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U.S. SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

Form 40-F

(Check One)

|  |  |                                                                                        
|- |  | ---------------------------------------------------------------------------------------
|o |  | Registration 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, 2003

Commission file number 1-15226

EnCana Corporation(Exact name of registrant as specified in its charter)

|       |  |      |  |               
|------ |  | ---- |  | --------------
|Canada |  | 1311 |  | Not 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 registered      
|                                   |  |                                                
|Common Shares
Preferred Securities |  | New York Stock Exchange
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: 460,063,418

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.

|     |  |    
|---- |  | ---
|Yeso |  | Noþ

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.

|     |  |    
|---- |  | ---
|Yesþ |  | Noo

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 No. 333-98087).



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TABLE OF CONTENTS



|                                                                                       |                                            |                                                         |  |  |  |  |  | 
|-------------------------------------------------------------------------------------- | ------------------------------------------ | ------------------------------------------------------- |  |  |  |  |  | 
|PRINCIPAL DOCUMENTS                                                                   
|ANNUAL INFORMATION FORM                                                               
|INTRODUCTORY INFORMATION                                                              
|NOTE REGARDING FORWARD-LOOKING STATEMENTS                                             
|NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION                        
|CORPORATE STRUCTURE                                                                   
|                                                                                       | Name and Incorporation                    
|                                                                                       | Intercorporate Relationships              
|GENERAL DEVELOPMENT OF THE BUSINESS                                                   
|                                                                                       | Upstream                                  
|                                                                                       | Midstream and Marketing                   
|NARRATIVE DESCRIPTION OF THE BUSINESS                                                 
|                                                                                       | UPSTREAM                                  
|                                                                                       |                                            | Canada                                                 
|                                                                                       |                                            | United States                                          
|                                                                                       |                                            | Ecuador                                                
|                                                                                       |                                            | United Kingdom                                         
|                                                                                       |                                            | International New Ventures Exploration                 
|                                                                                       | MIDSTREAM AND MARKETING                   
|                                                                                       |                                            | Midstream                                              
|                                                                                       |                                            | Marketing                                              
|                                                                                       | RESERVES AND OTHER OIL AND GAS INFORMATION
|                                                                                       |                                            | Reserve Quantities Information                         
|                                                                                       |                                            | Other Disclosures About Oil and Gas Activities         
|                                                                                       |                                            | Daily Sales Volumes, Royalty Rates and Per-Unit Results
|                                                                                       |                                            | Drilling Activity                                      
|                                                                                       |                                            | Location of Wells                                      
|                                                                                       |                                            | Interest in Material Properties                        
|                                                                                       |                                            | Acquisitions, Dispositions and Capital Expenditures    
|                                                                                       |                                            | Delivery Commitments                                   
|                                                                                       | GENERAL                                   
|SELECTED CONSOLIDATED FINANCIAL INFORMATION                                           
|MANAGEMENTS DISCUSSION AND ANALYSIS                                                  
|MARKET FOR SECURITIES                                                                 
|DIRECTORS AND OFFICERS                                                                
|SUPPLEMENTAL OIL AND GAS INFORMATION                                                  
|ADDITIONAL INFORMATION                                                                
|APPENDIX A  Report on Reserves Data by Independent Qualified Reserves Evaluators     
|APPENDIX B  Report of Management and Directors on Reserves Data and Other Information
|NOTE REGARDING FORWARD - LOOKING STATEMENTS                                           
|NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION                        
|MANAGEMENTS DISCUSSION AND ANALYSIS                                                  
|OVERVIEW                                                                              
|CONSOLIDATED FINANCIAL RESULTS                                                        
|ACQUISITIONS AND DIVESTITURES                                                         
|RESULTS OF OPERATIONS                                                                 
|LIQUIDITY AND CAPITAL RESOURCES                                                       
|OUTSTANDING SHARE DATA                                                                
|OFF BALANCE SHEET ARRANGEMENTS                                                        
|CONTRACTUAL OBLIGATIONS AND CONTINGENCIES                                             
|ACCOUNTING POLICIES AND ESTIMATES                                                     
|RISK MANAGEMENT                                                                       
|OUTLOOK                                                                               
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS                                            
|CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES.                      
|NOTICES PURSUANT TO REGULATION BTR.                                                   
|AUDIT COMMITTEE FINANCIAL EXPERT.                                                     
|CODE OF ETHICS.                                                                       
|PRINCIPAL ACCOUNTANT FEES AND SERVICES.                                               
|PRE-APPROVAL POLICIES AND PROCEDURES.                                                 
|OFF-BALANCE SHEET ARRANGEMENTS.                                                       
|TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS.                                        
|IDENTIFICATION OF THE AUDIT COMMITTEE.                                                
|DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE.               
|UNDERTAKING AND CONSENT TO SERVICE OF PROCESS                                         
|SIGNATURES                                                                            
|EXHIBIT INDEX                                                                         
|CERTIFICATION OF CEO                                                                  
|CERTIFICATION OF CFO                                                                  
|SECTION 1350 CERTIFICATION OF CEO                                                     
|SECTION 1350 CERTIFICATION OF CFO                                                     
|CONSENT OF PRICEWATERHOUSECOOPERS LLP                                                 
|CONSENT OF MCDANIEL  & ASSOCIATES CONSULTANTS LTD.                                    
|CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.                                      
|CONSENT OF RYDER SCOTT COMPANY                                                        
|CONSENT OF DEGOLYER AND MACNAUGHTON                                                   
|CONSENT OF GILBERT LAUSTSEN JUNG ASSOCIATES LTD.                                      

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, 2003;                                                                                                                                      
| | --- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | (b) |  | Managements Discussion and Analysis of Financial Condition
and Results of Operations for the fiscal year ended December 31,
2003; and                                                                    
|
| | (c) |  | Consolidated Financial Statements for the fiscal year ended
December 31, 2003 (Note 20 to the Consolidated Financial Statements
relates to United States Accounting Principles and Reporting (U.S.
GAAP)).

40-F1



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(ENCANA LOGO)



ANNUAL INFORMATION FORM


February 25, 2004



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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                      |                                                             |    | 8  |   
|NARRATIVE DESCRIPTION OF THE BUSINESS                                                      |                                            |                                                             | 9  |   
|                                                                                           | UPSTREAM                                   |                                                             |    | 9  |   
|                                                                                           |                                            | Canada                                                      |    |    | 9  | 
|                                                                                           |                                            | United States                                               |    |    | 14 | 
|                                                                                           |                                            | Ecuador                                                     |    |    | 16 | 
|                                                                                           |                                            | United Kingdom                                              |    |    | 17 | 
|                                                                                           |                                            | International New Ventures Exploration                      |    |    | 18 | 
|                                                                                           | MIDSTREAM & MARKETING                      |                                                             |    | 19 |   
|                                                                                           |                                            | Midstream                                                   |    |    | 19 | 
|                                                                                           |                                            | Marketing                                                   |    |    | 21 | 
|                                                                                           | RESERVES AND OTHER OIL AND GAS INFORMATION |                                                             |    | 23 |   
|                                                                                           |                                            | Reserve Quantities Information                              |    |    | 23 | 
|                                                                                           |                                            | Other Disclosures About Oil and
    Gas Activities          |    |    | 25 | 
|                                                                                           |                                            | Daily Sales Volumes, Royalty Rates and
    Per-Unit Results |    |    | 29 | 
|                                                                                           |                                            | Drilling Activity                                           |    |    | 37 | 
|                                                                                           |                                            | Location of Wells                                           |    |    | 38 | 
|                                                                                           |                                            | Interest in Material Properties                             |    |    | 38 | 
|                                                                                           |                                            | Acquisitions, Dispositions and Capital
    Expenditures     |    |    | 40 | 
|                                                                                           |                                            | Delivery Commitments                                        |    |    | 40 | 
|                                                                                           | GENERAL                                    |                                                             |    | 41 |   
|SELECTED CONSOLIDATED FINANCIAL INFORMATION                                                |                                            |                                                             | 42 |   
|MANAGEMENTS DISCUSSION AND ANALYSIS                                                       |                                            |                                                             | 43 |   
|MARKET FOR SECURITIES                                                                      |                                            |                                                             | 43 |   
|DIRECTORS AND OFFICERS                                                                     |                                            |                                                             | 44 |   
|SUPPLEMENTAL OIL AND GAS INFORMATION                                                       |                                            |                                                             | 47 |   
|ADDITIONAL INFORMATION                                                                     |                                            |                                                             | 52 |   
|APPENDIX A  Report on Reserves Data by
    Independent Qualified Reserves Evaluators      |                                            |                                                             | 53 |   
|APPENDIX B  Report of Management and
    Directors on Reserves Data and Other Information |                                            |                                                             | 55 |   

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INTRODUCTORY INFORMATION

EnCana Corporation (EnCana or the
Corporation) was formed through the business
combination (the Merger), on April 5, 2002, of
Alberta Energy Company Ltd. (AEC) and PanCanadian
Energy Corporation (PanCanadian). The Merger was
accomplished through an arrangement in respect of AEC under the
Business Corporations Act (Alberta) and certain corporate
changes for PanCanadian. Pursuant to the Merger, PanCanadian
indirectly acquired all of the outstanding common shares of AEC
in consideration for common shares issued by PanCanadian.
PanCanadians name was also changed to EnCana Corporation
and its board of directors and senior management were
reconstituted. Following completion of the Merger, AEC remained
in existence, as an indirect wholly owned subsidiary of EnCana.
On January 1, 2003, AEC and another subsidiary were
amalgamated with EnCana. As a result of these transactions, the
former PanCanadian and the former AEC continue as one
corporation known as EnCana Corporation.

In this annual information form, unless otherwise
specified or the context otherwise requires, reference to
EnCana or to the Corporation includes
reference to subsidiaries of and partnership interests held by
EnCana Corporation and its subsidiaries. Any reference to
EnCana or the Corporation for periods
prior to the Merger are to EnCanas founding companies,
PanCanadian and AEC, and their subsidiaries and partnership
interests.

Unless otherwise indicated, all financial
information included and incorporated by reference in this
annual information form is determined using Canadian generally
accepted accounting principles (Canadian GAAP),
which differs from generally accepted accounting principles in
the United States (U.S. GAAP). The notes to
EnCanas audited consolidated financial statements contain
a discussion of the principal differences between EnCanas
financial results calculated under Canadian GAAP and under
U.S. GAAP.

In accordance with Canadian GAAP, the
consolidated financial statements of EnCana include the results
of PanCanadian prior to the Merger and do not include any
results related to AECs operations prior to the Merger.
Accordingly, unless otherwise indicated, all financial
information contained in this annual information form for 2002
and prior periods does not reflect any results of AEC prior to
the Merger. Unless otherwise indicated, other statistical
information and operational results are presented on the
same basis.

Unless otherwise specified, all dollar amounts
are expressed in United States dollars, all references to
dollars or $ are to United States
dollars and all references to C$ are to Canadian
dollars.For the financial years ended
prior to December 31, 2003, all audited consolidated
financial statements of EnCana were expressed in Canadian
dollars. For purposes of expressing in United States dollars
amounts that were previously expressed in Canadian dollars, the
relevant amounts have been translated into United States dollars
in the manner discussed in Note 2 to EnCanas audited
consolidated financial statements for the year ended
December 31, 2003. Capital expenditures budgeted for 2004
which are expected to be incurred in Canada have been translated
into United States dollars using a rate of $0.73 United
States dollars per one Canadian dollar.

1



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NOTE REGARDING FORWARD-LOOKING
STATEMENTS

This annual information form contains certain
forward-looking statements within the meaning 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 or
similar words suggesting future outcomes or statements regarding
an outlook. Forward-looking statements in this annual
information form include, but are not limited to, statements
with respect to: capital investment levels and the allocation
thereof, drilling plans and the timing and location thereof,
production levels and the timing of achieving such levels,
pipeline capacity, reserve estimates, the timing of completion
of the Ekwan pipeline, the timing of completion of the Wild
Goose Storage Facility expansion, the timing of completion of
the Countess Storage Facility and the use of its capacity, the
use of facilities related to the Hythe Gas Storage Facility and
the timing thereof, the future impact of the Alberta Energy and
Utilities Boards September 2003 shut-in order, storage
capacity, the level of expenditures for compliance with
environmental regulations, site restoration costs including
abandonment and reclamation costs, the timing and completion of
acquisitions, the timing and completion of the Starks Storage
facility, net cash flows, geographical expansion, the amount and
use of steam power generated by the Foster Creek cogeneration
facility, recovery improvement in the Weyburn oil field, plans
for seismic surveys, the netback price received by EnCana,
projected increases in oil shipment volumes through the OCP
pipeline and the forward-looking statements identified in the
Corporations Managements Discussion and Analysis for
the year ended December 31, 2003, which is incorporated
into this annual information form by reference.

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 things
contemplated by the forward-looking statements will not occur.
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. Some
of the risks and other factors which could cause results to
differ materially from those expressed in the forward-looking
statements contained in this annual information form include,
but are not limited to: volatility of oil and natural gas
prices, fluctuations in currency and interest rates, product
supply and demand, market competition, risks inherent in
EnCanas North American and foreign oil and natural gas and
midstream operations, risks of war, hostilities, civil
insurrection and instability affecting countries in which EnCana
and its subsidiaries operate and terrorist threats, risks
inherent in EnCanas and its subsidiaries marketing
operations, including credit risk, imprecision of reserves
estimates and estimates of recoverable quantities of oil,
natural gas and liquids from resource plays and other sources
not currently classified as proved reserves, EnCanas and
its subsidiaries ability to replace and expand oil and
natural gas reserves, EnCanas ability to generate
sufficient cash flow from operations to meet its current and
future obligations, EnCanas ability to access external
sources of debt and equity capital, general economic and
business conditions, EnCanas ability to enter into or
renew leases, the timing and costs of gas storage facility, well
and pipeline construction, EnCanas ability to make capital
investments and the amounts of capital investments, imprecision
in estimating the timing, costs and levels of production and
drilling, the results of exploration, development and drilling,
imprecision in estimates of future production capacity,
EnCanas and its subsidiaries ability to secure
adequate product transportation, uncertainty in the amounts and
timing of royalty payments, imprecision in estimates of product
sales, changes in environmental and other regulations, risks
associated with existing and potential future lawsuits and
regulatory actions against EnCana and its subsidiaries,
political and economic conditions in the countries in which
EnCana and its subsidiaries operate including Ecuador, the risk
that the anticipated synergies to be realized by the Merger will
not be realized, difficulty in obtaining necessary regulatory
approvals and such other risks and uncertainties described from
time to time in EnCanas reports and filings with the
Canadian securities authorities and the United States Securities
and Exchange Commission (the SEC). Statements
relating to reserves are deemed to be
forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions, that the
reserves described exist in the quantities predicted or
estimated, and can be profitably produced in the future. Readers
are cautioned that the foregoing list of important factors is
not exhaustive.

2



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The forward-looking statements contained in this
annual information form are made as of the date hereof and
EnCana undertakes no obligation to update publicly or revise any
forward-looking statements, whether as a result of new
information, future events or otherwise. The forward-looking
statements contained in this annual information form are
expressly qualified by this cautionary statement.


NOTE REGARDING RESERVES DATA AND OTHER OIL AND
GAS INFORMATION

In 2003, the securities regulatory authorities in
Canada (other than Quebec) adopted National Instrument 51-101
(NI 51-101), which imposes new oil and gas
disclosure standards for Canadian public companies engaged in
oil and gas activities. NI 51-101 and its companion policy
specifically contemplate the granting of exemptions from some of
the disclosure standards prescribed by NI 51-101 to
companies that are active in the United States
(U.S.) capital markets, to permit the substitution
of the standards required by the SEC in order to provide for
comparability of oil and gas disclosure with that provided by
U.S. and other international issuers. EnCana has obtained
an exemption from Canadian securities regulatory authorities to
permit it to provide disclosure in accordance with the relevant
legal requirements of the SEC. Accordingly, the reserves data
and other oil and gas information included or incorporated by
reference in this annual information form is disclosed in
accordance with U.S. disclosure requirements and practices.
Such information, as well as the information that EnCana
discloses in the future in reliance on the exemption, may differ
from the corresponding information prepared in accordance with
NI 51-101 standards.

The primary differences between the
U.S. requirements and the NI 51-101 requirements are
that (i) the U.S. standards require disclosure only of
proved reserves, whereas NI 51-101 requires disclosure of
proved and probable reserves, and (ii) the
U.S. standards require that the reserves and related future
net revenue be estimated under existing economic and operating
conditions, i.e., prices and costs as of the date the
estimate is made, whereas NI 51-101 requires disclosure of
proved reserves and the related future net revenue estimated
using constant prices and costs as at the last day of the
financial year, and of proved and probable reserves and related
future net revenue using forecast prices and costs. The
definitions of proved reserves also differ, but according to the
Canadian Oil and Gas Evaluation Handbook (the reference source
for the definition of proved reserves under NI 51-101),
differences in the estimated proved reserve quantities based on
constant prices should not be material. EnCana concurs with
this assessment.

EnCana has disclosed proved reserve quantities,
using the standards contained in U.S. Regulation S-X,
and the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves determined in accordance
with United States Statement of Financial Accounting Standards
No. 69 Disclosures About Oil and Gas Producing
Activities (FAS 69).

Under U.S. disclosure standards, reserves
and production information is disclosed on a net basis (after
royalties). Unless otherwise indicated, the reserves and
production information contained in this annual information form
is shown on that basis.

In this annual information form, certain natural
gas volumes have been converted to barrels of oil equivalent
(BOEs) on the basis of six thousand cubic feet
(Mcf) to one barrel (bbl). BOEs may be
misleading, particularly if used in isolation. A BOE conversion
ratio of six Mcf to one bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and
does not represent equivalency at the well head.

3



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CORPORATE STRUCTURE



Name and Incorporation


As described under Introductory
Information, EnCana Corporation was formed through the
Merger involving AEC and PanCanadian. EnCana is incorporated
under the Canada Business Corporations
Act (CBCA).

AEC was incorporated on September 18, 1973
under The Companies Act(Alberta) and was continued under
the Business Corporations Act (Alberta) on
September 30, 1986.

PanCanadian was incorporated under the CBCA on
June 26, 2001 in order to participate in the reorganization
of Canadian Pacific Limited (CPL) by way of a plan
of arrangement whereby, effective October 1, 2001, CPL
distributed to its common shareholders all of the shares of five
public companies holding the assets of CPLs five primary
operating subsidiaries, including PanCanadian. The holders of
common shares of PanCanadian Petroleum Limited exchanged their
shares for common shares of PanCanadian. At the conclusion of
the CPL reorganization, PanCanadian Petroleum Limited became a
wholly owned subsidiary of PanCanadian. PanCanadian Petroleum
Limited and PanCanadian were amalgamated on January 1, 2002
and continued under the name PanCanadian Energy
Corporation. On completion of the Merger with AEC on
April 5, 2002, PanCanadians name was changed to
EnCana Corporation.

Prior to the CPL reorganization, PanCanadian
Petroleum Limited was a public corporation, approximately
85 percent of which was held by CPL and 15 percent by
the public. Originally established by CPL in 1958 as Canadian
Pacific Oil and Gas Limited, PanCanadian Petroleum Limited began
its operations using the fee title lands that the Government of
Canada had transferred to CPL as part of CPLs building of
the national railway across Canada. PanCanadian Petroleum
Limited resulted from the amalgamation, under the laws of
Canada, on December 31, 1971, of PanCanadian Petroleum
Limited (incorporated as Central Leduc Oils Limited in 1947) and
Canadian Pacific Oil and Gas Limited (incorporated in 1958).
PanCanadian Petroleum Limited was continued under the CBCA on
April 9, 1980.

The executive and registered office of EnCana is
located at 1800, 855  2nd Street S.W., Calgary,
Alberta, Canada T2P 2S5.

Intercorporate Relationships

The following table presents the name, the
percentage of voting securities owned and the jurisdiction of
incorporation, continuance or formation of EnCanas
principal subsidiaries and partnerships with total assets that
exceed 10 percent of the total consolidated assets of
EnCana or revenues that exceed 10 percent of the total
consolidated revenues of EnCana as at and for the year ended
December 31, 2003:

|                             |  |            |     |                 |  |  |          | 
|---------------------------- |  | ---------- | --- | --------------- |  |  | -------- | 
|                             |  |            |     | Jurisdiction of
|                             |  |            |     | Incorporation, 
|                             |  | Percentage |     | Continuance    
|Subsidiaries & Partnerships  |  | Owned(1)   |     | or Formation   
|                             |  |            |     |                
|EnCana Oil & Gas Partnership |  |            | 100 |                 |  |  | Alberta  | 
|EnCana Midstream & Marketing |  |            | 100 |                 |  |  | Alberta  | 
|EnCana West Ltd.             |  |            | 100 |                 |  |  | Alberta  | 
|Alenco Inc.                  |  |            | 100 |                 |  |  | Delaware | 
|EnCana Oil & Gas (USA) Inc.  |  |            | 100 |                 |  |  | Delaware | 
|McMurry Oil Company          |  |            | 100 |                 |  |  | Wyoming  | 
|EnCana Marketing (USA) Inc.  |  |            | 100 |                 |  |  | Delaware | 




Notes:



|    |                             
|--- | ----------------------------
|(1) | Includes indirect ownership.

The above table does not include all of the
subsidiaries and partnerships of EnCana. The assets and revenues
of unnamed subsidiaries and partnerships in the aggregate did
not exceed 20 percent of the total consolidated assets or
total consolidated revenues of EnCana as at and for the year
ended December 31, 2003.

4



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GENERAL DEVELOPMENT OF THE BUSINESS

EnCana is one of the worlds leading
independent crude oil and natural gas exploration and production
companies, based on landholdings and production at
December 31, 2003. EnCanas key landholdings are in
western Canada, the U.S. Rocky Mountains, Ecuador, the
United Kingdom (U.K.) central North Sea, offshore
Canadas East Coast and the Gulf of Mexico. EnCana explores
for, produces and markets natural gas, crude oil and natural gas
liquids (NGLs) in Canada and the U.S. EnCana is
also engaged in exploration and production activities
internationally including production from Ecuador and the U.K.
central North Sea. EnCana has interests in midstream operations
and assets, including natural gas storage, NGLs gathering and
processing facilities, power plants and pipelines.

Upon completion of the Merger on April 5,
2002, EnCanas business was organized into four operating
divisions: Onshore North America, Offshore &
International Operations, Offshore & New Ventures
Exploration, and Midstream & Marketing. During 2003,
EnCana reorganized its operations, and now operates under two
main divisions: (i) Upstream; and
(ii) Midstream & Marketing. The following
describes the significant transactions and events in the last
three years in the businesses that are now conducted in
those divisions.

UPSTREAM

The Upstream division manages EnCanas
exploration, development and production of natural gas, NGLs and
crude oil and other related activities. The majority of
EnCanas Upstream operations are located in Canada, the
U.S., Ecuador and the U.K. central North Sea. International new
ventures exploration is mainly focused on opportunities in
Africa, South America and the Middle East.

Canada

EnCanas Canadian Upstream operations are
divided into two regions  Canadian Plains and
Canadian Foothills & Frontier.

Canadian
Plains Region

The Canadian Plains region of western Canada
encompasses EnCanas natural gas production activities in
southern Alberta and Saskatchewan as well as the
Corporations crude oil projects in northeast Alberta,
southern Alberta and Saskatchewan and coalbed methane
(CBM) projects in southern Alberta.

EnCana pursues natural gas in shallow and deep
horizons and has had several discoveries over the last three
years. EnCana is also involved in crude oil development projects
including steam-assisted gravity drainage (SAGD)
operations at Foster Creek and Christina Lake in northeast
Alberta. Commercial production commenced at Foster Creek in the
fourth quarter of 2001. In 2003, the Corporation completed an
expansion of the Foster Creek project to increase production
beyond its original design capacity. At the end of 2003, EnCana
completed the third phase of a planned seven phase carbon
dioxide (CO2) miscible flood development
at Weyburn, Saskatchewan. There are now 32 patterns, or
well groupings, on stream out of a planned total of
75 patterns.

Exploration for CBM  natural gas
derived from coal seams  over the last three years
has led to the development of a number of CBM pilot projects
located on the Palliser Block of southern Alberta. In the last
half of 2003, EnCana expanded its CBM development by drilling
approximately 200 wells on the Palliser Block.

In February 2003, EnCana sold a 10 percent
interest in the Syncrude Joint Venture (Syncrude) to
Canadian Oil Sands Limited (COS) for net cash
consideration of approximately $690 million
(C$1.0 billion). In July 2003, COS acquired EnCanas
remaining 3.75 percent interest in Syncrude and an
overriding royalty for net cash consideration of approximately
$309 million (C$427 million), bringing the total net
cash consideration from the sales to approximately
$1.0 billion (C$1.5 billion). Both of these
transactions are subject to post-closing adjustments.

In February 2004, EnCana sold its
53.3 percent interest in Petrovera Resources
(Petrovera) for approximately $285 million
(C$374 million), before working capital adjustments.
Petrovera is an Alberta

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partnership that produces heavy oil in western
Canada. EnCanas share of Petroveras net production
averaged approximately 17,500 barrels per day of crude oil
in 2003.


Canadian
Foothills & Frontier Region

The Canadian Foothills & Frontier region
includes EnCanas natural gas and crude oil exploration,
development and production activities in northern Alberta and
British Columbia. It also includes EnCanas exploration and
development activities offshore the East Coast of Canada and in
the Northwest Territories.

In 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. In September 2003,
EnCana purchased a majority interest in 39 parcels of land
totalling roughly 350,000 net acres for approximately
$270 million (C$369 million). The Corporation had
previously acquired about 150,000 net acres through
purchases and land swaps with other companies and Crown land
sales, resulting in the total landholding of approximately
500,000 net acres.

The Corporation has developed a large land
position offshore the East Coast of Canada. Since the Deep
Panuke natural gas discovery in 1999, EnCana has conducted an
active exploration program, on its own and with partners. In
February 2003, EnCana requested an adjournment of the regulatory
approval process for offshore development at Deep Panuke. In
December 2003, following the drilling of two successful
exploration wells, Margaree and MarCoh, EnCana initiated work on
a new plan for a potential offshore development at
Deep Panuke.

United States

EnCanas interests in the U.S. are
primarily located in the U.S. Rockies, north Texas, the
Gulf of Mexico and Alaska. The development of the U.S. as a
core area began in June 2000, when EnCana Oil & Gas
(USA) Inc., an indirect wholly owned subsidiary of EnCana,
acquired all of the shares of McMurry Oil Company and other
private interests (McMurry) for total consideration
of approximately $778 million, including the assumption of
debt. McMurrys principal producing properties are in the
Jonah natural gas field located in the Green River Basin of
southwest Wyoming.

In February 2001, EnCana Oil & Gas (USA)
Inc., through a wholly owned subsidiary, acquired all of the
shares of Ballard Petroleum LLC (Ballard) for net
cash consideration of approximately $220 million.
Ballards principal producing properties are in the Mamm
Creek natural gas field located in the Piceance Basin of
northwest Colorado.

As a result of the McMurry acquisition in June
2000, and a consolidation of some of EnCanas
U.S. subsidiaries in December 2000, EnCana Oil &
Gas (USA) Inc. indirectly owned all of the partnership interests
in Jonah Gas Gathering Corporation, a Wyoming general
partnership which owned the Jonah Gas Gathering System. In
September 2001, EnCana Oil & Gas (USA) Inc.s indirect
interest in Jonah Gas Gathering Corporation was sold for
proceeds of approximately $360 million.

In May 2002, wholly owned subsidiaries of EnCana
Oil & Gas (USA) Inc. acquired natural gas and
associated NGLs production, reserves and acreage from
subsidiaries of El Paso Corporation (El Paso) for
approximately $275 million. The principal producing
properties acquired from the El Paso subsidiaries are located in
the Piceance Basin of northwest Colorado.

In July 2002, EnCana Oil & Gas (USA)
Inc. acquired natural gas and associated NGLs production,
reserves and acreage from a subsidiary of The Williams Companies
(Williams) for approximately $350 million. The
principal producing properties acquired from the Williams
subsidiary are located in the Jonah natural gas field in
southwest Wyoming.

In July 2003, EnCana Oil & Gas (USA)
Inc. acquired the common shares of Savannah Energy Inc.
(Savannah) for net cash consideration of
approximately $91 million. This acquisition included
interests in developed and undeveloped reserves, natural gas and
associated NGLs production, and acreage located in
north Texas.

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In October 2003, EnCana Oil & Gas (USA)
Inc. acquired natural gas and associated NGLs production,
reserves and acreage from Mesa Hydrocarbons LLC
(Mesa) for net cash consideration of approximately
$100 million. The principal producing properties acquired
from Mesa are in the Piceance Basin of northwest Colorado.

Also in October 2003, EnCana Energy Resources
Inc., an indirect wholly owned subsidiary of EnCana, divested
crude oil, natural gas and associated NGLs production, reserves,
acreage and facilities located primarily in Montana for net cash
consideration of approximately $85 million.

In the Gulf of Mexico, a subsidiary of EnCana
participated in the Llano oil discovery in 1998. In October
2003, this non-operated interest in the Llano discovery was
exchanged for additional interests in the Scott and Telford
fields in the U.K. central North Sea, which were received
by another subsidiary of EnCana.

EnCana has been increasing its landholdings in
the Gulf of Mexico through lease sales, farm-ins, exchanges and
acquisitions. Several exploration wells have been drilled over
the last three years, including a 25 percent non-operated
interest in a significant crude oil discovery at Tahiti in 2002.
A deepwater discovery in the Gulf of Mexico at Sturgis was
announced in October 2003 in which EnCana holds a
25 percent non-operated interest.

Ecuador

EnCana entered Ecuador in 1999 through the
acquisition of Pacalta Resources Ltd. for total consideration of
approximately $703 million, and is involved in crude oil
exploration, development and production primarily in the Oriente
Basin. In the fourth quarter of 2000, EnCana farmed-in to a
40 percent non-operated interest in Block 15 in the
Oriente Basin. The Corporation further increased its activity in
Ecuador in January 2003 through an acquisition of additional
reserves and production from Vintage Petroleum, Inc.
(Vintage) for net cash consideration of
approximately $116 million.

In November 2003, EnCana divested its interest in
Block 27 in the Oriente Basin for net cash consideration of
approximately $14 million.

EnCana is part of a consortium that completed
construction of the Oleoducto de Crudos Pesados
(OCP) pipeline in Ecuador in August 2003. The
pipeline was fully commissioned in November 2003 and has a
capacity of 450,000 barrels per day. EnCana has an indirect
36.3 percent equity interest in OCP and a 15-year shipping
commitment of approximately 108,000 barrels per day.

United Kingdom

In January 2000, EnCana completed the purchase of
13.5 percent and 20.2 percent interests in the Scott
and Telford crude oil fields, respectively, in the U.K. central
North Sea, for net cash consideration of approximately
$177 million. In October 2003, through the Llano exchange
referred to above, EnCana acquired an additional
14.0 percent interest in each of the Scott and Telford
fields. The Corporation also assumed operatorship of the Scott
and Telford fields. In early 2004, EnCana completed the purchase
of additional 13.5 percent and 20.2 percent interests
in the Scott and Telford fields, respectively, for net cash
consideration of approximately $126 million. EnCana now
holds 41.0 percent of the Scott field and 54.3 percent
of the Telford field.

In the spring of 2001, the Corporation made a
significant crude oil discovery in the U.K. central North Sea at
Buzzard. In November 2003, the U.K. Department of Trade and
Industry approved the development plan for Buzzard.

International New Ventures
Exploration

EnCana invests a small portion (less than
5 percent) of its capital in high potential exploration
beyond its core geographic areas, primarily in Africa, South
America and the Middle East.

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MIDSTREAM & MARKETING

EnCanas midstream activities are primarily
comprised of natural gas storage operations, NGLs processing and
power generation operations.

EnCana continues to pursue expansions of its
North American continental natural gas storage network with the
expansion of the Wild Goose storage facility in northern
California and the completion of the first phase of the Countess
storage facility east of Calgary. The Wild Goose expansion is
scheduled for completion in April 2004. The first phase of the
new Countess facility came online in October 2003.

Also in October 2003, EnCana Gas Storage Inc., an
indirect wholly owned subsidiary of EnCana, announced that it is
planning to build a new, high-deliverability natural gas storage
facility in southwest Louisiana. This planned facility is known
as the Starks project and the first phase of the facility is
anticipated to be fully in-service by the third quarter
of 2005.

In December 2001, EnCana sold its
100 percent interest in Alberta Oilsands Pipeline Ltd.,
owner of the Alberta Oilsands Pipelines System, for
approximately $137 million (C$218 million).

In January 2003, EnCana completed the sale of its
indirect 70 percent interest in the Cold Lake Pipeline
System (Cold Lake) for approximately
$270 million (C$425 million). The Corporation has
retained crude oil transportation capacity on the pipeline for
its production through its existing long-term contracts. EnCana
also completed the sale of its indirect 100 percent
interest in the Express Pipeline System (Express) in
January 2003 for approximately $778 million
(C$1.2 billion), which included the assumption of
approximately $385 million (C$600 million) in debt by
the purchaser. EnCana has retained crude oil transportation
capacity on the system through its existing long-term contracts.

EnCanas marketing activities include the
sale and delivery of produced product and the purchase of third
party product, primarily for the optimization of midstream
assets as well as the optimization of transportation
arrangements not fully utilized for the Corporations own
production. EnCanas production of NGLs in western Canada
is marketed through Kinetic Resources (LPG), an Alberta
partnership in which EnCana has an indirect 75 percent
interest, and Kinetic Resources (U.S.A.), a Michigan partnership
in which EnCana has an indirect 75 percent interest
(collectively, Kinetic). EnCana crude oil marketing
supplies a limited number of third parties with marketing
services for a fee.

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

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NARRATIVE DESCRIPTION OF THE
BUSINESS

EnCanas business is conducted in two main
divisions: (i) Upstream; and (ii) Midstream &
Marketing.

UPSTREAM

The majority of EnCanas Upstream operations
are located in Canada, the U.S., Ecuador and the U.K. central
North Sea. International new ventures exploration is mainly
focused on opportunities in Africa, South America and the
Middle East.

As at December 31, 2003, EnCana had net
proved reserves of approximately 957 million barrels of
crude oil and NGLs and 8.4 trillion cubic feet of natural
gas, as estimated by independent qualified reserves evaluators.
Proved developed reserves comprise approximately 61 percent
of total net proved reserves. See Reserves and Other Oil
and Gas Information.

In the following discussion, comparative
production information for 2002 is presented on the basis of
combining the results of PanCanadian and AEC for the period
prior to the Merger.

Canada

Western Canada is EnCanas principal
foundation, largely from its industry leading land position of
approximately 25.1 million gross acres (approximately
21.5 million net acres, of which approximately
15.1 million net acres are undeveloped). The mineral rights
on approximately one quarter of this land is acreage owned in
fee title by EnCana, which means that production is subject to a
mineral tax that is generally less than the Crown royalty
imposed on production from land where the government owns the
mineral rights.

Canadian
Plains Region

(CDN. PLAINS MAP)

The Canadian Plains region encompasses
EnCanas natural gas production activities in southern
Alberta and Saskatchewan as well as the Corporations crude
oil development projects, including thermal recovery projects at
Foster Creek and Christina Lake using SAGD technology and a
CO2 miscible flood project at Weyburn. The region
also includes EnCanas CBM projects in
southern Alberta.

EnCanas 2004 capital investment in core
programs for natural gas projects in the Canadian Plains region
is budgeted to be approximately $860 million, with
approximately $20 million directed to exploration and

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approximately $840 million to development.
EnCana anticipates drilling approximately 3,450 gross
natural gas wells (3,300 net wells) in this region in 2004.
Capital investment in 2004 for crude oil projects is budgeted to
be approximately $390 million, primarily directed towards
development projects, including approximately $180 million
for SAGD projects, and the drilling of approximately
570 gross oil wells (560 net wells).


The following describes EnCanas major
producing areas or activities in the Canadian Plains region.

Suffield

At December 31, 2003, EnCana held an average
99 percent interest in the petroleum and natural gas rights
to approximately 1.1 million gross acres (approximately
1.1 million net acres, of which approximately
223,000 net acres are undeveloped) in the productive Upper
Cretaceous shallow natural gas horizons and deeper formations in
the Suffield area in southeast Alberta.

The Suffield area is largely made up of the
Suffield Block. Operations on the Suffield Block are carried out
by EnCana in cooperation with the Canadian military according to
guidelines established under agreements with the Government of
Canada. At December 31, 2003, there were 6,514 gross
producing shallow natural gas wells (6,497 net wells).
There were also 66 gross natural gas wells (66 net
wells) producing from deeper formations. EnCanas 2003 net
production on the Suffield Block averaged 230 million cubic
feet per day of dry, sweet natural gas (193 million cubic
feet per day in 2002).

EnCana operates and holds a 100 percent
interest in properties along the west side of the Suffield Block
which produce heavy oil. At December 31, 2003, there were
861 gross producing oil wells (856 net wells), of
which 551 gross wells (551 net wells) were horizontal
wells. In 2003, EnCanas Suffield area net crude oil
production averaged 26,945 barrels per day
(22,834 barrels per day in 2002).

