
|                                       
|Oil and Natural Gas Liquids (bbls/d)    |                        |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                        | North America          |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                        |                        | Light and medium oil               |               |        | 54,459 |        |         |        | 56,585 |        |         |        | 54,597 |        |         |        | 52,733 |        |         |        | 53,890 |       
|                                        |                        | Heavy oil                          |               |        | 87,867 |        |         |        | 95,059 |        |         |        | 94,985 |        |         |        | 82,001 |        |         |        | 79,171 |       
|                                        |                        | Natural gas liquids                |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |       
|                                        |                        |                                    | Canada        |        |        | 14,278 |         |        |        | 13,348 |         |        |        | 13,758 |         |        |        | 14,740 |         |        |        | 15,291 | 
|                                        |                        |                                    | United States |        |        | 9,291  |         |        |        | 9,479  |         |        |        | 9,530  |         |        |        | 10,194 |         |        |        | 7,943  | 
|                                       
|Total Oil and Natural Gas Liquids       |                        |                                    | 165,895       |        |        |        | 174,471 |        |        |        | 172,870 |        |        |        | 159,668 |        |        |        | 156,295 |       
|                                       
|Total Continuing Operations (MMcfe/d)   |                        |                                    | 3,548         |        |        |        | 3,709   |        |        |        | 3,555   |        |        |        | 3,415   |        |        |        | 3,514   |       
|                                       
|Total Continuing Operations (BOE/d)     |                        |                                    | 591,395       |        |        |        | 618,138 |        |        |        | 592,537 |        |        |        | 569,168 |        |        |        | 585,628 |       
|                                       
|                                       
|Discontinued Operations:               
|                                       
|                                        | Ecuador                |                                    |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                        |                        | Production                         |               |        | 51,089 |        |         |        | 72,731 |        |         |        | 54,582 |        |         |        | 36,754 |        |         |        | 39,893 |       
|                                        |                        | Transferred to OCP
    Pipeline(1) |               |        | (3,213 | )      |         |        |       |        |         |        | (4,919 | )      |         |        | (2,039 | )      |         |        | (5,941 | )     
|                                        |                        | Over/(under) lifting               |               |        | (1,355 | )      |         |        | 4,621  |        |         |        | (9,856 | )      |         |        | 2,506  |        |         |        | (2,679 | )     
|                                       
|                                        | Ecuador Sales (bbls/d) |                                    |               | 46,521 |        |        |         | 77,352 |        |        |         | 39,807 |        |        |         | 37,221 |        |        |         | 31,273 |       
|                                       
|                                        | United Kingdom (BOE/d) |                                    |               | 12,295 |        |        |         | 18,400 |        |        |         | 6,979  |        |        |         | 11,019 |        |        |         | 12,777 |       
|                                       
|                                        | Syncrude (bbls/d)      |                                    |               | 7,629  |        |        |         |       |        |        |         | 3,399  |        |        |         | 7,316  |        |        |         | 20,070 |       
|                                       
|Total Discontinued Operations (MMcfe/d) |                        |                                    | 399           |        |        |        | 574     |        |        |        | 301     |        |        |        | 333     |        |        |        | 385     |       
|                                       
|Total Discontinued Operations (BOE/d)   |                        |                                    | 66,445        |        |        |        | 95,752  |        |        |        | 50,185  |        |        |        | 55,556  |        |        |        | 64,120  |       
|                                       
|Total (MMcfe/d)                         |                        |                                    | 3,947         |        |        |        | 4,283   |        |        |        | 3,856   |        |        |        | 3,748   |        |        |        | 3,899   |       
|                                       
|Total (BOE/d)                           |                        |                                    | 657,840       |        |        |        | 713,890 |        |        |        | 642,722 |        |        |        | 624,724 |        |        |        | 649,748 |       
|                                       





|    |                                                                                                           
|--- | ----------------------------------------------------------------------------------------------------------
|(1) | Crude oil production in Ecuador transferred to the OCP Pipeline
    for use by OCP in asset commissioning.

29



---



##### 



|                                        |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        | 
|--------------------------------------- | ---------------------- | -------------------------------- | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | 
|                                        |                        | Daily Sales Volumes  2002       |              
|                                        |                        |                                  |              
|                                        |                        | Year                             |               |        | Q4     |        |         | Q3     |        |        | Q2      |        |        | Q1     |        
|                                        |                       
|SALES                                   |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                       
|Continuing Operations:                  |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                       
|Produced Gas (MMcf/d)                   |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                        | Canada                 |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                        |                        | Production                       |               |        | 1,717  |        |         |        | 1,943  |        |         |        | 1,959  |        |         |        | 1,980  |        |         |        | 975    |       
|                                        |                        | Inventory withdrawal/(injection) |               |        | (6     | )      |         |        | 117    |        |         |        | (51    | )      |         |        | (90    | )      |         |        |       |       
|                                       
|                                        | Canada Sales           |                                  |               | 1,711  |        |        |         | 2,060  |        |        |         | 1,908  |        |        |         | 1,890  |        |        |         | 975    |       
|                                        | United States          |                                  |               | 337    |        |        |         | 516    |        |        |         | 423    |        |        |         | 345    |        |        |         | 58     |       
|                                       
|Total Produced Gas                      |                        |                                  | 2,048         |        |        |        | 2,576   |        |        |        | 2,331   |        |        |        | 2,235   |        |        |        | 1,033   |       
|                                       
|Oil and Natural Gas Liquids (bbls/d)    |                        |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                        | North America          |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                        |                        | Light and medium oil             |               |        | 58,328 |        |         |        | 55,265 |        |         |        | 58,321 |        |         |        | 58,885 |        |         |        | 60,903 |       
|                                        |                        | Heavy oil                        |               |        | 58,890 |        |         |        | 77,090 |        |         |        | 70,795 |        |         |        | 67,558 |        |         |        | 19,350 |       
|                                        |                        | Natural gas liquids              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |       
|                                        |                        |                                  | Canada        |        |        | 13,852 |         |        |        | 15,987 |         |        |        | 13,985 |         |        |        | 14,168 |         |        |        | 11,212 | 
|                                        |                        |                                  | United States |        |        | 6,407  |         |        |        | 10,016 |         |        |        | 5,901  |         |        |        | 6,368  |         |        |        | 3,274  | 
|                                       
|Total Oil and Natural Gas Liquids       |                        |                                  | 137,477       |        |        |        | 158,358 |        |        |        | 149,002 |        |        |        | 146,979 |        |        |        | 94,739  |       
|                                       
|Total Continuing Operations (MMcfe/d)   |                        |                                  | 2,873         |        |        |        | 3,526   |        |        |        | 3,225   |        |        |        | 3,117   |        |        |        | 1,601   |       
|                                       
|Total Continuing Operations (BOE/d)     |                        |                                  | 478,810       |        |        |        | 587,691 |        |        |        | 537,502 |        |        |        | 519,479 |        |        |        | 266,906 |       
|                                       
|                                       
|Discontinued Operations:               
|                                       
|                                        | Ecuador                |                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                        |                        | Production                       |               |        | 27,625 |        |         |        | 34,856 |        |         |        | 37,447 |        |         |        | 37,702 |        |         |        |       |       
|                                        |                        | Over/(under) lifting             |               |        | 2,115  |        |         |        | 1,044  |        |         |        | 2,316  |        |         |        | 5,088  |        |         |        |       |       
|                                       
|                                        | Ecuador Sales (bbls/d) |                                  |               | 29,740 |        |        |         | 35,900 |        |        |         | 39,763 |        |        |         | 42,790 |        |        |         |       |       
|                                       
|                                        | United Kingdom (BOE/d) |                                  |               | 12,195 |        |        |         | 9,120  |        |        |         | 11,038 |        |        |         | 13,299 |        |        |         | 14,722 |       
|                                       
|                                        | Syncrude (bbls/d)      |                                  |               | 23,540 |        |        |         | 33,918 |        |        |         | 35,585 |        |        |         | 24,152 |        |        |         |       |       
|                                       
|Total Discontinued Operations (MMcfe/d) |                        |                                  | 393           |        |        |        | 474     |        |        |        | 518     |        |        |        | 481     |        |        |        | 88      |       
|                                       
|Total Discontinued Operations (BOE/d)   |                        |                                  | 65,475        |        |        |        | 78,938  |        |        |        | 86,386  |        |        |        | 80,241  |        |        |        | 14,722  |       
|                                       
|Total (MMcfe/d)                         |                        |                                  | 3,266         |        |        |        | 4,000   |        |        |        | 3,743   |        |        |        | 3,598   |        |        |        | 1,689   |       
|                                       
|Total (BOE/d)                           |                        |                                  | 544,285       |        |        |        | 666,629 |        |        |        | 623,888 |        |        |        | 599,720 |        |        |        | 281,628 |       
|                                       

30



---



##### 



Average Royalty Rates




|                         |                          |           |      |           |      |           |      |      |  |  |      |      |  |    |      |      |      |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |  |      |      |  |  |      |      |  |  |     |      | 
|------------------------ | ------------------------ | --------- | ---- | --------- | ---- | --------- | ---- | ---- |  |  | ---- | ---- |  | -- | ---- | ---- | ---- |  | ---- | ---- |  |  | ---- | ---- |  | -- | ---- | ---- | -- |  | ---- | ---- |  |  | ---- | ---- |  | -- | ---- | ---- | -- |  | ---- | ---- |  |  | ---- | ---- |  |  | ---- | ---- |  |  | ---- | ---- |  |  | --- | ---- | 
|                         |                          | 2004      |      |           | 2003 |           |      | 2002 | 
|                         |                          |           |      |           |      |           |      |      | 
|                         |                          | Year      |      |           | Q4   |           |      | Q3   |  |  | Q2   |      |  | Q1 |      |      | Year |  |      | Q4   |  |  | Q3   |      |  | Q2 |      |      | Q1 |  |      | Year |  |  | Q4   |      |  | Q3 |      |      | Q2 |  |      | Q1   | 
|                         |                         
|                         |                          | (percent) |      | (percent) |      | (percent)
|Continuing Operations:   |                          |           |      |           |      |           |      |      |  |  |      |      |  |    |      |      |      |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |  |      |      |  |  |      |      |  |  |     |     
|                        
|Produced Gas             |                          |           |      |           |      |           |      |      |  |  |      |      |  |    |      |      |      |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |  |      |      |  |  |      |      |  |  |     |     
|                         | Canada                   |           |      | 12.5      |      |           |      | 12.0 |  |  |      | 12.2 |  |    |      | 12.7 |      |  |      | 13.3 |  |  |      | 12.9 |  |    |      | 12.2 |    |  |      | 12.9 |  |  |      | 14.2 |  |    |      | 12.4 |    |  |      | 10.7 |  |  |      | 13.3 |  |  |      | 10.4 |  |  |      | 11.8 |  |  |     | 2.7  | 
|                         | United States            |           |      | 19.6      |      |           |      | 19.8 |  |  |      | 18.3 |  |    |      | 21.1 |      |  |      | 19.3 |  |  |      | 20.0 |  |    |      | 19.5 |    |  |      | 20.2 |  |  |      | 20.1 |  |    |      | 20.5 |    |  |      | 21.1 |  |  |      | 21.1 |  |  |      | 23.1 |  |  |      | 19.4 |  |  |     | 19.4 | 
|Crude Oil                |                          |           |      |           |      |           |      |      |  |  |      |      |  |    |      |      |      |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |  |      |      |  |  |      |      |  |  |     |     
|                         | Canada and United States |           |      | 9.0       |      |           |      | 8.7  |  |  |      | 8.8  |  |    |      | 11.6 |      |  |      | 9.4  |  |  |      | 10.3 |  |    |      | 9.7  |    |  |      | 9.0  |  |  |      | 10.7 |  |    |      | 11.8 |    |  |      | 11.0 |  |  |      | 10.8 |  |  |      | 11.7 |  |  |      | 11.6 |  |  |     | 9.5  | 
|Natural Gas Liquids      |                          |           |      |           |      |           |      |      |  |  |      |      |  |    |      |      |      |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |    |      |      |    |  |      |      |  |  |      |      |  |  |      |      |  |  |      |      |  |  |     |     
|                         | Canada                   |           |      | 15.7      |      |           |      | 16.5 |  |  |      | 18.5 |  |    |      | 13.1 |      |  |      | 14.8 |  |  |      | 17.5 |  |    |      | 14.7 |    |  |      | 16.6 |  |  |      | 18.0 |  |    |      | 20.2 |    |  |      | 13.8 |  |  |      | 16.4 |  |  |      | 13.8 |  |  |      | 15.6 |  |  |     | 6.9  | 
|                         | United States            |           |      | 18.7      |      |           |      | 21.4 |  |  |      | 13.6 |  |    |      | 20.7 |      |  |      | 19.2 |  |  |      | 17.6 |  |    |      | 17.5 |    |  |      | 17.0 |  |  |      | 17.3 |  |    |      | 18.5 |    |  |      | 10.8 |  |  |      | 13.3 |  |  |      | 12.0 |  |  |      | 10.5 |  |  |     |     | 
|Total Upstream           |                          |           | 13.7 |           |      |           | 13.8 |      |  |  | 13.2 |      |  |    | 14.1 |      |      |  | 13.7 |      |  |  | 13.8 |      |  |    | 13.2 |      |    |  | 13.4 |      |  |  | 14.5 |      |  |    | 13.9 |      |    |  | 12.3 |      |  |  | 14.1 |      |  |  | 12.7 |      |  |  | 12.8 |      |  |  | 5.7 |     
|                        
|Discontinued Operations:
|                        
|Crude Oil  Ecuador      |                          |           | 27.1 |           |      |           | 27.8 |      |  |  | 26.5 |      |  |    | 26.5 |      |      |  | 27.4 |      |  |  | 25.6 |      |  |    | 25.4 |      |    |  | 25.7 |      |  |  | 24.9 |      |  |    | 26.9 |      |    |  | 28.4 |      |  |  | 28.1 |      |  |  | 28.5 |      |  |  | 28.5 |      |  |  |    |     
|                        

Per-Unit Results




|                                           |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |       | 
|------------------------------------------ | ---------------------------- | ----------------------- |  | ----- | -- |  |  | ----- |  |  | -- | ----- |  | -- |  | ----- |  |  |  | ----- | 
|                                           |                              | Per-Unit Results  2004 | 
|                                           |                              |                         | 
|                                           |                              | Year                    |  |       | Q4 |  |  | Q3    |  |  | Q2 |       |  | Q1 | 
|                                           |                             
|Continuing Operations:                     |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          
|Produced Gas  Canada ($/Mcf)              |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                           | Price                        |                         |  | 5.34  |    |  |  | 5.86  |  |  |    | 5.10  |  |    |  | 5.20  |  |  |  | 5.21  | 
|                                           | Production and mineral taxes |                         |  | 0.08  |    |  |  | 0.10  |  |  |    | 0.09  |  |    |  | 0.07  |  |  |  | 0.08  | 
|                                           | Transportation and selling   |                         |  | 0.39  |    |  |  | 0.39  |  |  |    | 0.37  |  |    |  | 0.35  |  |  |  | 0.44  | 
|                                           | Operating                    |                         |  | 0.52  |    |  |  | 0.55  |  |  |    | 0.50  |  |    |  | 0.49  |  |  |  | 0.56  | 
|                                          
|                                           | Netback                      |                         |  | 4.35  |    |  |  | 4.82  |  |  |    | 4.14  |  |    |  | 4.29  |  |  |  | 4.13  | 
|                                          
|Produced Gas  United States ($/Mcf)       |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                           | Price                        |                         |  | 5.79  |    |  |  | 6.53  |  |  |    | 5.36  |  |    |  | 5.72  |  |  |  | 5.39  | 
|                                           | Production and mineral taxes |                         |  | 0.65  |    |  |  | 0.69  |  |  |    | 0.57  |  |    |  | 0.80  |  |  |  | 0.51  | 
|                                           | Transportation and selling   |                         |  | 0.31  |    |  |  | 0.27  |  |  |    | 0.26  |  |    |  | 0.34  |  |  |  | 0.39  | 
|                                           | Operating                    |                         |  | 0.37  |    |  |  | 0.41  |  |  |    | 0.36  |  |    |  | 0.37  |  |  |  | 0.33  | 
|                                          
|                                           | Netback                      |                         |  | 4.46  |    |  |  | 5.16  |  |  |    | 4.17  |  |    |  | 4.21  |  |  |  | 4.16  | 
|                                          
|Produced Gas  Total North America ($/Mcf) |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                           | Price                        |                         |  | 5.47  |    |  |  | 6.08  |  |  |    | 5.18  |  |    |  | 5.34  |  |  |  | 5.26  | 
|                                           | Production and mineral taxes |                         |  | 0.25  |    |  |  | 0.29  |  |  |    | 0.24  |  |    |  | 0.27  |  |  |  | 0.19  | 
|                                           | Transportation and selling   |                         |  | 0.36  |    |  |  | 0.35  |  |  |    | 0.33  |  |    |  | 0.35  |  |  |  | 0.43  | 
|                                           | Operating                    |                         |  | 0.48  |    |  |  | 0.50  |  |  |    | 0.46  |  |    |  | 0.46  |  |  |  | 0.50  | 
|                                          
|                                           | Netback                      |                         |  | 4.38  |    |  |  | 4.94  |  |  |    | 4.15  |  |    |  | 4.26  |  |  |  | 4.14  | 
|                                          
|Natural Gas Liquids  Canada ($/bbl)       |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                           | Price                        |                         |  | 31.43 |    |  |  | 36.73 |  |  |    | 33.46 |  |    |  | 28.48 |  |  |  | 27.27 | 
|                                           | Production and mineral taxes |                         |  |      |    |  |  |      |  |  |    |      |  |    |  |      |  |  |  |      | 
|                                           | Transportation and selling   |                         |  | 0.41  |    |  |  | 0.47  |  |  |    | 0.45  |  |    |  | 0.35  |  |  |  | 0.35  | 
|                                          
|                                           | Netback                      |                         |  | 31.02 |    |  |  | 36.26 |  |  |    | 33.01 |  |    |  | 28.13 |  |  |  | 26.92 | 
|                                          

31



---



##### 



|                                                         |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |       | 
|-------------------------------------------------------- | ---------------------------- | ----------------------- |  | ----- | -- |  |  | ----- | - |  | -- | ----- |  | -- |  | ----- | - |  |  | ----- | 
|                                                         |                              | Per-Unit Results  2004 | 
|                                                         |                              |                         | 
|                                                         |                              | Year                    |  |       | Q4 |  |  | Q3    |   |  | Q2 |       |  | Q1 | 
|                                                         |                             
|Natural Gas Liquids  United States ($/bbl)              |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |      
|                                                         | Price                        |                         |  | 35.43 |    |  |  | 38.74 |   |  |    | 36.09 |  |    |  | 32.93 |   |  |  | 32.77 | 
|                                                         | Production and mineral taxes |                         |  | 3.82  |    |  |  | 3.94  |   |  |    | 4.05  |  |    |  | 3.93  |   |  |  | 3.09  | 
|                                                         | Transportation and selling   |                         |  |      |    |  |  |      |   |  |    |      |  |    |  |      |   |  |  |      | 
|                                                        
|                                                         | Netback                      |                         |  | 31.61 |    |  |  | 34.80 |   |  |    | 32.04 |  |    |  | 29.00 |   |  |  | 29.68 | 
|                                                        
|Natural Gas Liquids  Total North America ($/bbl)        |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |      
|                                                         | Price                        |                         |  | 33.36 |    |  |  | 37.75 |   |  |    | 34.85 |  |    |  | 30.63 |   |  |  | 29.46 | 
|                                                         | Production and mineral taxes |                         |  | 1.84  |    |  |  | 2.00  |   |  |    | 2.14  |  |    |  | 1.90  |   |  |  | 1.23  | 
|                                                         | Transportation and selling   |                         |  | 0.21  |    |  |  | 0.23  |   |  |    | 0.21  |  |    |  | 0.18  |   |  |  | 0.21  | 
|                                                        
|                                                         | Netback                      |                         |  | 31.31 |    |  |  | 35.52 |   |  |    | 32.50 |  |    |  | 28.55 |   |  |  | 28.02 | 
|                                                        
|Crude Oil  Light and Medium  North America
    ($/bbl) |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |      
|                                                         | Price                        |                         |  | 34.67 |    |  |  | 39.57 |   |  |    | 37.40 |  |    |  | 32.43 |   |  |  | 29.92 | 
|                                                         | Production and mineral taxes |                         |  | 0.96  |    |  |  | 1.38  |   |  |    | 0.85  |  |    |  | 0.79  |   |  |  | 0.86  | 
|                                                         | Transportation and selling   |                         |  | 1.01  |    |  |  | 1.04  |   |  |    | 1.08  |  |    |  | 0.76  |   |  |  | 1.19  | 
|                                                         | Operating                    |                         |  | 5.85  |    |  |  | 6.41  |   |  |    | 6.49  |  |    |  | 4.84  |   |  |  | 5.87  | 
|                                                        
|                                                         | Netback                      |                         |  | 26.85 |    |  |  | 30.74 |   |  |    | 28.98 |  |    |  | 26.04 |   |  |  | 22.00 | 
|                                                        
|Crude Oil  Heavy  North America ($/bbl)                |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |      
|                                                         | Price                        |                         |  | 23.41 |    |  |  | 21.37 |   |  |    | 28.01 |  |    |  | 22.35 |   |  |  | 21.48 | 
|                                                         | Production and mineral taxes |                         |  | 0.04  |    |  |  | 0.04  |   |  |    | 0.05  |  |    |  | (0.01 | ) |  |  | 0.06  | 
|                                                         | Transportation and selling   |                         |  | 1.09  |    |  |  | (0.57 | ) |  |    | 1.63  |  |    |  | 1.50  |   |  |  | 1.69  | 
|                                                         | Operating                    |                         |  | 5.32  |    |  |  | 6.27  |   |  |    | 4.79  |  |    |  | 4.82  |   |  |  | 5.44  | 
|                                                        
|                                                         | Netback                      |                         |  | 16.96 |    |  |  | 15.63 |   |  |    | 21.54 |  |    |  | 16.04 |   |  |  | 14.29 | 
|                                                        
|Crude Oil  Total North America ($/bbl)                  |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |      
|                                                         | Price                        |                         |  | 27.92 |    |  |  | 28.63 |   |  |    | 31.49 |  |    |  | 26.85 |   |  |  | 24.73 | 
|                                                         | Production and mineral taxes |                         |  | 0.41  |    |  |  | 0.57  |   |  |    | 0.34  |  |    |  | 0.35  |   |  |  | 0.37  | 
|                                                         | Transportation and selling   |                         |  | 1.06  |    |  |  | 0.07  |   |  |    | 1.42  |  |    |  | 1.17  |   |  |  | 1.50  | 
|                                                         | Operating                    |                         |  | 5.53  |    |  |  | 6.33  |   |  |    | 5.42  |  |    |  | 4.83  |   |  |  | 5.61  | 
|                                                        
|                                                         | Netback                      |                         |  | 20.92 |    |  |  | 21.66 |   |  |    | 24.31 |  |    |  | 20.50 |   |  |  | 17.25 | 
|                                                        
|Total Liquids  Canada ($/bbl)                           |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |      
|                                                         | Price                        |                         |  | 28.21 |    |  |  | 29.36 |   |  |    | 31.63 |  |    |  | 26.99 |   |  |  | 24.95 | 
|                                                         | Production and mineral taxes |                         |  | 0.37  |    |  |  | 0.52  |   |  |    | 0.31  |  |    |  | 0.32  |   |  |  | 0.34  | 
|                                                         | Transportation and selling   |                         |  | 1.00  |    |  |  | 0.11  |   |  |    | 1.35  |  |    |  | 1.10  |   |  |  | 1.40  | 
|                                                         | Operating                    |                         |  | 5.05  |    |  |  | 5.75  |   |  |    | 4.98  |  |    |  | 4.42  |   |  |  | 5.11  | 
|                                                        
|                                                         | Netback                      |                         |  | 21.79 |    |  |  | 22.98 |   |  |    | 24.99 |  |    |  | 21.15 |   |  |  | 18.10 | 
|                                                        
|Total Liquids  North America ($/bbl)                    |                              |                         |  |       |    |  |  |       |   |  |    |       |  |    |  |       |   |  |  |      
|                                                         | Price                        |                         |  | 28.77 |    |  |  | 30.20 |   |  |    | 32.03 |  |    |  | 27.43 |   |  |  | 25.39 | 
|                                                         | Production and mineral taxes |                         |  | 0.63  |    |  |  | 0.82  |   |  |    | 0.63  |  |    |  | 0.59  |   |  |  | 0.49  | 
|                                                         | Transportation and selling   |                         |  | 0.93  |    |  |  | 0.10  |   |  |    | 1.23  |  |    |  | 1.02  |   |  |  | 1.32  | 
|                                                         | Operating                    |                         |  | 4.67  |    |  |  | 5.24  |   |  |    | 4.55  |  |    |  | 4.09  |   |  |  | 4.82  | 
|                                                        
|                                                         | Netback                      |                         |  | 22.54 |    |  |  | 24.04 |   |  |    | 25.62 |  |    |  | 21.73 |   |  |  | 18.76 | 
|                                                        

32



---



##### 



|                                   |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |       | 
|---------------------------------- | ---------------------------- | ----------------------- |  | ----- | -- |  |  | ----- |  |  | -- | ----- |  | -- |  | ----- |  |  |  | ----- | 
|                                   |                              | Per-Unit Results  2004 | 
|                                   |                              |                         | 
|                                   |                              | Year                    |  |       | Q4 |  |  | Q3    |  |  | Q2 |       |  | Q1 | 
|                                   |                             
|Total North America ($/Mcfe)       |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                   | Price                        |                         |  | 5.30  |    |  |  | 5.83  |  |  |    | 5.22  |  |    |  | 5.15  |  |  |  | 4.98  | 
|                                   | Production and mineral taxes |                         |  | 0.21  |    |  |  | 0.25  |  |  |    | 0.21  |  |    |  | 0.22  |  |  |  | 0.16  | 
|                                   | Transportation and selling   |                         |  | 0.31  |    |  |  | 0.27  |  |  |    | 0.30  |  |    |  | 0.30  |  |  |  | 0.37  | 
|                                   | Operating                    |                         |  | 0.55  |    |  |  | 0.59  |  |  |    | 0.53  |  |    |  | 0.52  |  |  |  | 0.58  | 
|                                  
|                                   | Netback                      |                         |  | 4.23  |    |  |  | 4.72  |  |  |    | 4.18  |  |    |  | 4.11  |  |  |  | 3.87  | 
|                                  
|Discontinued Operations:           |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                  
|Crude Oil  Ecuador ($/bbl)        |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                   | Price                        |                         |  | 28.68 |    |  |  | 29.97 |  |  |    | 33.47 |  |    |  | 27.78 |  |  |  | 23.82 | 
|                                   | Production and mineral taxes |                         |  | 2.13  |    |  |  | 2.73  |  |  |    | 2.62  |  |    |  | 1.84  |  |  |  | 1.37  | 
|                                   | Transportation and selling   |                         |  | 2.12  |    |  |  | 1.57  |  |  |    | 2.36  |  |    |  | 1.92  |  |  |  | 2.63  | 
|                                   | Operating                    |                         |  | 4.39  |    |  |  | 5.02  |  |  |    | 4.35  |  |    |  | 4.14  |  |  |  | 4.04  | 
|                                  
|                                   | Netback                      |                         |  | 20.04 |    |  |  | 20.65 |  |  |    | 24.14 |  |    |  | 19.88 |  |  |  | 15.78 | 
|                                  
|Crude Oil  United Kingdom ($/bbl) |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                   | Price                        |                         |  | 36.92 |    |  |  | 46.19 |  |  |    | 40.88 |  |    |  | 34.68 |  |  |  | 31.11 | 
|                                   | Production and mineral taxes |                         |  |      |    |  |  |      |  |  |    |      |  |    |  |      |  |  |  |      | 
|                                   | Transportation and selling   |                         |  | 2.06  |    |  |  | 2.17  |  |  |    | 2.44  |  |    |  | 1.85  |  |  |  | 1.94  | 
|                                   | Operating                    |                         |  | 6.75  |    |  |  | 5.00  |  |  |    | 9.98  |  |    |  | 7.84  |  |  |  | 3.86  | 
|                                  
|                                   | Netback                      |                         |  | 28.11 |    |  |  | 39.02 |  |  |    | 28.46 |  |    |  | 24.99 |  |  |  | 25.31 | 
|                                  

33



---



##### 



|                                                         |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |       |  
|-------------------------------------------------------- | ---------------------------- | ----------------------- |  | ----- | -- |  |  | ----- |  |  | -- | ----- | - | -- |  | ----- |  |  |  | ----- | -
|                                                         |                              | Per-Unit Results  2003 | 
|                                                         |                              |                         | 
|                                                         |                              | Year                    |  |       | Q4 |  |  | Q3    |  |  | Q2 |       |   | Q1 | 
|                                                         |                             
|Continuing Operations:                                   |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                        
|Produced Gas  Canada ($/Mcf)                            |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 4.87  |    |  |  | 4.41  |  |  |    | 4.61  |   |    |  | 4.92  |  |  |  | 5.53  |  
|                                                         | Production and mineral taxes |                         |  | 0.07  |    |  |  | 0.10  |  |  |    | 0.08  |   |    |  | 0.08  |  |  |  | 0.02  |  
|                                                         | Transportation and selling   |                         |  | 0.38  |    |  |  | 0.44  |  |  |    | 0.40  |   |    |  | 0.35  |  |  |  | 0.33  |  
|                                                         | Operating                    |                         |  | 0.48  |    |  |  | 0.45  |  |  |    | 0.50  |   |    |  | 0.47  |  |  |  | 0.48  |  
|                                                        
|                                                         | Netback                      |                         |  | 3.94  |    |  |  | 3.42  |  |  |    | 3.63  |   |    |  | 4.02  |  |  |  | 4.70  |  
|                                                        
|Produced Gas  United States ($/Mcf)                     |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 4.88  |    |  |  | 4.71  |  |  |    | 4.82  |   |    |  | 4.74  |  |  |  | 5.32  |  
|                                                         | Production and mineral taxes |                         |  | 0.47  |    |  |  | 0.42  |  |  |    | 0.46  |   |    |  | 0.46  |  |  |  | 0.57  |  
|                                                         | Transportation and selling   |                         |  | 0.40  |    |  |  | 0.51  |  |  |    | 0.39  |   |    |  | 0.36  |  |  |  | 0.32  |  
|                                                         | Operating                    |                         |  | 0.28  |    |  |  | 0.29  |  |  |    | 0.33  |   |    |  | 0.31  |  |  |  | 0.20  |  
|                                                        
|                                                         | Netback                      |                         |  | 3.73  |    |  |  | 3.49  |  |  |    | 3.64  |   |    |  | 3.61  |  |  |  | 4.23  |  
|                                                        
|Produced Gas  Total North America ($/Mcf)               |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 4.87  |    |  |  | 4.49  |  |  |    | 4.66  |   |    |  | 4.88  |  |  |  | 5.49  |  
|                                                         | Production and mineral taxes |                         |  | 0.16  |    |  |  | 0.18  |  |  |    | 0.17  |   |    |  | 0.17  |  |  |  | 0.14  |  
|                                                         | Transportation and selling   |                         |  | 0.39  |    |  |  | 0.46  |  |  |    | 0.40  |   |    |  | 0.35  |  |  |  | 0.33  |  
|                                                         | Operating                    |                         |  | 0.43  |    |  |  | 0.41  |  |  |    | 0.46  |   |    |  | 0.43  |  |  |  | 0.42  |  
|                                                        
|                                                         | Netback                      |                         |  | 3.89  |    |  |  | 3.44  |  |  |    | 3.63  |   |    |  | 3.93  |  |  |  | 4.60  |  
|                                                        
|Natural Gas Liquids  Canada ($/bbl)                     |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 24.26 |    |  |  | 25.13 |  |  |    | 23.52 |   |    |  | 21.02 |  |  |  | 27.31 |  
|                                                         | Production and mineral taxes |                         |  |      |    |  |  |      |  |  |    |      |   |    |  |      |  |  |  |      |  
|                                                         | Transportation and selling   |                         |  | 0.17  |    |  |  | 0.13  |  |  |    | 0.58  |   |    |  |      |  |  |  |      |  
|                                                        
|                                                         | Netback                      |                         |  | 24.09 |    |  |  | 25.00 |  |  |    | 22.94 |   |    |  | 21.02 |  |  |  | 27.31 |  
|                                                        
|Natural Gas Liquids  United States ($/bbl)              |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 26.97 |    |  |  | 26.68 |  |  |    | 25.50 |   |    |  | 24.64 |  |  |  | 32.18 |  
|                                                         | Production and mineral taxes |                         |  | 2.03  |    |  |  | 2.69  |  |  |    | 2.64  |   |    |  | 1.21  |  |  |  | 1.55  |  
|                                                         | Transportation and selling   |                         |  |      |    |  |  |      |  |  |    |      |   |    |  |      |  |  |  |      |  
|                                                        
|                                                         | Netback                      |                         |  | 24.94 |    |  |  | 23.99 |  |  |    | 22.86 |   |    |  | 23.43 |  |  |  | 30.63 |  
|                                                        
|Natural Gas Liquids  Total North America ($/bbl)        |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 25.33 |    |  |  | 25.77 |  |  |    | 24.33 |   |    |  | 22.50 |  |  |  | 28.98 |  
|                                                         | Production and mineral taxes |                         |  | 0.80  |    |  |  | 1.12  |  |  |    | 1.08  |   |    |  | 0.50  |  |  |  | 0.53  |  
|                                                         | Transportation and selling   |                         |  | 0.10  |    |  |  | 0.08  |  |  |    | 0.35  |   |    |  |      |  |  |  |      |  
|                                                        
|                                                         | Netback                      |                         |  | 24.43 |    |  |  | 24.57 |  |  |    | 22.90 |   |    |  | 22.00 |  |  |  | 28.45 |  
|                                                        
|Crude Oil  Light and Medium  North America
    ($/bbl) |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 26.61 |    |  |  | 25.53 |  |  |    | 24.31 |   |    |  | 27.43 |  |  |  | 29.34 |  
|                                                         | Production and mineral taxes |                         |  | 0.29  |    |  |  | 0.73  |  |  |    | (1.35 | ) |    |  | 0.71  |  |  |  | 1.08  |  
|                                                         | Transportation and selling   |                         |  | 1.42  |    |  |  | 1.33  |  |  |    | 0.71  |   |    |  | 1.73  |  |  |  | 1.95  |  
|                                                         | Operating                    |                         |  | 6.00  |    |  |  | 6.28  |  |  |    | 5.93  |   |    |  | 6.07  |  |  |  | 5.68  |  
|                                                        
|                                                         | Netback                      |                         |  | 18.90 |    |  |  | 17.19 |  |  |    | 19.02 |   |    |  | 18.92 |  |  |  | 20.63 |  
|                                                        
|Crude Oil  Heavy  North America ($/bbl)                |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 19.61 |    |  |  | 18.43 |  |  |    | 17.93 |   |    |  | 20.07 |  |  |  | 22.62 |  
|                                                         | Production and mineral taxes |                         |  | (0.03 | )  |  |  | 0.09  |  |  |    | (0.49 | ) |    |  | 0.34  |  |  |  | (0.02 | )
|                                                         | Transportation and selling   |                         |  | 1.24  |    |  |  | 1.54  |  |  |    | 0.58  |   |    |  | 1.37  |  |  |  | 1.56  |  
|                                                         | Operating                    |                         |  | 5.67  |    |  |  | 4.95  |  |  |    | 5.93  |   |    |  | 6.18  |  |  |  | 5.70  |  
|                                                        
|                                                         | Netback                      |                         |  | 12.73 |    |  |  | 11.85 |  |  |    | 11.91 |   |    |  | 12.18 |  |  |  | 15.38 |  
|                                                        

34



---



##### 



|                                        |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |       | 
|--------------------------------------- | ---------------------------- | ----------------------- |  | ----- | -- |  |  | ----- |  |  | -- | ----- | - | -- |  | ----- |  |  |  | ----- | 
|                                        |                              | Per-Unit Results  2003 | 
|                                        |                              |                         | 
|                                        |                              | Year                    |  |       | Q4 |  |  | Q3    |  |  | Q2 |       |   | Q1 | 
|                                        |                             
|Crude Oil  Total North America ($/bbl) |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                        | Price                        |                         |  | 22.29 |    |  |  | 21.08 |  |  |    | 20.26 |   |    |  | 22.95 |  |  |  | 25.34 | 
|                                        | Production and mineral taxes |                         |  | 0.09  |    |  |  | 0.33  |  |  |    | (0.80 | ) |    |  | 0.49  |  |  |  | 0.43  | 
|                                        | Transportation and selling   |                         |  | 1.31  |    |  |  | 1.46  |  |  |    | 0.63  |   |    |  | 1.51  |  |  |  | 1.72  | 
|                                        | Operating                    |                         |  | 5.80  |    |  |  | 5.45  |  |  |    | 5.93  |   |    |  | 6.13  |  |  |  | 5.70  | 
|                                       
|                                        | Netback                      |                         |  | 15.09 |    |  |  | 13.84 |  |  |    | 14.50 |   |    |  | 14.82 |  |  |  | 17.49 | 
|                                       
|Total Liquids  Canada ($/bbl)          |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                        | Price                        |                         |  | 22.47 |    |  |  | 21.41 |  |  |    | 20.54 |   |    |  | 22.76 |  |  |  | 25.55 | 
|                                        | Production and mineral taxes |                         |  | 0.08  |    |  |  | 0.30  |  |  |    | (0.73 | ) |    |  | 0.44  |  |  |  | 0.38  | 
|                                        | Transportation and selling   |                         |  | 1.21  |    |  |  | 1.36  |  |  |    | 0.62  |   |    |  | 1.36  |  |  |  | 1.54  | 
|                                        | Operating                    |                         |  | 5.27  |    |  |  | 5.01  |  |  |    | 5.43  |   |    |  | 5.53  |  |  |  | 5.11  | 
|                                       
|                                        | Netback                      |                         |  | 15.91 |    |  |  | 14.74 |  |  |    | 15.22 |   |    |  | 15.43 |  |  |  | 18.52 | 
|                                       
|Total Liquids  North America ($/bbl)   |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                        | Price                        |                         |  | 22.72 |    |  |  | 21.69 |  |  |    | 20.81 |   |    |  | 22.88 |  |  |  | 25.88 | 
|                                        | Production and mineral taxes |                         |  | 0.19  |    |  |  | 0.43  |  |  |    | (0.55 | ) |    |  | 0.49  |  |  |  | 0.44  | 
|                                        | Transportation and selling   |                         |  | 1.14  |    |  |  | 1.28  |  |  |    | 0.59  |   |    |  | 1.28  |  |  |  | 1.46  | 
|                                        | Operating                    |                         |  | 4.97  |    |  |  | 4.74  |  |  |    | 5.13  |   |    |  | 5.18  |  |  |  | 4.85  | 
|                                       
|                                        | Netback                      |                         |  | 16.42 |    |  |  | 15.24 |  |  |    | 15.64 |   |    |  | 15.93 |  |  |  | 19.13 | 
|                                       
|Total North America ($/Mcfe)            |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                        | Price                        |                         |  | 4.57  |    |  |  | 4.24  |  |  |    | 4.31  |   |    |  | 4.58  |  |  |  | 5.17  | 
|                                        | Production and mineral taxes |                         |  | 0.13  |    |  |  | 0.15  |  |  |    | 0.10  |   |    |  | 0.14  |  |  |  | 0.12  | 
|                                        | Transportation and selling   |                         |  | 0.33  |    |  |  | 0.39  |  |  |    | 0.31  |   |    |  | 0.31  |  |  |  | 0.31  | 
|                                        | Operating                    |                         |  | 0.54  |    |  |  | 0.52  |  |  |    | 0.58  |   |    |  | 0.55  |  |  |  | 0.53  | 
|                                       
|                                        | Netback                      |                         |  | 3.57  |    |  |  | 3.18  |  |  |    | 3.32  |   |    |  | 3.58  |  |  |  | 4.21  | 
|                                       
|Discontinued Operations:                |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                       
|Crude Oil  Ecuador ($/bbl)             |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                        | Price                        |                         |  | 24.21 |    |  |  | 23.57 |  |  |    | 22.13 |   |    |  | 22.31 |  |  |  | 30.86 | 
|                                        | Production and mineral taxes |                         |  | 1.47  |    |  |  | 1.06  |  |  |    | 0.45  |   |    |  | 1.11  |  |  |  | 4.27  | 
|                                        | Transportation and selling   |                         |  | 2.56  |    |  |  | 2.81  |  |  |    | 2.36  |   |    |  | 2.41  |  |  |  | 2.35  | 
|                                        | Operating                    |                         |  | 4.84  |    |  |  | 4.62  |  |  |    | 4.33  |   |    |  | 5.63  |  |  |  | 5.09  | 
|                                       
|                                        | Netback                      |                         |  | 15.34 |    |  |  | 15.08 |  |  |    | 14.99 |   |    |  | 13.16 |  |  |  | 19.15 | 
|                                       
|Crude Oil  United Kingdom ($/bbl)      |                              |                         |  |       |    |  |  |       |  |  |    |       |   |    |  |       |  |  |  |      
|                                        | Price                        |                         |  | 28.11 |    |  |  | 27.05 |  |  |    | 27.92 |   |    |  | 27.17 |  |  |  | 30.61 | 
|                                        | Production and mineral taxes |                         |  |      |    |  |  |      |  |  |    |      |   |    |  |      |  |  |  |      | 
|                                        | Transportation and selling   |                         |  | 1.97  |    |  |  | 1.70  |  |  |    | 1.98  |   |    |  | 1.86  |  |  |  | 2.45  | 
|                                        | Operating                    |                         |  | 5.09  |    |  |  | 6.23  |  |  |    | 6.55  |   |    |  | 4.69  |  |  |  | 2.92  | 
|                                       
|                                        | Netback                      |                         |  | 21.05 |    |  |  | 19.12 |  |  |    | 19.39 |   |    |  | 20.62 |  |  |  | 25.24 | 
|                                       

35



---



##### 



|                                                         |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |       | 
|-------------------------------------------------------- | ---------------------------- | ----------------------- |  | ----- | -- |  |  | ----- |  |  | -- | ----- |  | -- |  | ----- |  |  |  | ----- | 
|                                                         |                              | Per-Unit Results  2002 | 
|                                                         |                              |                         | 
|                                                         |                              | Year                    |  |       | Q4 |  |  | Q3    |  |  | Q2 |       |  | Q1 | 
|                                                         |                             
|Continuing Operations:                                   |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                        
|Produced Gas  Canada ($/Mcf)                            |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                         | Price(1)                     |                         |  | 2.86  |    |  |  | 3.60  |  |  |    | 2.29  |  |    |  | 2.93  |  |  |  | 2.25  | 
|                                                         | Production and mineral taxes |                         |  | 0.08  |    |  |  | 0.07  |  |  |    | 0.04  |  |    |  | 0.10  |  |  |  | 0.14  | 
|                                                         | Transportation and selling   |                         |  | 0.24  |    |  |  | 0.30  |  |  |    | 0.21  |  |    |  | 0.21  |  |  |  | 0.22  | 
|                                                         | Operating                    |                         |  | 0.41  |    |  |  | 0.44  |  |  |    | 0.42  |  |    |  | 0.40  |  |  |  | 0.31  | 
|                                                        
|                                                         | Netback                      |                         |  | 2.13  |    |  |  | 2.79  |  |  |    | 1.62  |  |    |  | 2.22  |  |  |  | 1.58  | 
|                                                        
|Produced Gas  United States ($/Mcf)                     |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                         | Price(1)                     |                         |  | 2.96  |    |  |  | 3.48  |  |  |    | 2.78  |  |    |  | 2.51  |  |  |  | 2.36  | 
|                                                         | Production and mineral taxes |                         |  | 0.27  |    |  |  | 0.34  |  |  |    | 0.22  |  |    |  | 0.23  |  |  |  | 0.29  | 
|                                                         | Transportation and selling   |                         |  | 0.47  |    |  |  | 0.46  |  |  |    | 0.76  |  |    |  | 0.23  |  |  |  |      | 
|                                                         | Operating                    |                         |  | 0.28  |    |  |  | 0.23  |  |  |    | 0.28  |  |    |  | 0.31  |  |  |  | 0.60  | 
|                                                        
|                                                         | Netback                      |                         |  | 1.94  |    |  |  | 2.45  |  |  |    | 1.52  |  |    |  | 1.74  |  |  |  | 1.47  | 
|                                                        
|Produced Gas  Total North America ($/Mcf)               |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                         | Price(1)                     |                         |  | 2.87  |    |  |  | 3.58  |  |  |    | 2.37  |  |    |  | 2.86  |  |  |  | 2.26  | 
|                                                         | Production and mineral taxes |                         |  | 0.11  |    |  |  | 0.12  |  |  |    | 0.08  |  |    |  | 0.12  |  |  |  | 0.15  | 
|                                                         | Transportation and selling   |                         |  | 0.28  |    |  |  | 0.33  |  |  |    | 0.31  |  |    |  | 0.22  |  |  |  | 0.21  | 
|                                                         | Operating                    |                         |  | 0.39  |    |  |  | 0.40  |  |  |    | 0.39  |  |    |  | 0.39  |  |  |  | 0.32  | 
|                                                        
|                                                         | Netback                      |                         |  | 2.09  |    |  |  | 2.73  |  |  |    | 1.59  |  |    |  | 2.13  |  |  |  | 1.58  | 
|                                                        
|Natural Gas Liquids  Canada ($/bbl)                     |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 17.55 |    |  |  | 21.75 |  |  |    | 17.61 |  |    |  | 17.41 |  |  |  | 11.56 | 
|                                                         | Production and mineral taxes |                         |  |      |    |  |  |      |  |  |    |      |  |    |  |      |  |  |  |      | 
|                                                         | Transportation and selling   |                         |  |      |    |  |  |      |  |  |    |      |  |    |  |      |  |  |  |      | 
|                                                        
|                                                         | Netback                      |                         |  | 17.55 |    |  |  | 21.75 |  |  |    | 17.61 |  |    |  | 17.41 |  |  |  | 11.56 | 
|                                                        
|Natural Gas Liquids  United States ($/bbl)              |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 23.75 |    |  |  | 25.14 |  |  |    | 25.64 |  |    |  | 23.57 |  |  |  | 16.31 | 
|                                                         | Production and mineral taxes |                         |  | 1.02  |    |  |  | 0.94  |  |  |    | 1.32  |  |    |  | 1.37  |  |  |  |      | 
|                                                         | Transportation and selling   |                         |  |      |    |  |  |      |  |  |    |      |  |    |  |      |  |  |  |      | 
|                                                        
|                                                         | Netback                      |                         |  | 22.73 |    |  |  | 24.20 |  |  |    | 24.32 |  |    |  | 22.20 |  |  |  | 16.31 | 
|                                                        
|Natural Gas Liquids  Total North America ($/bbl)        |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 19.52 |    |  |  | 23.06 |  |  |    | 19.99 |  |    |  | 19.32 |  |  |  | 12.64 | 
|                                                         | Production and mineral taxes |                         |  | 0.32  |    |  |  | 0.36  |  |  |    | 0.39  |  |    |  | 0.42  |  |  |  |      | 
|                                                         | Transportation and selling   |                         |  |      |    |  |  |      |  |  |    |      |  |    |  |      |  |  |  |      | 
|                                                        
|                                                         | Netback                      |                         |  | 19.20 |    |  |  | 22.70 |  |  |    | 19.60 |  |    |  | 18.90 |  |  |  | 12.64 | 
|                                                        
|Crude Oil  Light and Medium  North America
    ($/bbl) |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                                         | Price                        |                         |  | 22.31 |    |  |  | 24.39 |  |  |    | 24.09 |  |    |  | 23.37 |  |  |  | 17.60 | 
|                                                         | Production and mineral taxes |                         |  | 0.65  |    |  |  | 0.48  |  |  |    | 0.51  |  |    |  | 0.14  |  |  |  | 1.44  | 
|                                                         | Transportation and selling   |                         |  | 0.94  |    |  |  | 1.22  |  |  |    | 1.04  |  |    |  | 0.62  |  |  |  | 0.87  | 
|                                                         | Operating                    |                         |  | 4.80  |    |  |  | 5.15  |  |  |    | 4.72  |  |    |  | 5.29  |  |  |  | 4.08  | 
|                                                        
|                                                         | Netback                      |                         |  | 15.92 |    |  |  | 17.54 |  |  |    | 17.82 |  |    |  | 17.32 |  |  |  | 11.21 | 
|                                                        





|    |                                                                                                                                                                                                                               
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Excludes the effect of $108 million increase to
    consolidated revenues relating to the mark-to-market value of
    the AEC fixed price forward natural gas contracts recorded as
    part of the purchase price allocation.

36



---



##### 



|                                          |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |       | 
|----------------------------------------- | ---------------------------- | ----------------------- |  | ----- | -- |  |  | ----- |  |  | -- | ----- |  | -- |  | ----- |  |  |  | ----- | 
|                                          |                              | Per-Unit Results  2002 | 
|                                          |                              |                         | 
|                                          |                              | Year                    |  |       | Q4 |  |  | Q3    |  |  | Q2 |       |  | Q1 | 
|                                          |                             
|Crude Oil  Heavy  North America ($/bbl) |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          | Price                        |                         |  | 17.88 |    |  |  | 17.38 |  |  |    | 19.67 |  |    |  | 17.76 |  |  |  | 13.62 | 
|                                          | Production and mineral taxes |                         |  | 0.22  |    |  |  | 0.54  |  |  |    | 0.03  |  |    |  | 0.04  |  |  |  | 0.32  | 
|                                          | Transportation and selling   |                         |  | 0.71  |    |  |  | 0.93  |  |  |    | 0.81  |  |    |  | 0.48  |  |  |  | 0.21  | 
|                                          | Operating                    |                         |  | 4.58  |    |  |  | 4.12  |  |  |    | 4.96  |  |    |  | 4.39  |  |  |  | 5.73  | 
|                                         
|                                          | Netback                      |                         |  | 12.37 |    |  |  | 11.79 |  |  |    | 13.87 |  |    |  | 12.85 |  |  |  | 7.36  | 
|                                         
|Crude Oil  Total North America ($/bbl)   |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          | Price                        |                         |  | 20.08 |    |  |  | 20.31 |  |  |    | 21.67 |  |    |  | 20.37 |  |  |  | 16.64 | 
|                                          | Production and mineral taxes |                         |  | 0.43  |    |  |  | 0.51  |  |  |    | 0.25  |  |    |  | 0.08  |  |  |  | 1.17  | 
|                                          | Transportation and selling   |                         |  | 0.82  |    |  |  | 1.05  |  |  |    | 0.92  |  |    |  | 0.55  |  |  |  | 0.71  | 
|                                          | Operating                    |                         |  | 4.69  |    |  |  | 4.55  |  |  |    | 4.85  |  |    |  | 4.81  |  |  |  | 4.48  | 
|                                         
|                                          | Netback                      |                         |  | 14.14 |    |  |  | 14.20 |  |  |    | 15.65 |  |    |  | 14.93 |  |  |  | 10.28 | 
|                                         
|Total Liquids  Canada ($/bbl)            |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          | Price                        |                         |  | 19.82 |    |  |  | 20.46 |  |  |    | 21.27 |  |    |  | 20.07 |  |  |  | 16.01 | 
|                                          | Production and mineral taxes |                         |  | 0.39  |    |  |  | 0.46  |  |  |    | 0.22  |  |    |  | 0.08  |  |  |  | 1.03  | 
|                                          | Transportation and selling   |                         |  | 0.73  |    |  |  | 0.94  |  |  |    | 0.83  |  |    |  | 0.49  |  |  |  | 0.63  | 
|                                          | Operating                    |                         |  | 4.19  |    |  |  | 4.06  |  |  |    | 4.38  |  |    |  | 4.32  |  |  |  | 3.93  | 
|                                         
|                                          | Netback                      |                         |  | 14.51 |    |  |  | 15.00 |  |  |    | 15.84 |  |    |  | 15.18 |  |  |  | 10.42 | 
|                                         
|Total Liquids  North America ($/bbl)     |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          | Price                        |                         |  | 20.00 |    |  |  | 20.76 |  |  |    | 21.44 |  |    |  | 20.22 |  |  |  | 16.03 | 
|                                          | Production and mineral taxes |                         |  | 0.42  |    |  |  | 0.49  |  |  |    | 0.27  |  |    |  | 0.13  |  |  |  | 0.99  | 
|                                          | Transportation and selling   |                         |  | 0.70  |    |  |  | 0.88  |  |  |    | 0.79  |  |    |  | 0.47  |  |  |  | 0.60  | 
|                                          | Operating                    |                         |  | 4.00  |    |  |  | 3.80  |  |  |    | 4.20  |  |    |  | 4.14  |  |  |  | 3.79  | 
|                                         
|                                          | Netback                      |                         |  | 14.88 |    |  |  | 15.59 |  |  |    | 16.18 |  |    |  | 15.48 |  |  |  | 10.65 | 
|                                         
|Total North America ($/Mcfe)              |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          | Price                        |                         |  | 3.01  |    |  |  | 3.55  |  |  |    | 2.71  |  |    |  | 3.01  |  |  |  | 2.41  | 
|                                          | Production and mineral taxes |                         |  | 0.10  |    |  |  | 0.11  |  |  |    | 0.07  |  |    |  | 0.10  |  |  |  | 0.15  | 
|                                          | Transportation and selling   |                         |  | 0.23  |    |  |  | 0.28  |  |  |    | 0.26  |  |    |  | 0.18  |  |  |  | 0.17  | 
|                                          | Operating                    |                         |  | 0.47  |    |  |  | 0.46  |  |  |    | 0.48  |  |    |  | 0.47  |  |  |  | 0.43  | 
|                                         
|                                          | Netback                      |                         |  | 2.21  |    |  |  | 2.70  |  |  |    | 1.90  |  |    |  | 2.26  |  |  |  | 1.66  | 
|                                         
|Discontinued Operations:                  |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                         
|Crude Oil  Ecuador ($/bbl)               |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          | Price                        |                         |  | 22.57 |    |  |  | 24.02 |  |  |    | 22.82 |  |    |  | 21.11 |  |  |  |      | 
|                                          | Production and mineral taxes |                         |  | 1.24  |    |  |  | 1.57  |  |  |    | 1.49  |  |    |  | 0.72  |  |  |  |      | 
|                                          | Transportation and selling   |                         |  | 2.00  |    |  |  | 1.99  |  |  |    | 2.47  |  |    |  | 1.56  |  |  |  |      | 
|                                          | Operating                    |                         |  | 4.86  |    |  |  | 5.35  |  |  |    | 4.12  |  |    |  | 5.13  |  |  |  |      | 
|                                         
|                                          | Netback                      |                         |  | 14.47 |    |  |  | 15.11 |  |  |    | 14.74 |  |    |  | 13.70 |  |  |  |      | 
|                                         
|Crude Oil  United Kingdom ($/bbl)        |                              |                         |  |       |    |  |  |       |  |  |    |       |  |    |  |       |  |  |  |      
|                                          | Price                        |                         |  | 24.76 |    |  |  | 25.73 |  |  |    | 27.07 |  |    |  | 25.92 |  |  |  | 21.18 | 
|                                          | Production and mineral taxes |                         |  |      |    |  |  |      |  |  |    |      |  |    |  |      |  |  |  |      | 
|                                          | Transportation and selling   |                         |  | 1.69  |    |  |  | 1.53  |  |  |    | 1.92  |  |    |  | 1.62  |  |  |  | 1.65  | 
|                                          | Operating                    |                         |  | 3.28  |    |  |  | 7.07  |  |  |    | 3.65  |  |    |  | 2.01  |  |  |  | 1.78  | 
|                                         
|                                          | Netback                      |                         |  | 19.79 |    |  |  | 17.13 |  |  |    | 21.50 |  |    |  | 22.29 |  |  |  | 17.75 | 
|                                         

37



---



##### 





|                                   |  |      |       |   |    |  |        |    |  |  |        |   |  |    |       |   |  |  |       |  
|---------------------------------- |  | ---- | ----- | - | -- |  | ------ | -- |  |  | ------ | - |  | -- | ----- | - |  |  | ----- | -
|                                   |  | 2004 |      
|                                   |  |      |      
|                                   |  | Year |       |   | Q4 |  |        | Q3 |  |  | Q2     |   |  | Q1 |      
|                                   | 
|Continuing Operations:             |  |      |       |   |    |  |        |    |  |  |        |   |  |    |       |   |  |  |       |  
|                                  
|Natural Gas ($/Mcf)                |  |      | (0.22 | ) |    |  | (0.37  | )  |  |  | (0.15  | ) |  |    | (0.25 | ) |  |  | (0.08 | )
|Liquids ($/bbl)                    |  |      | (7.08 | ) |    |  | (8.24  | )  |  |  | (8.75  | ) |  |    | (6.53 | ) |  |  | (4.79 | )
|Total ($/Mcfe)                     |  |      | (0.46 | ) |    |  | (0.61  | )  |  |  | (0.48  | ) |  |    | (0.47 | ) |  |  | (0.27 | )
|                                  
|Discontinued Operations:           |  |      |       |   |    |  |        |    |  |  |        |   |  |    |       |   |  |  |       |  
|                                  
|Ecuador Oil ($/bbl)                |  |      | (9.66 | ) |    |  | (14.60 | )  |  |  | (10.31 | ) |  |    | (7.13 | ) |  |  | (6.69 | )
|United Kingdom Oil
    ($/bbl) (1) |  |      | (7.62 | ) |    |  | (6.34  | )  |  |  | (11.75 | ) |  |    | (7.01 | ) |  |  | (5.72 | )
|                                  

|                           |  |      |       |   |    |  |       |    |  |  |       |   |  |    |       |   |  |  |       |  
|-------------------------- |  | ---- | ----- | - | -- |  | ----- | -- |  |  | ----- | - |  | -- | ----- | - |  |  | ----- | -
|                           |  | 2003 |      
|                           |  |      |      
|                           |  | Year |       |   | Q4 |  |       | Q3 |  |  | Q2    |   |  | Q1 |      
|                           | 
|Continuing Operations:     |  |      |       |   |    |  |       |    |  |  |       |   |  |    |       |   |  |  |       |  
|                          
|Natural Gas ($/Mcf)        |  |      | (0.10 | ) |    |  | 0.16  |    |  |  | (0.06 | ) |  |    | (0.25 | ) |  |  | (0.25 | )
|Liquids ($/bbl)            |  |      | (3.41 | ) |    |  | (3.29 | )  |  |  | (2.76 | ) |  |    | (2.08 | ) |  |  | (5.64 | )
|Total ($/Mcfe)             |  |      | (0.23 | ) |    |  | (0.04 | )  |  |  | (0.18 | ) |  |    | (0.28 | ) |  |  | (0.44 | )
|                          
|Discontinued Operations:   |  |      |       |   |    |  |       |    |  |  |       |   |  |    |       |   |  |  |       |  
|                          
|Ecuador Oil ($/bbl)        |  |      |      |   |    |  |      |    |  |  |      |   |  |    |      |   |  |  |      |  
|United Kingdom Oil ($/bbl) |  |      |      |   |    |  |      |    |  |  |      |   |  |    |      |   |  |  |      |  
|                          

|                           |  |      |       |   |    |  |       |    |  |  |       |   |  |    |       |   |  |  |       |  
|-------------------------- |  | ---- | ----- | - | -- |  | ----- | -- |  |  | ----- | - |  | -- | ----- | - |  |  | ----- | -
|                           |  | 2002 |      
|                           |  |      |      
|                           |  | Year |       |   | Q4 |  |       | Q3 |  |  | Q2    |   |  | Q1 |      
|                           | 
|Continuing Operations:     |  |      |       |   |    |  |       |    |  |  |       |   |  |    |       |   |  |  |       |  
|                          
|Natural Gas ($/Mcf)        |  |      | 0.09  |   |    |  | 0.02  |    |  |  | 0.26  |   |  |    | (0.06 | ) |  |  | 0.20  |  
|Liquids ($/bbl)            |  |      | (0.64 | ) |    |  | (0.73 | )  |  |  | (0.56 | ) |  |    | (0.72 | ) |  |  | (0.53 | )
|Total ($/Mcfe)             |  |      | 0.03  |   |    |  | (0.02 | )  |  |  | 0.16  |   |  |    | (0.08 | ) |  |  | 0.10  |  
|                          
|Discontinued Operations:   |  |      |       |   |    |  |       |    |  |  |       |   |  |    |       |   |  |  |       |  
|                          
|Ecuador Oil ($/bbl)        |  |      | (0.01 | ) |    |  |      |    |  |  |      |   |  |    | (0.03 | ) |  |  |      |  
|United Kingdom Oil ($/bbl) |  |      | (0.06 | ) |    |  |      |    |  |  |      |   |  |    |      |   |  |  | (0.19 | )
|                          





|    |                                                             
|--- | ------------------------------------------------------------
|(1) | Excludes hedges unwound as a result of the U.K. disposition.

38



---



##### 






Drilling Activity




Exploration Wells Drilled


|                         |               |       |     |     |     |     |     |             |               |  |          |    |  |         |    |    |       |  |    |       |  |  |     |    |  |       |     |     |       |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     | 
|------------------------ | ------------- | ----- | --- | --- | --- | --- | --- | ----------- | ------------- |  | -------- | -- |  | ------- | -- | -- | ----- |  | -- | ----- |  |  | --- | -- |  | ----- | --- | --- | ----- |  | --- | --- |  |  | --- | --- |  |  | --- | --- |  |  | --- | --- | 
|                         |               |       |     |     |     | Dry |     |             | Total Working |  |          |    |  |        
|                         |               | Gas   |     |     | Oil |     |     | & Abandoned |               |  | Interest |    |  | Royalty |    |    | Total | 
|                         |               |       |     |     |     |     |     |             |               |  |          |    |  |         |    |    |       | 
|                         |               | Gross |     |     | Net |     |     | Gross       |               |  | Net      |    |  | Gross   |    |    | Net   |  |    | Gross |  |  | Net |    |  | Gross |     |     | Gross |  |     | Net | 
|                         |              
|Continuing Operations:   |               |       |     |     |     |     |     |             |               |  |          |    |  |         |    |    |       |  |    |       |  |  |     |    |  |       |     |     |       |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|                        
|2004:                    |               |       |     |     |     |     |     |             |               |  |          |    |  |         |    |    |       |  |    |       |  |  |     |    |  |       |     |     |       |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|                         | Canada        |       |     | 566 |     |     |     | 534         |               |  |          | 48 |  |         |    | 47 |       |  |    | 9     |  |  |     | 6  |  |       |     | 623 |       |  |     | 587 |  |  |     | 51  |  |  |     | 674 |  |  |     | 587 | 
|                         | United States |       |     | 19  |     |     |     | 16          |               |  |          | 2  |  |         |    |   |       |  |    |      |  |  |     |   |  |       |     | 21  |       |  |     | 16  |  |  |     |    |  |  |     | 21  |  |  |     | 16  | 
|                         | Other         |       |     |    |     |     |     |            |               |  |          | 3  |  |         |    | 2  |       |  |    | 5     |  |  |     | 2  |  |       |     | 8   |       |  |     | 4   |  |  |     |    |  |  |     | 8   |  |  |     | 4   | 
|                        
|Total                    |               |       | 585 |     |     |     | 550 |             |               |  | 53       |    |  |         | 49 |    |       |  | 14 |       |  |  | 8   |    |  |       | 652 |     |       |  | 607 |     |  |  | 51  |     |  |  | 703 |     |  |  | 607 |    
|                        
|2003:                    |               |       |     |     |     |     |     |             |               |  |          |    |  |         |    |    |       |  |    |       |  |  |     |    |  |       |     |     |       |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|                         | Canada        |       |     | 532 |     |     |     | 511         |               |  |          | 51 |  |         |    | 31 |       |  |    | 35    |  |  |     | 28 |  |       |     | 618 |       |  |     | 570 |  |  |     | 153 |  |  |     | 771 |  |  |     | 570 | 
|                         | United States |       |     | 40  |     |     |     | 35          |               |  |          | 7  |  |         |    | 2  |       |  |    | 4     |  |  |     | 2  |  |       |     | 51  |       |  |     | 39  |  |  |     |    |  |  |     | 51  |  |  |     | 39  | 
|                         | Other         |       |     | 1   |     |     |     |            |               |  |          |   |  |         |    |   |       |  |    | 3     |  |  |     | 1  |  |       |     | 4   |       |  |     | 1   |  |  |     |    |  |  |     | 4   |  |  |     | 1   | 
|                        
|Total                    |               |       | 573 |     |     |     | 546 |             |               |  | 58       |    |  |         | 33 |    |       |  | 42 |       |  |  | 31  |    |  |       | 673 |     |       |  | 610 |     |  |  | 153 |     |  |  | 826 |     |  |  | 610 |    
|                        
|2002:                    |               |       |     |     |     |     |     |             |               |  |          |    |  |         |    |    |       |  |    |       |  |  |     |    |  |       |     |     |       |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|                         | Canada        |       |     | 423 |     |     |     | 382         |               |  |          | 84 |  |         |    | 72 |       |  |    | 44    |  |  |     | 37 |  |       |     | 551 |       |  |     | 491 |  |  |     | 190 |  |  |     | 741 |  |  |     | 491 | 
|                         | United States |       |     | 12  |     |     |     | 12          |               |  |          | 2  |  |         |    | 1  |       |  |    | 3     |  |  |     | 1  |  |       |     | 17  |       |  |     | 14  |  |  |     |    |  |  |     | 17  |  |  |     | 14  | 
|                         | Other         |       |     |    |     |     |     |            |               |  |          |   |  |         |    |   |       |  |    | 4     |  |  |     | 2  |  |       |     | 4   |       |  |     | 2   |  |  |     |    |  |  |     | 4   |  |  |     | 2   | 
|                        
|Total                    |               |       | 435 |     |     |     | 394 |             |               |  | 86       |    |  |         | 73 |    |       |  | 51 |       |  |  | 40  |    |  |       | 572 |     |       |  | 507 |     |  |  | 190 |     |  |  | 762 |     |  |  | 507 |    
|                        
|                        
|Discontinued Operations: |               |       |     |     |     |     |     |             |               |  |          |    |  |         |    |    |       |  |    |       |  |  |     |    |  |       |     |     |       |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|                        
|Ecuador  2004           |               |       |    |     |     |     |    |             |               |  | 6        |    |  |         | 3  |    |       |  |   |       |  |  |    |    |  |       | 6   |     |       |  | 3   |     |  |  |    |     |  |  | 6   |     |  |  | 3   |    
|Ecuador  2003           |               |       |    |     |     |     |    |             |               |  | 3        |    |  |         | 2  |    |       |  |   |       |  |  |    |    |  |       | 3   |     |       |  | 2   |     |  |  |    |     |  |  | 3   |     |  |  | 2   |    
|Ecuador  2002           |               |       |    |     |     |     |    |             |               |  | 7        |    |  |         | 5  |    |       |  |   |       |  |  |    |    |  |       | 7   |     |       |  | 5   |     |  |  |    |     |  |  | 7   |     |  |  | 5   |    
|                        
|United Kingdom  2004    |               |       |    |     |     |     |    |             |               |  | 1        |    |  |         |   |    |       |  | 4  |       |  |  | 2   |    |  |       | 5   |     |       |  | 2   |     |  |  |    |     |  |  | 5   |     |  |  | 2   |    
|United Kingdom  2003    |               |       |    |     |     |     |    |             |               |  | 2        |    |  |         | 1  |    |       |  | 5  |       |  |  | 3   |    |  |       | 7   |     |       |  | 4   |     |  |  |    |     |  |  | 7   |     |  |  | 4   |    
|United Kingdom  2002    |               |       |    |     |     |     |    |             |               |  | 7        |    |  |         | 3  |    |       |  | 2  |       |  |  | 1   |    |  |       | 9   |     |       |  | 4   |     |  |  |    |     |  |  | 9   |     |  |  | 4   |    
|                        

39



---



##### 



Development Wells Drilled


|                         |               |       |       |       |     |     |       |             |               |  |          |     |  |         |     |     |       |  |    |       |  |  |     |    |  |       |       |       |       |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       | 
|------------------------ | ------------- | ----- | ----- | ----- | --- | --- | ----- | ----------- | ------------- |  | -------- | --- |  | ------- | --- | --- | ----- |  | -- | ----- |  |  | --- | -- |  | ----- | ----- | ----- | ----- |  | ----- | ----- |  |  | ----- | ----- |  |  | ----- | ----- |  |  | ----- | ----- | 
|                         |               |       |       |       |     | Dry |       |             | Total Working |  |          |     |  |        
|                         |               | Gas   |       |       | Oil |     |       | & Abandoned |               |  | Interest |     |  | Royalty |     |     | Total | 
|                         |               |       |       |       |     |     |       |             |               |  |          |     |  |         |     |     |       | 
|                         |               | Gross |       |       | Net |     |       | Gross       |               |  | Net      |     |  | Gross   |     |     | Net   |  |    | Gross |  |  | Net |    |  | Gross |       |       | Gross |  |       | Net   | 
|                         |              
|Continuing Operations:   |               |       |       |       |     |     |       |             |               |  |          |     |  |         |     |     |       |  |    |       |  |  |     |    |  |       |       |       |       |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|                        
|2004:                    |               |       |       |       |     |     |       |             |               |  |          |     |  |         |     |     |       |  |    |       |  |  |     |    |  |       |       |       |       |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|                         | Canada        |       |       | 3,632 |     |     |       | 3,419       |               |  |          | 386 |  |         |     | 364 |       |  |    | 16    |  |  |     | 15 |  |       |       | 4,034 |       |  |       | 3,798 |  |  |       | 1,105 |  |  |       | 5,139 |  |  |       | 3,798 | 
|                         | United States |       |       | 600   |     |     |       | 515         |               |  |          | 1   |  |         |     |    |       |  |    | 3     |  |  |     | 3  |  |       |       | 604   |       |  |       | 518   |  |  |       |      |  |  |       | 604   |  |  |       | 518   | 
|                        
|Total                    |               |       | 4,232 |       |     |     | 3,934 |             |               |  | 387      |     |  |         | 364 |     |       |  | 19 |       |  |  | 18  |    |  |       | 4,638 |       |       |  | 4,316 |       |  |  | 1,105 |       |  |  | 5,743 |       |  |  | 4,316 |      
|                        
|2003:                    |               |       |       |       |     |     |       |             |               |  |          |     |  |         |     |     |       |  |    |       |  |  |     |    |  |       |       |       |       |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|                         | Canada        |       |       | 3,964 |     |     |       | 3,901       |               |  |          | 756 |  |         |     | 650 |       |  |    | 24    |  |  |     | 18 |  |       |       | 4,744 |       |  |       | 4,569 |  |  |       | 1,347 |  |  |       | 6,091 |  |  |       | 4,569 | 
|                         | United States |       |       | 426   |     |     |       | 401         |               |  |          |    |  |         |     |    |       |  |    | 1     |  |  |     | 1  |  |       |       | 427   |       |  |       | 402   |  |  |       |      |  |  |       | 427   |  |  |       | 402   | 
|                        
|Total                    |               |       | 4,390 |       |     |     | 4,302 |             |               |  | 756      |     |  |         | 650 |     |       |  | 25 |       |  |  | 19  |    |  |       | 5,171 |       |       |  | 4,971 |       |  |  | 1,347 |       |  |  | 6,518 |       |  |  | 4,971 |      
|                        
|2002:                    |               |       |       |       |     |     |       |             |               |  |          |     |  |         |     |     |       |  |    |       |  |  |     |    |  |       |       |       |       |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|                         | Canada        |       |       | 1,397 |     |     |       | 1,340       |               |  |          | 433 |  |         |     | 349 |       |  |    | 30    |  |  |     | 23 |  |       |       | 1,860 |       |  |       | 1,712 |  |  |       | 690   |  |  |       | 2,550 |  |  |       | 1,712 | 
|                         | United States |       |       | 287   |     |     |       | 250         |               |  |          | 3   |  |         |     | 3   |       |  |    | 1     |  |  |     | 1  |  |       |       | 291   |       |  |       | 254   |  |  |       |      |  |  |       | 291   |  |  |       | 254   | 
|                        
|Total                    |               |       | 1,684 |       |     |     | 1,590 |             |               |  | 436      |     |  |         | 352 |     |       |  | 31 |       |  |  | 24  |    |  |       | 2,151 |       |       |  | 1,966 |       |  |  | 690   |       |  |  | 2,841 |       |  |  | 1,966 |      
|                        
|                        
|Discontinued Operations: |               |       |       |       |     |     |       |             |               |  |          |     |  |         |     |     |       |  |    |       |  |  |     |    |  |       |       |       |       |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|                        
|Ecuador  2004           |               |       |      |       |     |     |      |             |               |  | 43       |     |  |         | 25  |     |       |  | 1  |       |  |  | 1   |    |  |       | 44    |       |       |  | 26    |       |  |  |      |       |  |  | 44    |       |  |  | 26    |      
|Ecuador  2003           |               |       |      |       |     |     |      |             |               |  | 53       |     |  |         | 39  |     |       |  | 6  |       |  |  | 6   |    |  |       | 59    |       |       |  | 45    |       |  |  |      |       |  |  | 59    |       |  |  | 45    |      
|Ecuador  2002           |               |       |      |       |     |     |      |             |               |  | 44       |     |  |         | 37  |     |       |  | 5  |       |  |  | 4   |    |  |       | 49    |       |       |  | 41    |       |  |  |      |       |  |  | 49    |       |  |  | 41    |      
|                        
|United Kingdom  2004    |               |       |      |       |     |     |      |             |               |  | 3        |     |  |         | 1   |     |       |  |   |       |  |  |    |    |  |       | 3     |       |       |  | 1     |       |  |  |      |       |  |  | 3     |       |  |  | 1     |      
|United Kingdom  2003    |               |       |      |       |     |     |      |             |               |  | 3        |     |  |         |    |     |       |  |   |       |  |  |    |    |  |       | 3     |       |       |  |      |       |  |  |      |       |  |  | 3     |       |  |  |      |      
|United Kingdom  2002    |               |       |      |       |     |     |      |             |               |  | 2        |     |  |         |    |     |       |  |   |       |  |  |    |    |  |       | 2     |       |       |  |      |       |  |  |      |       |  |  | 2     |       |  |  |      |      
|                        





|    |                                                                                                                                                                                                                                             
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Gross wells are the total number of wells in which
    EnCana has an interest.                                                                                                                                                            
|   
|(2) | Net wells are the number of wells obtained by
    aggregating EnCanas working interest in each of its gross
    wells.                                                                                                                   
|   
|(3) | At December 31, 2004, EnCana was in the process of drilling
    33 gross wells (32 net wells) in Canada, 50 gross wells (45 net
    wells) in the United States, 4 gross wells (2 net wells) in
    Ecuador and no wells in other countries.

40



---



##### 






Location of Wells




|                         |                  |       |        |        |     |  |        |        |  |  |       |       |  |       |       |       |     |  |        |        |  |  |        |        | 
|------------------------ | ---------------- | ----- | ------ | ------ | --- |  | ------ | ------ |  |  | ----- | ----- |  | ----- | ----- | ----- | --- |  | ------ | ------ |  |  | ------ | ------ | 
|                         |                  | Gas   |        |        | Oil |  |        | Total  | 
|                         |                  |       |        |        |     |  |        |        | 
|                         |                  | Gross |        |        | Net |  |        | Gross  |  |  | Net   |       |  | Gross |       |       | Net | 
|                         |                 
|Continuing Operations:   |                  |       |        |        |     |  |        |        |  |  |       |       |  |       |       |       |     |  |        |        |  |  |        |       
|                        
|                         | Alberta          |       |        | 29,790 |     |  |        | 27,943 |  |  |       | 4,700 |  |       |       | 4,151 |     |  |        | 34,490 |  |  |        | 32,094 | 
|                         | British Columbia |       |        | 1,329  |     |  |        | 1,196  |  |  |       | 16    |  |       |       | 10    |     |  |        | 1,345  |  |  |        | 1,206  | 
|                         | Saskatchewan     |       |        | 336    |     |  |        | 332    |  |  |       | 1,177 |  |       |       | 515   |     |  |        | 1,513  |  |  |        | 847    | 
|                         | Manitoba         |       |        |       |     |  |        |       |  |  |       | 3     |  |       |       | 3     |     |  |        | 3      |  |  |        | 3      | 
|                        
|Total Canada             |                  |       | 31,455 |        |     |  | 29,471 |        |  |  | 5,896 |       |  |       | 4,679 |       |     |  | 37,351 |        |  |  | 34,150 |       
|                        
|                         | Colorado         |       |        | 3,902  |     |  |        | 3,155  |  |  |       |      |  |       |       |      |     |  |        | 3,902  |  |  |        | 3,155  | 
|                         | Texas            |       |        | 1,179  |     |  |        | 762    |  |  |       | 30    |  |       |       | 12    |     |  |        | 1,209  |  |  |        | 774    | 
|                         | Wyoming          |       |        | 1,493  |     |  |        | 874    |  |  |       |      |  |       |       |      |     |  |        | 1,493  |  |  |        | 874    | 
|                         | Montana          |       |        | 42     |     |  |        | 37     |  |  |       |      |  |       |       |      |     |  |        | 42     |  |  |        | 37     | 
|                         | Utah             |       |        | 33     |     |  |        | 32     |  |  |       |      |  |       |       |      |     |  |        | 33     |  |  |        | 32     | 
|                         | Oklahoma         |       |        | 47     |     |  |        | 12     |  |  |       |      |  |       |       |      |     |  |        | 47     |  |  |        | 12     | 
|                         | Louisiana        |       |        | 4      |     |  |        | 2      |  |  |       |      |  |       |       |      |     |  |        | 4      |  |  |        | 2      | 
|                         | Gulf of Mexico   |       |        |       |     |  |        |       |  |  |       | 6     |  |       |       | 1     |     |  |        | 6      |  |  |        | 1      | 
|                        
|Total United States      |                  |       | 6,700  |        |     |  | 4,874  |        |  |  | 36    |       |  |       | 13    |       |     |  | 6,736  |        |  |  | 4,887  |       
|                        
|Total                    |                  |       | 38,155 |        |     |  | 34,345 |        |  |  | 5,932 |       |  |       | 4,692 |       |     |  | 44,087 |        |  |  | 39,037 |       
|                        
|Discontinued Operations: |                  |       |        |        |     |  |        |        |  |  |       |       |  |       |       |       |     |  |        |        |  |  |        |       
|                        
|Ecuador                  |                  |       |       |        |     |  |       |        |  |  | 289   |       |  |       | 227   |       |     |  | 289    |        |  |  | 227    |       
|                        





|    |                                                                                                                                                                        
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | EnCana has varying royalty interests in 8,396 crude oil wells
    and 12,970 natural gas wells which are producing or capable of
    producing.                        
|   
|(2) | Includes wells containing multiple completions as follows:
    26,879 gross natural gas wells (24,441 net wells) and 1,681
    gross crude oil wells (1,393 net wells).

41



---



##### 






Interest in Material Properties




|                       |                         |                      |            |           |  |  |             |       |  |       |       |       |     |  |        |       |  |  |        |       |  |  |        |       |  |  |        |       | 
|---------------------- | ----------------------- | -------------------- | ---------- | --------- |  |  | ----------- | ----- |  | ----- | ----- | ----- | --- |  | ------ | ----- |  |  | ------ | ----- |  |  | ------ | ----- |  |  | ------ | ----- | 
|                       |                         |                      |            | Developed |  |  | Undeveloped |       |  | Total |      
|                       |                         |                      |            |           |  |  |             |       |  |       |      
|                       |                         |                      |            | Gross     |  |  | Net         |       |  | Gross |       |       | Net |  |        | Gross |  |  | Net    |      
|                       |                        
|                       |                         | (thousands of acres) |           
|Continuing Operations: |                         |                      |            |           |  |  |             |       |  |       |       |       |     |  |        |       |  |  |        |       |  |  |        |      
|                      
|Canada                 |                         |                      |            |           |  |  |             |       |  |       |       |       |     |  |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|                       | Alberta                 |                      |            |  Fee     |  |  |             | 4,319 |  |       |       | 4,319 |     |  |        | 2,835 |  |  |        | 2,835 |  |  |        | 7,154 |  |  |        | 7,154 | 
|                       |                         |                      |  Crown    |           |  |  | 3,709       |       |  |       | 2,989 |       |     |  | 6,643  |       |  |  | 5,578  |       |  |  | 10,352 |       |  |  | 8,567  |      
|                       |                         |                      |  Freehold |           |  |  | 185         |       |  |       | 101   |       |     |  | 245    |       |  |  | 192    |       |  |  | 430    |       |  |  | 293    |      
|                      
|                       |                         |                      |            |           |  |  | 8,213       |       |  |       | 7,409 |       |     |  | 9,723  |       |  |  | 8,605  |       |  |  | 17,936 |       |  |  | 16,014 |      
|                      
|                       | British Columbia        |                      |            |  Crown   |  |  |             | 697   |  |       |       | 579   |     |  |        | 4,174 |  |  |        | 3,601 |  |  |        | 4,871 |  |  |        | 4,180 | 
|                       |                         |                      |  Freehold |           |  |  |            |       |  |       |      |       |     |  | 7      |       |  |  | 7      |       |  |  | 7      |       |  |  | 7      |      
|                      
|                       |                         |                      |            |           |  |  | 697         |       |  |       | 579   |       |     |  | 4,181  |       |  |  | 3,608  |       |  |  | 4,878  |       |  |  | 4,187  |      
|                      
|                       | Saskatchewan            |                      |            |  Fee     |  |  |             | 57    |  |       |       | 57    |     |  |        | 461   |  |  |        | 461   |  |  |        | 518   |  |  |        | 518   | 
|                       |                         |                      |  Crown    |           |  |  | 115         |       |  |       | 96    |       |     |  | 1,064  |       |  |  | 1,049  |       |  |  | 1,179  |       |  |  | 1,145  |      
|                       |                         |                      |  Freehold |           |  |  | 13          |       |  |       | 9     |       |     |  | 104    |       |  |  | 97     |       |  |  | 117    |       |  |  | 106    |      
|                      
|                       |                         |                      |            |           |  |  | 185         |       |  |       | 162   |       |     |  | 1,629  |       |  |  | 1,607  |       |  |  | 1,814  |       |  |  | 1,769  |      
|                      
|                       | Manitoba                |                      |            |  Fee     |  |  |             | 3     |  |       |       | 3     |     |  |        | 265   |  |  |        | 265   |  |  |        | 268   |  |  |        | 268   | 
|                       |                         |                      |  Freehold |           |  |  |            |       |  |       |      |       |     |  | 23     |       |  |  | 23     |       |  |  | 23     |       |  |  | 23     |      
|                      
|                       |                         |                      |            |           |  |  | 3           |       |  |       | 3     |       |     |  | 288    |       |  |  | 288    |       |  |  | 291    |       |  |  | 291    |      
|                      
|                       | Newfoundland & Labrador |                      |            |  Crown   |  |  |             |      |  |       |       |      |     |  |        | 4,027 |  |  |        | 2,514 |  |  |        | 4,027 |  |  |        | 2,514 | 
|                       | Nova Scotia             |                      |            |  Crown   |  |  |             |      |  |       |       |      |     |  |        | 1,834 |  |  |        | 1,043 |  |  |        | 1,834 |  |  |        | 1,043 | 
|                       | Northwest Territories   |                      |            |  Crown   |  |  |             |      |  |       |       |      |     |  |        | 633   |  |  |        | 234   |  |  |        | 633   |  |  |        | 234   | 
|                       | Nunavut                 |                      |            |  Crown   |  |  |             |      |  |       |       |      |     |  |        | 817   |  |  |        | 26    |  |  |        | 817   |  |  |        | 26    | 
|                       | Beaufort                |                      |            |  Crown   |  |  |             |      |  |       |       |      |     |  |        | 126   |  |  |        | 4     |  |  |        | 126   |  |  |        | 4     | 
|                      
|Total Canada           |                         |                      |            |           |  |  | 9,098       |       |  |       | 8,153 |       |     |  | 23,258 |       |  |  | 17,929 |       |  |  | 32,356 |       |  |  | 26,082 |      
|                      

42



---



##### 



|                         |                |                      |                            |                        |  |  |             |     |  |       |       |     |     |  |         |         |  |  |        |        |  |  |         |         |  |  |        |        | 
|------------------------ | -------------- | -------------------- | -------------------------- | ---------------------- |  |  | ----------- | --- |  | ----- | ----- | --- | --- |  | ------- | ------- |  |  | ------ | ------ |  |  | ------- | ------- |  |  | ------ | ------ | 
|                         |                |                      |                            | Developed              |  |  | Undeveloped |     |  | Total |      
|                         |                |                      |                            |                        |  |  |             |     |  |       |      
|                         |                |                      |                            | Gross                  |  |  | Net         |     |  | Gross |       |     | Net |  |         | Gross   |  |  | Net    |       
|                         |               
|                         |                | (thousands of acres) |                           
|United States            |                |                      |                            |                        |  |  |             |     |  |       |       |     |     |  |         |         |  |  |        |        |  |  |         |         |  |  |        |       
|                         | Colorado       |                      |                            |  Federal/ State Lands |  |  |             | 208 |  |       |       | 180 |     |  |         | 821     |  |  |        | 745    |  |  |         | 1,029   |  |  |        | 925    | 
|                         |                |                      |  Freehold                 |                        |  |  | 112         |     |  |       | 102   |     |     |  | 212     |         |  |  | 191    |        |  |  | 324     |         |  |  | 293    |       
|                         |                |                      |  Fee                      |                        |  |  | 3           |     |  |       | 3     |     |     |  | 60      |         |  |  | 60     |        |  |  | 63      |         |  |  | 63     |       
|                        
|                         |                |                      |                            |                        |  |  | 323         |     |  |       | 285   |     |     |  | 1,093   |         |  |  | 996    |        |  |  | 1,416   |         |  |  | 1,281  |       
|                        
|                         | Washington     |                      |                            |  Federal/ State Lands |  |  |             |    |  |       |       |    |     |  |         | 459     |  |  |        | 456    |  |  |         | 459     |  |  |        | 456    | 
|                         |                |                      |  Freehold                 |                        |  |  |            |     |  |       |      |     |     |  | 199     |         |  |  | 199    |        |  |  | 199     |         |  |  | 199    |       
|                         |                |                      |  Federal Acquired Lease   |                        |  |  |            |     |  |       |      |     |     |  | 219     |         |  |  | 213    |        |  |  | 219     |         |  |  | 213    |       
|                        
|                         |                |                      |                            |                        |  |  |            |     |  |       |      |     |     |  | 877     |         |  |  | 868    |        |  |  | 877     |         |  |  | 868    |       
|                        
|                         | Texas          |                      |                            |  Federal/ State Lands |  |  |             | 8   |  |       |       | 3   |     |  |         | 205     |  |  |        | 204    |  |  |         | 213     |  |  |        | 207    | 
|                         |                |                      |  Freehold                 |                        |  |  | 161         |     |  |       | 97    |     |     |  | 431     |         |  |  | 395    |        |  |  | 592     |         |  |  | 492    |       
|                        
|                         |                |                      |                            |                        |  |  | 169         |     |  |       | 100   |     |     |  | 636     |         |  |  | 599    |        |  |  | 805     |         |  |  | 699    |       
|                        
|                         | Wyoming        |                      |                            |  Federal/ State Lands |  |  |             | 148 |  |       |       | 73  |     |  |         | 729     |  |  |        | 490    |  |  |         | 877     |  |  |        | 563    | 
|                         |                |                      |  Freehold                 |                        |  |  | 26          |     |  |       | 18    |     |     |  | 81      |         |  |  | 46     |        |  |  | 107     |         |  |  | 64     |       
|                         |                |                      |  Bureau of Indian Affairs |                        |  |  | 11          |     |  |       | 10    |     |     |  | 5       |         |  |  | 4      |        |  |  | 16      |         |  |  | 14     |       
|                        
|                         |                |                      |                            |                        |  |  | 185         |     |  |       | 101   |     |     |  | 815     |         |  |  | 540    |        |  |  | 1,000   |         |  |  | 641    |       
|                        
|                         | Gulf of Mexico |                      |                            |  Federal/ State Lands |  |  |             |    |  |       |       |    |     |  |         | 1,371   |  |  |        | 557    |  |  |         | 1,371   |  |  |        | 557    | 
|                        
|                         | Alaska         |                      |                            |  Federal/ State Lands |  |  |             |    |  |       |       |    |     |  |         | 1,337   |  |  |        | 531    |  |  |         | 1,337   |  |  |        | 531    | 
|                        
|                         | Other          |                      |                            |  Federal Lands        |  |  |             | 11  |  |       |       | 10  |     |  |         | 374     |  |  |        | 236    |  |  |         | 385     |  |  |        | 246    | 
|                         |                |                      |  Freehold                 |                        |  |  | 19          |     |  |       | 10    |     |     |  | 22      |         |  |  | 13     |        |  |  | 41      |         |  |  | 23     |       
|                         |                |                      |  Fee                      |                        |  |  | 1           |     |  |       | 1     |     |     |  |        |         |  |  |       |        |  |  | 1       |         |  |  | 1      |       
|                        
|                         |                |                      |                            |                        |  |  | 31          |     |  |       | 21    |     |     |  | 396     |         |  |  | 249    |        |  |  | 427     |         |  |  | 270    |       
|                        
|Total United States      |                |                      |                            |                        |  |  | 708         |     |  |       | 507   |     |     |  | 6,525   |         |  |  | 4,340  |        |  |  | 7,233   |         |  |  | 4,847  |       
|                        
|                         | Chad           |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 108,536 |  |  |        | 54,268 |  |  |         | 108,536 |  |  |        | 54,268 | 
|                         | Oman           |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 9,606   |  |  |        | 9,606  |  |  |         | 9,606   |  |  |        | 9,606  | 
|                         | Qatar          |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 2,161   |  |  |        | 2,161  |  |  |         | 2,161   |  |  |        | 2,161  | 
|                         | Greenland      |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 985     |  |  |        | 862    |  |  |         | 985     |  |  |        | 862    | 
|                         | Yemen          |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 1,879   |  |  |        | 691    |  |  |         | 1,879   |  |  |        | 691    | 
|                         | Brazil         |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 1,444   |  |  |        | 554    |  |  |         | 1,444   |  |  |        | 554    | 
|                         | Australia      |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 960     |  |  |        | 320    |  |  |         | 960     |  |  |        | 320    | 
|                         | Bahrain        |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 97      |  |  |        | 48     |  |  |         | 97      |  |  |        | 48     | 
|                         | Azerbaijan     |                      |                            |                        |  |  |             |    |  |       |       |    |     |  |         | 346     |  |  |        | 17     |  |  |         | 346     |  |  |        | 17     | 
|                        
|Total International      |                |                      |                            |                        |  |  |            |     |  |       |      |     |     |  | 126,014 |         |  |  | 68,527 |        |  |  | 126,014 |         |  |  | 68,527 |       
|                        
|Total                    |                |                      |                            |                        |  |  | 9,806       |     |  |       | 8,660 |     |     |  | 155,797 |         |  |  | 90,796 |        |  |  | 165,603 |         |  |  | 99,456 |       
|                        
|Discontinued Operations: |                |                      |                            |                        |  |  |             |     |  |       |       |     |     |  |         |         |  |  |        |        |  |  |         |        
|                        
|Ecuador                  |                |                      |                            |                        |  |  | 160         |     |  |       | 99    |     |     |  | 1,243   |         |  |  | 795    |        |  |  | 1,403   |         |  |  | 894    |       
|                        





|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | This table excludes approximately 4.3 million gross acres
    under lease or sublease, reserving to EnCana royalties or other
    interests.                                                                                                                                                                                                                                                                                                                                                                                                                   
|   
|(2) | Fee lands are those lands in which EnCana has a fee simple
    interest in the minerals rights and has either: (i) not
    leased out all of the mineral zones; or (ii) retained a
    working interest. In prior years, fee lands in which any zones
    were leased out were excluded as fee lands except with respect
    to lands in which EnCana retained a working interest. The
    current fee lands acreage summary now includes all fee titles
    owned by EnCana that have one or more zones that remain unleased
    or available for development.
|   
|(3) | Crown / Federal / State lands are those owned by the federal,
    provincial, or state government or the First Nations, in which
    EnCana has purchased a working interest lease.                                                                                                                                                                                                                                                                                                                                                                            
|   
|(4) | Freehold lands are owned by individuals (other than a Government
    or EnCana), in which EnCana holds a working interest lease.                                                                                                                                                                                                                                                                                                                                                                                                                               
|   
|(5) | Gross acres are the total area of properties in which EnCana has
    an interest.                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|   
|(6) | Net acres are the sum of EnCanas fractional interest in
    gross acres.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      

43



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##### 






Acquisitions, Dispositions and Capital Expenditures






|                                                                        |                                        |              |                                               |       |      |       |       |       |    |      |  
|----------------------------------------------------------------------- | -------------------------------------- | ------------ | --------------------------------------------- | ----- | ---- | ----- | ----- | ----- | -- | ---- | -
|                                                                        |                                        | 2004         |                                               |       | 2003 |      
|                                                                        |                                       
|                                                                        |                                        | ($ millions) |                                              
|Upstream                                                                |                                        |              |                                               |       |      |       |       |      
|                                                                        | Canada                                 |              |                                               | 3,015 |      |       |       | 2,937 |   
|                                                                        | United States                          |              |                                               | 1,249 |      |       |       | 830   |   
|                                                                        | International New Ventures Exploration |              |                                               | 79    |      |       |       | 78    |   
|                                                                       
|                                                                        |                                        |              | 4,343                                         |       |      |       | 3,845 |      
|Midstream & Marketing                                                   |                                        |              | 64                                            |       |      |       | 223   |      
|Corporate                                                               |                                        |              | 46                                            |       |      |       | 57    |      
|                                                                       
|Core Capital from Continuing Operations                                 |                                        |              | 4,453                                         |       |      |       | 4,125 |      
|                                                                       
|Acquisitions                                                            |                                        |              |                                               |       |      |       |       |      
|                                                                        | Upstream                               |              |                                               |       |      |       |       |       |   
|                                                                        |                                        | Property     |                                               |       |      |       |       |       |    |     
|                                                                        |                                        |              | Canada                                        |       |      | 64    |       |       |    | 261  |  
|                                                                        |                                        |              | United States                                 |       |      | 300   |       |       |    | 138  |  
|                                                                        |                                        | Corporate    |                                               |       |      |       |       |       |    |     
|                                                                        |                                        |              | Savannah                                      |       |      |      |       |       |    | 91   |  
|                                                                        |                                        |              | Petrovera                                     |       |      | 253   |       |       |    |     |  
|                                                                        |                                        |              | Tom Brown,
    Inc. (1)                       |       |      | 2,335 |       |       |    |     |  
|                                                                        | Midstream & Marketing                  |              |                                               |       |      |       |       |       |   
|                                                                        |                                        | Other        |                                               |       | 34   |       |       |       | 53 |     
|                                                                        | Corporate                              |              |                                               |      |      |       |       | 50    |   
|Dispositions                                                            |                                        |              |                                               |       |      |       |       |      
|                                                                        | Upstream                               |              |                                               |       |      |       |       |       |   
|                                                                        |                                        | Property     |                                               |       |      |       |       |       |    |     
|                                                                        |                                        |              | Canada                                        |       |      | (877  | )     |       |    | (108 | )
|                                                                        |                                        |              | United States                                 |       |      | (266  | )     |       |    | (178 | )
|                                                                        |                                        |              | Other Countries                               |       |      |      |       |       |    | (15  | )
|                                                                        |                                        | Corporate    |                                               |       |      |       |       |       |    |     
|                                                                        |                                        |              | Petrovera                                     |       |      | (540  | )     |       |    |     |  
|                                                                        | Midstream & Marketing                  |              |                                               |       |      |       |       |       |   
|                                                                        |                                        | Property     |                                               |       | (1   | )     |       |       |   |     
|                                                                        |                                        | Corporate    |                                               |       |      |       |       |       |    |     
|                                                                        |                                        |              | Alberta Ethane Gathering System Joint Venture |       |      | (108  | )     |       |    |     |  
|                                                                        |                                        |              | Kingston CoGen Partnership                    |       |      | (25   | )     |       |    |     |  
|                                                                       
|Net Acquisition and Disposition Activity from Continuing
    Operations |                                        |              | 1,169                                         |       |      |       | 292   |      
|                                                                       
|Proceeds of Disposition of United Kingdom                               |                                        |              | (2,144                                        | )     |      |       |      |      
|Discontinued Operations                                                 |                                        |              | 728                                           |       |      |       | (995  | )    
|                                                                       
|Total Discontinued Operations                                           |                                        |              | (1,416                                        | )     |      |       | (995  | )    
|                                                                       





|    |                                                                    
|--- | -------------------------------------------------------------------
|(1) | Net cash consideration excluding debt acquired of
    $406 million.



44



---



##### 






Delivery Commitments







GENERAL





Competitive Conditions







Environmental Protection











Social and Environmental Policies










45



---



##### 












Employees




|                      |  |                         |       | 
|--------------------- |  | ----------------------- | ----- | 
|                      |  | Number of FTE Employees |      
|                      |  | As at December 31, 2004 |      
|                     
|Upstream              |  |                         | 3,176 | 
|Midstream & Marketing |  |                         | 306   | 
|Corporate             |  |                         | 608   | 
|                     
|Total                 |  |                         | 4,090 | 
|                     




Foreign Operations







Reorganizations






46



---



##### 






DIRECTORS AND OFFICERS




Directors


|                                               |  |           |      |  |                      |                                                                                                                                     
|---------------------------------------------- |  | --------- | ---- |  | -------------------- | ------------------------------------------------------------------------------------------------------------------------------------
|                                               |  | Director  |      |  |                     
|Name and Municipality of Residence             |  | Since(13) |      |  | Principal Occupation
|                                              
|Michael N.
    Chernoff(2,6)                   |  |           | 1999 |  |                      | Corporate Director                                                                                                                  
|West Vancouver, British Columbia, Canada       |  |           |      |  |                      |                                                                                                                                     
|Ralph S.
    Cunningham(2,3)                   |  |           | 2003 |  |                      | Corporate Director                                                                                                                  
|Houston, Texas, United States                  |  |           |      |  |                      |                                                                                                                                     
|Patrick D.
    Daniel(1,5)                     |  |           | 2001 |  |                      | President & Chief Executive Officer                                                                                                 
|Calgary, Alberta, Canada                       |  |           |      |  |                      | Enbridge Inc.(Energy delivery)                                                                                                      
|Ian W.
    Delaney(3,4)                        |  |           | 1999 |  |                      | Executive Chairman                                                                                                                  
|Toronto, Ontario, Canada                       |  |           |      |  |                      | Sherritt International Corporation(Nickel/cobalt mining, oil and natural gas production,
    electricity generation and coal mining)
|William R.
    Fatt(1,8)                       |  |           | 1995 |  |                      | Chief Executive Officer                                                                                                             
|Toronto, Ontario, Canada                       |  |           |      |  |                      | Fairmont Hotels & Resorts Inc.(Hotels)                                                                                              
|Michael A.
    Grandin(3,5,6,9)                |  |           | 1998 |  |                      | Dean of the Haskayne School of Business                                                                                             
|Calgary, Alberta, Canada                       |  |           |      |  |                      | University of Calgary(Education)                                                                                                    
|Barry W.
    Harrison(1,4,10)                  |  |           | 1996 |  |                      | Corporate Director and independent businessman                                                                                      
|Calgary, Alberta, Canada                       |  |           |      |  |                      |                                                                                                                                     
|Richard F.
    Haskayne,
    O.C., F.C.A.(3,4) |  |           | 1992 |  |                      | Chairman of the Board                                                                                                               
|Calgary, Alberta, Canada                       |  |           |      |  |                      | TransCanada Corporation(Pipelines and energy services)                                                                              
|Dale A.
    Lucas(1,5)                         |  |           | 1997 |  |                      | Corporate Director                                                                                                                  
|Calgary, Alberta, Canada                       |  |           |      |  |                      |                                                                                                                                     
|Ken F.
    McCready(2,5,11)                    |  |           | 1992 |  |                      | President                                                                                                                           
|Calgary, Alberta, Canada                       |  |           |      |  |                      | K.F. McCready & Associates Ltd.(Sustainable energy development consulting company)                                                  
|Gwyn Morgan                                    |  |           | 1993 |  |                      | President & Chief Executive Officer                                                                                                 
|Calgary, Alberta, Canada                       |  |           |      |  |                      | EnCana Corporation                                                                                                                  
|Valerie A. A.
    Nielsen(2,6)                 |  |           | 1990 |  |                      | Corporate Director                                                                                                                  
|Calgary, Alberta, Canada                       |  |           |      |  |                      |                                                                                                                                     
|David P.
    OBrien(4,7,12)                   |  |           | 1990 |  |                      | Chairman                                                                                                                            
|Calgary, Alberta, Canada                       |  |           |      |  |                      | EnCana Corporation                                                                                                                  
|                                               |  |           |      |  |                      | Chairman
    Royal Bank of Canada                                                                                                   
|Jane L.
    Peverett(1)                        |  |           | 2003 |  |                      | Chief Financial Officer                                                                                                             
|West Vancouver, British Columbia, Canada       |  |           |      |  |                      | British Columbia Transmission Corporation(Electricity transmission)                                                                 
|Dennis A.
    Sharp(2,4)                       |  |           | 1998 |  |                      | Executive Chairman                                                                                                                  
|Calgary, Alberta, Canada/                      |  |           |      |  |                      | UTS Energy Corporation                                                                                                              
|Montreal, Quebec, Canada                       |  |           |      |  |                      | (Oil and natural gas company)                                                                                                       
|James M. Stanford,
    O.C.(1,3,6)             |  |           | 2001 |  |                      | President                                                                                                                           
|Calgary, Alberta, Canada                       |  |           |      |  |                      | Stanford Resource Management Inc.(Investment management)                                                                            
|                                              

47



---



##### 







|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|---- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1)  | Audit Committee.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|    
|(2)  | Corporate Responsibility, Environment, Health and Safety
    Committee.                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|    
|(3)  | Human Resources and Compensation Committee.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|    
|(4)  | Nominating and Corporate Governance Committee.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|    
|(5)  | Pension Committee.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|    
|(6)  | Reserves Committee.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|    
|(7)  | Ex officio non-voting member of all other committees. As an ex
    officio non-voting member, Mr. OBrien attends as his
    schedule permits and may vote when necessary to achieve a quorum.                                                                                                                                                                                                                                                                                                                                    
|    
|(8)  | Mr. Fatt was a director of Unitel Communications Inc.
    (Unitel) in 1995 when it made a filing pursuant to
    the Companies Creditors Arrangement Act(Canada).
    Unitel instituted a compromise with creditors on
    December 8, 1995 and Mr. Fatt resigned as a director
    in January 1996.                                                                                                                                                                                                                           
|    
|(9)  | Mr. Grandin was a director of Pegasus Gold Inc. in 1998
    when that company filed voluntarily to reorganize under
    Chapter 11 of the Bankruptcy Code (United States). A
    liquidation plan for that company received court confirmation
    later that year.                                                                                                                                                                                                                                                               
|    
|(10) | Mr. Harrison was a director of Gauntlet Energy Corporation
    in June 2003 when it filed for and was granted an order pursuant
    to the Companies Creditors Arrangement Act(Canada). A plan of arrangement for that company received
    court confirmation later that year.                                                                                                                                                                                                                                                  
|    
|(11) | Mr. McCready was a director of Colonia Corporation when the
    company was placed into receivership in October 2000. The
    company came out of receivership in October 2001.
    Mr. McCready was a director, Chairman and Chief Executive
    Officer of Etho Power Corporation, a small private company, when
    it was assigned into bankruptcy on April 7, 2003.                                                                                                                                                          
|    
|(12) | Mr. OBrien resigned as a director of Air Canada on
    November 26, 2003. On April 1, 2003, Air Canada
    obtained an order from the Ontario Superior Court of Justice
    providing creditor protection under the Companies
    Creditors Arrangement Act(Canada). Air Canada also made a
    concurrent petition under Section 304 of the
    U.S. Bankruptcy Code. On September 30, 2004, Air
    Canada announced that it had successfully completed its
    restructuring process and implemented its Plan of Arrangement.
|    
|(13) | Denotes the year each individual became a director of AEC or
    PanCanadian, if prior to the Merger, or EnCana, if after the
    Merger.                                                                                                                                                                                                                                                                                                                                                                                         





Executive Officers


|                                   |  |                                                    |        |  |  | 
|---------------------------------- |  | -------------------------------------------------- | ------ |  |  | 
|Name and Municipality of Residence |  |                                                    | Office
|                                  
|Gwyn Morgan                        |  | President & Chief Executive Officer               
|Calgary, Alberta, Canada           |  |                                                    |        |  |  | 
|Randall K. Eresman                 |  | Executive Vice-President & Chief Operating Officer
|Calgary, Alberta, Canada           |  |                                                    |        |  |  | 
|Roger J. Biemans                   |  | Executive Vice-President                          
|Denver, Colorado, United States    |  |                                                    |        |  |  | 
|Brian C. Ferguson                  |  | Executive Vice-President, Corporate Development   
|Calgary, Alberta, Canada           |  |                                                    |        |  |  | 
|R. William Oliver                  |  | Executive Vice-President                          
|Calgary, Alberta, Canada           |  |                                                    |        |  |  | 
|Gerard J. Protti                   |  | Executive Vice-President, Corporate Relations     
|Calgary, Alberta, Canada           |  |                                                    |        |  |  | 
|Drude Rimell                       |  | Executive Vice-President, Corporate Services      
|Calgary, Alberta, Canada           |  |                                                    |        |  |  | 
|John D. Watson                     |  | Executive Vice-President & Chief Financial Officer
|Calgary, Alberta, Canada           |  |                                                    |        |  |  | 
|                                  

48



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AUDIT COMMITTEE INFORMATION


The full text of the audit committee mandate is included in
Appendix C of this annual information form.