Brooks

At December 31, 2003, EnCana held an average
96 percent interest in the petroleum and natural gas rights
to approximately 1.1 million gross acres (approximately
1.0 million net acres, of which approximately
134,000 net acres are undeveloped) in the Brooks area of
southern Alberta, located east of Calgary. EnCana had interests
in 7,886 gross producing natural gas wells (7,541 net
wells) and 459 gross producing oil wells (449 net
wells) at December 31, 2003. EnCanas net production
in 2003 averaged 434 million cubic feet per day of natural
gas and 15,295 barrels per day of crude oil and NGLs
(429 million cubic feet per day of natural gas and
16,253 barrels per day of crude oil and NGLs in 2002).

Calgary

At December 31, 2003, EnCana held an average
94 percent interest in the petroleum and natural gas rights
to approximately 1.3 million gross acres (approximately
1.2 million net acres, of which approximately
295,000 net acres are undeveloped) in the Calgary area.
EnCana had interests in 2,573 gross producing natural gas
wells (2,406 net wells) and 230 gross producing oil
wells (183 net wells) at December 31, 2003. Average
net production for 2003 in this area was 329 million cubic
feet per day of natural gas and 7,342 barrels per day of
crude oil and NGLs (345 million cubic feet per day of
natural gas and 8,019 barrels per day of crude oil and NGLs
in 2002).

Foster
Creek

EnCana holds surface access rights for petroleum,
natural gas and oilsands exploration, development and
transportation from areas within the Primrose Block (Cold Lake
Air Weapons Range) which were granted by the Government of
Canada. EnCana has acquired, and has certain rights to acquire,
oilsands leases wherever deposits of crude oil bitumen are
identified within the areas for which petroleum and natural gas
lease rights are held. EnCana is currently operating a
100 percent owned thermal oil recovery project in the
Foster Creek area of the Primrose Block using SAGD technology.
In 2003, EnCanas net production averaged
21,823 barrels per day of crude oil (13,026 barrels
per day in 2002). Construction of the Phase I Expansion of

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the Foster Creek project was completed in the
third quarter of 2003. The Phase I Expansion is designed to
increase 2004 net production to an expected average rate of
approximately 28,000 barrels per day of crude oil.


In 2003, EnCana completed the construction and
commenced commercial operation of an 80 megawatt, natural
gas-fired cogeneration facility in conjunction with its SAGD
operation at Foster Creek. The facility reached its full
capacity of 80 megawatts in the fourth quarter of 2003. The
steam generated by the facility is being used within the SAGD
operation and the power generated is being sold into the Alberta
Power Pool grid.

Christina
Lake

EnCana completed construction of a
100 percent owned thermal crude oil recovery pilot project
at Christina Lake using SAGD technology, and commenced
production at the end of the third quarter of 2002. Net
production was approximately 3,806 barrels of crude oil per
day in 2003 (307 barrels per day in 2002).

Thermal
Recovery Research and Development

EnCana continues to research and develop
technologies to increase recovery and decrease the costs of
extracting crude oil bitumen from oilsands.

One focus area is to reduce the reliance on steam
in crude oil bitumen production. To this end, EnCana is piloting
two technologies using solvents as part of the extraction
process. The Solvent Aided Process (SAP) mixes a
small amount of solvent with steam to enhance recovery, while
the Vapex process uses solvent in place of steam. After piloting
SAP at Senlac, Saskatchewan in 2002, EnCana began construction
of a pilot operation at Christina Lake in 2003. SAP testing at
Christina Lake is expected to begin in the second quarter of
2004. The Vapex pilot commenced testing at Foster Creek in 2002,
with additional research planned for 2004. Another focus area is
artificial lift where EnCana is pursuing pump designs that are
anticipated to enable the Corporation to implement low pressure
SAGD and decrease facility capital costs. In 2003, EnCana
successfully field-tested certain downhole pumps under existing
SAGD operating conditions, allowing for further development
of technology.

Weyburn

EnCana has a 62 percent working interest
(50 percent economic interest) in the Weyburn crude oil
field in southwest Saskatchewan. EnCana is the operator and
expects to improve ultimate recovery in the enhanced oil
recovery area with a CO2 miscible flood project.
EnCanas net production from Weyburn in 2003 averaged
10,846 barrels of crude oil per day (10,549 barrels
per day in 2002).

Coalbed
Methane

EnCana is expanding CBM development on its
100 percent owned fee title lands in southern Alberta.
During 2003, the Corporation drilled approximately
270 wells, increasing production from the commercial
demonstration project to approximately 10 million cubic
feet per day. In 2004, EnCana plans to drill approximately 300
wells, which is expected to increase CBM production to
approximately 30 million cubic feet per day by
year end.

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Canadian
Foothills & Frontier Region

(CDN. FOOTHILLS AND FRONTIER MAP)

The major producing areas of the Canadian
Foothills & Frontier region include Greater Sierra in
northeast British Columbia, Sexsmith/Hythe/Saddle Hills in
northwest Alberta, and the Primrose Block and Pelican Lake in
northeast Alberta. The region also encompasses EnCanas
recent Cutbank Ridge land acquisition spanning the British
Columbia-Alberta border, as well as exploration and development
activities offshore the East Coast of Canada and in the
Northwest Territories.

EnCanas 2004 capital investment in core
programs for natural gas projects in the Canadian
Foothills & Frontier region is budgeted to be
approximately $990 million, with approximately
$110 million directed to exploration and approximately
$880 million to development. EnCana plans to drill
approximately 620 gross natural gas wells (590 net
wells) and approximately 100 gross crude oil wells
(95 net wells) in this region in 2004. Capital investment
for crude oil projects is budgeted to be approximately
$100 million, primarily directed towards development
projects.

Greater
Sierra

In the Greater Sierra area of northeast British
Columbia, at December 31, 2003, EnCana held an average
86 percent interest in the petroleum and natural gas rights
to approximately 3.2 million gross acres (approximately
2.8 million net acres, of which approximately
2.4 million net acres are undeveloped). EnCana held an
average 96 percent interest in 13 production
facilities in the area that were capable of processing
approximately 320 million cubic feet per day of natural gas
as at December 31, 2003. EnCana is currently in the process
of constructing the $43 million Ekwan pipeline in northeast
British Columbia which will transport natural gas to Alberta.
The pipeline will extend approximately 80 kilometres with a
capacity of approximately 400 million cubic feet per day.
Completion of the pipeline is expected in the second quarter of
2004. EnCana had interests in 503 gross producing natural
gas wells (440 net wells) at December 31, 2003.
EnCanas net production in 2003 averaged 143 million
cubic feet per day of natural gas and 607 barrels per day
of NGLs (110 million cubic feet per day of natural gas and
524 barrels per day of NGLs in 2002).

Sexsmith/Hythe/Saddle
Hills

In the Sexsmith/Hythe/Saddle Hills area in
northwest Alberta, at December 31, 2003, EnCana held an
average 80 percent interest in the petroleum and natural
gas rights to approximately 529,000 gross acres

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(approximately 423,000 net acres, of which
approximately 248,000 net acres are undeveloped). EnCana had
interests in 296 gross natural gas wells (239 net
wells) and 100 gross oil wells (67 net wells) that
were producing at December 31, 2003. EnCanas net
production in 2003 averaged 114 million cubic feet per day
of natural gas and 2,990 barrels per day of crude oil and
NGLs (99 million cubic feet per day of natural gas and
3,113 barrels per day of crude oil and NGLs in 2002).


EnCana operates and has a 62 percent
interest in a 210 million cubic feet per day sour natural
gas and liquids processing plant and an 85 percent interest
in a 50 million cubic feet per day sweet natural gas plant
in the Sexsmith area. EnCana owns 100 percent of and
operates the Hythe sour natural gas plant, which has a capacity
of approximately 170 million cubic feet per day. The Hythe
and Sexsmith sour natural gas plants are interconnected by
pipeline to provide greater operating efficiencies. EnCana also
owns and operates a 240-kilometre natural gas gathering system
in the area.

Primrose
Block

At December 31, 2003, EnCana held an average
97 percent interest in the petroleum and natural gas rights
to approximately 868,000 gross acres (approximately 842,000 net
acres, of which approximately 541,000 net acres are undeveloped)
on the Primrose Block in northeast Alberta. At December 31,
2003, EnCana had interests in 533 gross natural gas wells
(511 net wells) that were producing. In 2003, EnCanas
net production from Primrose averaged 174 million cubic
feet per day of natural gas (187 million cubic feet per day
in 2002), the majority of which is processed through
100 percent controlled and operated compression facilities.
EnCanas 2003 production volumes, primarily from the
Primrose Block, were affected by an Alberta Energy and Utilities
Board decision, in September 2003, to shut-in natural gas
production that may put at risk the recovery of bitumen
resources in the area. The decision resulted in EnCanas
annualized natural gas production in the region declining by
approximately three million cubic feet per day. The future
impact of this decision is not known at this time but EnCana
does not expect it to be material.

Pelican
Lake

At December 31, 2003, EnCana held a
100 percent interest in approximately 224,000 gross acres
(approximately 224,000 net acres, of which approximately 167,000
net acres are undeveloped) of crude oil bitumen rights at
Pelican Lake in north-central Alberta. EnCana also holds a
38 percent interest in a 110-kilometre, 20-inch diameter
crude oil pipeline which connects the Pelican Lake area to a
major pipeline that transports crude oil from northern Alberta
to crude oil markets. EnCanas net production in 2003 from
this area averaged 15,944 barrels per day of crude oil
(13,739 barrels per day in 2002) from interests in
460 gross oil wells (453 net wells) that were
producing at December 31, 2003.

Cutbank
Ridge

In September 2003, EnCana completed the
acquisition of approximately 500,000 net acres of prospective
natural gas development lands in the Canadian Rocky Mountain
foothills. The lands in this new resource play 
called Cutbank Ridge  are located approximately
50 kilometres southwest of Dawson Creek, British Columbia.
In September 2003, EnCana purchased a majority interest in
39 parcels of land totalling roughly 350,000 net acres for
approximately $270 million (C$369 million). The
Corporation had previously acquired about 150,000 net acres
through purchases and land swaps with other companies and Crown
land sales, resulting in the total landholding of approximately
500,000 net acres in the area. In 2003, EnCana drilled
19 net natural gas wells at Cutbank Ridge which produced
approximately 14 million cubic feet per day of natural gas
in December 2003. In 2004, EnCana plans to drill approximately
40 net natural gas wells at Cutbank Ridge.

East
Coast of Canada

Offshore Nova Scotia on the East Coast of Canada,
EnCana has a 100 percent working interest in the Deep
Panuke natural gas discovery approximately 250 kilometres
off the coast of Nova Scotia in approximately 40 metres of
water. Infrastructure in this relatively under-explored basin
will require expansion,

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the cost of which must be borne at least partly
by the Deep Panuke project. In February 2003, EnCana requested
an adjournment of the regulatory approval process in order to
pursue further steps to improve the projects economics. In
December 2003, following the drilling of two successful
exploration wells, Margaree (100 percent operated interest)
and MarCoh (24.5 percent operated interest), EnCana
initiated work on a new plan for a potential offshore
development at Deep Panuke.


In 2002, the Corporation participated in the
drilling of the Annapolis well offshore Nova Scotia, which
encountered approximately 30 metres of net natural gas pay
over several zones. Further plans to assess the potential of
this discovery are under development. EnCana has a
26 percent non-operated interest in the discovery.

At December 31, 2003, EnCana held an
interest in approximately 4.4 million gross acres
(approximately 3.0 million net acres) of exploration lands
offshore Nova Scotia. The Corporation also held an interest in
approximately 4.3 million gross acres (approximately
2.8 million net acres) of exploration lands located
offshore Newfoundland and Labrador at December 31, 2003.
EnCana operates 19 of its 25 exploration licenses in these
areas and has an average working interest of approximately
66 percent.

Northwest
Territories

EnCana has an approximate 37 percent
interest in two exploration blocks comprising approximately
529,000 gross acres (approximately 198,000 net acres) in the
Mackenzie Delta region of Canadas Northwest Territories.
The Corporation is planning to drill one exploration well in the
first half of 2004.

The Corporation has an approximate
60 percent working interest in two exploration blocks
comprising approximately 388,000 gross acres (approximately
233,000 net acres) in the Norman Wells area of the Northwest
Territories. EnCana is planning to drill one exploration well in
the first half of 2004.

United States

(U.S.MAP)

EnCanas operations in the U.S. Rockies
area are currently focused on exploiting deep, tight, long-life
natural gas formations primarily in the Jonah sweet natural gas
field located in the Green River Basin of southwest Wyoming and
the Mamm Creek natural gas field located in the Piceance Basin
of northwest Colorado. EnCanas U.S. operations also
include interests in north Texas, the Gulf of Mexico and Alaska,
as well as various natural gas gathering and processing assets.

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EnCanas 2004 capital investment in core
programs for natural gas projects in the U.S. is budgeted
at approximately $820 million, with approximately
$90 million directed to exploration and approximately
$730 million to development, and includes the drilling of
approximately 535 gross natural gas wells (500 net
wells). Capital investment for crude oil projects is budgeted to
be approximately $100 million, primarily directed to
exploration projects.

Jonah

At Jonah in southwest Wyoming, EnCana held an
average 75 percent interest in the petroleum and natural
gas rights to approximately 77,000 gross acres
(approximately 58,000 net acres, of which approximately
48,000 net acres are undeveloped) and had interests in
327 gross natural gas wells (287 net wells) that were
producing at December 31, 2003. EnCanas net
production in 2003 averaged 374 million cubic feet per day
of natural gas and 3,348 barrels per day of NGLs
(275 million cubic feet per day of natural gas and
2,788 barrels per day of NGLs in 2002).

Mamm
Creek

At Mamm Creek in northwest Colorado, EnCana held
an average 96 percent interest in the petroleum and natural
gas rights to approximately 176,000 gross acres (approximately
168,000 net acres, of which approximately 113,000 net acres are
undeveloped) and had interests in 601 gross natural gas
wells (591 net wells) that were producing at
December 31, 2003. EnCanas net production in 2003
averaged 125 million cubic feet per day of natural gas and
1,013 barrels per day of NGLs (56 million cubic feet
per day of natural gas and 389 barrels per day of NGLs
in 2002).

In October 2003, EnCana Oil & Gas (USA)
Inc. acquired natural gas and associated NGLs production,
reserves and acreage from Mesa for net cash consideration of
approximately $100 million. The principal producing
properties acquired from Mesa are in the Piceance Basin of
northwest Colorado.

North
Texas

In north Texas, EnCana held an average
77 percent interest in the petroleum and natural gas rights
to approximately 95,000 gross acres (approximately
73,000 net acres, of which approximately 59,000 net
acres are undeveloped) and had interests in 163 gross
natural gas wells (159 net wells) that were producing at
December 31, 2003. EnCanas net production in 2003
averaged seven million cubic feet per day of natural gas and
218 barrels per day of NGLs.

In July 2003, EnCana Oil & Gas (USA)
Inc. acquired the common shares of Savannah for net cash
consideration of approximately $91 million. This
acquisition included interests in developed and undeveloped
reserves, natural gas and associated NGLs production, and
acreage located in north Texas.

Gulf
of Mexico

EnCana owns a 25 percent non-operated
interest in the Tahiti crude oil discovery, located in the deep
water Green Canyon Block 640. Four appraisal wells were
drilled in the first half of 2003 to evaluate
this discovery.

In October 2003, a subsidiary of EnCana exchanged
its 22.5 percent non-operated interest in the Llano crude
oil discovery in the Gulf of Mexico for additional interests in
the Scott and Telford fields in the U.K. central North Sea,
which were received by another subsidiary of EnCana. Also in
October 2003, a deepwater discovery in the Gulf of Mexico at
Sturgis was announced in which EnCana holds a 25 percent
non-operated interest.

EnCana has working interest acreage in over
262 exploration blocks comprising approximately
1.5 million gross acres (approximately 663,000 net acres)
in the Gulf of Mexico, with options to add approximately
15 additional blocks. Such options were acquired through
large regional farm-ins and the Corporations ongoing land
acquisition program.

15



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Alaska

EnCana has working interests in approximately
1.8 million gross acres (approximately 802,000 net acres)
of exploration lands in both offshore and onshore Alaska.

Other

EnCana owns and operates various gas gathering
and NGLs processing facilities in Colorado. Near Fort Lupton,
Colorado, the gathering facilities include field compression and
over 1,000 kilometres of pipelines, and the processing
plant has a capacity of approximately 90 million cubic feet
per day. Near Rifle, Colorado, EnCanas gathering
facilities have a capacity of approximately 240 million
cubic feet per day and include over 645 kilometres of
pipelines. Near Rangely, Colorado, the Corporations
gathering facilities include field compression and over
1,600 kilometres of pipelines. The processing plant has a
capacity of approximately 60 million cubic feet
per day.

Ecuador

(ECUADOR MAP)

In Ecuador, EnCana is the largest private sector
crude oil producer. An indirect, wholly owned subsidiary of
EnCana owns one concession in the Oriente Basin, known as the
Tarapoa Block. The Corporation has a 100 percent working
interest in this concession, which is operated under a
participation contract permitting the subsidiary to explore for
and produce crude oil at its sole risk and expense during the
contract term. The participation contract for the Tarapoa Block
has a primary term through to August 1, 2015.

EnCanas 2004 capital investment in core
programs for crude oil projects in Ecuador is budgeted to be
approximately $180 million, directed primarily to
development projects, and includes the drilling of approximately
45 gross crude oil wells (25 net wells).

In the fourth quarter of 2000, EnCana farmed-in
to a 40 percent non-operated interest in Block 15 in
the Oriente Basin. The concession is operated under a
participation contract which has primary terms through to July
2012 for base area production and July 2019 for production
resulting from additional exploration.

In January 2003, EnCana acquired majority
operating interest in Blocks 14, 17 and Shiripuno, in the
Oriente Basin, from Vintage for net cash consideration of
approximately $116 million. The acquisition included both
developed and undeveloped reserves producing approximately
4,000 barrels of crude oil per day from Blocks 14 and
17. The production contracts for Blocks 14 and 17 expire in
July, 2012 and December, 2018, respectively.

16



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At December 31, 2003, EnCana held an average
64 percent interest in the petroleum rights to
approximately 1.4 million gross acres (approximately
891,000 net acres, of which approximately 811,000 net acres are
undeveloped) in Ecuador. At December 31, 2003,
172 gross crude oil wells (127 net wells) were
producing. EnCanas net crude oil production in 2003 was
51,089 barrels per day (36,521 barrels per day
in 2002).

With the commissioning of the OCP pipeline
completed in November 2003, the Corporation expects 2004 net
production from Ecuador to range between 68,000 and
74,000 barrels per day of crude oil.

OCP
Pipeline

EnCana is part of a consortium that completed
construction of the OCP pipeline in August 2003. The pipeline
was fully commissioned in November 2003. OCP is a 500-kilometre
pipeline with a capacity of approximately 450,000 barrels per
day that runs from the crude oil producing area of Ecuador to
the Pacific Coast. Pursuant to the terms of the agreement with
the Government of Ecuador, the OCP pipeline will be transferred
to the Government of Ecuador, without cost, after a 20-year
operating period. EnCana has an indirect 36.3 percent
equity interest in OCP, and a 15-year shipping commitment of
approximately 108,000 barrels per day.

United Kingdom

(U.K.MAP)

EnCana has a working interest in the Scott and
Telford crude oil fields located in the U.K. central North Sea,
190 kilometres northeast of Aberdeen, Scotland.
EnCanas working interest is 41.0 percent at Scott and
54.3 percent at Telford. In October 2003, EnCana assumed
operatorship of the Scott and Telford fields.

Crude oil produced from both fields is processed
at the production platform and transported via pipeline through
the non-operated Forties pipeline system. The Corporation
acquired its initial interests in these fields
(13.5 percent in Scott and 20.2 percent in Telford) in
January 2000. In October 2003, EnCana increased its ownership by
14 percent in both the Scott and Telford fields through an
exchange involving a subsidiarys interest in the Llano
crude oil discovery in the Gulf of Mexico. In early 2004, EnCana
further increased its ownership through the purchase of
additional 13.5 percent and 20.2 percent interests in
the Scott and Telford fields, respectively.

EnCanas 2004 capital investment in the U.K.
is budgeted to be approximately $360 million, directed
primarily to development projects, and includes the drilling of
approximately 15 gross crude oil wells
(7 net wells).

At December 31, 2003, there were
24 gross crude oil wells (7 net wells) producing.
EnCanas net sales of crude oil and NGLs averaged
10,128 barrels per day in 2003 (10,528 barrels per day
in 2002). In 2003, average net natural gas sales were
approximately 13 million cubic feet per day (approximately
10 million cubic feet per day in 2002).

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Development work on the Buzzard discovery in the
central North Sea is continuing with initial production
anticipated in late 2006. In November 2003, the U.K. Department
of Trade and Industry approved the development plan for Buzzard.
EnCana is the operator and holds an approximate
43.2 percent interest in the Buzzard field.

At December 31, 2003, EnCana had interests
in 63 exploration blocks in the U.K. central North Sea and
held a total land position of approximately 1.9 million
gross acres (approximately 756,000 net acres, of which
approximately 744,000 net acres are undeveloped). Interests
range from 8.2 percent to 100 percent. Included in
these interests are interests in eight deepwater frontier blocks
in the Atlantic Margin west of Great Britain, comprising
approximately 241,000 gross acres (approximately
45,000 net acres).

International New Ventures
Exploration

Central and West Africa

EnCana has established onshore exploration
operations in Chad, based out of the Corporations office
in NDjamena. EnCana has a 50 percent working interest
in Permit H comprising approximately 108.5 million
gross acres (approximately 54.3 million net acres). EnCana
completed the drilling of one exploratory well in February 2004,
and activity over the remainder of the year is expected to
include seismic surveys and the drilling of an additional two to
three exploratory wells.

In 2003, EnCana participated in the drilling of
one well in the Gulf of Guinea, offshore Ghana. EnCana has a
40 percent working interest in the Keta Block, comprising
approximately 3.7 million gross acres (approximately
1.5 million net acres).

Brazil

EnCana has a 67 percent working interest in
Block BM-C-7 comprising approximately 161,000 gross acres
(approximately 108,000 net acres) offshore Brazil in the Campos
Basin. In 2004, the Corporation plans to drill one exploration
well on this block.

Middle East

During 2003, EnCana completed the testing of an
exploration well on Block 2 in the State of Qatar.
EnCanas share of Block 2 increased to
100 percent during the year. This block encompasses most of
the onshore lands in Qatar and covers approximately
2.8 million acres. The Corporation is currently evaluating
entry into the second exploration phase on Block 2.

In 2003, EnCana drilled one well on its acreage
on Block 47 in the Republic of Yemen. The Corporation has a
53 percent working interest in Block 47 (approximately
1.9 million gross acres and approximately 987,000 net
acres). EnCana and its partners relinquished the permit for
Block 60 in December 2003.

In 2003, the Corporation initiated exploration
activities in the Sultanate of Oman. EnCana has a
100 percent working interest in onshore Blocks 3 and
4, which cover approximately 9.6 million acres. During
2004, EnCana plans to conduct seismic surveys and drill
one well.

EnCana has a 50 percent working interest in
Block 5 in the Kingdom of Bahrain. Block 5 is
comprised of approximately 97,000 gross acres (approximately
48,000 net acres).

Australia

In the fourth quarter of 2003, EnCana sold,
subject to regulatory and other approvals, its 25 percent
working interest in the John Brookes gas development on the
North-West shelf (Blocks WA-214 and WA-205). EnCana has
interests remaining in approximately 18.4 million gross
acres (approximately 6.5 million net acres) in Australia.

Other

EnCana has also drilled a number of wells in
various other countries over the past two years; however, no
economic quantities of natural gas or crude oil were found.

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MIDSTREAM & MARKETING



Midstream


EnCanas midstream activities are primarily
comprised of natural gas storage operations, NGLs processing and
power generation operations. In addition, EnCana has minor
interests in transportation assets. EnCanas 2004 capital
investment in core programs in its midstream operations is
budgeted to be approximately $78 million.

Natural
Gas Storage

Based upon overall storage capacity, EnCana is
the largest independent (non-utility) natural gas storage
operator in North America with facilities in Alberta, California
and Oklahoma. EnCana also leases natural gas storage capacity
from other storage operators located in the U.S. Gulf Coast
and mid-continent regions. At December 31, 2003, EnCana had
owned and operated storage capacity of approximately
134 billion cubic feet, as well as leased storage capacity
of approximately 20 billion cubic feet. The Corporation
expects this capacity to increase in 2004 and 2005 upon
completion of the expansion of its Wild Goose Gas Storage
Facility in northern California, completion of the new Countess
Gas Storage Facility in southeast Alberta, and with development
of the Starks project in southwest Louisiana.

EnCana provides a portion of its storage capacity
under multi-year firm contracts to industry participants on a
fee-for-service basis as well as offering short-term firm or
interruptible storage services at market based rates. The
remaining capacity is used as part of the natural gas storage
optimization program (through the purchase and sale of third
party gas) and is available to manage EnCanas produced gas
sales.

AECO
HUB

EnCana operates and markets its Alberta natural
gas storage facilities under the commercial name AECO HUB.
These facilities, all of which are 100 percent owned by
EnCana, include the Suffield Gas Storage Facility, the Hythe Gas
Storage Facility and the new Countess Gas Storage Facility. The
AECO HUB is Canadas largest natural gas storage and
trading hub.

Suffield
Gas Storage Facility

Located on the Suffield Block, this facility was
the first and is the most significant in the AECO HUB
portfolio. It has undergone several expansions since start-up
and now has storage capacity of approximately 85 billion
cubic feet, a maximum withdrawal capability of approximately
1.8 billion cubic feet per day and a maximum injection
capability of approximately 1.6 billion cubic feet
per day.

Hythe
Gas Storage Facility

In 1999, EnCana expanded its commercial natural
gas storage capacity in Alberta through the conversion of a
depleted reservoir at Hythe in northwest Alberta. This facility
added approximately 10 billion cubic feet of working
natural gas capacity, approximately 200 million cubic feet
per day of withdrawal capability, and approximately
100 million cubic feet per day of injection capability. The
Hythe Gas Storage Facility is connected to both the Alberta
pipeline system of TransCanada Corporation and the Alliance
Pipeline system. Commencing April 1, 2004, the compression
and pipeline facilities related to the Hythe Gas Storage
Facility are expected to be utilized by the Upstream division to
facilitate incremental production from Cutbank Ridge.
Consequently, this facility will not be available for use in
providing storage services for a minimum term of one year.

Countess
Gas Storage Facility

In October 2002, EnCana announced plans to
develop a new natural gas storage facility in southeast Alberta
that is expected to store up to 40 billion cubic feet of
natural gas. The Countess Gas Storage Facility, designed for
peak injections of 950 million cubic feet per day and peak
withdrawals of 1.25 billion cubic feet per day, uses two
depleted underground reservoirs located about 85 kilometres
east of Calgary. The first

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10 billion cubic feet of new storage
capacity came online in October 2003. As of December 31,
2003, facilities construction was essentially complete, and
storage capacity at Countess in 2004 is expected to be
approximately 30 billion cubic feet. The full
40 billion cubic feet of storage capacity is expected to be
utilized in 2005 after further analysis of initial reservoir
performance.


Wild
Goose Gas Storage Facility

In April 1999, Wild Goose Storage Inc.
(Wild Goose), an indirect wholly owned subsidiary of
EnCana, commenced commercial operation of a 14 billion
cubic feet storage facility located north of Sacramento, in
northern California. The Wild Goose Gas Storage Facility was
Californias first independent natural gas storage facility
and currently has withdrawal capability of approximately
200 million cubic feet per day and injection capability of
approximately 80 million cubic feet per day. In July 2002,
Wild Goose was granted permission by the California Public
Utilities Commission to approximately double the storage size
and approximately triple the withdrawal capacity of the
facility. Completion of the initial phase expansion is expected
in April 2004, bringing the total working gas capacity to
approximately 24 billion cubic feet. This expansion is also
expected to increase withdrawal capability to approximately
480 million cubic feet per day and expand injection
capability to approximately 450 million cubic feet
per day.

Salt
Plains Gas Storage Facility

In February 2001, Salt Plains Storage Inc., an
indirect wholly owned subsidiary of EnCana, acquired
substantially all of the assets of a 15 billion cubic feet
storage facility located in northern Oklahoma. The Salt Plains
Gas Storage Facility has a maximum withdrawal capability of
approximately 200 million cubic feet per day and a maximum
injection capability of approximately 100 million cubic
feet per day.

Starks
Project

In October 2003, EnCana Gas Storage Inc., an
indirect wholly owned subsidiary of EnCana, announced plans to
develop a high-deliverability storage facility in southwest
Louisiana. Subject to regulatory approvals, the facility is
expected to be in-service during the third quarter of 2005 with
approximately 8.65 billion cubic feet of working natural
gas capacity, 375 million cubic feet of injection capacity
and 400 million cubic feet of withdrawal capacity.

Leased
Storage Capacity

EnCana Gas Storage Inc. has entered into
contracts to lease storage capacity in the U.S. Gulf Coast
and mid-continent regions. Total leased capacity at
December 31, 2003 was approximately 20 billion cubic
feet, with remaining contract terms ranging from three months to
13 years and an average remaining term of approximately
five years.

Natural
Gas Liquids

EnCanas NGLs midstream facilities and
associated marketing resources are among the largest in Canada.
The Corporation holds interests in four NGLs extraction plants
that straddle two major natural gas pipelines at Empress,
Alberta plus storage and fractionation assets in Saskatchewan,
eastern Canada and the U.S.

At Empress, the rights to extract NGLs from
natural gas transported through transmission pipelines are
acquired from the shippers of the natural gas. In October 2003,
the Corporations Empress NGLs extraction plant completed
an expansion that is expected to provide incremental ethane
production of up to 17,000 barrels per day. As at
December 31, 2003, EnCanas share of the combined
processing capacity was approximately two billion cubic feet
per day.

Ethane recovered at Empress is sold as a
specification product to petrochemical companies for consumption
within the Province of Alberta. The remaining liquids components
are transported as a mixed stream by pipeline to a plant at
Sarnia, Ontario in which EnCana holds an approximate
10.4 percent interest.

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The mixed stream is fractionated at Sarnia into
marketable products: propane, butane and pentanes plus. These
are sold by Kinetic to distributors, refiners and petrochemical
manufacturers in Canada and the U.S. under contracts, the
terms of which are typically one year or less.


Other significant NGLs midstream assets include:
(i) a one-third interest in a pipeline which delivers
ethane from extraction plants located in Alberta at Waterton,
Empress (four plants), Cochrane and Edmonton to ethylene plants
at Joffre and Fort Saskatchewan and storage caverns at Fort
Saskatchewan; (ii) a 50 percent interest in a pipeline
that delivers NGLs from Empress to storage facilities and the
Enbridge pipeline at Kerrobert, Saskatchewan;
(iii) interests in a NGLs storage facility and depropanizer
at Superior, Wisconsin; and (iv) a 49 percent interest
in a propane and butane storage facility at Marysville, Michigan.

Power
Generation

EnCana has interests in two 106-megawatt power
plants in southern Alberta, which supply electricity to the
Power Pool of Alberta. The Cavalier Power Station began selling
electricity to the Alberta Power Pool in late August 2001. The
plant, located approximately 54 kilometres east of Calgary,
is 100 percent owned and operated by EnCana. The Balzac
Power Station, in which EnCana holds a 50 percent
non-operated interest, is also located near Calgary and was
brought into service in December 2001. The Corporation also has
a 25 percent non-operated interest in a cogeneration
facility in Kingston, Ontario. EnCanas power generation
capacity, excluding power generated at the Foster Creek SAGD
operation, is approximately 186 megawatts. In 2003, the
Corporation generated 598,000 megawatt hours of EnCana owned
electricity from the Cavalier, Balzac and Kingston plants
(603,000 megawatt hours in 2002).

Transportation

In February 2001, EnCana purchased a
36 percent equity interest in the Trasandino Pipeline
system for approximately $64 million. The Trasandino system
carries crude oil from Argentinas Neuquen Basin to
refineries in Chile. The pipeline is 420 kilometres in
length and has a design capacity of approximately 113,000
barrels per day. Shipments on the Trasandino system in 2003
averaged approximately 104,000 barrels per day (approximately
112,000 barrels per day in 2002).

Marketing

Natural
Gas Marketing

In 2003, approximately 87 percent of
EnCanas produced natural gas sales were directly marketed
by EnCana to local distribution companies, industrials and
energy marketing companies. The remaining 13 percent of
produced natural gas sales were marketed to aggregators who
supply natural gas to markets throughout North America. Prices
received by EnCana are based primarily upon prevailing index
prices for natural gas. Prices are impacted by competing fuels
in such markets and by regional supply and demand for
natural gas.

To mitigate the market risk associated with
forecasted cash flows, EnCana entered into various risk
management contracts relating to produced natural gas in 2003.
The Corporation entered into fixed price AECO and NYMEX swaps
and AECO and NYMEX collars as a means of protecting corporate
cash flow to ensure sufficient funds for capital programs. To
protect against weakening production area prices, EnCana entered
into AECO and Rockies basis transactions. Details of these
transactions are found in Note 17 to EnCanas audited
consolidated financial statements for the year ended
December 31, 2003.

In 2003, EnCana sold approximately
47 percent of its produced natural gas at fixed prices,
approximately 9 percent at AECO Index based pricing,
approximately 39 percent at NYMEX based pricing and
approximately 5 percent at other prices. As of
December 31, 2003, for 2004 EnCana has arranged for the
sale of approximately 45 percent of its natural gas at
fixed prices, approximately 9 percent exposed to AECO Index
based prices, approximately 42 percent exposed to NYMEX
based prices and approximately 4 percent at other
prices.

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In addition to sales of its proprietary
production, EnCana purchases and sells natural gas for the
purpose of optimizing the profitability of its midstream assets
and the netback price to the Corporation. In 2003, EnCanas
sales of purchased natural gas amounted to approximately
903 million cubic feet per day (approximately
962 million cubic feet per day in 2002).

Crude
Oil Marketing

EnCana sells and manages the transportation of
its western Canadian crude oil to markets in Canada and the
U.S. (138,784 barrels per day in 2003 and 116,634 barrels
per day in 2002). Crude oil sales are normally executed under
spot and monthly evergreen contracts with delivery to major
pipeline hubs, such as Edmonton, Hardisty or Cromer, in Alberta,
with EnCana arranging the intermediate transportation on the
feeder pipeline systems. Sales are also made on a delivered
basis using trunk pipeline systems, such as Express, for sales
to refinery destinations.

EnCana provides North American marketing services
to certain organizations on a fee for service basis. In 2003,
EnCana acted as exclusive agent for COS and marketed COS
Syncrude volumes of 64,863 barrels per day
(24,555 barrels per day in 2002). The COS marketing
agreement terminates in the second quarter of 2006. EnCana also
provides marketing services to the Alberta Governments
Department of Energy (69,264 barrels per day in 2003 and
48,133 barrels per day in 2002). This agency agreement ends
in the second quarter of 2007.

In Ecuador, EnCanas crude oil volumes are
sold FOB at the marine loading facility at Balao, Esmeraldas
Province, Ecuador. A total of 45,561 barrels per day was
marketed in 2003 (37,253 barrels per day in 2002). Until
September 2003, Ecuador production was transported from the
Ecuador Oriente region to Balao via the SOTE Pipeline. EnCana
began shipping on the OCP Pipeline in September 2003, and the
pipeline was fully commissioned in November 2003. EnCanas
production in Ecuador consists of a high viscosity crude oil
with characteristics well-suited to refineries on the
U.S. West and Gulf Coasts.

In the U.K., EnCana marketed 8,439 barrels
per day of crude oil in 2003 (10,543 barrels per day
in 2002).

To mitigate the market risk associated with
forecasted cash flows, EnCana enters into various risk
management contracts relating to crude oil. As of
December 31, 2003, for 2004, EnCana had approximately
62,500 barrels per day in costless collars with a price
floor averaging $20.00 per barrel and a price cap of $25.69 per
barrel. Also for 2004, there are approximately
62,500 barrels per day in fixed price swaps with an average
price of $23.13 per barrel. For 2005, EnCana has approximately
10,000 barrels per day in costless three-way put spreads.
The three-way put spreads provide a price floor averaging $25.00
per barrel when the WTI price is above $20.00 or the WTI price
plus $5.00 if the WTI price is below $20.00. The price cap set
by the three-way put spreads is $28.775 per barrel.

NGLs
Marketing

In 2003, Kinetic continued to market a portion of
EnCanas western Canada NGLs primarily to eastern Canada
and the U.S. Kinetic also markets NGLs on behalf of
other parties.

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In the following section
(pages 23-40), unless otherwise indicated, the information
for EnCana for periods prior to April 5, 2002 (the date of
the Merger) represents information for PanCanadian and does not
combine the results of PanCanadian and AEC. Accordingly, the
amounts shown exclude the results of AEC prior to April 5,
2002, and the amounts for 2001 and the first quarter of 2002
represent solely the results of PanCanadian.

RESERVES AND OTHER OIL AND GAS
INFORMATION

EnCana retained independent qualified reserves
evaluators to evaluate and prepare reports on 100 percent
of EnCanas crude oil and natural gas reserves as of
December 31, 2003. EnCanas Canadian reserves were
evaluated by McDaniel & Associates Consultants Ltd., Gilbert
Laustsen Jung Associates Ltd. and Ryder Scott Company,
EnCanas continental U.S. reserves were evaluated by
Netherland, Sewell & Associates, Inc., EnCanas
Ecuadorian reserves were evaluated by Ryder Scott Company and
EnCanas U.K. reserves were evaluated by DeGolyer and
MacNaughton. The previous year, 2002, was the first year for
which all of EnCanas reserves were independently evaluated.