Composition of the Audit Committee


Audit Committees


Patrick D. Daniel




William R. Fatt




49



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##### 





Barry W. Harrison (Audit Committee Chair)




Dale A. Lucas




Jane L. Peverett




James M. Stanford, O.C.






Pre-Approval Policies and Procedures






50



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External Auditor Service Fees




|                          |  |      |       |  |      |  |       | 
|------------------------- |  | ---- | ----- |  | ---- |  | ----- | 
|($ thousands)             |  | 2004 |       |  | 2003 | 
|                          | 
|Audit
    Fees(1)         |  |      | 3,177 |  |      |  | 1,977 | 
|Audit-Related
    Fees(2) |  |      | 166   |  |      |  | 127   | 
|Tax
    Fees(3)           |  |      | 1,097 |  |      |  | 1,408 | 
|All Other
    Fees(4)     |  |      | 24    |  |      |  | 26    | 
|                         
|Total                     |  |      | 4,464 |  |      |  | 3,538 | 
|                         





|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Audit fees consist of fees for the audit of the
    Corporations annual financial statements or services that
    are normally provided in connection with statutory and
    regulatory filings or engagements.                                                                                                                                                                                                                                                                                                                                                                                                                    
|   
|(2) | Audit-related fees consist of fees for assurance and related
    services that are reasonably related to the performance of the
    audit or review of the Corporations financial statements
    and are not reported as Audit Fees. During fiscal 2004 and 2003,
    the services provided in this category included due diligence
    reviews in connection with acquisitions and dispositions,
    research of accounting and audit-related issues, review of
    reserves disclosure and the completion of audits required by
    contracts to which the Corporation is a party.                                               
|   
|(3) | Tax fees consist of fees for tax compliance services, tax advice
    and tax planning. During fiscal 2004 and 2003, the services
    provided in this category included assistance and advice in
    relation to the preparation of corporate income tax returns and
    expatriate tax services.                                                                                                                                                                                                                                                                                                                                   
|   
|(4) | During fiscal 2004, the services provided in this category
    included the payment of maintenance fees associated with a
    research tool that grants access to a comprehensive library of
    financial reporting and assurance literature and a working paper
    documentation package used by the Corporations internal
    audit group. During fiscal 2003, the services provided in this
    category included the review of EnCanas Corporate
    Responsibility Report and the payment of maintenance fees
    associated with a working paper documentation package used by
    the Corporations internal audit group.

de
minimus de minimus





DESCRIPTION OF SHARE CAPITAL




Common Shares




51



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Preferred Shares







CREDIT RATINGS




|                                   |  |                          |  |                     |  |                     
|---------------------------------- |  | ------------------------ |  | ------------------- |  | --------------------
|                                   |  | Standard & Poors        |  | Moodys Investors   |  | Dominion Bond Rating
|                                   |  | Ratings Services (S&P) |  | Service (Moodys) |  | Service (DBRS)    
|                                  
|Senior Unsecured/Long-Term Rating  |  | A-                       |  | Baa2                |  | A (low)             
|Commercial Paper/Short-Term Rating |  | A-1 (low)                |  | P-2                 |  | R-1 (low)           
|Outlook                            |  | Negative                 |  | Stable              |  | Stable              
|                                  





52



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MARKET FOR SECURITIES




|          |  |                           |       |  |                         |  |                           |               |  |  |            |  |  |      |      |  |     |  |       |       |  |  |        |  |  |  |       |  |  |  |      | 
|--------- |  | ------------------------- | ----- |  | ----------------------- |  | ------------------------- | ------------- |  |  | ---------- |  |  | ---- | ---- |  | --- |  | ----- | ----- |  |  | ------ |  |  |  | ----- |  |  |  | ---- | 
|          |  | Toronto Stock Exchange    |       |  | New York Stock Exchange | 
|          |  | Share Price Trading Range |       |  |                         |  | Share Price Trading Range |               |  | 
|          |  |                           |       |  | Share                   |  |                           |               |  |  | Share      | 
|          |  | High                      |       |  | Low                     |  |                           | Close         |  |  | Volume     |  |  | High |      |  | Low |  |       | Close |  |  | Volume | 
|          | 
|          |  | (C$ per share)            |       |  | (millions)              |  |                           | ($ per share) |  |  | (millions) | 
|2004      |  |                           |       |  |                         |  |                           |               |  |  |            |  |  |      |      |  |     |  |       |       |  |  |        |  |  |  |       |  |  |  |      | 
|January   |  |                           | 56.00 |  |                         |  | 51.00                     |               |  |  | 51.58      |  |  |      | 36.4 |  |     |  | 43.43 |       |  |  | 39.00  |  |  |  | 39.10 |  |  |  | 9.2  | 
|February  |  |                           | 58.25 |  |                         |  | 51.29                     |               |  |  | 57.84      |  |  |      | 27.5 |  |     |  | 43.60 |       |  |  | 38.36  |  |  |  | 43.45 |  |  |  | 10.4 | 
|March     |  |                           | 59.27 |  |                         |  | 54.22                     |               |  |  | 56.69      |  |  |      | 35.5 |  |     |  | 44.25 |       |  |  | 40.62  |  |  |  | 43.12 |  |  |  | 9.9  | 
|April     |  |                           | 59.73 |  |                         |  | 53.75                     |               |  |  | 53.80      |  |  |      | 30.3 |  |     |  | 44.73 |       |  |  | 39.18  |  |  |  | 39.22 |  |  |  | 13.7 | 
|May       |  |                           | 57.70 |  |                         |  | 52.99                     |               |  |  | 54.55      |  |  |      | 29.2 |  |     |  | 42.05 |       |  |  | 38.05  |  |  |  | 39.35 |  |  |  | 12.5 | 
|June      |  |                           | 58.85 |  |                         |  | 53.55                     |               |  |  | 57.62      |  |  |      | 25.8 |  |     |  | 43.41 |       |  |  | 39.45  |  |  |  | 43.16 |  |  |  | 9.7  | 
|July      |  |                           | 60.60 |  |                         |  | 56.55                     |               |  |  | 58.90      |  |  |      | 26.3 |  |     |  | 45.75 |       |  |  | 42.83  |  |  |  | 44.32 |  |  |  | 10.7 | 
|August    |  |                           | 59.94 |  |                         |  | 52.30                     |               |  |  | 53.66      |  |  |      | 28.4 |  |     |  | 45.50 |       |  |  | 39.95  |  |  |  | 41.10 |  |  |  | 12.1 | 
|September |  |                           | 59.46 |  |                         |  | 53.40                     |               |  |  | 58.35      |  |  |      | 26.7 |  |     |  | 46.92 |       |  |  | 41.09  |  |  |  | 46.30 |  |  |  | 10.6 | 
|October   |  |                           | 62.81 |  |                         |  | 57.90                     |               |  |  | 60.40      |  |  |      | 36.1 |  |     |  | 50.26 |       |  |  | 46.10  |  |  |  | 49.40 |  |  |  | 15.1 | 
|November  |  |                           | 68.20 |  |                         |  | 59.61                     |               |  |  | 67.80      |  |  |      | 40.5 |  |     |  | 57.43 |       |  |  | 48.85  |  |  |  | 57.03 |  |  |  | 19.8 | 
|December  |  |                           | 70.02 |  |                         |  | 63.13                     |               |  |  | 68.40      |  |  |      | 33.1 |  |     |  | 57.30 |       |  |  | 51.59  |  |  |  | 57.06 |  |  |  | 18.7 | 
|         



53



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|                                     |  |                  |              |  |        |  |      |            |  |  |                |  |  |             |                 |  |  |  |        |  
|------------------------------------ |  | ---------------- | ------------ |  | ------ |  | ---- | ---------- |  |  | -------------- |  |  | ----------- | --------------- |  |  |  | ------ | -
|Issuer                               |  | Principal Amount |              |  | Coupon |  |      | Issue Date |  |  | Maturity Date  |  |  | Issue Price |                
|                                     | 
|EnCana Holdings Finance
    Corp.(1) |  |                  | $1 billion   |  |        |  | 5.80 | %          |  |  | May 13, 2004   |  |  |             | May 1, 2014     |  |  |  | 99.614 | %
|EnCana Corporation                   |  |                  | $250 million |  |        |  | 4.60 | %          |  |  | August 4, 2004 |  |  |             | August 15, 2009 |  |  |  | 99.838 | %
|EnCana Corporation                   |  |                  | $750 million |  |        |  | 6.50 | %          |  |  | August 4, 2004 |  |  |             | August 15, 2034 |  |  |  | 99.123 | %
|                                    





|    |                                                                                                                                                                                                         
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | EnCana Holdings Finance Corp. (EHF) is an indirect,
    wholly owned subsidiary of EnCana Corporation. The notes issued
    by EHF are fully and unconditionally guaranteed by EnCana
    Corporation.




DIVIDENDS







LEGAL PROCEEDINGS









RISK FACTORS




A substantial or extended decline in crude oil and natural
gas prices could have a material adverse effect on EnCana.






54



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##### 





If EnCana fails to acquire or find additional crude oil and
natural gas reserves, the Corporations reserves and
production will decline materially from their current levels.




EnCanas crude oil and natural gas reserve data and
future net revenue estimates are uncertain.






EnCanas hedging activities could result in realized and
unrealized losses.








| |   |                                                                                                                                 
| | - | --------------------------------------------------------------------------------------------------------------------------------
| |  | the Corporation is unable to produce oil or natural gas to
    fulfill delivery obligations;                                    
|
| |  | the Corporation is required to pay royalties based on market or
    reference prices that are higher than hedged prices; or     
|
| |  | counterparties to the Corporations hedging agreements are
    unable to fulfill their obligations under the hedging agreements.

55



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##### 



The Corporations business is subject to environmental
legislation in all jurisdictions in which it operates and any
changes in such legislation could negatively affect its results
of operations.








EnCanas operations are subject to the risk of business
interruption and casualty losses.






Fluctuations in exchange rates could affect expenses or
result in realized and unrealized losses.






EnCana does not operate all of its properties and assets.




56



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| |   |                                                  
| | - | -------------------------------------------------
| |  | timing and amount of capital expenditures;       
|
| |  | the operators expertise and financial resources;
|
| |  | approval of other participants;                  
|
| |  | selection of technology; and                     
|
| |  | risk management practices.                       

The Corporations foreign operations will expose it to
risks from abroad which could negatively affect its results of
operations.




EnCanas ability to complete projects is dependent on
factors outside of its control.






| |   |                                                     
| | - | ----------------------------------------------------
| |  | the availability of processing capacity;            
|
| |  | the availability and proximity of pipeline capacity;
|
| |  | the availability of equipment;                      
|
| |  | the ability to access lands;                        
|
| |  | inclement weather;                                  
|
| |  | unexpected cost increases;                          
|
| |  | accidents;                                          
|
| |  | the availability of skilled labour; and             
|
| |  | regulatory matters.                                 



EnCana may be adversely affected by legal proceedings related
to its discontinued merchant energy trading operations.




57



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##### 







EnCana is subject to indemnification obligations in
connection with PanCanadians spin-off from Canadian
Pacific Limited.




58



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##### 






TRANSFER AGENTS AND REGISTRARS


|                             |  |                             
|---------------------------- |  | ----------------------------
|In Canada:                   |  | In the United States:       
|CIBC Mellon Trust Company    |  | Mellon Investor Services LLC
|320 Bay Street               |  | 44 Wall Street, 6th Floor   
|P.O. Box 1                   |  | New York, New York          
|Toronto, ON M5H 4A6          |  | 10005                       
|Tel: 1-800-387-0825          |  | Tel: 1-800-387-0825         
|Web site: www.cibcmellon.com |  | Web site: www.cibcmellon.com




INTERESTS OF EXPERTS









ADDITIONAL INFORMATION


www.sedar.com




59



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APPENDIX A


Report on Reserves Data by Independent Qualified Reserves
Evaluators






|   |                                                                                                                               
|-- | ------------------------------------------------------------------------------------------------------------------------------
|1. | We have evaluated the Corporations reserves data as at
    December 31, 2004. The reserves data consist of the
    following:



| |      |                                                                                                                                                        
| | ---- | -------------------------------------------------------------------------------------------------------------------------------------------------------
| | (i)  | estimated proved oil and gas reserve quantities as at
    December 31, 2004 using constant prices and costs; and                                       
|
| | (ii) | the related estimates of discounted future net cash flows under
    the standardized measure calculation for proved oil and gas
    reserve quantities.



|   |                                                                                                                                                                            
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2. | The reserves data are the responsibility of the
    Corporations management. Our responsibility is to express
    an opinion on the reserves data based on our evaluation.



| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | We carried out our evaluation in accordance with standards set
    out in the Canadian Oil and Gas Evaluation Handbook (the
    COGE Handbook) prepared jointly by the Society of
    Petroleum Evaluation Engineers (Calgary Chapter) and the
    Canadian Institute of Mining, Metallurgy & Petroleum
    (Petroleum Society) with the necessary modifications to reflect
    definitions and standards under the U.S. Financial
    Accounting Standards Board policies (the FASB
    Standards) and the legal requirements of the
    U.S. Securities and Exchange Commission (SEC
    Requirements).



|   |                                                                                                                                                                                                                                                                                                                                                                                                      
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3. | Those standards require that we plan and perform an evaluation
    to obtain reasonable assurance as to whether the reserves data
    are free of material misstatement. An evaluation also includes
    assessing whether the reserves data are in accordance with the
    principles and definitions outlined above.                                                                               
|  
|4. | The following table sets forth both the estimated proved reserve
    quantities (after royalties) and related estimates of future net
    cash flows (before deduction of income taxes) assuming constant
    prices and costs and calculated using a discount rate of
    10 percent, included in the reserves data of the
    Corporation evaluated by us for the year ended December 31,
    2004:

|                                         |  |                   |  |                    |         |  |                     |         |     |               |  |  |        | 
|---------------------------------------- |  | ----------------- |  | ------------------ | ------- |  | ------------------- | ------- | --- | ------------- |  |  | ------ | 
|                                         |  |                   |  | Estimated Proved   |         |  | Related             |        
|                                         |  |                   |  | Reserve Quantities |         |  | Estimates of Future |        
|                                         |  |                   |  | After Royalty      |         |  | Net Cash Flow       |        
|                                         |  |                   |  |                    |         |  | BTax, 10%           |        
|Evaluator and Preparation Date of Report |  | Reserves Location |  | Gas                |         |  | Liquids             |         |     | discount rate | 
|                                         | 
|                                         |  | (Bcf)             |  |                    | (MMbbl) |  |                     | ($USMM) |    
|                                         | 
|McDaniel & Associates Consultants Ltd.   |  | Canada            |  |                    | 3,434   |  |                     |         | 146 |               |  |  | 9,770  | 
|January 14, 2005                         |  |                   |  |                    |         |  |                     |         |     |               |  |  |        | 
|Gilbert Laustsen Jung Associates Ltd.    |  | Canada            |  |                    | 2,390   |  |                     |         | 121 |               |  |  | 6,529  | 
|January 14, 2005                         |  |                   |  |                    |         |  |                     |         |     |               |  |  |        | 
|Netherland, Sewell & Associates, Inc.    |  | United States     |  |                    | 3,946   |  |                     |         | 49  |               |  |  | 9,276  | 
|January 14, 2005                         |  |                   |  |                    |         |  |                     |         |     |               |  |  |        | 
|DeGolyer and MacNaughton                 |  | United States     |  |                    | 690     |  |                     |         | 42  |               |  |  | 1,907  | 
|February 3, 2005                         |  |                   |  |                    |         |  |                     |         |     |               |  |  |        | 
|Gilbert Laustsen Jung Associates Ltd.    |  | Ecuador           |  |                    |         |  |                     |         | 143 |               |  |  | 1,752  | 
|January 14, 2005                         |  |                   |  |                    |         |  |                     |         |     |               |  |  |        | 
|                                        
|Totals                                   |  |                   |  |                    | 10,460  |  |                     |         | 501 |               |  |  | 29,234 | 
|                                        



|   |                                                                                                                                                                                                                                
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|5. | In our opinion, the reserves data respectively evaluated by us
    have, in all material respects, been determined and are in
    accordance with the COGE Handbook as modified by the FASB
    Standards and SEC requirements.
|  
|6. | We have no responsibility to update our reports referred to in
    paragraph 4 for events and circumstances occurring after
    their respective preparation dates.                                                            

60



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|   |                                                                                                                                                                                                                   
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|7. | Reserves are estimates only, and not exact quantities. In
    addition, as the reserves data are based on judgements regarding
    future events, actual results will vary and the variations may
    be material.



|                                                |  |                                               
|----------------------------------------------- |  | ----------------------------------------------
|(signed) McDaniel & Associates Consultants Ltd. |  | (signed) Gilbert Laustsen Jung Associates Ltd.
|Calgary, Alberta, Canada                        |  | Calgary, Alberta, Canada                      
|                                               
|(signed) Netherland, Sewell & Associates, Inc.  |  | (signed) DeGolyer and MacNaughton             
|Dallas, Texas, U.S.A.                           |  | Dallas, Texas, U.S.A.                         



61



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APPENDIX B


Report of Management and Directors on Reserves Data and Other
Information






| |      |                                                                                                                                                        
| | ---- | -------------------------------------------------------------------------------------------------------------------------------------------------------
| | (i)  | proved oil and gas reserve quantities estimated as at
    December 31, 2004 using constant prices and costs; and                                       
|
| | (ii) | the related estimates of discounted future net cash flows under
    the standardized measure calculation for proved oil and gas
    reserve quantities.







| |     |                                                                                                                                                                                                                                       
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | (a) | reviewed the Corporations procedures for providing
    information to the independent qualified reserves evaluators;                                                                                                                 
|
| | (b) | met with the independent qualified reserves evaluators to
    determine whether any restrictions placed by management affected
    the ability of the independent qualified reserves evaluators to
    report without reservation; and
|
| | (c) | reviewed the reserves data as outlined in the IQRE Report with
    management and each of the independent qualified reserves
    evaluators.                                                                                          





| |     |                                                                                                                                                                                                                                                                                                       
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | (a) | the content and filing with securities regulatory authorities of
    the proved oil and gas reserve quantities, related standardized
    measure calculation and other oil and gas activity information,
    contained in the annual information form of the Corporation
    accompanying this Report;
|
| | (b) | the filing of the IQRE Report; and                                                                                                                                                                                                                                                                    
|
| | (c) | the content and filing of this Report.                                                                                                                                                                                                                                                                





















62



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APPENDIX C


Audit Committee Mandate


I.   PURPOSE








| |   |                                                                                                                                                                                                                                              
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Review and approve managements identification of principal
    financial risks and monitor the process to manage such risks.                                                                                                                
|
| |  | Oversee and monitor the Corporations compliance with legal
    and regulatory requirements.                                                                                                                                                 
|
| |  | Receive and review the reports of the Audit Committee of any
    subsidiary with public securities.                                                                                                                                          
|
| |  | Oversee and monitor the integrity of the Corporations
    accounting and financial reporting processes, financial
    statements and system of internal controls regarding accounting
    and financial reporting and accounting compliance.
|
| |  | Oversee audits of the Corporations financial statements.                                                                                                                                                                                    
|
| |  | Oversee and monitor the qualifications, independence and
    performance of the Corporations external auditors and
    internal auditing department.                                                                                        
|
| |  | Provide an avenue of communication among the external auditors,
    management, the internal auditing department, and the Board of
    Directors.                                                                                            
|
| |  | Report to the Board of Directors regularly.                                                                                                                                                                                                  



II.  COMPOSITION AND MEETINGS


Committee Members Duties in addition to those of a
Director




Composition








| |   |                                                                                                                                                                                                                                            
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | An understanding of generally accepted accounting principles and
    financial statements;                                                                                                                                                 
|
| |  | The ability to assess the general application of such principles
    in connection with the accounting for estimates, accruals and
    reserves;                                                                                           
|
| |  | Experience preparing, auditing, analyzing or evaluating
    financial statements that present a breadth and level of
    complexity of accounting issues that are generally comparable to
    the breadth and complexity of issues that can

63



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| |   |                                                                                                                                                                         
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   | reasonably be expected to be raised by the registrants
    financial statements, or experience actively supervising one or
    more persons engaged in such activities;
|
| |  | An understanding of internal controls and procedures for
    financial reporting; and                                                                                   
|
| |  | An understanding of audit committee functions.                                                                                                                          









Appointment of Members














Meetings














64



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##### 



Notice of Meeting






Quorum




Minutes








III. RESPONSIBILITIES


Review Procedures






Annual Financial Statements




|   |                                                                                                                                                                                                                                                              
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|1. | Discuss and review with management and the external auditors the
    Corporations and any subsidiary with public securities
    annual audited financial statements and related documents prior
    to their filing or distribution. Such review to include:



| |    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
| | -- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | a. | The annual financial statements and related footnotes including
    significant issues regarding accounting principles, practices
    and significant management estimates and judgments, including
    any significant changes in the Corporations selection or
    application of accounting principles, any major issues as to the
    adequacy of the Corporations internal controls and any
    special steps adopted in light of material control deficiencies.
|
| | b. | Managements Discussion and Analysis.                                                                                                                                                                                                                                                                                                                                                                                                                                  
|
| | c. | A review of the use of off-balance sheet financing including
    managements risk assessment and adequacy of disclosure.                                                                                                                                                                                                                                                                                                                                              
|
| | d. | A review of the external auditors audit examination of the
    financial statements and their report thereon.                                                                                                                                                                                                                                                                                                                                                         
|
| | e. | Review of any significant changes required in the external
    auditors audit plan.                                                                                                                                                                                                                                                                                                                                                                                   
|
| | f. | A review of any serious difficulties or disputes with management
    encountered during the course of the audit, including any
    restrictions on the scope of the external auditors work or
    access to required information.                                                                                                                                                                                                                                     
|
| | g. | A review of other matters related to the conduct of the audit,
    which are to be communicated to the Committee under generally
    accepted auditing standards.                                                                                                                                                                                                                                                                                                      

65



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|   |                                                                              
|-- | -----------------------------------------------------------------------------
|2. | Review and formally recommend approval to the Board of the
    Corporations:



| |    |                                                                                                                                  
| | -- | ---------------------------------------------------------------------------------------------------------------------------------
| | a. | Year-end audited financial statements. Such review shall include
    discussions with management and the external auditors as to:



| |       |                                                                        
| | ----- | -----------------------------------------------------------------------
| | (i)   | The accounting policies of the Corporation and any changes
    thereto.
|
| | (ii)  | The effect of significant judgements, accruals and estimates.          
|
| | (iii) | The manner of presentation of significant accounting items.            
|
| | (iv)  | The consistency of disclosure.                                         



| |    |                                                                            
| | -- | ---------------------------------------------------------------------------
| | b. | Managements Discussion and Analysis.                                      
|
| | c. | Annual Information Form as to financial information.                       
|
| | d. | All prospectuses and information circulars as to financial
    information.



Quarterly Financial Statements




|   |                                                                                                                                                                                                                   
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3. | Review with management and the external auditors and either
    approve (such approval to include the authorization for public
    release) or formally recommend for approval to the Board the
    Corporations:



| |    |                                                                                                                    
| | -- | -------------------------------------------------------------------------------------------------------------------
| | a. | Quarterly unaudited financial statements and related documents,
    including Managements Discussion and Analysis.
|
| | b. | Any significant changes to the Corporations accounting
    principles.                                            



Other Financial Filings and Public Documents




|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4. | Review and discuss with management financial information,
    including earnings press releases, the use of pro
    forma or non-GAAP financial information and earnings
    guidance, contained in any filings with the securities
    regulators or news releases related thereto (or provided to
    analysts or rating agencies) and consider whether the
    information is consistent with the information contained in the
    financial statements of the Corporation or any subsidiary with
    public securities. Such discussion may be done generally
    (consisting of discussing the types of information to be
    disclosed and the types of presentations to be made).

Internal Control Environment




|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|5. | Ensure that management, the external auditors, and the internal
    auditors provide to the Committee an annual report on the
    Corporations control environment as it pertains to the
    Corporations financial reporting process and controls.                                                                                                                                                                                                                                                                                                                                                                                               
|  
|6. | Review and discuss significant financial risks or exposures and
    assess the steps management has taken to monitor, control,
    report and mitigate such risk to the Corporation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|  
|7. | Review significant findings prepared by the external auditors
    and the internal auditing department together with
    managements responses.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|  
|8. | Review in consultation with the internal auditors and the
    external auditors the degree of coordination in the audit plans
    of the internal auditors and the external auditors and enquire
    as to the extent the planned scope can be relied upon to detect
    weaknesses in internal controls, fraud, or other illegal acts.
    The Committee will assess the coordination of audit effort to
    assure completeness of coverage and the effective use of audit
    resources. Any significant recommendations made by the auditors
    for the strengthening of internal controls shall be reviewed and
    discussed with management.

66



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##### 



Other Review Items




|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|9.  | Review policies and procedures with respect to officers
    and directors expense accounts and perquisites, including
    their use of corporate assets, and consider the results of any
    review of these areas by the internal auditor or the external
    auditors.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|   
|10. | Review all related party transactions between the Corporation
    and any officers or directors, including affiliations of any
    officers or directors.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|   
|11. | Review with the General Counsel, the head of internal audit and
    the external auditors the results of their review of the
    Corporations monitoring compliance with each of the
    Corporations published codes of business conduct and
    applicable legal requirements.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|   
|12. | Review legal and regulatory matters, including correspondence
    with regulators and governmental agencies, that may have a
    material impact on the interim or annual financial statements,
    related corporation compliance policies, and programs and
    reports received from regulators or governmental agencies.
    Members from the Legal and Tax departments should be at the
    meeting in person to deliver their reports.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|   
|13. | Review policies and practices with respect to off-balance sheet
    transactions and trading and hedging activities, and consider
    the results of any review of these areas by the internal
    auditors or the external auditors.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|   
|14. | Ensure that the Corporations presentations on net proven
    reserves have been reviewed with the Reserves Committee of the
    Board.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|   
|15. | Establish procedures for the receipt, retention and treatment of
    complaints received by the Corporation, including confidential,
    anonymous submissions by employees of the Corporation, regarding
    accounting, internal accounting controls, or auditing matters.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|   
|16. | Review with the President & Chief Executive Officer, the
    Executive Vice-President & Chief Financial Officer of the
    Corporation and the external auditors: (i) all significant
    deficiencies and material weaknesses in the design or operation
    of the Corporations internal controls and procedures for
    financial reporting which could adversely affect the
    Corporations ability to record, process, summarize and
    report financial information required to be disclosed by the
    Corporation in the reports that it files or submits under the
    United States Securities Exchange Act of 1934, as amended (the
    Exchange Act) or applicable Canadian federal and
    provincial legislation and regulations within the required time
    periods, and (ii) any fraud, whether or not material, that
    involves management of the Corporation or other employees who
    have a significant role in the Corporations internal
    controls and procedures for financial reporting.
|   
|17. | Meet on a periodic basis separately with management.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         

External Auditors




|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|18. | Be directly responsible, in the Committees capacity as a
    committee of the Board and subject to the rights of shareholders
    and applicable law, for the appointment, compensation, retention
    and oversight of the work of the external auditors (including
    resolution of disagreements between management and the external
    auditors regarding financial reporting) for the purpose of
    preparing or issuing an audit report, or performing other audit,
    review or attest services for the Corporation. The external
    auditors shall report directly to the Committee.
|   
|19. | Meet on a regular basis with the external auditors (without
    management present) and have the external auditors be available
    to attend Committee meetings or portions thereof at the request
    of the Chairman of the Committee or by a majority of the members
    of the Committee.                                                                                                                                                                                                                                                                                                    
|   
|20. | Review and discuss a report from the external auditors at least
    quarterly regarding:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          



| |    |                                                                                                                                                                                                                                                                                                                                               
| | -- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | a. | All critical accounting policies and practices to be used;                                                                                                                                                                                                                                                                                    
|
| | b. | All alternative treatments within generally accepted accounting
    principles for policies and practices related to material items
    that have been discussed with management, including the
    ramifications of the use of such alternative disclosures and
    treatments, and the treatment preferred by the external
    auditors; and
|
| | c. | Other material written communications between the external
    auditors and management, such as any management letter or
    schedule of unadjusted differences.                                                                                                                                                                              

67



---



##### 





|    |                                                                                       
|--- | --------------------------------------------------------------------------------------
|21. | Obtain and review a report from the external auditors at least
    annually regarding:



| |    |                                                                                                                                                                                                                                                                                                                                                                                             
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | a. | The external auditors internal quality-control procedures.                                                                                                                                                                                                                                                                                                                                 
|
| | b. | Any material issues raised by the most recent internal
    quality-control review, or peer review, of the external
    auditors, or by any inquiry or investigation by governmental or
    professional authorities, within the preceding five years,
    respecting one or more independent audits carried out by the
    external auditors, and any steps taken to deal with those issues.
|
| | c. | To the extent contemplated in the following paragraph, all
    relationships between the external auditors and the Corporation.                                                                                                                                                                                                                                                             



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|22. | Review and discuss with the external auditors all relationships
    that the external auditors and their affiliates have with the
    Corporation and its affiliates in order to determine the
    external auditors independence, including, without
    limitation, (i) receiving and reviewing, as part of the
    report described in the preceding paragraph, a formal written
    statement from the external auditors delineating all
    relationships that may reasonably be thought to bear on the
    independence of the external auditors with respect to the
    Corporation and its affiliates, (ii) discussing with the
    external auditors any disclosed relationships or services that
    the external auditors believe may affect the objectivity and
    independence of the external auditors, and
    (iii) recommending that the Board take appropriate action
    in response to the external auditors report to satisfy
    itself of the external auditors independence.
|   
|23. | Review and evaluate:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    



| |    |                                                                                                                                                                                                                                                                                                                                     
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | a. | The external auditors and the lead partner of the external
    auditors teams performance, and make a
    recommendation to the Board of Directors regarding the
    reappointment of the external auditors at the annual meeting of
    the Corporations shareholders or regarding the discharge
    of such external auditors.
|
| | b. | The terms of engagement of the external auditors together with
    their proposed fees.                                                                                                                                                                                                                                             
|
| | c. | External audit plans and results.                                                                                                                                                                                                                                                                                                   
|
| | d. | Any other related audit engagement matters.                                                                                                                                                                                                                                                                                         
|
| | e. | The engagement of the external auditors to perform non-audit
    services, together with the fees therefor, and the impact
    thereof, on the independence of the external auditors.                                                                                                                                               



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|24. | Upon reviewing and discussing the information provided to the
    Committee in accordance with paragraphs 20 through 23,
    evaluate the external auditors qualifications, performance
    and independence, including whether or not the external
    auditors quality controls are adequate and the provision
    of permitted non-audit services is compatible with maintaining
    auditor independence, taking into account the opinions of
    management and the head of internal audit. The Committee shall
    present its conclusions with respect to the external auditors to
    the Board.
|   
|25. | Ensure the rotation of partners on the audit engagement team in
    accordance with applicable law. Consider whether, in order to
    assure continuing external auditor independence, it is
    appropriate to adopt a policy of rotating the external auditing
    firm on a regular basis.                                                                                                                                                                                                                                                                                                             
|   
|26. | Set clear hiring policies for the Corporations hiring of
    employees or former employees of the external auditors.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|   
|27. | Consider with management and the external auditors the rationale
    for employing audit firms other than the principal external
    auditors.                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|   
|28. | Consider and review with the external auditors, management and
    the head of internal audit:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            



| |    |                                                                                                                                                                                        
| | -- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | a. | Significant findings during the year and managements
    responses and follow-up thereto.                                                                                             
|
| | b. | Any difficulties encountered in the course of their audits,
    including any restrictions on the scope of their work or access
    to required information, and managements response.
|
| | c. | Any significant disagreements between the external auditors or
    internal auditors and management.                                                                                   
|
| | d. | Any changes required in the planned scope of their audit plan.                                                                                                                         
|
| | e. | The resources, budget, reporting relationships, responsibilities
    and planned activities of the internal auditors.                                                                  
|
| | f. | The internal audit department mandate.                                                                                                                                                 
|
| | g. | Internal audits compliance with the Institute of Internal
    Auditors standards.                                                                                                    

68



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##### 



Internal Audit Department and Legal Compliance




|    |                                                                                                                               
|--- | ------------------------------------------------------------------------------------------------------------------------------
|29. | Meet on a periodic basis separately with the head of internal
    audit.                                                      
|   
|30. | Review and concur in the appointment, compensation, replacement,
    reassignment, or dismissal of the head of internal audit.
|   
|31. | Confirm and assure, annually, the independence of the internal
    audit department and the external auditors.                

Approval of Audit and Non-Audit Services




|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|32. | Review and, where appropriate, approve the provision of all
    permitted non-audit services (including the fees and terms
    thereof) in advance of the provision of those services by the
    external auditors (subject to the de minimus exception for
    non-audit services described in the Exchange Act or applicable
    Canadian federal and provincial legislation and regulations
    which are approved by the Committee prior to the completion of
    the audit).   
|   
|33. | Review and, where appropriate and permitted, approve the
    provision of all audit services (including the fees and terms
    thereof) in advance of the provision of those services by the
    external auditors.                                                                                                                                                                                                                                                                 
|   
|34. | If the pre-approvals contemplated in paragraphs 32 and 33
    are not obtained, approve, where appropriate and permitted, the
    provision of all audit and non-audit services promptly after the
    Committee or a member of the Committee to whom authority is
    delegated becomes aware of the provision of those services.                                                                                                                                                  
|   
|35. | Delegate, if the Committee deems necessary or desirable, to
    subcommittees consisting of one or more members of the
    Committee, the authority to grant the pre-approvals and
    approvals described in paragraphs 32 through 34. The
    decision of any such subcommittee to grant pre-approval shall be
    presented to the full Committee at the next scheduled Committee
    meeting.                                                                                   
|   
|36. | The Committee may establish policies and procedures for the
    pre-approvals described in paragraphs 32 and 33, so long as
    such policies and procedures are detailed as to the particular
    service, the Committee is informed of each service and such
    policies and procedures do not include delegation of the
    Committees responsibilities under the Exchange Act or
    applicable Canadian federal and provincial legislation and
    regulations to management.

Other Matters




|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|37. | Review and concur in the appointment, replacement, reassignment,
    or dismissal of the Chief Financial Officer.                                                                                                                                                                                                                                                                                                                                                                                                                                        
|   
|38. | Upon a majority vote of the Committee outside resources may be
    engaged where and if deemed advisable.                                                                                                                                                                                                                                                                                                                                                                                                                                                
|   
|39. | Report Committee actions to the Board of Directors with such
    recommendations, as the Committee may deem appropriate.                                                                                                                                                                                                                                                                                                                                                                                                                                 
|   
|40. | Conduct or authorize investigations into any matters within the
    Committees scope of responsibilities. The Committee shall
    be empowered to retain, obtain advice or otherwise receive
    assistance from independent counsel, accountants, or others to
    assist it in the conduct of any investigation as it deems
    necessary and the carrying out of its duties.                                                                                                                                                                         
|   
|41. | The Corporation shall provide for appropriate funding, as
    determined by the Committee in its capacity as a committee of
    the Board, for payment (i) of compensation to the external
    auditors for the purpose of preparing or issuing an audit report
    or performing other audit, review or attest services for the
    Corporation, (ii) of compensation to any advisors employed
    by the Committee and (iii) of ordinary administrative
    expenses of the Committee that are necessary or appropriate in
    carrying out its duties.
|   
|42. | Obtain assurance from the external auditors that disclosure to
    the Committee is not required pursuant to the provisions of the
    Exchange Act regarding the discovery of illegal acts by the
    external auditors.                                                                                                                                                                                                                                                                                                                                
|   
|43. | The Committee shall review and reassess the adequacy of this
    Mandate annually and recommend any proposed changes to the Board
    for approval.                                                                                                                                                                                                                                                                                                                                                                                                      
|   
|44. | The Committees performance shall be evaluated annually by
    the Nominating and Corporate Governance Committee of the Board
    of Directors.                                                                                                                                                                                                                                                                                                                                                                                                          
|   
|45. | Perform such other functions as required by law, the
    Corporations mandate or bylaws, or the Board of Directors.                                                                                                                                                                                                                                                                                                                                                                                                                                     
|   
|46. | Consider any other matters referred to it by the Board of
    Directors.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 

69



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##### 



ENCANA CORPORATION 2004
Managements Discussion and Analysis




---



##### 



MANAGEMENTS DISCUSSION & ANALYSIS This Managements Discussion and Analysis (MD&A) for EnCana Corporation (EnCana or the
Company) should be read in conjunction with the audited Consolidated Financial Statements
(Consolidated Financial Statements) for the year ended December 31, 2004, as well as the audited
Consolidated Financial Statements and MD&A for the year ended December 31, 2003. Readers are
referred to the legal advisory detailing Forward-Looking Statements contained in the back of this
MD&A. The Consolidated Financial Statements and comparative information have been prepared in
accordance with Canadian GAAP in United States dollars (except where indicated as being in another
currency).
 This MD&A has been prepared in United States dollars with production and sales volumes presented on
an after royalties basis consistent with U.S. protocol reporting. This MD&A is dated February 22,
2005. SUMMARY OF KEY SECTIONS PageSUMMARY OF KEY EVENTS AND
FINANCIAL RESULTS IN 2004
    
    
    M1OVERVIEW
    
    
    M1BUSINESS ENVIRONMENT
    
    
    M2CONSOLIDATED FINANCIAL RESULTS
    
    
    M3DISCONTINUED OPERATIONS
    
    
    M15LIQUIDITY AND CAPITAL RESOURCES
    
    
    M16OUTSTANDING SHARE DATA
    
    
    M17CONTRACTUAL OBLIGATIONS
AND CONTINGENCIES
    
    
    M18ACCOUNTING POLICIES AND ESTIMATES
    
    
    M19RISK MANAGEMENT
    
    
    M21OUTLOOK
    
    
    M23ADVISORIES
    
    
    M24
 Certain terms used in this MD&A (and not otherwise defined) are defined in the notes regarding Oil
and Gas Information, Currency, Non-GAAP Measures and References to EnCana, found at the end of this
MD&A. SUMMARY OF KEY EVENTS AND FINANCIAL RESULTS IN 2004  
    Total sales volumes increased 16 percent to 4,560 million cubic feet of gas (MMcf) equivalent per day (MMcfe/d) comprised of 2,998 MMcf/d of natural gas and 260,383 barrels per day (bbls/d) of liquids.  
    Average sales prices, excluding financial hedges, increased 12 percent for North American natural gas and 27 percent for North American liquids.  
    EnCana recorded total realized commodity and currency hedging losses of approximately $0.7 billion after tax.  
    EnCana purchased approximately 20 million shares under the Normal Course Issuer Bid for a total cost of $1 billion.  
    As part of the sharpening of EnCanas strategic focus to
unconventional resource plays, the Company:  
    Acquired Tom Brown, Inc. (TBI) on May 19,
2004 for approximately $2.7 billion, contributing approximately 194 MMcfe/d to EnCanas annual production;
    Sold its United Kingdom (U.K.) operations for
approximately $2.1 billion on December 1, 2004;
    Completed approximately $1.4 billion in mature, North
American conventional property dispositions during 2004; and
    Initiated a strategic review of its Ecuador assets and has
announced that these assets are for sale. OVERVIEW EnCana is a leading independent North American oil and gas company. EnCana pursues predictable,
profitable growth from its portfolio of long-life resource plays situated in Canada and the United
States. EnCanas disciplined pursuit of these unconventional
resources has enabled it to become North
Americas leading natural gas producer and a technical and cost performance leader in the
development of oilsands through in-situ recovery. EnCana reports the results of its continuing operations under two business segments:  
    Upstream, which focuses on the Companys exploration for and development and production of natural gas, crude oil and natural gas liquids (NGLs), and other related activities.
    Midstream & Market Optimization, which is conducted by the Midstream & Marketing
division. Midstream focuses on natural gas storage operations, NGLs processing and power
generation operations. Marketing undertakes market optimization activities to enhance the
sale of Upstreams proprietary production. Market optimization results reflect third party
purchases and sales of product which provide operational flexibility for transportation
commitments, product type, delivery points and customer diversification. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M1




---



##### 



BUSINESS ENVIRONMENT NATURAL GAS
Lack of overall North American industry natural gas supply combined with increasing demand and
the influence of high crude oil prices have continued to result in historically high average NYMEX
gas prices. Higher average AECO gas prices in 2004 can be attributed to an increased NYMEX index
partially offset by wider AECO differentials from NYMEX combined with the appreciation of the
U.S./Canadian dollar exchange rate. The increased AECO/NYMEX basis differential in 2004 compared to
2003 can be attributed to increased transportation differentials for the incremental sales volumes
transported from Alberta to Eastern Canada. Natural Gas Price Benchmarks 2004 vs
    
    
    
    
    
    
    2003 vs(average for the period)
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002AECO Price (C$/Mcf)
    
    $
    6.79
    
    
    
    1
    %
    
    $
    6.70
    
    
    
    65
    %
    
    $
    4.07NYMEX Price ($/MMBtu)
    
    
    6.14
    
    
    
    14
    %
    
    
    5.39
    
    
    
    67
    %
    
    
    3.22Rockies (Opal) Price ($/MMBtu)
    
    
    5.23
    
    
    
    27
    %
    
    
    4.12
    
    
    
    103
    %
    
    
    2.03AECO/NYMEX Basis Differential ($/MMBtu)
    
    
    0.91
    
    
    
    40
    %
    
    
    0.65
    
    
    
    -2
    %
    
    
    0.66Rockies/NYMEX Basis Differential ($/MMBtu)
    
    
    0.91
    
    
    
    -28
    %
    
    
    1.27
    
    
    
    7
    %
    
    
    1.19
 CRUDE OIL
The West Texas Intermediate (WTI) crude oil price was significantly higher both in the fourth
quarter and for the year of 2004 compared to the corresponding periods in 2003. This was caused by
continued world oil demand strength, primarily in Asia and North America, and during the fourth
quarter, concerns over winter heating oil supplies in North America. The world oil price in the
fourth quarter was further supported by supply uncertainties in the Middle East and West Africa, as
well as reduced supply from the Gulf of Mexico, the North Sea, Russia and Canada. OPECs reaction
to high prices resulted in an increase in production over the course of the year. However, the
incremental production was a heavier and more sour blend of crude oil than WTI and put added
pressure on light to heavy oil price differentials. The WTI/Bow River heavy oil differential widened in the fourth quarter of 2004 to record levels
primarily due to the higher price for WTI, as well as wider U.S. Gulf Coast light to heavy product
differentials and increased Canadian heavy crude-on-crude competition. As a percentage of WTI, Bow
River Blend average sales price for the fourth quarter of 2004 was 60 percent of WTI compared to 69
percent in the fourth quarter of 2003. On a year over year basis, the WTI/Bow River heavy oil differential was higher primarily as a
result of the increase in WTI. NAPO blend in Ecuador is a heavier crude than the SOTE Oriente blend
(previously the predominant crude oil from Ecuador) resulting in a wider differential to WTI. The
fourth quarter and annual 2004 increases in the WTI/Oriente differential compared to the same
periods in 2003 are primarily related to the increase in the WTI price as well as wider U.S. Gulf
Coast light to heavy product differentials. Crude Oil Price Benchmarks 2004 vs
    
    
    
    
    
    
    2003 vs(average for the period, unless otherwise noted)
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002WTI ($/bbl)
    
    $
    41.47
    
    
    
    34
    %
    
    $
    30.99
    
    
    
    19
    %
    
    $
    26.15Dated Brent ($/bbl)
    
    
    38.27
    
    
    
    33
    %
    
    
    28.83
    
    
    
    15
    %
    
    
    25.02WTI/Bow River Differential ($/bbl)
    
    
    12.82
    
    
    
    60
    %
    
    
    8.01
    
    
    
    35
    %
    
    
    5.93WTI/OCP NAPO Differential (Ecuador) ($/bbl)(1)
    
    
    14.33
    
    
    
    78
    %
    
    
    8.06
    
    
    
    
    
    
    
    WTI/Oriente Differential (Ecuador) ($/bbl)
    
    
    11.12
    
    
    
    99
    %
    
    
    5.59
    
    
    
    34
    %
    
    
    4.16
  (1)
    The WTI/ OCP NAPO Differential was posted as of September 2003. U.S./CANADIAN DOLLAR EXCHANGE RATES
The 2004 year-end U.S./Canadian dollar exchange rate of US$0.831 per C$1 increased by seven
percent compared with the 2003 year-end rate of $0.774. The 2003 year-end rate increased by 22
percent when compared with the 2002 year-end rate of $0.633. The increased value of the Canadian dollar has resulted primarily from continuing differences
between Canadian and U.S. interest rates and the U.S. current account deficit. (U.S.-CANADIAN EXCHANGE RATES LINE CHART) ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M2




---



##### 



CONSOLIDATED FINANCIAL RESULTS SUMMARY 2004 vs. 2003
Cash flow increased to $5 billion from $4.5 billion, an increase of $0.5 billion or $1.34 per share
diluted. Higher commodity prices and growth in sales volumes were partially offset by realized
financial commodity and currency hedge losses and increased expenses. Cash flow from continuing
operations also increased $0.5 billion, or $1.22 per share diluted, to a total of $4.6 billion in
2004 compared to $4.1 billion in 2003. Net earnings increased $1.1 billion to $3.5 billion in 2004. Included in net earnings is a $1.4
billion gain on the sale of the U.K. discontinued operations. EnCanas net earnings from continuing
operations in 2004 are $2.2 billion compared with $2.1 billion in 2003. Higher volumes and prices
in 2004 were offset by increased expenses and increased depreciation, depletion and amortization
(DD&A). Net earnings in 2004 include an unrealized after tax gain of $229 million on Canadian
issued U.S. denominated debt resulting from the increase in the value of the Canadian dollar and an
unrealized after tax mark-to-market accounting loss of $165 million. 2003 vs. 2002
Cash flow increased 84 percent and net earnings increased 191 percent compared with 2002 as a
result of growth in sales volumes, higher commodity prices and the inclusion of a full year of post
merger operations, partially offset by increased expenses. Net earnings for the year also included an unrealized after-tax gain on the U.S. denominated debt
issued in Canada of $433 million, or $0.90 per share diluted resulting from the increase in the
value of the Canadian dollar versus the U.S. dollar, and a $359 million, or $0.75 per share diluted
recovery of future income taxes resulting from reductions in the Canadian federal and Alberta
corporate income tax rates. Cash flow from continuing operations and net earnings from continuing operations increased 101
percent and 222 percent, respectively, compared to 2002. ACQUISITIONS AND DIVESTITURES In May 2004, the Company successfully completed its cash tender offer for all of the
outstanding common shares of TBI which became an indirect wholly owned subsidiary following the
merger of TBI and another of the Companys indirect wholly owned subsidiaries. The total
consideration was approximately $2.3 billion plus the assumed debt of TBI of approximately $0.4
billion. The TBI assets are primarily strong growth long-life North American resource play assets,
contributing approximately 194 MMcfe/d (32,300 BOE/d) to EnCanas annual production in 2004, which
complement existing Company assets and are consistent with managements strategic focus. In December 2004, a subsidiary of the Company sold its U.K. operations for approximately $2.1
billion. These assets included interests in the Buzzard, Scott and Telford oil fields, plus
interests in other satellite discoveries and exploration licences in the U.K. central North Sea. In
the first quarter of 2004, an EnCana subsidiary completed the purchase, through two separate
transactions, of additional interests in the North Sea, for net cash consideration of approximately
$131 million. In line with the Companys strategy of focusing on its inventory of North American resource play
assets in 2004, the Company disposed of a number of mature conventional producing assets. The
Company recorded proceeds of approximately $1.1 billion on the sales of conventional oil and
natural gas assets which were primarily located in western Canada. At the time of disposition,
these assets were producing approximately 200 MMcfe/d (33,770 BOE/d). In February 2004, the Company sold its 53.3 percent partnership interest in Petrovera Resources
(Petrovera) for net cash consideration of approximately $287 million including working capital
adjustments. Petroveras production was approximately 120 MMcfe/d (20,000 BOE/d) of primarily heavy
crude oil at the time of disposition. In December 2004, the Company sold its interest in the Alberta Ethane Gathering System for
approximately $108 million. Proceeds received from the non-core divestitures described above have been used to repay debt,
purchase EnCana shares and for general corporate purposes. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M3




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##### 



Consolidated Financial Summary
    
    
    
    
    
    2004 vs
    
    
    
    
    
    
    2003 vs($ millions, except per share amounts)
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002Cash Flow(1)
    
    $
    4,980
    
    
    
    12
    %
    
    $
    4,459
    
    
    
    84
    %
    
    $
    2,419- per share  basic
    
    
    10.82
    
    
    
    15
    %
    
    
    9.41
    
    
    
    63
    %
    
    
    5.79- per share  diluted
    
    
    10.64
    
    
    
    14
    %
    
    
    9.30
    
    
    
    63
    %
    
    
    5.72Net Earnings
    
    
    3,513
    
    
    
    49
    %
    
    
    2,360
    
    
    
    191
    %
    
    
    812- per share  basic
    
    
    7.63
    
    
    
    53
    %
    
    
    4.98
    
    
    
    157
    %
    
    
    1.94- per share  diluted
    
    
    7.51
    
    
    
    53
    %
    
    
    4.92
    
    
    
    156
    %
    
    
    1.92Operating Earnings(2)
    
    
    1,976
    
    
    
    41
    %
    
    
    1,399
    
    
    
    78
    %
    
    
    787- per share  diluted
    
    
    4.22
    
    
    
    45
    %
    
    
    2.92
    
    
    
    57
    %
    
    
    1.86Cash Flow from Continuing Operations(1)
    
    
    4,605
    
    
    
    11
    %
    
    
    4,135
    
    
    
    101
    %
    
    
    2,059- per share  basic
    
    
    10.00
    
    
    
    15
    %
    
    
    8.72
    
    
    
    77
    %
    
    
    4.93- per share  diluted
    
    
    9.84
    
    
    
    14
    %
    
    
    8.62
    
    
    
    77
    %
    
    
    4.87Net Earnings from Continuing Operations
    
    
    2,211
    
    
    
    3
    %
    
    
    2,142
    
    
    
    222
    %
    
    
    666- per share  basic
    
    
    4.80
    
    
    
    6
    %
    
    
    4.52
    
    
    
    184
    %
    
    
    1.59- per share  diluted
    
    
    4.72
    
    
    
    6
    %
    
    
    4.47
    
    
    
    183
    %
    
    
    1.58Operating Earnings from Continuing Operations (2)
    
    
    1,989
    
    
    
    47
    %
    
    
    1,350
    
    
    
    115
    %
    
    
    629- per share  diluted
    
    
    4.25
    
    
    
    51
    %
    
    
    2.82
    
    
    
    89
    %
    
    
    1.49Revenues, Net of Royalties
    
    
    11,810
    
    
    
    22
    %
    
    
    9,686
    
    
    
    63
    %
    
    
    5,928Total Assets
    
    
    31,213
    
    
    
    29
    %
    
    
    24,110
    
    
    
    21
    %
    
    
    19,912Long-Term Debt
    
    
    7,742
    
    
    
    27
    %
    
    
    6,088
    
    
    
    21
    %
    
    
    5,051Cash Dividends(3)
    
    
    183
    
    
    
    32
    %
    
    
    139
    
    
    
    29
    %
    
    
    108
   (1)
    
    Cash Flow and Cash Flow from Continuing Operations are non-GAAP measures and
are discussed under Cash Flow in this MD&A.(2)
    
    Operating Earnings and Operating Earnings from Continuing Operations are
non-GAAP measures and are described and discussed under Operating Earnings in this
MD&A.(3)
    
    Represents cash dividends paid to common shareholders at the rate of US$0.40
per share annually except for 2003 and
2002 which were paid
at the rate of
C$0.40 per share
annually. Quarterly Summary
    
    2004
    
    
    2003($ millions, except per share amounts)
    
    Q4
    
    
    Q3
    
    
    Q2
    
    
    Q1
    
    
    Q4
    
    
    Q3
    
    
    Q2
    
    
    Q1Cash Flow(1)
    