EnCana has a reserves committee of independent
board members which reviews the qualifications and appointment
of the independent qualified reserves evaluators. The committee
also reviews the procedures for providing information to the
evaluators. All booked reserves are based upon annual
evaluations by the independent qualified reserves evaluators.
The evaluations are conducted from the fundamental geological
and engineering data.

Any references to NGLs in this section include
condensate.

Reserve Quantities Information

EnCanas reserves increased in 2003
primarily from exploration and development drilling, and to a
lesser extent from acquisitions and upward revisions. Reserve
acquisitions were approximately equal to reserve dispositions in
2003. The Corporations reserves increased in 2002
predominantly from the Merger with AEC, and also partly due to
extensions and discoveries. The 2002 increase was partially
offset by downward revisions of reserve quantities. In 2001, the
increase in reserves due to extensions and discoveries was
offset by sales during the year.

The following table sets forth reserves
continuity information prepared by EnCana in accordance with
U.S. disclosure standards, including FAS 69. The end
of year numbers for 2003 represent estimates derived from the
reports of the independent qualified reserves evaluators
referred to above. The end of year numbers for 2002 represent
estimates derived from the reports of the independent petroleum
engineering consultants who evaluated EnCanas reserves as
of December 31, 2002. The beginning and end of year numbers
for 2001 represent internal estimates of PanCanadian at
the time.

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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
|                                  |  |                          |        |                                   |  |         |       |       |  |       |    |        |  |        |     |         |  |         |       |       |  |      
|2001                              |  |                          |        |                                   |  |         |       |       |  |       |    |        |  |        |     |         |  |         |       |       |  |       |       |   |  |  |      |   |  |  |       |   |  |  |       |   |  |  |      |   |  |  |       |  
|Beginning of year                 |  |                          | 3,350  |                                   |  |         | 208   |       |  |       | 10 |        |  |        |    |         |  |         | 3,568 |       |  |       | 348.0 |   |  |  | 16.7 |   |  |  |      |   |  |  | 23.7  |   |  |  | 5.0  |   |  |  | 393.4 |  
|Revisions and improved recovery   |  |                          | 59     |                                   |  |         | 6     |       |  |       |   |        |  |        |    |         |  |         | 65    |       |  |       | 5.0   |   |  |  | 1.6  |   |  |  |      |   |  |  | 2.1   |   |  |  |     |   |  |  | 8.7   |  
|Extensions and discoveries        |  |                          | 448    |                                   |  |         | 13    |       |  |       |   |        |  |        |    |         |  |         | 461   |       |  |       | 15.0  |   |  |  | 2.0  |   |  |  |      |   |  |  |      |   |  |  |     |   |  |  | 17.0  |  
|Purchase of reserves in place     |  |                          | 1      |                                   |  |         | 25    |       |  |       |   |        |  |        |    |         |  |         | 26    |       |  |       |      |   |  |  |     |   |  |  |      |   |  |  |      |   |  |  |     |   |  |  |      |  
|Sale of reserves in place         |  |                          | (1     | )                                 |  |         |      |       |  |       |   |        |  |        |    |         |  |         | (1    | )     |  |       | (48.0 | ) |  |  |     |   |  |  |      |   |  |  |      |   |  |  | (5.0 | ) |  |  | (53.0 | )
|Production                        |  |                          | (353   | )                                 |  |         | (16   | )     |  |       | (3 | )      |  |        |    |         |  |         | (372  | )     |  |       | (33.4 | ) |  |  | (0.7 | ) |  |  |      |   |  |  | (4.2  | ) |  |  |     |   |  |  | (38.3 | )
|                                  |  |                          |        |                                   |  |         |       |       |  |       |    |        |  |        |     |         |  |         |       |       |  |       |       |   |  |  |      |   |  |  |       |   |  |  |       |   |  |  |      |   |  |  |       |  
|End of Year                       |  |                          | 3,504  |                                   |  |         | 236   |       |  |       | 7  |        |  |        |    |         |  |         | 3,747 |       |  |       | 286.6 |   |  |  | 19.6 |   |  |  |      |   |  |  | 21.6  |   |  |  |     |   |  |  | 327.8 |  
|                                  |  |                          |        |                                   |  |         |       |       |  |       |    |        |  |        |     |         |  |         |       |       |  |       |       |   |  |  |      |   |  |  |       |   |  |  |       |   |  |  |      |   |  |  |       |  
|Developed                         |  |                          | 2,908  |                                   |  |         | 172   |       |  |       | 7  |        |  |        |    |         |  |         | 3,087 |       |  |       | 245.3 |   |  |  | 14.9 |   |  |  |      |   |  |  | 21.6  |   |  |  |     |   |  |  | 281.8 |  
|Undeveloped                       |  |                          | 596    |                                   |  |         | 64    |       |  |       |   |        |  |        |    |         |  |         | 660   |       |  |       | 41.3  |   |  |  | 4.7  |   |  |  |      |   |  |  |      |   |  |  |     |   |  |  | 46.0  |  
|                                  |  |                          |        |                                   |  |         |       |       |  |       |    |        |  |        |     |         |  |         |       |       |  |       |       |   |  |  |      |   |  |  |       |   |  |  |       |   |  |  |      |   |  |  |       |  
|Total                             |  |                          | 3,504  |                                   |  |         | 236   |       |  |       | 7  |        |  |        |    |         |  |         | 3,747 |       |  |       | 286.6 |   |  |  | 19.6 |   |  |  |      |   |  |  | 21.6  |   |  |  |     |   |  |  | 327.8 |  
|                                  |  |                          |        |                                   |  |         |       |       |  |       |    |        |  |        |     |         |  |         |       |       |  |       |       |   |  |  |      |   |  |  |       |   |  |  |       |   |  |  |      |   |  |  |       |  
|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 |  
|                                  |  |                          |        |                                   |  |         |       |       |  |       |    |        |  |        |     |         |  |         |       |       |  |       |       |   |  |  |      |   |  |  |       |   |  |  |       |   |  |  |      |   |  |  |       |  




Notes:



|    |             
|--- | ------------
|(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.

24



---



##### 



Other Disclosures About Oil and Gas
Activities

The tables in this section set forth oil and gas
information prepared by EnCana in accordance with
U.S. disclosure standards, including FAS 69.

Standardized
Measure of Discounted Future Net Cash Flows and Changes
Therein

In calculating the standardized measure of
discounted future net cash flows, year end constant prices and
cost assumptions were applied to EnCanas annual future
production from proved reserves to determine cash inflows.
Future production and development costs are based on constant
price assumptions and assume the continuation of existing
economic, operating and regulatory conditions. Future income
taxes are calculated by applying statutory income tax rates to
future pre-tax cash flows after provision for the tax cost of
the oil and natural gas properties based upon existing laws and
regulations. The discount was computed by application of a
10 percent discount factor to the future net cash flows.
The calculation of the standardized measure of discounted future
net cash flows is based upon the discounted future net cash
flows prepared by EnCanas independent qualified reserves
evaluators in relation to the reserves they respectively
evaluated, and adjusted by EnCana to account for
managements estimates of risk management activities, asset
retirement obligations and future income taxes.

EnCana cautions that the discounted future net
cash flows relating to proved oil and gas reserves are an
indication of neither the fair market value of EnCanas oil
and gas properties, nor of the future net cash flows expected to
be generated from such properties. The discounted future net
cash flows do not include the fair market value of exploratory
properties and probable or possible oil and gas reserves, nor is
consideration given to the effect of anticipated future changes
in crude oil and natural gas prices, development, asset
retirement and production costs and possible changes to tax and
royalty regulations. The prescribed discount rate of
10 percent may not appropriately reflect future interest
rates. The computation also excludes values attributable to
EnCanas Syncrude interest (disposed of in 2003) and
Midstream & Marketing interest.

Standardized Measure of Discounted Future Net
Cash Flows

Relating to Proved Oil and
Gas Reserves


|                                                     |  |              |        |               |  |         |        |      |  |      |        |      |  |      |        |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 
|---------------------------------------------------- |  | ------------ | ------ | ------------- |  | ------- | ------ | ---- |  | ---- | ------ | ---- |  | ---- | ------ | ---- |  | ---- | ----- |  |  |  | --- |  |  |  | ----- |  |  |  | ----- |  |  |  | - | 
|                                                     |  |              |        |               |  |        
|                                                     |  | Canada       |        | United States |  | Ecuador
|                                                     |  |              |        |               |  |        
|                                                     |  | 2003         |        | 2002          |  | 2001    |        | 2003 |  | 2002 |        | 2001 |  | 2003 |        | 2002 |  | 2001
|                                                     |  |              |        |               |  |         |        |      |  |      |        |      |  |      |        |      |  |     
|                                                     |  |             
|                                                     |  | ($ millions)
|Future cash inflows                                  |  |              | 35,126 |               |  |         | 29,890 |      |  |      | 10,768 |      |  |      | 17,472 |      |  |      | 9,398 |  |  |  | 845 |  |  |  | 3,533 |  |  |  | 3,368 |  |  |  |  | 
|Future production and development costs              |  |              | 14,018 |               |  |         | 8,686  |      |  |      | 3,070  |      |  |      | 2,889  |      |  |      | 3,360 |  |  |  | 285 |  |  |  | 987   |  |  |  | 908   |  |  |  |  | 
|                                                     |  |              |        |               |  |         |        |      |  |      |        |      |  |      |        |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 
|Undiscounted pre-tax cash flows                      |  |              | 21,108 |               |  |         | 21,204 |      |  |      | 7,698  |      |  |      | 14,583 |      |  |      | 6,038 |  |  |  | 560 |  |  |  | 2,546 |  |  |  | 2,460 |  |  |  |  | 
|Future income taxes                                  |  |              | 5,874  |               |  |         | 6,353  |      |  |      | 2,604  |      |  |      | 4,960  |      |  |      | 1,504 |  |  |  | 24  |  |  |  | 536   |  |  |  | 585   |  |  |  |  | 
|                                                     |  |              |        |               |  |         |        |      |  |      |        |      |  |      |        |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 
|Future net cash flows                                |  |              | 15,234 |               |  |         | 14,851 |      |  |      | 5,094  |      |  |      | 9,623  |      |  |      | 4,534 |  |  |  | 536 |  |  |  | 2,010 |  |  |  | 1,875 |  |  |  |  | 
|Less discount of net cash flows using a
    10% rate |  |              | 5,219  |               |  |         | 6,018  |      |  |      | 2,034  |      |  |      | 4,735  |      |  |      | 2,383 |  |  |  | 236 |  |  |  | 643   |  |  |  | 617   |  |  |  |  | 
|                                                     |  |              |        |               |  |         |        |      |  |      |        |      |  |      |        |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 
|Discounted future net cash flows                     |  |              | 10,015 |               |  |         | 8,833  |      |  |      | 3,060  |      |  |      | 4,888  |      |  |      | 2,151 |  |  |  | 300 |  |  |  | 1,367 |  |  |  | 1,258 |  |  |  |  | 
|                                                     |  |              |        |               |  |         |        |      |  |      |        |      |  |      |        |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 

|                                                     |  |                |       |       |  |       |       |      |  |      |     |      |  |      |   |      |  |      |   |  |  |  |   |  |  |  |        |  |  |  |        |  |  |  |        | 
|---------------------------------------------------- |  | -------------- | ----- | ----- |  | ----- | ----- | ---- |  | ---- | --- | ---- |  | ---- | - | ---- |  | ---- | - |  |  |  | - |  |  |  | ------ |  |  |  | ------ |  |  |  | ------ | 
|                                                     |  |                |       |       |  |      
|                                                     |  | United Kingdom |       | Other |  | Total
|                                                     |  |                |       |       |  |      
|                                                     |  | 2003           |       | 2002  |  | 2001  |       | 2003 |  | 2002 |     | 2001 |  | 2003 |   | 2002 |  | 2001
|                                                     |  |                |       |       |  |       |       |      |  |      |     |      |  |      |   |      |  |     
|                                                     |  |               
|                                                     |  | ($ millions)  
|Future cash inflows                                  |  |                | 3,483 |       |  |       | 2,565 |      |  |      | 414 |      |  |      |  |      |  |      |  |  |  |  |  |  |  |  | 59,614 |  |  |  | 45,221 |  |  |  | 12,027 | 
|Future production and development costs              |  |                | 1,969 |       |  |       | 1,233 |      |  |      | 161 |      |  |      |  |      |  |      |  |  |  |  |  |  |  |  | 19,863 |  |  |  | 14,187 |  |  |  | 3,516  | 
|                                                     |  |                |       |       |  |       |       |      |  |      |     |      |  |      |   |      |  |      |   |  |  |  |   |  |  |  |        |  |  |  |        |  |  |  |        | 
|Undiscounted pre-tax cash flows                      |  |                | 1,514 |       |  |       | 1,332 |      |  |      | 253 |      |  |      |  |      |  |      |  |  |  |  |  |  |  |  | 39,751 |  |  |  | 31,034 |  |  |  | 8,511  | 
|Future income taxes                                  |  |                | 456   |       |  |       | 483   |      |  |      | 53  |      |  |      |  |      |  |      |  |  |  |  |  |  |  |  | 11,826 |  |  |  | 8,925  |  |  |  | 2,681  | 
|                                                     |  |                |       |       |  |       |       |      |  |      |     |      |  |      |   |      |  |      |   |  |  |  |   |  |  |  |        |  |  |  |        |  |  |  |        | 
|Future net cash flows                                |  |                | 1,058 |       |  |       | 849   |      |  |      | 200 |      |  |      |  |      |  |      |  |  |  |  |  |  |  |  | 27,925 |  |  |  | 22,109 |  |  |  | 5,830  | 
|Less discount of net cash flows using a
    10% rate |  |                | 493   |       |  |       | 438   |      |  |      | 60  |      |  |      |  |      |  |      |  |  |  |  |  |  |  |  | 11,090 |  |  |  | 9,456  |  |  |  | 2,330  | 
|                                                     |  |                |       |       |  |       |       |      |  |      |     |      |  |      |   |      |  |      |   |  |  |  |   |  |  |  |        |  |  |  |        |  |  |  |        | 
|Discounted future net cash flows                     |  |                | 565   |       |  |       | 411   |      |  |      | 140 |      |  |      |  |      |  |      |  |  |  |  |  |  |  |  | 16,835 |  |  |  | 12,653 |  |  |  | 3,500  | 
|                                                     |  |                |       |       |  |       |       |      |  |      |     |      |  |      |   |      |  |      |   |  |  |  |   |  |  |  |        |  |  |  |        |  |  |  |        | 

25



---



##### 



Changes in Standardized Measure of Discounted
Future Net Cash Flows

Relating to Proved Oil and
Gas Reserves


|                           |                                                       |              |        |               |   |         |        |        |   |      |       |        |   |      |        |       |   |      |       |       |   |  |     |     |   |  |       |      |   |  |       |       |   |  |   |   | 
|-------------------------- | ----------------------------------------------------- | ------------ | ------ | ------------- | - | ------- | ------ | ------ | - | ---- | ----- | ------ | - | ---- | ------ | ----- | - | ---- | ----- | ----- | - |  | --- | --- | - |  | ----- | ---- | - |  | ----- | ----- | - |  | - | - | 
|                           |                                                       |              |        |               |   |        
|                           |                                                       | Canada       |        | United States |   | Ecuador
|                           |                                                       |              |        |               |   |        
|                           |                                                       | 2003         |        | 2002          |   | 2001    |        | 2003   |   | 2002 |       | 2001   |   | 2003 |        | 2002  |   | 2001
|                           |                                                       |              |        |               |   |         |        |        |   |      |       |        |   |      |        |       |   |     
|                           |                                                       |             
|                           |                                                       | ($ millions)
|Balance, beginning of year |                                                       |              | 8,833  |               |   |         | 3,060  |        |   |      | 7,844 |        |   |      | 2,151  |       |   |      | 300   |       |   |  | 145 |     |   |  | 1,258 |      |   |  |      |       |   |  |  |  
|Changes resulting from:    |                                                       |              |        |               |   |         |        |        |   |      |       |        |   |      |        |       |   |      |       |       |   |  |     |     |   |  |       |      |   |  |       |       |   |  |   |  
|                           | Sales of oil and gas produced during
    the period   |              |        | (3,429        | ) |         |        | (2,092 | ) |      |       | (1,701 | ) |      |        | (889  | ) |      |       | (329  | ) |  |     | (47 | ) |  |       | (258 | ) |  |       | (157  | ) |  |   |  | 
|                           | Discoveries and extensions, net of
    related costs  |              |        | 1,272         |   |         |        | 1,293  |   |      |       | 487    |   |      |        | 1,381 |   |      |       | 293   |   |  |     | 36  |   |  |       | 126  |   |  |       | 330   |   |  |   |  | 
|                           | Purchases of proved AEC reserves in place             |              |        |              |   |         |        | 6,810  |   |      |       |       |   |      |        |      |   |      |       | 1,044 |   |  |     |    |   |  |       |     |   |  |       | 1,830 |   |  |   |  | 
|                           | Purchases of proved reserves in place                 |              |        | 26            |   |         |        | 93     |   |      |       | 4      |   |      |        | 340   |   |      |       | 613   |   |  |     | 30  |   |  |       | 93   |   |  |       |      |   |  |   |  | 
|                           | Sales of proved reserves in place                     |              |        | (95           | ) |         |        | (371   | ) |      |       | (234   | ) |      |        | (108  | ) |      |       | (72   | ) |  |     |    |   |  |       | (54  | ) |  |       |      |   |  |   |  | 
|                           | Net change in prices and production costs             |              |        | 242           |   |         |        | 3,358  |   |      |       | (7,561 | ) |      |        | 2,751 |   |      |       | 194   |   |  |     | 109 |   |  |       | (47  | ) |  |       |      |   |  |   |  | 
|                           | Revisions to quantity estimates                       |              |        | 416           |   |         |        | (1,345 | ) |      |       | 90     |   |      |        | 4     |   |      |       | 667   |   |  |     | 12  |   |  |       | 4    |   |  |       | (354  | ) |  |   |  | 
|                           | Accretion of discount                                 |              |        | 1,636         |   |         |        | 455    |   |      |       | 1,197  |   |      |        | 304   |   |      |       | 56    |   |  |     | 21  |   |  |       | 182  |   |  |       |      |   |  |   |  | 
|                           | Future development costs incurred, net
    of changes |              |        | 340           |   |         |        | 101    |   |      |       | 180    |   |      |        | 534   |   |      |       | 54    |   |  |     | (70 | ) |  |       | 89   |   |  |       |      |   |  |   |  | 
|                           | Other                                                 |              |        | 470           |   |         |        | (67    | ) |      |       | 21     |   |      |        | 157   |   |      |       | (51   | ) |  |     |    |   |  |       | (27  | ) |  |       |      |   |  |   |  | 
|Net change in income taxes |                                                       |              | 304    |               |   |         | (2,462 | )      |   |      | 2,733 |        |   |      | (1,737 | )     |   |      | (618  | )     |   |  | 64  |     |   |  | 1     |      |   |  | (391  | )     |   |  |  |  
|                           |                                                       |              |        |               |   |         |        |        |   |      |       |        |   |      |        |       |   |      |       |       |   |  |     |     |   |  |       |      |   |  |       |       |   |  |   |  
|Balance, end of year       |                                                       |              | 10,015 |               |   |         | 8,833  |        |   |      | 3,060 |        |   |      | 4,888  |       |   |      | 2,151 |       |   |  | 300 |     |   |  | 1,367 |      |   |  | 1,258 |       |   |  |  |  
|                           |                                                       |              |        |               |   |         |        |        |   |      |       |        |   |      |        |       |   |      |       |       |   |  |     |     |   |  |       |      |   |  |       |       |   |  |   |  

|                           |                                                       |                |     |       |   |       |      |      |   |      |     |      |   |      |   |      |  |      |   |   |  |  |    |     |   |  |        |        |   |  |        |        |   |  |       |        |  
|-------------------------- | ----------------------------------------------------- | -------------- | --- | ----- | - | ----- | ---- | ---- | - | ---- | --- | ---- | - | ---- | - | ---- |  | ---- | - | - |  |  | -- | --- | - |  | ------ | ------ | - |  | ------ | ------ | - |  | ----- | ------ | -
|                           |                                                       |                |     |       |   |      
|                           |                                                       | United Kingdom |     | Other |   | Total
|                           |                                                       |                |     |       |   |      
|                           |                                                       | 2003           |     | 2002  |   | 2001  |      | 2003 |   | 2002 |     | 2001 |   | 2003 |   | 2002 |  | 2001
|                           |                                                       |                |     |       |   |       |      |      |   |      |     |      |   |      |   |      |  |     
|                           |                                                       |               
|                           |                                                       | ($ millions)  
|Balance, beginning of year |                                                       |                | 411 |       |   |       | 140  |      |   |      | 147 |      |   |      |  |      |  |      |  |   |  |  | 49 |     |   |  | 12,653 |        |   |  | 3,500  |        |   |  | 8,185 |       
|Changes resulting from:    |                                                       |                |     |       |   |       |      |      |   |      |     |      |   |      |   |      |  |      |   |   |  |  |    |     |   |  |        |        |   |  |        |        |   |  |       |       
|                           | Sales of oil and gas produced during
    the period   |                |     | (83   | ) |       |      | (81  | ) |      |     | (89  | ) |      |   |     |  |      |   |  |  |  |    |    |   |  |        | (4,659 | ) |  |        | (2,659 | ) |  |       | (1,837 | )
|                           | Discoveries and extensions, net of
    related costs  |                |     |      |   |       |      | 594  |   |      |     |     |   |      |   |     |  |      |   |  |  |  |    |    |   |  |        | 2,779  |   |  |        | 2,510  |   |  |       | 523    |  
|                           | Purchases of proved AEC reserves in place             |                |     |      |   |       |      |     |   |      |     |     |   |      |   |     |  |      |   |  |  |  |    |    |   |  |        |       |   |  |        | 9,684  |   |  |       |       |  
|                           | Purchases of proved reserves in place                 |                |     | 57    |   |       |      |     |   |      |     |     |   |      |   |     |  |      |   |  |  |  |    |    |   |  |        | 516    |   |  |        | 706    |   |  |       | 34     |  
|                           | Sales of proved reserves in place                     |                |     |      |   |       |      |     |   |      |     |     |   |      |   |     |  |      |   |  |  |  |    | (49 | ) |  |        | (257   | ) |  |        | (443   | ) |  |       | (283   | )
|                           | Net change in prices and production costs             |                |     | (119  | ) |       |      | (1   | ) |      |     | 12   |   |      |   |     |  |      |   |  |  |  |    |    |   |  |        | 2,827  |   |  |        | 3,551  |   |  |       | (7,440 | )
|                           | Revisions to quantity estimates                       |                |     | 157   |   |       |      | (53  | ) |      |     | 19   |   |      |   |     |  |      |   |  |  |  |    |    |   |  |        | 581    |   |  |        | (1,085 | ) |  |       | 121    |  
|                           | Accretion of discount                                 |                |     | 91    |   |       |      | 14   |   |      |     | 32   |   |      |   |     |  |      |   |  |  |  |    |    |   |  |        | 2,213  |   |  |        | 525    |   |  |       | 1,250  |  
|                           | Future development costs incurred, net
    of changes |                |     | 108   |   |       |      | 3    |   |      |     | (4   | ) |      |   |     |  |      |   |  |  |  |    |    |   |  |        | 1,071  |   |  |        | 158    |   |  |       | 106    |  
|                           | Other                                                 |                |     | (38   | ) |       |      | (8   | ) |      |     |     |   |      |   |     |  |      |   |  |  |  |    |    |   |  |        | 562    |   |  |        | (126   | ) |  |       | 21     |  
|Net change in income taxes |                                                       |                | (19 | )     |   |       | (197 | )    |   |      | 23  |      |   |      |  |      |  |      |  |   |  |  |   |     |   |  | (1,451 | )      |   |  | (3,668 | )      |   |  | 2,820 |       
|                           |                                                       |                |     |       |   |       |      |      |   |      |     |      |   |      |   |      |  |      |   |   |  |  |    |     |   |  |        |        |   |  |        |        |   |  |       |       
|Balance, end of year       |                                                       |                | 565 |       |   |       | 411  |      |   |      | 140 |      |   |      |  |      |  |      |  |   |  |  |   |     |   |  | 16,835 |        |   |  | 12,653 |        |   |  | 3,500 |       
|                           |                                                       |                |     |       |   |       |      |      |   |      |     |      |   |      |   |      |  |      |   |   |  |  |    |     |   |  |        |        |   |  |        |        |   |  |       |       

26



---



##### 





| |                                                                
| | ---------------------------------------------------------------
| | Results of Operations, Capitalized Costs
    and Costs Incurred

Results of Operations

|                                                                             |  |              |       |               |  |         |       |      |  |      |       |      |  |      |       |      |  |      |     |  |  |  |    |  |  |  |     |  |  |  |     |  |  |  |   | 
|---------------------------------------------------------------------------- |  | ------------ | ----- | ------------- |  | ------- | ----- | ---- |  | ---- | ----- | ---- |  | ---- | ----- | ---- |  | ---- | --- |  |  |  | -- |  |  |  | --- |  |  |  | --- |  |  |  | - | 
|                                                                             |  |              |       |               |  |        
|                                                                             |  | Canada       |       | United States |  | Ecuador
|                                                                             |  |              |       |               |  |        
|                                                                             |  | 2003         |       | 2002          |  | 2001    |       | 2003 |  | 2002 |       | 2001 |  | 2003 |       | 2002 |  | 2001
|                                                                             |  |              |       |               |  |         |       |      |  |      |       |      |  |      |       |      |  |     
|                                                                             |  |             
|                                                                             |  | ($ millions)
|Oil and gas revenues, net of royalties,
    transportation and selling costs |  |              | 4,189 |               |  |         | 2,630 |      |  |      | 2,043 |      |  |      | 1,091 |      |  |      | 406 |  |  |  | 73 |  |  |  | 367 |  |  |  | 224 |  |  |  |  | 
|Operating costs, production and mineral taxes                                |  |              | 760   |               |  |         | 538   |      |  |      | 342   |      |  |      | 202   |      |  |      | 77  |  |  |  | 26 |  |  |  | 109 |  |  |  | 67  |  |  |  |  | 
|Depreciation, depletion and amortization                                     |  |              | 1,511 |               |  |         | 871   |      |  |      | 385   |      |  |      | 297   |      |  |      | 206 |  |  |  | 31 |  |  |  | 159 |  |  |  | 79  |  |  |  |  | 
|                                                                             |  |              |       |               |  |         |       |      |  |      |       |      |  |      |       |      |  |      |     |  |  |  |    |  |  |  |     |  |  |  |     |  |  |  |   | 
|Operating income (loss)                                                      |  |              | 1,918 |               |  |         | 1,221 |      |  |      | 1,316 |      |  |      | 592   |      |  |      | 123 |  |  |  | 16 |  |  |  | 99  |  |  |  | 78  |  |  |  |  | 
|Income taxes                                                                 |  |              | 218   |               |  |         | 456   |      |  |      | 423   |      |  |      | 219   |      |  |      | 47  |  |  |  | 6  |  |  |  | 17  |  |  |  | 28  |  |  |  |  | 
|                                                                             |  |              |       |               |  |         |       |      |  |      |       |      |  |      |       |      |  |      |     |  |  |  |    |  |  |  |     |  |  |  |     |  |  |  |   | 
|Results of operations                                                        |  |              | 1,700 |               |  |         | 765   |      |  |      | 893   |      |  |      | 373   |      |  |      | 76  |  |  |  | 10 |  |  |  | 82  |  |  |  | 50  |  |  |  |  | 
|                                                                             |  |              |       |               |  |         |       |      |  |      |       |      |  |      |       |      |  |      |     |  |  |  |    |  |  |  |     |  |  |  |     |  |  |  |   | 

|                                                                             |  |                |     |       |  |       |    |      |  |      |    |      |  |      |      |      |  |      |     |   |  |  |     |   |  |  |       |  |  |  |       |  |  |  |       | 
|---------------------------------------------------------------------------- |  | -------------- | --- | ----- |  | ----- | -- | ---- |  | ---- | -- | ---- |  | ---- | ---- | ---- |  | ---- | --- | - |  |  | --- | - |  |  | ----- |  |  |  | ----- |  |  |  | ----- | 
|                                                                             |  |                |     |       |  |      
|                                                                             |  | United Kingdom |     | Other |  | Total
|                                                                             |  |                |     |       |  |      
|                                                                             |  | 2003           |     | 2002  |  | 2001  |    | 2003 |  | 2002 |    | 2001 |  | 2003 |      | 2002 |  | 2001
|                                                                             |  |                |     |       |  |       |    |      |  |      |    |      |  |      |      |      |  |     
|                                                                             |  |               
|                                                                             |  | ($ millions)  
|Oil and gas revenues, net of royalties,
    transportation and selling costs |  |                | 102 |       |  |       | 92 |      |  |      | 99 |      |  |      |     |      |  |      |    |   |  |  |    |   |  |  | 5,749 |  |  |  | 3,352 |  |  |  | 2,215 | 
|Operating costs, production and mineral taxes                                |  |                | 19  |       |  |       | 11 |      |  |      | 10 |      |  |      | 20   |      |  |      | 29  |   |  |  | 1   |   |  |  | 1,110 |  |  |  | 722   |  |  |  | 379   | 
|Depreciation, depletion and amortization                                     |  |                | 74  |       |  |       | 39 |      |  |      | 42 |      |  |      | 83   |      |  |      | 35  |   |  |  | 17  |   |  |  | 2,124 |  |  |  | 1,230 |  |  |  | 475   | 
|                                                                             |  |                |     |       |  |       |    |      |  |      |    |      |  |      |      |      |  |      |     |   |  |  |     |   |  |  |       |  |  |  |       |  |  |  |       | 
|Operating income (loss)                                                      |  |                | 9   |       |  |       | 42 |      |  |      | 47 |      |  |      | (103 | )    |  |      | (64 | ) |  |  | (18 | ) |  |  | 2,515 |  |  |  | 1,400 |  |  |  | 1,361 | 
|Income taxes                                                                 |  |                | 17  |       |  |       | 17 |      |  |      | 17 |      |  |      | (4   | )    |  |      |    |   |  |  |    |   |  |  | 467   |  |  |  | 548   |  |  |  | 446   | 
|                                                                             |  |                |     |       |  |       |    |      |  |      |    |      |  |      |      |      |  |      |     |   |  |  |     |   |  |  |       |  |  |  |       |  |  |  |       | 
|Results of operations                                                        |  |                | (8  | )     |  |       | 25 |      |  |      | 30 |      |  |      | (99  | )    |  |      | (64 | ) |  |  | (18 | ) |  |  | 2,048 |  |  |  | 852   |  |  |  | 915   | 
|                                                                             |  |                |     |       |  |       |    |      |  |      |    |      |  |      |      |      |  |      |     |   |  |  |     |   |  |  |       |  |  |  |       |  |  |  |       | 

Capitalized Costs

|                                |  |              |        |               |  |         |        |      |  |      |       |      |  |      |       |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 
|------------------------------- |  | ------------ | ------ | ------------- |  | ------- | ------ | ---- |  | ---- | ----- | ---- |  | ---- | ----- | ---- |  | ---- | ----- |  |  |  | --- |  |  |  | ----- |  |  |  | ----- |  |  |  | - | 
|                                |  |              |        |               |  |        
|                                |  | Canada       |        | United States |  | Ecuador
|                                |  |              |        |               |  |        
|                                |  | 2003         |        | 2002          |  | 2001    |        | 2003 |  | 2002 |       | 2001 |  | 2003 |       | 2002 |  | 2001
|                                |  |              |        |               |  |         |        |      |  |      |       |      |  |      |       |      |  |     
|                                |  |             
|                                |  | ($ millions)
|Proved oil and gas properties   |  |              | 18,549 |               |  |         | 12,504 |      |  |      | 7,704 |      |  |      | 3,485 |      |  |      | 2,769 |  |  |  | 471 |  |  |  | 1,372 |  |  |  | 1,000 |  |  |  |  | 
|Unproved oil and gas properties |  |              | 1,981  |               |  |         | 1,573  |      |  |      | 203   |      |  |      | 501   |      |  |      | 415   |  |  |  | 116 |  |  |  | 70    |  |  |  | 60    |  |  |  |  | 
|                                |  |              |        |               |  |         |        |      |  |      |       |      |  |      |       |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 
|Total capital cost              |  |              | 20,530 |               |  |         | 14,077 |      |  |      | 7,907 |      |  |      | 3,986 |      |  |      | 3,184 |  |  |  | 587 |  |  |  | 1,442 |  |  |  | 1,060 |  |  |  |  | 
|Accumulated DD&A                |  |              | 7,498  |               |  |         | 4,770  |      |  |      | 3,893 |      |  |      | 516   |      |  |      | 262   |  |  |  | 29  |  |  |  | 188   |  |  |  | 73    |  |  |  |  | 
|                                |  |              |        |               |  |         |        |      |  |      |       |      |  |      |       |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 
|Net capitalized costs           |  |              | 13,032 |               |  |         | 9,307  |      |  |      | 4,014 |      |  |      | 3,470 |      |  |      | 2,922 |  |  |  | 558 |  |  |  | 1,254 |  |  |  | 987   |  |  |  |  | 
|                                |  |              |        |               |  |         |        |      |  |      |       |      |  |      |       |      |  |      |       |  |  |  |     |  |  |  |       |  |  |  |       |  |  |  |   | 

|                                |  |                |     |       |  |       |     |      |  |      |     |      |  |      |     |      |  |      |     |  |  |  |     |  |  |  |        |  |  |  |        |  |  |  |       | 
|------------------------------- |  | -------------- | --- | ----- |  | ----- | --- | ---- |  | ---- | --- | ---- |  | ---- | --- | ---- |  | ---- | --- |  |  |  | --- |  |  |  | ------ |  |  |  | ------ |  |  |  | ----- | 
|                                |  |                |     |       |  |      
|                                |  | United Kingdom |     | Other |  | Total
|                                |  |                |     |       |  |      
|                                |  | 2003           |     | 2002  |  | 2001  |     | 2003 |  | 2002 |     | 2001 |  | 2003 |     | 2002 |  | 2001
|                                |  |                |     |       |  |       |     |      |  |      |     |      |  |      |     |      |  |     
|                                |  |               
|                                |  | ($ millions)  
|Proved oil and gas properties   |  |                | 675 |       |  |       | 445 |      |  |      | 288 |      |  |      |    |      |  |      |    |  |  |  |    |  |  |  | 24,081 |  |  |  | 16,718 |  |  |  | 8,463 | 
|Unproved oil and gas properties |  |                | 77  |       |  |       | 3   |      |  |      | 44  |      |  |      | 317 |      |  |      | 226 |  |  |  | 144 |  |  |  | 2,946  |  |  |  | 2,277  |  |  |  | 507   | 
|                                |  |                |     |       |  |       |     |      |  |      |     |      |  |      |     |      |  |      |     |  |  |  |     |  |  |  |        |  |  |  |        |  |  |  |       | 
|Total capital cost              |  |                | 752 |       |  |       | 448 |      |  |      | 332 |      |  |      | 317 |      |  |      | 226 |  |  |  | 144 |  |  |  | 27,027 |  |  |  | 18,995 |  |  |  | 8,970 | 
|Accumulated DD&A                |  |                | 230 |       |  |       | 136 |      |  |      | 88  |      |  |      | 206 |      |  |      | 98  |  |  |  | 92  |  |  |  | 8,638  |  |  |  | 5,339  |  |  |  | 4,102 | 
|                                |  |                |     |       |  |       |     |      |  |      |     |      |  |      |     |      |  |      |     |  |  |  |     |  |  |  |        |  |  |  |        |  |  |  |       | 
|Net capitalized costs           |  |                | 522 |       |  |       | 312 |      |  |      | 244 |      |  |      | 111 |      |  |      | 128 |  |  |  | 52  |  |  |  | 18,389 |  |  |  | 13,656 |  |  |  | 4,868 | 
|                                |  |                |     |       |  |       |     |      |  |      |     |      |  |      |     |      |  |      |     |  |  |  |     |  |  |  |        |  |  |  |        |  |  |  |       | 