    $
    1,491
    
    
    $
    1,363
    
    
    $
    1,131
    
    
    $
    995
    
    
    $
    1,254
    
    
    $
    977
    
    
    $
    1,007
    
    
    $
    1,221- per share  basic
    
    
    3.25
    
    
    
    2.95
    
    
    
    2.46
    
    
    
    2.16
    
    
    
    2.71
    
    
    
    2.06
    
    
    
    2.10
    
    
    
    2.54- per share  diluted
    
    
    3.21
    
    
    
    2.92
    
    
    
    2.43
    
    
    
    2.13
    
    
    
    2.69
    
    
    
    2.04
    
    
    
    2.08
    
    
    
    2.52Net Earnings
    
    
    2,580
    
    
    
    393
    
    
    
    250
    
    
    
    290
    
    
    
    426
    
    
    
    290
    
    
    
    807
    
    
    
    837- per share  basic
    
    
    5.62
    
    
    
    0.85
    
    
    
    0.54
    
    
    
    0.63
    
    
    
    0.92
    
    
    
    0.61
    
    
    
    1.68
    
    
    
    1.74- per share  diluted
    
    
    5.55
    
    
    
    0.84
    
    
    
    0.54
    
    
    
    0.62
    
    
    
    0.91
    
    
    
    0.61
    
    
    
    1.67
    
    
    
    1.73Operating Earnings(2)
    
    
    573
    
    
    
    559
    
    
    
    379
    
    
    
    465
    
    
    
    316
    
    
    
    278
    
    
    
    277
    
    
    
    528- per share  diluted
    
    
    1.23
    
    
    
    1.20
    
    
    
    0.81
    
    
    
    1.00
    
    
    
    0.68
    
    
    
    0.58
    
    
    
    0.57
    
    
    
    1.09Cash Flow from Continuing Operations(1)
    
    
    1,429
    
    
    
    1,259
    
    
    
    1,021
    
    
    
    896
    
    
    
    1,103
    
    
    
    918
    
    
    
    990
    
    
    
    1,124- per share  basic
    
    
    3.11
    
    
    
    2.73
    
    
    
    2.22
    
    
    
    1.94
    
    
    
    2.39
    
    
    
    1.94
    
    
    
    2.06
    
    
    
    2.34- per share  diluted
    
    
    3.07
    
    
    
    2.70
    
    
    
    2.19
    
    
    
    1.92
    
    
    
    2.37
    
    
    
    1.92
    
    
    
    2.04
    
    
    
    2.32Net Earnings from Continuing Operations
    
    
    1,188
    
    
    
    432
    
    
    
    265
    
    
    
    326
    
    
    
    447
    
    
    
    266
    
    
    
    801
    
    
    
    628- per share  basic
    
    
    2.59
    
    
    
    0.94
    
    
    
    0.58
    
    
    
    0.71
    
    
    
    0.97
    
    
    
    0.56
    
    
    
    1.67
    
    
    
    1.31- per share  diluted
    
    
    2.56
    
    
    
    0.93
    
    
    
    0.57
    
    
    
    0.70
    
    
    
    0.96
    
    
    
    0.56
    
    
    
    1.65
    
    
    
    1.30Operating Earnings from Continuing
Operations(2)
    
    
    612
    
    
    
    553
    
    
    
    362
    
    
    
    462
    
    
    
    337
    
    
    
    254
    
    
    
    271
    
    
    
    488- per share  diluted
    
    
    1.32
    
    
    
    1.19
    
    
    
    0.78
    
    
    
    0.99
    
    
    
    0.72
    
    
    
    0.53
    
    
    
    0.56
    
    
    
    1.01Revenues, Net of Royalties
    
    
    4,208
    
    
    
    2,320
    
    
    
    2,552
    
    
    
    2,730
    
    
    
    2,639
    
    
    
    2,190
    
    
    
    2,233
    
    
    
    2,624
   (1)
    
    Cash Flow and Cash Flow from Continuing Operations are non-GAAP measures and
are discussed under Cash Flow in this MD&A.(2)
    
    Operating Earnings and Operating Earnings from Continuing Operations are non-GAAP measures and are described and
discussed under Operating Earnings in this MD&A. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M4




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##### 



CASH FLOW
EnCanas cash flow increased to $4,980 million in 2004, an increase of $521 million from 2003. This
increase reflects the Companys overall 16 percent sales volume growth, increased prices in 2004,
realized hedge losses, realized foreign exchange gains and an increase in the current income tax
provision. EnCanas discontinued operations contributed $375 million to cash flow in 2004, an
increase of $51 million from 2003. EnCanas 2004 cash flow from continuing operations increased $470 million, or $1.22 per share
diluted, to $4,605 million over 2003 with significant items as follows:  
    Natural gas sales volumes increased 16 percent to 2,968 MMcf/d.
    Average North American natural gas prices, excluding financial hedges, were $5.47 per Mcf in 2004 compared to $4.87 per Mcf in 2003, an increase of 12 percent.
    Average North American liquids prices, excluding financial hedges, were $28.77 per bbl in 2004 compared to $22.72 per bbl in 2003, an increase of 27 percent.
    Realized financial commodity and currency hedge losses included in cash flow from
continuing operations were approximately $686 million ($464 million after-tax) in 2004
compared to $259 million ($164 million after-tax) for 2003.
    Realized foreign exchange gains of $190 million ($154 million after-tax) on the settlement
of long-term debt in 2004 compared to realized gains of $86 million ($68 million after-tax)
in 2003, as a result of the rise in the U.S./Canadian dollar exchange rate and its impact on
the settlement of Canadian issued U.S. denominated debt.
    Current income tax provision increased by $680 million to $567 million in 2004 from a
recovery of $113 million in 2003 partially offsetting increased cash flow from higher volumes
and prices. Cash flow measures are considered non-GAAP but are commonly used in the oil and gas industry to
assist management and investors to measure the Companys ability to finance its capital programs
and meet its credit obligations. The calculation of cash flow is disclosed on the Consolidated
Statement of Cash Flows in the Consolidated Financial Statements. NET EARNINGS
EnCanas net earnings increased $1,153 million to $3,513 million in 2004. Included in 2004 net
earnings is a gain of $1,364 million on the sale of EnCanas U.K. operations. EnCanas net earnings from continuing operations increased $69 million, or $0.25 per share diluted
in 2004 compared with 2003. In addition to the items affecting cash flow as detailed previously,
significant items are:  
    Unrealized mark-to-market losses of $190 million ($116 million after-tax) are included in 2004 with no corresponding amount in 2003.
    Included in 2004 is a gain due to a change in tax rates of $109 million, compared to a gain of $359 million in 2003.
    A $285 million ($229 million after-tax) unrealized gain on Canadian issued U.S. dollar
debt in 2004 compared to an unrealized gain of $545 million ($433 million after-tax) in 2003.
This results from the continued strengthening in the year-end U.S./Canadian dollar exchange
rate between December 31, 2003 and December 31, 2004 compared to the change between December
31, 2002 and December 31, 2003. The impacts on results from the conversion of Canadian to U.S. dollars should be considered when
analyzing specific components contained in the Consolidated Financial Statements. For every 100
Canadian dollars spent on capital projects, operating expenses and administrative expenses, the
Company incurred additional costs of approximately US$5.20 based on the increase in the average
U.S./Canadian dollar exchange rate from $0.716 in 2003 to $0.768 in 2004. Revenues were relatively
unaffected by the increase in the exchange rate since commodity prices received are largely based
in U.S. dollars or in Canadian dollar prices which are closely tied to the value of the U.S.
dollar. Reconciliation of Net Earnings from Continuing
Operations from 2003 to 2004 ($millions) 2003 net earnings from continuing operations
    
    $
    2,142Upstream prices
    
    
    915
    (1)Upstream volumes
    
    
    864Gain on disposition of investments
    
    
    112Realized foreign exchange gain on long-term debt
    
    
    79Unrealized fair value adjustment on financial contracts
    
    
    (190
    )Unrealized foreign exchange gain on long-term debt
    
    
    (260
    )Income tax
    
    
    (294
    )Upstream expenses
    
    
    (344
    )DD&A costs
    
    
    (413
    )Realized loss on financial contracts
    
    
    (427
    )Other
    
    
    272004 net earnings from continuing operations
    
    $
    2,211
   (1)
    
    Excludes the effect of upstream financial hedging. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M5




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##### 



OPERATING EARNINGS  Summary of Operating Earnings 2004 vs
    
    
    
    
    
    
    2003 vs($ millions)
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002Net Earnings, as reported
    
    $
    3,513
    
    
    
    49
    %
    
    $
    2,360
    
    
    
    191
    %
    
    $
    812Deduct: (Gain) loss on discontinuance
    
    
    (1,364
    )
    
    
    
    
    
    
    (169
    )
    
    
    
    
    
    
    12Add: Unrealized mark-to-market accounting loss (after-tax)(2)
    
    
    165
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Deduct: Unrealized foreign exchange gain on translation of
Canadian issued U.S. dollar debt
(after-tax)
    
    
    (229
    )
    
    
    
    
    
    
    (433
    )
    
    
    
    
    
    
    (17
    )Deduct: Future tax recovery due to tax rate reductions
    
    
    (109
    )
    
    
    
    
    
    
    (359
    )
    
    
    
    
    
    
    (20
    )Operating Earnings (1)(3)
    
    $
    1,976
    
    
    
    41
    %
    
    $
    1,399
    
    
    
    78
    %
    
    $
    787($  per Common Share  Diluted)Net Earnings, as reported
    
    $
    7.51
    
    
    
    53
    %
    
    $
    4.92
    
    
    
    156
    %
    
    $
    1.92Deduct: (Gain) loss on discontinuance
    
    
    (2.92
    )
    
    
    
    
    
    
    (0.35
    )
    
    
    
    
    
    
    0.03Add: Unrealized mark-to-market accounting loss (after-tax)(2)
    
    
    0.35
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Deduct: Unrealized foreign exchange gain on translation of
Canadian issued U.S. dollar debt
(after-tax)
    
    
    (0.49
    )
    
    
    
    
    
    
    (0.90
    )
    
    
    
    
    
    
    (0.04
    )Deduct: Future tax recovery due to tax rate reductions
    
    
    (0.23
    )
    
    
    
    
    
    
    (0.75
    )
    
    
    
    
    
    
    (0.05
    )Operating Earnings (1)(3)
    
    $
    4.22
    
    
    
    45
    %
    
    $
    2.92
    
    
    
    57
    %
    
    $
    1.86
   (1)
    
    Operating Earnings is a non-GAAP measure that shows net earnings excluding the after-tax gain or loss from the
disposition of discontinued
operations, the after-tax effects of unrealized mark-to-market accounting for derivative instruments, the after-tax
gain on translation of U.S.
dollar denominated debt issued in Canada and the effect of the
reduction in income tax rates.(2)
    
    The Company adopted mark-to-market accounting on derivative financial instruments prospectively on January 1, 2004.
See Note 2 to the Consolidated Financial Statements.(3)
    
    Unrealized (gains)/ losses have
no impact on cash flow. Summary of Operating Earnings from Continuing Operations 2004 vs
    
    
    
    
    
    
    2003 vs($ millions)
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002Net Earnings from Continuing Operations, as reported
    
    $
    2,211
    
    
    
    3
    %
    
    $
    2,142
    
    
    
    222
    %
    
    $
    666Add: Unrealized mark-to-market accounting loss (after-tax)(2)
    
    
    116
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Deduct: Unrealized foreign exchange gain on translation of Canadian issued U.S. dollar debt (after-tax)
    
    
    (229
    )
    
    
    
    
    
    
    (433
    )
    
    
    
    
    
    
    (17
    )Deduct: Future tax recovery due to tax rate reductions
    
    
    (109
    )
    
    
    
    
    
    
    (359
    )
    
    
    
    
    
    
    (20
    )Operating Earnings from Continuing Operations (1)(3)
    
    $
    1,989
    
    
    
    47
    %
    
    $
    1,350
    
    
    
    115
    %
    
    $
    629($  per Common Share  Diluted)Net Earnings from Continuing Operations, as reported
    
    $
    4.72
    
    
    
    6
    %
    
    $
    4.47
    
    
    
    183
    %
    
    $
    1.58Add: Unrealized mark-to-market accounting loss (after-tax)(2)
    
    
    0.25
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Deduct: Unrealized foreign exchange gain on translation of Canadian issued U.S. dollar debt (after-tax)
    
    
    (0.49
    )
    
    
    
    
    
    
    (0.90
    )
    
    
    
    
    
    
    (0.04
    )Deduct: Future tax recovery due to tax rate reductions
    
    
    (0.23
    )
    
    
    
    
    
    
    (0.75
    )
    
    
    
    
    
    
    (0.05
    )Operating Earnings from Continuing Operations (1)(3)
    
    $
    4.25
    
    
    
    51
    %
    
    $
    2.82
    
    
    
    89
    %
    
    $
    1.49
   (1)
    
    Operating Earnings from Continuing Operations is a non-GAAP measure that shows net earnings from continuing operations excluding the
after-tax effects of unrealized mark-to-market accounting for derivative instruments, the gain on translation of U.S. dollar denominated debt
issued in Canada and the effect of the reduction in income tax rates.(2)
    
    The Company adopted mark-to-market accounting on derivative financial instruments prospectively on January 1, 2004. See Note 2 to the
Consolidated Financial Statements.(3)
    
    Unrealized (gains)/losses have no impact on cash flow. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M6




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##### 



RESULTS OF OPERATIONS UPSTREAM OPERATIONS Financial Results from Continuing Operations ($ millions)
    2004
    2003
    2002Produced
    
    
    Crude Oil
    
    
    
    
    
    
    
    
    
    
    Produced
    
    
    Crude Oil
    
    
    
    
    
    
    
    
    
    
    Produced
    
    
    Crude OilGas
    
    
    and NGLs
    
    
    Other
    
    
    Total
    
    
    Gas
    
    
    and NGLs
    
    
    Other
    
    
    Total
    
    
    Gas
    
    
    and NGLs
    
    
    Other
    
    
    TotalRevenues, Net of Royalties
    
    $
    5,704
    
    
    $
    1,320
    
    
    $
    232
    
    
    $
    7,256
    
    
    $
    4,447
    
    
    $
    1,170
    
    
    $
    180
    
    
    $
    5,797
    
    
    $
    2,280
    
    
    $
    970
    
    
    $
    76
    
    
    $
    3,326ExpensesProduction and mineral taxes
    
    
    270
    
    
    
    41
    
    
    
    
    
    
    
    311
    
    
    
    153
    
    
    
    11
    
    
    
    
    
    
    
    164
    
    
    
    82
    
    
    
    23
    
    
    
    
    
    
    
    105Transportation and selling
    
    
    416
    
    
    
    56
    
    
    
    
    
    
    
    472
    
    
    
    360
    
    
    
    69
    
    
    
    
    
    
    
    429
    
    
    
    210
    
    
    
    35
    
    
    
    
    
    
    
    245Operating
    
    
    519
    
    
    
    285
    
    
    
    222
    
    
    
    1,026
    
    
    
    402
    
    
    
    300
    
    
    
    170
    
    
    
    872
    
    
    
    290
    
    
    
    201
    
    
    
    71
    
    
    
    562Operating Cash Flow
    
    $
    4,499
    
    
    $
    938
    
    
    $
    10
    
    
    $
    5,447
    
    
    $
    3,532
    
    
    $
    790
    
    
    $
    10
    
    
    $
    4,332
    
    
    $
    1,698
    
    
    $
    711
    
    
    $
    5
    
    
    $
    2,414Depreciation, depletion and
amortization
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,271
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,900
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,115Upstream Income
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    3,176
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    2,432
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    1,299
 2004 vs. 2003
Results from continuing operations reflect a 12 percent increase in sales volumes of 418 MMcfe/d
(69,689 BOE/d) for the year ended December 31, 2004 compared with 2003. Revenues, net of royalties, reflect the increase in natural gas and crude oil benchmark prices (see
the Business Environment section of this MD&A) for the year offset by the realized hedging
losses. The effect of realized commodity and currency hedging losses for the year ended December
31, 2004 was $669 million, or $0.46 per Mcfe ($2.77 per BOE), compared to $297 million or $0.23 per
Mcfe ($1.38 per BOE) for 2003. North American production and mineral taxes for produced gas increased 76 percent in 2004 compared
to 2003 primarily due to increased natural gas prices and volumes in the United States and a higher
effective tax rate on production growth in Colorado. Transportation and selling expenses increased ten percent in 2004 as a result of increased natural
gas volumes in the U.S. and Canada and the impact of the change in the average U.S./Canadian dollar
exchange rate on Canadian dollar denominated transactions. For the year ended December 31, 2004, operating expenses were slightly higher at $0.55 per Mcfe
($3.33 per BOE) compared to $0.54 per Mcfe ($3.26 per BOE) for the same period in 2003 due
primarily to the increase in the average U.S./Canadian dollar exchange rate during 2004. Excluding
the impact of foreign exchange, operating expenses in 2004 would have decreased to $0.51 per Mcfe
($3.10 per BOE) primarily as a result of increased volumes. DD&A expense increased by $371 million in 2004 compared to 2003 primarily as a result of increased
sales volumes and the impact of the higher value of the Canadian dollar compared to the U.S. dollar
applied to Canadian dollar denominated DD&A expense. On a North America basis, excluding Other
activities, DD&A rates were $1.53 per Mcfe ($9.20 per BOE) for 2004 compared to $1.39 per Mcfe
($8.36 per BOE) in 2003. Increased DD&A rates in 2004 were primarily the result of the increase in
the average U.S./Canadian dollar exchange rate and the impact of the acquisition cost of TBI. DD&A
rates for the year ended December 31, 2004 exclude impairments
of exploration prospects in Ghana, Bahrain and other areas of $23 million, which were recorded in the second and
fourth quarters of 2004, respectively. 2003 vs. 2002
The Companys 2003 Upstream revenues, net of royalties, increased $2,471 million, or 74 percent,
over 2002 due to the increase in commodity prices, growth in sales volumes and the inclusion of a
full year of post merger results. The 23 percent growth in sales volumes from continuing operations
of 675 MMcfe/d (112,585 BOE/d) for the year ended December 31, 2003, compared to 2002, reflected
increased production in the U.S., the addition of a full year of post merger volumes and the
expansion of production from the Companys Steam Assisted Gravity Drainage (SAGD) projects. Production and mineral tax increases in 2003 were the result of higher prices in the U.S. and a
full year of post merger results. The increased transportation and selling expenses in 2003 were attributable to growth in North
American volumes, a full year of post merger results and the effect of the change in the average
U.S./Canadian dollar exchange rate on Canadian dollar denominated transportation and selling
expenses. Upstream operating costs increased 55 percent compared to 2002 due to additional production
volumes, a full year of post merger results, the change in the average U.S./Canadian dollar
exchange rate and its impact on Canadian dollar denominated operating expenses, as well as
increased costs for maintenance, workovers, higher fuel and power expense due to higher natural gas
prices and an increased proportionate share of costs from SAGD operations. DD&A expense increased by $785 million in 2003 compared to 2002. On a North America basis,
excluding Other activities, DD&A rates were $1.39 per Mcfe ($8.36 per BOE) for 2003 compared to
$1.01 per Mcfe ($6.09 per BOE) in 2002. The increased DD&A rate in 2003 reflects increased future
development costs related to the proved reserves added for SAGD projects and the U.S., and the
effect of the increase in the average U.S./Canadian dollar exchange rate on the Canadian dollar
denominated DD&A expense. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M7




---



##### 



Revenue Variances for 2004 compared to 2003 and 2003 compared to 2002
From Continuing Operations ($ millions)
    
    
    2004
    
    
    20032003
    
    
    Revenue
    
    
    2004
    
    
    2002
    
    
    Revenue
    
    
    2003Revenues,
    
    
    Variances
    
    
    Revenues,
    
    
    Revenues,
    
    
    Variances
    
    
    Revenues,Net of
    
    
    in:
    
    
    Net of
    
    
    Net of
    
    
    in:
    
    
    Net ofRoyalties
    
    
    Price(1)
    
    
    Volume
    
    
    Royalties
    
    
    Royalties
    
    
    Price(1)
    
    
    Volume
    
    
    RoyaltiesProduced GasCanada
    
    $
    3,396
    
    
    $
    271
    
    
    $
    261
    
    
    $
    3,928
    
    
    $
    1,882
    
    
    $
    1,075
    
    
    $
    439
    
    
    $
    3,396United States
    
    
    1,051
    
    
    
    147
    
    
    
    578
    
    
    
    1,776
    
    
    
    398
    
    
    
    204
    
    
    
    449
    
    
    
    1,051Total Produced Gas
    
    $
    4,447
    
    
    $
    418
    
    
    $
    839
    
    
    $
    5,704
    
    
    $
    2,280
    
    
    $
    1,279
    
    
    $
    888
    
    
    $
    4,447Crude Oil and NGLsCanada
    
    $
    1,078
    
    
    $
    95
    
    
    $
    (18
    )
    
    $
    1,155
    
    
    $
    914
    
    
    $
    (11
    )
    
    $
    175
    
    
    $
    1,078United States
    
    
    92
    
    
    
    30
    
    
    
    43
    
    
    
    165
    
    
    
    56
    
    
    
    6
    
    
    
    30
    
    
    
    92Total Crude Oil and NGLs
    
    $
    1,170
    
    
    $
    125
    
    
    $
    25
    
    
    $
    1,320
    
    
    $
    970
    
    
    $
    (5
    )
    
    $
    205
    
    
    $
    1,170
   (1)
    
    Includes realized commodity and currency hedging impacts. The increase in sales volumes accounts for approximately 61 percent of the change in revenues, net
of royalties, for 2004 compared with 2003. In the table above, impacts from price changes are
reduced as a result of the year over year changes in realized commodity and currency hedge losses
mentioned previously. The Crude Oil and NGLs volume variance in Canada of $(18) million for 2004 compared with 2003 was
mainly due to the dispositions of mature conventional producing assets during 2004. Sales Volumes 2004 vs
    
    
    
    
    
    
    2003 vs2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002Produced Gas (million cubic feet per day)
    
    
    2,968
    
    
    
    16
    %
    
    
    2,553
    
    
    
    25
    %
    
    
    2,048Crude Oil (barrels per day)
    
    
    140,379
    
    
    
    -1
    %
    
    
    142,326
    
    
    
    21
    %
    
    
    117,218NGLs (barrels per day)
    
    
    26,038
    
    
    
    10
    %
    
    
    23,569
    
    
    
    16
    %
    
    
    20,259Continuing Operations (million cubic feet equivalent per day)(1)
    
    
    3,966
    
    
    
    12
    %
    
    
    3,548
    
    
    
    23
    %
    
    
    2,873Continuing Operations (barrels of oil equivalent per day)(2)
    
    
    661,084
    
    
    
    12
    %
    
    
    591,395
    
    
    
    23
    %
    
    
    478,810Discontinued OperationsEcuador (barrels per day)
    
    
    77,993
    
    
    
    68
    %
    
    
    46,521
    
    
    
    56
    %
    
    
    29,740United Kingdom (barrels of oil equivalent per day)(2)
    
    
    20,973
    
    
    
    71
    %
    
    
    12,295
    
    
    
    1
    %
    
    
    12,195Syncrude (barrels per day)
    
    
    
    
    
    
    
    
    
    
    7,629
    
    
    
    -68
    %
    
    
    23,540Discontinued Operations (million cubic feet equivalent per day)(1)
    
    
    594
    
    
    
    49
    %
    
    
    399
    
    
    
    2
    %
    
    
    393Total (million cubic feet equivalent per day)(1)
    
    
    4,560
    
    
    
    16
    %
    
    
    3,947
    
    
    
    21
    %
    
    
    3,266Total (barrels of oil equivalent per day)(2)
    
    
    760,050
    
    
    
    16
    %
    
    
    657,840
    
    
    
    21
    %
    
    
    544,285
   (1)
    
    Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet.(2)
    
    Includes natural gas and liquids (converted to BOE). In 2004, volumes from continuing operations were higher by 12 percent, or 418 MMcfe/d (69,689
BOE/d), compared to 2003. Canadian natural gas sales volumes increased approximately seven percent or 134 MMcf/d in 2004.
This increase results mostly from successful resource play drilling programs at Greater Sierra and
Cutbank Ridge in northeast British Columbia as well as Shallow Gas in southern Alberta; the
increased volumes were partially reduced by the disposition of non-core properties during 2004,
producing approximately 56 MMcf/d on an annualized basis. Natural gas sales volumes in the United
States increased approximately 48 percent or 281 MMcf/d during 2004 primarily due to successful
resource play drilling programs in the Piceance and Fort Worth basins and incremental production of
161 MMcf/d from the TBI acquisition. In 2004, liquids sales volumes were relatively unchanged when compared to 2003. The impacts of
continued development at Foster Creek, successful drilling programs at Suffield and Weyburn, and
positive response from the waterflood program at Pelican Lake were offset by the Petrovera and
other non-core dispositions in the first and third quarters of 2004, respectively, which reduced
production by 19,800 bbls/d on an annualized basis. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M8




---



##### 



Highlights:  
    Greater Sierra
Natural gas production averaged 230 MMcf/d, an increase of 61 percent (or 87 MMcf/d) in 2004
mainly due to the success of the 2003/2004 drilling program. In 2004, 187 net wells were drilled.
    Cutbank Ridge
2004 was the first full year of operations. Natural gas production averaged 40 MMcf/d and exited the year at 47 MMcf/d. In 2004, 50 net wells were drilled.
    Coalbed Methane
Natural gas production in 2004 exited the year at 30 MMcf/d and averaged 17 MMcf/d, up from 4 MMcf/d in 2003. During the year, 577 net wells were drilled.
    Shallow Gas
During 2004, natural gas production increased 17 percent to 592 MMcf/d with 1,552 net wells drilled.
    Piceance
Natural gas production averaged 261 MMcf/d in 2004, an increase of 73 percent or 110 MMcf/d
compared to 2003. This increase is the result of a successful drilling program (250 net wells)
and the TBI acquisition.
    Fort Worth
EnCana acquired assets in the Fort Worth Basin in 2003 with the Savannah Energy Inc. acquisition
and added to those assets as a result of a December 2004 property acquisition. Production
averaged 27 MMcf/d in 2004.
    East Texas
East Texas, which produced 50 MMcf/d during 2004, was acquired as part of the TBI acquisition. During 2004, 50 net wells were drilled.
    Foster Creek
Completion of the first phase of facility expansion in the fall of 2003 resulted in a 32 percent increase in 2004 crude oil production to 28,800 bbls/d.
    Pelican Lake
Average crude oil production in 2004 increased 19 percent to 18,900 bbls/d due to the response of
the waterflood program which began in the last half of 2004. Per Unit Results  Produced Gas($  per thousand cubic feet) Canada
    
    
    United States2004 vs
    
    
    
    
    
    
    2003 vs
    
    
    
    
    
    
    
    
    
    
    2004 vs
    
    
    
    
    
    
    2003 vs2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002Price(1)
    
    $
    5.34
    
    
    
    10
    %
    
    $
    4.87
    
    
    
    70
    %
    
    $
    2.86
    
    
    $
    5.79
    
    
    
    19
    %
    
    $
    4.88
    
    
    
    65
    %
    
    $
    2.96ExpensesProduction and mineral taxes
    
    
    0.08
    
    
    
    14
    %
    
    
    0.07
    
    
    
    -13
    %
    
    
    0.08
    
    
    
    0.65
    
    
    
    38
    %
    
    
    0.47
    
    
    
    74
    %
    
    
    0.27Transportation and selling(2)
    
    
    0.39
    
    
    
    3
    %
    
    
    0.38
    
    
    
    58
    %
    
    
    0.24
    
    
    
    0.31
    
    
    
    -23
    %
    
    
    0.40
    
    
    
    -15
    %
    
    
    0.47Operating
    
    
    0.52
    
    
    
    8
    %
    
    
    0.48
    
    
    
    17
    %
    
    
    0.41
    
    
    
    0.37
    
    
    
    32
    %
    
    
    0.28
    
    
    
    
    
    
    
    0.28Netback
    
    $
    4.35
    
    
    
    
    
    
    $
    3.94
    
    
    
    
    
    
    $
    2.13
    
    
    $
    4.46
    
    
    
    
    
    
    $
    3.73
    
    
    
    
    
    
    $
    1.94Gas Sales Volumes (MMcf per day)
    
    
    2,099
    
    
    
    7
    %
    
    
    1,965
    
    
    
    15
    %
    
    
    1,711
    
    
    
    869
    
    
    
    48
    %
    
    
    588
    
    
    
    74
    %
    
    
    337
   (1)
    
    Excludes realized commodity and currency hedge activities.(2)
    
    U.S. per unit transportation and selling costs in 2004 exclude a one-time payment of $21 million made to terminate a long-term physical delivery contract. Benchmark natural gas NYMEX prices were higher by 14 percent compared with 2003, however this
increase has been partially offset by increased natural gas price differentials in Canada. For the
year ended December 31, 2004, realized commodity and currency hedging losses on natural gas were
approximately $238 million, or $0.22 per Mcf compared to a loss of approximately $91 million, or
$0.10 per Mcf in 2003. Certain of these hedges were put in place to secure the economics of the TBI
acquisition. Per unit production and mineral taxes in the U.S. for the year ended December 31, 2004 compared to
2003 increased 38 percent or $0.18 per Mcf due to a combination of higher gas prices and a higher
effective tax rate on the significant production growth in Colorado. Natural gas per unit transportation and selling costs for the U.S. have decreased 23 percent or
$0.09 per Mcf for the year ended December 31, 2004 compared to 2003, primarily as a result of the
TBI acquisition where a majority of the production is sold at the wellhead and does not incur
transportation charges. Canadian natural gas per unit operating expenses for 2004 were eight percent or $0.04 per Mcf
higher compared to 2003 primarily due to the higher U.S./Canadian exchange rates. Increases in the
U.S. per unit natural gas operating expenses of 32 percent or $0.09 per Mcf for the year ended
December 31, 2004 compared to 2003 were a result of higher operating expenses from the TBI
properties, incremental operating costs associated with waste water disposal in Colorado and other
non-recurring charges related to the prior year. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M9




---



##### 



Average realized prices for natural gas in the U.S. and Canada for 2003 increased by approximately
65 percent and 70 percent respectively, over 2002 due to concerns about overall North American
storage inventory levels and a lack of confidence concerning prospects for North American supply
growth. Realized commodity and currency hedging gains in 2002 for natural gas were $66 million, or
$0.09 per Mcf. Per unit production and mineral tax expense in the U.S. was $0.20 per Mcf higher in 2003 than 2002
due to higher natural gas prices. For Canadian produced gas operations, per unit transportation and selling costs were higher in 2003
compared to 2002 by $0.14 per Mcf due to an increased proportion of sales transported to more
distant markets and the change in the U.S./Canadian dollar exchange rate. Per unit operating expenses for Canadian produced gas were higher in 2003 compared to 2002 by $0.07
per Mcf as a result of increased maintenance, workovers, the effect of the change in the
U.S./Canadian dollar exchange rate and production from higher operating cost areas. Per Unit Results  Crude Oil($  per barrel) North America2004 vs
    
    
    
    
    
    
    2003 vs2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002Price(1)
    
    $
    27.92
    
    
    
    25
    %
    
    $
    22.29
    
    
    
    11
    %
    
    $
    20.08ExpensesProduction and mineral taxes
    
    
    0.41
    
    
    
    356
    %
    
    
    0.09
    
    
    
    -79
    %
    
    
    0.43Transportation and selling
    
    
    1.06
    
    
    
    -19
    %
    
    
    1.31
    
    
    
    60
    %
    
    
    0.82Operating
    
    
    5.53
    
    
    
    -5
    %
    
    
    5.80
    
    
    
    24
    %
    
    
    4.69Netback
    
    $
    20.92
    
    
    
    
    
    
    $
    15.09
    
    
    
    
    
    
    $
    14.14Crude Oil Sales Volumes (bbls per day)
    
    
    140,379
    
    
    
    -1
    %
    
    
    142,326
    
    
    
    21
    %
    
    
    117,218
   (1)
    
    Excludes realized commodity and currency hedge activities. Increases in the average crude oil price in 2004, excluding the impact of financial hedges, reflect
the increase in the benchmark WTI which increased 34 percent in 2004 compared to 2003. This
increase was partially offset by the increased WTI/Bow River crude oil price differential (up
approximately 60 percent) and a higher proportionate share of heavier blend oils in the product
mix. Realized commodity and currency hedging losses on crude oil were approximately $431 million,
or $7.08 per bbl of liquids in 2004 compared to a loss of approximately $206 million, or $3.41 per
bbl of liquids in 2003. North American per unit production and mineral taxes increased in 2004 primarily as a result of
mineral tax amendments related to prior years that were recorded in the third quarter of 2003.
Higher freehold mineral tax and Saskatchewan surtax in the Weyburn area resulted from higher prices
and increased production. The 2004 per unit crude oil transportation and selling expenses in North America have decreased
$0.25 per bbl mainly due to an adjustment in oil transportation rates. North American crude oil per unit operating costs for 2004 have decreased $0.27 per bbl compared to
2003 mainly due to the sale of Petrovera, which had higher operating costs relative to other
properties. This reduction was partially offset by the effect of increased U.S./Canadian exchange
rates and higher fuel gas costs for the SAGD projects. Average realized crude oil prices in 2003 increased approximately 11 percent over 2002 as a result
of concerns over tensions in the Middle East combined with strong Asian demand and OPECs
management of its production quotas. Realized commodity and currency hedging losses in 2002 on
crude oil were $32 million, or $0.64 per bbl of liquids. Per unit transportation and selling costs were higher by $0.49 per bbl over 2002 as a result of
increased heavy crude oil volumes which attract a 20 percent premium transportation charge over
light crude oil combined with annual tariff increases. The increase in per unit operating expenses of $1.11 per bbl for 2003 compared to 2002 is
attributable to the increase in the U.S./Canadian dollar exchange rate, higher maintenance costs
and increased production weighting of heavy oil volumes from SAGD projects, which have higher
operating expenses, combined with higher fuel and electricity costs resulting from the rise in
natural gas prices. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M10




---



##### 



Per Unit Results 
NGLs(1) ($  per barrel) Canada
    
    
    United States2004 vs
    
    
    
    
    
    
    2003 vs
    
    
    
    
    
    
    
    
    
    
    2004 vs
    
    
    
    
    
    
    2003 vs2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002Price
    
    $
    31.43
    
    
    
    30
    %
    
    $
    24.26
    
    
    
    38
    %
    
    $
    17.55
    
    
    $
    35.43
    
    
    
    31
    %
    
    $
    26.97
    
    
    
    14
    %
    
    $
    23.75ExpensesProduction and mineral taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3.82
    
    
    
    88
    %
    
    
    2.03
    
    
    
    99
    %
    
    
    1.02Transportation and selling
    
    
    0.41
    
    
    
    141
    %
    
    
    0.17
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Netback
    
    $
    31.02
    
    
    
    
    
    
    $
    24.09
    
    
    
    
    
    
    $
    17.55
    
    
    $
    31.61
    
    
    
    
    
    
    $
    24.94
    
    
    
    
    
    
    $
    22.73NGLs Sales Volumes (bbls per day)
    
    
    13,452
    
    
    
    -6
    %
    
    
    14,278
    
    
    
    3
    %
    
    
    13,852
    
    
    
    12,586
    
    
    
    35
    %
    
    
    9,291
    
    
    
    45
    %
    
    
    6,407
   (1)
    
    NGLs results include Condensate. NGLs realized price changes generally correlate with changes in WTI oil prices. The strong WTI oil
price in 2004 positively impacted NGLs prices. U.S. per unit production and mineral taxes for the year ended December 31, 2004 compared to 2003
increased by 88 percent or $1.79 per bbl. Higher NGLs prices in 2004 and increased production
growth in Colorado, which has a higher effective production tax rate, were the key reasons for this
increase. Per unit transportation and selling costs for NGLs in Canada increased by 141 percent or $0.24 per
bbl in 2004 compared to 2003 as the Company incurred a full year of trucking charges for volumes in
northeast British Columbia that came onstream in the fall of 2003. MIDSTREAM & MARKET OPTIMIZATION OPERATIONS Financial Results ($ millions)
    

2004
    
    
    2003
    
    
    2002Market
    
    
    
    
    
    
    
    
    
    
    Market
    
    
    
    
    
    
    
    
    
    
    MarketMidstream
    
    
    Optimization
    
    
    Total
    
    
    Midstream
    
    
    Optimization
    
    
    Total
    
    
    Midstream
    
    
    Optimization
    
    
    TotalRevenues
    
    $
    1,450
    
    
    $
    3,299
    
    
    $
    4,749
    
    
    $
    1,084
    
    
    $
    2,803
    
    
    $
    3,887
    
    
    $
    440
    
    
    $
    2,154
    
    
    $
    2,594ExpensesTransportation and selling
    
    
    
    
    
    
    27
    
    
    
    27
    
    
    
    
    
    
    
    55
    
    
    
    55
    
    
    
    
    
    
    
    87
    
    
    
    87Operating
    
    
    279
    
    
    
    46
    
    
    
    325
    
    
    
    261
    
    
    
    63
    
    
    
    324
    
    
    
    174
    
    
    
    13
    
    
    
    187Purchased product
    
    
    1,071
    
    
    
    3,205
    
    
    
    4,276
    
    
    
    762
    
    
    
    2,693
    
    
    
    3,455
    
    
    
    169
    
    
    
    2,031
    
    
    
    2,200Operating Cash Flow
    
    $
    100
    
    
    $
    21
    
    
    $
    121
    
    
    $
    61
    
    
    $
    (8
    )
    
    $
    53
    
    
    $
    97
    
    
    $
    23
    
    
    $
    120Depreciation, depletion and
amortization
    
    
    
    
    
    
    
    
    
    
    70
    
    
    
    
    
    
    
    
    
    
    
    48
    
    
    
    
    
    
    
    
    
    
    
    36Segment Income
    
    
    
    
    
    
    
    
    
    $
    51
    
    
    
    
    
    
    
    
    
    
    $
    5
    
    
    
    
    
    
    
    
    
    
    $
    84
 Revenues and purchased product expense in Midstream & Market Optimization operations increased in
2004 compared to 2003 due primarily to increases in commodity prices. Operating cash flow increased
$68 million in 2004 to $121 million as a result of improved margins from natural gas liquids
processing and gas storage optimization activities. Decreases in transportation and selling costs
in 2004 compared to 2003 are primarily due to the reallocation of natural gas downstream
transportation costs to the Upstream segment. Operating expenses in 2003 included a $20 million
settlement with the U.S. Commodity Futures Trading Commission as described in the Contractual
Obligations and Contingencies section of this MD&A. The increase in 2004 DD&A is primarily due to a write down in the value of the Companys equity
investment interest in the Trasandino Pipeline in Argentina and Chile of approximately $35 million. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M11




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##### 



CORPORATE ($ millions)
    
    2004
    
    
    2003
    
    
    2002Revenues
    
    $
    (195
    )
    
    $
    2
    
    
    $
    8ExpensesOperating
    
    
    (1
    )
    
    
    
    
    
    
    Depreciation, depletion and amortization
    
    
    61
    
    
    
    41
    
    
    
    35Segment Income
    
    $
    (255
    )
    
    $
    (39
    )
    
    $
    (27
    )Administrative
    
    
    197
    
    
    
    173
    
    
    
    118Interest, net
    
    
    397
    
    
    
    283
    
    
    
    286Accretion of asset retirement obligation
    
    
    22
    
    
    
    17
    
    
    
    13Foreign exchange gain
    
    
    (417
    )
    
    
    (598
    )
    
    
    (11
    )Stock-based compensation
    
    
    17
    
    
    
    18
    
    
    
    Gain on dispositions
    
    
    (113
    )
    
    
    (1
    )
    
    
    (33
    )Income tax expense
    
    
    658
    
    
    
    364
    
    
    
    317
 Corporate revenues in 2004 include approximately $197 million in unrealized mark-to-market losses
related to financial and commodity contracts. Other mark-to-market gains ($7 million) on derivative
financial instruments related to interest and electricity consumption are recorded in interest, net
and operating expenses respectively. DD&A includes provisions for corporate assets such as computer equipment, office furniture and
leasehold improvements. The increase in expense on a year-over-year basis is the result of higher
capital spending in prior periods on corporate capital items and the impact of the change in the
U.S./Canadian dollar exchange rate. Administrative expenses increased 14 percent in 2004. The increase reflects the effect of the
change in the U.S./Canadian dollar exchange rate and increased long-term compensation expenses.
Administrative costs were approximately $0.12 per Mcfe in both 2004 and 2003. The higher interest expense resulted primarily from the higher average outstanding debt level
during the year as a result of the TBI acquisition in the second quarter of 2004. EnCanas weighted
average interest rate on outstanding debt was marginally lower in 2004 than it was in 2003 and
partially mitigated the effect of higher debt levels. The majority of the foreign exchange gain of $417 million in 2004 resulted from the change in the
U.S./Canadian dollar exchange rate during 2004 applied to U.S. dollar denominated debt issued in
Canada as discussed previously in this MD&A. Under Canadian GAAP, the Company is required to
translate long-term debt issued in Canada and denominated in U.S. dollars into Canadian dollars at
the period-end exchange rate. Resulting foreign exchange gains or losses are recorded in the
Consolidated Statement of Earnings. During 2004, EnCana sold certain corporate investments and recorded gains of $113 million on these
sales. The effective tax rate for 2004 was 23 percent compared to 15 percent for 2003 and 32 percent for
2002. Further information regarding EnCanas effective tax rate can be found in Note 9 to the
Consolidated Financial Statements. EnCanas effective rate in any year is a function of the
relationship between the amount of net earnings before income taxes for the year and the magnitude
of the items representing permanent differences that are excluded from the earnings subject to
tax. There are a variety of items of this type, including:  
    The effects of asset dispositions where the tax values of the assets sold differ from their accounting value.
    Adjustments for the impact of legislative tax changes which have a prospective impact on future income tax obligations.
    The non-taxable half of Canadian capital gains (losses).
    Items such as resource allowance and non-deductible crown payments where the income tax treatment is different from the accounting treatment. The 2004 effective tax rate reflects a reduction of $109 million in future income taxes resulting
from the reduction in the Alberta tax rate from 12.5 percent to 11.5 percent and Albertas
retention of the resource allowance and non-deductible crown royalties regime until 2007. In 2003,
the effective tax rate reflected a $359 million reduction in future income taxes resulting from the
reductions in the Canadian federal and Alberta corporate income tax rates and related changes to
the Canadian federal resource allowance deduction. Current income tax expense for the year ended 2004 was $567 million compared to $(113) million in
2003 and $(66) million in 2002. As expected, current taxes increased significantly in 2004; 2003
and 2002 were abnormally low as a result of the effects of the merger with Alberta Energy Company
Ltd. The operations of the Company are complex and related tax interpretations, regulations and
legislation in the various jurisdictions that the Company and its subsidiaries operate in are
continually changing. As a result, there are usually some tax matters under review. The Company
believes that the provision for taxes is adequate. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M12




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##### 



CAPITAL EXPENDITURES Capital Summary 2004
    
    
    2003
    
    
    2002(1)Upstream
    
    $
    4,343
    
    
    $
    3,845
    
    
    $
    1,932Midstream & Market Optimization
    
    
    64
    
    
    
    223
    
    
    
    47Corporate
    
    
    46
    
    
    
    57
    
    
    
    43Core Capital Expenditures
    
    $
    4,453
    
    
    $
    4,125
    
    
    $
    2,022Acquisitions
    
    
    2,986
    
    
    
    593
    
    
    
    748Dispositions
    
    
    (1,817
    )
    
    
    (301
    )
    
    
    (423
    )Discontinued Operations
    
    
    (1,416
    )
    
    
    (995
    )
    
    
    397Net Capital
    
    $
    4,206
    
    
    $
    3,422
    
    
    $
    2,744
   (1)
    
    2002 amounts include post merger capital only. The Companys core capital expenditures increased approximately $0.3 billion to $4.5 billion in
2004. The increase in Upstream core capital expenditures in 2004 compared to 2003 was primarily as
a result of continued development of EnCanas United States resource play properties. Net capital
expenditures increased approximately $0.8 billion compared to 2003 as a result of the TBI
acquisition, increased drilling in the U.S., higher cost wells drilled both in Canada and the U.S.,
and the impact of the higher U.S./Canadian dollar exchange rate partially offset by the sale of the
U.K. operations and non-core asset dispositions. The Companys capital investment was funded by
cash flow in excess of amounts paid for purchases of Common Shares under the Normal Course Issuer
Bid, proceeds received on dispositions of non-core assets and debt. (UPSTREAM BAR CHART) UPSTREAM CAPITAL EXPENDITURES
The increase in Upstream capital expenditures in 2004 compared to 2003 reflects increased drilling
and development activities in the U.S. and the impact of the increased average U.S./Canadian dollar
exchange rate on Canadian dollar denominated expenditures. On an annual basis the change in the
average U.S./Canadian dollar exchange rate resulted in an increase on Canadian dollar denominated
core capital expenditures of approximately $230 million. Capital spending during 2004 was primarily
focused on North American resource play properties. Natural gas capital expenditures were primarily
focused on continued development of the Companys key resource plays in Greater Sierra, Cutbank
Ridge and Shallow Gas in Canada, and Piceance, Jonah, East Texas and Fort Worth in the United
States. Crude oil capital spending in 2004 was concentrated at Foster Creek, Pelican Lake and
Suffield in Alberta and Weyburn in Saskatchewan. The Company drilled 4,923 net wells in 2004
compared to 5,581 net wells in 2003. Canadian East Coast
In 2004, the Company participated in two deep water tests at Weymouth and Crimson. Both of these
wells were plugged and abandoned. As of December 31, 2004, the Companys investment in its East
Coast assets, including Deep Panuke, is recorded at approximately $371 million. Until assessments
of the economics of the Panuke project are complete, the timing of any potential start of
production and amount of additional costs which may be incurred are not determinable. Gulf of Mexico
During 2004, the Companys operating partner completed a well test at the Tahiti oilfield which is
located 304 kilometres southwest of New Orleans. As of December 31, 2004, the Company had invested
approximately $394 million in the Gulf of Mexico, including Tahiti. The field is expected to begin
production in 2008. The Company has announced that it intends to sell its interests in the Gulf of
Mexico. Reserves
Each year, EnCana engages independent qualified reserve evaluators to prepare reports on 100
percent of the Corporations oil and natural gas reserves. The Company has a Reserves Committee of
independent board members which reviews the qualifications and appointment of the independent
qualified reserve evaluators. The Committee also reviews the procedure for providing information to
the evaluators. EnCanas disclosure of reserves data is covered by NI 51-101 as amended by a Mutual
Reliance Review System Decision Document dated December 16, 2003 permitting the adoption of U.S.
reporting standards, including compliance with the practices and procedures of the U.S. Securities
and Exchange Commission (SEC) and Financial Accounting Standards Board (FASB) reserve reporting
requirements, in 2003. These standards require that reserves be estimated employing the single day
field price of the commodity at the effective date of the valuation - in this case December
31, 2004. EnCanas proved natural gas reserves as at December 31, 2004, on an SEC constant price basis,
totalled 10,460 Bcf. Extensions and discoveries resulting from successful exploration and
development capital programs amounted to 2,431 Bcf. Downward revisions of 252 Bcf in the United
States were largely the result of reduced reserve estimates per well in the northern and southern
Rockies. Net acquisitions were dominated by the purchase of TBI in May 2004. The Companys proved crude oil and natural gas liquids reserves as at December 31, 2004, on an SEC
constant price basis, totalled 501 MMbbls. Extensions and discoveries resulting from successful
exploration and development capital programs amounted to 163 MMbbls. Downward revisions in Canada
were dominated by a 363 MMbbls adjustment at Foster Creek necessitated by reliance on year-end
prices for bitumen determined in accordance with SEC and FASB requirements. If EnCana were applying
the approach set out by the Canadian Securities Administrators in their Staff Notice 51-315, dated
January 20, 2005, namely the use of the average price differential for the preceding 12 months, it
is expected that no negative revisions to the companys proved bitumen reserves would occur.
Divestitures were dominated by the sale of all of EnCanas interests in the U.K. central North Sea
and non-core interests in Western Canada. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M13




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##### 



Proved Reserves by Country Constant Prices After Royalties
    
    Natural Gas
    
    
    Crude Oil and NGLs(1)2004 vs.
    
    
    2003 vs.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2004 vs.
    