27



---



##### 



Costs Incurred

|                          |  |              |       |               |  |         |       |      |  |      |     |      |  |      |     |      |  |      |       |  |  |  |     |  |  |  |     |  |  |  |       |  |  |  |   | 
|------------------------- |  | ------------ | ----- | ------------- |  | ------- | ----- | ---- |  | ---- | --- | ---- |  | ---- | --- | ---- |  | ---- | ----- |  |  |  | --- |  |  |  | --- |  |  |  | ----- |  |  |  | - | 
|                          |  |              |       |               |  |        
|                          |  | Canada       |       | United States |  | Ecuador
|                          |  |              |       |               |  |        
|                          |  | 2003         |       | 2002          |  | 2001    |       | 2003 |  | 2002 |     | 2001 |  | 2003 |     | 2002 |  | 2001
|                          |  |              |       |               |  |         |       |      |  |      |     |      |  |      |     |      |  |     
|                          |  |             
|                          |  | ($ millions)
|Acquisitions              |  |              |       |               |  |         |       |      |  |      |     |      |  |      |     |      |  |      |       |  |  |  |     |  |  |  |     |  |  |  |       |  |  |  |   | 
| AEC unproved reserves   |  |              |      |               |  |         | 1,496 |      |  |      |    |      |  |      |    |      |  |      | 444   |  |  |  |    |  |  |  |    |  |  |  | 221   |  |  |  |  | 
| other unproved reserves |  |              | 47    |               |  |         | 12    |      |  |      | 4   |      |  |      | 21  |      |  |      | 202   |  |  |  | 13  |  |  |  | 80  |  |  |  |      |  |  |  |  | 
| AEC proved reserves     |  |              |      |               |  |         | 3,540 |      |  |      |    |      |  |      |    |      |  |      | 1,024 |  |  |  |    |  |  |  |    |  |  |  | 686   |  |  |  |  | 
| other proved reserves   |  |              | 207   |               |  |         | 78    |      |  |      | 1   |      |  |      | 115 |      |  |      | 457   |  |  |  | 34  |  |  |  | 59  |  |  |  |      |  |  |  |  | 
|                          |  |              |       |               |  |         |       |      |  |      |     |      |  |      |     |      |  |      |       |  |  |  |     |  |  |  |     |  |  |  |       |  |  |  |   | 
|Total acquisitions        |  |              | 254   |               |  |         | 5,126 |      |  |      | 5   |      |  |      | 136 |      |  |      | 2,127 |  |  |  | 47  |  |  |  | 139 |  |  |  | 907   |  |  |  |  | 
|Exploration               |  |              | 846   |               |  |         | 403   |      |  |      | 304 |      |  |      | 187 |      |  |      | 226   |  |  |  | 129 |  |  |  | 20  |  |  |  | 35    |  |  |  |  | 
|Development               |  |              | 2,131 |               |  |         | 902   |      |  |      | 592 |      |  |      | 651 |      |  |      | 282   |  |  |  | 11  |  |  |  | 111 |  |  |  | 133   |  |  |  |  | 
|                          |  |              |       |               |  |         |       |      |  |      |     |      |  |      |     |      |  |      |       |  |  |  |     |  |  |  |     |  |  |  |       |  |  |  |   | 
|Total costs incurred      |  |              | 3,231 |               |  |         | 6,431 |      |  |      | 901 |      |  |      | 974 |      |  |      | 2,635 |  |  |  | 187 |  |  |  | 270 |  |  |  | 1,075 |  |  |  |  | 
|                          |  |              |       |               |  |         |       |      |  |      |     |      |  |      |     |      |  |      |       |  |  |  |     |  |  |  |     |  |  |  |       |  |  |  |   | 

|                          |  |                |     |       |  |       |    |      |  |      |    |      |  |      |    |      |  |      |     |  |  |  |    |  |  |  |       |  |  |  |        |  |  |  |       | 
|------------------------- |  | -------------- | --- | ----- |  | ----- | -- | ---- |  | ---- | -- | ---- |  | ---- | -- | ---- |  | ---- | --- |  |  |  | -- |  |  |  | ----- |  |  |  | ------ |  |  |  | ----- | 
|                          |  |                |     |       |  |      
|                          |  | United Kingdom |     | Other |  | Total
|                          |  |                |     |       |  |      
|                          |  | 2003           |     | 2002  |  | 2001  |    | 2003 |  | 2002 |    | 2001 |  | 2003 |    | 2002 |  | 2001
|                          |  |                |     |       |  |       |    |      |  |      |    |      |  |      |    |      |  |     
|                          |  |               
|                          |  | ($ millions)  
|Acquisitions              |  |                |     |       |  |       |    |      |  |      |    |      |  |      |    |      |  |      |     |  |  |  |    |  |  |  |       |  |  |  |        |  |  |  |       | 
| AEC unproved reserves   |  |                |    |       |  |       |   |      |  |      |   |      |  |      |   |      |  |      |    |  |  |  |   |  |  |  |      |  |  |  | 2,161  |  |  |  |      | 
| other unproved reserves |  |                | 16  |       |  |       |   |      |  |      |   |      |  |      |   |      |  |      |    |  |  |  |   |  |  |  | 164   |  |  |  | 214    |  |  |  | 17    | 
| AEC proved reserves     |  |                |    |       |  |       |   |      |  |      |   |      |  |      |   |      |  |      |    |  |  |  |   |  |  |  |      |  |  |  | 5,250  |  |  |  |      | 
| other proved reserves   |  |                | 95  |       |  |       |   |      |  |      |   |      |  |      |   |      |  |      |    |  |  |  | 4  |  |  |  | 476   |  |  |  | 535    |  |  |  | 39    | 
|                          |  |                |     |       |  |       |    |      |  |      |    |      |  |      |    |      |  |      |     |  |  |  |    |  |  |  |       |  |  |  |        |  |  |  |       | 
|Total acquisitions        |  |                | 111 |       |  |       |   |      |  |      |   |      |  |      |   |      |  |      |    |  |  |  | 4  |  |  |  | 640   |  |  |  | 8,160  |  |  |  | 56    | 
|Exploration               |  |                | 30  |       |  |       | 16 |      |  |      | 25 |      |  |      | 78 |      |  |      | 118 |  |  |  | 41 |  |  |  | 1,161 |  |  |  | 798    |  |  |  | 499   | 
|Development               |  |                | 96  |       |  |       | 66 |      |  |      | 17 |      |  |      |   |      |  |      |    |  |  |  |   |  |  |  | 2,989 |  |  |  | 1,383  |  |  |  | 620   | 
|                          |  |                |     |       |  |       |    |      |  |      |    |      |  |      |    |      |  |      |     |  |  |  |    |  |  |  |       |  |  |  |        |  |  |  |       | 
|Total costs incurred      |  |                | 237 |       |  |       | 82 |      |  |      | 42 |      |  |      | 78 |      |  |      | 118 |  |  |  | 45 |  |  |  | 4,790 |  |  |  | 10,341 |  |  |  | 1,175 | 
|                          |  |                |     |       |  |       |    |      |  |      |    |      |  |      |    |      |  |      |     |  |  |  |    |  |  |  |       |  |  |  |        |  |  |  |       | 

28



---



##### 



Daily Sales Volumes, Royalty Rates and
Per-Unit Results

Daily
Sales Volumes

The following tables summarize net daily sales
volumes for EnCana on a quarterly basis for the periods
indicated.

|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        | 
|--------------------------------------------- | -------------- | -------------------------------------------- | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | 
|                                              |                |                                             
|                                              |                | Daily Sales Volumes  2003 (After Royalties)
|                                              |                |                                             
|                                              |                | Year                                         |               | Q4     |        | Q3     |         | Q2     |        | Q1    
|                                              |                |                                              |               |        |        |        |         |        |        |       
|SALES                                         |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Produced Gas (million cubic
    feet/day)     |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | 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    |       
|                                              | United Kingdom |                                              |               | 13     |        |        |         | 20     |        |        |         | 7      |        |        |         | 12     |        |        |         | 13     |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Produced Gas                            |                |                                              | 2,566         |        |        |        | 2,682   |        |        |        | 2,525   |        |        |        | 2,469   |        |        |        | 2,589   |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Oil and Natural Gas Liquids
    (barrels/day) |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | 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 North America                           |                |                                              | 165,895       |        |        |        | 174,471 |        |        |        | 172,870 |        |        |        | 159,668 |        |        |        | 156,295 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | 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  |                                              |               | 46,521 |        |        |         | 77,352 |        |        |         | 39,807 |        |        |         | 37,221 |        |        |         | 31,273 |       
|                                              | United Kingdom |                                              |               | 10,128 |        |        |         | 15,067 |        |        |         | 5,813  |        |        |         | 9,019  |        |        |         | 10,610 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Oil and Natural Gas Liquids             |                |                                              | 222,544       |        |        |        | 266,890 |        |        |        | 218,490 |        |        |        | 205,908 |        |        |        | 198,178 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total (barrels of oil
    equivalent/day)     |                |                                              | 650,211       |        |        |        | 713,890 |        |        |        | 639,323 |        |        |        | 617,408 |        |        |        | 629,678 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Syncrude                                      |                |                                              | 7,629         |        |        |        |        |        |        |        | 3,399   |        |        |        | 7,316   |        |        |        | 20,070  |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       




Notes:



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

29



---



##### 



|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        | 
|--------------------------------------------- | -------------- | -------------------------------------------- | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | 
|                                              |                |                                             
|                                              |                | Daily Sales Volumes  2002 (After Royalties)
|                                              |                |                                             
|                                              |                | Year                                         |               | Q4     |        | Q3     |         | Q2     |        | Q1    
|                                              |                |                                              |               |        |        |        |         |        |        |       
|SALES                                         |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Produced Gas (million cubic
    feet/day)     |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | 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     |       
|                                              | United Kingdom |                                              |               | 10     |        |        |         | 8      |        |        |         | 9      |        |        |         | 8      |        |        |         | 11     |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Produced Gas                            |                |                                              | 2,058         |        |        |        | 2,584   |        |        |        | 2,340   |        |        |        | 2,243   |        |        |        | 1,044   |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Oil and Natural Gas Liquids
    (barrels/day) |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | 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 North America                           |                |                                              | 137,477       |        |        |        | 158,358 |        |        |        | 149,002 |        |        |        | 146,979 |        |        |        | 94,739  |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Ecuador        |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                              |                | Production                                   |               |        | 27,625 |        |         |        | 34,856 |        |         |        | 37,447 |        |         |        | 37,702 |        |         |        |       |       
|                                              |                | Over/(under) lifting                         |               |        | 2,115  |        |         |        | 1,044  |        |         |        | 2,316  |        |         |        | 5,088  |        |         |        |       |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Ecuador Sales  |                                              |               | 29,740 |        |        |         | 35,900 |        |        |         | 39,763 |        |        |         | 42,790 |        |        |         |       |       
|                                              | United Kingdom |                                              |               | 10,528 |        |        |         | 7,786  |        |        |         | 9,538  |        |        |         | 11,966 |        |        |         | 12,889 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Oil and Natural Gas Liquids             |                |                                              | 177,745       |        |        |        | 202,044 |        |        |        | 198,303 |        |        |        | 201,735 |        |        |        | 107,628 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total (barrels of oil
    equivalent/day)     |                |                                              | 520,745       |        |        |        | 632,711 |        |        |        | 588,303 |        |        |        | 575,568 |        |        |        | 281,628 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Syncrude                                      |                |                                              | 23,540        |        |        |        | 33,918  |        |        |        | 35,585  |        |        |        | 24,152  |        |        |        |        |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       

|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |        |        |        | 
|--------------------------------------------- | -------------- | -------------------------------------------- | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ----- | ------- | ------ | ------ | ----- | ------- | ------ | ------ | ------ | 
|                                              |                |                                             
|                                              |                | Daily Sales Volumes  2001 (After Royalties)
|                                              |                |                                             
|                                              |                | Year                                         |               | Q4     |        | Q3     |         | Q2     |        | Q1    
|                                              |                |                                              |               |        |        |        |         |        |        |       
|SALES                                         |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|Produced Gas (million cubic
    feet/day)     |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|                                              | Canada         |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |        |       
|                                              |                | Production                                   |               |        | 953    |        |         |        | 974    |        |         |        | 951    |       |         |        | 943    |       |         |        | 946    |       
|                                              |                | Inventory withdrawal/(injection)             |               |        |       |        |         |        |       |        |         |        |       |       |         |        |       |       |         |        |       |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|                                              | Canada Sales   |                                              |               | 953    |        |        |         | 974    |        |        |         | 951    |        |       |         | 943    |        |       |         | 946    |       
|                                              | United States  |                                              |               | 43     |        |        |         | 55     |        |        |         | 48     |        |       |         | 36     |        |       |         | 33     |       
|                                              | United Kingdom |                                              |               | 9      |        |        |         | 9      |        |        |         | 10     |        |       |         | 8      |        |       |         | 8      |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|Total Produced Gas                            |                |                                              | 1,005         |        |        |        | 1,038   |        |        |        | 1,009   |        |        |       | 987     |        |        |       | 987     |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|Oil and Natural Gas Liquids
    (barrels/day) |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|                                              | North America  |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |        |       
|                                              |                | Light and medium oil                         |               |        | 60,332 |        |         |        | 58,591 |        |         |        | 62,250 |       |         |        | 59,511 |       |         |        | 60,981 |       
|                                              |                | Heavy oil                                    |               |        | 19,940 |        |         |        | 20,168 |        |         |        | 19,948 |       |         |        | 17,069 |       |         |        | 22,602 |       
|                                              |                | Natural gas liquids                          |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |        |        |       
|                                              |                |                                              | Canada        |        |        | 10,142 |         |        |        | 10,792 |         |        |        | 9,474 |         |        |        | 9,944 |         |        |        | 10,362 | 
|                                              |                |                                              | United States |        |        | 2,443  |         |        |        | 2,224  |         |        |        | 2,954 |         |        |        | 2,207 |         |        |        | 2,383  | 
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|Total North America                           |                |                                              | 92,857        |        |        |        | 91,775  |        |        |        | 94,626  |        |        |       | 88,731  |        |        |       | 96,328  |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|                                              | United Kingdom |                                              |               | 11,362 |        |        |         | 10,839 |        |        |         | 12,669 |        |       |         | 10,914 |        |       |         | 11,012 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|Total Oil and Natural Gas Liquids             |                |                                              | 104,219       |        |        |        | 102,614 |        |        |        | 107,295 |        |        |       | 99,645  |        |        |       | 107,340 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       
|Total (barrels of oil
    equivalent/day)     |                |                                              | 271,719       |        |        |        | 275,614 |        |        |        | 275,462 |        |        |       | 264,145 |        |        |       | 271,840 |       
|                                              |                |                                              |               |        |        |        |         |        |        |        |         |        |        |       |         |        |        |       |         |       

30



---



##### 



Average
Royalty Rates

The following table sets forth average royalty
rates on a quarterly basis for the periods indicated. These
rates exclude the impact of financial hedging.

|                    |                          |           |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |    |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |  |      |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      | 
|------------------- | ------------------------ | --------- | ---- | ---- |  | ---- | ---- | ---- |  | -- | ---- | ---- |  | -- | ---- | ---- |  | -- | ---- | ---- |  | ---- | ---- | ---- |  | -- | ---- | ---- |  | -- | ---- | ---- |  |  | ---- | ---- |  |  | --- | ---- |  |  | --- | ---- |  |  | --- | ---- |  |  | --- | ---- |  |  | --- | ---- |  |  | --- | ---- | 
|                    |                          |           |      |      |  |     
|                    |                          | 2003      |      | 2002 |  | 2001
|                    |                          |           |      |      |  |     
|                    |                          | Year      |      | Q4   |  | Q3   |      | Q2   |  | Q1 |      | Year |  | Q4 |      | Q3   |  | Q2 |      | Q1   |  | Year |      | Q4   |  | Q3 |      | Q2   |  | Q1
|                    |                          |           |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |    |      |      |  |      |      |      |  |    |      |      |  |   
|                    |                          |          
|                    |                          | (percent)
|Produced Gas        |                          |           |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |    |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |  |      |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |     
|                    | Canada                   |           |      | 12.9 |  |      |      | 12.2 |  |    |      | 12.9 |  |    |      | 14.2 |  |    |      | 12.4 |  |      |      | 10.7 |  |    |      | 13.3 |  |    |      | 10.4 |  |  |      | 11.8 |  |  |     | 2.7  |  |  |     | 3.0  |  |  |     | 2.2  |  |  |     | 2.7  |  |  |     | 4.3  |  |  |     | 2.4  | 
|                    | United States            |           |      | 20.0 |  |      |      | 19.5 |  |    |      | 20.2 |  |    |      | 20.1 |  |    |      | 20.5 |  |      |      | 21.1 |  |    |      | 21.1 |  |    |      | 23.1 |  |  |      | 19.4 |  |  |     | 19.4 |  |  |     | 30.6 |  |  |     | 23.6 |  |  |     | 22.6 |  |  |     | 42.9 |  |  |     | 36.5 | 
|Crude Oil           |                          |           |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |    |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |  |      |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |     
|                    | Canada and United States |           |      | 10.3 |  |      |      | 9.7  |  |    |      | 9.0  |  |    |      | 10.7 |  |    |      | 11.8 |  |      |      | 11.0 |  |    |      | 10.8 |  |    |      | 11.7 |  |  |      | 11.6 |  |  |     | 9.5  |  |  |     | 10.8 |  |  |     | 12.2 |  |  |     | 10.6 |  |  |     | 11.4 |  |  |     | 9.0  | 
|                    | Ecuador                  |           |      | 25.6 |  |      |      | 25.4 |  |    |      | 25.7 |  |    |      | 24.9 |  |    |      | 26.9 |  |      |      | 28.4 |  |    |      | 28.1 |  |    |      | 28.5 |  |  |      | 28.5 |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     | 
|Natural Gas Liquids |                          |           |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |    |      |      |  |      |      |      |  |    |      |      |  |    |      |      |  |  |      |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |      |  |  |     |     
|                    | Canada                   |           |      | 17.5 |  |      |      | 14.7 |  |    |      | 16.6 |  |    |      | 18.0 |  |    |      | 20.2 |  |      |      | 13.8 |  |    |      | 16.4 |  |    |      | 13.8 |  |  |      | 15.6 |  |  |     | 6.9  |  |  |     | 4.8  |  |  |     | 2.4  |  |  |     | 6.9  |  |  |     | 6.4  |  |  |     | 3.7  | 
|                    | United States            |           |      | 17.6 |  |      |      | 17.5 |  |    |      | 17.0 |  |    |      | 17.3 |  |    |      | 18.5 |  |      |      | 10.8 |  |    |      | 13.3 |  |    |      | 12.0 |  |  |      | 10.5 |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     | 
|Total Upstream      |                          |           | 14.5 |      |  |      | 14.4 |      |  |    | 14.2 |      |  |    | 15.1 |      |  |    | 14.4 |      |  |      | 13.1 |      |  |    | 14.8 |      |  |    | 13.8 |      |  |  | 13.9 |      |  |  | 5.4 |      |  |  | 6.3 |      |  |  | 6.0 |      |  |  | 5.8 |      |  |  | 7.7 |      |  |  | 5.4 |     

Per-Unit
Results

The following tables summarize net per-unit
results for EnCana on a quarterly basis for the periods
indicated.

|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |  
|-------------------------------------------- | ---------------------------- | ----------------------- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                             |                              |                        
|                                             |                              | Per-Unit Results  2003
|                                             |                              |                        
|                                             |                              | Year                    |  | Q4    |   | Q3 |  | Q2    |   | Q1
|                                             |                              |                         |  |       |   |    |  |       |   |   
|Produced Gas  Canada ($/Mcf)                |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 0.48  |   |    |  | 0.45  |   |    |  | 0.50  |   |  |  | 0.47  |   |  |  | 0.48  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback excluding hedge      |                         |  | 3.94  |   |    |  | 3.42  |   |    |  | 3.63  |   |  |  | 4.02  |   |  |  | 4.70  |  
|                                             | Financial hedge              |                         |  | (0.13 | ) |    |  | 0.25  |   |    |  | (0.03 | ) |  |  | (0.26 | ) |  |  | (0.49 | )
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback including hedge      |                         |  | 3.81  |   |    |  | 3.67  |   |    |  | 3.60  |   |  |  | 3.76  |   |  |  | 4.21  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Produced Gas  United States ($/Mcf)         |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 0.28  |   |    |  | 0.29  |   |    |  | 0.33  |   |  |  | 0.31  |   |  |  | 0.20  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback excluding hedge      |                         |  | 3.73  |   |    |  | 3.49  |   |    |  | 3.64  |   |  |  | 3.61  |   |  |  | 4.23  |  
|                                             | Financial hedge              |                         |  | 0.02  |   |    |  | (0.13 | ) |    |  | (0.16 | ) |  |  | (0.22 | ) |  |  | 0.67  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback including hedge      |                         |  | 3.75  |   |    |  | 3.36  |   |    |  | 3.48  |   |  |  | 3.39  |   |  |  | 4.90  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Produced Gas  Total North America ($/Mcf)   |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 0.43  |   |    |  | 0.41  |   |    |  | 0.46  |   |  |  | 0.43  |   |  |  | 0.42  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback excluding hedge      |                         |  | 3.89  |   |    |  | 3.44  |   |    |  | 3.63  |   |  |  | 3.93  |   |  |  | 4.60  |  
|                                             | Financial hedge              |                         |  | (0.10 | ) |    |  | 0.16  |   |    |  | (0.06 | ) |  |  | (0.25 | ) |  |  | (0.25 | )
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback including hedge      |                         |  | 3.79  |   |    |  | 3.60  |   |    |  | 3.57  |   |  |  | 3.68  |   |  |  | 4.35  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Light and Medium Oil  North America ($/bbl) |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 6.00  |   |    |  | 6.28  |   |    |  | 5.93  |   |  |  | 6.07  |   |  |  | 5.68  |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback excluding hedge      |                         |  | 18.90 |   |    |  | 17.19 |   |    |  | 19.02 |   |  |  | 18.92 |   |  |  | 20.63 |  
|                                             | Financial hedge              |                         |  | (4.07 | ) |    |  | (3.74 | ) |    |  | (3.24 | ) |  |  | (2.81 | ) |  |  | (6.54 | )
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                             | Netback including hedge      |                         |  | 14.83 |   |    |  | 13.45 |   |    |  | 15.78 |   |  |  | 16.11 |   |  |  | 14.09 |  
|                                             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      

31



---



##### 



|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |  
|----------------------------------------------------- | ---------------------------- | ----------------------- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                                      |                              |                        
|                                                      |                              | Per-Unit Results  2003
|                                                      |                              |                        
|                                                      |                              | Year                    |  | Q4    |   | Q3 |  | Q2    |   | Q1
|                                                      |                              |                         |  |       |   |    |  |       |   |   
|Heavy Oil  North America ($/bbl)                     |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 5.67  |   |    |  | 4.95  |   |    |  | 5.93  |   |  |  | 6.18  |   |  |  | 5.70  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 12.73 |   |    |  | 11.85 |   |    |  | 11.91 |   |  |  | 12.18 |   |  |  | 15.38 |  
|                                                      | Financial hedge              |                         |  | (3.91 | ) |    |  | (3.81 | ) |    |  | (3.17 | ) |  |  | (2.24 | ) |  |  | (6.69 | )
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 8.82  |   |    |  | 8.04  |   |    |  | 8.74  |   |  |  | 9.94  |   |  |  | 8.69  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Total Oil  North America ($/bbl)                     |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 5.80  |   |    |  | 5.45  |   |    |  | 5.93  |   |  |  | 6.13  |   |  |  | 5.70  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 15.09 |   |    |  | 13.84 |   |    |  | 14.50 |   |  |  | 14.82 |   |  |  | 17.49 |  
|                                                      | Financial hedge              |                         |  | (3.97 | ) |    |  | (3.78 | ) |    |  | (3.19 | ) |  |  | (2.47 | ) |  |  | (6.63 | )
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 11.12 |   |    |  | 10.06 |   |    |  | 11.31 |   |  |  | 12.35 |   |  |  | 10.86 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Canada ($/bbl)                  |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 24.26 |   |    |  | 25.13 |   |    |  | 23.52 |   |  |  | 21.02 |   |  |  | 27.31 |  
|                                                      | Transportation and selling   |                         |  | 0.17  |   |    |  | 0.13  |   |    |  | 0.58  |   |  |  |      |   |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback                      |                         |  | 24.09 |   |    |  | 25.00 |   |    |  | 22.94 |   |  |  | 21.02 |   |  |  | 27.31 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  United States
    ($/bbl)       |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 26.97 |   |    |  | 26.68 |   |    |  | 25.50 |   |  |  | 24.64 |   |  |  | 32.18 |  
|                                                      | Production and mineral taxes |                         |  | 2.03  |   |    |  | 2.69  |   |    |  | 2.64  |   |  |  | 1.21  |   |  |  | 1.55  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback                      |                         |  | 24.94 |   |    |  | 23.99 |   |    |  | 22.86 |   |  |  | 23.43 |   |  |  | 30.63 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Total North
    America ($/bbl) |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 25.33 |   |    |  | 25.77 |   |    |  | 24.33 |   |  |  | 22.50 |   |  |  | 28.98 |  
|                                                      | Production and mineral taxes |                         |  | 0.80  |   |    |  | 1.12  |   |    |  | 1.08  |   |  |  | 0.50  |   |  |  | 0.53  |  
|                                                      | Transportation and selling   |                         |  | 0.10  |   |    |  | 0.08  |   |    |  | 0.35  |   |  |  |      |   |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback                      |                         |  | 24.43 |   |    |  | 24.57 |   |    |  | 22.90 |   |  |  | 22.00 |   |  |  | 28.45 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Total Liquids  Canada ($/bbl)                        |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 5.27  |   |    |  | 5.01  |   |    |  | 5.43  |   |  |  | 5.53  |   |  |  | 5.11  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 15.91 |   |    |  | 14.74 |   |    |  | 15.22 |   |  |  | 15.43 |   |  |  | 18.52 |  
|                                                      | Financial hedge              |                         |  | (3.61 | ) |    |  | (3.47 | ) |    |  | (2.92 | ) |  |  | (2.22 | ) |  |  | (5.95 | )
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 12.30 |   |    |  | 11.27 |   |    |  | 12.30 |   |  |  | 13.21 |   |  |  | 12.57 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Ecuador Oil ($/bbl)                                   |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 4.84  |   |    |  | 4.62  |   |    |  | 4.33  |   |  |  | 5.63  |   |  |  | 5.09  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 15.34 |   |    |  | 15.08 |   |    |  | 14.99 |   |  |  | 13.16 |   |  |  | 19.15 |  
|                                                      | Financial hedge              |                         |  |      |   |    |  |      |   |    |  |      |   |  |  |      |   |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 15.34 |   |    |  | 15.08 |   |    |  | 14.99 |   |  |  | 13.16 |   |  |  | 19.15 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|United Kingdom Oil ($/bbl)                            |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 28.11 |   |    |  | 27.05 |   |    |  | 27.92 |   |  |  | 27.17 |   |  |  | 30.61 |  
|                                                      | Transportation and selling   |                         |  | 1.97  |   |    |  | 1.70  |   |    |  | 1.98  |   |  |  | 1.86  |   |  |  | 2.45  |  
|                                                      | Operating expenses           |                         |  | 5.09  |   |    |  | 6.23  |   |    |  | 6.55  |   |  |  | 4.69  |   |  |  | 2.92  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 21.05 |   |    |  | 19.12 |   |    |  | 19.39 |   |  |  | 20.62 |   |  |  | 25.24 |  
|                                                      | Financial hedge              |                         |  |      |   |    |  |      |   |    |  |      |   |  |  |      |   |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 21.05 |   |    |  | 19.12 |   |    |  | 19.39 |   |  |  | 20.62 |   |  |  | 25.24 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Total Liquids  All Countries ($/bbl)                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 23.25 |   |    |  | 22.51 |   |    |  | 21.22 |   |  |  | 22.93 |   |  |  | 26.89 |  
|                                                      | Production and mineral taxes |                         |  | 0.45  |   |    |  | 0.59  |   |    |  | (0.35 | ) |  |  | 0.58  |   |  |  | 1.02  |  
|                                                      | Transportation and selling   |                         |  | 1.47  |   |    |  | 1.74  |   |    |  | 0.95  |   |  |  | 1.51  |   |  |  | 1.64  |  
|                                                      | Operating expenses           |                         |  | 4.93  |   |    |  | 4.75  |   |    |  | 5.01  |   |  |  | 5.22  |   |  |  | 4.77  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 16.40 |   |    |  | 15.43 |   |    |  | 15.61 |   |  |  | 15.62 |   |  |  | 19.46 |  
|                                                      | Financial hedge              |                         |  | (2.54 | ) |    |  | (2.15 | ) |    |  | (2.18 | ) |  |  | (1.61 | ) |  |  | (4.45 | )
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 13.86 |   |    |  | 13.28 |   |    |  | 13.43 |   |  |  | 14.01 |   |  |  | 15.01 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      

32



---



##### 



|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |  
|------------------------------------------------ | ---------------------------- | ----------------------- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                                 |                              |                        
|                                                 |                              | Per-Unit Results  2002
|                                                 |                              |                        
|                                                 |                              | Year                    |  | Q4    |   | Q3 |  | Q2    |   | Q1
|                                                 |                              |                         |  |       |   |    |  |       |   |   
|Produced Gas  Canada ($/Mcf)                    |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties(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 expenses           |                         |  | 0.41  |   |    |  | 0.44  |   |    |  | 0.42  |   |  |  | 0.40  |   |  |  | 0.31  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 2.13  |   |    |  | 2.79  |   |    |  | 1.62  |   |  |  | 2.22  |   |  |  | 1.58  |  
|                                                 | Financial hedge              |                         |  | 0.05  |   |    |  | (0.06 | ) |    |  | 0.21  |   |  |  | (0.08 | ) |  |  | 0.21  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 2.18  |   |    |  | 2.73  |   |    |  | 1.83  |   |  |  | 2.14  |   |  |  | 1.79  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Produced Gas  United States ($/Mcf)             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties(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 expenses           |                         |  | 0.28  |   |    |  | 0.23  |   |    |  | 0.28  |   |  |  | 0.31  |   |  |  | 0.60  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 1.94  |   |    |  | 2.45  |   |    |  | 1.52  |   |  |  | 1.74  |   |  |  | 1.47  |  
|                                                 | Financial hedge              |                         |  | 0.29  |   |    |  | 0.34  |   |    |  | 0.47  |   |  |  | 0.05  |   |  |  |      |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 2.23  |   |    |  | 2.79  |   |    |  | 1.99  |   |  |  | 1.79  |   |  |  | 1.47  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Produced Gas  Total North America
    ($/Mcf)   |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties(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 expenses           |                         |  | 0.39  |   |    |  | 0.40  |   |    |  | 0.39  |   |  |  | 0.39  |   |  |  | 0.32  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 2.09  |   |    |  | 2.73  |   |    |  | 1.59  |   |  |  | 2.13  |   |  |  | 1.58  |  
|                                                 | Financial hedge              |                         |  | 0.09  |   |    |  | 0.02  |   |    |  | 0.26  |   |  |  | (0.06 | ) |  |  | 0.20  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 2.18  |   |    |  | 2.75  |   |    |  | 1.85  |   |  |  | 2.07  |   |  |  | 1.78  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Light and Medium Oil  North America
    ($/bbl) |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 4.80  |   |    |  | 5.15  |   |    |  | 4.72  |   |  |  | 5.29  |   |  |  | 4.08  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 15.92 |   |    |  | 17.54 |   |    |  | 17.82 |   |  |  | 17.32 |   |  |  | 11.21 |  
|                                                 | Financial hedge              |                         |  | (0.83 | ) |    |  | (0.91 | ) |    |  | (0.64 | ) |  |  | (1.16 | ) |  |  | (0.62 | )
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 15.09 |   |    |  | 16.63 |   |    |  | 17.18 |   |  |  | 16.16 |   |  |  | 10.59 |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Heavy Oil  North America ($/bbl)                |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 4.58  |   |    |  | 4.12  |   |    |  | 4.96  |   |  |  | 4.39  |   |  |  | 5.73  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 12.37 |   |    |  | 11.79 |   |    |  | 13.87 |   |  |  | 12.85 |   |  |  | 7.36  |  
|                                                 | Financial hedge              |                         |  | (0.68 | ) |    |  | (0.84 | ) |    |  | (0.65 | ) |  |  | (0.55 | ) |  |  | (0.65 | )
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 11.69 |   |    |  | 10.95 |   |    |  | 13.22 |   |  |  | 12.30 |   |  |  | 6.71  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Total Oil  North America ($/bbl)                |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 4.69  |   |    |  | 4.55  |   |    |  | 4.85  |   |  |  | 4.81  |   |  |  | 4.48  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 14.14 |   |    |  | 14.20 |   |    |  | 15.65 |   |  |  | 14.93 |   |  |  | 10.28 |  
|                                                 | Financial hedge              |                         |  | (0.76 | ) |    |  | (0.87 | ) |    |  | (0.64 | ) |  |  | (0.83 | ) |  |  | (0.63 | )
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 13.38 |   |    |  | 13.33 |   |    |  | 15.01 |   |  |  | 14.10 |   |  |  | 9.65  |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Canada ($/bbl)             |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 17.55 |   |    |  | 21.75 |   |    |  | 17.61 |   |  |  | 17.41 |   |  |  | 11.56 |  
|                                                 | Transportation and selling   |                         |  |      |   |    |  |      |   |    |  |      |   |  |  |      |   |  |  |      |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback                      |                         |  | 17.55 |   |    |  | 21.75 |   |    |  | 17.61 |   |  |  | 17.41 |   |  |  | 11.56 |  
|                                                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      

33



---



##### 



|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |  
|----------------------------------------------------- | ---------------------------- | ----------------------- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                                      |                              |                        
|                                                      |                              | Per-Unit Results  2002
|                                                      |                              |                        
|                                                      |                              | Year                    |  | Q4    |   | Q3 |  | Q2    |   | Q1
|                                                      |                              |                         |  |       |   |    |  |       |   |   
|Natural Gas Liquids  United States
    ($/bbl)       |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 23.75 |   |    |  | 25.14 |   |    |  | 25.64 |   |  |  | 23.57 |   |  |  | 16.31 |  
|                                                      | Production and mineral taxes |                         |  | 1.02  |   |    |  | 0.94  |   |    |  | 1.32  |   |  |  | 1.37  |   |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback                      |                         |  | 22.73 |   |    |  | 24.20 |   |    |  | 24.32 |   |  |  | 22.20 |   |  |  | 16.31 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Total North
    America ($/bbl) |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 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 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Total Liquids  Canada ($/bbl)                        |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 4.19  |   |    |  | 4.06  |   |    |  | 4.38  |   |  |  | 4.32  |   |  |  | 3.93  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 14.51 |   |    |  | 15.00 |   |    |  | 15.84 |   |  |  | 15.18 |   |  |  | 10.42 |  
|                                                      | Financial hedge              |                         |  | (0.68 | ) |    |  | (0.77 | ) |    |  | (0.58 | ) |  |  | (0.75 | ) |  |  | (0.55 | )
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 13.83 |   |    |  | 14.23 |   |    |  | 15.26 |   |  |  | 14.43 |   |  |  | 9.87  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Ecuador Oil ($/bbl)                                   |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 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 expenses           |                         |  | 4.86  |   |    |  | 5.35  |   |    |  | 4.12  |   |  |  | 5.13  |   |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 14.47 |   |    |  | 15.11 |   |    |  | 14.74 |   |  |  | 13.70 |   |  |  |      |  
|                                                      | Financial hedge              |                         |  | (0.01 | ) |    |  |      |   |    |  |      |   |  |  | (0.03 | ) |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 14.46 |   |    |  | 15.11 |   |    |  | 14.74 |   |  |  | 13.67 |   |  |  |      |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|United Kingdom Oil ($/bbl)                            |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 24.76 |   |    |  | 25.73 |   |    |  | 27.07 |   |  |  | 25.92 |   |  |  | 21.18 |  
|                                                      | Transportation and selling   |                         |  | 1.69  |   |    |  | 1.53  |   |    |  | 1.92  |   |  |  | 1.62  |   |  |  | 1.65  |  
|                                                      | Operating expenses           |                         |  | 3.28  |   |    |  | 7.07  |   |    |  | 3.65  |   |  |  | 2.01  |   |  |  | 1.78  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 19.79 |   |    |  | 17.13 |   |    |  | 21.50 |   |  |  | 22.29 |   |  |  | 17.75 |  
|                                                      | Financial hedge              |                         |  | (0.06 | ) |    |  |      |   |    |  |      |   |  |  |      |   |  |  | (0.19 | )
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 19.73 |   |    |  | 17.13 |   |    |  | 21.50 |   |  |  | 22.29 |   |  |  | 17.56 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|Total Liquids  All Countries ($/bbl)                 |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 20.67 |   |    |  | 21.51 |   |    |  | 21.95 |   |  |  | 20.70 |   |  |  | 16.60 |  
|                                                      | Production and mineral taxes |                         |  | 0.53  |   |    |  | 0.66  |   |    |  | 0.50  |   |  |  | 0.25  |   |  |  | 0.87  |  
|                                                      | Transportation and selling   |                         |  | 0.97  |   |    |  | 1.10  |   |    |  | 1.18  |   |  |  | 0.76  |   |  |  | 0.71  |  
|                                                      | Operating expenses           |                         |  | 4.09  |   |    |  | 4.18  |   |    |  | 4.16  |   |  |  | 4.21  |   |  |  | 3.53  |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 15.08 |   |    |  | 15.57 |   |    |  | 16.11 |   |  |  | 15.48 |   |  |  | 11.49 |  
|                                                      | Financial hedge              |                         |  | (0.50 | ) |    |  | (0.57 | ) |    |  | (0.42 | ) |  |  | (0.53 | ) |  |  | (0.49 | )
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 14.58 |   |    |  | 15.00 |   |    |  | 15.69 |   |  |  | 14.95 |   |  |  | 11.00 |  
|                                                      |                              |                         |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |      




Notes:



|    |                                                                                                                                                                                                                               
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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.

34



---



##### 



|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |       |  
|------------------------------------------------ | ---------------------------- | ----------------------- |  | ----- |  | -- |  | ----- |  | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                                 |                              |                        
|                                                 |                              | Per-Unit Results  2001
|                                                 |                              |                        
|                                                 |                              | Year                    |  | Q4    |  | Q3 |  | Q2    |  | Q1
|                                                 |                              |                         |  |       |  |    |  |       |  |   
|Produced Gas  Canada ($/Mcf)                    |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 4.06  |  |    |  | 2.29  |  |    |  | 2.53  |   |  |  | 4.56  |   |  |  | 7.01  |  
|                                                 | Production and mineral taxes |                         |  | 0.14  |  |    |  | 0.14  |  |    |  | 0.09  |   |  |  | 0.10  |   |  |  | 0.24  |  
|                                                 | Transportation and selling   |                         |  | 0.21  |  |    |  | 0.23  |  |    |  | 0.21  |   |  |  | 0.18  |   |  |  | 0.21  |  
|                                                 | Operating expenses           |                         |  | 0.32  |  |    |  | 0.35  |  |    |  | 0.33  |   |  |  | 0.33  |   |  |  | 0.28  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 3.39  |  |    |  | 1.57  |  |    |  | 1.90  |   |  |  | 3.95  |   |  |  | 6.28  |  
|                                                 | Financial hedge              |                         |  | 0.38  |  |    |  | 0.68  |  |    |  | 1.39  |   |  |  | 0.28  |   |  |  | (0.87 | )
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 3.77  |  |    |  | 2.25  |  |    |  | 3.29  |   |  |  | 4.23  |   |  |  | 5.41  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Produced Gas  United States ($/Mcf)             |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 2.46  |  |    |  | 1.79  |  |    |  | 2.47  |   |  |  | 1.95  |   |  |  | 4.18  |  
|                                                 | Production and mineral taxes |                         |  | 0.49  |  |    |  | 0.29  |  |    |  | 0.30  |   |  |  | 0.60  |   |  |  | 1.01  |  
|                                                 | Transportation and selling   |                         |  |      |  |    |  |      |  |    |  |      |   |  |  |      |   |  |  |      |  
|                                                 | Operating expenses           |                         |  | 0.68  |  |    |  | 0.51  |  |    |  | 0.87  |   |  |  | 0.71  |   |  |  | 0.61  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 1.29  |  |    |  | 0.99  |  |    |  | 1.30  |   |  |  | 0.64  |   |  |  | 2.56  |  
|                                                 | Financial hedge              |                         |  |      |  |    |  |      |  |    |  |      |   |  |  |      |   |  |  |      |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 1.29  |  |    |  | 0.99  |  |    |  | 1.30  |   |  |  | 0.64  |   |  |  | 2.56  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Produced Gas  Total North America
    ($/Mcf)   |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 3.99  |  |    |  | 2.26  |  |    |  | 2.53  |   |  |  | 4.46  |   |  |  | 6.92  |  
|                                                 | Production and mineral taxes |                         |  | 0.15  |  |    |  | 0.15  |  |    |  | 0.10  |   |  |  | 0.12  |   |  |  | 0.26  |  
|                                                 | Transportation and selling   |                         |  | 0.20  |  |    |  | 0.22  |  |    |  | 0.20  |   |  |  | 0.17  |   |  |  | 0.20  |  
|                                                 | Operating expenses           |                         |  | 0.33  |  |    |  | 0.36  |  |    |  | 0.35  |   |  |  | 0.34  |   |  |  | 0.29  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 3.31  |  |    |  | 1.53  |  |    |  | 1.88  |   |  |  | 3.83  |   |  |  | 6.17  |  
|                                                 | Financial hedge              |                         |  | 0.36  |  |    |  | 0.64  |  |    |  | 1.33  |   |  |  | 0.27  |   |  |  | (0.84 | )
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 3.67  |  |    |  | 2.17  |  |    |  | 3.21  |   |  |  | 4.10  |   |  |  | 5.33  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Light and Medium Oil  North America
    ($/bbl) |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 19.31 |  |    |  | 12.56 |  |    |  | 22.62 |   |  |  | 20.54 |   |  |  | 21.29 |  
|                                                 | Production and mineral taxes |                         |  | 0.78  |  |    |  | 0.93  |  |    |  | 0.52  |   |  |  | 1.31  |   |  |  | 0.40  |  
|                                                 | Transportation and selling   |                         |  | 0.70  |  |    |  | 0.55  |  |    |  | 0.75  |   |  |  | 0.61  |   |  |  | 0.88  |  
|                                                 | Operating expenses           |                         |  | 4.78  |  |    |  | 4.25  |  |    |  | 4.71  |   |  |  | 5.35  |   |  |  | 4.81  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 13.05 |  |    |  | 6.83  |  |    |  | 16.64 |   |  |  | 13.27 |   |  |  | 15.20 |  
|                                                 | Financial hedge              |                         |  | 0.80  |  |    |  | 5.43  |  |    |  | (0.26 | ) |  |  | (0.59 | ) |  |  | (1.27 | )
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 13.85 |  |    |  | 12.26 |  |    |  | 16.38 |   |  |  | 12.68 |   |  |  | 13.93 |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Heavy Oil  North America ($/bbl)                |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 11.41 |  |    |  | 7.77  |  |    |  | 16.62 |   |  |  | 11.21 |   |  |  | 10.15 |  
|                                                 | Production and mineral taxes |                         |  | 0.50  |  |    |  | 0.43  |  |    |  | 0.39  |   |  |  | 0.65  |   |  |  | 0.54  |  
|                                                 | Transportation and selling   |                         |  | 0.12  |  |    |  | 0.11  |  |    |  | 0.14  |   |  |  | (0.02 | ) |  |  | 0.20  |  
|                                                 | Operating expenses           |                         |  | 6.63  |  |    |  | 6.89  |  |    |  | 5.68  |   |  |  | 8.06  |   |  |  | 6.15  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 4.16  |  |    |  | 0.34  |  |    |  | 10.41 |   |  |  | 2.52  |   |  |  | 3.26  |  
|                                                 | Financial hedge              |                         |  |      |  |    |  |      |  |    |  |      |   |  |  |      |   |  |  |      |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 4.16  |  |    |  | 0.34  |  |    |  | 10.41 |   |  |  | 2.52  |   |  |  | 3.26  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Total Oil  North America ($/bbl)                |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 17.35 |  |    |  | 11.33 |  |    |  | 21.16 |   |  |  | 18.46 |   |  |  | 18.28 |  
|                                                 | Production and mineral taxes |                         |  | 0.71  |  |    |  | 0.80  |  |    |  | 0.49  |   |  |  | 1.16  |   |  |  | 0.44  |  
|                                                 | Transportation and selling   |                         |  | 0.55  |  |    |  | 0.44  |  |    |  | 0.60  |   |  |  | 0.47  |   |  |  | 0.70  |  
|                                                 | Operating expenses           |                         |  | 5.24  |  |    |  | 4.93  |  |    |  | 4.95  |   |  |  | 5.96  |   |  |  | 5.17  |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback excluding hedge      |                         |  | 10.85 |  |    |  | 5.16  |  |    |  | 15.12 |   |  |  | 10.87 |   |  |  | 11.97 |  
|                                                 | Financial hedge              |                         |  | 0.60  |  |    |  | 4.04  |  |    |  | (0.20 | ) |  |  | (0.46 | ) |  |  | (0.93 | )
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback including hedge      |                         |  | 11.45 |  |    |  | 9.20  |  |    |  | 14.92 |   |  |  | 10.41 |   |  |  | 11.04 |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Canada ($/bbl)             |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Price, net of royalties      |                         |  | 19.70 |  |    |  | 13.25 |  |    |  | 18.24 |   |  |  | 22.30 |   |  |  | 25.42 |  
|                                                 | Transportation and selling   |                         |  |      |  |    |  |      |  |    |  |      |   |  |  |      |   |  |  |      |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                 | Netback                      |                         |  | 19.70 |  |    |  | 13.25 |  |    |  | 18.24 |   |  |  | 22.30 |   |  |  | 25.42 |  
|                                                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      

35



---



##### 



|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |       |  
|----------------------------------------------------- | ---------------------------- | ----------------------- |  | ----- |  | -- |  | ----- |  | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                                      |                              |                        
|                                                      |                              | Per-Unit Results  2001
|                                                      |                              |                        
|                                                      |                              | Year                    |  | Q4    |  | Q3 |  | Q2    |  | Q1
|                                                      |                              |                         |  |       |  |    |  |       |  |   
|Natural Gas Liquids  United States
    ($/bbl)       |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 22.22 |  |    |  | 16.75 |  |    |  | 20.90 |   |  |  | 24.40 |   |  |  | 27.08 |  
|                                                      | Production and mineral taxes |                         |  |      |  |    |  |      |  |    |  |      |   |  |  |      |   |  |  |      |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback                      |                         |  | 22.22 |  |    |  | 16.75 |  |    |  | 20.90 |   |  |  | 24.40 |   |  |  | 27.08 |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Total North
    America ($/bbl) |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 20.19 |  |    |  | 13.85 |  |    |  | 18.87 |   |  |  | 22.68 |   |  |  | 25.73 |  
|                                                      | Production and mineral taxes |                         |  |      |  |    |  |      |  |    |  |      |   |  |  |      |   |  |  |      |  
|                                                      | Transportation and selling   |                         |  |      |  |    |  |      |  |    |  |      |   |  |  |      |   |  |  |      |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback                      |                         |  | 20.19 |  |    |  | 13.85 |  |    |  | 18.87 |   |  |  | 22.68 |   |  |  | 25.73 |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Total Liquids  Canada ($/bbl)                        |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 17.61 |  |    |  | 11.56 |  |    |  | 20.86 |   |  |  | 18.90 |   |  |  | 19.06 |  
|                                                      | Production and mineral taxes |                         |  | 0.63  |  |    |  | 0.70  |  |    |  | 0.44  |   |  |  | 1.03  |   |  |  | 0.39  |  
|                                                      | Transportation and selling   |                         |  | 0.49  |  |    |  | 0.38  |  |    |  | 0.54  |   |  |  | 0.41  |   |  |  | 0.62  |  
|                                                      | Operating expenses           |                         |  | 4.65  |  |    |  | 4.33  |  |    |  | 4.44  |   |  |  | 5.27  |   |  |  | 4.60  |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 11.84 |  |    |  | 6.15  |  |    |  | 15.44 |   |  |  | 12.19 |   |  |  | 13.45 |  
|                                                      | Financial hedge              |                         |  | 0.53  |  |    |  | 3.55  |  |    |  | (0.18 | ) |  |  | (0.41 | ) |  |  | (0.83 | )
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 12.37 |  |    |  | 9.70  |  |    |  | 15.26 |   |  |  | 11.78 |   |  |  | 12.62 |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|United Kingdom Oil ($/bbl)                            |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 24.62 |  |    |  | 19.72 |  |    |  | 23.26 |   |  |  | 26.78 |   |  |  | 28.67 |  
|                                                      | Transportation and selling   |                         |  | 1.68  |  |    |  | 1.55  |  |    |  | 1.76  |   |  |  | 1.68  |   |  |  | 1.72  |  
|                                                      | Operating expenses           |                         |  | 2.69  |  |    |  | 4.00  |  |    |  | 2.04  |   |  |  | 1.83  |   |  |  | 3.09  |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 20.25 |  |    |  | 14.17 |  |    |  | 19.46 |   |  |  | 23.27 |   |  |  | 23.86 |  
|                                                      | Financial hedge              |                         |  | 0.46  |  |    |  | 4.59  |  |    |  | (0.77 | ) |  |  | (1.56 | ) |  |  | 0.05  |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 20.71 |  |    |  | 18.76 |  |    |  | 18.69 |   |  |  | 21.71 |   |  |  | 23.91 |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|Total Liquids  All Countries ($/bbl)                 |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Price, net of royalties      |                         |  | 18.44 |  |    |  | 12.52 |  |    |  | 21.11 |   |  |  | 19.85 |   |  |  | 20.19 |  
|                                                      | Production and mineral taxes |                         |  | 0.55  |  |    |  | 0.61  |  |    |  | 0.37  |   |  |  | 0.89  |   |  |  | 0.34  |  
|                                                      | Transportation and selling   |                         |  | 0.60  |  |    |  | 0.48  |  |    |  | 0.66  |   |  |  | 0.54  |   |  |  | 0.71  |  
|                                                      | Operating expenses           |                         |  | 4.31  |  |    |  | 4.16  |  |    |  | 4.02  |   |  |  | 4.77  |   |  |  | 4.33  |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback excluding hedge      |                         |  | 12.98 |  |    |  | 7.27  |  |    |  | 16.06 |   |  |  | 13.65 |   |  |  | 14.81 |  
|                                                      | Financial hedge              |                         |  | 0.51  |  |    |  | 3.54  |  |    |  | (0.24 | ) |  |  | (0.52 | ) |  |  | (0.72 | )
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      
|                                                      | Netback including hedge      |                         |  | 13.49 |  |    |  | 10.81 |  |    |  | 15.82 |   |  |  | 13.13 |   |  |  | 14.09 |  
|                                                      |                              |                         |  |       |  |    |  |       |  |    |  |       |   |  |  |       |   |  |  |      

36



---



##### 



Drilling Activity

The following tables summarize EnCanas
gross participation and net interest in wells drilled for 2001,
2002 and 2003.

Exploration Wells Drilled

|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     | 
|----- | -------------- | ----- | --- | --- |  | ----------- | --- | ------------- |  | ------- | --- | ----- |  | ----- | -- | --- |  | ----- | --- | ----- |  | --- | -- | -- |  |  | --- | --- |  |  | --- | --- |  |  | --- | --- |  |  | --- | --- |  |  | --- | --- | 
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |      
|      |                |       |     |     |  | Dry         |     | Total Working |  |         |     |      
|      |                | Gas   |     | Oil |  | & Abandoned |     | Interest      |  | Royalty |     | Total
|      |                |       |     |     |  |             |     |               |  |         |     |      
|      |                | Gross |     | Net |  | Gross       |     | Net           |  | Gross   |     | Net   |  | Gross |    | Net |  | Gross |     | Gross |  | Net
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |    
|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  | 
|      | Ecuador        |       |     |    |  |             |     |              |  |         |     | 3     |  |       |    | 2   |  |       |     |      |  |     |    |   |  |  |     | 3   |  |  |     | 2   |  |  |     |    |  |  |     | 3   |  |  |     | 2   | 
|      | United Kingdom |       |     |    |  |             |     |              |  |         |     | 2     |  |       |    | 1   |  |       |     | 5     |  |     |    | 3  |  |  |     | 7   |  |  |     | 4   |  |  |     |    |  |  |     | 7   |  |  |     | 4   | 
|      | Other          |       |     | 1   |  |             |     |              |  |         |     |      |  |       |    |    |  |       |     | 3     |  |     |    | 1  |  |  |     | 4   |  |  |     | 1   |  |  |     |    |  |  |     | 4   |  |  |     | 1   | 
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|Total |                |       | 573 |     |  |             | 546 |               |  |         | 63  |       |  |       | 36 |     |  |       | 47  |       |  |     | 34 |    |  |  | 683 |     |  |  | 616 |     |  |  | 153 |     |  |  | 836 |     |  |  | 616 |    
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|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  | 
|      | Ecuador        |       |     |    |  |             |     |              |  |         |     | 7     |  |       |    | 5   |  |       |     |      |  |     |    |   |  |  |     | 7   |  |  |     | 5   |  |  |     |    |  |  |     | 7   |  |  |     | 5   | 
|      | United Kingdom |       |     |    |  |             |     |              |  |         |     | 7     |  |       |    | 3   |  |       |     | 2     |  |     |    | 1  |  |  |     | 9   |  |  |     | 4   |  |  |     |    |  |  |     | 9   |  |  |     | 4   | 
|      | Other          |       |     |    |  |             |     |              |  |         |     |      |  |       |    |    |  |       |     | 4     |  |     |    | 2  |  |  |     | 4   |  |  |     | 2   |  |  |     |    |  |  |     | 4   |  |  |     | 2   | 
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|Total |                |       | 435 |     |  |             | 394 |               |  |         | 100 |       |  |       | 81 |     |  |       | 53  |       |  |     | 41 |    |  |  | 588 |     |  |  | 516 |     |  |  | 190 |     |  |  | 778 |     |  |  | 516 |    
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|2001: |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|      | Canada         |       |     | 403 |  |             |     | 328           |  |         |     | 81    |  |       |    | 59  |  |       |     | 105   |  |     |    | 90 |  |  |     | 589 |  |  |     | 477 |  |  |     | 260 |  |  |     | 849 |  |  |     | 477 | 
|      | United States  |       |     | 13  |  |             |     | 11            |  |         |     | 1     |  |       |    |    |  |       |     | 2     |  |     |    |   |  |  |     | 16  |  |  |     | 11  |  |  |     |    |  |  |     | 16  |  |  |     | 11  | 
|      | Ecuador        |       |     |    |  |             |     |              |  |         |     |      |  |       |    |    |  |       |     |      |  |     |    |   |  |  |     |    |  |  |     |    |  |  |     |    |  |  |     |    |  |  |     |    | 
|      | United Kingdom |       |     |    |  |             |     |              |  |         |     | 1     |  |       |    |    |  |       |     | 2     |  |     |    | 1  |  |  |     | 3   |  |  |     | 1   |  |  |     |    |  |  |     | 3   |  |  |     | 1   | 
|      | Other          |       |     |    |  |             |     |              |  |         |     |      |  |       |    |    |  |       |     | 4     |  |     |    | 1  |  |  |     | 4   |  |  |     | 1   |  |  |     |    |  |  |     | 4   |  |  |     | 1   | 
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    
|Total |                |       | 416 |     |  |             | 339 |               |  |         | 83  |       |  |       | 59 |     |  |       | 113 |       |  |     | 92 |    |  |  | 612 |     |  |  | 490 |     |  |  | 260 |     |  |  | 872 |     |  |  | 490 |    
|      |                |       |     |     |  |             |     |               |  |         |     |       |  |       |    |     |  |       |     |       |  |     |    |    |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |     |  |  |     |    

Development Wells Drilled

|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       | 
|----- | -------------- | ----- | ----- | ----- |  | ----------- | ----- | ------------- |  | ------- | --- | ----- |  | ----- | --- | --- |  | ----- | -- | ----- |  | --- | -- | -- |  |  | ----- | ----- |  |  | ----- | ----- |  |  | ----- | ----- |  |  | ----- | ----- |  |  | ----- | ----- | 
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |      
|      |                |       |       |       |  | Dry         |       | Total Working |  |         |     |      
|      |                | Gas   |       | Oil   |  | & Abandoned |       | Interest      |  | Royalty |     | Total
|      |                |       |       |       |  |             |       |               |  |         |     |      
|      |                | Gross |       | Net   |  | Gross       |       | Net           |  | Gross   |     | Net   |  | Gross |     | Net |  | Gross |    | Gross |  | Net
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |    
|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   | 
|      | Ecuador        |       |       |      |  |             |       |              |  |         |     | 53    |  |       |     | 39  |  |       |    | 6     |  |     |    | 6  |  |  |       | 59    |  |  |       | 45    |  |  |       |      |  |  |       | 59    |  |  |       | 45    | 
|      | United Kingdom |       |       |      |  |             |       |              |  |         |     | 3     |  |       |     |    |  |       |    |      |  |     |    |   |  |  |       | 3     |  |  |       |      |  |  |       |      |  |  |       | 3     |  |  |       |      | 
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|Total |                |       | 4,390 |       |  |             | 4,302 |               |  |         | 812 |       |  |       | 689 |     |  |       | 31 |       |  |     | 25 |    |  |  | 5,233 |       |  |  | 5,016 |       |  |  | 1,347 |       |  |  | 6,580 |       |  |  | 5,016 |      
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|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   | 
|      | Ecuador        |       |       |      |  |             |       |              |  |         |     | 44    |  |       |     | 37  |  |       |    | 5     |  |     |    | 4  |  |  |       | 49    |  |  |       | 41    |  |  |       |      |  |  |       | 49    |  |  |       | 41    | 
|      | United Kingdom |       |       |      |  |             |       |              |  |         |     | 2     |  |       |     |    |  |       |    |      |  |     |    |   |  |  |       | 2     |  |  |       |      |  |  |       |      |  |  |       | 2     |  |  |       |      | 
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|Total |                |       | 1,684 |       |  |             | 1,590 |               |  |         | 482 |       |  |       | 389 |     |  |       | 36 |       |  |     | 28 |    |  |  | 2,202 |       |  |  | 2,007 |       |  |  | 690   |       |  |  | 2,892 |       |  |  | 2,007 |      
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|2001: |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|      | Canada         |       |       | 1,125 |  |             |       | 1,052         |  |         |     | 333   |  |       |     | 198 |  |       |    | 35    |  |     |    | 29 |  |  |       | 1,493 |  |  |       | 1,279 |  |  |       | 1,227 |  |  |       | 2,720 |  |  |       | 1,279 | 
|      | United States  |       |       | 83    |  |             |       | 47            |  |         |     |      |  |       |     |    |  |       |    | 3     |  |     |    | 1  |  |  |       | 86    |  |  |       | 48    |  |  |       |      |  |  |       | 86    |  |  |       | 48    | 
|      | Ecuador        |       |       |      |  |             |       |              |  |         |     |      |  |       |     |    |  |       |    |      |  |     |    |   |  |  |       |      |  |  |       |      |  |  |       |      |  |  |       |      |  |  |       |      | 
|      | United Kingdom |       |       |      |  |             |       |              |  |         |     | 4     |  |       |     | 1   |  |       |    |      |  |     |    |   |  |  |       | 4     |  |  |       | 1     |  |  |       |      |  |  |       | 4     |  |  |       | 1     | 
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      
|Total |                |       | 1,208 |       |  |             | 1,099 |               |  |         | 337 |       |  |       | 199 |     |  |       | 38 |       |  |     | 30 |    |  |  | 1,583 |       |  |  | 1,328 |       |  |  | 1,227 |       |  |  | 2,810 |       |  |  | 1,328 |      
|      |                |       |       |       |  |             |       |               |  |         |     |       |  |       |     |     |  |       |    |       |  |     |    |    |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |       |  |  |       |      




Notes:



|    |                                                                                                                          
|--- | -------------------------------------------------------------------------------------------------------------------------
|(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.

At December 31, 2003, EnCana was in the
process of drilling 23 gross wells (21 net wells) in
Canada, 20 gross wells (20 net wells) in the United
States, 4 gross wells (1.9 net wells) in Ecuador,
1 gross well (0.3 net wells) in the United Kingdom and
2 gross wells (0.9 net wells) in other countries.

37



---



##### 



Location of Wells

The following table summarizes EnCanas
interest in producing wells and wells capable of producing as at
December 31, 2003:

Location of Wells

As at December 31, 2003


|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |        | 
|------------------- | ---------------- | ----- | ------ | ------ |  | ----- | ------ | ------ |  | ----- | ------ | ----- |  |  | ----- | ----- |  |  | ------ | ------ |  |  | ------ | ------ | 
|                    |                  |       |        |        |  |      
|                    |                  | Gas   |        | Oil    |  | Total
|                    |                  |       |        |        |  |      
|                    |                  | Gross |        | Net    |  | Gross |        | Net    |  | Gross |        | Net  
|                    |                  |       |        |        |  |       |        |        |  |       |        |      
|                    | Alberta          |       |        | 25,200 |  |       |        | 23,693 |  |       |        | 6,224 |  |  |       | 5,104 |  |  |        | 31,424 |  |  |        | 28,797 | 
|                    | British Columbia |       |        | 827    |  |       |        | 703    |  |       |        | 8     |  |  |       | 7     |  |  |        | 835    |  |  |        | 710    | 
|                    | Saskatchewan     |       |        | 548    |  |       |        | 400    |  |       |        | 3,571 |  |  |       | 1,832 |  |  |        | 4,119  |  |  |        | 2,232  | 
|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |       
|Total Canada        |                  |       | 26,575 |        |  |       | 24,796 |        |  |       | 9,803  |       |  |  | 6,943 |       |  |  | 36,378 |        |  |  | 31,739 |       
|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |       
|                    | Colorado         |       |        | 2,133  |  |       |        | 1,878  |  |       |        | 7     |  |  |       | 3     |  |  |        | 2,140  |  |  |        | 1,881  | 
|                    | Montana          |       |        | 44     |  |       |        | 39     |  |       |        |      |  |  |       |      |  |  |        | 44     |  |  |        | 39     | 
|                    | Texas            |       |        | 167    |  |       |        | 163    |  |       |        | 1     |  |  |       | 1     |  |  |        | 168    |  |  |        | 164    | 
|                    | Wyoming          |       |        | 543    |  |       |        | 363    |  |       |        | 1     |  |  |       | 1     |  |  |        | 544    |  |  |        | 364    | 
|                    | Gulf of Mexico   |       |        |       |  |       |        |       |  |       |        | 4     |  |  |       | 1     |  |  |        | 4      |  |  |        | 1      | 
|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |       
|Total United States |                  |       | 2,887  |        |  |       | 2,443  |        |  |       | 13     |       |  |  | 6     |       |  |  | 2,900  |        |  |  | 2,449  |       
|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |       
|United Kingdom      |                  |       | 1      |        |  |       |       |        |  |       | 38     |       |  |  | 11    |       |  |  | 39     |        |  |  | 11     |       
|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |       
|Ecuador             |                  |       |       |        |  |       |       |        |  |       | 231    |       |  |  | 189   |       |  |  | 231    |        |  |  | 189    |       
|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |       
|Total               |                  |       | 29,463 |        |  |       | 27,239 |        |  |       | 10,085 |       |  |  | 7,149 |       |  |  | 39,548 |        |  |  | 34,388 |       
|                    |                  |       |        |        |  |       |        |        |  |       |        |       |  |  |       |       |  |  |        |        |  |  |        |       




Notes:



|    |                                                                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | EnCana has varying royalty interests in
    8,715 crude oil wells and 11,661 natural gas wells which
    are producing or capable of producing.                   
|   
|(2) | Includes wells containing multiple completions as
    follows: 10,773 gross natural gas wells (9,953 net
    wells) and 321 gross crude oil wells (177 net wells).

Interest in Material Properties

The following table summarizes EnCanas
developed, undeveloped and total landholdings as at
December 31, 2003:

|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |       | 
|------------ | ----------------------- |  | ---------- | -------------------- |  | ----------- | ----- | ----- |  | --- | ----- | ----- |  | --- | ------ | ----- |  |  | ------ | ----- |  |  | ------ | ----- |  |  | ------ | ----- | 
|             |                         |  |            |                      |  |             |       |      
|             |                         |  |            | Developed            |  | Undeveloped |       | Total
|             |                         |  |            |                      |  |             |       |      
|             |                         |  |            | Gross                |  | Net         |       | Gross |  | Net |       | Gross |  | Net
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |    
|             |                         |  |            |                     
|             |                         |  |            | (thousands of acres)
|Canada       |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             | Alberta                 |  |            |  Fee                |  |             |       | 2,566 |  |     |       | 2,422 |  |     |        | 2,746 |  |  |        | 2,717 |  |  |        | 5,312 |  |  |        | 5,139 | 
|             |                         |  |  Crown    |                      |  |             | 3,710 |       |  |     | 3,149 |       |  |     | 6,986  |       |  |  | 5,978  |       |  |  | 10,696 |       |  |  | 9,127  |      
|             |                         |  |  Freehold |                      |  |             | 197   |       |  |     | 63    |       |  |     | 554    |       |  |  | 279    |       |  |  | 751    |       |  |  | 342    |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             |                         |  |            |                      |  |             | 6,473 |       |  |     | 5,634 |       |  |     | 10,286 |       |  |  | 8,974  |       |  |  | 16,759 |       |  |  | 14,608 |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             | British Columbia        |  |            |  Fee                |  |             |       |      |  |     |       |      |  |     |        | 7     |  |  |        | 7     |  |  |        | 7     |  |  |        | 7     | 
|             |                         |  |  Crown    |                      |  |             | 656   |       |  |     | 549   |       |  |     | 4,850  |       |  |  | 4,031  |       |  |  | 5,506  |       |  |  | 4,580  |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             |                         |  |            |                      |  |             | 656   |       |  |     | 549   |       |  |     | 4,857  |       |  |  | 4,038  |       |  |  | 5,513  |       |  |  | 4,587  |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             | Saskatchewan            |  |            |  Fee                |  |             |       | 12    |  |     |       | 10    |  |     |        | 481   |  |  |        | 467   |  |  |        | 493   |  |  |        | 477   | 
|             |                         |  |  Crown    |                      |  |             | 345   |       |  |     | 214   |       |  |     | 1,326  |       |  |  | 1,128  |       |  |  | 1,671  |       |  |  | 1,342  |      
|             |                         |  |  Freehold |                      |  |             | 73    |       |  |     | 37    |       |  |     | 235    |       |  |  | 157    |       |  |  | 308    |       |  |  | 194    |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             |                         |  |            |                      |  |             | 430   |       |  |     | 261   |       |  |     | 2,042  |       |  |  | 1,752  |       |  |  | 2,472  |       |  |  | 2,013  |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             | Manitoba                |  |            |  Fee                |  |             |       |      |  |     |       |      |  |     |        | 271   |  |  |        | 266   |  |  |        | 271   |  |  |        | 266   | 
|             |                         |  |  Crown    |                      |  |             |      |       |  |     |      |       |  |     | 30     |       |  |  | 30     |       |  |  | 30     |       |  |  | 30     |      
|             |                         |  |  Freehold |                      |  |             |      |       |  |     |      |       |  |     | 23     |       |  |  | 23     |       |  |  | 23     |       |  |  | 23     |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             |                         |  |            |                      |  |             |      |       |  |     |      |       |  |     | 324    |       |  |  | 319    |       |  |  | 324    |       |  |  | 319    |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|             | Nova Scotia             |  |            |  Crown              |  |             |       |      |  |     |       |      |  |     |        | 4,404 |  |  |        | 2,988 |  |  |        | 4,404 |  |  |        | 2,988 | 
|             | Newfoundland & Labrador |  |            |  Crown              |  |             |       |      |  |     |       |      |  |     |        | 4,294 |  |  |        | 2,781 |  |  |        | 4,294 |  |  |        | 2,781 | 
|             | Northwest Territories   |  |            |  Crown              |  |             |       |      |  |     |       |      |  |     |        | 1,019 |  |  |        | 459   |  |  |        | 1,019 |  |  |        | 459   | 
|             | Nunavut                 |  |            |  Crown              |  |             |       |      |  |     |       |      |  |     |        | 817   |  |  |        | 26    |  |  |        | 817   |  |  |        | 26    | 
|             | Beaufort                |  |            |  Crown              |  |             |       |      |  |     |       |      |  |     |        | 126   |  |  |        | 4     |  |  |        | 126   |  |  |        | 4     | 
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      
|Total Canada |                         |  |            |                      |  |             | 7,559 |       |  |     | 6,444 |       |  |     | 28,169 |       |  |  | 21,341 |       |  |  | 35,728 |       |  |  | 27,785 |      
|             |                         |  |            |                      |  |             |       |       |  |     |       |       |  |     |        |       |  |  |        |       |  |  |        |       |  |  |        |      

38



---



##### 



|                    |                 |  |                  |                        |  |             |       |       |  |     |       |       |  |     |         |       |  |  |         |     |  |  |         |       |  |  |         |     | 
|------------------- | --------------- |  | ---------------- | ---------------------- |  | ----------- | ----- | ----- |  | --- | ----- | ----- |  | --- | ------- | ----- |  |  | ------- | --- |  |  | ------- | ----- |  |  | ------- | --- | 
|                    |                 |  |                  |                        |  |             |       |      
|                    |                 |  |                  | Developed              |  | Undeveloped |       | Total
|                    |                 |  |                  |                        |  |             |       |      
|                    |                 |  |                  | Gross                  |  | Net         |       | Gross |  | Net |       | Gross |  | Net
|                    |                 |  |                  |                        |  |             |       |       |  |     |       |       |  |    
|                    |                 |  |                  |                       
|                    |                 |  |                  | (thousands of acres)  
|United States       |                 |  |                  |                        |  |             |       |       |  |     |       |       |  |     |         |       |  |  |         |     |  |  |         |       |  |  |         |    
|                    | Colorado        |  |                  |  Federal/ State Lands |  |             |       | 173   |  |     |       | 144   |  |     |         | 439   |  |  |         | 381 |  |  |         | 612   |  |  |         | 525 | 
|                    |                 |  |  Freehold       |                        |  |             | 84    |       |  |     | 70    |       |  |     | 215     |       |  |  | 186     |     |  |  | 299     |       |  |  | 256     |    
|                    |                 |  |  Fee            |                        |  |             | 4 261 |       |  |     | 3 217 |       |  |     | 9 663   |       |  |  | 8 575   |     |  |  | 13 924  |       |  |  | 11 792  |    
|                    |                 |  |  Federal/ State |                        |  |             | 58    |       |  |     | 23    |       |  |     | 640     |       |  |  | 463     |     |  |  | 698     |       |  |  | 486     |    
|                    | Wyoming         |  |                  | Lands  Freehold       |  |             |       | 4     |  |     |       | 2     |  |     |         | 46    |  |  |         | 33  |  |  |         | 50    |  |  |         | 35  | 
|                    |                 |  |                  |                        |  |             | 62    |       |  |     | 25    |       |  |     | 686     |       |  |  | 496     |     |  |  | 748     |       |  |  | 521     |    
|                    |                 |  |  Federal/ State |                        |  |             |      |       |  |     |      |       |  |     | 1,794   |       |  |  | 802     |     |  |  | 1,794   |       |  |  | 802     |    
|                    | Alaska          |  |                  | Lands  Federal/ State |  |             |       |      |  |     |       |      |  |     |         | 1,511 |  |  |         | 663 |  |  |         | 1,511 |  |  |         | 663 | 
|                    | Gulf of Mexico. |  |                  | Lands  Federal Lands  |  |             |       | 10    |  |     |       | 7     |  |     |         | 320   |  |  |         | 270 |  |  |         | 330   |  |  |         | 277 | 
|                    | Other           |  |                  |  Freehold             |  |             |       | 18    |  |     |       | 12    |  |     |         | 259   |  |  |         | 126 |  |  |         | 277   |  |  |         | 138 | 
|                    |                 |  |                  |                        |  |             | 28    |       |  |     | 19    |       |  |     | 579     |       |  |  | 396     |     |  |  | 607     |       |  |  | 415     |    
|                    |                 |  |                  |                        |  |             | 351   |       |  |     | 261   |       |  |     | 5,233   |       |  |  | 2,932   |     |  |  | 5,584   |       |  |  | 3,193   |    
|Total United States |                 |  |                  |                        |  |             | 141   |       |  |     | 80    |       |  |     | 1,258   |       |  |  | 811     |     |  |  | 1,399   |       |  |  | 891     |    
|Ecuador             |                 |  |                  |                        |  |             | 44    |       |  |     | 12    |       |  |     | 1,822   |       |  |  | 744     |     |  |  | 1,866   |       |  |  | 756     |    
|United Kingdom      |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 108,536 |       |  |  | 54,268  |     |  |  | 108,536 |       |  |  | 54,268  |    
|Chad                |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 9,606   |       |  |  | 9,606   |     |  |  | 9,606   |       |  |  | 9,606   |    
|Oman                |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 18,396  |       |  |  | 6,512   |     |  |  | 18,396  |       |  |  | 6,512   |    
|Australia           |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 2,758   |       |  |  | 2,758   |     |  |  | 2,758   |       |  |  | 2,758   |    
|Qatar               |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 3,677   |       |  |  | 1,471   |     |  |  | 3,677   |       |  |  | 1,471   |    
|Ghana               |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 1,879   |       |  |  | 987     |     |  |  | 1,879   |       |  |  | 987     |    
|Yemen               |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 985     |       |  |  | 862     |     |  |  | 985     |       |  |  | 862     |    
|Greenland           |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 161     |       |  |  | 108     |     |  |  | 161     |       |  |  | 108     |    
|Brazil              |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 97      |       |  |  | 48      |     |  |  | 97      |       |  |  | 48      |    
|Bahrain             |                 |  |                  |                        |  |             |      |       |  |     |      |       |  |     | 346     |       |  |  | 17      |     |  |  | 346     |       |  |  | 17      |    
|Azerbaijan          |                 |  |                  |                        |  |             | 185   |       |  |     | 92    |       |  |     | 149,521 |       |  |  | 78,192  |     |  |  | 149,706 |       |  |  | 78,284  |    
|Total International |                 |  |                  |                        |  |             | 8,095 |       |  |     | 6,797 |       |  |     | 182,923 |       |  |  | 102,465 |     |  |  | 191,018 |       |  |  | 109,262 |    
|Total               |                 |  |                  |                        |  |             |       |       |  |     |       |       |  |     |         |       |  |  |         |     |  |  |         |       |  |  |         |    
|                    |                 |  |                  |                        |  |             |       |       |  |     |       |       |  |     |         |       |  |  |         |     |  |  |         |       |  |  |         |    




Notes:



|    |                                                                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | This table excludes approximately
    3.6 million gross acres under lease or sublease, reserving
    to EnCana royalties or other interests.                                       
|   
|(2) | Fee lands are those in which EnCana owns mineral
    rights and in which it retains a working interest.                                                                            
|   
|(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.                                                                                                          

39



---



##### 



Acquisitions, Dispositions and Capital
Expenditures

EnCanas growth in recent years has been
achieved through both internal growth and acquisitions. EnCana
has a large inventory of internal growth opportunities and also
continues to examine acquisition opportunities to develop and
expand its business. The acquisition opportunities may include
significant corporate or asset acquisitions and EnCana may
finance any such acquisitions with debt or equity or a
combination of both.