    
    
    
    
    
    2003 vs.As at December 31
    
    2004
    
    
    2003
    
    
    2003
    
    
    2002
    
    
    2002
    
    
    2004
    
    
    2003(2)
    
    
    2003
    
    
    2002
    
    
    2002(billions of cubic feet)
    
    (millions of barrels)Canada
    
    
    5,824
    
    
    
    11
    %
    
    
    5,256
    
    
    
    4
    %
    
    
    5,073
    
    
    
    267
    
    
    
    -58
    %
    
    
    629
    
    
    
    16
    %
    
    
    542United States
    
    
    4,636
    
    
    
    48
    %
    
    
    3,129
    
    
    
    22
    %
    
    
    2,573
    
    
    
    91
    
    
    
    117
    %
    
    
    42
    
    
    
    2
    %
    
    
    41Ecuador
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    143
    
    
    
    -12
    %
    
    
    162
    
    
    
    4
    %
    
    
    156United Kingdom
    
    
    
    
    
    
    -100
    %
    
    
    26
    
    
    
    30
    %
    
    
    20
    
    
    
    
    
    
    
    -100
    %
    
    
    124
    
    
    
    28
    %
    
    
    97Total
    
    
    10,460
    
    
    
    24
    %
    
    
    8,411
    
    
    
    10
    %
    
    
    7,666
    
    
    
    501
    
    
    
    -48
    %
    
    
    957
    
    
    
    14
    %
    
    
    836
   (1)
    
    NGLs include condensate.(2)
    
    Year-end 2004 Canadian Crude Oil and NGLs reserves were
essentially unchanged from the previous year, prior to the bitumen
revisions caused by an anomalously low
December 31, 2004 field price. Proved Reserves Reconciliation by Country Constant Prices After Royalties
    
    Natural Gas
    
    
    Crude Oil and NGLs(1)As at December 31, 2004
    (billions of cubic feet)
    
    
    (millions of barrels)Canada
    
    
    USA
    
    
    UK
    
    
    Total
    
    
    Canada
    
    
    USA
    
    
    Ecuador
    
    
    UK
    
    
    TotalBeginning of year
    
    
    5,256
    
    
    
    3,129
    
    
    
    26
    
    
    
    8,411
    
    
    
    629
    
    
    
    42
    
    
    
    162
    
    
    
    124
    
    
    
    957Revisions and improved recovery
    
    
    67
    
    
    
    (252
    )
    
    
    
    
    
    
    (185
    )
    
    
    32
    
    
    
    
    
    
    
    (12
    )
    
    
    
    
    
    
    20Extensions and discoveries
    
    
    1,422
    
    
    
    1,009
    
    
    
    
    
    
    
    2,431
    
    
    
    94
    
    
    
    48
    
    
    
    21
    
    
    
    
    
    
    
    163Acquisitions
    
    
    65
    
    
    
    1,150
    
    
    
    10
    
    
    
    1,225
    
    
    
    29
    
    
    
    12
    
    
    
    
    
    
    
    10
    
    
    
    51Divestitures
    
    
    (215
    )
    
    
    (82
    )
    
    
    (25
    )
    
    
    (322
    )
    
    
    (97
    )
    
    
    (6
    )
    
    
    
    
    
    
    (128
    )
    
    
    (231
    )Production
    
    
    (771
    )
    
    
    (318
    )
    
    
    (11
    )
    
    
    (1,100
    )
    
    
    (57
    )
    
    
    (5
    )
    
    
    (28
    )
    
    
    (6
    )
    
    
    (96
    )End of year before bitumen revisions
    
    
    5,824
    
    
    
    4,636
    
    
    
    
    
    
    
    10,460
    
    
    
    630
    (3)
    
    
    91
    
    
    
    143
    
    
    
    
    
    
    
    864Revisions due to bitumen price(2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (363
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (363
    )End of year
    
    
    5,824
    
    
    
    4,636
    
    
    
    
    
    
    
    10,460
    
    
    
    267
    
    
    
    91
    
    
    
    143
    
    
    
    
    
    
    
    501
   (1)
    
    NGLs include condensate.(2)
    
    As a result of using year-end price.(3)
    
    Year-end 2004 Canadian Crude Oil and NGLs reserves were
essentially unchanged from the previous year, prior to the bitumen
revisions caused by an anomalously low
December 31, 2004 field price. MIDSTREAM & MARKET OPTIMIZATION CAPITAL EXPENDITURES
Expenditures in 2004 related primarily to ongoing improvements to midstream facilities. CORPORATE CAPITAL EXPENDITURES
Corporate capital expenditures relate primarily to spending on business information systems,
leasehold improvements and furniture and office equipment. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M14




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##### 



DISCONTINUED OPERATIONS United Kingdom and Ecuador assets are presented as discontinued operations in the Consolidated
Financial Statements. EnCanas net earnings from discontinued operations are $1,302 million and
include a gain of $1,364 million on the discontinuance of U.K. operations, realized financial and
commodity hedge losses of $358 million and unrealized financial and commodity hedge losses of $71
million. Summary information is presented below. Additional information concerning EnCanas
discontinued operations can be found in Note 5 to EnCanas Consolidated Financial Statements. UNITED KINGDOM 2004
    
    
    2003
    
    
    2002Sales volumesProduced Gas (million cubic feet per day)
    
    
    30
    
    
    
    13
    
    
    
    10Crude Oil (barrels per day)
    
    
    14,128
    
    
    
    9,231
    
    
    
    9,733NGLs (barrels per day)
    
    
    1,845
    
    
    
    897
    
    
    
    795Total (million cubic feet equivalent per day)
    
    
    126
    
    
    
    74
    
    
    
    73($ millions)Net earnings (loss) from discontinued operations
    
    $
    1,338
    
    
    $
    (7
    )
    
    $
    24Capital Investment
    
    
    488
    
    
    
    223
    
    
    
    82
 In December 2004, a subsidiary of the Company completed the sale of its U.K. central North Sea
assets, production and prospects for net cash consideration of approximately $2.1 billion,
resulting in a gain on sale of approximately $1.4 billion. Liquids sales volumes in 2004 increased to 15,973 bbls/d from 10,128 bbls/d in 2003 primarily as a
result of the acquisitions of additional interests in the Scott and Telford fields in October 2003
and February 2004. Higher transportation and selling expenses in 2004 compared to 2003 of $20
million were primarily due to higher product volumes. Operating expenses increased approximately
$18 million in 2004 due to a platform turnaround, higher maintenance costs and higher volumes.
Increased DD&A expense in 2004 of $44 million over 2003 was primarily due to increased volumes
offset by a decrease in the DD&A rate. ECUADOR 2004
    
    
    2003
    
    
    2002Sales volumesCrude Oil (barrels per day)
    
    
    77,993
    
    
    
    46,521
    
    
    
    29,740($ millions)Net (loss) earnings from discontinued operations
    
    $
    (33
    )
    
    $
    32
    
    
    $
    45Capital Investment
    
    
    240
    
    
    
    367
    
    
    
    169
 At December 31, 2004, EnCana has decided to sell its Ecuador operations, and accordingly the
Ecuador operations have been accounted for as discontinued operations. Sales volumes in 2004 increased 68 percent to average approximately 78,000 bbls/d. The increased
sales volumes are primarily due to the combination of available capacity on the OCP pipeline in
Ecuador and increased production from Block 15. Production and mineral taxes were $36 million higher in 2004 compared to 2003 as a result of higher
realized prices and volumes on the Tarapoa block. The Company is required to pay a percentage of
revenue from this block to the Ecuador government based on realized prices over a base price.
Operating costs were $42 million higher in 2004 compared to 2003 due to higher workover costs and
increased fuel and diesel costs and higher maintenance and personnel costs on Block 15. DD&A
expense increased $104 million compared to 2003 as a result of higher crude oil volumes. Crude oil sales volumes increased 56 percent in 2003, compared to 2002, due to the inclusion of a
full year of post merger volumes and the removal of transportation capacity constraints as a result
of the commencement of shipments on the OCP pipeline in September 2003. Higher production and
mineral taxes in 2003, compared to 2002 resulted from increased production from the Tarapoa block
and higher realized prices from Tarapoa volumes. Transportation and selling costs were higher in
2003 and reflect the higher tariff on OCP pipeline compared to the SOTE pipeline system. Operating
expenses and DD&A increased in 2003 compared to 2002 primarily due to higher crude oil volumes. Contingency information concerning Ecuador discontinued operations is included in Note 5 to
EnCanas Consolidated Financial Statements. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M15




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##### 



LIQUIDITY AND CAPITAL RESOURCES EnCanas cash flow from continuing operations was $4,605 million in 2004, up $470 million compared
to 2003. The increase in cash flow was primarily due to increased revenues from the growth in sales
volumes and higher commodity prices offset by higher realized commodity and currency hedging
losses, an increase in the current tax provision and an increase in the U.S./Canadian dollar
exchange rate. During 2004, long-term debt plus the current portion of long-term debt increased $1,555 million.
This increase resulted from the acquisition of TBI and capital spending offset by proceeds of
dispositions and increased cash flow during 2004, including proceeds of $2.1 billion received from
the sale of the U.K. assets on December 1, which were used to repay bank and other indebtedness.
EnCanas net debt adjusted for working capital was $7,184 million as at December 31, 2004 compared
with $5,544 million at December 31, 2003. Working capital was $558 million and included unrealized
losses on mark-to-market accounting on derivatives of $95 million and a current tax payable of $359
million. This compares to a working capital of $544 million as at December 31, 2003. Cash flow
together with proceeds from dispositions were used for the purchase of shares under the Companys
Normal Course Issuer Bid and capital expenditures. Net debt to capitalization at the end of 2004 is 33 percent, unchanged from 2003. Management
calculates this ratio for internal purposes to steward the Companys overall debt position as a
measure of a companys financial strength. EnCanas long term credit ratings were confirmed by Standard & Poors and Dominion Bond Rating
Services credit rating agencies in October 2004. Standard &
Poors has affirmed an A with a
Negative Outlook and Dominion Bond Rating Services has affirmed an A(low) with a Stable Trend.
Moodys long-term credit rating for EnCana remains at Baa2 Stable. The agencies are expected to
continue to monitor the Companys operating and financial performance through the first quarter of
2005. On March 23, 2004 the Company redeemed all of its Coupon Reset Subordinated Term Securities, Series
A (Term Securities) which had an aggregate principal amount of approximately C$126 million. The
redemption price of the Term Securities was the principal amount plus accrued and unpaid interest
to the redemption date. In March 2004, an indirect wholly owned subsidiary, EnCana Holdings Finance Corp. (EHFC), filed a
shelf prospectus whereby it may issue from time to time up to $2 billion of debt securities. Debt
securities issued under this shelf prospectus are unconditionally guaranteed by EnCana Corporation.
On May 13, 2004 EHFC completed a $1.0 billion unsecured public debt offering in the U.S. The notes,
which are due in 2014, bear interest at 5.8 percent. The net proceeds of the offering were used to
fund a portion of the acquisition of TBI. After EnCanas acquisition of TBI, TBI and a subsidiary made a consent tender offer for $225
million for their 7.25 percent Senior Subordinated Notes. A total of 98.9 percent of the notes were
tendered for a total cost of approximately $258 million. Subsequently, in December 2004 and January
2005, the balance of the notes were purchased for a total cost of approximately $2.9 million. On August 4, 2004, EnCana completed a public offering in the United States for $250 million notes
due in 2009 at 4.60 percent and $750 million notes due in 2034 at 6.50 percent. The proceeds from
these issues were used primarily to repay existing bank and commercial paper indebtedness. On August 9, 2004, EnCana redeemed all of its 8.50 percent Unsecured Junior Subordinated Debentures
due 2048, which had an aggregate principal amount of C$200 million, at par plus accrued interest.
On September 30, 2004, EnCana redeemed all of its 9.50 percent Preferred Securities due 2048, which
had an aggregate principal amount of $150 million, at par. In September 2004, EnCana filed a multi-jurisdictional shelf prospectus whereby it may issue from
time to time up to $2 billion of debt securities. This shelf prospectus replaced EnCanas previous
$2 billion U.S. debt shelf prospectus which expired on September 22, 2004. No amounts have been
issued under the new shelf prospectus. In October 2004, the Company completed the refinancing of its general corporate bank credit
facilities. Under this refinancing, EnCanas core bank facilities were increased in size from C$4.0
billion to C$4.5 billion, and the term of the two tranches were extended to three and five years.
In December, the bank credit facilities of a wholly owned U.S. subsidiary were increased from $300
million to $600 million, all in a five year term. As at December 31, 2004, the Company had available unused committed bank credit facilities in the
amount of $2.4 billion. In October 2004, EnCana received approval from the Toronto Stock Exchange (TSX) to continue to
purchase, for cancellation, Common Shares under a Normal Course Issuer Bid (the Bid). Under the
Bid, EnCana was entitled to purchase for cancellation up to five percent of its Common Shares
issued and outstanding on October 22, 2004 over a 12-month period ending October 28, 2005. As of
December 31, 2004, EnCana had purchased for cancellation approximately 14.8 million of its shares
under the Bid. In February 2005, EnCana received approval from the TSX to amend the Bid. Under the
amended Bid, EnCana is entitled to purchase up to 46.1 million Common Shares (ten percent of the
public float on October 22, 2004). Purchases may be made through the facilities of the TSX and the
New York Stock Exchange, in accordance with the policies and rules of each exchange. During 2004, EnCana purchased for cancellation a total of approximately 20 million shares for a
total of approximately $1 billion under the terms of its Normal Course Issuer Bids. Normal Course Issuer Bid (millions)
    Share Purchases
    
    Number of shares2004
    
    
    2003
    
    
    2002
    
    
    Total
    
    
    entitled to purchaseBid expiring October 2003
    
    
    
    
    
    
    20.2
    
    
    
    
    
    
    
    20.2
    
    
    
    23.8Bid expiring October 2004
    
    
    5.5
    
    
    
    3.6
    
    
    
    
    
    
    
    9.1
    
    
    
    23.2Bid expiring October 2005
    
    
    14.8
    
    
    
    
    
    
    
    
    
    
    
    14.8
    
    
    
    46.120.3
    
    
    
    23.8
    
    
    
    
    
    
    
    44.1
 ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M16




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OUTSTANDING SHARE DATA The Company is authorized to issue an unlimited number of Common Shares, an unlimited number of
First Preferred Shares and an unlimited number of Second Preferred Shares. The reduction of 10.3
million Common Shares outstanding from the end of 2003 to the end of 2004 (18.3 million from the
end of 2002 to the end of 2003) results from the repurchase of 20.3 million shares in 2004 (23.8
million in 2003) under the Normal Course Issuer Bid and the issuance of 9.7 million Common Shares
(5.5 million in 2003) under Option plans. Share Capital  Common Shares ($ millions)
    
    2004
    
    
    2003
    
    
    2002Common shares outstanding,
end of year
    
    
    450.3
    
    
    
    460.6
    
    
    
    478.9Weighted average common
shares outstanding  diluted
    
    
    468.0
    
    
    
    479.7
    
    
    
    422.6
 As at January 31, 2005, there were 446.5 million Common Shares outstanding. There were no Preferred
Shares outstanding during these periods. Employees and directors have been granted options to
purchase Common Shares under various plans. These plans and their terms and outstanding balances
are disclosed in detail in Note 15 to the Consolidated Financial Statements. Effective February 22, 2005 the Companys Board of Directors resolved to recommend the split of the
Corporations outstanding Common Shares on a two-for-one basis (Share Split). EnCanas
shareholders will be asked to approve the Share Split at its annual and special meeting to be held
on April 27, 2005. In addition to shareholder approval, the Share Split is subject to the receipt
of all required regulatory approvals. If approved by shareholders, and subject to regulatory
approvals, each shareholder will receive one additional common share for each common share he or
she holds on the record date for the Share Split of May 12, 2005. Pursuant to the rules of the
Toronto Stock Exchange, EnCanas common shares will commence trading on a subdivided basis at the
opening of business on May 10, 2005, which is the second trading day preceding the record date.
Also on May 10, 2005, EnCanas common shares listed on the New York Stock Exchange (NYSE) will
commence trading with rights entitling holders to an additional common share for each common share
held upon the commencement of trading of the common shares on a subdivided basis on the NYSE. The
trading of the common shares on a subdivided basis on the NYSE will occur one day after the
delivery of share certificates to registered holders of EnCanas common shares. It is anticipated
that share certificates representing the additional common shares resulting from the Share Split
will be delivered to registered common shareholders on or about May 20, 2005. The Compensation Committee of the Board of Directors, in 2003, approved a long-term incentive
strategy for employees throughout EnCana which includes a significantly reduced level of stock
option grants to be supplemented by grants of Performance Share Units (PSUs). In 2004, the Board
of Directors approved a modification to the PSU plan that provides a reduced payout if relative
ranking is below median. This change applies to units granted in both 2004 and 2005. PSUs will not
result in the issue of new Common Shares by the Company. Stock options granted in 2004 have an
associated Tandem Share Appreciation Right (TSAR) and employees may elect to exercise either the
stock option or the associated TSAR. TSAR exercises will result in either cash payments by the
Company or issuance of Common Shares. As previously detailed in the Liquidity and Capital Resources section of this MD&A, the Company
obtained regulatory approval under Canadian securities laws to purchase Common Shares under three
consecutive Normal Course Issuer Bids which commenced in October 2002 and may continue until
October 28, 2005. Under the terms of the bids, the Company repurchased for cancellation
approximately 20 million Common Shares during 2004, and as of December 31, 2004, was entitled to
purchase for cancellation an additional 8 million Common Shares. On February 4, 2005, EnCana
received approval from the TSX to amend the Bid and increase the number of Common Shares available
for purchase from five percent of the issued and outstanding shares on October 22, 2004 to ten
percent of the public float. Under the amended Bid, EnCana is entitled to purchase for cancellation
up to approximately 46.1 million Common Shares. To the date of the amendment, EnCana had purchased
approximately 21.2 million Common Shares under the Bid, leaving approximately 24.9 million Common
Shares available for purchase through the expiry of the Bid on October 28, 2005. Shareholders may
obtain a copy of the Bid documents without charge at www.sedar.com or by contacting
investor.relations@encana.com ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M17




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CONTRACTUAL OBLIGATIONS AND CONTINGENCIES The Company has entered into various commitments primarily related to debt, demand charges on firm
transportation agreements, capital commitments and marketing agreements. The following table
summarizes the Companys contractual obligations at December 31, 2004: Expected Payment Date2006 to
    
    
    2008 to($ millions)
    
    2005
    
    
    2007
    
    
    2009
    
    
    2010+
    
    
    TotalLong-Term Debt
    
    $
    188
    
    
    $
    487
    
    
    $
    841
    
    
    $
    4,434
    
    
    $
    5,950Asset Retirement Obligations
    
    
    2
    
    
    
    13
    
    
    
    
    
    
    
    3,680
    
    
    
    3,695Operating Leases(2)
    
    
    42
    
    
    
    84
    
    
    
    65
    
    
    
    152
    
    
    
    343Pipeline Transportation
    
    
    297
    
    
    
    499
    
    
    
    402
    
    
    
    1,010
    
    
    
    2,208Capital Commitments
    
    
    190
    
    
    
    63
    
    
    
    4
    
    
    
    38
    
    
    
    295Purchase of Goods and Services
    
    
    121
    
    
    
    37
    
    
    
    12
    
    
    
    5
    
    
    
    175Product Purchases
    
    
    171
    
    
    
    57
    
    
    
    48
    
    
    
    134
    
    
    
    4101,011
    
    
    
    1,240
    
    
    
    1,372
    
    
    
    9,453
    
    
    
    13,076Discontinued operations (3)
    
    
    99
    
    
    
    185
    
    
    
    189
    
    
    
    876
    
    
    
    1,349Total Contractual Obligations(1)
    
    $
    1,110
    
    
    $
    1,425
    
    
    $
    1,561
    
    
    $
    10,329
    
    
    $
    14,425
   (1)
    
    In addition, the Company has made commitments related to its risk management program. See Note 17 to the Consolidated Financial Statements.
The Company also has an obligation to fund its Pension Plan and Other Post Retirement Benefits as disclosed in Note 16 to the Consolidated
Financial Statements.(2)
    
    Related to office space.(3)
    
    Primarily related to long term transportation commitments. In addition to the long-term debt payments outlined above, at December 31, 2004 the Company had
$1,914 million outstanding related to Bankers Acceptances, Commercial Paper and LIBOR loans that
are supported by revolving credit facilities and term loan borrowings. The Company intends and
expects that it will have the ability to extend the term of this debt on an ongoing basis. Further
details regarding the Companys long-term debt are described in Note 13 to the Consolidated
Financial Statements. Additional disclosure regarding the contractual obligations outlined above is included in Note 19
to the Consolidated Financial Statements. As at December 31, 2004, EnCana had remained a party to long-term, fixed price, physical contracts
with a current delivery of approximately 48 MMcf/d with varying terms and volumes through 2017. The
total volume to be delivered within the terms of these contracts is 167 Bcf at a weighted average
price of $3.71 per Mcf. At December 31, 2004, these transactions had an unrealized loss of $157
million. Commitments and Contingencies associated with Ecuador discontinued operations are included in Note
5 to EnCanas Consolidated Financial Statements. Variable Interest Entities (VIE)
In December 2004, an EnCana subsidiary finalized the purchase of certain oil and gas properties in
Texas for approximately $251 million. The purchase was facilitated by an unrelated party, which
holds the assets in trust for the Company. EnCana operates the properties, receives all the revenue
and pays all of the expenses associated with these properties. The assets will be transferred to
EnCana at the earliest of June 15, 2005 or upon the disposition of certain natural gas and crude
oil properties by EnCana. EnCana has determined that this relationship represents an interest in a
VIE and that EnCana is the primary beneficiary of the VIE. EnCana has included these properties in
its consolidated results from the date of acquisition. This subsidiary will not hold title to these
properties until an exchange transaction has been completed. Off-Balance Sheet Arrangements
The Company does not have any off-balance sheet arrangements that have or are reasonably likely to
have an effect on its results of operations or financial condition. Leases
As a normal course of business, the Company leases office space for personnel who support field
operations and corporate purposes. Legal Proceedings Related to Discontinued Merchant Energy Operations
In July 2003, the Companys indirect wholly owned U.S. marketing subsidiary, WD Energy Services
Inc. (WD), concluded a settlement with the U.S. Commodity Futures Trading Commission (CFTC) of
a previously disclosed CFTC investigation. The investigation related to alleged inaccurate
reporting of natural gas trading information during 2000 and 2001 by former employees of WDs now
discontinued Houston-based merchant energy trading operation to energy industry publications that
compiled and reported index prices. All Houston-based merchant energy trading operations were
discontinued following the merger with AEC in 2002. Under the terms of the settlement, WD agreed to
pay a civil monetary penalty in the amount of $20 million without admitting or denying the findings
in the CFTCs order. The Company and WD are defendants in a lawsuit filed by E. & J. Gallo Winery in the United States
District Court in California and, along with other energy companies, are defendants in several
other lawsuits in California (many of which are class actions) and three class action lawsuits
filed in the United States District Court ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M18




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in New York. A motion by the Company and WD to dismiss the Gallo complaint on the basis that the
Federal Energy Regulatory Commission had exclusive jurisdiction regarding this matter was not
granted. The Gallo complaint claims damages in excess of $30 million, before potential trebling
under California laws. Most of the California lawsuits were transferred by the Judicial Panel on Multidistrict Litigation
on a consolidated basis to the Nevada District Court and all of the New York lawsuits were
consolidated in New York District Court by the plaintiffs application. The Nevada District Court
has remanded the California State Court cases back to the California State Court for hearing. The
California lawsuits relate to sales of natural gas in California from 1999 to the present and
contain allegations that the defendants engaged in a conspiracy with unnamed competitors in the
natural gas and derivatives market in California in violation of U.S. and California anti-trust and
unfair competition laws to artificially raise the price of natural gas through various means
including the illegal sharing of price information through online trading, price indices and wash
trading. The New York lawsuits claim that the defendants alleged manipulation of natural gas price
indices resulted in higher prices of natural gas futures and option contracts traded on the NYMEX
from 2000 to 2002. EnCana Corporation has been dismissed from the New York lawsuits, leaving WD and
several other companies unrelated to the Company as the remaining defendants. As is customary, the
class actions do not specify the amount of damages claimed. The Company and WD intend to vigorously defend against these claims; however, the Company cannot
predict the outcome of these proceedings or any future proceedings against the Company, whether
these proceedings would lead to monetary damages which could have a material adverse effect on the
Companys financial position, or whether there will be other proceedings arising out of these
allegations. ACCOUNTING POLICIES AND ESTIMATES CHANGES IN ACCOUNTING PRINCIPLES AND PRACTICES Hedging Relationships
On January 1, 2004, the Company adopted the amendments made to the Canadian Institute of Chartered
Accountants (CICA) Accounting Guideline AcG-13 Hedging Relationships. Derivative instruments
outstanding at January 1, 2004 that did not qualify as a hedge under AcG-13 or were not designated
as a hedge, were recorded using the mark-to-market accounting method whereby their fair value was
recorded on the Consolidated Balance Sheet. The impact on the Companys Consolidated Financial
Statements at January 1, 2004 was an increase in assets of $145 million, an increase in liabilities
of $380 million and a net deferred loss of $235 million. These amounts are taken into net earnings
as the contracts expire. At December 31, 2004, there remains a net gain of $72 million to be
recognized as described in Note 2 to the Consolidated Financial Statements. Consolidation of Variable Interest Entities
On November 1, 2004, the Company retroactively adopted the new CICA Accounting Guideline AcG-15
Consolidation of Variable Interest Entities. AcG-15 defines a variable interest entity (VIE) as
a legal entity in which either the total equity at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support provided by other parties
or the equity owners lack a controlling financial interest. The guideline requires the enterprise
which absorbs the majority of a VIEs expected gains or losses, the primary beneficiary, to
consolidate the VIE. The retroactive adoption of AcG-15 had no effect on EnCanas prior Consolidated Financial
Statements. CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management is required to make judgments, assumptions and estimates in the application of generally
accepted accounting principles that have a significant impact on the financial results of the
Company. The following discussion outlines the accounting policies and practices that are critical
to determining EnCanas financial results. Full Cost Accounting
EnCana follows the CICA guideline on full cost accounting in the oil and gas industry to account
for oil and gas properties. Under this method, all costs directly associated with the acquisition
of, exploration for, and the development of natural gas and crude oil reserves are capitalized on a
country-by-country cost centre basis and costs associated with production are expensed. The
capitalized costs are depreciated, depleted and amortized using the unit-of-production method based
on estimated proved reserves. Reserve estimates can have a significant impact on earnings, as they
are a key component in the calculation of DD&A. A downward revision in a reserve estimate could
result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to
be in excess of the calculated ceiling, which is based largely on reserve estimates (see asset
impairment discussion below), the excess must be written off as an expense charged against
earnings. In the event of a property disposition, proceeds are normally deducted from the full cost
pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20 percent
or greater. Oil and Gas Reserves
All of EnCanas oil and gas reserves are evaluated and reported on by independent qualified reserve
evaluators. The estimation of reserves is a subjective process. Forecasts are based on engineering
data, projected future rates of production, estimated commodity price forecasts and the timing of
future expenditures, all of which are subject to numerous uncertainties and various
interpretations. Reserve estimates can be revised upward or downward based on the results of future
drilling, testing, production levels and economics of recovery based on cash flow forecasts. Asset Impairments
Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized
costs in each cost centre do not exceed their fair value. An impairment loss is recognized in net
earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of
the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable
if the carrying amount exceeds the sum of the ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M19




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undiscounted cash flows from proved reserves. If the sum of the cash flows is less than carrying
amount, the impairment loss is limited to an amount by which the carrying amount exceeds the sum
of:  i)
    the fair value of proved and probable reserves; andii)
    the costs of unproved properties that have been subject to a separate impairment test. Asset Retirement Obligations
The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance
Sheet when identified and a reasonable estimate of fair value can be made. Asset retirement
obligations include those legal obligations where the Company will be required to retire tangible
long-lived assets such as producing well sites, offshore production platforms and natural gas
processing plants. These obligations also include items for which the Company has made promissory
estoppel. The asset retirement cost, equal to the initially estimated fair value of the asset
retirement obligation, is capitalized as part of the cost of the related long-lived asset.
Increases in the asset retirement obligation resulting from the passage of time are recorded as
accretion of asset retirement obligation in the Consolidated Statement of Earnings. Amounts
recorded for asset retirement obligations are based on estimates of reserves and on retirement
costs which will not be incurred for several years. Actual payments to settle the obligations may
differ from estimated amounts. Goodwill
Goodwill, which represents the excess of purchase price over fair value of net assets acquired in
the merger with AEC and the acquisition of TBI, is assessed by the Company for impairment at least
annually. Goodwill was allocated to the business segments at the time of the above transactions
based on their respective book values compared to fair values. If it is determined that the fair
value of the assets and liabilities of the business segment is less than the book value of the
business segment at the time of assessment, an impairment amount is determined by deducting the
fair value from the book value and applying it against the book balance of goodwill. The offset is
charged to the Consolidated Statement of Earnings as additional DD&A. Derivative Financial Instruments
Derivative financial instruments are used by the Company to manage its exposure to market risks
relating to commodity prices, foreign currency exchange rates and interest rates. The Companys
policy is not to utilize derivative financial instruments for speculative purposes. The Company enters into financial transactions to reduce its exposure to price fluctuations with
respect to a portion of its oil and gas production to help achieve returns on new projects,
targeted returns on new investments and steady funding of growth projects or to mitigate market
price risk associated with cash flows expected to be generated from budgeted capital programs.
These transactions generally are swaps, collars or options and are generally entered into with
major financial institutions or commodities trading institutions. The Company may also utilize derivative financial instruments such as interest rate swap agreements
to manage the fixed and floating interest rate mix of the Companys total debt portfolio and
related overall cost of borrowing. The interest rate swap agreements involve the periodic exchange
of payments, without the exchange of the normal principal amount upon which the payments are based,
and are recorded as an adjustment of interest expense on the hedged debt instrument. The Company may enter into hedges of its foreign currency exposures on foreign currency denominated
long-term debt by entering into offsetting forward exchange contracts. Foreign exchange translation
gains and losses on these instruments are accrued under other current, or non-current, assets or
liabilities on the balance sheet and recognized in foreign exchange in the period to which they
relate, offsetting the respective translation losses and gains recognized on the underlying foreign
currency long-term debt. Premiums or discounts on these forward instruments are amortized as an
adjustment of interest expense over the term of the contract. The Company also purchases foreign exchange forward contracts to hedge anticipated sales to
customers in the United States. Foreign exchange translation gains and losses on these instruments
are recognized as an adjustment of the revenues when the sale is recorded. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded
using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated
Balance Sheet as either an asset or liability with changes in fair value recognized in net
earnings. Realized gains or losses from financial derivatives are recognized in natural gas and
crude oil revenues as the related production occurs. Unrealized gains and losses are recognized in
revenues at the end of each respective reporting period. The estimate of fair value of all
derivative instruments is based on quoted market prices or, in their absence, third party market
indicators. In 2004, the Company elected not to designate any of its current price risk management activities
as accounting hedges under AcG-13 and accordingly, accounts for all derivatives using the
mark-to-market accounting method. Pensions and Other Post Retirement Benefits
The Company accrues for its obligations under its employee benefit plans and the related costs, net
of plan assets. The cost of pensions and other retirement benefits is actuarially determined using the projected
benefit method based on length of service, and reflects Managements best estimate of expected plan
investment performance, salary escalation, retirement ages of employees and expected future health
care costs. The expected return on plan assets is based on the fair value of those assets. The
obligation is discounted using a market interest rate at the beginning of the year on high quality
corporate debt instruments. Pension expense includes the cost of pension benefits earned during the current year, the interest
cost on pension obligations, the expected return on pension plan assets, the amortization of the
net transitional obligation, the amortization of adjustments arising from pension plan amendments
and the amortization of the excess of the net actuarial gain or loss over ten percent of the
greater of the benefit obligation and the fair value of plan assets. The amortization period covers
the expected average remaining services lives of employees covered by the plans. ENCANA CORPORATION 2004
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Pension expense for the defined contribution pension plans is recorded as the benefits are earned
by the employees covered by the plan. Pension costs are a component of compensation costs. Performance Share Units (PSUs)
The PSU plans provide for a range of payouts, based on EnCanas performance relative to certain
peers. The Company expenses the cost of PSUs based on expected payouts, however, the amounts to be paid,
if any, may vary from the current estimate. RISK MANAGEMENT EnCanas results are affected by  
    financial risks (including commodity price, foreign exchange, interest rate and credit risks)
    operational risks
    environmental, health, safety and security risks
    reputational risks FINANCIAL RISKS
The Company partially mitigates its exposure to financial risks through the use of various
financial instruments and physical contracts. The use of derivative instruments is governed under
formal policies approved by senior management, and is subject to limits established by the Board of
Directors. As a means of mitigating exposure to commodity price risk, the Company has entered into
various financial instrument agreements. The Companys policy is not to use derivative financial
instruments for speculative purposes. The details of these instruments, including any unrealized
gains or losses, as of December 31, 2004, are disclosed in Note 17 to the Consolidated Financial
Statements. The Company has in place policies and procedures with respect to the required documentation and
approvals for the use of derivative financial instruments and specifically ties their use, in the
case of commodities, to the mitigation of price risk associated with cash flows expected to be
generated from budgeted capital programs and in other cases to the mitigation of price risks for
specific assets and obligations. With respect to transactions involving proprietary production or assets, the financial instruments
generally used by the Company are swaps, collars or options which are entered into with major
financial institutions, integrated energy companies or commodities trading institutions. Commodity Price
To partially mitigate the natural gas commodity price risk, the Company entered into swaps which
fix the AECO and NYMEX prices and collars and put options which fix the range of AECO and NYMEX
prices. To help protect against widening natural gas price differentials in various production
areas, the Company has entered into swaps to fix the AECO and Rockies price differential from the
NYMEX price. Physical contracts relating to these activities had an unrecognized loss of $9
million. The Company has also entered into contracts to purchase and sell natural gas as part of its daily
ongoing operations of the Companys proprietary production management. Physical contracts
associated with this activity had an unrecognized gain of $43 million. As part of its gas storage optimization program, EnCana has entered into financial instruments and
physical contracts at various locations and terms over the next 15 months to partially manage the
price volatility of the corresponding physical transactions and inventories. The financial
instruments used include futures, fixed for floating swaps and basis swaps. For crude oil price risk, the Company has partially mitigated its exposure to the WTI NYMEX price
for a portion of its oil production with fixed price swaps, three-way put spreads and put options. The Company has a power purchase arrangement contract that expires in 2005. This contract was
entered into as part of a cost management strategy. Foreign Exchange
As a means of mitigating the exposure to fluctuations in the U.S. to Canadian exchange rate, the
Company may enter into foreign exchange contracts. The Company also enters into foreign exchange
contracts in conjunction with crude oil marketing transactions. Gains or losses on these contracts
are recognized when the difference between the average month spot rate and the rate on the date of
settlement is determined. The Company also maintains a mix of both U.S. dollar and Canadian dollar debt which helps to offset
the exposure to the fluctuations in the U.S./Canadian dollar exchange rate. In addition to direct
issuance of U.S. dollar denominated debt, the Company has entered into cross currency swaps on a
portion of its debt as a means of managing the U.S./Canadian dollar debt mix. Interest Rates
The Company partially mitigates its exposure to interest rate changes by maintaining a mix of both
fixed and floating rate debt. The Company has entered into interest rate swap transactions from
time to time as a means of managing the fixed/floating rate debt portfolio mix. Credit Risk
The Company is exposed to credit related losses in the event of default by counterparties. The
Company does not expect any counterparties to fail to meet their obligations because of credit
practices that are in place that limit transactions to counterparties of investment grade credit
quality. A substantial portion of the Companys accounts receivable is with customers in the oil
and gas industry. Credit losses on the accounts receivable may arise as a result of non-performance
by customers on their contractual obligations. To manage the Companys exposure to credit losses,
Board-approved credit policies govern the Companys credit portfolio. ENCANA CORPORATION 2004
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OPERATIONAL RISK
EnCana mitigates operational risk through a number of policies and processes. As part of the
capital approval process, the Companys projects are evaluated on a fully risked basis, including
geological risk and engineering risk. In addition, the asset teams undertake a process called
Lookback and Learning. In this process, each asset team undertakes a thorough review of their
previous capital program to identify key learnings, which often includes operational issues that
positively and negatively impacted the projects results. Mitigation plans are developed for the
operational issues which had a negative impact on results. These mitigation plans are then
incorporated into the current year plan for the project. On an annual basis, these Lookback results
are analyzed for the Companys capital program with the results and identified learnings shared
across the Company. All projects include a Business Risk Burden that is intended to account for the unforeseen risks.
The amount of Business Risk Burden that is used on a particular project depends on the projects
history of Lookback results and the type of expenditure.
A peer review process is used to ensure that capital projects are appropriately risked and that
knowledge is shared across the Company. Peer reviews are undertaken primarily for exploration
projects and early stage resource plays, although they may occur for any type of project. The Company also partially mitigates operational risks by maintaining a comprehensive insurance
program. ENVIRONMENT, HEALTH, SAFETY AND SECURITY RISK
These risks are managed by executing policies and standards that comply with or exceed government
regulations and industry standards. In addition, the Company maintains a system that identifies,
assesses and controls safety and environmental risk and requires regular reporting to senior
management and the Board of Directors. The Corporate Responsibility, Environment, Health & Safety
Committee of EnCanas Board of Directors approves environmental policy and oversees compliance with
government laws and regulations. Monitoring and reporting programs for environmental, health and
safety performance in day-to-day operations, as well as inspections and assessments, are designed
to provide assurance that environmental and regulatory standards are met. Contingency plans are in
place for a timely response to an environmental event and remediation/reclamation strategies are
utilized to restore the environment. Security risks are managed through a Security Program designed to ensure that EnCanas personnel
and assets are protected. EnCana has also established an Investigations Committee with the mandate
to address potential violations of Company policies and practices. Kyoto Protocol
The Kyoto protocol, ratified by the Canadian Federal Government in December 2002, came into force
on February 16, 2005. The protocol commits Canada to reducing greenhouse gas emissions to six
percent below 1990 levels over the period 2008  2012. It is expected that the Federal Government
will make a substantive announcement outlining its Climate Change action plan coinciding with Kyoto
coming into force. The Climate Change Working Group of Canadian Association of Petroleum Producers
is working with the Federal and Alberta governments to develop an approach for implementing targets
and enabling greenhouse gas control legislation which protects the industrys competitiveness,
limits the cost and administrative burden of compliance and supports continued investment in the
sector. As the federal government has yet to release its Kyoto compliance plan, EnCana is unable to predict
the impact of the potential regulations upon its business; however, it is possible that the Company
would face increases in operating costs in order to comply with greenhouse gas emissions
legislation. REPUTATIONAL RISK
EnCana takes a pro-active approach to the identification and management of issues that affect the
Companys reputation and has established consistent and clear procedures, guidelines and
responsibility for identifying and managing these issues. Issues affecting or with the potential to
affect EnCanas reputation are generally either emerging issues that can be identified early and
then managed or unforeseen issues that arise unexpectedly and must be managed on an urgent basis. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M22




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OUTLOOK Volume Outlook for Continuing Operations 2005 Guidance(2)
    
    2004 Actual
    
    
    Increase in 2005 (3)Produced Gas Sales (MMcf per day)Canada
    
    2,200 - 2,300
    
    
    2,099
    
    
    
    7
    %United States
    
    1,150 - 1,200
    
    
    869
    
    
    
    35
    %Total Produced Gas Sales
    
    3,350 - 3,500
    
    
    2,968
    
    
    
    15
    %Crude Oil and NGLs (Mbbls per day)Canada
    
    135 - 155
    
    
    154
    
    
    
    -6
    %United States
    
    12 - 14
    
    
    12
    
    
    
    8
    %Total Crude Oil and NGLs
    
    150 - 170
    
    
    166
    
    
    
    -4
    %Total(MMcfe per day)(1)
    
    4,250 - 4,500
    
    
    3,966
    
    
    
    10
    %
   (1)
    
    Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet.(2)
    
    Guidance released February 23, 2005.(3)
    
    Using mid-point of guidance. 2005 Capital Investment for Continuing Operations ($ billions)Upstream
    
    $4.5 - $4.8Midstream & Marketing and Corporate
    
    0.4 - 0.4Core Capital
    
    $4.9 - $5.2
 EnCana plans to continue to focus principally on growing natural gas production and storage capacity in
North America. The Company will also continue to invest in in situ oilsands
development. Strong natural gas storage injection requirements combined with reduced U.S. and Canadian supply
have tightened the balance between supply and demand resulting in higher average natural gas prices
in 2004. The outlook for 2005 and beyond will be impacted by weather, timing of new
supplies and economic activity. Volatility in crude oil prices is expected to continue in 2005 as a result of market uncertainties
over continued demand growth in China, the reliability of production from key producing countries,
and OPEC success at managing prices and the overall state of the world economies. The Company expects its 2005 core capital investment program, of between $4.9 billion and $5.2
billion, to be funded from cash flow. EnCanas results are affected by external market factors, such as fluctuations in the prices of
crude oil and natural gas, as well as movements in foreign currency exchange rates. The following
tables provide projected estimates for 2005 of the sensitivity of the Companys 2005 net earnings
and cash flow to changes in commodity prices and the U.S./Canadian dollar exchange rate. Sensitivity of 2005 Net Earnings From Continuing Operations and
Cash Flow From Continuing Operations (Including
Hedges)(1)(2) Net Earnings
    
    
    Cash Flow FromFrom Continuing
    
    
    Continuing($ millions)
    
    Operations
    
    
    Operations$0.25 per million British thermal units increase in the NYMEX gas price
    
    $
    95
    
    
    $
    135$1.00 per barrel increase in the WTI oil price
    
    
    15
    
    
    
    15$0.01 decrease in the U.S.\ Canadian dollar exchange rate
    
    
    (20
    )
    
    
    5
   (1)
    
    Hedge position as at December 31, 2004.(2)
    
    Based on forward curve commodity price and forward curve estimates dated December 31, 2004. Sensitivity of 2005 Net Earnings From Continuing Operations and
Cash Flow From Continuing Operations (Excluding
Hedges)(1) Net Earnings
    
    
    Cash Flow FromFrom Continuing
    
    
    Continuing($ millions)
    
    Operations
    
    
    Operations$0.25 per million British thermal units increase in the NYMEX gas price
    
    $
    185
    
    
    $
    185$1.00 per barrel increase in the WTI oil price
    
    
    25
    
    
    
    25$0.01 decrease in the U.S.\ Canadian dollar exchange rate
    
    
    (20
    )
    
    
    5
   (1)
    
    Based on forward curve commodity price and forward curve estimates dated December 31, 2004. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M23




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##### 



These estimates are based on managements assumptions utilized for 2005 planning purposes, as
discussed in this section. Assumptions include certain levels and profiles of capital expenditures,
projected asset disposals, operating costs, projected sales volumes, tax rates, interest rates,
foreign currency exchange rates, inflation rates and other assumptions that impact operations.
These assumptions can vary significantly from actual events and may result in material variances
from the expected results. In determining the current income tax expense deducted in arriving at these estimates, management
has assumed a combined marginal tax rate of approximately 37 percent. This tax rate is itself
affected in varying degrees by the assumptions referred to in the preceding paragraph. ADVISORIES FORWARD-LOOKING STATEMENTS
In the interest of providing EnCana shareholders and potential investors with information regarding
the Company and its subsidiaries, including managements assessment of EnCanas and its
subsidiaries future plans and operations, certain statements contained in this MD&A constitute
forward-looking statements within the meaning of the safe harbour provisions of the United States
Private Securities Litigation Reform Act of 1995. Forward-looking statements are typically
identified by words such as anticipate, believe, expect, plan, intend, forecast,
target, project or similar words suggesting future outcomes or statements regarding an outlook.
Forward-looking statements in this MD&A include, but are not limited to, statements with respect
to: production and sales estimates for produced gas, crude oil and NGLs for 2005 and beyond;
projections regarding Canadian and U.S. supply, demand and storage requirements; the Companys
plans to focus on growing natural gas production and storage capacity in North America and medium
and long-term growth prospects internationally; projections relating to the volatility of crude oil
prices in 2005 and the reasons therefor; amounts which may be issued under the Companys
multi-jurisdictional shelf prospectus program; the Companys projected capital investment levels
for 2005 and the source of funding therefor; the effect of the Companys risk management program,
including the impact of derivative financial instruments; the Companys execution of share
purchases under its Normal Course Issuer Bid; the Companys defence of lawsuits; projections and
assumptions relating to capital expenditures, operating costs, sales volumes, tax rates, interest
rates, foreign currency exchange rates, inflation rates and other variables impacting the Company
and its operations; projections relating to expenses under the Companys Performance Share Units
plan; anticipated asset retirement obligation expenses; the impact of the Kyoto Accord on operating
costs; projected tax rates and projected current taxes payable for 2005 and the adequacy of the
Companys provision for taxes; rating agency monitoring and reviews which may occur in the future;
and the projected impact of off-balance sheet arrangements. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based will occur. By their
nature, forward-looking statements involve numerous assumptions, known and unknown risks and
uncertainties, both general and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward-looking statements will not occur, which may cause the
Companys actual performance and financial results in future periods to differ materially from any
estimates or projections of future performance or results expressed or implied by such
forward-looking statements. These risks and uncertainties include, among other things: volatility
of oil and gas prices; fluctuations in currency and interest rates; product supply and demand;
market competition; risks inherent in the Companys and its subsidiaries marketing operations,
including credit risks; imprecision of reserve estimates and estimates of recoverable quantities of
oil, natural gas and liquids from resource plays and other sources not currently classified as
proved; the Companys and its subsidiaries ability to replace and expand oil and gas reserves; its
ability to generate sufficient cash flow from operations to meet its current and future
obligations; the Companys ability to access external sources of debt and equity capital; the
timing and the costs of well and pipeline construction; the Companys and its subsidiaries ability
to secure adequate product transportation; changes in environmental and other regulations or the
interpretations of such regulations; political and economic conditions in the countries in which
the Company and its subsidiaries operate, including Ecuador; the risk of international war,
hostilities, civil insurrection and instability affecting countries in which the Company and its
subsidiaries operate and terrorist threats; risks associated with existing and potential future
lawsuits and regulatory actions made against the Company and its subsidiaries; and other risks and
uncertainties described from time to time in the reports and filings made with securities
regulatory authorities by EnCana. Statements relating to reserves or resources or resource
potential are deemed to be forward-looking statements, as they involve the implied assessment,
based on certain estimates and assumptions that the resources and reserves described exist in the
quantities predicted or estimated, and can be profitably produced in the future. Although EnCana
believes that the expectations represented by such forward-looking statements are reasonable, there
can be no assurance that such expectations will prove to be correct. Readers are cautioned that the
foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements
contained in this MD&A are made as of the date of this MD&A, and EnCana does not undertake any
obligation to update publicly or to revise any of the included forward-looking statements, whether
as a result of new information, future events or otherwise. The forward-looking statements
contained in this MD&A are expressly qualified by this cautionary statement. OIL AND GAS INFORMATION
EnCanas disclosure of reserves data and other oil and gas information is made in reliance on an
exemption granted to EnCana by Canadian securities regulatory authorities which permits it to
provide such disclosure in accordance with U.S. disclosure requirements. The information provided
by EnCana may differ from the corresponding information prepared in accordance with Canadian
disclosure standards under National ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M24




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##### 



Instrument 51-101 (NI 51-101). The reserves quantities disclosed by EnCana represent net proved
reserves calculated using the standards contained in Regulation S-X of the U.S. Securities and
Exchange Commission. Further information about the differences between the U.S. requirements and
the NI 51-101 requirements is set forth under the heading Note Regarding Reserves Data and Other
Oil and Gas Information in EnCanas Annual Information Form. Crude Oil, Natural Gas Liquids and Natural Gas Conversions
In this MD&A, certain crude oil and natural gas liquids (NGLs) volumes have been converted to
millions of cubic feet equivalent (MMcfe) or thousands of cubic feet equivalent (Mcfe) on the
basis of one barrel (bbl) to six thousand cubic feet (Mcf). Also, certain natural gas volumes
have been converted to barrels of oil equivalent (BOE), thousands of BOE (MBOE) or millions of
BOE (MMBOE) on the same basis. MMcfe, Mcfe, BOE, MBOE and MMBOE may be misleading, particularly
if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent equivalency at the
well head. Resource Play, Estimated Ultimate Recovery and Resource Potential
EnCana uses the terms resource play, estimated ultimate recovery and resource potential. Resource
play is a term used by EnCana to describe an accumulation of hydrocarbons known to exist over a
large areal expanse and/or thick vertical section, which when compared to a conventional play,
typically has a lower geological and/or commercial development risk and lower average decline rate.
As used by EnCana, estimated ultimate recovery has the meaning set out jointly by the Society of
Petroleum Engineers and World Petroleum Congress in the year 2000, being those quantities of
petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation,
plus those quantities already produced therefrom. Resource potential is a term used by EnCana to
refer to the estimated quantities of hydrocarbons that may be added to proved reserves over a
specified period of time largely from a specified resource play or plays. EnCanas current stated
estimates of unbooked resource potential utilize a five year time frame for their specified period
of time. CURRENCY, NON-GAAP MEASURES AND REFERENCES TO ENCANA
All information included in this MD&A and the Consolidated Financial Statements and comparative
information is shown on a U.S. dollar, after-royalties basis unless otherwise noted. Sales
forecasts reflect the mid-point of current public guidance on an after royalties basis. Current
Corporate Guidance assumes a U.S. dollar exchange rate of $0.79 for every Canadian dollar. Non-GAAP Measures
Certain measures in this MD&A do not have any standardized meaning as prescribed by Canadian
generally accepted accounting principles (Canadian GAAP) such as Cash Flow from Continuing
Operations, Cash Flow, Cash Flow from Continuing Operations per share-basic, Cash Flow from
Continuing Operations per share-diluted, Cash Flow per share-basic and Cash Flow per share-diluted,
Operating Earnings and Operating Earnings per share-diluted, Operating Earnings from Continuing
Operations and Operating Earnings from Continuing Operations per share diluted and therefore are
considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures
presented by other issuers. These measures have been described and presented in this MD&A in order
to provide shareholders and potential investors with additional information regarding the Companys
liquidity and its ability to generate funds to finance its operations. Managements use of these
measures has been disclosed further in this MD&A as these measures are discussed and presented. References To EnCana
For convenience, references in this MD&A to EnCana, the Company, we, us and our may,
where applicable, refer only to or include any relevant direct and indirect subsidiary corporations
and partnerships (Subsidiaries) of EnCana Corporation, and the assets, activities and initiatives
of such Subsidiaries. Additional Information
Further information regarding EnCana Corporation can be accessed under the Companys public filings
found at www.sedar.com and on the Companys website at
www.encana.com. ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$) M25




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##### 



EnCana Corporation CONSOLIDATED FINANCIAL
STATEMENTS Prepared in US$ For the Year Ended December 31, 2004




---



##### 



MANAGEMENT REPORT The accompanying Consolidated Financial Statements of EnCana Corporation are the
responsibility of Management. The financial statements have been prepared by Management in United
States dollars in accordance with Canadian Generally Accepted Accounting Principles and include
certain estimates that reflect Managements best judgments. Financial information contained
throughout the annual report is consistent with these financial statements. Management has overall responsibility for internal controls and has developed and maintains an
extensive system of internal controls that provides reasonable assurance that all transactions are
accurately recorded, that the financial statements realistically report the Companys operating and
financial results and that the Companys assets are safeguarded. The Companys Internal Audit
department reviews and evaluates the adequacy of and compliance with the Companys internal
controls. The policy of the Company is to maintain the highest standard of ethics in all its
activities and it has a written business conduct and ethics practice. The Companys Board of Directors has approved the information contained in the financial
statements. The Board of Directors fulfills its responsibility regarding the financial statements
mainly through its Audit Committee, which has a written mandate that complies with the current
requirements of the United States Sarbanes-Oxley Act of 2002 and voluntarily complies, in
principle, with the Audit Committee guidelines of the New York Stock Exchange and the Toronto Stock
Exchange. The Audit Committee meets at least on a quarterly basis. PricewaterhouseCoopers LLP, an independent firm of chartered accountants, was appointed by a vote
of shareholders at the Companys last annual meeting to audit the Consolidated Financial Statements
and provide an independent opinion. (signed)
Gwyn Morgan
President &
Chief Executive Officer
    
    (signed)
John D. Watson
Executive Vice-President &
Chief Financial Officer
 February 7, 2005 1




---



##### 



AUDITORS REPORT To the Shareholders of EnCana Corporation We have audited the Consolidated Balance Sheets of EnCana Corporation as at December 31, 2004 and
December 31, 2003 and the Consolidated Statements of Earnings, Retained Earnings and Cash Flows for
each of the years in the three-year period ended December 31, 2004. These financial statements are
the responsibility of the Companys Management. Our responsibility is to express an opinion on
these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we plan and perform an audit to obtain reasonable assurance whether the
financial statements are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant estimates made by Management, as
well as evaluating the overall financial statement presentation. In our opinion, these Consolidated Financial Statements present fairly, in all material respects,
the financial position of the Company as at December 31, 2004 and December 31, 2003 and the results
of its operations and its cash flows for each of the years in the three-year period ended December
31, 2004 in accordance with Canadian generally accepted accounting principles. (signed)
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada
February 7, 2005 Comments by Auditor for U.S. readers on Canada-U.S. Reporting Differences In the United States, reporting standards for auditors require the addition of an explanatory
paragraph (following the opinion paragraph) when there is a change in accounting principles that
has a material effect on the comparability of the Companys financial statements, such as the
changes described in Note 2 to the Consolidated Financial Statements. Our report to the
shareholders dated February 7, 2005 is expressed in accordance with Canadian reporting standards
which do not require a reference to such a change in accounting principles in the Auditors report
when the change is properly accounted for and adequately disclosed in the financial statements. (signed)
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada
February 7, 2005 2




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##### 



U.S. Dollars EnCana Corporation Consolidated Statement of Earnings For the years ended December 31,($ millions, except per share amounts)
    
    
    
    
    
    2004
    
    
    
    2003
    
    
    
    2002Revenues, Net of Royalties
    
    (Note 4)Upstream
    
    
    
    
    
    $
    7,256
    
    
    
    $
    5,797
    
    
    
    $
    3,326Midstream & Market Optimization
    
    
    
    
    
    
    4,749
    
    
    
    
    3,887
    
    
    
    
    2,594Corporate
    
    
    
    
    
    
    (195
    )
    
    
    
    2
    
    
    
    
    811,810
    
    
    
    
    9,686
    
    
    
    
    5,928Expenses
    
    (Note 4)Production and mineral taxes
    
    
    
    
    
    
    311
    
    
    
    
    164
    
    
    
    
    105Transportation and selling
    
    
    
    
    
    
    499
    
    
    
    
    484
    
    
    
    
    332Operating
    
    
    
    
    
    
    1,350
    
    
    
    
    1,196
    
    
    
    
    749Purchased product
    
    
    
    
    
    
    4,276
    
    
    
    
    3,455
    
    
    
    
    2,200Depreciation, depletion and amortization
    
    
    
    
    
    
    2,402
    
    
    
    
    1,989
    
    
    
    
    1,186Administrative
    
    
    
    
    
    
    197
    
    
    
    
    173
    
    
    
    
    118Interest, net
    
    (Note 7)
    
    
    397
    
    
    
    
    283
    
    
    
    
    286Accretion of asset retirement obligation
    
    (Note 14)
    
    
    22
    
    
    
    
    17
    
    
    
    
    13Foreign exchange gain
    
    (Note 8)
    
    
    (417
    )
    
    
    
    (598
    )
    
    
    
    (11
    )Stock-based compensation
    
    
    
    
    
    
    17
    
    
    
    
    18
    
    
    
    
    Gain on dispositions
    
    (Note 6)
    
    
    (113
    )
    
    
    
    (1
    )
    
    
    
    (33
    )8,941
    
    
    
    
    7,180
    
    
    
    
    4,945Net Earnings Before Income Tax
    
    
    
    
    
    
    2,869
    
    
    
    
    2,506
    
    
    
    
    983Income tax expense
    
    (Note 9)
    
    
    658
    
    
    
    
    364
    
    
    
    
    317Net Earnings From Continuing Operations
    
    
    
    
    
    
    2,211
    
    
    
    
    2,142
    
    
    
    
    666Net Earnings From Discontinued Operations
    
    (Note 5)
    
    
    1,302
    
    
    
    
    218
    
    
    
    
    146Net Earnings
    
    
    
    
    
    $
    3,513
    
    
    
    $
    2,360
    
    
    
    $
    812Net Earnings From Continuing Operations per Common Share
    
    (Note 18)Basic
    
    
    
    
    
    $
    4.80
    
    
    
    $
    4.52
    
    
    
    $
    1.59Diluted
    
    
    
    
    
    $
    4.72
    
    
    
    $
    4.47
    
    
    
    $
    1.58Net Earnings per Common Share
    
    (Note 18)Basic
    
    
    
    
    
    $
    7.63
    
    
    