The following table summarizes EnCanas net
capital investment for 2002 and 2003. Information for 2002 is
presented on the basis of combining the results for PanCanadian
and AEC for the period prior to the Merger.

Net Capital Investment

($ million)


|                                                   |                       |           |        |       |     |  |       |       |     | 
|-------------------------------------------------- | --------------------- | --------- | ------ | ----- | --- |  | ----- | ----- | --- | 
|                                                   |                       | 2003      |        | 2002 
|                                                   |                       |           |        |      
|Upstream                                           |                       |           |        |       |     |  |       |      
|                                                   | Canada                |           |        | 2,937 |     |  |       | 1,601 |    
|                                                   | United States         |           |        | 830   |     |  |       | 616   |    
|                                                   | Ecuador               |           |        | 265   |     |  |       | 212   |    
|                                                   | United Kingdom        |           |        | 112   |     |  |       | 82    |    
|                                                   | Other Countries       |           |        | 78    |     |  |       | 113   |    
|                                                   |                       |           |        |       |     |  |       |      
|                                                   |                       |           | 4,222  |       |     |  | 2,624 |      
|Midstream & Marketing                              |                       |           | 223    |       |     |  | 51    |      
|Corporate                                          |                       |           | 57     |       |     |  | 46    |      
|                                                   |                       |           |        |       |     |  |       |      
|Core Capital                                       |                       |           | 4,502  |       |     |  | 2,721 |      
|Acquisitions                                       |                       |           |        |       |     |  |       |      
|                                                   | Upstream              |           |        |       |     |  |       |       |    
|                                                   |                       | Property  |        |       | 510 |  |       |       | 786 | 
|                                                   |                       | Corporate |        |       | 207 |  |       |       |    | 
|                                                   | Midstream & Marketing |           |        | 53    |     |  |       |      |    
|                                                   | Corporate             |           |        | 50    |     |  |       |      |    
|Dispositions                                       |                       |           |        |       |     |  |       |      
|                                                   | Upstream              |           |        | (301  | )   |  |       | (385  | )  
|                                                   | Corporate             |           |        | (14   | )   |  |       | (60   | )  
|                                                   |                       |           |        |       |     |  |       |      
|Net Capital Investment  Continuing
    Operations |                       |           | 5,007  |       |     |  | 3,062 |      
|Discontinued Operations                            |                       |           | (1,585 | )     |     |  | 172   |      
|                                                   |                       |           |        |       |     |  |       |      
|Total Net Capital Investment                       |                       |           | 3,422  |       |     |  | 3,234 |      
|                                                   |                       |           |        |       |     |  |       |      

As part of a regular dispositions program, EnCana
plans to dispose of approximately $365 million of non-core
assets in 2004, which includes EnCanas interest in
Petrovera sold in February 2004.

Delivery Commitments

As part of ordinary business operations, EnCana
has a number of delivery commitments to provide crude oil and
natural gas under existing contracts and agreements. These
commitments comprise a small portion of EnCanas total
revenues and the Corporation has sufficient reserves to meet
these commitments. More detailed information relating to such
commitments can be found in Note 19 to EnCanas
audited consolidated financial statements for the year ended
December 31, 2003.

40



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##### 



GENERAL

Competitive Conditions

All aspects of the oil and natural gas industry
are highly competitive and EnCana actively competes with oil and
natural gas and other companies for reserve acquisitions,
exploration leases, licenses and concessions, midstream assets
and industry personnel.

Environmental Protection

EnCanas worldwide operations are subject to
government laws and regulations concerning pollution, protection
of the environment and the handling and transport of hazardous
materials. These laws and regulations generally require EnCana
to remove or remedy the effect of its activities on the
environment at present and former operating sites, including
dismantling production facilities and remediating damage caused
by the use or release of specified substances. The Corporate
Responsibility, Environment, Health and 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.

EnCana expects to incur abandonment and site
reclamation costs as existing oil and gas properties are
abandoned and reclaimed. EnCana does not anticipate making
material expenditures for compliance with environmental
regulations in 2004. In 2003, the Corporation adopted Canadian
Institute of Chartered Accountants Handbook Section 3110
Asset Retirement Obligations, whereby the
Corporation includes the fair value of future asset retirement
obligations for abandonment and reclamation costs in the audited
consolidated financial statements.

Based on EnCanas current estimate, the
total anticipated undiscounted future cost of abandonment and
reclamation costs to be incurred over the life of the reserves
is estimated at $3.2 billion.

Employees

At December 31, 2003, EnCana employed 3,854
full time equivalent (FTE) employees as set forth in
the following table:

|                      |  |                   |       | 
|--------------------- |  | ----------------- | ----- | 
|                      |  | Number of        
|                      |  | FTE Employees    
|                      |  | As at            
|                      |  | December 31, 2003
|                      |  |                  
|Upstream              |  |                   | 2,808 | 
|Midstream & Marketing |  |                   | 280   | 
|Corporate             |  |                   | 766   | 
|                      |  |                   |       | 
|Total                 |  |                   | 3,854 | 
|                      |  |                   |       | 

Foreign Operations

As at December 31, 2003, approximately
90 percent of EnCanas reserves and production were
located in North America, which limits EnCanas exposure to
risks and uncertainties in countries considered politically and
economically unstable. EnCanas operations and related
assets outside North America may be adversely affected by
changes in governmental policy, social instability or other
political or economic developments which are not within the
control of EnCana, including the expropriation of property, the
cancellation or modification of contract rights and restrictions
on repatriation of cash. The Corporation has undertaken to
mitigate these risks where practical and considered warranted.

41



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##### 



SELECTED CONSOLIDATED FINANCIAL
INFORMATION

The following sets forth selected financial
information for EnCana for the periods indicated. The
information for EnCana includes the results of AEC from the
closing date of the Merger. As such, the amounts reported for
EnCana for the year ended December 31, 2002 reflect
12 months of PanCanadian or EnCana results, combined with
the nine months of post-Merger AEC results. The amounts for
EnCana for 2001 represent solely the results of PanCanadian.

|                                                   |                     |                             |        |      |  |      |        |      |  |  |       |      | 
|-------------------------------------------------- | ------------------- | --------------------------- | ------ | ---- |  | ---- | ------ | ---- |  |  | ----- | ---- | 
|                                                   |                     |                            
|                                                   |                     | Year Ended December 31     
|                                                   |                     |                            
|                                                   |                     | 2003                        |        | 2002 |  | 2001
|                                                   |                     |                             |        |      |  |     
|                                                   |                     |                            
|                                                   |                     | ($million, except per share
|                                                   |                     | amounts)                   
|Revenues, net of royalties                         |                     |                             | 10,216 |      |  |      | 6,276  |      |  |  | 3,244 |     
|Cash flow from continuing
    operations(3,5)      |                     |                             | 4,420  |      |  |      | 2,267  |      |  |  | 1,463 |     
|Cash flow(5)                                       |                     |                             | 4,459  |      |  |      | 2,419  |      |  |  | 1,494 |     
|Net earnings from continuing
    operations(1,2,3) |                     |                             | 2,167  |      |  |      | 735    |      |  |  | 832   |     
|Net earnings(1,2)                                  |                     |                             | 2,360  |      |  |      | 812    |      |  |  | 854   |     
|Total assets                                       |                     |                             | 24,110 |      |  |      | 19,912 |      |  |  | 6,823 |     
|Long-term debt                                     |                     |                             | 6,088  |      |  |      | 5,051  |      |  |  | 1,467 |     
|Cash dividends(4)                                  |                     |                             | 139    |      |  |      | 108    |      |  |  | 818   |     
|Per Share
    Data(1,2)                            |                     |                             |        |      |  |      |        |      |  |  |       |     
|Cash flow from continuing operations(5)            |                     |                             |        |      |  |      |        |      |  |  |       |     
|                                                   | Per share  basic   |                             |        | 9.32 |  |      |        | 5.43 |  |  |       | 5.72 | 
|                                                   | Per share  diluted |                             |        | 9.21 |  |      |        | 5.36 |  |  |       | 5.65 | 
|Cash flow(5)                                       |                     |                             |        |      |  |      |        |      |  |  |       |     
|                                                   | Per share  basic   |                             |        | 9.41 |  |      |        | 5.79 |  |  |       | 5.85 | 
|                                                   | Per share  diluted |                             |        | 9.30 |  |      |        | 5.72 |  |  |       | 5.77 | 
|Net earnings from continuing operations            |                     |                             |        |      |  |      |        |      |  |  |       |     
|                                                   | Per share  basic   |                             |        | 4.57 |  |      |        | 1.76 |  |  |       | 3.26 | 
|                                                   | Per share  diluted |                             |        | 4.52 |  |      |        | 1.74 |  |  |       | 3.21 | 
|Net earnings                                       |                     |                             |        |      |  |      |        |      |  |  |       |     
|                                                   | Per share  basic   |                             |        | 4.98 |  |      |        | 1.94 |  |  |       | 3.34 | 
|                                                   | Per share  diluted |                             |        | 4.92 |  |      |        | 1.92 |  |  |       | 3.30 | 




Notes:



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | In accordance with Canadian GAAP, the Corporation
    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
    or, in the case of long-term debt held by self-sustaining
    operations, in the currency translation adjustment account
    included in Shareholders Equity in the Consolidated
    Balance Sheet. As a result, 2003 net earnings includes an
    after-tax unrealized foreign exchange gain of $433 million
    (2002  $17 million gain; 2001 
    $28 million loss).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|   
|(2) | Canadian GAAP requires the Corporation to
    recognize impacts of tax rate changes that are substantively
    enacted. Gains or losses from these changes are recorded in the
    Consolidated Statement of Earnings and included as an adjustment
    to Future Income Taxes in the Consolidated Balance Sheet. Tax
    rate reductions increased 2003 net earnings by $359 million
    (2002  $20 million; 2001 
    $53 million).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|   
|(3) | Following the Merger, the Corporation determined
    to discontinue the Houston-based merchant energy operation of a
    subsidiary of its predecessor company, PanCanadian, which was
    included in the Midstream & Marketing segment. Accordingly,
    these operations were accounted for as discontinued operations.
    On July 9, 2002, the Corporation announced that it planned
    to sell its 70 percent equity investment in Cold Lake and
    its 100 percent interest in Express. Both crude oil
    pipeline systems were acquired in the business combination with
    AEC on April 5, 2002. These sales were completed in January
    2003 for $1.0 billion (C$1.6 billion), including the
    assumption of debt, with a resulting after-tax gain on sale of
    $169 million. Accordingly, these operations were accounted
    for as discontinued operations. On February 28, 2003, the
    Corporation completed the sale of its 10 percent working
    interest in Syncrude to COS for net cash consideration of
    $690 million (C$1,026 million), subject to
    post-closing adjustments. On July 10, 2003 the Corporation
    completed the sale of its remaining 3.75 percent interest
    in Syncrude and a gross overriding royalty for net cash
    consideration of $309 million (C$427 million), subject
    to post-closing adjustments. This transaction completed the
    Corporations disposition of its interests in Syncrude and,
    as a result, these operations have been accounted for as
    discontinued operations.

42



---



##### 





|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | Represents cash dividends paid to common
    shareholders at a rate of C$0.40 per share annually. As part of
    the CPL reorganization, the Corporation paid a Special Dividend
    of $754 million (C$1,180 million or C$4.60 per common
    share) on September 14, 2001. The amounts shown as
    dividends on the Consolidated Statements of Retained Earnings
    and Cash Flows include both the Special Dividend and the
    quarterly dividend. EnCanas Board of Directors has
    declared a dividend of $0.10 per share payable on March 31,
    2004 to common shareholders of record on March 15, 2004.
    EnCanas dividend policy is examined annually by the Board
    of Directors.                                                                                                                                                                                                                                                                
|   
|(5) | 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, Cash Flow per share-diluted are not measures that
    have any standardized meaning prescribed by Canadian GAAP and
    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 annual information form in order to provide shareholders
    and potential investors with additional information regarding
    the Corporations liquidity and its ability to generate
    funds to finance its operations. Management utilizes Cash Flow
    and Cash Flow from Continuing Operations as key measures to
    assess the ability of the Corporation to finance operating
    activities and capital expenditures.

MANAGEMENTS DISCUSSION AND
ANALYSIS

Managements Discussion and Analysis for the
year ended December 31, 2003, accompanying the 2003 audited
consolidated financial statements, is incorporated by reference.

MARKET FOR SECURITIES

All of the outstanding common shares of EnCana
are listed and posted for trading on the Toronto Stock Exchange
and the New York Stock Exchange. The Corporations Coupon
Reset Subordinated Term Securities, Series A (Term
Securities) and 8.50 percent Preferred Securities are
listed and posted for trading on the Toronto Stock Exchange and
the Corporations 9.50 percent Preferred Securities
are listed and posted for trading on the New York Stock Exchange.

In February 2004, EnCana announced its intention
to redeem all of the Term Securities on March 23, 2004.

43



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##### 



DIRECTORS AND OFFICERS

The following information is provided for each
director and executive officer of EnCana as at the date of this
annual information form:

Directors

|                                       |  |           |  |                                                                                                                                      
|-------------------------------------- |  | --------- |  | -------------------------------------------------------------------------------------------------------------------------------------
|                                       |  | Director  |  |                                                                                                                                      
|Name and Municipality of Residence     |  | Since(13) |  | Principal Occupation                                                                                                                 
|                                       |  |           |  |                                                                                                                                      
|MICHAEL N. CHERNOFF(2,6)               |  | 1999      |  | Corporate Director                                                                                                                   
|West Vancouver, British Columbia       |  |           |  |                                                                                                                                      
|                                      
|RALPH S. CUNNINGHAM(2,3)               |  | 2003      |  | Corporate Director                                                                                                                   
|Montgomery, Texas                      |  |           |  |                                                                                                                                      
|                                      
|PATRICK D. DANIEL(1,5)                 |  | 2001      |  | President & Chief Executive Officer                                                                                                  
|Calgary, Alberta                       |  |           |  | Enbridge Inc.(Energy, transportation and services)                                                                                   
|                                      
|IAN W. DELANEY(3,4)                    |  | 1999      |  | Chairman of the Board                                                                                                                
|Toronto, Ontario                       |  |           |  | 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                       |  |           |  | Fairmont Hotels & Resorts Inc.(Hotels)                                                                                               
|                                      
|MICHAEL A. GRANDIN(3,5,6,9)            |  | 1998      |  | Chairman & Chief Executive Officer                                                                                                   
|Calgary, Alberta                       |  |           |  | Fording Canadian Coal Trust(Metallurgical coal)                                                                                      
|                                      
|BARRY W. HARRISON(1,4,10)              |  | 1996      |  | Corporate Director and independent businessman                                                                                       
|Calgary, Alberta                       |  |           |  |                                                                                                                                      
|                                      
|RICHARD F. HASKAYNE, O.C., F.C.A.(3,4) |  | 1992      |  | Chairman of the Board                                                                                                                
|Calgary, Alberta                       |  |           |  | TransCanada Corporation(Pipelines and energy services)                                                                               
|                                      
|DALE A. LUCAS(1,5)                     |  | 1997      |  | Corporate Director                                                                                                                   
|Calgary, Alberta                       |  |           |  |                                                                                                                                      
|                                      
|KEN F. MCCREADY(2,5,11)                |  | 1992      |  | President                                                                                                                            
|Calgary, Alberta                       |  |           |  | K.F. McCready & Associates Ltd.(Sustainable energy development consulting company)                                                   
|                                      
|GWYN MORGAN                            |  | 1993      |  | President & Chief Executive Officer                                                                                                  
|Calgary, Alberta                       |  |           |  | EnCana Corporation                                                                                                                   
|                                      
|VALERIE A.A. NIELSEN(2,6)              |  | 1990      |  | Corporate Director                                                                                                                   
|Calgary, Alberta                       |  |           |  |                                                                                                                                      
|                                      
|DAVID P. OBRIEN(4,7,12)               |  | 1990      |  | Chairman                                                                                                                             
|Calgary, Alberta                       |  |           |  | EnCana Corporation                                                                                                                   

44



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##### 



|                                   |  |           |  |                                                                    
|---------------------------------- |  | --------- |  | -------------------------------------------------------------------
|                                   |  | Director  |  |                                                                    
|Name and Municipality of Residence |  | Since(13) |  | Principal Occupation                                               
|                                   |  |           |  |                                                                    
|                                  
|JANE L. PEVERETT(1)                |  | 2003      |  | Chief Financial Officer                                            
|West Vancouver, British Columbia   |  |           |  | British Columbia Transmission Corporation(Electricity transmission)
|                                  
|DENNIS A. SHARP(2,4)               |  | 1998      |  | Chairman & Chief Executive Officer                                 
|Calgary, Alberta                   |  |           |  | UTS Energy Corporation(Oil and natural gas company)                
|                                  
|JAMES M. STANFORD(1,3,6)           |  | 2001      |  | President                                                          
|Calgary, Alberta                   |  |           |  | Stanford Resource Management Inc.(Investment management)           




Notes:



|     |                                                                                                                                                                                                                                                                                                                                                                         
|---- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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. in 1995 when it made a filing pursuant to
    the Companies Creditors Arrangement Act(Canada).                                                                                                                                                                                                               
|    
|(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.                                                                                                                                                                                     
|    
|(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.
|    
|(13) | Denotes the year each individual became a
    director of AEC or PanCanadian, if prior to the Merger, or
    EnCana, if after the Merger.                                                                                                                                                                                                                               

EnCana does not have an Executive Committee of
its Board of Directors.

At the date of this annual information form,
there are 16 directors of the Corporation. At the next Annual
Meeting of Shareholders, shareholders will be asked to elect as
directors the 16 nominees listed in the above table to serve
until the close of the next annual meeting of shareholders, or
until their respective successors are duly elected or appointed.
Subject to mandatory retirement age restrictions which have been
established by the Board of Directors, all of the directors
shall be eligible for re-election.

45



---



##### 



Executive Officers

|                                   |  |                                                       
|---------------------------------- |  | ------------------------------------------------------
|Name and Municipality of Residence |  | Office                                                
|                                   |  |                                                       
|GWYN MORGAN                        |  | President & Chief Executive Officer                   
|Calgary, Alberta                   |  |                                                       
|                                  
|RANDALL K. ERESMAN                 |  | Executive Vice-President & Chief Operating
    Officer
|Calgary, Alberta                   |  |                                                       
|                                  
|ROGER J. BIEMANS                   |  | Executive Vice-President                              
|Denver, Colorado                   |  |                                                       
|                                  
|BRIAN C. FERGUSON                  |  | Executive Vice-President, Corporate Development       
|Calgary, Alberta                   |  |                                                       
|                                  
|GERALD J. MACEY                    |  | Executive Vice-President                              
|Calgary, Alberta                   |  |                                                       
|                                  
|R. WILLIAM OLIVER                  |  | Executive Vice-President                              
|Calgary, Alberta                   |  |                                                       
|                                  
|GERARD J. PROTTI                   |  | Executive Vice-President, Corporate Relations         
|Calgary, Alberta                   |  |                                                       
|                                  
|DRUDE RIMELL                       |  | Executive Vice-President, Corporate Services          
|Calgary, Alberta                   |  |                                                       
|                                  
|JOHN D. WATSON                     |  | Executive Vice-President & Chief Financial
    Officer
|Calgary, Alberta                   |  |                                                       

During the last five years, all of the directors
and executive officers have served in various capacities with
EnCana or its predecessor companies or have held the principal
occupation indicated opposite their names except for the
following:

Mr. Chernoff was President of Pacalta
Resources Ltd. from 1988 to 1996 and Chairman of the Board of
that company from 1988 to May 1999.

Mr. Daniel was President and Chief Operating
Officer of Interprovincial Pipe Line Corporation from May 1994
to January 2001.

Mr. Fatt was Chairman and Chief Executive
Officer of FHR Holdings Inc. (formerly Canadian Pacific Hotels
& Resorts Inc.) from January 1998 to October 2001.

Mr. Grandin was President of PanCanadian
Energy Corporation from October 2001 to April 2002. He was
Executive Vice-President and Chief Financial Officer of Canadian
Pacific Limited from December 1997 to October 2001.

Mr. OBrien was Chairman and Chief
Executive Officer of PanCanadian Energy Corporation from October
2001 to April 2002 and Chairman, President and Chief Executive
Officer of Canadian Pacific Limited from May 1996 to October
2001.

Ms. Peverett was President of Union Gas
Limited from April 2002 to May 2003, was President and Chief
Executive Officer from April 2001 to April 2002, was Senior Vice
President Sales & Marketing from June 2000 to April 2001,
and was Chief Financial Officer from March 1999 to June 2000.
She was Vice President Finance of Westcoast Energy Inc. from
June 1998 to March 1999.

Mr. Stanford was President and Chief
Executive Officer of Petro-Canada from January 1993 to January
2000.

All of the directors and executive officers of
EnCana listed above beneficially owned, as of February 25,
2004, directly or indirectly, or exercised control or direction
over an aggregate of 1,187,935 common shares

46



---



##### 



representing 0.26 percent of the issued and
outstanding voting shares of EnCana, and directors and executive
officers held options to acquire an aggregate of
2,677,116 additional common shares.


Investors should be aware that some of the
directors and officers of the Corporation are directors and
officers of other private and public companies. Some of these
private and public companies may, from time to time, be involved
in business transactions or banking relationships which may
create situations in which conflicts might arise. Any such
conflicts shall be resolved in accordance with the procedures
and requirements of the relevant provisions of the CBCA,
including the duty of such directors and officers to act
honestly and in good faith with a view to the best interests of
the Corporation.

SUPPLEMENTAL OIL AND GAS INFORMATION

The following information is provided in addition
to the information required under U.S. disclosure standards.

Reserve
Quantities Information

The following table sets forth estimates of gross
proved reserves derived in the same manner as the net proved
reserves continuity information on page 24 above. Gross
proved reserves refer to the sum of (i) working interest
reserves before deduction of royalty burdens payable and
(ii) royalty interest reserves (lessor royalty and
overriding royalty volumes derived from other working interest
owners). The definitions of proved reserves, developed and
undeveloped, are the same as those presented on page 24
above.

Gross Proved Reserves (Before
Royalties)(1)

Constant Pricing


|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|------------------ |  | ------------------------ | ----- | --------------------------------- |  | ------- | ----- | ----- |  | ------ | -- | ------ |  | ------- | ----- | ------- |  | ----- | ----- |  |  |  | ---- |  |  |  | ----- |  |  |  | ----- |  |  |  | ------- | 
|                   |  |                          |       |                                  
|                   |  | Natural Gas              |       | Crude Oil and Natural Gas Liquids
|                   |  |                          |       |                                  
|                   |  |                          |       |                                  
|                   |  | (billions of cubic feet) |       | (millions of barrels)            
|                   |  |                          |       |                                  
|                   |  |                          |       | United                            |  | United  |       |       |  |        |    | United |  |         |       | United  |  |      
|                   |  | Canada                   |       | States                            |  | Kingdom |       | Total |  | Canada |    | States |  | Ecuador |       | Kingdom |  | Total
|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |      
|2001  End of Year |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|Developed          |  |                          | 3,009 |                                   |  |         | 226   |       |  |        | 7  |        |  |         | 3,242 |         |  |       | 268.9 |  |  |  | 20.4 |  |  |  |      |  |  |  | 21.6  |  |  |  | 310.9   | 
|Undeveloped        |  |                          | 586   |                                   |  |         | 69    |       |  |        |   |        |  |         | 655   |         |  |       | 47.4  |  |  |  | 3.7  |  |  |  |      |  |  |  |      |  |  |  | 51.1    | 
|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|Total              |  |                          | 3,595 |                                   |  |         | 295   |       |  |        | 7  |        |  |         | 3,897 |         |  |       | 316.3 |  |  |  | 24.1 |  |  |  |      |  |  |  | 21.6  |  |  |  | 362.0   | 
|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|2002  End of Year |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|Developed          |  |                          | 4,715 |                                   |  |         | 1,808 |       |  |        | 9  |        |  |         | 6,532 |         |  |       | 336.0 |  |  |  | 27.3 |  |  |  | 142.7 |  |  |  | 8.3   |  |  |  | 514.3   | 
|Undeveloped        |  |                          | 1,068 |                                   |  |         | 1,362 |       |  |        | 11 |        |  |         | 2,441 |         |  |       | 287.0 |  |  |  | 22.6 |  |  |  | 69.8  |  |  |  | 89.3  |  |  |  | 468.7   | 
|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|Total              |  |                          | 5,783 |                                   |  |         | 3,170 |       |  |        | 20 |        |  |         | 8,973 |         |  |       | 623.0 |  |  |  | 49.9 |  |  |  | 212.5 |  |  |  | 97.6  |  |  |  | 983.0   | 
|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|2003  End of Year |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|Developed          |  |                          | 4,576 |                                   |  |         | 2,283 |       |  |        | 13 |        |  |         | 6,872 |         |  |       | 350.0 |  |  |  | 32.5 |  |  |  | 156.1 |  |  |  | 16.7  |  |  |  | 555.3   | 
|Undeveloped        |  |                          | 1,412 |                                   |  |         | 1,582 |       |  |        | 13 |        |  |         | 3,007 |         |  |       | 392.2 |  |  |  | 18.9 |  |  |  | 62.3  |  |  |  | 107.8 |  |  |  | 581.2   | 
|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 
|Total              |  |                          | 5,988 |                                   |  |         | 3,865 |       |  |        | 26 |        |  |         | 9,879 |         |  |       | 742.2 |  |  |  | 51.4 |  |  |  | 218.4 |  |  |  | 124.5 |  |  |  | 1,136.5 | 
|                   |  |                          |       |                                   |  |         |       |       |  |        |    |        |  |         |       |         |  |       |       |  |  |  |      |  |  |  |       |  |  |  |       |  |  |  |         | 




Notes:



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Includes EnCanas royalty interest volumes.
    At December 31, 2003, these volumes amounted to
    approximately 183 billion cubic feet of natural gas and
    14.8 million barrels of liquids in Canada. At
    December 31, 2002, these volumes were approximately
    225 billion cubic feet of natural gas and 18.7 million
    barrels of liquids in Canada. At December 31, 2001, these
    volumes were approximately 336 billion cubic feet of
    natural gas and 21.3 million barrels of liquids in Canada.

47



---



##### 



Daily
Sales Volume and Per-Unit Results

The following tables summarize gross and net
daily sales volumes and per-unit results for EnCana on a
quarterly basis for the periods indicated. The information
for 2002 is presented on the basis of combining the results for
PanCanadian and AEC for the period prior to the Merger.

|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |        |        |        | 
|--------------------------------------------- | -------------- | ------------------------------------------------ | ------------- | ------ | ------ | ------ | ------- | ------- | ------- | ------ | ------- | ------ | ------- | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | 
|                                              |                |                                                 
|                                              |                | Daily Sales Volumes  2003 (Before Royalties)(1)
|                                              |                |                                                 
|                                              |                | Year                                             |               | Q4     |        | Q3     |         | Q2      |         | Q1    
|                                              |                |                                                  |               |        |        |        |         |         |         |       
|SALES                                         |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|Produced Gas (million cubic
    feet/day)     |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|                                              | Canada         |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |        |       
|                                              |                | Production                                       |               |        | 2,222  |        |         |         | 2,287   |        |         |        | 2,197   |        |         |        | 2,213  |        |         |        | 2,190  |       
|                                              |                | Inventory withdrawal/(injection)                 |               |        | 35     |        |         |         |        |        |         |        |        |        |         |        |       |        |         |        | 141    |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|                                              | Canada Sales   |                                                  |               | 2,257  |        |        |         | 2,287   |         |        |         | 2,197  |         |        |         | 2,213  |        |        |         | 2,331  |       
|                                              | United States  |                                                  |               | 735    |        |        |         | 813     |         |        |         | 757    |         |        |         | 698    |        |        |         | 672    |       
|                                              | United Kingdom |                                                  |               | 13     |        |        |         | 20      |         |        |         | 7      |         |        |         | 12     |        |        |         | 13     |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|Total Produced Gas                            |                |                                                  | 3,005         |        |        |        | 3,120   |         |         |        | 2,961   |        |         |        | 2,923   |        |        |        | 3,016   |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|Oil and Natural Gas Liquids
    (barrels/day) |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|                                              | North America  |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |        |       
|                                              |                | Light and medium oil                             |               |        | 60,316 |        |         |         | 62,284  |        |         |        | 59,708  |        |         |        | 59,012 |        |         |        | 60,246 |       
|                                              |                | Heavy oil                                        |               |        | 98,304 |        |         |         | 105,703 |        |         |        | 104,702 |        |         |        | 91,939 |        |         |        | 90,636 |       
|                                              |                | Natural gas liquids                              |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |        |        |       
|                                              |                |                                                  | Canada        |        |        | 17,307 |         |         |         | 15,656 |         |        |         | 16,488 |         |        |        | 17,970 |         |        |        | 19,162 | 
|                                              |                |                                                  | United States |        |        | 11,269 |         |         |         | 11,486 |         |        |         | 11,487 |         |        |        | 12,329 |         |        |        | 9,751  | 
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|Total North America                           |                |                                                  | 187,196       |        |        |        | 195,129 |         |         |        | 192,385 |        |         |        | 181,250 |        |        |        | 179,795 |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|                                              | Ecuador        |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |        |       
|                                              |                | Production                                       |               |        | 68,865 |        |         |         | 97,446  |        |         |        | 73,760  |        |         |        | 49,006 |        |         |        | 54,726 |       
|                                              |                | Transferred to OCP Pipeline(2)                   |               |        | (4,437 | )      |         |         |        |        |         |        | (6,805  | )      |         |        | (2,816 | )      |         |        | (8,191 | )     
|                                              |                | Over/(under) lifting                             |               |        | (1,905 | )      |         |         | 6,192   |        |         |        | (13,412 | )      |         |        | 3,385  |        |         |        | (3,771 | )     
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|                                              | Ecuador Sales  |                                                  |               | 62,523 |        |        |         | 103,638 |         |        |         | 53,543 |         |        |         | 49,575 |        |        |         | 42,764 |       
|                                              | United Kingdom |                                                  |               | 10,128 |        |        |         | 15,067  |         |        |         | 5,813  |         |        |         | 9,019  |        |        |         | 10,610 |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|Total Oil and Natural Gas Liquids             |                |                                                  | 259,847       |        |        |        | 313,834 |         |         |        | 251,741 |        |         |        | 239,844 |        |        |        | 233,169 |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|Total (barrels of oil
    equivalent/day)     |                |                                                  | 760,680       |        |        |        | 833,834 |         |         |        | 745,241 |        |         |        | 727,011 |        |        |        | 735,836 |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       
|Syncrude                                      |                |                                                  | 7,697         |        |        |        |        |         |         |        | 3,401   |        |         |        | 7,383   |        |        |        | 20,272  |       
|                                              |                |                                                  |               |        |        |        |         |         |         |        |         |        |         |        |         |        |        |        |         |       




Notes:



|    |                                                                                                           
|--- | ----------------------------------------------------------------------------------------------------------
|(1) | Includes EnCanas royalty interest volumes.                                                               
|   
|(2) | Crude oil production in Ecuador transferred to
    the OCP Pipeline for use by OCP in asset commissioning.

48



---



##### 



|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |         |        | 
|--------------------------------------------- | -------------- | ------------------------------------------------ | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------- | ------ | 
|                                              |                |                                                 
|                                              |                | Daily Sales Volumes  2002 (Before Royalties)(1)
|                                              |                |                                                 
|                                              |                | Year(2)                                          |               | Q4     |        | Q3     |         | Q2     |        | Q1(2) 
|                                              |                |                                                  |               |        |        |        |         |        |        |       
|SALES                                         |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Produced Gas (million cubic
    feet/day)     |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Canada         |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        
|                                              |                | Production                                       |               |        | 2,220  |        |         |        | 2,226  |        |         |        | 2,209  |        |         |        | 2,262  |        |         |        | 2,188   |       
|                                              |                | Inventory withdrawal/(injection)                 |               |        | 28     |        |         |        | 149    |        |         |        | (80    | )      |         |        | (118   | )      |         |        | 160     |       
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Canada Sales   |                                                  |               | 2,248  |        |        |         | 2,375  |        |        |         | 2,129  |        |        |         | 2,144  |        |        |         | 2,348  |        
|                                              | United States  |                                                  |               | 500    |        |        |         | 654    |        |        |         | 550    |        |        |         | 428    |        |        |         | 365    |        
|                                              | United Kingdom |                                                  |               | 10     |        |        |         | 8      |        |        |         | 9      |        |        |         | 8      |        |        |         | 11     |        
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Produced Gas                            |                |                                                  | 2,758         |        |        |        | 3,037   |        |        |        | 2,688   |        |        |        | 2,580   |        |        |        | 2,724   |       
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Oil and Natural Gas Liquids
    (barrels/day) |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | North America  |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        
|                                              |                | Light and medium oil                             |               |        | 66,333 |        |         |        | 62,369 |        |         |        | 65,345 |        |         |        | 66,807 |        |         |        | 70,914  |       
|                                              |                | Heavy oil                                        |               |        | 78,029 |        |         |        | 86,019 |        |         |        | 80,797 |        |         |        | 76,233 |        |         |        | 68,846  |       
|                                              |                | Natural gas liquids                              |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |         |       
|                                              |                |                                                  | Canada        |        |        | 17,399 |         |        |        | 19,121 |         |        |        | 16,225 |         |        |        | 16,796 |         |        |         | 17,448 | 
|                                              |                |                                                  | United States |        |        | 7,961  |         |        |        | 11,558 |         |        |        | 6,702  |         |        |        | 7,115  |         |        |         | 6,427  | 
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total North America                           |                |                                                  | 169,722       |        |        |        | 179,067 |        |        |        | 169,069 |        |        |        | 166,951 |        |        |        | 163,635 |       
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Ecuador        |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        
|                                              |                | Production                                       |               |        | 50,980 |        |         |        | 48,486 |        |         |        | 52,344 |        |         |        | 52,744 |        |         |        | 50,351  |       
|                                              |                | Over/(under) lifting                             |               |        | 101    |        |         |        | 1,448  |        |         |        | 3,235  |        |         |        | 7,120  |        |         |        | (11,577 | )     
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Ecuador Sales  |                                                  |               | 51,081 |        |        |         | 49,934 |        |        |         | 55,579 |        |        |         | 59,864 |        |        |         | 38,774 |        
|                                              | United Kingdom |                                                  |               | 10,528 |        |        |         | 7,786  |        |        |         | 9,538  |        |        |         | 11,966 |        |        |         | 12,889 |        
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Oil and Natural Gas Liquids             |                |                                                  | 231,331       |        |        |        | 236,787 |        |        |        | 234,186 |        |        |        | 238,781 |        |        |        | 215,298 |       
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total (barrels of oil
    equivalent/day)     |                |                                                  | 690,998       |        |        |        | 742,954 |        |        |        | 682,186 |        |        |        | 668,781 |        |        |        | 669,298 |       
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Syncrude                                      |                |                                                  | 31,556        |        |        |        | 34,261  |        |        |        | 36,039  |        |        |        | 24,295  |        |        |        | 31,548  |       
|                                              |                |                                                  |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       

|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        | 
|--------------------------------------------- | -------------- | ----------------------------------------------- | ------------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | ------- | ------ | ------ | ------ | 
|                                              |                |                                                
|                                              |                | Daily Sales Volumes  2002 (After Royalties)(1)
|                                              |                |                                                
|                                              |                | Year(2)                                         |               | Q4     |        | Q3     |         | Q2     |        | Q1(2) 
|                                              |                |                                                 |               |        |        |        |         |        |        |       
|SALES                                         |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Produced Gas (million cubic
    feet/day)     |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Canada         |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                              |                | Production                                      |               |        | 1,953  |        |         |        | 1,943  |        |         |        | 1,959  |        |         |        | 1,980  |        |         |        | 1,930  |       
|                                              |                | Inventory withdrawal/(injection)                |               |        | 22     |        |         |        | 117    |        |         |        | (51    | )      |         |        | (90    | )      |         |        | 113    |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Canada Sales   |                                                 |               | 1,975  |        |        |         | 2,060  |        |        |         | 1,908  |        |        |         | 1,890  |        |        |         | 2,043  |       
|                                              | United States  |                                                 |               | 395    |        |        |         | 516    |        |        |         | 423    |        |        |         | 345    |        |        |         | 295    |       
|                                              | United Kingdom |                                                 |               | 10     |        |        |         | 8      |        |        |         | 9      |        |        |         | 8      |        |        |         | 11     |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Produced Gas                            |                |                                                 | 2,380         |        |        |        | 2,584   |        |        |        | 2,340   |        |        |        | 2,243   |        |        |        | 2,349   |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Oil and Natural Gas Liquids
    (barrels/day) |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | North America  |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                              |                | Light and medium oil                            |               |        | 59,222 |        |         |        | 55,265 |        |         |        | 58,321 |        |         |        | 58,885 |        |         |        | 64,531 |       
|                                              |                | Heavy oil                                       |               |        | 69,465 |        |         |        | 77,090 |        |         |        | 70,795 |        |         |        | 67,558 |        |         |        | 62,237 |       
|                                              |                | Natural gas liquids                             |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |        |       
|                                              |                |                                                 | Canada        |        |        | 14,778 |         |        |        | 15,987 |         |        |        | 13,985 |         |        |        | 14,168 |         |        |        | 14,968 | 
|                                              |                |                                                 | United States |        |        | 7,019  |         |        |        | 10,016 |         |        |        | 5,901  |         |        |        | 6,368  |         |        |        | 5,757  | 
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total North America                           |                |                                                 | 150,484       |        |        |        | 158,358 |        |        |        | 149,002 |        |        |        | 146,979 |        |        |        | 147,493 |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Ecuador        |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |        |       
|                                              |                | Production                                      |               |        | 36,521 |        |         |        | 34,856 |        |         |        | 37,447 |        |         |        | 37,702 |        |         |        | 36,082 |       
|                                              |                | Over/(under) lifting                            |               |        | 70     |        |         |        | 1,044  |        |         |        | 2,316  |        |         |        | 5,088  |        |         |        | (8,295 | )     
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|                                              | Ecuador Sales  |                                                 |               | 36,591 |        |        |         | 35,900 |        |        |         | 39,763 |        |        |         | 42,790 |        |        |         | 27,787 |       
|                                              | United Kingdom |                                                 |               | 10,528 |        |        |         | 7,786  |        |        |         | 9,538  |        |        |         | 11,966 |        |        |         | 12,889 |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total Oil and Natural Gas Liquids             |                |                                                 | 197,603       |        |        |        | 202,044 |        |        |        | 198,303 |        |        |        | 201,735 |        |        |        | 188,169 |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Total (barrels of oil
    equivalent/day)     |                |                                                 | 594,270       |        |        |        | 632,711 |        |        |        | 588,303 |        |        |        | 575,568 |        |        |        | 579,669 |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       
|Syncrude                                      |                |                                                 | 31,267        |        |        |        | 33,918  |        |        |        | 35,585  |        |        |        | 24,152  |        |        |        | 31,337  |       
|                                              |                |                                                 |               |        |        |        |         |        |        |        |         |        |        |        |         |        |        |        |         |       




Notes:



|    |                                                        
|--- | -------------------------------------------------------
|(1) | Includes EnCanas royalty interest volumes.            
|   
|(2) | Includes AEC volumes for the first quarter of
    2002.