    $
    4.98
    
    
    
    $
    1.94Diluted
    
    
    
    
    
    $
    7.51
    
    
    
    $
    4.92
    
    
    
    $
    1.92
 Consolidated Statement of Retained Earnings For the years ended December 31,($ millions)
    
    
    
    
    
    2004
    
    
    
    2003
    
    
    
    2002Retained Earnings, Beginning of Year
    
    
    
    
    
    $
    5,276
    
    
    
    $
    3,523
    
    
    
    $
    2,819Net Earnings
    
    
    
    
    
    
    3,513
    
    
    
    
    2,360
    
    
    
    
    812Dividends on Common Shares
    
    
    
    
    
    
    (183
    )
    
    
    
    (139
    )
    
    
    
    (108
    )Charges for Normal Course Issuer Bid
    
    (Note 15)
    
    
    (671
    )
    
    
    
    (468
    )
    
    
    
    Retained Earnings, End of Year
    
    
    
    
    
    $
    7,935
    
    
    
    $
    5,276
    
    
    
    $
    3,523
 See accompanying notes to Consolidated Financial Statements. 3




---



##### 



U.S. Dollars EnCana Corporation Consolidated Balance Sheet As at December 31,($ millions)
    
    
    
    
    
    2004
    
    
    
    2003AssetsCurrent AssetsCash and cash equivalents
    
    
    
    
    
    $
    602
    
    
    
    $
    113Accounts receivable and accrued revenues
    
    
    
    
    
    
    1,898
    
    
    
    
    1,165Risk management
    
    (Notes 2, 17)
    
    
    336
    
    
    
    
    Inventories
    
    (Note 10)
    
    
    513
    
    
    
    
    557Assets of discontinued operations
    
    (Note 5)
    
    
    156
    
    
    
    
    7813,505
    
    
    
    
    2,616Property, Plant and Equipment, net
    
    (Notes 4, 11)
    
    
    23,140
    
    
    
    
    17,770Investments and Other Assets
    
    (Note 12)
    
    
    334
    
    
    
    
    268Risk Management
    
    (Notes 2, 17)
    
    
    87
    
    
    
    
    Assets of Discontinued Operations
    
    (Note 5)
    
    
    1,623
    
    
    
    
    1,545Goodwill
    
    
    
    
    
    
    2,524
    
    
    
    
    1,911(Note 4)
    
    $
    31,213
    
    
    
    $
    24,110Liabilities and Shareholders EquityCurrent LiabilitiesAccounts payable and accrued liabilities
    
    
    
    
    
    $
    1,879
    
    
    
    $
    1,348Income tax payable
    
    
    
    
    
    
    359
    
    
    
    
    32Risk management
    
    (Notes 2, 17)
    
    
    241
    
    
    
    
    Liabilities of discontinued operations
    
    (Note 5)
    
    
    280
    
    
    
    
    405Current portion of long-term debt
    
    (Note 13)
    
    
    188
    
    
    
    
    2872,947
    
    
    
    
    2,072Long-Term Debt
    
    (Note 13)
    
    
    7,742
    
    
    
    
    6,088Other Liabilities
    
    
    
    
    
    
    118
    
    
    
    
    21Risk Management
    
    (Notes 2, 17)
    
    
    192
    
    
    
    
    Asset Retirement Obligation
    
    (Note 14)
    
    
    611
    
    
    
    
    383Liabilities of Discontinued Operations
    
    (Note 5)
    
    
    102
    
    
    
    
    112Future Income Taxes
    
    (Note 9)
    
    
    5,193
    
    
    
    
    4,15616,905
    
    
    
    
    12,832Commitments and Contingencies
    
    (Note 19)Shareholders EquityShare capital
    
    (Note 15)
    
    
    5,299
    
    
    
    
    5,305Share options, net
    
    
    
    
    
    
    10
    
    
    
    
    55Paid in surplus
    
    
    
    
    
    
    28
    
    
    
    
    18Retained earnings
    
    
    
    
    
    
    7,935
    
    
    
    
    5,276Foreign currency translation adjustment
    
    
    
    
    
    
    1,036
    
    
    
    
    62414,308
    
    
    
    
    11,278$
    31,213
    
    
    
    $
    24,110
 See accompanying notes to Consolidated Financial Statements. Approved by the Board (signed)
David P. OBrien
Director
    
    (signed)
Barry W. Harrison
Director
 4




---



##### 



U.S. Dollars EnCana Corporation Consolidated Statement of Cash Flows For the years ended December 31,($ millions)
    
    
    
    
    
    2004
    
    
    
    2003
    
    
    
    2002Operating ActivitiesNet earnings from continuing operations
    
    
    
    
    
    $
    2,211
    
    
    
    $
    2,142
    
    
    
    $
    666Depreciation, depletion and amortization
    
    
    
    
    
    
    2,402
    
    
    
    
    1,989
    
    
    
    
    1,186Future income taxes
    
    (Note 9)
    
    
    91
    
    
    
    
    477
    
    
    
    
    383Unrealized loss on risk management
    
    (Note 17)
    
    
    190
    
    
    
    
    
    
    
    
    
    Unrealized foreign exchange gain
    
    (Note 8)
    
    
    (285
    )
    
    
    
    (545
    )
    
    
    
    (23
    )Accretion of asset retirement obligation
    
    (Note 14)
    
    
    22
    
    
    
    
    17
    
    
    
    
    13Gain on dispositions
    
    (Note 6)
    
    
    (113
    )
    
    
    
    (1
    )
    
    
    
    (33
    )Other
    
    
    
    
    
    
    87
    
    
    
    
    56
    
    
    
    
    (133
    )Cash flow from continuing operations
    
    
    
    
    
    
    4,605
    
    
    
    
    4,135
    
    
    
    
    2,059Cash flow from discontinued operations
    
    
    
    
    
    
    375
    
    
    
    
    324
    
    
    
    
    360Cash flow
    
    
    
    
    
    
    4,980
    
    
    
    
    4,459
    
    
    
    
    2,419Net change in other assets and liabilities
    
    
    
    
    
    
    (176
    )
    
    
    
    (84
    )
    
    
    
    (17
    )Net change in non-cash working capital from continuing operations
    
    (Note 18)
    
    
    1,455
    
    
    
    
    (568
    )
    
    
    
    (889
    )Net change in non-cash working capital from discontinued operations
    
    
    
    
    
    
    (1,668
    )
    
    
    
    497
    
    
    
    
    1044,591
    
    
    
    
    4,304
    
    
    
    
    1,617Investing ActivitiesBusiness combinations
    
    (Note 3)
    
    
    (2,335
    )
    
    
    
    
    
    
    
    
    (80
    )Capital expenditures
    
    (Note 4)
    
    
    (4,817
    )
    
    
    
    (4,627
    )
    
    
    
    (2,771
    )Proceeds on disposal of assets
    
    (Note 4)
    
    
    1,144
    
    
    
    
    301
    
    
    
    
    363Dispositions (acquisitions)
    
    (Note 6)
    
    
    386
    
    
    
    
    (91
    )
    
    
    
    60Equity investments
    
    
    
    
    
    
    47
    
    
    
    
    (6
    )
    
    
    
    Net change in investments and other
    
    
    
    
    
    
    45
    
    
    
    
    (15
    )
    
    
    
    39Net change in non-cash working capital from continuing operations
    
    (Note 18)
    
    
    (21
    )
    
    
    
    (113
    )
    
    
    
    195Discontinued operations
    
    
    
    
    
    
    1,292
    
    
    
    
    822
    
    
    
    
    (401
    )(4,259
    )
    
    
    
    (3,729
    )
    
    
    
    (2,595
    )Financing ActivitiesNet issuance of revolving long-term debt
    
    
    
    
    
    
    72
    
    
    
    
    288
    
    
    
    
    Issuance of long-term debt
    
    
    
    
    
    
    3,761
    
    
    
    
    500
    
    
    
    
    1,506Repayment of long-term debt
    
    
    
    
    
    
    (2,759
    )
    
    
    
    (142
    )
    
    
    
    (1,206
    )Issuance of common shares
    
    (Note 15)
    
    
    281
    
    
    
    
    114
    
    
    
    
    88Purchase of common shares
    
    (Note 15)
    
    
    (1,004
    )
    
    
    
    (868
    )
    
    
    
    Dividends on common shares
    
    
    
    
    
    
    (183
    )
    
    
    
    (139
    )
    
    
    
    (108
    )Other
    
    
    
    
    
    
    (5
    )
    
    
    
    (13
    )
    
    
    
    (54
    )Discontinued operations
    
    
    
    
    
    
    
    
    
    
    
    (282
    )
    
    
    
    272163
    
    
    
    
    (542
    )
    
    
    
    498Deduct: Foreign Exchange Loss (Gain) on Cash and
Cash Equivalents Held in Foreign Currency
    
    
    
    
    
    
    6
    
    
    
    
    10
    
    
    
    
    (2
    )Increase (Decrease) in Cash and Cash Equivalents
    
    
    
    
    
    
    489
    
    
    
    
    23
    
    
    
    
    (478
    )Cash and Cash Equivalents, Beginning of Year
    
    
    
    
    
    
    113
    
    
    
    
    90
    
    
    
    
    568Cash and Cash Equivalents, End of Year
    
    
    
    
    
    $
    602
    
    
    
    $
    113
    
    
    
    $
    90Supplemental Cash Flow Information
    
    (Note 18)
 See accompanying notes to Consolidated Financial Statements. 5




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##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are
expressed in United States (U.S.) dollars. EnCana has adopted the U.S. dollar as its reporting
currency since most of its revenue is closely tied to the U.S. dollar and to facilitate a more
direct comparison to other North American upstream exploration and development companies. All
references to US$ or to $ are to United States dollars and references to C$ are to Canadian
dollars. EnCana is in the business of exploration for, production and marketing of natural gas, crude oil
and natural gas liquids, as well as natural gas storage, natural gas liquids processing and power
generation operations. A) Principles of Consolidation The Consolidated Financial Statements include the accounts of EnCana Corporation and its
subsidiaries (EnCana or the Company), and are presented in accordance with Canadian generally
accepted accounting principles. Information prepared in accordance with generally accepted
accounting principles in the United States is included in Note 20. Investments in jointly controlled companies, jointly controlled partnerships (collectively called
affiliates) and unincorporated joint ventures are accounted for using the proportionate
consolidation method, whereby EnCanas proportionate share of revenues, expenses, assets and
liabilities are included in the accounts. Investments in companies and partnerships in which EnCana does not have direct or joint control
over the strategic operating, investing and financing decisions, but does have significant
influence on them, are accounted for using the equity method. B) Foreign Currency Translation The accounts of self-sustaining operations are translated using the current rate method, whereby
assets and liabilities are translated at period-end exchange rates, while revenues and expenses are
translated using average rates over the period. Translation gains and losses relating to the
self-sustaining operations are included as a separate component of shareholders equity. Monetary assets and liabilities of the Company that are denominated in foreign currencies are
translated into its functional currency at the rates of exchange in effect at the period end date.
Any gains or losses are recorded in the Consolidated Statement of Earnings. C) Measurement Uncertainty The timely preparation of the Consolidated Financial Statements in conformity with Canadian
generally accepted accounting principles requires that Management make estimates and assumptions
and use judgment regarding the reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the Consolidated Financial Statements and the
reported amounts of revenues and expenses during the period. Such estimates primarily relate to
unsettled transactions and events as of the date of the Consolidated Financial Statements.
Accordingly, actual results may differ from estimated amounts as future confirming events occur. Amounts recorded for depreciation, depletion and amortization, asset retirement costs and
obligations and amounts used for ceiling test and impairment calculations are based on estimates of
natural gas and
crude oil reserves and future costs required to develop those reserves. By their nature, these
estimates of reserves, including the estimates of future prices and costs, and the related future
cash flows are subject to measurement uncertainty, and the impact in the consolidated financial
statements of future periods could be material. 6




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The values of pension assets and obligations and the amount of pension costs charged to net
earnings depend on certain actuarial and economic assumptions which by their nature are subject to
measurement uncertainty. The amount of compensation expense accrued for long-term performance based compensation
arrangements are subject to Managements best estimate of whether or not the performance criteria
will be met and what the ultimate payout will be. D) Revenue Recognition Revenues associated with the sales of EnCanas natural gas, crude oil and natural gas liquids
(NGLs) are recognized when title passes from the Company to its customer. Natural gas and crude
oil produced and sold by EnCana below or above its working interest share in the related resource
properties results in production underliftings or overliftings. Underliftings are recorded as
inventory and overliftings are recorded as deferred revenue. Realized gains and losses from the
Companys commodity price risk management activities are recorded in revenue when the product is
sold. Marketing revenues and purchased product are recorded on a gross basis as the Company takes title
to product and has risks and rewards of ownership. Revenues associated with the services provided
where EnCana acts as agent are recorded as the services are provided. Revenues associated with the
sale of natural gas storage services are recognized when the services are provided. Sales of
electric power are recognized when power is provided to the customer. Unrealized gains and losses from the Companys commodity price risk management activities are
recorded as revenue based on the related mark-to-market calculations at the end of the respective
period. E) Production and Mineral Taxes Costs paid by EnCana to non-mineral interest owners based on production of natural gas, crude oil
and NGLs are recognized when the product is produced. F) Transportation and Selling Costs Costs paid by EnCana for the transportation and selling of natural gas, crude oil and NGLs are
recognized when the product is delivered and the services provided. G) Employee Benefit Plans EnCana accrues for its obligations under its employee benefit plans and the related costs, net of
plan assets. The cost of pensions and other retirement and post-employment benefits is actuarially determined
using the projected benefit method based on length of service, and reflects Managements best
estimate of expected plan investment performance, salary escalation, retirement ages of employees
and expected future health care costs. The expected return on plan assets is based on the fair
value of those assets. The obligation is discounted using a market interest rate at the beginning
of the year on high quality corporate debt instruments. Pension expense includes the cost of pension benefits earned during the current year, the interest
cost on pension obligations, the expected return on pension plan assets, the amortization of the net
transitional obligation, the amortization of adjustments arising from pension plan amendments and
the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of
the benefit obligation and the fair value of plan assets. The amortization period covers the
expected 7




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##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED average remaining service lives of employees covered by the plans. Pension expense for the defined contribution pension plans is recorded as the benefits are earned
by the employees covered by the plans. H) Income Taxes EnCana follows the liability method of accounting for income taxes. Under this method, future
income taxes are recorded for the effect of any difference between the accounting and income tax
basis of an asset or liability, using the substantively enacted income tax rates. Accumulated
future income tax balances are adjusted to reflect changes in income tax rates that are
substantively enacted with the adjustment being recognized in earnings in the period that the
change occurs. I) Earnings Per Share Amounts Basic net earnings per common share is computed by dividing the net earnings by the weighted
average number of common shares outstanding during the period. Diluted net earnings per share
amounts are calculated giving effect to the potential dilution that would occur if stock options
were exercised or other contracts to issue common shares were exercised or converted to common
shares. The treasury stock method is used to determine the dilutive effect of stock options and
other dilutive instruments. The treasury stock method assumes that proceeds received from the
exercise of in-the-money stock options are used to repurchase common shares at the average market
price. J) Cash and Cash Equivalents Cash and cash equivalents include short-term investments, such as money market deposits or similar
type instruments, with a maturity of three months or less when purchased. K) Inventories Product inventories are valued at the lower of average cost and net realizable value on a first-in,
first-out basis. Materials and supplies are valued at cost. L) Property, Plant and Equipment Upstream EnCana accounts for natural gas and crude oil properties in accordance with the Canadian Institute
of Chartered Accountants guideline on full cost accounting in the oil and gas industry. Under
this method, all costs directly associated with the acquisition of, exploration for and the
development of, natural gas and crude oil reserves, including asset retirement costs, are
capitalized on a country-by-country cost centre basis. Costs accumulated within each cost centre are depreciated, depleted and amortized using the
unit-of-production method based on estimated proved reserves determined using estimated future
prices and costs. For purposes of this calculation, oil is converted to gas on an energy equivalent
basis. Capitalized costs subject to depletion include estimated future costs to be incurred in
developing proved reserves. Proceeds from the disposal of properties are normally deducted from
the full cost pool without recognition of gain or loss unless that deduction would result in a
change to the rate of depreciation, depletion and amortization of 20 percent or greater in which
case a gain or loss is recorded. Costs of major development projects and costs of acquiring and
evaluating significant unproved properties are excluded,
on a cost centre basis, from costs subject to depletion until it is determined whether or not
proved reserves are attributable to the properties, or impairment has occurred. Costs that have
been impaired are included in the costs subject to depreciation, depletion and amortization. 8




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not
recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount
of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted
cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount,
the impairment loss is limited to the amount by which the carrying amount exceeds the sum of:  i.
    the fair value of proved and probable reserves; andii.
    the costs of unproved properties that have been subject to a separate impairment test. Midstream Midstream facilities, including natural gas storage facilities, natural gas liquids extraction
plant facilities and power generation facilities, are carried at cost and depreciated on a
straight-line basis over the estimated service lives of the assets, which range from 20 to 25
years. Capital assets related to pipelines are carried at cost and depreciated or amortized using
the straight-line method over their economic lives, which range from 20 to 35 years. Corporate Costs associated with office furniture, fixtures, leasehold improvements, information technology
and aircraft are carried at cost and depreciated on a straight-line basis over the estimated
service lives of the assets, which range from 3 to 25 years. M) Capitalization of Costs Expenditures related to renewals or betterments that improve the productive capacity or extend the
life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Interest is capitalized during the construction phase of large capital projects. N) Amortization of Other Assets Amortization of deferred items included in Investments and Other Assets is provided for, where
applicable, on a straight-line basis over the estimated useful lives of the assets. O) Goodwill Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is
assessed by the Company for impairment at least annually. Goodwill and all other assets and
liabilities have been allocated to business levels, within the Companys segments, referred to as
reporting units. To assess impairment, the fair value of each reporting unit is determined and
compared to the book value of the reporting unit. If the fair value of the reporting unit is less
than the book value, then a second test is performed to determine the amount of the impairment.
The amount of the impairment is determined by deducting the fair value of the reporting units
assets and liabilities from the fair value of the reporting unit to determine the implied fair
value of goodwill and comparing that amount to the book value of the reporting units goodwill.
Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment
amount. P) Asset Retirement Obligation The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance
Sheet when identified and a reasonable estimate of fair value can be made. Asset retirement obligations
include those legal obligations where the Company will be required to retire tangible long-lived
assets such as producing well sites, offshore production platforms and natural gas processing 9




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED plants. These obligations also include items for which the Company has made promissory estoppel.
The asset retirement cost, equal to the initially estimated fair value of the asset retirement
obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the
estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash
flows are recognized as a change in the asset retirement obligation and the related asset
retirement cost. Asset retirement costs for natural gas and crude oil assets are amortized using the
unit-of-production method. Amortization of asset retirement costs are included in depreciation,
depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset
retirement obligation resulting from the passage of time are recorded as accretion of asset
retirement obligation in the Consolidated Statement of Earnings. Actual expenditures incurred are charged against the accumulated obligation. Q) Stock-based Compensation EnCana records compensation expense in the Consolidated Financial Statements for stock options
granted to employees and directors using the fair value method. Fair values are determined using
the Black-Scholes option-pricing model. Compensation costs are recognized over the vesting period. Obligations for cash payments under the Companys share appreciation rights, tandem share
appreciation rights, deferred share units and performance share units are accrued as compensation
expense over the vesting period. Fluctuations in the price of EnCanas common shares will change
the accrued compensation expense and are recognized when they occur. R) Derivative Financial Instruments Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded
using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated
Balance Sheet as either an asset or liability with changes in fair value recognized in net
earnings. Realized gains or losses from financial derivatives related to commodity prices are
recognized in natural gas and crude oil revenues as the related sales occur. Unrealized gains and
losses are recognized in revenues at the end of each respective reporting period. The estimated
fair value of all derivative instruments is based on quoted market prices or, in their absence,
third party market indications and forecasts. Derivative financial instruments are used by EnCana to manage economic exposure to market risks
relating to commodity prices, foreign currency exchange rates and interest rates. The Companys
policy is not to utilize derivative financial instruments for speculative purposes. EnCana has in place policies and procedures with respect to the required documentation and
approvals for the use of derivative financial instruments and specifically ties their use, in the
case of commodities, to the mitigation of market price risk associated with cash flows expected to
be generated from budgeted capital programs, and in other cases to the mitigation of market price
risks for specific assets and obligations. When applicable, the Company identifies relationships
between financial instruments and anticipated transactions, as well as its risk management
objective and the strategy for undertaking the economic hedge transaction. Where specific financial
instruments are executed, the Company assesses, both at the time of purchase and on an ongoing
basis, whether the financial instrument used in the particular transaction is effective in
offsetting changes in fair values or cash flows of the transaction. S) Reclassification Certain information provided for prior years has been reclassified to conform to the presentation
adopted in 2004. 10




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 2. CHANGES IN ACCOUNTING POLICIES AND PRACTICES A) Hedging Relationships On January 1, 2004, EnCana adopted the amendments made to the Canadian Institute of Chartered
Accountants Accounting Guideline 13 (AcG  13) Hedging Relationships, and Emerging Issues
Committee Abstract 128 (EIC 128) Accounting for Trading, Speculative or Non Trading Derivative
Financial Instruments. Derivative instruments that do not qualify as a hedge under AcG  13, or
are not designated as a hedge, are recorded in the Consolidated Balance Sheet as either an asset or
liability with changes in fair value recognized in net earnings. The Company elected not to
designate any of its risk management activities in place at December 31, 2003 as accounting hedges
under AcG  13 and, accordingly, accounted for all these non-hedging derivatives using the
mark-to-market accounting method. The impact on EnCanas Consolidated Financial Statements at January 1, 2004, resulted in the
recognition of risk management assets with a fair value of $145 million, risk management
liabilities with a fair value of $380 million and a net deferred loss of $235 million. At December
31, 2004, a net unrealized gain remains to be recognized over the next four years as follows: Unrealized Gain20053 months ended March 31
    
    $
    3 months ended June 30
    
    
    143 months ended September 30
    
    
    93 months ended December 31
    
    
    9Total to be recognized in 2005
    
    
    
    
    
    $
    322006
    
    $
    242007
    
    
    152008
    
    
    1Total to be recognized in 2006 through to 2008
    
    
    
    
    
    $
    40Total to be recognized
    
    
    
    
    
    $
    72Total to be
recognized  Continuing Operations
    
    
    
    
    
    $
    73Total to be
recognized  Discontinued Operations
    
    
    
    
    
    
    (1
    )$
    72
 At December 31, 2004, the remaining net deferred amounts recognized on transition are recorded
in the Consolidated Balance Sheet as follows: As at December 31
    
    2004Accounts receivable and accrued revenues
    
    $
    11Investments and other assets
    
    
    4Accounts payable and accrued liabilities
    
    
    44Other liabilities
    
    
    44Total Net
Deferred Gain  Continuing Operations
    
    $
    73Total Net
Deferred Loss  Discontinued Operations
    
    
    (1
    )Total Net Deferred Gain
    
    $
    72
 11




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED B) Consolidation of Variable Interest Entities On November 1, 2004, the
Company retroactively adopted the new CICA Accounting Guideline 15
(AcG 
15) Consolidation of Variable Interest Entities. AcG  15 defines a variable interest entity
(VIE) as a legal entity in which either the total equity at risk is not sufficient to permit the
entity to finance its activities without additional subordinated financial support provided by
other parties or the equity owners lack a controlling financial interest. The guideline requires
the enterprise which absorbs the majority of a VIEs expected gains or losses, the primary
beneficiary, to consolidate the VIE. There was no effect on EnCanas Consolidated Financial Statements prior to the adoption of the
guideline on November 1, 2004. Subsequent to November 1, 2004, the Company became the primary
beneficiary of a VIE. At December 31, 2004, EnCana has consolidated this VIE as described in Note
4. NOTE 3. BUSINESS COMBINATIONS TOM BROWN, INC. (TBI) On May 19, 2004, EnCana, through a wholly owned subsidiary, completed the tender offer for the
shares of Tom Brown, Inc. (TBI), a Denver based independent energy company, for total cash
consideration of $2.3 billion plus the assumption of $406 million of long-term debt. As part of the acquisition, EnCana acquired certain natural gas and crude oil properties in west
Texas and New Mexico and the assets of Sauer Drilling Company, a subsidiary of TBI, which were
designated as assets held for sale at the date of acquisition. These assets were sold on July 30,
2004. ALBERTA ENERGY COMPANY LTD. (AEC) On April 5, 2002, PanCanadian Energy Corporation (PanCanadian) and Alberta Energy Company Ltd.
completed a plan of arrangement (the Arrangement) under the Business Corporations Act (Alberta).
The Arrangement included a common share exchange, pursuant to which holders of common shares of AEC
received 1.472 common shares of PanCanadian for each common share of AEC that they held.
PanCanadian then changed its name to EnCana Corporation. These business combinations have been accounted for using the purchase method with the results of
operations included in the Consolidated Financial Statements from the dates of acquisition. 12




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The calculation of the purchase prices and the allocations to assets and liabilities is shown
below: TBI
    
    
    AECCalculation of Purchase Price:Common Shares issued to AEC shareholders (millions)
    
    
    
    
    
    
    218.5Price of Common Shares (C$  per common share)
    
    
    
    
    
    
    38.43Value of Common Shares issued
    
    
    
    
    
    $
    5,281Fair value of AEC share options exchanged for share options of
EnCana Corporation (Share options)
    
    
    
    
    
    
    105Cash paid for common shares of TBI
    
    $
    2,341Transaction costs
    
    
    13
    
    
    
    94Total purchase price
    
    $
    2,354
    
    
    $
    5,480Plus: Fair value of liabilities assumedCurrent liabilities
    
    
    224
    
    
    
    1,120Long-term debt (including preferred securities)
    
    
    406
    
    
    
    3,714Other non-current liabilities
    
    
    39
    
    
    
    180Future income taxes
    
    
    774
    
    
    
    1,665Total Purchase Price and Liabilities Assumed
    
    $
    3,797
    
    
    $
    12,159Fair Value of Assets Acquired:Current assets (including cash acquired)
    
    $
    425
    
    
    $
    946Property, plant and equipment, net
    
    
    2,890
    
    
    
    8,897Other non-current assets
    
    
    9
    
    
    
    381Goodwill
    
    
    473
    
    
    
    1,935Total Fair Value of Assets Acquired
    
    $
    3,797
    
    
    $
    12,159Goodwill Allocation:Upstream
    
    $
    473
    
    
    $
    1,504Midstream & Market Optimization
    
    
    
    
    
    
    49473
    
    
    
    1,553Discontinued Operations
    
    
    
    
    
    
    382Total Goodwill Allocation
    
    $
    473
    
    
    $
    1,935
 13




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 4. SEGMENTED INFORMATION The Company has defined its continuing operations into the following segments:  
    Upstream includes the Companys exploration for, and development and production of, natural
gas, crude oil and natural gas liquids and other related activities. The majority of the Companys
Upstream operations are located in Canada and the United States. International new venture
exploration is mainly focused on opportunities in Africa, South America, the Middle East and
Greenland.
    Midstream & Market Optimization is conducted by the Midstream & Marketing division.
Midstream includes natural gas storage, natural gas liquids processing and power generation. The
Marketing groups primary responsibility is the sale of the Companys proprietary production.
These results are included in the Upstream segment. Correspondingly, the Marketing groups also
undertake market optimization activities which comprise third party purchases and sales of product
that provide operational flexibility for transportation commitments, product type, delivery points
and customer diversification. These activities are reflected in the Midstream & Market
Optimization segment.
    Corporate includes unrealized gains or losses recorded on derivative instruments. Once
amounts are settled, the realized gains and losses are recorded in the operating segment to which
the derivative relates. Midstream & Market Optimization purchases substantially all of the Companys North American
Upstream production. Transactions between business segments are based on market values and
eliminated on consolidation. The tables in this note present financial information on an after
eliminations basis. Operations that have been discontinued are disclosed in Note 5. 14




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Results of Continuing Operations(for the years ended December 31) Midstream & MarketUpstream
    
    
    
    Optimization2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues, Net of Royalties
    
    $
    7,256
    
    
    $
    5,797
    
    
    $
    3,326
    
    
    
    $
    4,749
    
    
    $
    3,887
    
    
    $
    2,594ExpensesProduction and mineral taxes
    
    
    311
    
    
    
    164
    
    
    
    105
    
    
    
    
    
    
    
    
    
    
    
    
    Transportation and selling
    
    
    472
    
    
    
    429
    
    
    
    245
    
    
    
    
    27
    
    
    
    55
    
    
    
    87Operating
    
    
    1,026
    
    
    
    872
    
    
    
    562
    
    
    
    
    325
    
    
    
    324
    
    
    
    187Purchased product
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,276
    
    
    
    3,455
    
    
    
    2,200Depreciation, depletion and amortization
    
    
    2,271
    
    
    
    1,900
    
    
    
    1,115
    
    
    
    
    70
    
    
    
    48
    
    
    
    36Segment Income
    
    $
    3,176
    
    
    $
    2,432
    
    
    $
    1,299
    
    
    
    $
    51
    
    
    $
    5
    
    
    $
    84
 Corporate
    
    
    
    Consolidated2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues, Net of Royalties
    
    $
    (195
    )
    
    $
    2
    
    
    $
    8
    
    
    
    $
    11,810
    
    
    $
    9,686
    
    
    $
    5,928ExpensesProduction and mineral taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    311
    
    
    
    164
    
    
    
    105Transportation and selling
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    499
    
    
    
    484
    
    
    
    332Operating
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    
    1,350
    
    
    
    1,196
    
    
    
    749Purchased product
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,276
    
    
    
    3,455
    
    
    
    2,200Depreciation, depletion and amortization
    
    
    61
    
    
    
    41
    
    
    
    35
    
    
    
    
    2,402
    
    
    
    1,989
    
    
    
    1,186Segment Income
    
    $
    (255
    )
    
    $
    (39
    )
    
    $
    (27
    )
    
    
    
    2,972
    
    
    
    2,398
    
    
    
    1,356Administrative
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    197
    
    
    
    173
    
    
    
    118Interest, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    397
    
    
    
    283
    
    
    
    286Accretion of asset retirement obligation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    22
    
    
    
    17
    
    
    
    13Foreign exchange gain
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (417
    )
    
    
    (598
    )
    
    
    (11
    )Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    17
    
    
    
    18
    
    
    
    Gain on dispositions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (113
    )
    
    
    (1
    )
    
    
    (33
    )103
    
    
    
    (108
    )
    
    
    373Net Earnings Before Income Tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,869
    
    
    
    2,506
    
    
    
    983Income tax expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    658
    
    
    
    364
    
    
    
    317Net Earnings From Continuing Operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    2,211
    
    
    $
    2,142
    
    
    $
    666
 Results of Continuing Operations(for the years ended December 31) Canada
    
    
    
    United States2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues, Net of Royalties
    
    $
    5,083
    
    
    $
    4,474
    
    
    $
    2,796
    
    
    
    $
    1,941
    
    
    $
    1,143
    
    
    $
    454ExpensesProduction and mineral taxes
    
    
    87
    
    
    
    56
    
    
    
    70
    
    
    
    
    224
    
    
    
    108
    
    
    
    35Transportation and selling
    
    
    352
    
    
    
    343
    
    
    
    186
    
    
    
    
    120
    
    
    
    86
    
    
    
    59Operating
    
    
    685
    
    
    
    642
    
    
    
    456
    
    
    
    
    119
    
    
    
    60
    
    
    
    35Depreciation, depletion and amortization
    
    
    1,751
    
    
    
    1,511
    
    
    
    862
    
    
    
    
    475
    
    
    
    293
    
    
    
    202Segment Income
    
    $
    2,208
    
    
    $
    1,922
    
    
    $
    1,222
    
    
    
    $
    1,003
    
    
    $
    596
    
    
    $
    123
 Other
    
    
    
    Total Upstream2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues, Net of Royalties
    
    $
    232
    
    
    $
    180
    
    
    $
    76
    
    
    
    $
    7,256
    
    
    $
    5,797
    
    
    $
    3,326ExpensesProduction and mineral taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    311
    
    
    
    164
    
    
    
    105Transportation and selling
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    472
    
    
    
    429
    
    
    
    245Operating
    
    
    222
    
    
    
    170
    
    
    
    71
    
    
    
    
    1,026
    
    
    
    872
    
    
    
    562Depreciation, depletion and amortization
    
    
    45
    
    
    
    96
    
    
    
    51
    
    
    
    
    2,271
    
    
    
    1,900
    
    
    
    1,115Segment Income
    
    $
    (35
    )
    
    $
    (86
    )
    
    $
    (46
    )
    
    
    $
    3,176
    
    
    $
    2,432
    
    
    $
    1,299
 15




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Total Midstream & MarketMidstream
    
    
    
    Market Optimization
    
    
    
    Optimization2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues
    
    $
    1,450
    
    
    $
    1,084
    
    
    $
    440
    
    
    
    $
    3,299
    
    
    $
    2,803
    
    
    $
    2,154
    
    
    
    $
    4,749
    
    
    $
    3,887
    
    
    $
    2,594ExpensesTransportation and selling
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    27
    
    
    
    55
    
    
    
    87
    
    
    
    
    27
    
    
    
    55
    
    
    
    87Operating
    
    
    279
    
    
    
    261
    
    
    
    174
    
    
    
    
    46
    
    
    
    63
    
    
    
    13
    
    
    
    
    325
    
    
    
    324
    
    
    
    187Purchased product
    
    
    1,071
    
    
    
    762
    
    
    
    169
    
    
    
    
    3,205
    
    
    
    2,693
    
    
    
    2,031
    
    
    
    
    4,276
    
    
    
    3,455
    
    
    
    2,200Depreciation, depletion and amortization
    
    
    68
    
    
    
    40
    
    
    
    24
    
    
    
    
    2
    
    
    
    8
    
    
    
    12
    
    
    
    
    70
    
    
    
    48
    
    
    
    36Segment Income
    
    $
    32
    
    
    $
    21
    
    
    $
    73
    
    
    
    $
    19
    
    
    $
    (16
    )
    
    $
    11
    
    
    
    $
    51
    
    
    $
    5
    
    
    $
    84
 Upstream Geographic and Product Information (Continuing Operations)(for the years ended December 31) Produced GasCanada
    
    
    
    United States
    
    
    
    Total2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues, Net of Royalties
    
    $
    3,928
    
    
    $
    3,396
    
    
    $
    1,882
    
    
    
    $
    1,776
    
    
    $
    1,051
    
    
    $
    398
    
    
    
    $
    5,704
    
    
    $
    4,447
    
    
    $
    2,280ExpensesProduction and mineral taxes
    
    
    65
    
    
    
    52
    
    
    
    50
    
    
    
    
    205
    
    
    
    101
    
    
    
    32
    
    
    
    
    270
    
    
    
    153
    
    
    
    82Transportation and selling
    
    
    296
    
    
    
    274
    
    
    
    151
    
    
    
    
    120
    
    
    
    86
    
    
    
    59
    
    
    
    
    416
    
    
    
    360
    
    
    
    210Operating
    
    
    400
    
    
    
    342
    
    
    
    255
    
    
    
    
    119
    
    
    
    60
    
    
    
    35
    
    
    
    
    519
    
    
    
    402
    
    
    
    290Operating Cash Flow
    
    $
    3,167
    
    
    $
    2,728
    
    
    $
    1,426
    
    
    
    $
    1,332
    
    
    $
    804
    
    
    $
    272
    
    
    
    $
    4,499
    
    
    $
    3,532
    
    
    $
    1,698
 Oil and NGLsCanada
    
    
    
    United States
    
    
    
    Total2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues, Net of Royalties
    
    $
    1,155
    
    
    $
    1,078
    
    
    $
    914
    
    
    
    $
    165
    
    
    $
    92
    
    
    $
    56
    
    
    
    $
    1,320
    
    
    $
    1,170
    
    
    $
    970ExpensesProduction and mineral taxes
    
    
    22
    
    
    
    4
    
    
    
    20
    
    
    
    
    19
    
    
    
    7
    
    
    
    3
    
    
    
    
    41
    
    
    
    11
    
    
    
    23Transportation and selling
    
    
    56
    
    
    
    69
    
    
    
    35
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    56
    
    
    
    69
    
    
    
    35Operating
    
    
    285
    
    
    
    300
    
    
    
    201
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    285
    
    
    
    300
    
    
    
    201Operating Cash Flow
    
    $
    792
    
    
    $
    705
    
    
    $
    658
    
    
    
    $
    146
    
    
    $
    85
    
    
    $
    53
    
    
    
    $
    938
    
    
    $
    790
    
    
    $
    711
 Other
    
    
    
    Total Upstream2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Revenues, Net of Royalties
    
    $
    232
    
    
    $
    180
    
    
    $
    76
    
    
    
    $
    7,256
    
    
    $
    5,797
    
    
    $
    3,326ExpensesProduction and mineral taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    311
    
    
    
    164
    
    
    
    105Transportation and selling
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    472
    
    
    
    429
    
    
    
    245Operating
    
    
    222
    
    
    
    170
    
    
    
    71
    
    
    
    
    1,026
    
    
    
    872
    
    
    
    562Operating Cash Flow
    
    $
    10
    
    
    $
    10
    
    
    $
    5
    
    
    
    $
    5,447
    
    
    $
    4,332
    
    
    $
    2,414
 Capital Expenditures (Continuing Operations) For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002UpstreamCanada
    
    $
    3,079
    
    
    
    $
    3,198
    
    
    
    $
    1,388United States
    
    
    1,549
    
    
    
    
    968
    
    
    
    
    1,176Other Countries
    
    
    79
    
    
    
    
    78
    
    
    
    
    1174,707
    
    
    
    
    4,244
    
    
    
    
    2,681Midstream & Market Optimization
    
    
    64
    
    
    
    
    276
    
    
    
    
    47Corporate
    
    
    46
    
    
    
    
    107
    
    
    
    
    43Total
    
    $
    4,817
    
    
    
    $
    4,627
    
    
    
    $
    2,771
 16




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED On December 17, 2004, EnCana acquired certain natural gas and crude oil properties in Texas
for approximately $251 million. The purchase was facilitated by an unrelated party, Brown Ranger
LLC, which holds the assets in trust for the Company. Pursuant to the agreement with Brown Ranger
LLC, EnCana operates the properties, receives all the revenue and pays all of the expenses
associated with the properties. The assets will be transferred to EnCana at the earlier of June 15,
2005 or upon the disposition of certain natural gas and crude oil properties by EnCana. EnCana has
determined that the relationship with Brown Ranger LLC represents an interest in a VIE and that
EnCana is the primary beneficiary of the VIE. EnCana has consolidated Brown Ranger LLC from the
date of acquisition. In addition to the capital expenditures, during 2004, EnCana divested of mature conventional oil
and gas assets and other property, plant and equipment for proceeds of $1,144 million (2003  $301
million; 2002  $363 million). Additions to Goodwill There was one addition to
goodwill during 2004 (2003  none) as a result of the business
combination with Tom Brown, Inc. (see Note 3). Property, Plant and Equipment and Total Assets Property, Plant andAs at December 31
    
    
    
    
    
    Equipment
    
    
    
    Total Assets2004
    
    
    2003
    
    
    
    2004
    
    
    2003Upstream
    
    
    
    
    
    $
    22,097
    
    
    $
    16,757
    
    
    
    $
    26,118
    
    
    $
    19,416Midstream & Market Optimization
    
    
    
    
    
    
    804
    
    
    
    784
    
    
    
    
    1,904
    
    
    
    1,879Corporate
    
    
    
    
    
    
    239
    
    
    
    229
    
    
    
    
    1,412
    
    
    
    489Assets of Discontinued Operations
    
    (Note 5)
    
    
    
    
    
    
    
    
    
    
    
    1,779
    
    
    
    2,326Total
    
    
    
    
    
    $
    23,140
    
    
    $
    17,770
    
    
    
    $
    31,213
    
    
    $
    24,110
 Export Sales
Sales of natural gas, crude oil and natural gas liquids produced or purchased in Canada made
outside of Canada were $1,747 million (2003  $1,484 million; 2002  $1,333 million). Major Customers
In connection with the marketing and sale of EnCanas own and purchased natural gas and crude oil,
for the year ended December 31, 2004, the Company had one
customer (2003  two) which individually accounted for more than 10 percent of its consolidated revenues, net of royalties. Sales to this
customer, a major international integrated energy company with a high quality investment grade
credit rating, were approximately $1,709 million (2003  $1,362 million). NOTE 5. DISCONTINUED OPERATIONS 2004 On December 1, 2004, the Company completed the sale of its 100 percent interest in EnCana (U.K.)
Limited for net cash consideration of approximately $2.1 billion. EnCanas U.K. operations included
crude oil and natural gas interests in the U.K. central North Sea including the Buzzard, Scott and
Telford oil fields, as well as other satellite discoveries and exploration licenses. A gain on sale
of approximately $1.4 billion was recorded. Accordingly, these operations have been accounted for
as discontinued operations. At December 31, 2004, EnCana has decided to divest of its Ecuador operations and such operations
have been accounted for as discontinued operations. EnCanas Ecuador operations include the 100
percent working interest in the Tarapoa Block, majority operating interest in Blocks 14, 17 and 17




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Shiripuno, the non-operated economic interest in Block 15 and the 36.3 percent indirect equity
investment in Oleoducto de Crudos Pesados (OCP) Ltd. (OCP), which is the owner of a crude oil
pipeline in Ecuador that ships crude oil from the producing areas of Ecuador to an export marine terminal. The Company
is a shipper on the OCP Pipeline and pays commercial rates for tariffs. The majority of the
Companys crude oil produced in Ecuador is sold to a single marketing company. Payments are secured
by letters of credit from a major financial institution which has a high quality investment grade
credit rating. 2003 In 2003, in two separate transactions, the Company completed the sale of its 13.75 percent working
interest and a gross overriding royalty in the Syncrude Joint Venture (Syncrude) for net cash
consideration of $999 million. 2002 On April 24, 2002, the Company adopted formal plans to exit from the Houston-based merchant energy
operation, which were completed in 2002. These operations were included in the Midstream & Market
Optimization segment. Accordingly, these operations have been accounted for as discontinued
operations. On November 19, 2002, the Company announced that it had entered into agreements to sell its
discontinued pipelines operations for approximately $1 billion including the assumption of
long-term debt by the purchaser. On January 2, 2003 and January 9, 2003, these sales were
completed resulting in an after-tax gain on sale of $169 million. CONSOLIDATED STATEMENT OF EARNINGS The following tables present the effect of discontinued operations in the Consolidated Statement of
Earnings: 2004 Upstream  United Kingdom For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Revenues, Net of Royalties
    
    $
    153
    
    
    
    $
    118
    
    
    
    $
    103ExpensesTransportation and selling
    
    
    36
    
    
    
    
    16
    
    
    
    
    11Operating
    
    
    36
    
    
    
    
    18
    
    
    
    
    11Depreciation, depletion and amortization
    
    
    118
    
    
    
    
    74
    
    
    
    
    39Interest, net
    
    
    (9
    )
    
    
    
    
    
    
    
    
    Accretion of asset retirement obligation
    
    
    3
    
    
    
    
    1
    
    
    
    
    Foreign exchange gain
    
    
    (2
    )
    
    
    
    (5
    )
    
    
    
    (3
    )(Gain) loss on disposition
    
    
    (1
    )
    
    
    
    1
    
    
    
    
    (Gain) loss on discontinuance
    
    
    (1,364
    )
    
    
    
    
    
    
    
    
    (1,183
    )
    
    
    
    105
    
    
    
    
    58Net Earnings Before Income Tax
    
    
    1,336
    
    
    
    
    13
    
    
    
    
    45Income tax (recovery) expense
    
    
    (2
    )
    
    
    
    20
    
    
    
    
    21Net Earnings (Loss) From Discontinued Operations
    
    $
    1,338
    
    
    
    $
    (7
    )
    
    
    $
    24
 18




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Upstream  Ecuador For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Revenues, Net of Royalties
    
    $
    471
    
    
    
    $
    412
    
    
    
    $
    245ExpensesProduction and mineral taxes
    
    
    61
    
    
    
    
    25
    
    
    
    
    14Transportation and selling
    
    
    60
    
    
    
    
    45
    
    
    
    
    21Operating
    
    
    125
    
    
    
    
    83
    
    
    
    
    53Depreciation, depletion and amortization
    
    
    263
    
    
    
    
    159
    
    
    
    
    79Administrative
    
    
    
    
    
    
    
    
    
    
    
    
    1Interest, net
    
    
    (3
    )
    
    
    
    4
    
    
    
    
    4Accretion of asset retirement obligation
    
    
    1
    
    
    
    
    1
    
    
    
    
    Foreign exchange loss
    
    
    5
    
    
    
    
    2
    
    
    
    
    512
    
    
    
    
    319
    
    
    
    
    172Net (Loss) Earnings Before Income Tax
    
    
    (41
    )
    
    
    
    93
    
    
    
    
    73Income tax (recovery) expense
    
    
    (8
    )
    
    
    
    61
    
    
    
    
    28Net (Loss) Earnings From Discontinued Operations
    
    $
    (33
    )
    
    
    $
    32
    
    
    
    $
    45
 2003 Upstream  Syncrude For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Revenues, Net of Royalties
    
    $
    (1
    )
    
    
    $
    87
    
    
    
    $
    232ExpensesTransportation and selling
    
    
    
    
    
    
    
    2
    
    
    
    
    3Operating
    
    
    
    
    
    
    
    46
    
    
    
    
    105Depreciation, depletion and amortization
    
    
    
    
    
    
    
    7
    
    
    
    
    16Interest, net
    
    
    
    
    
    
    
    
    
    
    
    
    1Loss on discontinuance
    
    
    2
    
    
    
    
    
    
    
    
    
    2
    
    
    
    
    55
    
    
    
    
    125Net (Loss) Earnings Before Income Tax
    
    
    (3
    )
    
    
    
    32
    
    
    
    
    107Income tax expense
    
    
    
    
    
    
    
    8
    
    
    
    
    28Net (Loss) Earnings From Discontinued Operations
    
    $
    (3
    )
    
    
    $
    24
    
    
    
    $
    79
 2002 Midstream & Market Optimization For the years ended December 31
    
    Merchant Energy
    
    
    
    Midstream  Pipelines
    
    
    
    Total2003
    
    
    2002
    
    
    
    2003
    
    
    2002
    
    
    
    2003
    
    
    2002Revenues
    
    $
    
    
    
    $
    922
    
    
    
    $
    
    
    
    $
    135
    
    
    
    $
    
    
    
    $
    1,057ExpensesOperating
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    50
    
    
    
    
    
    
    
    
    50Purchased product
    
    
    
    
    
    
    931
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    931Depreciation, depletion and
amortization
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18
    
    
    
    
    
    
    
    
    18Administrative
    
    
    
    
    
    
    22
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    22Interest, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19
    
    
    
    
    
    
    
    
    19Foreign exchange gain
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3
    )
    
    
    
    
    
    
    
    (3
    )Loss (gain) on discontinuance
    
    
    
    
    
    
    19
    
    
    
    
    (220
    )
    
    
    
    
    
    
    
    (220
    )
    
    
    19
    
    
    
    972
    
    
    
    
    (220
    )
    
    
    84
    
    
    
    
    (220
    )
    
    
    1,056Net (Loss) Earnings Before Income Tax
    
    
    
    
    
    
    (50
    )
    
    
    
    220
    
    
    
    51
    
    
    
    
    220
    
    
    
    1Income tax (recovery) expense
    
    
    
    
    
    
    (17
    )
    
    
    
    51
    
    
    
    20
    
    
    
    
    51
    
    
    
    3Net (Loss) Earnings From
Discontinued Operations
    
    $
    
    
    
    $
    (33
    )
    
    
    $
    169
    
    
    $
    31
    
    
    
    $
    169
    
    
    $
    (2
    )
 19




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Consolidated Total For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Revenues, Net of Royalties
    
    $
    623
    
    
    
    $
    617
    
    
    
    $
    1,637ExpensesProduction and mineral taxes
    
    
    61
    
    
    
    
    25
    
    
    
    
    14Transportation and selling
    
    
    96
    
    
    
    
    63
    
    
    
    
    35Operating
    
    
    161
    
    
    
    
    147
    
    
    
    
    219Purchased product
    
    
    
    
    
    
    
    
    
    
    
    
    931Depreciation, depletion and amortization
    
    
    381
    
    
    
    
    240
    
    
    
    
    152Administrative
    
    
    
    
    
    
    
    
    
    
    
    
    23Interest, net
    
    
    (12
    )
    
    
    
    4
    
    
    
    
    24Accretion of asset retirement obligation
    
    
    4
    
    
    
    
    2
    
    
    
    
    Foreign exchange loss (gain)
    
    
    3
    
    
    
    
    (3
    )
    
    
    
    (6
    )(Gain) loss on disposition
    
    
    (1
    )
    
    
    
    1
    
    
    
    
    (Gain) loss on discontinuance
    
    
    (1,362
    )
    
    
    
    (220
    )
    
    
    
    19(669
    )
    
    
    
    259
    
    
    
    
    1,411Net Earnings Before Income Tax
    
    
    1,292
    
    
    
    
    358
    
    
    
    
    226Income tax (recovery) expense
    
    
    (10
    )
    
    
    
    140
    
    
    
    
    80Net Earnings From Discontinued Operations
    
    $
    1,302
    
    
    
    $
    218
    
    
    
    $
    146
 CONSOLIDATED BALANCE SHEET The impact of the discontinued operations in the Consolidated Balance Sheet is as follows: As at December 31
    
    2004
    
    
    
    2003AssetsCash and cash equivalents
    
    $
    14
    
    
    
    $
    35Accounts receivable and accrued revenues
    
    
    124
    
    
    
    
    202Risk management
    
    
    3
    
    
    
    
    Inventories
    
    
    15
    
    
    
    
    16156
    
    
    
    
    253Property, plant and equipment, net
    
    
    1,295
    
    
    
    
    1,775Investments and other assets
    
    
    328
    
    
    
    
    298$
    1,779
    
    
    
    $
    2,326LiabilitiesAccounts payable and accrued liabilities
    
    $
    96
    
    
    
    $
    231Income tax payable
    
    
    101
    
    
    
    
    33Risk management
    
    
    72
    
    
    
    
    269
    
    
    
    
    264Asset retirement obligation
    
    
    22
    
    
    
    
    47Future income taxes
    
    
    91
    
    
    
    
    206382
    
    
    
    
    517Net Assets of Discontinued Operations
    
    $
    1,397
    
    
    
    $
    1,809
 The prices used in the ceiling test evaluation of the Companys crude oil reserves in Ecuador
at December 31, 2004 were as follows: % increase to2005
    
    
    
    2006
    
    
    
    2007
    
    
    
    2008
    
    
    
    2009
    
    
    
    2016Crude Oil ($/barrel)
    
    $
    33.27
    
    
    
    $
    29.89
    
    
    
    $
    23.47
    
    
    
    $
    23.43
    
    
    
    $
    23.45
    
    
    
    
    13
    %
 20




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Acquisition / Disposition On January 31, 2003, the Company acquired the Ecuador interests of Vintage Petroleum Inc.
(Vintage) for net cash consideration of $116 million. During the fourth quarter of 2003, the
Company disposed of its interest in Block 27 in Ecuador for approximately $14 million. Commitments and Contingencies The Company is a shipper on the OCP Pipeline and has tariff commitments as follows: As at December 31, 2004
    
    2005
    
    
    
    2006
    
    
    
    2007
    
    
    
    2008
    
    
    
    2009
    
    
    
    Thereafter
    
    
    
    TotalPipeline Transportation
    
    $
    99
    
    
    
    $
    93
    
    
    
    $
    92
    
    
    
    $
    93
    
    
    
    $
    95
    
    
    
    $
    837
    
    
    
    $
    1,309
 In Ecuador, a subsidiary of EnCana has a 40 percent non-operated economic interest in relation
to Block 15 pursuant to a contract with a subsidiary of Occidental Petroleum Corporation. During
the year, Occidental Petroleum Corporation filed a Form 8-K indicating that its subsidiary had
received formal notification from Petroecuador, the state oil company of Ecuador, initiating
proceedings to determine if the subsidiary had violated the Hydrocarbons Law and its Participation
Contract for Block 15 with Petroecuador and whether such violations constitute grounds for
terminating the Participation Contract. In its Form 8-K, Occidental Petroleum Corporation indicated that it believes that it has complied
with all material obligations under the Participation Contract and that any termination of the
Participation Contract by Ecuador based upon these stated allegations would be unfounded and would
constitute an unlawful expropriation under international treaties. In addition to the above, the Company is proceeding with its arbitration related to value-added tax
(VAT) owed to EnCana ($139 million at December 31, 2004). EnCana is also in discussions related
to certain income tax matters related to the deductibility of interest expense in Ecuador. NOTE 6. DISPOSITIONS (ACQUISITIONS) For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002AcquisitionsPetrovera Resources
    
    $
    (253
    )
    
    
    $
    
    
    
    
    $
    Savannah
    
    
    
    
    
    
    
    (91
    )
    
    
    
    Other
    
    
    (34
    )
    
    
    
    
    
    
    
    
    (287
    )
    
    
    
    (91
    )
    
    
    
    DispositionsPetrovera Resources
    
    
    540
    
    
    
    
    
    
    
    
    
    Alberta Ethane Gathering System Joint Venture
    
    
    108
    
    
    
    
    
    
    
    
    
    Kingston CoGen Limited Partnership
    
    
    25
    
    
    
    
    
    
    
    
    
    EnCana Suffield Gas Pipeline Inc.
    