49



---



##### 



The following per-unit results are presented
in Canadian dollars.The results are
not measures that have any standardized meaning prescribed by
Canadian GAAP and are considered non-GAAP measures. Therefore,
these measures may not be comparable to similar measures
presented by other issuers. These measures have been provided as
additional information.

|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |       |  
|------------------------------------------------- | ---------------------------------------- | --------------------- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                                  |                                          |                      
|                                                  |                                          | Per-Unit Results (C$)
|                                                  |                                          |                      
|                                                  |                                          |                       |  |      
|                                                  |                                          | 2003                  |  | 2002 
|                                                  |                                          |                       |  |      
|                                                  |                                          | Year                  |  | Q4    |   | Q3 |  | Q2    |   | Q1 |  | Q4    |   | Q3 |  | Q2   
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |      
|Produced Gas  Canada (C$/Mcf)                    |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Price, net of transportation and selling |                       |  | 6.34  |   |    |  | 5.25  |   |    |  | 5.80  |   |    |  | 6.43  |   |  |  | 7.85  |   |  |  | 5.17  |   |  |  | 3.24  |   |  |  | 4.23  |  
|                                                  | Royalties(1)                             |                       |  | 0.92  |   |    |  | 0.78  |   |    |  | 0.85  |   |    |  | 1.05  |   |  |  | 1.00  |   |  |  | 0.77  |   |  |  | 0.39  |   |  |  | 0.65  |  
|                                                  | Operating expenses                       |                       |  | 0.57  |   |    |  | 0.51  |   |    |  | 0.58  |   |    |  | 0.54  |   |  |  | 0.63  |   |  |  | 0.59  |   |  |  | 0.58  |   |  |  | 0.54  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback excluding hedge                  |                       |  | 4.85  |   |    |  | 3.96  |   |    |  | 4.37  |   |    |  | 4.84  |   |  |  | 6.22  |   |  |  | 3.81  |   |  |  | 2.27  |   |  |  | 3.04  |  
|                                                  | Financial hedge                          |                       |  | (0.18 | ) |    |  | 0.29  |   |    |  | (0.04 | ) |    |  | (0.31 | ) |  |  | (0.65 | ) |  |  | (0.08 | ) |  |  | 0.29  |   |  |  | (0.12 | )
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback including hedge                  |                       |  | 4.67  |   |    |  | 4.25  |   |    |  | 4.33  |   |    |  | 4.53  |   |  |  | 5.57  |   |  |  | 3.73  |   |  |  | 2.56  |   |  |  | 2.92  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Produced Gas  United States (C$/Mcf)             |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Price, net of transportation and selling |                       |  | 6.28  |   |    |  | 5.54  |   |    |  | 6.11  |   |    |  | 6.13  |   |  |  | 7.55  |   |  |  | 4.74  |   |  |  | 3.16  |   |  |  | 3.56  |  
|                                                  | Royalties(1)                             |                       |  | 1.79  |   |    |  | 1.52  |   |    |  | 1.73  |   |    |  | 1.74  |   |  |  | 2.23  |   |  |  | 1.42  |   |  |  | 0.99  |   |  |  | 0.98  |  
|                                                  | Operating expenses                       |                       |  | 0.31  |   |    |  | 0.30  |   |    |  | 0.36  |   |    |  | 0.33  |   |  |  | 0.25  |   |  |  | 0.28  |   |  |  | 0.34  |   |  |  | 0.38  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback excluding hedge                  |                       |  | 4.18  |   |    |  | 3.72  |   |    |  | 4.02  |   |    |  | 4.06  |   |  |  | 5.07  |   |  |  | 3.04  |   |  |  | 1.83  |   |  |  | 2.20  |  
|                                                  | Financial hedge                          |                       |  | 0.04  |   |    |  | (0.13 | ) |    |  | (0.17 | ) |    |  | (0.24 | ) |  |  | 0.80  |   |  |  | 0.42  |   |  |  | 0.57  |   |  |  | 0.06  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback including hedge                  |                       |  | 4.22  |   |    |  | 3.59  |   |    |  | 3.85  |   |    |  | 3.82  |   |  |  | 5.87  |   |  |  | 3.46  |   |  |  | 2.40  |   |  |  | 2.26  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Produced Gas  Total North America
    (C$/Mcf)   |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Price, net of transportation and selling |                       |  | 6.32  |   |    |  | 5.33  |   |    |  | 5.88  |   |    |  | 6.36  |   |  |  | 7.78  |   |  |  | 5.08  |   |  |  | 3.21  |   |  |  | 4.11  |  
|                                                  | Royalties(1)                             |                       |  | 1.13  |   |    |  | 0.98  |   |    |  | 1.08  |   |    |  | 1.22  |   |  |  | 1.28  |   |  |  | 0.91  |   |  |  | 0.51  |   |  |  | 0.70  |  
|                                                  | Operating expenses                       |                       |  | 0.50  |   |    |  | 0.45  |   |    |  | 0.53  |   |    |  | 0.49  |   |  |  | 0.54  |   |  |  | 0.52  |   |  |  | 0.53  |   |  |  | 0.52  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback excluding hedge                  |                       |  | 4.69  |   |    |  | 3.90  |   |    |  | 4.27  |   |    |  | 4.65  |   |  |  | 5.96  |   |  |  | 3.65  |   |  |  | 2.17  |   |  |  | 2.89  |  
|                                                  | Financial hedge                          |                       |  | (0.13 | ) |    |  | 0.18  |   |    |  | (0.07 | ) |    |  | (0.30 | ) |  |  | (0.33 | ) |  |  | 0.03  |   |  |  | 0.35  |   |  |  | (0.09 | )
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback including hedge                  |                       |  | 4.56  |   |    |  | 4.08  |   |    |  | 4.20  |   |    |  | 4.35  |   |  |  | 5.63  |   |  |  | 3.68  |   |  |  | 2.52  |   |  |  | 2.80  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Light and Medium Oil  North America
    (C$/bbl) |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Price, net of transportation and selling |                       |  | 35.33 |   |    |  | 31.84 |   |    |  | 32.59 |   |    |  | 35.78 |   |  |  | 41.36 |   |  |  | 36.36 |   |  |  | 36.01 |   |  |  | 35.35 |  
|                                                  | Royalties(1,2)                           |                       |  | 4.42  |   |    |  | 3.78  |   |    |  | 3.59  |   |    |  | 4.56  |   |  |  | 5.82  |   |  |  | 4.81  |   |  |  | 4.56  |   |  |  | 4.36  |  
|                                                  | Operating expenses                       |                       |  | 7.63  |   |    |  | 7.29  |   |    |  | 8.02  |   |    |  | 7.54  |   |  |  | 7.68  |   |  |  | 7.16  |   |  |  | 6.58  |   |  |  | 7.25  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback excluding hedge                  |                       |  | 23.28 |   |    |  | 20.77 |   |    |  | 20.98 |   |    |  | 23.68 |   |  |  | 27.86 |   |  |  | 24.39 |   |  |  | 24.87 |   |  |  | 23.74 |  
|                                                  | Financial hedge                          |                       |  | (5.21 | ) |    |  | (4.47 | ) |    |  | (4.08 | ) |    |  | (3.52 | ) |  |  | (8.83 | ) |  |  | (1.26 | ) |  |  | (0.89 | ) |  |  | (1.59 | )
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback including hedge                  |                       |  | 18.07 |   |    |  | 16.30 |   |    |  | 16.90 |   |    |  | 20.16 |   |  |  | 19.03 |   |  |  | 23.13 |   |  |  | 23.98 |   |  |  | 22.15 |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Heavy Oil  North America (C$/bbl)                |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Price, net of transportation and selling |                       |  | 25.74 |   |    |  | 22.21 |   |    |  | 23.96 |   |    |  | 25.99 |   |  |  | 31.80 |   |  |  | 25.81 |   |  |  | 29.44 |   |  |  | 26.85 |  
|                                                  | Royalties(1,2)                           |                       |  | 2.92  |   |    |  | 2.32  |   |    |  | 2.45  |   |    |  | 3.10  |   |  |  | 3.99  |   |  |  | 3.43  |   |  |  | 3.67  |   |  |  | 3.09  |  
|                                                  | Operating expenses                       |                       |  | 7.05  |   |    |  | 5.94  |   |    |  | 7.38  |   |    |  | 7.52  |   |  |  | 7.52  |   |  |  | 5.64  |   |  |  | 6.71  |   |  |  | 5.87  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback excluding hedge                  |                       |  | 15.77 |   |    |  | 13.95 |   |    |  | 14.13 |   |    |  | 15.37 |   |  |  | 20.29 |   |  |  | 16.74 |   |  |  | 19.06 |   |  |  | 17.89 |  
|                                                  | Financial hedge                          |                       |  | (4.95 | ) |    |  | (4.52 | ) |    |  | (3.95 | ) |    |  | (2.80 | ) |  |  | (8.83 | ) |  |  | (1.18 | ) |  |  | (0.89 | ) |  |  | (0.76 | )
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback including hedge                  |                       |  | 10.82 |   |    |  | 9.43  |   |    |  | 10.18 |   |    |  | 12.57 |   |  |  | 11.46 |   |  |  | 15.56 |   |  |  | 18.17 |   |  |  | 17.13 |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Total Oil  North America (C$/bbl)                |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Price, net of transportation and selling |                       |  | 29.39 |   |    |  | 25.78 |   |    |  | 27.09 |   |    |  | 29.80 |   |  |  | 35.61 |   |  |  | 30.26 |   |  |  | 32.38 |   |  |  | 30.82 |  
|                                                  | Royalties(1,2)                           |                       |  | 3.49  |   |    |  | 2.86  |   |    |  | 2.87  |   |    |  | 3.67  |   |  |  | 4.72  |   |  |  | 4.01  |   |  |  | 4.07  |   |  |  | 3.68  |  
|                                                  | Operating expenses                       |                       |  | 7.27  |   |    |  | 6.44  |   |    |  | 7.61  |   |    |  | 7.53  |   |  |  | 7.59  |   |  |  | 6.28  |   |  |  | 6.66  |   |  |  | 6.51  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback excluding hedge                  |                       |  | 18.63 |   |    |  | 16.48 |   |    |  | 16.61 |   |    |  | 18.60 |   |  |  | 23.30 |   |  |  | 19.97 |   |  |  | 21.65 |   |  |  | 20.63 |  
|                                                  | Financial hedge                          |                       |  | (5.05 | ) |    |  | (4.50 | ) |    |  | (4.00 | ) |    |  | (3.08 | ) |  |  | (8.83 | ) |  |  | (1.22 | ) |  |  | (0.89 | ) |  |  | (1.15 | )
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback including hedge                  |                       |  | 13.58 |   |    |  | 11.98 |   |    |  | 12.61 |   |    |  | 15.52 |   |  |  | 14.47 |   |  |  | 18.75 |   |  |  | 20.76 |   |  |  | 19.48 |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Canada (C$/bbl)             |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Price, net of transportation and selling |                       |  | 33.97 |   |    |  | 32.90 |   |    |  | 31.65 |   |    |  | 29.40 |   |  |  | 41.25 |   |  |  | 34.15 |   |  |  | 27.51 |   |  |  | 27.07 |  
|                                                  | Royalties                                |                       |  | 6.01  |   |    |  | 4.85  |   |    |  | 5.24  |   |    |  | 5.28  |   |  |  | 8.33  |   |  |  | 5.60  |   |  |  | 3.80  |   |  |  | 4.24  |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                  | Netback                                  |                       |  | 27.96 |   |    |  | 28.05 |   |    |  | 26.41 |   |    |  | 24.12 |   |  |  | 32.92 |   |  |  | 28.55 |   |  |  | 23.71 |   |  |  | 22.83 |  
|                                                  |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      

50



---



##### 



|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |       |  
|------------------------------------------------------ | ---------------------------------------- | --------------------- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - | -- |  | ----- | - |  |  | ----- | - |  |  | ----- | - |  |  | ----- | - |  |  | ----- | -
|                                                       |                                          |                      
|                                                       |                                          | Per-Unit Results (C$)
|                                                       |                                          |                      
|                                                       |                                          |                       |  |      
|                                                       |                                          | 2003                  |  | 2002 
|                                                       |                                          |                       |  |      
|                                                       |                                          | Year                  |  | Q4    |   | Q3 |  | Q2    |   | Q1 |  | Q4    |   | Q3 |  | Q2   
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |      
|Natural Gas Liquids  United States
    (C$/bbl)       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Price, net of transportation and selling |                       |  | 37.83 |   |    |  | 35.11 |   |    |  | 35.18 |   |    |  | 34.45 |   |  |  | 48.59 |   |  |  | 39.47 |   |  |  | 40.07 |   |  |  | 36.65 |  
|                                                       | Royalties(1)                             |                       |  | 8.98  |   |    |  | 9.05  |   |    |  | 9.02  |   |    |  | 7.37  |   |  |  | 10.92 |   |  |  | 6.54  |   |  |  | 6.60  |   |  |  | 5.75  |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Netback                                  |                       |  | 28.85 |   |    |  | 26.06 |   |    |  | 26.16 |   |    |  | 27.08 |   |  |  | 37.67 |   |  |  | 32.93 |   |  |  | 33.47 |   |  |  | 30.90 |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Natural Gas Liquids  Total North
    America (C$/bbl) |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Price, net of transportation and selling |                       |  | 35.49 |   |    |  | 33.83 |   |    |  | 33.10 |   |    |  | 31.45 |   |  |  | 43.73 |   |  |  | 36.15 |   |  |  | 31.18 |   |  |  | 29.92 |  
|                                                       | Royalties(1)                             |                       |  | 7.18  |   |    |  | 6.63  |   |    |  | 6.79  |   |    |  | 6.13  |   |  |  | 9.21  |   |  |  | 5.95  |   |  |  | 4.62  |   |  |  | 4.69  |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Netback                                  |                       |  | 28.31 |   |    |  | 27.20 |   |    |  | 26.31 |   |    |  | 25.32 |   |  |  | 34.52 |   |  |  | 30.20 |   |  |  | 26.56 |   |  |  | 25.23 |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Total Liquids  Canada (C$/bbl)                        |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Price, net of transportation and selling |                       |  | 29.84 |   |    |  | 26.38 |   |    |  | 27.51 |   |    |  | 29.77 |   |  |  | 36.25 |   |  |  | 30.69 |   |  |  | 31.89 |   |  |  | 30.42 |  
|                                                       | Royalties(1)                             |                       |  | 3.74  |   |    |  | 3.03  |   |    |  | 3.08  |   |    |  | 3.84  |   |  |  | 5.13  |   |  |  | 4.19  |   |  |  | 4.04  |   |  |  | 3.74  |  
|                                                       | Operating expenses                       |                       |  | 6.56  |   |    |  | 5.89  |   |    |  | 6.92  |   |    |  | 6.73  |   |  |  | 6.73  |   |  |  | 5.56  |   |  |  | 5.99  |   |  |  | 5.83  |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Netback excluding hedge                  |                       |  | 19.54 |   |    |  | 17.46 |   |    |  | 17.51 |   |    |  | 19.20 |   |  |  | 24.39 |   |  |  | 20.94 |   |  |  | 21.86 |   |  |  | 20.85 |  
|                                                       | Financial hedge                          |                       |  | (4.55 | ) |    |  | (4.11 | ) |    |  | (3.64 | ) |    |  | (2.75 | ) |  |  | (7.83 | ) |  |  | (1.08 | ) |  |  | (0.80 | ) |  |  | (1.02 | )
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Netback including hedge                  |                       |  | 14.99 |   |    |  | 13.35 |   |    |  | 13.87 |   |    |  | 16.45 |   |  |  | 16.56 |   |  |  | 19.86 |   |  |  | 21.06 |   |  |  | 19.83 |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|Ecuador Oil (C$/bbl)                                   |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Price, net of transportation and selling |                       |  | 31.13 |   |    |  | 28.16 |   |    |  | 28.40 |   |    |  | 29.50 |   |  |  | 43.90 |   |  |  | 35.38 |   |  |  | 33.59 |   |  |  | 31.67 |  
|                                                       | Royalties(1)                             |                       |  | 10.36 |   |    |  | 8.82  |   |    |  | 8.59  |   |    |  | 9.78  |   |  |  | 17.12 |   |  |  | 12.29 |   |  |  | 12.51 |   |  |  | 10.76 |  
|                                                       | Operating expenses                       |                       |  | 4.97  |   |    |  | 4.53  |   |    |  | 4.45  |   |    |  | 5.91  |   |  |  | 5.63  |   |  |  | 6.04  |   |  |  | 4.60  |   |  |  | 5.70  |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Netback excluding hedge                  |                       |  | 15.80 |   |    |  | 14.81 |   |    |  | 15.36 |   |    |  | 13.81 |   |  |  | 21.15 |   |  |  | 17.05 |   |  |  | 16.48 |   |  |  | 15.21 |  
|                                                       | Financial hedge                          |                       |  |      |   |    |  |      |   |    |  |      |   |    |  |      |   |  |  |      |   |  |  |      |   |  |  |      |   |  |  | (0.04 | )
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Netback including hedge                  |                       |  | 15.80 |   |    |  | 14.81 |   |    |  | 15.36 |   |    |  | 13.81 |   |  |  | 21.15 |   |  |  | 17.05 |   |  |  | 16.48 |   |  |  | 15.17 |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|United Kingdom Oil (C$/bbl)                            |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Price, net of transportation and selling |                       |  | 36.50 |   |    |  | 33.36 |   |    |  | 35.79 |   |    |  | 35.39 |   |  |  | 42.53 |   |  |  | 37.99 |   |  |  | 39.30 |   |  |  | 37.78 |  
|                                                       | Operating expenses                       |                       |  | 6.99  |   |    |  | 8.20  |   |    |  | 9.03  |   |    |  | 6.56  |   |  |  | 4.41  |   |  |  | 11.10 |   |  |  | 5.71  |   |  |  | 3.12  |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      
|                                                       | Netback                                  |                       |  | 29.51 |   |    |  | 25.16 |   |    |  | 26.76 |   |    |  | 28.83 |   |  |  | 38.12 |   |  |  | 26.89 |   |  |  | 33.59 |   |  |  | 34.66 |  
|                                                       |                                          |                       |  |       |   |    |  |       |   |    |  |       |   |    |  |       |   |  |  |       |   |  |  |       |   |  |  |       |   |  |  |      




Notes:



|    |                                                                                                                        
|--- | -----------------------------------------------------------------------------------------------------------------------
|(1) | Includes production and mineral taxes.                                                                                 
|   
|(2) | Excludes impact of amendments, made in Q3 2003,
    related to prior years which reduced royalties by
    C$21 million.

51



---



##### 



ADDITIONAL INFORMATION

Additional information, including directors
and officers remuneration, principal holders of
EnCanas securities, and options to purchase securities, is
contained in the Information Circular for EnCanas most
recent annual meeting of shareholders that involved the election
of directors. Additional financial information is contained in
EnCanas audited consolidated financial statements for the
year ended December 31, 2003.

When the securities of EnCana are in the course
of a distribution pursuant to a short form prospectus or a
preliminary short form prospectus has been filed in respect of a
distribution of its securities, EnCana will, upon request to the
Corporate Secretary as listed below, provide to any person the
following information:



| |       |                                                                                                                                                                                                                                                                                                                                                                                                                                
| | ----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | (i)   | one copy of the Corporations annual
    information form, together with one copy of any document, or the
    pertinent pages of any document, incorporated by reference in
    the annual information form,                                                                                                                                                                                                                   
|
| | (ii)  | one copy of the audited consolidated financial
    statements of EnCana for its most recently completed financial
    year for which financial statements have been filed together
    with the accompanying report of the auditor and one copy of the
    most recent interim financial statements of EnCana that have
    been filed, if any, for any period after the end of its most
    recently completed financial year,
|
| | (iii) | one copy of the information circular of EnCana in
    respect of its most recent annual meeting of shareholders that
    involved the election of directors, and                                                                                                                                                                                                                                                               
|
| | (iv)  | one copy of any other documents that are
    incorporated by reference into the preliminary short form
    prospectus or the short form prospectus and are not required to
    be provided under (i) to (iii) above.                                                                                                                                                                                                           

At any other time, EnCana will, upon request to
the Corporate Secretary as listed below, provide to any person
one copy of any of the documents referred to in (i), (ii) and
(iii) above, provided EnCana may require the payment of a
reasonable charge if the request is made by a person or
Corporation who is not a security holder of EnCana.

For additional copies of this annual information
form or any of the materials listed in the preceding paragraphs,
please contact:

|                                                                                                                                                                            |  |                                                                                   
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------------------------------------------
|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 |  | Corporate Development Department:
    Phone: 403-645-2000
    Fax:    403-645-4617

52



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##### 



APPENDIX A

Report on Reserves Data by Independent
Qualified Reserves Evaluators

To the Board of Directors of EnCana Corporation
(the Corporation):



|   |                                                                                                                               
|-- | ------------------------------------------------------------------------------------------------------------------------------
|1. | We have evaluated the Corporations reserves
    data as at December 31, 2003. The reserves data consist of
    the following:



| |      |                                                                                                                                                        
| | ---- | -------------------------------------------------------------------------------------------------------------------------------------------------------
| | (i)  | estimated proved oil and gas reserve quantities
    as at December 31, 2003 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, 2003:

|                                         |                  |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        |  | 
|---------------------------------------- | ---------------- | ----------------- | -------------- | -------------- |  | ------------------- | ----- | ----------------------- |  |  | ----- |  |  |  | ------ |  | 
|                                         |                  |                   |                |                |  |                    
|                                         |                  |                   |                | Estimated      |  |                    
|                                         |                  |                   |                | Proved Reserve |  |                    
|                                         |                  |                   |                | Quantities     |  | Related            
|                                         |                  |                   |                | After Royalty  |  | Estimates of Future
|                                         |                  |                   |                |                |  | Net Cash Flow      
|Evaluator and Preparation Date of Report |                  | Reserves Location |                | Gas            |  | Liquids             |       | BTax, 10% discount rate
|                                         |                  |                   |                |                |  |                     |       |                        
|                                         |                  |                   |                | (Bcf)          |  | (MMbbl)             |       | ($USMM)                
|McDaniel & Associates Consultants Ltd.   |                  |                   | Canada         |                |  |                     | 3,217 |                         |  |  | 451.4 |  |  |  | 8,719  | 
|                                         | January 10, 2004 |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        |  | 
|                                        
|Gilbert Laustsen Jung Associates Ltd.    |                  |                   | Canada         |                |  |                     | 2,019 |                         |  |  | 136.1 |  |  |  | 4,808  | 
|                                         | January 23, 2004 |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        |  | 
|                                        
|Ryder Scott Company                      |                  |                   | Canada         |                |  |                     | 20    |                         |  |  | 42.0  |  |  |  | 261    | 
|                                         | January 5, 2004  |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        |  | 
|                                        
|Netherland, Sewell & Associates, Inc.    |                  |                   | United States  |                |  |                     | 3,130 |                         |  |  | 41.6  |  |  |  | 7,304  | 
|                                         | January 6, 2004  |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        |  | 
|                                        
|Ryder Scott Company                      |                  |                   | Ecuador        |                |  |                     |       |                         |  |  | 161.7 |  |  |  | 1,894  | 
|                                         | January 5, 2004  |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        |  | 
|                                        
|DeGolyer and MacNaughton                 |                  |                   | UK - North Sea |                |  |                     | 26    |                         |  |  | 124.4 |  |  |  | 814    | 
|                                         | January 2, 2004  |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        |  | 
|                                         |                  |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        | 
|Totals                                   |                  |                   |                |                |  |                     | 8,411 |                         |  |  | 957.2 |  |  |  | 23,800 | 
|                                         |                  |                   |                |                |  |                     |       |                         |  |  |       |  |  |  |        | 

53



---



##### 





|   |                                                                                                                                                                                                                                
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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.                                                            
|  
|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.             

Executed as to our report referred to above:

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

February 9, 2004

54



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##### 



APPENDIX B

Report of Management and Directors on Reserves
Data and Other Information

Management and directors of EnCana Corporation
(the Corporation) are responsible for the
preparation and disclosure of information with respect to the
Corporations oil and gas activities in accordance with
securities regulatory requirements. In the case of the
Corporation, the regulatory requirements are covered under
NI 51-101 as amended by an MRRS Decision Document dated
December 16, 2003, and require disclosure of information
contemplated by, and consistent with, US Disclosure Requirements
and US Disclosure Practices (as defined in the Decision
Document). Required information includes reserves data, which
consist of the following:



| |      |                                                                                                                                                        
| | ---- | -------------------------------------------------------------------------------------------------------------------------------------------------------
| | (i)  | proved oil and gas reserve quantities estimated
    as at December 31, 2003 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.

Independent qualified reserves evaluators have
evaluated the Corporations reserves data. A report from
the independent qualified reserves evaluators dated
February 9, 2004 (the IQRE Report),
highlighting the standards they followed and their results,
accompanies this Report.

The Reserves Committee of the board of directors
(the Board of Directors) of the Corporation, which
Committee is comprised exclusively of non-management and
unrelated directors, has:



| |     |                                                                                                                                                                                                                                       
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | (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.                                                                                          

The Board of Directors has reviewed the
standardized measure calculation with respect to the
Corporations proved oil and gas reserve quantities. The
Board of Directors has reviewed the Corporations
procedures for assembling and reporting other information
associated with oil and gas activities and has reviewed that
information with management. The Board of Directors has approved:



| |     |                                                                                                                                                                                                                                                                                                       
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | (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.                                                                                                                                                                                                                                                                

55



---



##### 



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

(signed) Gwyn Morgan

President & Chief Executive Officer


(signed) Brian C. Ferguson

Executive Vice-President, Corporate Development


(signed) David P. OBrien

Director and Chairman of the Board


(signed) James M. Stanford

Director and Chairman of the Reserves Committee


February 25, 2004

56



---



##### 



ENCANA CORPORATION 2003 Managements Discussion and Analysis




---



##### 



NOTE
REGARDING FORWARD - LOOKING STATEMENTS ADVISORY  In the interest of providing EnCana Corporation (EnCana or the
Company) shareholders and potential investors with information regarding
the Company and its subsidiaries, certain statements throughout this
Managements Discussion and Analysis (MD&A) constitute forward-looking
statements within the meaning 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 estimates for crude oil, natural gas and NGLs for
2004 and beyond; the Companys oilsands strategy; projected increases in
oil shipment volumes through the OCP pipeline; the timing for completion of
the various phases of the Countess and Wild Goose gas storage projects and
storage capacities, injection and withdrawal rates expected upon
completion; the production and growth potential, including the Companys
plans therefore, with respect to EnCanas various assets and initiatives,
including assets and initiatives in North America, Ecuador, the U.K.
central North Sea, the Gulf of Mexico and potential new ventures
exploration growth platforms; the potential for acquisitions, the
disposition of non-core assets and the expansion of storage and other
Midstream assets; the Companys projected capital investment levels for
2004 and the source of funding therefore; projections with respect to the
sufficiency of the Companys credit facilities and forecasted capital
resources to support planned capital investment programs and projected
financial requirements; the effect of the Companys risk management
program, including the impact of derivative financial instruments; the
Companys plans for the execution of share purchases under its Normal
Course Issuer Bid; the Companys defence of lawsuits; the impact of the
Kyoto Accord and similar initiatives in the U.S.A. on operating costs;
proved oil and gas reserves and reserve life index projections; the
Companys projected ability to extend its debt program on an ongoing basis;
the impact of safety and environmental risk management programs; projected
volatility of crude oil prices in 2004 and the impact which weather and
economic activity levels may have on commodity prices and storage demand in
2004 and beyond; projected net earnings and cash flow sensitivity to
changes in commodity prices for 2004; projected tax rates and projected
cash taxes payable for 2004 and the assumptions on which they are based;
the impact on 2004 natural gas production of regulatory rulings and the
impact of pipeline rate increases on AECO basis prices in 2004 and beyond. 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 or probable reserves; 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; 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 brought against the Company and its
subsidiaries; the risk that the anticipated synergies to be realized by the
merger of Alberta Energy Company Ltd. (AEC) and the Company will not be
realized; costs relating to the merger of AEC and the Company being higher
than anticipated 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. M1




---



##### 



NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION ADVISORY  The reserves and other oil and gas information contained in this
MD&A has been prepared in accordance with U.S. disclosure standards, in
reliance on an exemption from the Canadian disclosure standards granted to
EnCana by Canadian securities regulatory authorities. Such information may
differ from the corresponding information prepared in accordance with
Canadian disclosure standards under National Instrument 51-101 (NI 51-101).
The reserves quantities disclosed in this MD&A represent net proved
reserves calculated on a constant price basis using the standards contained
in U.S. Regulation S-X. The primary differences between the U.S. requirements and the NI 51-101
requirements are that (i) the U.S. standards require disclosure only of
proved reserves, whereas NI 51-101 requires disclosure of proved and
probable reserves, and (ii) the U.S. standards require that the reserves
and related future net revenue be estimated under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made, whereas NI 51-101 requires disclosure of proved reserves and the
related future net revenue estimated using constant prices and costs as at
the last day of the financial year, and of proved and probable reserves and
related future net revenue using forecast prices and costs. The definitions
of proved reserves also differ, but according to the Canadian Oil and Gas
Evaluation Handbook (the reference source for the definition of proved
reserves under NI 51-101) differences in the estimated proved reserve
quantities based on constant prices should not be material. EnCana concurs
with this assessment. In this MD&A, certain natural gas volumes have been converted to barrels of
oil equivalent (BOEs) on the basis of six thousand cubic feet (mcf) to one
barrel (bbl). BOEs may be misleading, particularly if used in isolation. A
BOE conversion ratio of 6 mcf:1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent equivalency at the well head. Natural gas volumes are sold based on heat content or in millions of
British Thermal Units (MMBtu) but physically measured in thousands of
cubic feet. The average heat content per cubic foot of EnCanas natural gas
is approximately 1,040 Btu or a conversion ratio of 1 mcf = 1.040 MMBtu. MANAGEMENTS DISCUSSION AND ANALYSIS This Managements Discussion and Analysis (MD&A) for EnCana Corporation
(EnCana or the Company) should be read in conjunction with the audited
annual Consolidated Financial Statements (Consolidated Financial
Statements) and accompanying notes. The Consolidated Financial Statements
and comparative information have been prepared in accordance with Canadian
generally accepted accounting principles (Canadian GAAP) in the currency
of the United States (except where indicated as being in another currency).
A reconciliation to United States GAAP is included in Note 20 to the
Consolidated Financial Statements. This MD&A is dated February 6, 2004. M2




---



##### 



OVERVIEW U.S. DOLLAR AND U.S. PROTOCOL REPORTING The audited Consolidated Financial Statements, including the 2001 and 2002
comparative figures, have been presented in United States dollars (U.S.
dollars). The Company has adopted the U.S. dollar as its reporting
currency since most of its revenues are closely tied to the U.S. dollar and
to facilitate direct comparisons to other North American upstream
exploration and development companies. In this MD&A, all references to $
are to the U.S. dollar. References to C$ are to the Canadian dollar. In this MD&A and in the supplementary information to the audited
Consolidated Financial Statements, reserves quantities, production and
sales volumes are presented on an after royalties basis consistent with
U.S. protocol reporting. Changing the reporting currency affects the presentation in the Companys
Consolidated Financial Statements, but not the underlying accounting
records. The functional currency of the Company, and its subsidiaries,
remains Canadian dollars for Canadian legal entities and U.S. dollars and
pounds sterling for non-Canadian legal entities. The financial results of
Canadian and United Kingdom (U.K.) legal entities have been translated
into U.S. dollars as described in Notes 1 and 2 of the Consolidated
Financial Statements. Impacts on results due to the change in the U.S./Canadian dollar exchange
rate in prior periods have been significant when analyzing specific
components of the Canadian business contained in the Consolidated Financial
Statements. The stronger Canadian dollar resulted in gains on U.S. dollar
denominated long-term debt borrowed in Canada, but adversely affected the
reported U.S. dollar costs of operating, capital expenditures and
depreciation, depletion and amortization (DD&A) denominated in Canadian
dollars. Since commodity prices received are based on U.S. dollars, or on
Canadian dollar prices which are closely tied to the U.S. dollar, revenues
for the Company were relatively unaffected by the exchange rate change. BUSINESS SEGMENTS EnCana reports the results of its continuing operations under two main
business segments: Upstream and Midstream & Marketing. Upstream includes
the Companys exploration for, as well as development and production of,
natural gas, natural gas liquids (NGLs), crude oil and other related
activities. Upstream operations are divided into producing and other
activities. Producing activities are further segmented by geography and
product type. Natural gas and NGLs are principally produced in Canada, the
United States, and the U.K. central North Sea. Crude oil is principally
produced in North America (primarily Canada), Ecuador and the U.K. central
North Sea. International New Ventures Exploration is mainly focused on
exploration opportunities in Africa, South America and the Middle East and
is included under Other activities. Other activities also include third
party gas processing, gas gathering and electrical generation associated
with producing activities. The Midstream & Marketing segment includes
natural gas storage operations, NGLs processing, power generating
operations and marketing activities. These marketing activities include the
sale and delivery of produced product and the purchase of third party
product primarily for the optimization of the Midstream assets as well as
the optimization of transportation arrangements not fully utilized for the
Companys own production. BUSINESS ENVIRONMENT Commodity Price and Foreign Exchange Benchmarks 2003 vs
    
    
    
    
    
    2002 vs(average for the year unless otherwise noted)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001AECO Price (C$  per thousand
cubic feet)
    
    $
    6.70
    
    
    
    65
    %
    
    $
    4.07
    
    
    
    35
    %
    
    $
    6.30NYMEX Price ($  per million
British thermal units)
    
    
    5.39
    
    
    
    67
    %
    
    
    3.22
    
    
    
    25
    %
    
    
    4.27AECO/NYMEX Basis Differential
($  per million British
thermal units)
    
    
    0.65
    
    
    
    2
    %
    
    
    0.66
    
    
    
    128
    %
    
    
    0.29WTI ($  per barrel)
    
    
    30.99
    
    
    
    19
    %
    
    
    26.15
    
    
    
    1
    %
    
    
    25.95WTI/Bow River Differential ($
per barrel)
    
    
    8.01
    
    
    
    35
    %
    
    
    5.93
    
    
    
    40
    %
    
    
    9.87WTI/OCP NAPO Differential
(Ecuador) ($  per barrel)(1)
    
    
    8.06
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    WTI/Oriente Differential
(Ecuador) ($  per barrel)
    
    
    5.59
    
    
    
    34
    %
    
    
    4.16
    
    
    
    41
    %
    
    
    7.02U.S./Canadian Dollar Year End
Exchange Rate
    
    
    0.774
    
    
    
    22
    %
    
    
    0.633
    
    
    
    1
    %
    
    
    0.628U.S./Canadian Dollar Average
Exchange Rate
    
    
    0.716
    
    
    
    12
    %
    
    
    0.637
    
    
    
    1
    %
    
    
    0.646
  (1)
    
    This reference price was not available previously and represents the
average differential for the period of September (OCP Pipeline shipment
commencement) to December 2003. M3