    
    
    
    
    
    
    
    
    
    
    
    60673
    
    
    
    
    
    
    
    
    
    60$
    386
    
    
    
    $
    (91
    )
    
    
    $
    60
 On December 22, 2004 EnCana completed the disposition of its interest in the Alberta Ethane
Gathering System Joint Venture for approximately $108 million, including working capital. A $54
million pre-tax gain was recorded on this sale. On December 15, 2004, EnCana sold its 25 percent limited partnership interest in the Kingston CoGen
Limited Partnership (Kingston) for net cash consideration of $25 million. A pre-tax gain of $28
million was recorded on this sale. 21




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED In March 2004, the Company sold its equity investment in a well servicing company for
approximately $44 million, recording a pre-tax gain on sale of $34 million. On February 18, 2004, the Company sold its 53.3 percent interest in Petrovera Resources for
approximately $287 million, including working capital adjustments. In order to facilitate the
transaction, the Company purchased the 46.7 percent interest of its partner for approximately $253
million, including working capital adjustments, and then sold the 100 percent interest for a total
of approximately $540 million, including working capital adjustments. In accordance with full cost
accounting for oil and gas activities, proceeds were credited to property, plant and equipment. On July 18, 2003, the Company acquired the common shares of Savannah Energy Inc. (Savannah) for
net cash consideration of $91 million. Savannahs operations are in Texas, U.S.A. In 2002, the Company sold its interest in EnCana Suffield Gas Pipeline Inc. for $60 million,
recording a pre-tax gain on sale of $33 million. NOTE 7. INTEREST, NET For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Interest
Expense  Long-Term Debt
    
    $
    385
    
    
    
    $
    281
    
    
    
    $
    252Early Retirement of Long-Term Debt
    
    
    (16
    )
    
    
    
    
    
    
    
    
    34Interest
Expense  Other
    
    
    42
    
    
    
    
    20
    
    
    
    
    10Interest Income
    
    
    (14
    )
    
    
    
    (18
    )
    
    
    
    (10
    )$
    397
    
    
    
    $
    283
    
    
    
    $
    286
 EnCana has entered into a series of one or more interest rate swaps, foreign exchange swaps
and option transactions on certain of its long-term notes and debentures detailed below (see also
Note 13). The net effect of these transactions reduced interest costs
in 2004 by $22 million (2003  $23 million; 2002  $20 million). Principal Amount
    
    Indenture Interest
    
    Net Swap to
    
    Effective Rate8.75% due November 9, 2005
C$200 million
    
    US$73 million
US$73 million
    
    C$ Fixed
C$ Fixed
    
    US$ Fixed*
US$ Floating*
    
    4.99%
3 month LIBOR less 4 basis points7.50% due August 25, 2006
C$100 million
    
    US$73 million
    
    C$ Fixed
    
    US$ Fixed*
    
    4.14%5.80% due June 2, 2008
C$225 million
    
    US$71 million
C$125 million
    
    C$ Fixed
C$ Fixed
    
    US$ Fixed*
C$ Floating
    
    4.80%
3 month Bankers
Acceptance less 5
basis points
 * These instruments have been subject to multiple swap transactions. NOTE 8. FOREIGN EXCHANGE GAIN For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Unrealized Foreign Exchange Gain on Translation of U.S. Dollar
Debt Issued in Canada
    
    $
    (285
    )
    
    
    $
    (545
    )
    
    
    $
    (23
    )Realized Foreign Exchange (Gains) Losses
    
    
    (132
    )
    
    
    
    (53
    )
    
    
    
    12$
    (417
    )
    
    
    $
    (598
    )
    
    
    $
    (11
    )
 22




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 9. INCOME TAXES The provision for income taxes is as follows: For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002CurrentCanada
    
    $
    594
    
    
    
    $
    (136
    )
    
    
    $
    (26
    )United States
    
    
    (12
    )
    
    
    
    39
    
    
    
    
    (31
    )Other
    
    
    (15
    )
    
    
    
    (16
    )
    
    
    
    (9
    )Total Current Tax
    
    
    567
    
    
    
    
    (113
    )
    
    
    
    (66
    )Future
    
    
    200
    
    
    
    
    836
    
    
    
    
    403Future Tax Rate Reductions
    
    
    (109
    )
    
    
    
    (359
    )
    
    
    
    (20
    )Total Future Tax
    
    
    91
    
    
    
    
    477
    
    
    
    
    383$
    658
    
    
    
    $
    364
    
    
    
    $
    317
 The following table reconciles income taxes calculated at the Canadian statutory rate with
actual income taxes: For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Net Earnings Before Income Tax
    
    $
    2,869
    
    
    
    $
    2,506
    
    
    
    $
    983Canadian Statutory Rate
    
    
    39.1
    %
    
    
    
    41.0
    %
    
    
    
    42.3
    %Expected Income Tax
    
    
    1,123
    
    
    
    
    1,026
    
    
    
    
    416Effect on Taxes Resulting from:Non-deductible Canadian crown payments
    
    
    192
    
    
    
    
    231
    
    
    
    
    147Canadian resource allowance
    
    
    (246
    )
    
    
    
    (258
    )
    
    
    
    (200
    )Canadian resource allowance on unrealized risk management losses
    
    
    (10
    )
    
    
    
    
    
    
    
    
    Statutory and other rate differences
    
    
    (55
    )
    
    
    
    (45
    )
    
    
    
    (35
    )Effect of tax rate changes
    
    
    (109
    )
    
    
    
    (359
    )
    
    
    
    (20
    )Non-taxable capital gains
    
    
    (91
    )
    
    
    
    (119
    )
    
    
    
    Previously unrecognized capital losses
    
    
    17
    
    
    
    
    (119
    )
    
    
    
    Tax basis retained on dispositions
    
    
    (179
    )
    
    
    
    
    
    
    
    
    Large corporations tax
    
    
    24
    
    
    
    
    27
    
    
    
    
    23Other
    
    
    (8
    )
    
    
    
    (20
    )
    
    
    
    (14
    )$
    658
    
    
    
    $
    364
    
    
    
    $
    317Effective Tax Rate
    
    
    22.9
    %
    
    
    
    14.5
    %
    
    
    
    32.2
    %
 The net future income tax liability is comprised of: As at December 31
    
    2004
    
    
    
    2003Future Tax LiabilitiesProperty, plant and equipment in excess of tax values
    
    $
    4,472
    
    
    
    $
    3,199Timing of Partnership items
    
    
    1,005
    
    
    
    
    1,162Future Tax AssetsNet operating losses carried forward
    
    
    (103
    )
    
    
    
    (99
    )Other
    
    
    (181
    )
    
    
    
    (106
    )Net Future Income Tax Liability
    
    $
    5,193
    
    
    
    $
    4,156
 23




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The approximate amounts of tax pools available are as follows: As at December 31
    
    2004
    
    
    
    2003Canada
    
    $
    7,183
    
    
    
    $
    6,904United States
    
    
    3,009
    
    
    
    
    2,112$
    10,192
    
    
    
    $
    9,016
 Included in the above tax pools are $275 million (2003  $256 million) related to non-capital
or net operating losses available for carry forward to reduce taxable income in future years. The current income tax provision includes amounts payable or recoverable in respect of Canadian
partnership earnings included in the Consolidated Financial Statements for partnerships that have a
year end that is after that of EnCana. NOTE 10. INVENTORIES As at December 31
    
    2004
    
    
    
    2003ProductUpstream
    
    $
    14
    
    
    
    $
    6Midstream & Market Optimization
    
    
    497
    
    
    
    
    546Parts and Supplies
    
    
    2
    
    
    
    
    5$
    513
    
    
    
    $
    557
 NOTE 11. PROPERTY, PLANT AND EQUIPMENT, NET As at December 31
    
    2004
    
    
    
    2003Accumulated
    
    
    
    
    
    
    
    
    
    
    
    AccumulatedCost
    
    
    DD&A*
    
    
    Net
    
    
    
    Cost
    
    
    DD&A*
    
    
    NetUpstreamCanada
    
    $
    24,390
    
    
    $
    (9,775
    )
    
    $
    14,615
    
    
    
    $
    20,607
    
    
    $
    (7,500
    )
    
    $
    13,107United States
    
    
    8,360
    
    
    
    (1,056
    )
    
    
    7,304
    
    
    
    
    4,062
    
    
    
    (523
    )
    
    
    3,539Other Countries
    
    
    425
    
    
    
    (247
    )
    
    
    178
    
    
    
    
    316
    
    
    
    (205
    )
    
    
    111Total Upstream
    
    
    33,175
    
    
    
    (11,078
    )
    
    
    22,097
    
    
    
    
    24,985
    
    
    
    (8,228
    )
    
    
    16,757Midstream & Market Optimization
    
    
    975
    
    
    
    (171
    )
    
    
    804
    
    
    
    
    915
    
    
    
    (131
    )
    
    
    784Corporate
    
    
    455
    
    
    
    (216
    )
    
    
    239
    
    
    
    
    320
    
    
    
    (91
    )
    
    
    229$
    34,605
    
    
    $
    (11,465
    )
    
    $
    23,140
    
    
    
    $
    26,220
    
    
    $
    (8,450
    )
    
    $
    17,770
 * Depreciation, depletion and amortization Included in Midstream is $102 million (2003  $97 million; 2002  $47 million) related to
cushion gas, required to operate the gas storage facilities, which is not subject to depletion. Included in property, plant and equipment are asset retirement costs, net of amortization, of $393
million (2003  $212 million). Administrative costs have not been capitalized as part of the
capital expenditures. 24




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Upstream costs in respect of significant unproved properties and major development projects
excluded from depletable costs at the end of the year were: As at December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Canada
    
    $
    1,444
    
    
    
    $
    1,444
    
    
    
    $
    1,035United States
    
    
    1,119
    
    
    
    
    499
    
    
    
    
    604Other Countries
    
    
    177
    
    
    
    
    112
    
    
    
    
    111$
    2,740
    
    
    
    $
    2,055
    
    
    
    $
    1,750
 The costs excluded from depletable costs in Other Countries represents costs related to
unproved properties incurred in cost centres that are considered to be in the pre-production stage.
Currently, there are no proved reserves in these cost centres. All costs, net of any associated
revenues, in these cost centres have been capitalized. Ultimate recoverability of these costs will
be dependent upon the finding of proved oil and natural gas reserves. At December 31, 2004, the
Company completed its impairment review of pre-production cost centres and determined that $23
million of costs should be charged to the Consolidated Statement of Earnings (2003  $85 million;
2002  nil). The prices used in the ceiling test evaluation of the Companys crude oil and natural gas reserves
at December 31, 2004 were: % increase to2005
    
    
    
    2006
    
    
    
    2007
    
    
    
    2008
    
    
    
    2009
    
    
    
    2016Natural Gas ($/Mcf)Canada
    
    $
    6.00
    
    
    
    $
    5.34
    
    
    
    $
    4.52
    
    
    
    $
    4.45
    
    
    
    $
    4.58
    
    
    
    
    12
    %United States
    
    
    6.24
    
    
    
    
    5.61
    
    
    
    
    4.35
    
    
    
    
    4.77
    
    
    
    
    4.77
    
    
    
    
    13
    %Crude Oil ($/barrel)Canada
    
    $
    28.66
    
    
    
    $
    24.38
    
    
    
    $
    17.03
    
    
    
    $
    17.20
    
    
    
    $
    16.88
    
    
    
    
    7
    %United States
    
    
    43.51
    
    
    
    
    38.84
    
    
    
    
    26.95
    
    
    
    
    26.49
    
    
    
    
    26.45
    
    
    
    
    18
    %Natural Gas Liquids ($/barrel)Canada
    
    $
    38.61
    
    
    
    $
    33.99
    
    
    
    $
    25.65
    
    
    
    $
    25.41
    
    
    
    $
    25.25
    
    
    
    
    17
    %United States
    
    
    38.18
    
    
    
    
    34.54
    
    
    
    
    26.93
    
    
    
    
    27.14
    
    
    
    
    27.22
    
    
    
    
    14
    %
 NOTE 12. INVESTMENTS AND OTHER ASSETS As at December 31
    
    2004
    
    
    
    2003Equity Investments
    
    $
    8
    
    
    
    $
    57Marketing Contracts
    
    
    12
    
    
    
    
    22Deferred Financing Costs
    
    
    61
    
    
    
    
    35Deferred Pension Plan and Savings Plan
    
    
    64
    
    
    
    
    53Prepaid Capital and Other
    
    
    189
    
    
    
    
    101$
    334
    
    
    
    $
    268
 Equity Investments Included in Equity Investments is a 36 percent indirect equity investment in Oleoducto Trasandino
which owns a crude oil pipeline that ships crude oil from the producing areas of Argentina to
refineries in Chile. In the second quarter of 2004, a $35 million impairment charge was made to
depreciation, depletion and amortization on the Companys interest in Oleoducto Trasandino. 25




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 13. LONG-TERM DEBT As at December 31
    
    Note
    
    
    2004
    
    
    
    2003Canadian Dollar Denominated DebtRevolving credit and term loan borrowings
    
    
    B
    
    
    $
    1,515
    
    
    
    $
    1,425Unsecured notes and debentures
    
    
    C
    
    
    
    1,309
    
    
    
    
    1,335Preferred securities
    
    
    D
    
    
    
    
    
    
    
    
    2522,824
    
    
    
    
    3,012U.S. Dollar Denominated DebtRevolving credit and term loan borrowings
    
    
    E
    
    
    
    399
    
    
    
    
    417Unsecured notes and debentures
    
    
    F
    
    
    
    4,641
    
    
    
    
    2,713Preferred securities
    
    
    D
    
    
    
    
    
    
    
    
    1505,040
    
    
    
    
    3,280Increase in Value of Debt Acquired
    
    
    G
    
    
    
    66
    
    
    
    
    83Current Portion of Long-Term Debt
    
    
    H
    
    
    
    (188
    )
    
    
    
    (287
    )$
    7,742
    
    
    
    $
    6,088
 A) Overview Revolving credit and term loan borrowings At December 31, 2004, EnCana had in place a revolving credit facility for $4.5 billion Canadian
dollars or its equivalent amount in U.S. dollars ($3.7 billion). The facility consists of two
tranches of C$1.7 billion ($1.4 billion) and C$2.8 billion ($2.3 billion) respectively. The
first tranche is fully revolving for a period of three years from the date of the agreement,
October 2004. This tranche is extendible annually for an additional one year period at the
option of the lenders and upon notice from EnCana. The second tranche is fully revolving for a
period of five years from the date of the agreement, October 2004. This tranche is extendible
annually for an additional one year period at the option of the lenders and upon notice from the
Company. The facility is unsecured and bears interest at either the lenders rates for Canadian
prime commercial loans, U.S. base rate loans, Bankers Acceptances rates, or at LIBOR plus
applicable margins. To fund the acquisition of Tom Brown, Inc., EnCana arranged a $3 billion non-revolving term loan
facility. Initially, $1.8 billion was drawn on this facility. At December 31, 2004, this
facility has been completely repaid and cancelled. At December 31, 2004, one of EnCanas subsidiaries had in place a credit facility totaling $600
million (C$722 million). The facility is guaranteed by EnCana Corporation and fully revolving
for five years from the date of the Agreement, December, 2004. The facility is extendable
annually for an additional one year period at the option of the lenders and upon notice from the
subsidiary. This facility bears interest at either the lenders U.S. base rate or at LIBOR plus
applicable margins. Revolving credit and term loan borrowings include Bankers Acceptances and Commercial Paper of
$1,559 million (2003  $1,749 million) maturing at various dates with a weighted average
interest rate of 2.83% (2003  2.55%) and LIBOR loans of $355 million (2003  $65 million) with
a weighted average interest rate of 2.98% (2003  1.69%). These amounts are fully supported and
Management expects that they will continue to be supported by revolving credit and term loan
facilities that have no repayment requirements within the next year. Standby fees paid in 2004 relating to revolving credit and term loan agreements were
approximately $5 million (2003  $3 million; 2002  $3 million). 26




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Unsecured notes and debentures Unsecured notes and debentures include medium term notes and senior notes that are issued from
time to time under trust indentures. The Companys current medium term note program was renewed
in 2003 with C$1 billion ($831 million) unutilized at December 31, 2004. The notes may be
denominated in Canadian dollars or in foreign currencies. EnCana has in place a shelf prospectus for U.S. Unsecured Notes in the amount of $2 billion
under the Multijurisdictional Disclosure System. The shelf prospectus provides that debt
securities in U.S. dollars or other foreign currencies may be issued from time to time in one or
more series. Terms of the notes, including interest at either fixed or floating rates and expiry
dates are determined by reference to market conditions at the date of issue. At December 31,
2004, $2 billion of the shelf prospectus remains unutilized. EnCana has an indirect wholly owned subsidiary, EnCana Holdings Finance Corp., which has in
place a shelf prospectus in the amount of $2 billion under the Multijurisdictional Disclosure
System. The shelf prospectus provides that debt securities in U.S. dollars or other foreign
currencies may be issued from time to time in one or more series. Terms of the notes, including
interest at either fixed or floating rates and expiry dates are determined by reference to
market conditions at the date of issue. The debt securities issued under this shelf prospectus
are fully and unconditionally guaranteed by EnCana Corporation. EnCana has also obtained certain
exemption orders from Canadian securities regulatory authorities that allow the filing of
certain financial and other information of EnCana to satisfy certain continuous disclosure
obligations of EnCana Holdings Finance Corp. At December 31, 2004, $1 billion of the shelf
prospectus remains unutilized. B) Canadian revolving credit and term loan borrowings C$ PrincipalAmount
    
    
    2004
    
    
    
    2003Bankers Acceptances
    
    $
    615
    
    
    $
    511
    
    
    
    $
    598Commercial Paper
    
    
    1,209
    
    
    
    1,004
    
    
    
    
    799Cogeneration
Facility, matures March 31, 2016 *
    
    
    
    
    
    
    
    
    
    
    
    28$
    1,824
    
    
    $
    1,515
    
    
    
    $
    1,425
 *On December 15, 2004, EnCana sold its limited partnership interest in Kingston. See Note 6. C) Canadian unsecured notes and debentures C$ PrincipalAmount
    
    
    2004
    
    
    
    20036.60% due June 30, 2004
    
    $
    
    
    
    $
    
    
    
    
    $
    397.00% due December 1, 2004
    
    
    
    
    
    
    
    
    
    
    
    775.95% due October 1, 2007
    
    
    200
    
    
    
    166
    
    
    
    
    1555.30% due December 3, 2007
    
    
    300
    
    
    
    248
    
    
    
    
    2325.95% due June 2, 2008
    
    
    100
    
    
    
    83
    
    
    
    
    775.80% due June 2, 2008
    
    
    125
    
    
    
    104
    
    
    
    
    975.80% due June 19, 2008
    
    
    100
    
    
    
    83
    
    
    
    
    776.10% due June 1, 2009
    
    
    150
    
    
    
    125
    
    
    
    
    1167.15% due December 17, 2009
    
    
    150
    
    
    
    125
    
    
    
    
    1168.50% due March 15, 2011
    
    
    50
    
    
    
    42
    
    
    
    
    397.10% due October 11, 2011
    
    
    200
    
    
    
    166
    
    
    
    
    1557.30% due September 2, 2014
    
    
    150
    
    
    
    125
    
    
    
    
    1165.50% / 6.20% due June 23, 2028
    
    
    50
    
    
    
    42
    
    
    
    
    39$
    1,575
    
    
    $
    1,309
    
    
    
    $
    1,335
 27




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED D) Preferred securities C$ PrincipalAmount
    
    
    2004
    
    
    
    2003Canadian Dollar7.00% due March 23, 2034
    
    $
    
    
    
    $
    
    
    
    
    $
    978.50% due September 30, 2048
    
    
    
    
    
    
    
    
    
    
    
    155$
    
    
    
    
    
    
    
    
    
    252U.S. Dollar9.50% due September 30, 2048
    
    
    
    
    
    
    
    
    
    
    
    150$
    
    
    
    
    $
    402
 All of the preferred securities were redeemed during 2004 at par plus accrued and unpaid
interest. E) U.S. revolving credit and term loan borrowings 2004
    
    
    
    2003Commercial Paper
    
    $
    44
    
    
    
    $
    352LIBOR Loan
    
    
    355
    
    
    
    
    65$
    399
    
    
    
    $
    417
 F) U.S. unsecured notes and debentures C$ Amount
    
    
    2004
    
    
    
    2003Floating Rate8.40% due December 15, 2004
    
    $
    
    
    
    $
    
    
    
    
    $
    738.75% due November 9, 2005
    
    
    88
    *
    
    
    73
    
    
    
    
    73Fixed Rate8.75% due November 9, 2005
    
    
    88
    *
    
    
    73
    
    
    
    
    737.50% due August 25, 2006
    
    
    88
    *
    
    
    73
    
    
    
    
    735.80% due June 2, 2008
    
    
    85
    *
    
    
    71
    
    
    
    
    714.60% due August 15, 2009
    
    
    
    
    
    
    250
    
    
    
    
    7.65% due September 15, 2010
    
    
    
    
    
    
    200
    
    
    
    
    2006.30% due November 1, 2011
    
    
    
    
    
    
    500
    
    
    
    
    5007.25% due September 15, 2013
    
    
    
    
    
    
    1
    
    
    
    
    4.75% due October 15, 2013
    
    
    
    
    
    
    500
    
    
    
    
    5005.80% due May 1, 2014
    
    
    
    
    
    
    1,000
    
    
    
    
    8.125% due September 15, 2030
    
    
    
    
    
    
    300
    
    
    
    
    3007.20% due November 1, 2031
    
    
    
    
    
    
    350
    
    
    
    
    3507.375% due November 1, 2031
    
    
    
    
    
    
    500
    
    
    
    
    5006.50% due August 15, 2034
    
    
    
    
    
    
    750
    
    
    
    
    $
    4,641
    
    
    
    $
    2,713
 * The Company has entered into a series of cross-currency and interest rate swap transactions
that effectively convert these Canadian dollar denominated notes to U.S. dollars. The effective
U.S. dollar principal is shown in the table. The 5.80% Notes due May 1, 2014 were issued by the Companys indirect wholly owned
subsidiary, EnCana Holdings Finance Corp. These notes are fully and unconditionally guaranteed
by EnCana Corporation. 28




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED G) Increase in value of debt acquired Certain of the notes and debentures of the Company were acquired in business combinations and
were accounted for at their fair value at the date of acquisition. The difference between the
fair value and the principal amount of the debt is being amortized over the remaining life of
the outstanding debt acquired, approximately 22 years. H) Current portion of long-term debt 2004
    
    
    
    20037.00% Coupon Reset Subordinated Term Securities due March 23, 2034
    
    $
    
    
    
    
    $
    976.60% Medium Term Note due June 30, 2004
    
    
    
    
    
    
    
    397.00% Medium Term Note due December 1, 2004
    
    
    
    
    
    
    
    778.40% Medium Term Note due December 15, 2004
    
    
    
    
    
    
    
    735.50% / 6.20% Medium Term Note due June 23, 2028
    
    
    42
    
    
    
    
    8.75% Unsecured Note due November 9, 2005
    
    
    146
    
    
    
    
    Cogeneration facility
    
    
    
    
    
    
    
    1$
    188
    
    
    
    $
    287
 The 5.50% / 6.20% Medium Term Note due June 23, 2028 has a put option attached to it
whereby holders of the note may require EnCana to repay the outstanding note on June 23, 2005,
if the notice is given prior to June 9, 2005 that the option will be exercised. Should notice
not be received, the note is then payable on June 23, 2028. I) Mandatory debt payments C$ Principal
    
    
    
    US$ Principal
    
    
    
    Total US$Amount
    
    
    
    Amount
    
    
    
    Equivalent2005
    
    $
    50
    
    
    
    $
    146
    
    
    
    $
    1882006
    
    
    
    
    
    
    
    73
    
    
    
    
    732007
    
    
    500
    
    
    
    
    
    
    
    
    
    4142008
    
    
    325
    
    
    
    
    71
    
    
    
    
    3412009
    
    
    300
    
    
    
    
    250
    
    
    
    
    500Thereafter
    
    
    2,224
    
    
    
    
    4,500
    
    
    
    
    6,348Total
    
    $
    3,399
    
    
    
    $
    5,040
    
    
    
    $
    7,864
 The amount due in 2005 excludes Bankers Acceptances and Commercial Paper, which are fully
supported by revolving credit and term loan facilities that have no repayment requirements
within the next year. 29




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 14. ASSET RETIREMENT OBLIGATION The following table presents the reconciliation of the beginning and ending aggregate carrying
amount of the obligation associated with the retirement of oil and gas properties. As at December 31
    
    2004
    
    
    
    2003Asset Retirement Obligation, Beginning of Year
    
    $
    383
    
    
    
    $
    288Liabilities Incurred
    
    
    98
    
    
    
    
    45Liabilities Settled
    
    
    (16
    )
    
    
    
    (23
    )Liabilities Disposed
    
    
    (35
    )
    
    
    
    Change in Estimated Future Cash Flows
    
    
    124
    
    
    
    
    Accretion Expense
    
    
    22
    
    
    
    
    17Other
    
    
    35
    
    
    
    
    56Asset Retirement Obligation, End of Year
    
    $
    611
    
    
    
    $
    383
 The total undiscounted amount of estimated cash flows required to settle the obligation is
$3,695 million (2003  $3,118 million), which has been discounted using a credit-adjusted risk
free rate of 6.0 percent (2003  5.9 percent). Most of these obligations are not expected to be
paid for several years, or decades, in the future and will be funded from general company
resources at that time. NOTE 15. SHARE CAPITAL Authorized The Company is authorized to issue an unlimited number of Common Shares, an unlimited number of
First Preferred Shares and an unlimited number of Second Preferred Shares. Issued and Outstanding As at December 31
    
    2004
    
    
    
    2003Number
    
    
    
    
    
    
    
    Number(millions)
    
    
    Amount
    
    
    
    (millions)
    
    
    AmountCommon Shares Outstanding, Beginning of Year
    
    
    460.6
    
    
    $
    5,305
    
    
    
    
    478.9
    
    
    $
    5,511Shares Issued under Option Plans
    
    
    9.7
    
    
    
    281
    
    
    
    
    5.5
    
    
    
    114Shares Repurchased
    
    
    (20.0
    )
    
    
    (287
    )
    
    
    
    (23.8
    )
    
    
    (320
    )Common Shares Outstanding, End of Year
    
    
    450.3
    
    
    $
    5,299
    
    
    
    
    460.6
    
    
    $
    5,305
 Normal Course Issuer Bid On October 26, 2004, the Company received regulatory approval for a new Normal Course Issuer Bid
commencing October 29, 2004. Under this bid, the Company may purchase for cancellation up to
23,114,500 of its Common Shares, representing five percent of the approximately 462.29 million
Common Shares outstanding as of the filing of the bid on October 22, 2004. On February 4, 2005,
the Company received regulatory approval for an amendment to the Normal Course Issuer Bid which
increases the number of shares available for purchase from five percent of the issued and
outstanding Common Shares to ten percent of the public float of Common Shares (a total of
approximately 46.1 million Common Shares). The current Normal Course Issuer Bid expires on
October 28, 2005. On October 20, 2003, the Company received regulatory approval for a new Normal Course Issuer Bid
commencing October 22, 2003. Under this bid, the Company could purchase for cancellation up to
23,212,341 of its Common Shares, representing five percent of the 464,246,813 Common Shares
outstanding as of October 14, 2003. 30




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED In 2004, the Company purchased, for cancellation, 19,983,600 Common Shares for total
consideration of $1,004 million. Of the $1,004 million paid, $287 million was charged to Share
capital, $46 million was charged to Paid in surplus and $671 million was charged to Retained
earnings. Stock Options EnCana has stock-based compensation plans that allow employees to purchase Common Shares of the
Company. Option exercise prices approximate the market price for the Common Shares on the date
the options were issued. Options granted under the plans are generally fully exercisable after
three years and expire five years after the grant date. Options granted under predecessor and/or
related company replacement plans expire up to 10 years from the date the options were granted. In conjunction with the business combination transaction with AEC described in Note 3, options
to purchase AEC common shares were replaced with options to purchase Common Shares of EnCana
(AEC replacement plan) in a manner consistent with the provisions of the AEC stock option
plan. Options granted under the AEC plan prior to April 21, 1999 expire after seven years and
options granted after April 20, 1999 expire after five years. The business combination resulted
in these replacement options, along with all options then outstanding under the EnCana plan,
becoming exercisable after the close of business on April 5, 2002. EnCana Plan Pursuant to the terms of a stock option plan, options may be granted to certain key employees to
purchase Common Shares of the Company. Options granted prior to February 27, 1997, are
exercisable at half the number of options granted after two years and are fully exercisable
after three years. The options expire 10 years after the date granted. Options granted on or
after February 27, 1997, and prior to November 4, 1999, are exercisable after three years and
expire five years after the date granted. Options granted on or after November 4, 1999, are
exercisable at 30 percent of the number granted after one year, an additional 30 percent of the
number granted after two years, are fully exercisable after three years and expire five years
after the date granted. For stock options granted after February 27, 1997, and prior to November
4, 1999, the employees can surrender their options in exchange for, at the election of the
Company, cash or a payment in common stock for the difference between the market price and
exercise price. All options issued in 2004 have an associated Tandem Share Appreciation Right
(TSAR) attached to them (see Note 16). Canadian Pacific Limited Replacement Plan As part of the 2001 reorganization of Canadian Pacific Limited (CPL), EnCanas former parent
company, CPL stock options were replaced with stock options granted by the Company in a manner
that was consistent with the provisions of the CPL stock option plan. Under CPLs stock option
plan, options were granted to certain key employees to purchase common shares of CPL at a price
not less than the market value of the shares at the grant date. The options expire 10 years
after the grant date and are all exercisable. Directors Plan Effective April 5, 2002, the Company amended the director stock option plan. Under the terms of
the plan, new non-employee directors were given an initial grant of 15,000 options to purchase
common shares of the Company. Thereafter, there was an annual grant of 7,500 options to each
non-employee director. Options, which expire five years after the grant date, are 100 percent
exercisable on the earlier of the next annual general meeting following the grant date and the
first anniversary of the grant date. On October 23, 2003, issuances of stock options under this
plan were discontinued. 31




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The following tables summarize the information about options to purchase Common Shares that have
no TSAR attached to them: As at December 31
    2004
    
    
    
    2003
    
    
    
    2002Stock Options
    
    
    Weighted Average
    
    
    
    Stock Options
    
    
    Weighted Average
    
    
    
    Stock Options
    
    
    Weighted Average(millions)
    
    
    Exercise Price(C$)
    
    
    
    (millions)
    
    
    Exercise Price (C$)
    
    
    
    (millions)
    
    
    Exercise Price (C$)Outstanding, Beginning of Year
    
    
    28.8
    
    
    
    43.13
    
    
    
    
    29.6
    
    
    
    39.74
    
    
    
    
    10.5
    
    
    
    32.31Granted under EnCana Plan
    
    
    
    
    
    
    
    
    
    
    
    6.3
    
    
    
    47.98
    
    
    
    
    12.1
    
    
    
    48.13Granted under AEC Replacement
Plan
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    13.1
    
    
    
    32.01Granted under Directors Plan
    
    
    
    
    
    
    
    
    
    
    
    0.1
    
    
    
    47.87
    
    
    
    
    0.1
    
    
    
    48.04Exercised
    
    
    (9.7
    )
    
    
    36.63
    
    
    
    
    (5.5
    )
    
    
    29.11
    
    
    
    
    (5.5
    )
    
    
    25.20Forfeited
    
    
    (1.0
    )
    
    
    47.50
    
    
    
    
    (1.7
    )
    
    
    41.18
    
    
    
    
    (0.7
    )
    
    
    43.81Outstanding, End of Year
    
    
    18.1
    
    
    
    46.29
    
    
    
    
    28.8
    
    
    
    43.13
    
    
    
    
    29.6
    
    
    
    39.74Exercisable, End of Year
    
    
    10.8
    
    
    
    45.09
    
    
    
    
    15.6
    
    
    
    38.92
    
    
    
    
    17.7
    
    
    
    34.10
 As at December 31
    Outstanding Options
    
    
    
    Exercisable OptionsWeightedNumber of
    
    
    Average
    
    
    Weighted
    
    
    
    Number of
    
    
    WeightedOptions
    
    
    Remaining
    
    
    Average
    
    
    
    Options
    
    
    AverageOutstanding
    
    
    Contractual
    
    
    Exercise
    
    
    
    Outstanding
    
    
    ExerciseRange of Exercise Price (C$)
    
    (millions)
    
    
    Life (years)
    
    
    Price (C$)
    
    
    
    (millions)
    
    
    Price (C$)13.50 to 19.99
    
    
    0.1
    
    
    
    0.2
    
    
    
    18.49
    
    
    
    
    0.1
    
    
    
    18.4920.00 to 24.99
    
    
    0.6
    
    
    
    3.5
    
    
    
    22.69
    
    
    
    
    0.6
    
    
    
    22.6925.00 to 29.99
    
    
    0.4
    
    
    
    1.3
    
    
    
    26.18
    
    
    
    
    0.4
    
    
    
    26.1830.00 to 43.99
    
    
    0.5
    
    
    
    1.7
    
    
    
    40.18
    
    
    
    
    0.4
    
    
    
    39.9344.00 to 53.00
    
    
    16.5
    
    
    
    2.4
    
    
    
    47.97
    
    
    
    
    9.3
    
    
    
    47.8718.1
    
    
    
    2.4
    
    
    
    46.29
    
    
    
    
    10.8
    
    
    
    45.09
 At December 31, 2004, there were 8.0 million common shares reserved for issuance under
stock option plans (2003  7.8 million; 2002  12.4 million). EnCana has recorded stock-based compensation expense in the Consolidated Statement of Earnings
for stock options granted to employees and directors in 2003 using the fair value method.
Compensation expense has not been recorded in the Consolidated Statement of Earnings related to
stock options granted prior to 2003. If the Company had applied the fair value method to options
granted prior to 2003, pro forma Net Earnings and Net Earnings per Common Share in 2004 would
have been $3,476 million; $7.55 per common share  basic;
$7.43 per common share  diluted (2003
  $2,326 million; $4.91 per common share  basic;
$4.85 per common share  diluted). The fair value of each option granted is estimated on the date of grant using the Black-Scholes
option-pricing model with weighted average assumptions for grants as follows: For the years ended December 31
    
    2003
    
    
    
    2002Weighted Average Fair Value of Options Granted (C$)
    
    $
    12.21
    
    
    
    $
    13.31Risk-Free Interest Rate
    
    
    3.87
    %
    
    
    
    4.29
    %Expected Lives (years)
    
    
    3.00
    
    
    
    
    3.00Expected Volatility
    
    
    0.33
    
    
    
    
    0.35Annual Dividend per Share (C$/common share)
    
    $
    0.40
    
    
    
    $
    0.40
 32




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 16. COMPENSATION PLANS A) Pensions The most recent actuarial evaluation completed for the Company is dated December 31, 2004. The Company sponsors both defined benefit and defined contribution plans providing pension and
other retirement and post-employment benefits (OPEB) to substantially all of its employees. For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Total Expense for Defined Contribution Plans
    
    $
    19
    
    
    
    $
    12
    
    
    
    $
    9
 Information about defined benefit post-retirement benefit plans, in aggregate, is as
follows: As at December 31
    Pension Benefits
    
    
    
    OPEB2004
    
    
    2003
    
    
    
    2004
    
    
    2003Accrued Benefit Obligation, Beginning of Year
    
    $
    214
    
    
    $
    159
    
    
    
    $
    14
    
    
    $
    8Beginning of year adjustment
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    
    Current service cost
    
    
    5
    
    
    
    5
    
    
    
    
    1
    
    
    
    1Interest cost
    
    
    13
    
    
    
    11
    
    
    
    
    1
    
    
    
    1Benefits paid
    
    
    (10
    )
    
    
    (11
    )
    
    
    
    
    
    
    
    Actuarial loss
    
    
    8
    
    
    
    12
    
    
    
    
    1
    
    
    
    1Contributions
    
    
    1
    
    
    
    1
    
    
    
    
    
    
    
    
    Plan amendments
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1Foreign exchange
    
    
    16
    
    
    
    37
    
    
    
    
    2
    
    
    
    2Accrued Benefit Obligation, End of Year
    
    $
    246
    
    
    $
    214
    
    
    
    $
    19
    
    
    $
    14
 As at December 31
    Pension Benefits
    
    
    
    OPEB2004
    
    
    2003
    
    
    
    2004
    
    
    2003Fair Value of Plan Assets, Beginning of Year
    
    $
    203
    
    
    $
    117
    
    
    
    $
    
    
    
    $
    Beginning of year adjustment
    
    
    
    
    
    
    (1
    )
    
    
    
    
    
    
    
    Actual return on plan assets
    
    
    19
    
    
    
    16
    
    
    
    
    
    
    
    
    Employer contributions
    
    
    17
    
    
    
    51
    
    
    
    
    
    
    
    
    Employees contributions
    
    
    1
    
    
    
    1
    
    
    
    
    
    
    
    
    Benefits paid
    
    
    (10
    )
    
    
    (10
    )
    
    
    
    
    
    
    
    Foreign exchange
    
    
    17
    
    
    
    29
    
    
    
    
    
    
    
    
    Fair Value of Plan Assets, End of Year
    
    $
    247
    
    
    $
    203
    
    
    
    $
    
    
    
    $
    
 As at December 31
    Pension Benefits
    
    
    
    OPEB2004
    
    
    2003
    
    
    
    2004
    
    
    2003Funded Status  Plan Assets less than Benefit Obligation
    
    $
    1
    
    
    $
    (11
    )
    
    
    $
    (19
    )
    
    $
    (14
    )Amounts Not Recognized:Unamortized net actuarial loss
    
    
    54
    
    
    
    64
    
    
    
    
    4
    
    
    
    2Unamortized past service cost
    
    
    10
    
    
    
    12
    
    
    
    
    2
    
    
    
    1Net transitional asset
    
    
    (11
    )
    
    
    (12
    )
    
    
    
    2
    
    
    
    3Accrued Benefit Asset
    
    $
    54
    
    
    $
    53
    
    
    
    $
    (11
    )
    
    $
    (8
    )
 33




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED As at December 31
    
    Pension Benefits
    
    
    
    OPEB2004
    
    
    2003
    
    
    
    2004
    
    
    2003Prepaid Benefit Cost
    
    $
    54
    
    
    $
    53
    
    
    
    $
    
    
    
    $
    Accrued Benefit Cost
    
    
    
    
    
    
    
    
    
    
    
    (11
    )
    
    
    (8
    )Net Amount Recognized
    
    $
    54
    
    
    $
    53
    
    
    
    $
    (11
    )
    
    $
    (8
    )
 The Companys other post employment benefit plans are funded on an as required basis. The weighted average assumptions used to determine benefit obligations are as follows: As at December 31
    
    Pension Benefits
    
    
    
    OPEB2004
    
    
    2003
    
    
    
    2004
    
    
    2003Discount Rate
    
    
    5.75
    %
    
    
    6.00
    %
    
    
    
    5.75
    %
    
    
    6.00
    %Rate of Compensation Increase
    
    
    4.60
    %
    
    
    4.75
    %
    
    
    
    5.65
    %
    
    
    5.75
    %
 The weighted average assumptions used to determine periodic expense are as follows: For the years ended December 31
    
    Pension Benefits
    
    
    
    OPEB2004
    
    
    2003
    
    
    
    2004
    
    
    2003Discount Rate
    
    
    6.00
    %
    
    
    6.50
    %
    
    
    
    6.00
    %
    
    
    6.50
    %Expected Long-Term Rate of Return on Plan AssetsRegistered pension plans
    
    
    6.75
    %
    
    
    6.75
    %
    
    
    
    n/a
    
    
    
    n/aSupplemental pension plans
    
    
    3.375
    %
    
    
    3.375
    %
    
    
    
    n/a
    
    
    
    n/aRate of Compensation Increase
    
    
    4.75
    %
    
    
    4.75
    %
    
    
    
    5.75
    %
    
    
    5.75
    %
 The periodic expense for benefits is as follows: For the years ended December 31
    
    Pension Benefits
    
    
    
    OPEB2004
    
    
    2003
    
    
    2002
    
    
    
    2004
    
    
    2003
    
    
    2002Current Service Cost
    
    $
    5
    
    
    $
    5
    
    
    $
    2
    
    
    
    $
    1
    
    
    $
    1
    
    
    $
    1Interest Cost
    
    
    13
    
    
    
    11
    
    
    
    8
    
    
    
    
    1
    
    
    
    1
    
    
    
    Actual Return on Plan Assets
    
    
    (19
    )
    
    
    (16
    )
    
    
    9
    
    
    
    
    
    
    
    
    
    
    
    
    Actuarial Loss on Accrued Benefit
Obligation
    
    
    8
    
    
    
    12
    
    
    
    9
    
    
    
    
    1
    
    
    
    1
    
    
    
    Plan Amendment
    
    
    
    
    
    
    
    
    
    
    9
    
    
    
    
    
    
    
    
    2
    
    
    
    Difference Between Actual and:Expected return on plan assets
    
    
    7
    
    
    
    7
    
    
    
    (17
    )
    
    
    
    
    
    
    
    
    
    
    
    Recognized actuarial loss
    
    
    (4
    )
    
    
    (8
    )
    
    
    (8
    )
    
    
    
    (1
    )
    
    
    (1
    )
    
    
    Difference Between Amortization of
Past Service Costs and Actual Plan
Amendments
    
    
    2
    
    
    
    1
    
    
    
    (8
    )
    
    
    
    
    
    
    
    (2
    )Amortization of Transitional Obligation
    
    
    (2
    )
    
    
    (2
    )
    
    
    (2
    )
    
    
    
    
    
    
    
    
    
    
    
    Curtailment Loss
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    
    Special Termination Benefits
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    Expense for Defined Contribution Plan
    
    
    19
    
    
    
    12
    
    
    
    9
    
    
    
    
    
    
    
    
    
    
    
    
    Net Benefit Plan Expense
    
    $
    29
    
    
    $
    22
    
    
    $
    14
    
    
    
    $
    2
    
    
    $
    2
    
    
    $
    1
 The average remaining service period of the active employees covered by the defined benefit
pension plan is eight years. The average remaining service period of the active employees
covered by the other retirement benefits plan is 12 years. After the business combination transaction as described in Note 3, a number of employees were
involuntarily terminated. Terminated members of the defined benefit pension plan, who were age
50 or above, could elect enhanced benefits under the registered pension plan. For pension
accounting 34




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED purposes, this resulted in special termination benefits being provided and a curtailment event
that impacted some of the pension arrangements sponsored by the Company. Assumed health care cost trend rates are as follows: As at December 31
    
    2004
    
    
    
    2003Health Care Cost Trend Rate for Next Year
    
    
    10.00
    %
    
    
    
    10.00
    %Rate that the Trend Rate Gradually Trends To
    
    
    5.00
    %
    
    
    
    5.00
    %Year that the Trend Rate Reaches the Rate which it is Expected to Remain At
    
    
    2015
    
    
    
    
    2014
 Assumed health care cost trend rates have an effect on the amounts reported for the other
benefit plans. A one percentage point change in assumed health care cost trend rates would have
the following effects: One Percentage
    
    
    
    One PercentagePoint Increase
    
    
    
    Point DecreaseEffect on Total of Service and Interest Cost
    
    $
    
    
    
    
    $
    Effect on Post Retirement Benefit Obligation
    
    $
    2
    
    
    
    $
    (1
    )
 The Companys pension plan asset allocations are as follows: % of Plan Assets at
    
    
    
    Expected Long-TermAsset Category
    
    Target Allocation %
    
    
    
    December 31
    
    
    
    Rate of ReturnNormal
    
    
    Range
    
    
    
    2004
    
    
    2003Domestic Equity
    
    
    35
    
    
    
    25-45
    
    
    
    
    38
    
    
    
    35Foreign Equity
    
    
    30
    
    
    
    20-40
    
    
    
    
    28
    
    
    
    29Bonds
    
    
    30
    
    
    
    20-40
    
    
    
    
    27
    
    
    
    27Real Estate and Other
    
    
    5
    
    
    
    0-20
    
    
    
    
    7
    
    
    
    9Total
    
    
    100
    
    
    
    
    
    
    
    
    100
    
    
    
    100
    
    
    
    
    6.75
    %
 The expected rate of return on plan assets is based on historical and projected rates of
return for each asset class in the plan investment portfolio. The objective of the asset
allocation policy is to manage the funded status of the plan at an appropriate level of risk,
giving consideration to the security of the assets and the potential volatility of market
returns and the resulting effect on both contribution requirements and pension expense. The
long-term return is expected to achieve or exceed the return from a composite benchmark
comprised of passive investments in appropriate market indices. The Supplemental Pension Plan
(approximately $40 million) is funded through a retirement compensation arrangement and is
subject to the applicable Canada Revenue Agency regulations. The asset allocation structure is subject to diversification requirements and constraints which
reduce risk by limiting exposure to individual equity investments, credit rating categories and
foreign currency exposure. The Company expects to contribute $6 million to the plans in 2005. Contributions by the
participants to the pension and other benefits plans were $1 million for the year ended December
31, 2004 (2003  $1 million; 2002  nil). 35




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Estimated future payments for pension and other benefits are as follows: Pension Benefits
    
    
    
    OPEB2005
    
    $
    12
    
    
    
    $
    2006
    
    
    13
    
    
    
    
    12007
    
    
    13
    
    
    
    
    12008
    
    
    14
    
    
    
    
    12009
    
    
    15
    
    
    
    
    12010  2014
    
    
    88
    
    
    
    
    7Total
    
    $
    155
    
    
    
    $
    11
 B) Share Appreciation Rights EnCana has in place a program whereby certain employees are granted Share Appreciation Rights
(SARs) which entitle the employee to receive a cash payment equal to the excess of the market
price of the Companys Common Shares at the time of exercise over the exercise price of the
right. SARs granted expire after five years. The following tables summarize the information about the SARs: As at December 31
    2004
    
    
    
    2003Weighted
    
    
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    
    
    AverageOutstanding
    
    
    Exercise
    
    
    
    Outstanding
    
    
    ExerciseSARs
    
    
    Price
    
    
    
    SARs
    
    
    PriceCanadian Dollar Denominated(C$)Outstanding, Beginning of Year
    
    
    1,175,070
    
    
    
    35.87
    
    
    
    
    2,284,901
    
    
    
    35.56Exercised
    
    
    (698,775
    )
    
    
    35.48
    
    
    
    
    (1,101,987
    )
    
    
    35.17Forfeited
    
    
    (11,040
    )
    
    
    29.25
    
    
    
    
    (7,844
    )
    
    
    46.28Outstanding, End of Year
    
    
    465,255
    
    
    
    36.61
    
    
    
    
    1,175,070
    
    
    
    35.87Exercisable, End of Year
    
    
    465,255
    
    
    
    36.61
    
    
    
    
    1,175,070
    
    
    
    35.87U.S. Dollar Denominated(US$)Outstanding, Beginning of Year
    
    
    753,417
    
    
    
    28.98
    
    
    
    
    1,346,437
    
    
    
    28.52Exercised
    
    
    (365,647
    )
    
    
    29.19
    
    
    
    
    (589,340
    )
    
    
    27.91Forfeited
    
    
    (1,840
    )
    
    
    25.29
    
    
    
    
    (3,680
    )
    
    
    30.73Outstanding, End of Year
    
    
    385,930
    
    
    
    28.80
    
    
    
    
    753,417
    
    
    
    28.98Exercisable, End of Year
    
    
    385,930
    
    
    
    28.80
    
    
    
    
    753,417
    
    
    
    28.98
 36




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED As at December 31
    SARs OutstandingWeightedAverage
    
    
    WeightedRemaining
    
    
    AverageNumber of
    
    
    Contractual
    
    
    ExerciseRange of Exercise Price
    
    SARs
    
    
    Life(years)
    
    
    PriceCanadian Dollar Denominated(C$)20.00 to 29.99
    
    
    225,327
    
    
    
    0.153
    
    
    
    26.2430.00 to 39.99
    
    
    
    
    
    
    
    
    
    
    40.00 to 49.99
    
    
    238,416
    
    
    
    1.190
    
    
    
    46.3150.00 to 60.00
    
    
    1,512
    
    
    
    1.332
    
    
    
    51.94465,255
    
    
    
    0.689
    
    
    
    36.61U.S. Dollar Denominated(US$)20.00 to 29.99
    
    
    166,640
    
    
    
    1.379
    
    
    
    26.6930.00 to 40.00
    
    
    219,290
    
    
    
    1.158
    
    
    
    30.39385,930
    
    
    
    1.254
    
    
    
    28.80
 During the year, the Company recorded compensation costs of $17 million related to the
outstanding SARs (2003  $12 million; 2002  $4 million). C) Tandem Share Appreciation Rights In 2004, all options to purchase common shares issued have an associated Tandem Share
Appreciation Right (TSAR) attached to them whereby the option holder has the right to receive
cash payment equal to the excess of the market price of the Companys Common Shares at the time
of exercise over the exercise price of the right. These TSARs expire after five years. The following tables summarize the information about the TSARs: As at December 31
    2004WeightedAverageOutstanding
    
    
    ExerciseTSARs
    
    
    PriceCanadian Dollar Denominated(C$)Outstanding, Beginning of Year
    
    
    
    
    
    
    Granted
    
    
    1,080,450
    
    
    
    55.31Forfeited
    
    
    (212,950
    )
    
    
    54.37Outstanding, End of Year
    
    
    867,500
    
    
    
    55.54Exercisable, End of Year
    
    
    
    
    
    
    
 As at December 31
    TSARs OutstandingWeightedAverage
    
    
    WeightedRemaining
    
    
    AverageNumber of
    
    
    Contractual
    
    
    ExerciseRange of Exercise Price
    
    TSARs
    
    
    Life(years)
    
    
    PriceCanadian Dollar Denominated(C$)50.00 to 59.99
    
    
    784,000
    
    
    
    4.359
    
    
    
    54.7560.00 to 70.00
    
    
    83,500
    
    
    
    4.874
    
    
    
    62.91867,500
    
    
    
    4.408
    
    
    
    55.54
 During the year, the Company recorded compensation costs of $3 million related to the
outstanding 37




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED TSARs. D) Deferred Share Units The Company has in place a program whereby Directors and certain key employees are issued
Deferred Share Units (DSUs), which are equivalent in value to a common share of the Company.
DSUs granted to directors vest immediately. DSUs granted to Senior Executives in 2002 vest
over a three year period. DSUs expire on December 15th of the year following the
employees retirement or death. The following table summarizes the information about the DSUs: As at December 31
    
    2004
    
    
    
    2003Outstanding
    
    
    Average
    
    
    
    Outstanding
    
    
    AverageDSUs
    
    
    Share Price
    
    
    
    DSUs
    
    
    Share PriceCanadian Dollar Denominated(C$)Outstanding, Beginning of Year
    
    
    319,250
    
    
    
    48.68
    
    
    
    
    309,167
    
    
    
    48.69Granted, Directors
    
    
    58,931
    
    
    
    54.04
    
    
    
    
    36,402
    
    
    
    48.20Units, in lieu of dividends
    
    
    3,208
    
    
    
    59.86
    
    
    
    
    2,723
    
    
    
    46.72Exercised
    
    
    (6,083
    )
    
    
    48.68
    
    
    
    
    (29,042
    )
    
    
    48.04Outstanding, End of Year
    
    
    375,306
    
    
    
    49.61
    
    
    
    
    319,250
    
    
    
    48.68Exercisable, End of Year
    
    
    293,955
    
    
    
    52.55
    
    
    
    
    80,645
    
    
    
    48.68
 During the year, the Company recorded compensation costs of $10 million related to the
outstanding DSUs (2003  $4 million; 2002  $4 million). E) Performance Share Units EnCana has in place a program whereby employees may be granted Performance Share Units (PSUs)
which entitle the employee to receive, upon vesting, either a common share of EnCana or a cash
payment equal to the value of one common share of EnCana depending upon the terms of the PSU
granted. PSUs vest at the end of a three year period. Their ultimate value will depend upon
EnCanas performance measured over three calendar years. Performance will be measured by total
shareholder return relative to a fixed North American oil and gas comparison group. If EnCanas
performance is below the specified level compared to the comparison group, the units awarded
will be forfeited. If EnCanas performance is at or above the specified level compared to the
comparison group, the value of the PSUs shall be determined by EnCanas relative ranking, with
payments ranging from one to two times for PSUs granted for the 2003 grant and one half to two
times the PSUs granted for the 2004 grant. PSUs granted in 2004 are to be paid in common shares (2003  paid in cash). 38




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The following table summarizes the information about the PSUs: As at December 31
    
    2004
    
    
    
    2003Outstanding
    
    
    Average
    
    
    
    Outstanding
    
    
    AveragePSU's
    
    
    Share Price
    
    
    
    PSU's
    
    
    Share PriceCanadian Dollar Denominated(C$)Outstanding, Beginning of Year
    
    
    126,283
    
    
    
    46.52
    
    
    
    
    
    
    
    
    Granted
    
    
    1,690,790
    
    
    
    53.95
    
    
    
    
    128,893
    
    
    
    46.52Forfeited
    
    
    (169,970
    )
    
    
    53.51
    
    
    
    
    (2,610
    )
    
    
    46.52Outstanding, End of Year
    
    
    1,647,103
    
    
    
    53.42
    
    
    
    
    126,283
    
    
    
    46.52Exercisable, End of Year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    U.S. Dollar Denominated(US$)Outstanding, Beginning of Year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Granted
    
    
    250,224
    
    
    
    41.12
    
    
    
    
    
    
    
    
    Forfeited
    
    
    (25,609
    )
    
    
    41.12
    
    
    
    
    
    
    
    
    Outstanding, End of Year
    
    
    224,615
    
    
    
    41.12
    
    
    
    
    
    
    
    
    Exercisable, End of Year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
 During the year, the Company recorded compensation costs of $25 million related to the
outstanding PSUs (2003  $1 million; 2002  nil). NOTE 17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT As a means of managing commodity price volatility, EnCana has entered into various financial
instrument agreements and physical contracts. The following information presents all positions
for financial instruments. As discussed in Note 2, on January 1, 2004, the fair value of all outstanding financial
instruments that were not considered accounting hedges was recorded in the Consolidated Balance
Sheet with an offsetting net deferred loss amount. The deferred loss is recognized into net
earnings over the life of the related contracts. Changes in fair value after that time are
recorded in the Consolidated Balance Sheet with the associated unrealized gain or loss recorded
in net earnings. The estimated fair value of all derivative instruments is based on quoted
market prices or, in their absence, third party market indications and forecasts. The following table presents a reconciliation of the change in the unrealized amounts during
2004: Net DeferredAmounts
    
    
    Fair
    
    
    TotalRecognized on
    
    
    Market
    
    
    UnrealizedTransition
    
    
    Value
    
    
    Gain/(Loss)Fair Value of Contracts, January 1, 2004
    
    $
    235
    
    
    $
    (235
    )
    
    $
    Change in Fair Value of Contracts Still
Outstanding at December 31, 2004
    
    
    
    
    
    
    78
    
    
    
    78Fair Value of Contracts Realized During 2004
    
    
    (307
    )
    
    
    307
    
    
    
    Fair Value of Contracts Entered into During 2004
    
    
    
    
    
    
    (339
    )
    
    
    (339
    )Fair Value of Contracts Outstanding
    
    $
    (72
    )
    
    $
    (189
    )
    
    $
    (261
    )Premiums Paid on Collars and Options
    
    
    
    
    
    
    110Fair Value of Contracts Outstanding and
Premiums Paid, End of Year
    
    
    
    
    
    $
    (79
    )Amounts Allocated to Continuing Operations
    
    $
    (73
    )
    
    $
    (10
    )
    
    $
    (190
    )Amounts Allocated to Discontinued Operations
    
    
    1
    
    
    
    (69
    )
    
    
    (71
    )$
    (72
    )
    
    $
    (79
    )
    
    $
    (261
    )
 39




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The total realized loss recognized in net earnings from continuing operations for the year
ended December 31, 2004 was $464 million ($686 million, before tax). At December 31, 2004, the risk management amounts are recorded in the Consolidated Balance Sheet
as follows: As at December 31
    
    2004Risk ManagementCurrent asset
    
    $
    336Long-term asset
    
    
    87Current liability
    
    
    241Long-term liability
    
    
    192Net Risk Management Liability  Continuing Operations
    
    
    (10
    )Net Risk Management Liability  Discontinued Operations
    
    
    (69
    )$
    (79
    )
 A summary of all unrealized estimated fair value financial positions is as follows: As at December 31
    
    Note
    
    
    2004
    
    
    
    2003Commodity Price Risk
    
    
    ANatural gas
    
    
    
    
    
    $
    107
    
    
    
    $
    (13
    )Crude oil
    
    
    
    
    
    
    (143
    )
    
    
    
    (174
    )Power
    
    
    
    
    
    
    2
    
    
    
    
    4Foreign Currency Risk
    
    
    B
    
    
    
    
    
    
    
    
    7Interest Rate Risk
    
    
    C
    
    
    
    24
    
    
    
    
    45Total Fair Value Positions  Continuing Operations
    
    
    
    
    
    
    (10
    )
    
    
    
    (131
    )Total Fair Value Positions  Discontinued Operations
    
    
    
    
    
    
    (69
    )
    
    
    
    (104
    )$
    (79
    )
    
    
    $
    (235
    )
 40




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED A) Commodity Price Risk Natural Gas At December 31, 2004 the gas risk management activities from financial contracts had an
unrealized gain of $36 million and a fair market value position of $107 million. The contracts
were as follows: NotionalVolumes(MMcf/d)
    
    
    Term
    
    
    AveragePrice
    
    
    
    
    
    
    FairMarketValueSales ContractsFixed Price ContractsNYMEX Fixed Price
    
    
    481
    
    
    
    2005
    
    
    
    6.72
    
    
    US$/Mcf
    
    $
    81Colorado Interstate Gas (CIG)
    
    
    113
    
    
    
    2005
    
    
    
    4.87
    
    
    US$/Mcf
    
    
    (27
    )Other
    
    
    110
    
    
    
    2005
    
    
    
    5.21
    
    
    US$/Mcf
    
    
    (23
    )NYMEX Fixed Price
    
    
    525
    
    
    
    2006
    
    
    
    5.66
    
    
    US$/Mcf
    
    
    (105
    )Colorado Interstate Gas (CIG)
    
    
    100
    
    
    
    2006
    
    
    
    4.44
    
    
    US$/Mcf
    
    
    (37
    )Other
    
    
    171
    
    
    
    2006
    
    
    
    4.85
    
    
    US$/Mcf
    
    
    (59
    )Collars and Other OptionsPurchased NYMEX Put Options
    
    
    906
    
    
    
    2005
    
    
    
    5.46
    
    
    US$/Mcf
    
    
    29Other
    
    
    5
    
    
    
    2005
    
    
    
    4.57 - 7.23
    
    
    US$/Mcf
    
    
    NYMEX 3-Way Call Spread
    
    
    180
    
    
    
    2005
    
    
    
    5.00/6.69/7.69
    
    
    US$/Mcf
    
    
    (13
    )Purchased NYMEX Put Options
    
    
    210
    
    
    
    2006
    
    
    
    5.00
    
    
    US$/Mcf
    
    
    5Basis ContractsFixed NYMEX to AECO basis
    
    
    877
    
    
    
    2005
    
    
    
    (0.66
    )
    
    US$/Mcf
    
    
    70Fixed NYMEX to Rockies basis
    
    
    268
    
    
    
    2005
    
    
    
    (0.49
    )
    
    US$/Mcf
    
    
    19Other
    
    
    442
    
    
    
    2005
    
    
    
    (0.47
    )
    
    US$/Mcf
    
    
    4Fixed NYMEX to AECO basis
    
    
    703
    
    
    
    2006
    
    
    
    (0.65
    )
    
    US$/Mcf
    
    
    41Fixed NYMEX to Rockies basis
    
    
    312
    
    
    
    2006
    
    
    
    (0.57
    )
    
    US$/Mcf
    
    
    14Fixed NYMEX to CIG basis
    
    
    279
    
    
    
    2006
    
    
    
    (0.83
    )
    
    US$/Mcf
    
    
    (9
    )Other
    
    
    182
    
    
    
    2006
    
    
    
    (0.36
    )
    
    US$/Mcf
    
    
    2Fixed Rockies to CIG basis
    
    
    12
    
    
    
    2007
    
    
    
    (0.10
    )
    
    US$/Mcf
    
    
    Fixed NYMEX to AECO basis
    
    
    345
    
    
    
    2007-2008
    
    
    
    (0.65
    )
    
    US$/Mcf
    
    
    17Fixed NYMEX to Rockies basis
    
    
    248
    
    
    
    2007-2008
    
    
    
    (0.57
    )
    
    US$/Mcf
    
    
    14Fixed NYMEX to CIG basis
    
    
    110
    
    
    
    2007-2009
    
    
    
    (0.68
    )
    
    US$/Mcf
    
    
    5Purchase ContractsFixed Price
Contract  Waha Purchase
    
    
    27
    
    
    
    2005
    
    
    
    5.90
    
    
    US$/Mcf
    
    
    (2
    )Fixed Price
Contract  Waha Purchase
    
    
    23
    
    
    
    2006
    
    
    
    5.32
    
    
    US$/Mcf
    
    
    329Gas Storage Optimization Financial Positions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2Gas Marketing Financial Positions (1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5Total Unrealized Gain on Financial Contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    36Premiums Paid on Options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    71Total Fair Value Positions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    107
  (1)
    The gas marketing activities are part of the daily ongoing operations of the
Companys proprietary production management. 41




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Crude Oil As at December 31, 2004, the Companys oil risk management activities from all financial
contracts had an unrealized loss of $251 million and a fair market value position of $(212)
million. The contracts were as follows: Notional
    
    
    
    
    
    
    
    
    
    FairVolumes
    
    
    
    
    
    
    Average
    
    
    Market(bbls/d)
    
    
    Term
    
    
    Price
    
    
    ValueFixed WTI NYMEX Price
    
    
    41,000
    
    
    
    2005
    
    
    
    28.41
    
    
    $
    (209
    )Costless 3-Way Put Spread
    
    
    9,000
    
    
    
    2005
    
    
    
    20.00/25.00/28.78
    
    
    
    (45
    )Unwind WTI NYMEX Fixed Price
    
    
    (4,500
    )
    
    
    2005
    
    
    
    35.90
    
    
    
    11Purchased WTI NYMEX Call Options
    
    
    (38,000
    )
    
    
    2005
    
    
    
    49.76
    
    
    
    13Purchased WTI NYMEX Put Options
    
    
    35,000
    
    
    
    2005
    
    
    
    40.00
    
    
    
    13Fixed WTI NYMEX Price
    
    
    15,000
    
    
    
    2006
    
    
    
    34.56
    
    
    
    (31
    )Purchased WTI NYMEX Put Options
    
    
    22,000
    
    
    
    2006
    
    
    
    27.36
    
    
    
    (2
    )(250
    )Crude Oil Marketing Financial Positions(1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1
    )Total Unrealized Loss on Financial Contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (251
    )Premiums Paid on Options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    39Total Fair Value Positions
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (212
    )Total Fair Value Positions  Continuing Operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (143
    )Total Fair Value Positions  Discontinued Operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (69
    )$
    (212
    )
  (1)
    The crude oil marketing activities are part of the daily ongoing operations of
the Companys proprietary production management. Power EnCana has one electricity contract which expires in 2005. The contract was entered into as part
of an electricity cost management strategy. At December 31, 2004, the unrealized gain on the
contract was $2 million. B) Foreign Currency Risk Foreign currency risk is the risk that a variation in exchange rates between the Canadian dollar
and foreign currencies will affect the Companys operating and financial results. The Company
has significant operations outside of Canada, which are subject to these foreign exchange risks. No forward foreign currency exchange contracts were in place to hedge future commodity revenue
streams as at December 31, 2004. C) Interest Rate Risk The Company has entered into various derivative contracts to manage the Companys interest rate
exposure on debt instruments. The impact of these transactions is described in Note 7. 42




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The unrealized gains on the outstanding financial instruments as at December 31, 2004 were as
follows: UnrealizedGain5.80% Medium Term Notes
    
    $
    117.50% Medium Term Notes
    
    
    58.75% Debenture
    
    
    8$
    24
 At December 31, 2004, the increase or decrease in net earnings for each one percent change
in interest rates on floating rate debt amounts to $13 million (2003  $14 million). D) Fair Value of Financial Assets and Liabilities The fair values of financial instruments not recorded at their fair values that are included in
the Consolidated Balance Sheet, other than long-term borrowings, approximate their carrying
amount due to the short-term maturity of those instruments. The estimated fair values of long-term borrowings have been determined based on market
information where available, or by discounting future payments of interest and principal at
estimated interest rates that would be available to the Company at year end. As at December 31
    
    2004
    
    
    
    2003Carrying
    
    
    Fair
    
    
    
    Carrying
    
    
    FairAmount
    
    
    Value
    
    
    
    Amount
    
    
    ValueFinancial AssetsCash and cash equivalents
    
    $
    602
    
    
    $
    602
    
    
    
    $
    113
    
    
    $
    113Accounts receivable
    
    
    1,898
    
    
    
    1,898
    
    
    
    
    1,165
    
    
    
    1,165Financial LiabilitiesAccounts payable, income taxes payable
    
    $
    2,238
    
    
    $
    2,238
    
    
    
    $
    1,380
    
    
    $
    1,380Long-term debt
    
    
    7,930
    
    
    
    8,479
    
    
    
    
    6,375
    
    
    
    6,767
 E) Credit Risk A substantial portion of the Companys accounts receivable are with customers in the oil and gas
industry and are subject to normal industry credit risks. The Board has approved a credit
policy governing the Companys credit portfolio and procedures are in place to ensure adherence
to this policy. With respect to counterparties to financial instruments, the Company partially
mitigates associated credit risk by limiting transactions to counterparties with investment
grade credit ratings. All foreign currency agreements are with major financial institutions in Canada and the United
States or with counterparties having investment grade credit ratings. 43




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED NOTE 18. SUPPLEMENTARY INFORMATION A) Per Share Amounts The following table summarizes the Common Shares used in calculating Net Earnings and Cash Flow
per Common Share. For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Weighted
Average Common Shares Outstanding  Basic
    
    
    460.4
    
    
    
    
    474.1
    
    
    
    
    417.8Effect of Stock Options and Other Dilutive Securities
    
    
    7.6
    
    
    
    
    5.6
    
    
    
    
    4.8Weighted
Average Common Shares Outstanding  Diluted
    
    
    468.0
    
    
    
    
    479.7
    
    
    
    
    422.6
 B) Net Change in Non-Cash Working Capital from Continuing Operations For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Operating ActivitiesAccounts receivable and accrued revenues
    
    $
    665
    
    
    
    $
    (107
    )
    
    
    $
    (276
    )Inventories
    
    
    14
    
    
    
    
    (241
    )
    
    
    
    (64
    )Accounts payable and accrued liabilities
    
    
    601
    
    
    
    
    (252
    )
    
    
    
    (14
    )Income taxes payable
    
    
    175
    
    
    
    
    32
    
    
    
    
    (535
    )$
    1,455
    
    
    
    $
    (568
    )
    
    
    $
    (889
    )Investing ActivitiesAccounts payable and accrued liabilities
    
    $
    (21
    )
    
    
    $
    (113
    )
    
    
    $
    195
 C) Supplementary Cash
Flow Information  Continuing Operations For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Interest Paid
    
    $
    401
    
    
    
    $
    284
    
    
    
    $
    261Income Taxes Paid (Received)
    
    $
    148
    
    
    
    $
    (127
    )
    
    
    $
    567
 NOTE 19. COMMITMENTS AND CONTINGENCIES Commitments As at December 31, 2004
    
    2005
    
    
    
    2006
    
    
    
    2007
    
    
    
    2008
    
    
    
    2009
    
    
    
    Thereafter
    
    
    
    TotalPipeline Transportation
    
    $
    297
    
    
    
    $
    262
    
    
    
    $
    237
    
    
    
    $
    220
    
    
    
    $
    182
    
    
    
    $
    1,010
    
    
    
    $
    2,208Purchases of Goods and Services
    
    
    121
    
    
    
    
    23
    
    
    
    
    14
    
    
    
    
    9
    
    
    
    
    3
    
    
    
    
    5
    
    
    
    
    175Product Purchases
    
    
    171
    
    
    
    
    32
    
    
    
    
    25
    
    
    
    
    24
    
    
    
    
    24
    
    
    
    
    134
    
    
    
    
    410Operating Leases
    
    
    42
    
    
    
    
    43
    
    
    
    
    41
    
    
    
    
    36
    
    
    
    
    29
    
    
    
    
    152
    
    
    
    
    343Capital Commitments
    
    
    190
    
    
    
    
    41
    
    
    
    
    22
    
    
    
    
    4
    
    
    
    
    
    
    
    
    
    38
    
    
    
    
    295Total
    
    $
    821
    
    
    
    $
    401
    
    
    
    $
    339
    
    
    
    $
    293
    
    
    
    $
    238
    
    
    
    $
    1,339
    
    
    
    $
    3,431Product Sales
    
    $
    502
    
    
    
    $
    56
    
    
    
    $
    58
    
    
    
    $
    61
    
    
    
    $
    33
    
    
    
    $
    275
    
    
    
    $
    985
 In addition to the above, the Company has made commitments related to its risk management
program (see Note 17). 44




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Contingencies Legal Proceedings The Company is involved in various legal claims associated with the normal course of operations.
The Company believes it has made adequate provision for such legal claims. Discontinued Merchant Energy Operations In July 2003, the Companys indirect wholly owned U.S. marketing subsidiary, WD Energy Services
Inc. (WD), concluded a settlement with the U.S. Commodity Futures Trading Commission (CFTC)
of a previously disclosed CFTC investigation. The investigation related to alleged inaccurate
reporting of natural gas trading information during 2000 and 2001 by former employees of WDs
now discontinued Houston-based merchant energy trading operation to energy industry publications
that compiled and reported index prices. All Houston-based merchant energy trading operations
were discontinued following the merger with Alberta Energy Company Ltd. in 2002. Under the terms
of the settlement, WD agreed to pay a civil monetary penalty in the amount of $20 million
without admitting or denying the findings in the CFTCs order. The Company and WD are defendants in a lawsuit filed by E. & J. Gallo Winery in the United
States District Court in California and, along with other energy companies, are defendants in
several other lawsuits in California (many of which are class actions) and three class action
lawsuits filed in the United States District Court in New York. A motion by the Company and WD
to dismiss the Gallo complaint on the basis that the Federal Energy Regulatory Commission had
exclusive jurisdiction regarding this matter was not granted. The Gallo complaint claims damages
in excess of $30 million, before potential trebling under California laws. Most of the California class action lawsuits were transferred by the Judicial Panel on
Multidistrict Litigation on a consolidated basis to the Nevada District Court and all of the New
York lawsuits were consolidated in New York District Court by the plaintiffs application. The
Nevada District Court has remanded the California State Court cases back to the California State
Court for hearing. The California lawsuits relate to sales of natural gas in California from
1999 to the present and contain allegations that the defendants engaged in a conspiracy with
unnamed competitors in the natural gas and derivatives market in California in violation of U.S.
and California anti-trust and unfair competition laws to artificially raise the price of natural
gas through various means including the illegal sharing of price information through online
trading, price indices and wash trading. The New York lawsuits claim that the defendants
alleged manipulation of natural gas price indices resulted in higher prices of natural gas
futures and option contracts traded on the NYMEX from 2000 to 2002. EnCana Corporation has been
dismissed from the New York lawsuits, leaving only WD and several other companies unrelated to
EnCana as the remaining defendants. As is customary, the class actions do not specify the
amount of damages claimed. The Company and WD intend to vigorously defend against these claims; however, the Company cannot
predict the outcome of these proceedings or any future proceedings against the Company, whether
these proceedings would lead to monetary damages which could have a material adverse effect on
the Companys financial position, or whether there will be other proceedings arising out of
these allegations. Asset Retirement The Company is responsible for the retirement of long-lived assets related to its oil and gas
properties and Midstream facilities at the end of their useful lives. The Company has recognized
a liability of $611 million based on current legislation and estimated costs. Actual costs may
differ from those estimated due to changes in legislation and changes in costs. 45




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED Income Tax Matters The operations of the Company are complex, and related tax interpretations, regulations and
legislation in the various jurisdictions that the Company operates in are continually changing.
As a result, there are usually some tax matters under review. The Company believes that the
provision for taxes is adequate. NOTE 20. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING The Consolidated Financial Statements have been prepared in accordance with accounting
principles generally accepted in Canada (Canadian GAAP) which, in most respects, conform to
accounting principles generally accepted in the United States (U.S. GAAP). The significant
differences between Canadian and U.S. GAAP are described in this note. RECONCILIATION OF NET EARNINGS UNDER CANADIAN GAAP TO U.S. GAAP For the years ended December 31
    
    Note
    
    
    2004
    
    
    
    2003
    
    
    
    2002Net Earnings  Canadian GAAP
    
    
    
    
    
    $
    3,513
    
    
    
    $
    2,360
    
    
    
    $
    812Less:Net Earnings
From Discontinued Operations  Canadian GAAP
    
    
    
    
    
    
    1,302
    
    
    
    
    218
    
    
    
    
    146Net Earnings From Continuing Operations  Canadian GAAP
    
    
    
    
    
    
    2,211
    
    
    
    
    2,142
    
    
    
    
    666Increase (Decrease) under U.S. GAAP:Revenues, net of royalties
    
    
    B
    
    
    
    243
    
    
    
    
    (101
    )
    
    
    
    (174
    )Operating
    
    
    B
    
    
    
    (3
    )
    
    
    
    
    
    
    
    
    Depreciation, depletion and amortization
    
    
    A,G
    
    
    
    31
    
    
    
    
    14
    
    
    
    
    (41
    )Interest, net
    
    
    B
    
    
    
    (41
    )
    
    
    
    70
    
    
    
    
    126Accretion of asset retirement obligation
    
    
    G
    
    
    
    
    
    
    
    
    
    
    
    
    
    13Stock-based compensation
    
    
    C
    
    
    
    (5
    )
    
    
    
    (1
    )
    
    
    
    (3
    )Income tax expense
    
    
    E,G
    
    
    
    (73
    )
    
    
    
    7
    
    
    
    
    21Net Earnings From Continuing Operations  U.S. GAAP
    
    
    
    
    
    
    2,363
    
    
    
    
    2,131
    
    
    
    
    608Net Earnings From Discontinued Operations  U.S. GAAP
    
    
    
    
    
    
    1,370
    
    
    
    
    152
    
    
    
    
    146Net Earnings Before Change in Accounting Policy  U.S. GAAP
    
    
    
    
    
    
    3,733
    
    
    
    
    2,283
    
    
    
    
    754Cumulative Effect of Change in Accounting Policy, net of tax
    
    
    G
    
    
    
    
    
    
    
    
    66
    
    
    
    
    Net Earnings
 U.S. GAAP
    
    
    
    
    
    $
    3,733
    
    
    
    $
    2,349
    
    
    
    $
    754Net Earnings
per Common Share Before Change in Accounting Policy  U.S. GAAPBasic
    
    
    
    
    
    $
    8.11
    
    
    
    $
    4.82
    
    
    
    $
    1.81Diluted
    
    
    
    
    
    $
    7.98
    
    
    
    $
    4.76
    
    
    
    $
    1.78Net Earnings per Common Share Including Cumulative Effect
of Change in Accounting Policy  U.S. GAAPBasic
    
    
    
    
    
    $
    8.11
    
    
    
    $
    4.95
    
    
    
    $
    1.81Diluted
    
    
    
    
    
    $
    7.98
    
    
    
    $
    4.90
    
    
    
    $
    1.78
 46




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED CONSOLIDATED STATEMENT OF EARNINGS  U.S. GAAP For the years ended December 31
    
    Note
    
    
    2004
    
    
    
    2003
    
    
    
    2002Revenues, Net of Royalties
    
    
    B
    
    
    $
    12,053
    
    
    
    $
    9,585
    
    
    
    $
    5,754ExpensesProduction and mineral taxes
    
    
    
    
    
    
    311
    
    
    
    
    164
    
    
    
    
    105Transportation and selling
    
    
    
    
    
    
    499
    
    
    
    
    484
    
    
    
    
    332Operating
    
    
    B
    
    
    
    1,353
    
    
    
    
    1,196
    
    
    
    
    749Purchased product
    
    
    
    
    
    
    4,276
    
    
    
    
    3,455
    
    
    
    
    2,200Depreciation, depletion and amortization
    
    
    A,G
    
    
    
    2,371
    
    
    
    
    1,975
    
    
    
    
    1,227Administrative
    
    
    C
    
    
    
    197
    
    
    
    
    173
    
    
    
    
    121Interest, net
    
    
    B
    
    
    
    438
    
    
    
    
    213
    
    
    
    
    160Accretion of asset retirement obligation
    
    
    G
    
    
    
    22
    
    
    
    
    17
    
    
    
    
    Foreign exchange gain
    
    
    
    
    
    
    (417
    )
    
    
    
    (598
    )
    
    
    
    (11
    )Stock-based compensation
    
    
    
    
    
    
    22
    
    
    
    
    19
    
    
    
    
    Gain on dispositions
    
    
    
    
    
    
    (113
    )
    
    
    
    (1
    )
    
    
    
    (33
    )Net Earnings Before Income Tax
    
    
    
    
    
    
    3,094
    
    
    
    
    2,488
    
    
    
    
    904Income tax expense
    
    
    E
    
    
    
    731
    
    
    
    
    357
    
    
    
    
    296Net Earnings From Continuing Operations  U.S. GAAP
    
    
    
    
    
    
    2,363
    
    
    
    
    2,131
    
    
    
    
    608Net Earnings From Discontinued Operations  U.S. GAAP
    
    
    A,B
    
    
    
    1,370
    
    
    
    
    152
    
    
    
    
    146Net Earnings Before Change in Accounting Policy  U.S. GAAP
    
    
    
    
    
    
    3,733
    
    
    
    
    2,283
    
    
    
    
    754Cumulative Effect of Change in Accounting Policy, net of tax
    
    
    G
    
    
    
    
    
    
    
    
    66
    
    
    
    
    Net Earnings   U.S. GAAP
    
    
    
    
    
    $
    3,733
    
    
    
    $
    2,349
    
    
    
    $
    754Net Earnings From Continuing Operations per Common Share 
U.S. GAAPBasic
    
    
    
    
    
    $
    5.13
    
    
    
    $
    4.49
    
    
    
    $
    1.46Diluted
    
    
    
    
    
    $
    5.05
    
    
    
    $
    4.44
    
    
    
    $
    1.44Net Earnings
per Common Share Before Change in Accounting Policy  U.S. GAAPBasic
    
    
    
    
    
    $
    8.11
    
    
    
    $
    4.82
    
    
    
    $
    1.81Diluted
    
    
    
    
    
    $
    7.98
    
    
    
    $
    4.76
    
    
    
    $
    1.78Net Earnings per Common Share Including Cumulative Effect
of Change in Accounting Policy  U.S. GAAPBasic
    
    
    
    
    
    $
    8.11
    
    
    
    $
    4.95
    
    
    
    $
    1.81Diluted
    
    
    
    
    
    $
    7.98
    
    
    
    $
    4.90
    
    
    
    $
    1.78
 STATEMENT OF OTHER COMPREHENSIVE INCOME For the years ended December 31
    
    Note
    
    
    2004
    
    
    
    2003
    
    
    
    2002Net Earnings  U.S. GAAP
    
    
    
    
    
    $
    3,733
    
    
    
    $
    2,349
    
    
    
    $
    754Change in Fair Value of Financial Instruments
    
    
    B,F
    
    
    
    
    
    
    
    
    4
    
    
    
    
    (7
    )Foreign Currency Translation Adjustment
    
    
    D
    
    
    
    420
    
    
    
    
    1,046
    
    
    
    
    136Other
    
    
    
    
    
    
    
    
    
    
    
    6
    
    
    
    
    (6
    )Other Comprehensive Income
    
    
    
    
    
    $
    4,153
    
    
    
    $
    3,405
    
    
    
    $
    877
 47




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED CONDENSED CONSOLIDATED BALANCE SHEET As at December 31
    
    
    
    
    
    2004
    
    
    
    2003Note
    
    
    As reported
    
    
    
    U.S. GAAP
    
    
    
    As reported
    
    
    
    U.S. GAAPAssetsCurrent Assets
    
    
    A,B
    
    
    $
    3,505
    
    
    
    $
    3,497
    
    
    
    $
    2,616
    
    
    
    $
    2,676Property, Plant and Equipment, net
    
    
    A,G
    
    
    
    23,140
    
    
    
    
    23,044
    
    
    
    
    17,770
    
    
    
    
    17,644Investments and Other Assets
    
    
    B
    
    
    
    334
    
    
    
    
    330
    
    
    
    
    268
    
    
    
    
    271Risk Management
    
    
    B
    
    
    
    87
    
    
    
    
    87
    
    
    
    
    
    
    
    
    
    85Assets of Discontinued Operations
    
    
    
    
    
    
    1,623
    
    
    
    
    1,623
    
    
    
    
    1,545
    
    
    
    
    1,545Goodwill
    
    
    
    
    
    
    2,524
    
    
    
    
    2,524
    
    
    
    
    1,911
    
    
    
    
    1,911$
    31,213
    
    
    
    $
    31,105
    
    
    
    $
    24,110
    
    
    
    $
    24,132Liabilities and Shareholders EquityCurrent Liabilities
    
    
    A,B
    
    
    $
    2,947
    
    
    
    $
    2,942
    
    
    
    $
    2,072
    
    
    
    $
    2,435Long-Term Debt
    
    
    
    
    
    
    7,742
    
    
    
    
    7,742
    
    
    
    
    6,088
    
    
    
    
    6,088Other Liabilities
    
    
    B
    
    
    
    118
    
    
    
    
    64
    
    
    
    
    21
    
    
    
    
    8Risk Management
    
    
    B
    
    
    
    192
    
    
    
    
    192
    
    
    
    
    
    
    
    
    
    10Asset Retirement Obligation
    
    
    G
    
    
    
    611
    
    
    
    
    611
    
    
    
    
    383
    
    
    
    
    383Liabilities of Discontinued Operations
    
    
    A,B
    
    
    
    102
    
    
    
    
    102
    
    
    
    
    112
    
    
    
    
    82Future Income Taxes
    
    
    E,G
    
    
    
    5,193
    
    
    
    
    5,118
    
    
    
    
    4,156
    
    
    
    
    4,05416,905
    
    
    
    
    16,771
    
    
    
    
    12,832
    
    
    
    
    13,060Share Capital
    
    
    C
    
    
    
    5,299
    
    
    
    
    5,316
    
    
    
    
    5,305
    
    
    
    
    5,318Share Options, net
    
    
    
    
    
    
    10
    
    
    
    
    10
    
    
    
    
    55
    
    
    
    
    55Paid in Surplus
    
    
    
    
    
    
    28
    
    
    
    
    28
    
    
    
    
    18
    
    
    
    
    18Retained Earnings
    
    
    
    
    
    
    7,935
    
    
    
    
    7,955
    
    
    
    
    5,276
    
    
    
    
    5,076Foreign Currency Translation Adjustment
    
    
    D
    
    
    
    1,036
    
    
    
    
    
    
    
    
    
    624
    
    
    
    
    Accumulated Other Comprehensive Income
    
    
    
    
    
    
    
    
    
    
    
    1,025
    
    
    
    
    
    
    
    
    
    60514,308
    
    
    
    
    14,334
    
    
    
    
    11,278
    
    
    
    
    11,072$
    31,213
    
    
    
    $
    31,105
    
    
    
    $
    24,110
    
    
    
    $
    24,132
 The following table summarizes the assets and liabilities of discontinued operations
included in current assets and current liabilities: As at December 31
    
    
    
    
    
    2004
    
    
    
    2003Note
    
    
    As reported
    
    
    
    U.S. GAAP
    
    
    
    As reported
    
    
    
    U.S. GAAPAssets of Discontinued Operations
    
    
    A,B
    
    
    $
    156
    
    
    
    $
    159
    
    
    
    $
    781
    
    
    
    $
    781Liabilities of Discontinued Operations
    
    
    A,B
    
    
    
    280
    
    
    
    
    315
    
    
    
    
    405
    
    
    
    
    500
 48




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED CONDENSED CONSOLIDATED
STATEMENT OF CASH FLOWS  U.S. GAAP For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Operating ActivitiesNet earnings from continuing operations
    
    $
    2,363
    
    
    
    $
    2,131
    
    
    
    $
    608Depreciation, depletion and amortization
    
    
    2,371
    
    
    
    
    1,975
    
    
    
    
    1,227Future income taxes
    
    
    164
    
    
    
    
    470
    
    
    
    
    362Unrealized (gain) loss on risk management
    
    
    (15
    )
    
    
    
    31
    
    
    
    
    48Unrealized foreign exchange gain
    
    
    (285
    )
    
    
    
    (545
    )
    
    
    
    (23
    )Accretion of asset retirement obligation
    
    
    22
    
    
    
    
    17
    
    
    
    
    Gain on dispositions
    
    
    (113
    )
    
    
    
    (1
    )
    
    
    
    Other
    
    
    98
    
    
    
    
    57
    
    
    
    
    (163
    )Cash flow from discontinued operations
    
    
    375
    
    
    
    
    324
    
    
    
    
    360Net change in other assets and liabilities
    
    
    (176
    )
    
    
    
    (84
    )
    
    
    
    (17
    )Net change in non-cash working capital from continuing operations
    
    
    1,455
    
    
    
    
    (568
    )
    
    
    
    (889
    )Net change in non-cash working capital from discontinued
operations
    
    
    (1,668
    )
    
    
    
    497
    
    
    
    
    104Cash From Operating Activities
    
    $
    4,591
    
    
    
    $
    4,304
    
    
    
    $
    1,617Cash Used in Investing Activities
    
    $
    (4,259
    )
    
    
    $
    (3,729
    )
    
    
    $
    (2,595
    )Cash From (Used in) Financing Activities
    
    $
    163
    
    
    
    $
    (542
    )
    
    
    $
    498
 Notes: A) Full Cost Accounting The full cost method of accounting for crude oil and natural gas operations under Canadian and
U.S. GAAP differ in the following respects. Under U.S. GAAP, a ceiling test is applied to ensure
the unamortized capitalized costs in each cost centre do not exceed the sum of the present
value, discounted at 10 percent, of the estimated unescalated future net operating revenue from
proved reserves plus unimpaired unproved property costs less future development costs, related
production costs and applicable taxes. Under Canadian GAAP, a similar ceiling test calculation
is performed with the exception that cash flows from proved reserves are undiscounted and
utilize forecast pricing to determine whether impairment exists. Any impairment amount is
measured using the fair value of proved and probable reserves. In computing its consolidated net earnings for U.S. GAAP purposes, the Company recorded
additional depletion in 2001 and certain years prior to 2001 as a result of the application of
the ceiling test. These charges were not required under the Canadian GAAP ceiling tests. As a
result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes. Effective January 1, 2004, the Canadian Accounting Standards Board amended the Full Cost
Accounting Guideline. Under Canadian GAAP, depletion charges are calculated by reference to
proved reserves estimated using estimated future prices and costs. Under U.S. GAAP, depletion
charges are calculated by reference to proved reserves estimated using constant prices. B) Derivative Instruments and Hedging On January 1, 2004, the Company implemented under Canadian GAAP, EIC 128 Accounting For
Trading, Speculative or Non-Hedging Derivative Financial Instruments which requires derivatives
not designated as hedges to be recorded in the balance sheet as either assets or liabilities at
their fair value. Changes in the derivatives fair value are recognized in current period
earnings. Under the transitional rules any gain or loss at the implementation date is deferred
and recognized into revenue 49




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED once realized. Currently, Management has not designated any of the financial instruments as
hedges. The adoption of EIC 128 at January 1, 2004 resulted in the recognition of a $235 million
deferred loss which will be recognized into earnings when realized. As at December 31, 2004,
under Canadian GAAP a $72 million deferred gain remains, of which a $1 million deferred loss has
been classified in liabilities of discontinued operations. For U.S. GAAP, the Company adopted Statement of Financial Accounting Standards (FAS) 133
effective January 1, 2001. FAS 133 requires that all derivatives be recorded in the balance
sheet as either assets or liabilities at their fair value. Changes in the derivatives fair
value are recognized in current period earnings unless specific hedge accounting criteria are
met. Management has currently not designated any of the financial instruments as hedges for U.S.
GAAP purposes under FAS 133. Realized and unrealized gain/(loss) on derivatives related to: For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Commodity Prices (Revenues, net of royalties)
    
    $
    76
    
    
    
    $
    (205
    )
    
    
    $
    (174
    )Interest and Currency Swaps (Interest, net)
    
    
    (29
    )
    
    
    
    70
    
    
    
    
    126Total Unrealized Gain (Loss)
    
    $
    47
    
    
    
    $
    (135
    )
    
    
    $
    (48
    )Amounts Allocated to Continuing Operations
    
    $
    15
    
    
    
    $
    (31
    )
    
    
    $
    (48
    )Amounts Allocated to Discontinued Operations
    
    
    32
    
    
    
    
    (104
    )
    
    
    
    $
    47
    
    
    
    $
    (135
    )
    
    
    $
    (48
    )
 As at December 31, 2004, it is estimated that over the following 12 months, $3 million ($2
million, net of tax) will be reclassified into net earnings from other comprehensive income. C) Stock-based
Compensation  CPL Reorganization Under Canadian GAAP, compensation costs have been recognized in the financial statements for
stock options granted to employees and directors in 2003. For the effect of stock-based
compensation on the Canadian GAAP financial statements, which would be the same adjustment under
U.S. GAAP, see Note 15. Under Financial Accounting Standards Board (FASB) Interpretation No. 44 Accounting for
Certain Transactions involving Stock Compensation, compensation expense must be recorded if the
intrinsic value of the stock options is not exactly the same immediately before and after an
equity restructuring. As part of the corporate reorganization of Canadian Pacific Ltd., an
equity restructuring occurred which resulted in CPL stock options being replaced with stock
options granted by EnCana as described in Note 15. This resulted in the replacement options
having a different intrinsic value after the restructuring than prior to the restructuring.
Canadian GAAP does not require revaluation of these options. D) Foreign Currency Translation Adjustments U.S. GAAP requires gains or losses arising from the translation of self-sustaining operations to
be included in other comprehensive income. Canadian GAAP requires these amounts to be recorded
in Shareholders Equity. E) Future Income Taxes Under U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP
uses substantively enacted tax rates. 50




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED The future income tax adjustments included in the Reconciliation of Net Earnings under Canadian
GAAP to U.S. GAAP and the Condensed Consolidated Balance Sheet include the effect of such rate
differences, if any, as well as the tax effect of the other reconciling items noted. The following table provides a reconciliation of the statutory rate to the actual tax rate: For the years ended December 31
    
    2004
    
    
    
    2003
    
    
    
    2002Using Canadian GAAP:Net Earnings Before Income Tax
    
    $
    2,869
    
    
    
    $
    2,506
    
    
    
    $
    983Canadian Statutory Rate
    
    
    39.1
    %
    
    
    
    41.0
    %
    
    
    
    42.3
    %Expected Income Tax
    
    
    1,123
    
    
    
    
    1,026
    
    
    
    
    416Effect on Taxes Resulting from:Non-deductible Canadian crown payments
    
    
    192
    
    
    
    
    231
    
    
    
    
    147Canadian resource allowance
    
    
    (246
    )
    
    
    
    (258
    )
    
    
    
    (200
    )Canadian resource allowance on unrealized risk management losses
    
    
    (10
    )
    
    
    
    
    
    
    
    
    Statutory and other rate differences
    
    
    (55
    )
    
    
    
    (45
    )
    
    
    
    (35
    )Effect of tax rate reductions
    
    
    (109
    )
    
    
    
    (359
    )
    
    
    
    (20
    )Non-taxable capital gains
    
    
    (91
    )
    
    
    
    (119
    )
    
    
    
    Previously unrecognized capital losses
    
    
    17
    
    
    
    
    (119
    )
    
    
    
    Tax basis retained on dispositions
    
    
    (179
    )
    
    
    
    
    
    
    
    
    Large corporations tax
    
    
    24
    
    
    
    
    27
    
    
    
    
    23Other
    
    
    (8
    )
    
    
    
    (20
    )
    
    
    
    (14
    )658
    
    
    
    
    364
    
    
    
    
    317U.S. GAAP Adjustments to Net Earnings Before Income Tax
    
    
    225
    
    
    
    
    (18
    )
    
    
    
    (79
    )Expected Income Tax
    
    
    88
    
    
    
    
    (7
    )
    
    
    
    (33
    )Other
    
    
    (15
    )
    
    
    
    
    
    
    
    
    1273
    
    
    
    
    (7
    )
    
    
    
    (21
    )Income Tax  U.S. GAAP
    
    $
    731
    
    
    
    $
    357
    
    
    
    $
    296Effective Tax Rate
    
    
    23.6
    %
    
    
    
    14.3
    %
    
    
    
    32.7
    %
 The net future income tax liability is comprised of: As at December 31
    
    2004
    
    
    
    2003Future Tax LiabilitiesProperty, plant and equipment in excess of tax values
    
    $
    4,436
    
    
    
    $
    3,152Timing of partnership items
    
    
    1,005
    
    
    
    
    1,162Future Tax AssetsNet operating losses carried forward
    
    
    (103
    )
    
    
    
    (99
    )Other
    
    
    (220
    )
    
    
    
    (161
    )Net Future Income Tax Liability
    
    $
    5,118
    
    
    
    $
    4,054
 F) Other Comprehensive Income U.S. GAAP requires the disclosure, as other comprehensive income, of changes in equity during
the period from transaction and other events from non-owner sources. Canadian GAAP does not
require similar disclosure. Other comprehensive income arose from the transition adjustment
resulting from the January 1, 2001 adoption of FAS 133. At December 31, 2004, accumulated other
comprehensive income related to these items was a loss of $9 million, net of tax. G) Asset Retirement Obligation In 2003, the Company early adopted the Canadian accounting standard for asset retirement
obligations, as outlined in the CICA handbook section 3110. This standard is equivalent to U.S.
FAS 51




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED 143 Accounting for Asset Retirement Obligations, which was effective for fiscal periods
beginning on or after January 1, 2003. Early adopting the Canadian standard eliminated a U.S.
GAAP reconciling item in respect to accounting for the obligation, however a difference is
created in how the transition amounts are disclosed. U.S. GAAP requires the cumulative impact of a change in an accounting policy be presented in the
current year Consolidated Statement of Earnings and prior periods not be restated. The
following table illustrates the pro forma impact on the Companys financial results under U.S.
GAAP if the prior periods had been restated: For the year ended December 31
    
    As Reported
    
    
    Change
    
    
    As Restated2002 Consolidated Statement of EarningsNet Earnings
    
    $
    754
    
    
    $
    34
    
    
    $
    788Net Earnings per Common Share  Diluted
    
    $
    1.78
    
    
    $
    0.08
    
    
    $
    1.86
 H) Consolidated Statement of Cash Flows Under U.S. GAAP, separate subtotals within cash flow from operating activities are not
presented. I) Recent Accounting Pronouncements During 2004, the following new standards were issued: Share-Based Payment In 2004, FASB issued revised FAS 123 Share-Based Payment. This amended statement eliminates
the alternative to use Accounting Principles Board (APB) Opinion No. 25s intrinsic value
method of accounting, as was provided in the originally issued Statement 123. As a result,
public entities are required to use the grant-date fair value of the award in measuring the cost
of employee services received in exchange for an equity award of equity instruments.
Compensation cost is required to be recognized over the requisite service period. For liability
awards, entities are required to re-measure the fair value of the award at each reporting date
up until the settlement date. Changes in fair value of liability awards during the requisite
service period are required to be recognized as compensation cost over the vesting period.
Compensation cost is not recognized for equity instruments for which employees do not render the
requisite service. This amended statement is effective the beginning of the first interim or
annual reporting period that begins after June 15, 2005. The Company is currently assessing the
impact of this amendment. Exchange of Non-monetary Assets In 2004, FASB issued FAS 153 Exchange of Non-monetary Assets. This statement is an
amendment of APB Opinion No. 29 Accounting for Non-monetary Transactions. Based on the
guidance in APB Opinion No. 29, exchanges of non-monetary assets are to be measured based on the
fair value of the assets exchanged. Furthermore, APB Opinion No. 29 previously allowed for
certain exceptions to this fair value principle. FAS 153 eliminates APB Opinion No. 29s
exception to fair value for non-monetary exchanges of similar productive assets and replaces
this with a general exception for exchanges of non-monetary assets which do not have commercial
substance. For purposes of this statement, a non-monetary exchange is defined as having
commercial substance when the future cash flows of an entity are expected to change
significantly as a result of the exchange. The provisions of this statement are effective for
non-monetary asset exchanges which occur in fiscal periods beginning after June 15, 2005 and are
to be applied prospectively. Earlier application is permitted for non-monetary asset exchanges
which occur in fiscal periods beginning after the issue date of this statement. Currently, this
statement does not have an impact on EnCana; 52




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED however, this may result in a future impact to the Company if EnCana enters into any
non-monetary asset exchanges. 53




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ADDITIONAL DISCLOSURE Certifications and Disclosure Regarding Controls and Procedures.  (a)
    Certifications. See Exhibits 99.1 and 99.2 to this Annual Report on Form 40-F.(b)
    Disclosure Controls and Procedures. As of the end of the registrants fiscal year
ended December 31, 2004, an evaluation of the effectiveness of the registrants disclosure
controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the
Securities Exchange Act of 1934, as amended (the Exchange Act)) was carried out by the
registrants principal executive officer and principal financial officer. Based upon that
evaluation, the registrants principal executive officer and principal financial officer have
concluded that as of the end of that fiscal year, the registrants disclosure controls and
procedures are effective to ensure that information required to be disclosed by the registrant
in reports that it files or submits under the Exchange Act is (i) recorded, processed,
summarized and reported within the time periods specified in Securities and Exchange
Commission rules and forms and (ii) accumulated and communicated to the registrants
management, including its principal executive officer and principal financial officer, to
allow timely decisions regarding required disclosure.It should be noted that while the registrants principal executive officer and principal
financial officer believe that the registrants disclosure controls and procedures provide
a reasonable level of assurance that they are effective, they do not expect that the
registrants disclosure controls and procedures or internal control over financial
reporting will prevent all errors and fraud. A control system, no matter how well
conceived or operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met.(c)
    Changes in Internal Control Over Financial Reporting. During the fiscal year ended
December 31, 2004, there were no changes in the registrants internal control over financial
reporting that have materially affected, or are reasonably likely to materially affect, the
registrants internal control over financial reporting. Notices Pursuant to Regulation BTR. None. Audit Committee Financial Expert. The registrants board of directors has determined that Jane L. Peverett, a member of the
registrants audit committee, qualifies as an audit committee financial expert (as such term is
defined in Form 40-F). 40-F2




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Code of Ethics. The registrant has adopted a code of ethics (as that term is defined in Form 40-F), entitled the
Business Conduct and Ethics Practice (the Code of Ethics), that applies to its principal
executive officer, principal financial officer, principal accounting officer or controller, and
persons performing similar functions (together, the Financial Supervisors). The Code of Ethics is available for viewing on the registrants website at www.encana.com. Since the adoption of the Code of Ethics, there have not been any amendments to the Code of Ethics
or waivers, including implicit waivers, from any provision of the Code of Ethics. Principal Accountant Fees and Services. The required disclosure is included under the heading Audit Committee Information-External Auditor
Service Fees in the registrants Annual Information Form for the fiscal year ended December 31,
2004, filed as part of this Annual Report on Form 40-F. Pre-Approval Policies and Procedures. The required disclosure is included under the heading Audit Committee Information-Pre-Approval
Policies and Procedures in the registrants Annual Information Form for the fiscal year ended
December 31, 2004, filed as part of this Annual Report on Form 40-F. Off-Balance Sheet Arrangements. The required disclosure is
included under the heading Off-Balance Sheet Arrangements in the
registrants Managements Discussion and Analysis of Financial Condition and Results of Operations
for the fiscal year ended December 31, 2004, filed as part of this Annual Report on Form 40-F. Tabular Disclosure of Contractual Obligations. The required disclosure is included under the heading Contractual Obligations and Contingencies
in the registrants Managements Discussion and Analysis of Financial Condition and Results of
Operations for the fiscal year ended December 31, 2004, filed as part of this Annual Report on Form
40-F. Identification of the Audit Committee. The registrant has a separately-designated standing audit committee established in accordance with
section 3(a)(58)(A) of the Exchange Act. The members of the audit 40-F3




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committee are: Patrick D. Daniel, William R. Fatt, Barry W. Harrison, Dale A. Lucas, Jane L.
Peverett, James M. Stanford and David P. OBrien (ex officio). Disclosure Pursuant to the Requirements of the New York Stock Exchange. Presiding Director at Meetings of Non-Management Directors The registrant schedules regular executive sessions in which the registrants non-management
directors (as that term is defined in the rules of the New York Stock Exchange) meet without
management participation. Mr. David P. OBrien serves as the presiding director (the Presiding
Director) at such sessions. Each of the registrants non-management directors is unrelated as
such term is used in the rules of the Toronto Stock Exchange. Communication with Non-Management Directors Shareholders may send communications to the registrants non-management directors by writing to the
Presiding Director, c/o Kerry D. Dyte, General Counsel and Corporate Secretary, EnCana Corporation,
1800, 855  2nd Street S.W., Calgary, Alberta, Canada, T2P 2S5. Communications will be
referred to the Presiding Director for appropriate action. The status of all outstanding concerns
addressed to the Presiding Director will be reported to the board of directors as appropriate. Corporate Governance Guidelines According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and
disclose a set of corporate governance guidelines with respect to specified topics. Such
guidelines are required to be posted on the listed companys website. The registrant operates
under corporate governance principles that are consistent with the requirements of Section 303A.09
of the NYSE Listed Company Manual, and which are described under the heading Statement of
Corporate Governance Practices in the registrants Information Circular in connection with its
2005 Annual Meeting. However, the registrant has not codified its corporate governance principles
into formal guidelines in order to post them on its website. Board Committee Mandates The Mandates of the registrants audit committee, human resources and compensation committee, and
nominating and corporate governance committee are each available for viewing on the registrants
website at www.encana.com, and are available in print to any shareholder who requests them.
Requests for copies of these documents should be made by contacting: Kerry D. Dyte, General
Counsel and Corporate Secretary, EnCana Corporation, 1800, 855-2nd Street S.W., P.O. Box
2850, Calgary, Alberta, Canada T2P 2S5. Alternatively, requests for these documents may be made
by contacting the registrants Corporate Development Department at (403) 645-2000 (Fax: (403)
645-4617). 40-F4




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UNDERTAKING AND CONSENT TO SERVICE OF PROCESS A. Undertaking. The registrant undertakes to make available, in person or by telephone, representatives to
respond to inquiries made by the Securities and Exchange Commission (the Commission) staff, and
to furnish promptly, when requested to do so by the Commission staff, information relating to: the
securities registered pursuant to Form 40-F; the securities in relation to which the obligation
to file an annual report on Form 40-F arises; or transactions in said securities. B. Consent to Service of Process. The Company has previously filed a Form F-X in connection with the class of securities in
relation to which the obligation to file this report arises. Any change to the name or address of the agent for service of process of the registrant shall
be communicated promptly to the Securities and Exchange Commission by an amendment to the Form F-X
referencing the file number of the relevant registration statement. SIGNATURES Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all
of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on
its behalf by the undersigned, thereunto duly authorized, on February 25, 2005. EnCana CorporationBy: /s/ Thomas G. HintonName: Thomas G. HintonTitle: TreasurerBy: /s/ Gerald T. InceName: Gerald T. InceTitle: Assistant Treasurer
 40-F5




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EXHIBIT INDEX Exhibit
    
    Description99.1
    
    Certification of Chief Executive Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 193499.2
    
    Certification of Chief Financial Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 193499.3
    
    Section 1350 Certification of Chief Executive Officer99.4
    
    Section 1350 Certification of Chief Financial Officer99.5
    
    Consent of PricewaterhouseCoopers LLP99.6
    
    Consent of McDaniel & Associates Consultants Ltd.99.7
    
    Consent of Netherland, Sewell & Associates, Inc.99.8
    
    Consent of DeGolyer and MacNaughton99.9
    
    Consent of Gilbert Laustsen Jung Associates Ltd.