---



##### 



Natural gas prices rebounded in 2003 from weaker prices experienced in
2002. Continuing concerns about overall North American storage inventory
levels, cooler than normal temperatures experienced in the fourth quarter
and a lack of confidence concerning prospects for North American supply
growth resulted in an increase in the average New York Mercantile Exchange
(NYMEX) price of 67 percent in 2003 when compared to 2002. The average
NYMEX gas price in the fourth quarter of 2003 was $4.58 per MMBtu, an
increase of 15 percent over the fourth quarter price in 2002 of $3.98 per
MMBtu. Lower gas prices in 2002 were the result of high levels of natural
gas in storage from decreased demand. The AECO/NYMEX basis differential in
the fourth quarter of 2003 averaged $0.37 per MMBtu below NYMEX. This
represented an improvement of $0.26 per MMBtu over the average in the same
period in 2002 of $0.63 per MMBtu. The improvement in the basis
differential can be attributed to a stronger Canadian dollar and higher
prices for the portion of sales volumes transported from Alberta to Eastern
Canada. In 2003, EnCana sold approximately 47 percent of its produced natural gas
at fixed prices, approximately 9 percent at AECO Index based pricing,
approximately 39 percent at NYMEX based pricing and approximately 5 percent
at other prices. As of December 31, 2003, the Company had arranged for the
sale of its projected 2004 natural gas production of approximately 45
percent at fixed prices, approximately 9 percent at AECO Index based
prices, approximately 42 percent at NYMEX based prices and approximately 4
percent at other prices. World crude oil prices increased significantly in 2003 over 2002 and 2001
as supply disruptions in Venezuela and Nigeria preceded the invasion of
Iraq. The slow return of Iraqi oil production and OPECs successful
production management combined with strong Asian demand kept crude oil
inventories low with resulting upward pressure on prices. The benchmark
West Texas Intermediate (WTI) crude oil price of $31.16 per barrel in the
fourth quarter of 2003 was $2.93 higher than the $28.23 per barrel in the
fourth quarter of 2002. Canadian heavy oil differentials, as evidenced by the WTI/Bow River
differential, widened in absolute terms in 2003 compared to 2002. The
widening is primarily due to the higher price for WTI. As a percentage of
WTI, Bow Rivers average sales price for 2003 was 74 percent of WTI as
compared to 77 percent in 2002. In 2001, Canadian heavy oil differentials
were very wide due to refinery problems and narrowed in 2002 as those
problems were rectified. Ecuadors Oriente differential also widened in 2003 compared to 2002 as a
result of the increase in WTI prices. In September 2003, the OCP Pipeline
became operational resulting in the creation of a new Ecuadorian crude
called NAPO blend. NAPO blend is a heavier crude than Oriente and therefore
has a wider differential to WTI. The 2003 year end U.S./Canadian dollar exchange rate increased by 22
percent when compared to 2002 and was $0.774 per $1 Canadian at December
31, 2003 compared to $0.633 and $0.628 at the end of 2002 and 2001
respectively. The change from 2002 was primarily the result of the economic
slowdown in the U.S., continuing differences between Canadian and U.S.
interest rates and the U.S. current account deficit. MANAGEMENT STRATEGY Upstream capital investment programs are principally focused on growing
reserves and production in North American resource plays where the Company
believes it has a competitive advantage through exploitation of existing
resource holdings in strategic gas developments at Greater Sierra and
Cutbank Ridge in British Columbia, Southern Alberta, Jonah and Mamm Creek
in the U.S. Rockies as well as oil development at Foster Creek, Pelican
Lake and Suffield. In addition to Ecuador, the development of discoveries
in the U.K. central North Sea and the Gulf of Mexico are expected to add
further to oil growth. Additional upside potential exists in the East Coast
of Canada and international exploration activities. Midstream opportunities
are focused on expansion and development of the Companys North American
gas storage business. The success of these strategies is subject to numerous risk factors such as
(including but not limited to) fluctuations in commodity prices, foreign
exchange rates and interest rates, in addition to credit, operational and
safety and environmental risks. A number of these risks have been partially
mitigated through the risk management program detailed in Note 17 of the
Consolidated Financial Statements and discussed in the Risk Management
section of this MD&A. 2003 VERSUS 2002 COMPARATIVES The 2002 comparative figures included in the Consolidated Financial
Statements for the year ended December 31, 2003 exclude the results of
Alberta Energy Company Ltd. (AEC) prior to the April 5, 2002 merger
(Merger) with AEC. M4




---



##### 



CONSOLIDATED FINANCIAL RESULTS Consolidated Financial Summary 2003vs
    
    
    
    
    
    2002vs($ millions, except per share amounts)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Revenues, Net of Royalties
    
    $
    10,216
    
    
    
    63
    %
    
    $
    6,276
    
    
    
    93
    %
    
    $
    3,244Net Earnings from Continuing Operations
    
    
    2,167
    
    
    
    195
    %
    
    
    735
    
    
    
    12
    %
    
    
    832 per share  basic
    
    
    4.57
    
    
    
    160
    %
    
    
    1.76
    
    
    
    46
    %
    
    
    3.26 per share  diluted
    
    
    4.52
    
    
    
    160
    %
    
    
    1.74
    
    
    
    46
    %
    
    
    3.21Net Earnings
    
    
    2,360
    
    
    
    191
    %
    
    
    812
    
    
    
    5
    %
    
    
    854 per share  basic
    
    
    4.98
    
    
    
    157
    %
    
    
    1.94
    
    
    
    42
    %
    
    
    3.34 per share  diluted
    
    
    4.92
    
    
    
    156
    %
    
    
    1.92
    
    
    
    42
    %
    
    
    3.30Cash Flow from Continuing Operations
    
    
    4,420
    
    
    
    95
    %
    
    
    2,267
    
    
    
    55
    %
    
    
    1,463 per share  basic
    
    
    9.32
    
    
    
    72
    %
    
    
    5.43
    
    
    
    5
    %
    
    
    5.72 per share  diluted
    
    
    9.21
    
    
    
    72
    %
    
    
    5.36
    
    
    
    5
    %
    
    
    5.65Cash Flow
    
    
    4,459
    
    
    
    84
    %
    
    
    2,419
    
    
    
    62
    %
    
    
    1,494 per share  basic
    
    
    9.41
    
    
    
    63
    %
    
    
    5.79
    
    
    
    1
    %
    
    
    5.85 per share  diluted
    
    
    9.30
    
    
    
    63
    %
    
    
    5.72
    
    
    
    1
    %
    
    
    5.77Total Assets
    
    
    24,110
    
    
    
    21
    %
    
    
    19,912
    
    
    
    192
    %
    
    
    6,823Long-Term Debt
    
    
    6,088
    
    
    
    21
    %
    
    
    5,051
    
    
    
    244
    %
    
    
    1,467Cash Dividends (1)
    
    
    139
    
    
    
    29
    %
    
    
    108
    
    
    
    87
    %
    
    
    818
  (1)
    
    Represents cash dividends paid to common shareholders at the rate of
C$0.40 per share annually. 2001 also includes a special dividend paid to
common shareholders of C$4.60 per share as part of the reorganization of
Canadian Pacific Limited, the former principal shareholder of the Companys
predecessor, PanCanadian Petroleum Ltd. 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
are not measures that have any standardized meaning prescribed by Canadian
GAAP and 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 utilizes Cash Flow and Cash Flow from Continuing
Operations as key measures to assess the ability of the Company to finance
operating activities and capital expenditures. EnCanas cash flow from continuing operations and net earnings from
continuing operations increased 95 percent and 195 percent respectively
compared to 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. dollar denominated debt issued in Canada of $433 million, or $0.90 per
diluted share resulting from the increase in the value of the Canadian
dollar versus the U.S. dollar, and a $359 million, or $0.75 per diluted
share recovery of future income taxes resulting from reductions in the
Canadian federal and Alberta corporate income tax rates. Impacts on results
due to the change in the U.S./Canadian dollar exchange rate have been
significant when analyzing specific components contained in the
Consolidated Financial Statements. For every 100 dollars denominated in
Canadian currency spent on capital projects, operating expenses and
administrative expenses, the Company incurred additional costs, as reported
in U.S. dollars, of approximately $7.90 based on the increase in the
average U.S./Canadian dollar exchange rate in 2003 of $0.716 over 2002 of
$0.637. Revenues for the Company were relatively unaffected by the
increased exchange rate since commodity prices received are based in U.S.
dollars or in Canadian dollar prices which are closely tied to the U.S.
dollar. 2002 VERSUS 2001 Cash flow from continuing operations and net earnings from continuing
operations in 2002 increased 55 percent and decreased 12 percent
respectively compared to 2001. The cash flow increase was due to the
inclusion of nine months of post Merger results in 2002, reduced operating
costs associated with crude oil production, partially offset by reduced
natural gas prices. The net earnings drop was the result of weaker natural
gas prices, increased depreciation, depletion and amortization rates
resulting from the Merger, partially offset by increased sales volumes
resulting from the Merger and the Companys expansion of its North American
operations. Earnings from Continuing Operations Excluding Unrealized Foreign Exchange
on Translation of Canadian Issued U.S. Dollar Debt (After Tax) and Tax
Rate Reductions The following table has been prepared in order to provide shareholders and
potential investors with information clearly presenting the effect of the
translation of the outstanding U.S. dollar debt issued in Canada and the
effect of M5




---



##### 



the reduction in the Canadian and Alberta tax rates on the Companys
results. The majority of these unrealized gains/losses on U.S. dollar debt
issued in Canada relate to debt with maturity dates in excess of 5 years.
In accordance with Canadian GAAP, the Company is required to translate U.S.
dollar denominated long-term debt issued in Canada into Canadian dollars at
the period end exchange rate. Resulting foreign exchange gains or losses
are recorded in the Consolidated Statement of Earnings. Canadian GAAP also
requires the Company to recognize impacts of tax rate changes that are
substantively enacted. Gains or losses from these changes are also recorded
in the Consolidated Statement of Earnings and included as an adjustment to
Future Income Taxes in the Consolidated Balance Sheet. ($ millions)
    
    2003
    
    2002
    
    2001Net Earnings from Continuing Operations, as reported
    
    $
    2,167
    
    
    $
    735
    
    
    $
    832Deduct: Unrealized foreign exchange gain (loss) on translation
of Canadian issued U.S. dollar debt (after-tax) (1)
    
    
    433
    
    
    
    17
    
    
    
    (28
    )Deduct: Future tax recovery due to tax rate reductions (2)
    
    
    359
    
    
    
    20
    
    
    
    53Earnings from Continuing Operations, excluding unrealized
foreign exchange on translation of Canadian issued
U.S. dollar debt (after-tax) and tax rate reductions
    
    $
    1,375
    
    
    $
    698
    
    
    $
    807
 ($ per Common Share  DilutedNet Earnings from Continuing Operations, as reported
    
    $
    4.52
    
    
    $
    1.74
    
    
    $
    3.21Deduct: Unrealized foreign exchange gain (loss) on translation
of Canadian issued U.S. dollar debt (after-tax) (1)
    
    
    0.90
    
    
    
    0.04
    
    
    
    (0.11
    )Deduct: Future tax recovery due to tax rate reductions (2)
    
    
    0.75
    
    
    
    0.05
    
    
    
    0.20Earnings from Continuing Operations, excluding unrealized
foreign exchange on translation of Canadian issued
U.S. dollar debt (after-tax) and tax rate reductions
    
    $
    2.87
    
    
    $
    1.65
    
    
    $
    3.12
  (1)
    
    Unrealized gain (loss)
has no impact on cash flow.  (2)
    
    Future tax adjustments
have no impact on cash flow. Earnings from Continuing Operations, excluding unrealized foreign exchange
on translation of Canadian issued U.S. dollar debt (after tax) and tax rate
reductions is not a measure that has any standardized meaning prescribed by
Canadian GAAP and is considered a non-GAAP measure. Therefore, this measure
may not be comparable to similar measures presented by other issuers. This
measure has been described and presented in this MD&A in order to provide
shareholders and potential investors with additional information regarding
the Companys finances and results of operations. Management believes items
such as foreign exchange gains and losses or tax rate reductions distort
results and reduce comparability of the Companys underlying financial
performance between periods. Quarterly results were as follows: 2003 and 2002 Quarterly Summary 2003
    
    2002($ millions, except per share amounts)
    
    Q4
    
    Q3
    
    Q2
    
    Q1
    
    Q4
    
    Q3
    
    Q2
    
    Q1*Revenues, Net of Royalties
    
    $
    2,850
    
    
    $
    2,291
    
    
    $
    2,332
    
    
    $
    2,743
    
    
    $
    2,116
    
    
    $
    1,780
    
    
    $
    1,693
    
    
    $
    687Net Earnings from Continuing
Operations
    
    
    426
    
    
    
    286
    
    
    
    805
    
    
    
    650
    
    
    
    248
    
    
    
    79
    
    
    
    318
    
    
    
    90 per share  basic
    
    
    0.92
    
    
    
    0.60
    
    
    
    1.67
    
    
    
    1.35
    
    
    
    0.52
    
    
    
    0.17
    
    
    
    0.69
    
    
    
    0.35 per share  diluted
    
    
    0.91
    
    
    
    0.60
    
    
    
    1.66
    
    
    
    1.34
    
    
    
    0.51
    
    
    
    0.16
    
    
    
    0.68
    
    
    
    0.35Net Earnings
    
    
    426
    
    
    
    290
    
    
    
    807
    
    
    
    837
    
    
    
    282
    
    
    
    136
    
    
    
    303
    
    
    
    91 per share  basic
    
    
    0.92
    
    
    
    0.61
    
    
    
    1.68
    
    
    
    1.74
    
    
    
    0.59
    
    
    
    0.29
    
    
    
    0.66
    
    
    
    0.36 per share  diluted
    
    
    0.91
    
    
    
    0.61
    
    
    
    1.67
    
    
    
    1.73
    
    
    
    0.58
    
    
    
    0.28
    
    
    
    0.65
    
    
    
    0.35Cash Flow from Continuing
Operations
    
    
    1,217
    
    
    
    973
    
    
    
    1,039
    
    
    
    1,191
    
    
    
    874
    
    
    
    583
    
    
    
    569
    
    
    
    241 per share  basic
    
    
    2.63
    
    
    
    2.06
    
    
    
    2.16
    
    
    
    2.48
    
    
    
    1.83
    
    
    
    1.22
    
    
    
    1.23
    
    
    
    0.94 per share  diluted
    
    
    2.61
    
    
    
    2.04
    
    
    
    2.14
    
    
    
    2.46
    
    
    
    1.81
    
    
    
    1.21
    
    
    
    1.22
    
    
    
    0.93Cash Flow
    
    
    1,254
    
    
    
    977
    
    
    
    1,007
    
    
    
    1,221
    
    
    
    935
    
    
    
    651
    
    
    
    591
    
    
    
    242 per share  basic
    
    
    2.71
    
    
    
    2.06
    
    
    
    2.10
    
    
    
    2.54
    
    
    
    1.96
    
    
    
    1.37
    
    
    
    1.28
    
    
    
    0.95 per share  diluted
    
    
    2.69
    
    
    
    2.04
    
    
    
    2.08
    
    
    
    2.52
    
    
    
    1.94
    
    
    
    1.35
    
    
    
    1.26
    
    
    
    0.94
 * Excludes the pre-merger results of
AEC. M6




---



##### 



Quarterly results in 2003, as compared to the same periods in 2002, reflect
the impacts of increasing commodity prices, increased production volumes,
inclusion of a full year of post Merger results and are partially offset by
increased expenses. The 2003 after tax unrealized foreign exchange gain on
translation of Canadian issued U.S. dollar debt of $433 million was
reported as $140 million in the first quarter, $168 million in the second
quarter, $12 million in the third quarter and $113 million in the fourth
quarter. The 2003 future tax recovery due to tax rate reductions of $359
million was recorded in the second quarter. ACQUISITIONS AND DIVESTITURES On October 1, 2003, an EnCana U.K. subsidiary became the operator of the
Scott and Telford fields in the U.K. central North Sea marking the close of
the purchase and sale agreements to exchange the 22.5 percent non-operated
interest in the Llano oil discovery in the Gulf of Mexico for a 14 percent
interest in both the Scott and Telford oil fields. In early 2004, the EnCana
U.K. subsidiary completed the purchase of additional 13.5 percent and 20.2
percent interests in the Scott and Telford fields, respectively, for net
cash consideration of approximately $126 million. As a result of these
acquisitions and the initial ownership interest held, the EnCana U.K.
subsidiary now holds a 41 percent interest in the Scott field and a 54.3
percent interest in the Telford field. On July 18, 2003, an EnCana U.S. subsidiary acquired the common shares of
Savannah Energy Inc. (Savannah) for net cash consideration of
approximately $91 million. Included in this acquisition were interests in
developed and undeveloped reserves and landholdings in Texas, U.S.A. which
are currently producing approximately 21 million cubic feet of natural gas
per day. On January 31, 2003, the Company expanded its production and landholdings
in Ecuador through the purchase of interests held by Vintage Petroleum Inc.
for net cash consideration of approximately $116 million. This acquisition
included interests in developed and undeveloped reserves producing
approximately 4,000 barrels of oil per day in three blocks adjacent to
Block 15, where an EnCana subsidiary has an existing non-operated working
interest. During 2003, the Company acquired and disposed of other properties that had
a less significant impact on operations. On a net basis, the total amount
of additional acquisitions over dispositions was $183 million. Property
acquisitions have been included as part of total capital expenditures as
discussed in the Liquidity and Capital Resources section of this MD&A. DISCONTINUED OPERATIONS Syncrude During 2003, subsidiaries of the Company completed the sale of their
working interest together with EnCanas gross overriding royalty in the
Syncrude Joint Venture for net cash consideration of approximately $1.0
billion
(C$1.45 billion). There was no gain or loss recorded on this sale. Net
earnings from Syncrude operations were $24 million in 2003. With the sale of
the Syncrude interest completed, the Company intends to focus its oilsands
strategy on developing its high quality bitumen resources, recovered through
producing wells using Steam Assisted Gravity Drainage (SAGD) technology on
100 percent owned and operated lands at Foster Creek and Christina Lake. Midstream  Pipelines Subsidiaries of the Company closed the sale of their interests in the Cold
Lake Pipeline System and Express Pipeline System on January 2, 2003 and
January 9, 2003, respectively, for total consideration of approximately
$1.0 billion
(C$1.6 billion), including the assumption of related long-term debt by the
purchaser. An after-tax gain on sale of $169 million was recorded in
relation to these transactions. These sales were part of EnCanas strategic realignment to focus on
developing its large portfolio of higher return growth assets. The proceeds
were used for general corporate purposes, including debt reduction, prior
to being re-deployed as discussed in the Liquidity and Capital Resources
section of this MD&A. The Syncrude and Midstream-Pipelines operations described above have been
accounted for as discontinued operations as disclosed in Note 5 to the
Consolidated Financial Statements. M7




---



##### 



RESULTS OF OPERATIONS UPSTREAM OPERATIONS* Financial Results($ millions) 2003
    
    2002
    
    2001Produced
    
    
    
    
    
    
    
    
    
    
    
    
    
    Produced
    
    
    
    
    
    
    
    
    
    
    
    
    
    ProducedYear ended
    
    Gas &
    
    Crude
    
    
    
    
    
    
    
    
    
    Gas &
    
    Crude
    
    
    
    
    
    
    
    
    
    Gas &
    
    CrudeDecember 31
    
    NGLs (1)
    
    Oil
    
    Other
    
    Total
    
    NGLs (1)
    
    Oil
    
    Other
    
    Total
    
    NGLs (1)
    
    Oil
    
    Other
    
    TotalRevenues, Net
of Royalties
    
    $
    4,690
    
    
    $
    1,457
    
    
    $
    180
    
    
    $
    6,327
    
    
    $
    2,440
    
    
    $
    1,158
    
    
    $
    76
    
    
    $
    3,674
    
    
    $
    1,670
    
    
    $
    621
    
    
    $
    24
    
    
    $
    2,315ExpensesProduction
and Mineral Taxes
    
    
    160
    
    
    
    29
    
    
    
    
    
    
    
    189
    
    
    
    85
    
    
    
    34
    
    
    
    
    
    
    
    119
    
    
    
    55
    
    
    
    22
    
    
    
    
    
    
    
    77Transportation
and Selling
    
    
    370
    
    
    
    120
    
    
    
    
    
    
    
    490
    
    
    
    216
    
    
    
    61
    
    
    
    
    
    
    
    277
    
    
    
    78
    
    
    
    22
    
    
    
    
    
    
    
    100Operating
    
    
    402
    
    
    
    401
    
    
    
    170
    
    
    
    973
    
    
    
    290
    
    
    
    265
    
    
    
    71
    
    
    
    626
    
    
    
    123
    
    
    
    163
    
    
    
    8
    
    
    
    294Depreciation,
Depletion and
Amortization
    
    
    1,368
    
    
    
    669
    
    
    
    96
    
    
    
    2,133
    
    
    
    827
    
    
    
    355
    
    
    
    51
    
    
    
    1,233
    
    
    
    292
    
    
    
    166
    
    
    
    20
    
    
    
    478Upstream Income
    
    $
    2,390
    
    
    $
    238
    
    
    $
    (86
    )
    
    $
    2,542
    
    
    $
    1,022
    
    
    $
    443
    
    
    $
    (46
    )
    
    $
    1,419
    
    
    $
    1,122
    
    
    $
    248
    
    
    $
    (4
    )
    
    $
    1,366
  *
    
    Upstream results exclude Syncrude operations which have been accounted for as
discontinued operations as described in Note 5 to the Consolidated Financial
Statements.  (1)
    
    NGL results includes Condensate. Sales Volumes 2003 vs
    
    
    
    
    
    2002 vs(After Royalties)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Produced Gas (million cubic feet per day)
    
    
    2,566
    
    
    
    25
    %
    
    
    2,058
    
    
    
    105
    %
    
    
    1,005Crude Oil (barrels per day)
    
    
    198,078
    
    
    
    26
    %
    
    
    156,691
    
    
    
    72
    %
    
    
    91,093NGLs (barrels per day)
    
    
    24,466
    
    
    
    16
    %
    
    
    21,054
    
    
    
    60
    %
    
    
    13,126Continuing
Operations (barrels of oil equivalent per day)(1)
    
    
    650,211
    
    
    
    25
    %
    
    
    520,745
    
    
    
    92
    %
    
    
    271,719Syncrude (barrels per day)
    
    
    7,629
    
    
    
    68
    %
    
    
    23,540
    
    
    
    
    
    
    
    Total (barrels of oil equivalent per day)(1)
    
    
    657,840
    
    
    
    21
    %
    
    
    544,285
    
    
    
    100
    %
    
    
    271,719
  (1)
    
    Natural gas converted to barrels of oil equivalent at 6 thousand cubic feet = 1 barrel of oil equivalent. Revenue Variance(1) 2003 compared to 2002
    
    2002 compared to 2001($ millions)
    
    Price
    
    Volume
    
    Total
    
    Price
    
    Volume
    
    TotalProduced Gas and NGLs
    
    $
    1,336
    
    
    $
    914
    
    
    $
    2,250
    
    
    $
    (459
    )
    
    $
    1,229
    
    
    $
    770Crude Oil
    
    
    (5
    )
    
    
    304
    
    
    
    299
    
    
    
    52
    
    
    
    485
    
    
    
    537Other
    
    
    
    
    
    
    
    
    
    
    104
    
    
    
    
    
    
    
    
    
    
    
    52Total Revenue, Net of Royalties
    
    $
    1,331
    
    
    $
    1,218
    
    
    $
    2,653
    
    
    $
    (407
    )
    
    $
    1,714
    
    
    $
    1,359
  (1)
    
    Includes continuing operations only. CONSOLIDATED UPSTREAM RESULTS The Companys 2003 Upstream revenues, net of royalties, increased $2,653
million, or 72 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 revenue variance table shows the 2003 increase over 2002 to be
approximately 50 percent volume and 50 percent price related. The 25 percent
growth in barrels of oil equivalent sales volumes from continuing
operations, compared to 2002, reflected increased production in the U.S.
Rockies, the addition of a full year of post Merger volumes, the removal of
transportation capacity restrictions in Ecuador as a result of the
completion of the OCP Pipeline and the expansion of production from the
Companys SAGD projects. Production and mineral tax increases in 2003 are the result of higher
prices in the U.S. and Ecuador and a full year of post Merger results. M8




---



##### 



The increased expenditures for transportation and selling in 2003 are
attributable to growth in North American volumes, increases in Ecuador
volumes as a result of the commencement of shipments on the OCP Pipeline, a
full year of post Merger results and the effect of the change in the
U.S./Canadian dollar exchange rate on Canadian transportation and selling
expenses. Upstream operating costs, excluding costs related to Other activities,
increased 45 percent compared to 2002, and 94 percent when comparing 2002
to 2001. The increase in 2003 over 2002 is due to additional production
volumes, a full year of post Merger results, as well as higher unit
operating expenses. Operating expenses from continuing operations,
excluding Other activities, were $3.38 per barrel of oil equivalent for
2003 up from $2.92 per barrel of oil equivalent in 2002 and $2.88 per
barrel of oil equivalent in 2001. The increase is mainly related to 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. The increase in 2002 over 2001 resulted primarily from the
inclusion of nine months operations from the Merger. DD&A expense increased 73 percent, or $900 million, compared to 2002 and
158 percent, or $755 million, comparing 2002 to 2001. On a barrel of oil
equivalent basis, excluding Other, DD&A rates were $8.58 per barrel for
2003 compared to $6.22 per barrel and $4.62 per barrel in 2002 and 2001
respectively. 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. Rockies, and the effect of the increase in the U.S./Canadian
dollar exchange rate on the Canadian DD&A expense. The 2003 future
development costs are approximately $1.81 per barrel of oil equivalent of
the DD&A rate calculation compared to $0.53 per barrel of oil equivalent in
2002. The higher costs in 2002 compared to 2001 primarily reflected the
additional charges associated with the addition of the post Merger assets,
which were recorded at their fair value as part of the allocation of the
purchase price. Other activities added $180 million in revenues and $170 million in
operating expenses in 2003 and include activities that do not result
directly in the production of oil and gas. These activities include revenue
from third party gas processing, gas gathering and electrical generation
associated with cogeneration of steam. The higher DD&A expense, reflected
in Other activities, includes an expense of approximately $103 million for
impairments on Upstream international exploration prospects deemed not to
be commercially viable, offset by a gain realized on divestiture of an
exploration property. Produced Gas and NGLs(1) Financial Results  Canada
    
    
    
    
    
    2003 vs
    
    
    
    
    
    2002 vsYear ended December 31 ($ millions)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Revenues, Net of Royalties
    
    $
    3,523
    
    
    
    79
    %
    
    $
    1,971
    
    
    
    23
    %
    
    $
    1,598ExpensesProduction and Mineral Taxes
    
    
    52
    
    
    
    4
    %
    
    
    50
    
    
    
    4
    %
    
    
    48Transportation and Selling
    
    
    274
    
    
    
    81
    %
    
    
    151
    
    
    
    110
    %
    
    
    72Operating
    
    
    342
    
    
    
    34
    %
    
    
    255
    
    
    
    128
    %
    
    
    112Depreciation, Depletion and Amortization
    
    
    1,075
    
    
    
    72
    %
    
    
    625
    
    
    
    139
    %
    
    
    261Segment Income
    
    $
    1,780
    
    
    
    100
    %
    
    $
    890
    
    
    
    19
    %
    
    $
    1,105Gas Volume (million cubic feet per day)
    
    
    1,965
    
    
    
    15
    %
    
    
    1,711
    
    
    
    80
    %
    
    
    953NGL Volume (barrels per day)
    
    
    14,278
    
    
    
    3
    %
    
    
    13,852
    
    
    
    37
    %
    
    
    10,142
  (1)
    
    NGL results include Condensate. Financial Results - United States 2003 vs
    
    
    
    
    
    2002 vsYear ended December 31 ($ millions)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Revenues, Net of Royalties
    
    $
    1,143
    
    
    
    152
    %
    
    $
    454
    
    
    
    669
    %
    
    $
    59ExpensesProduction and Mineral Taxes
    
    
    108
    
    
    
    209
    %
    
    
    35
    
    
    
    400
    %
    
    
    7Transportation and Selling
    
    
    86
    
    
    
    46
    %
    
    
    59
    
    
    
    
    
    
    
    Operating
    
    
    60
    
    
    
    71
    %
    
    
    35
    
    
    
    218
    %
    
    
    11Depreciation, Depletion and Amortization
    
    
    293
    
    
    
    45
    %
    
    
    202
    
    
    
    552
    %
    
    
    31Segment Income
    
    $
    596
    
    
    
    385
    %
    
    $
    123
    
    
    
    1130
    %
    
    $
    10Gas Volume (million cubic feet per day)
    
    
    588
    
    
    
    74
    %
    
    
    337
    
    
    
    684
    %
    
    
    43NGL Volume (barrels per day)
    
    
    9,291
    
    
    
    45
    %
    
    
    6,407
    
    
    
    162
    %
    
    
    2,443
  (1)
    
    NGL results include Condensate. M9




---



##### 



Financial Results  United Kingdom 2003 vs
    
    
    
    
    
    2002 vsYear ended December 31 ($ millions)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Revenues, Net of Royalties
    
    $
    24
    
    
    
    60
    %
    
    $
    15
    
    
    
    15
    %
    
    $
    13ExpensesProduction and Mineral Taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Transportation and Selling
    
    
    10
    
    
    
    67
    %
    
    
    6
    
    
    
    
    
    
    
    6Operating
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Depreciation, Depletion and Amortization
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Segment Income
    
    $
    14
    
    
    
    56
    %
    
    $
    9
    
    
    
    29
    %
    
    $
    7Gas Volume (million cubic feet per day)
    
    
    13
    
    
    
    30
    %
    
    
    10
    
    
    
    11
    %
    
    
    9NGL Volume (barrels per day)
    
    
    897
    
    
    
    13
    %
    
    
    795
    
    
    
    47
    %
    
    
    541
  (1)
    
    NGL results include Condensate. In 2003, revenues, net of royalties from sales of produced gas and NGLs
contributed 74 percent of the Companys total Upstream revenue and in total
were $2,250 million higher than in 2002. The increase in 2003 revenues net
of royalties from produced gas and NGLs over 2002 was due to increased
commodity prices, drilling successes in both Canada and the U.S.,
significant property acquisitions in the U.S. Rockies in 2002 and a full
year of post Merger results. Natural gas revenues in 2003 were reduced by a
loss of $91 million due to financial currency and commodity hedging
activities, compared to a gain of $65 million in 2002 and a gain of $134
million in 2001. Gas sales from the U.S. have risen 74 percent, or 251 million cubic feet
per day, when comparing 2003 to 2002 due to drilling successes and property
acquisitions combined with a full year of post Merger results. Canadian gas
sales volumes have increased 254 million cubic feet per day primarily due
to inclusion of a full year of post Merger operations. 2003 Canadian
production gains achieved through resource development were offset by
higher than anticipated declines at Ladyfern, divestments in non-core
producing areas and weather delays for well tie-ins. Volume increases in
2002 compared to 2001 is due to the inclusion of nine months of post Merger
results in 2002. Per Unit Results  Produced Gas Produced Gas  Canada
    
    Produced Gas  U.S.($ per thousand cubic feet)
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Price, net of royalties
    
    $
    4.87
    
    
    $
    2.86
    
    
    $
    4.06
    
    
    $
    4.88
    
    
    $
    2.96
    
    
    $
    2.46ExpensesProduction and mineral taxes
    
    
    0.07
    
    
    
    0.08
    
    
    
    0.14
    
    
    
    0.47
    
    
    
    0.27
    
    
    
    0.49Transportation and selling
    
    
    0.38
    
    
    
    0.24
    
    
    
    0.21
    
    
    
    0.40
    
    
    
    0.47
    
    
    
    Operating
    
    
    0.48
    
    
    
    0.41
    
    
    
    0.32
    
    
    
    0.28
    
    
    
    0.28
    
    
    
    0.68Netback excluding hedging
    
    $
    3.94
    
    
    $
    2.13
    
    
    $
    3.39
    
    
    $
    3.73
    
    
    $
    1.94
    
    
    $
    1.29Financial hedge
    
    
    (0.13
    )
    
    
    0.05
    
    
    
    0.38
    
    
    
    0.02
    
    
    
    0.29
    
    
    
    Netback including hedging
    
    $
    3.81
    
    
    $
    2.18
    
    
    $
    3.77
    
    
    $
    3.75
    
    
    $
    2.23
    
    
    $
    1.29
 Per Unit Results  NGLs(1) NGLs  Canada
    
    NGLs  U.S.($ per barrel)
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Price, net of royalties
    
    $
    24.26
    
    
    $
    17.55
    
    
    $
    19.70
    
    
    $
    26.97
    
    
    $
    23.75
    
    
    $
    22.22ExpensesProduction and mineral taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.03
    
    
    
    1.02
    
    
    
    Transportation and selling
    
    
    0.17
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Netback
    
    $
    24.09
    
    
    $
    17.55
    
    
    $
    19.70
    
    
    $
    24.94
    
    
    $
    22.73
    
    
    $
    22.22
  (1)
    
    NGL results include Condensate. Average realized prices for natural gas in the U.S. and Canada increased
approximately 65 percent and 70 percent respectively in 2003 compared to
2002. Concerns about overall North American storage inventory levels and a
lack of confidence concerning prospects for North American supply growth
were the primary reasons for the overall increase. Lower realized gas
prices in Canada experienced in 2002 compared to 2001 were caused by high
levels of natural gas in storage during 2002 resulting from decreased
demand. Average realized prices for NGLs in the U.S. and Canada increased
approximately 14 percent and 38 percent respectively in 2003 compared to
2002. NGL realized price increases generally resulted from changes in the
price of WTI discussed previously in this MD&A. M10




---



##### 



Per unit production and mineral tax expense for produced gas in the U.S.
Rockies was higher in 2003 than 2002 by $0.20 per thousand cubic feet due
to higher natural gas prices. Per unit produced gas production and mineral
taxes were $0.22 per thousand cubic feet lower in 2002 than in 2001,
reflecting the addition of properties attracting lower production and
mineral tax rates as a result of the Merger. For Canadian produced gas operations, per unit transportation and selling
costs were higher in 2003 by $0.14 per thousand cubic feet primarily 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
transportation and selling expense in the U.S. decreased $0.07 per thousand
cubic feet when compared to 2002 due to shorter average transportation
distances to markets. Per unit operating expenses for Canadian produced gas were higher in 2003
by $0.07 per thousand cubic feet 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. Operating expenses in
the U.S. per unit remained flat for 2003 over 2002. Canadian per unit
operating expenses were higher in 2002 compared to 2001 reflecting the
addition of higher cost operations from the Merger combined with higher
processing fees, gathering, maintenance and electricity costs. U.S. per
unit operating expenses decreased in 2002 compared to 2001 reflecting the
addition of significant lower cost operations and higher production volumes
from the Merger. Crude Oil Financial Results  North America 2003 vs
    
    
    
    
    
    2002 vsYear ended December 31 ($ millions)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Revenues, Net of Royalties
    
    $
    951
    
    
    
    15
    %
    
    $
    825
    
    
    
    58
    %
    
    $
    523ExpensesProduction and Mineral
Taxes
    
    
    4
    
    
    
    80
    %
    
    
    20
    
    
    
    9
    %
    
    
    22Transportation and Selling
    
    
    69
    
    
    
    97
    %
    
    
    35
    
    
    
    119
    %
    
    
    16Operating
    
    
    300
    
    
    
    49
    %
    
    
    201
    
    
    
    31
    %
    
    
    153Depreciation, Depletion
and Amortization
    
    
    436
    
    
    
    84
    %
    
    
    237
    
    
    
    91
    %
    
    
    124Segment Income
    
    $
    142
    
    
    
    57
    %
    
    $
    332
    
    
    
    60
    %
    
    $
    208Volumes (barrels per day)
    
    
    142,326
    
    
    
    21
    %
    
    
    117,218
    
    
    
    46
    %
    
    
    80,272
 Financial Results - Ecuador 2003 vs
    
    
    
    
    
    2002 vsYear ended December 31 ($ millions)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Revenues, Net of Royalties
    
    $
    412
    
    
    
    68
    %
    
    $
    245
    
    
    
    
    
    
    $
    ExpensesProduction and Mineral
Taxes
    
    
    25
    
    
    
    79
    %
    
    
    14
    
    
    
    
    
    
    
    Transportation and Selling
    
    
    45
    
    
    
    114
    %
    
    
    21
    
    
    
    
    
    
    
    Operating
    
    
    83
    
    
    
    57
    %
    
    
    53
    
    
    
    
    
    
    
    Depreciation, Depletion
and Amortization
    
    
    159
    
    
    
    101
    %
    
    
    79
    
    
    
    
    
    
    
    Segment Income
    
    $
    100
    
    
    
    28
    %
    
    $
    78
    
    
    
    
    
    
    $
    Volumes (barrels per day)
    
    
    46,521
    
    
    
    56
    %
    
    
    29,740
    
    
    
    
    
    
    
    
 Financial Results - United Kingdom 2003 vs
    
    
    
    
    
    2002 vsYear ended December 31 ($ millions)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Revenues, Net of Royalties
    
    $
    94
    
    
    
    7
    %
    
    $
    88
    
    
    
    10
    %
    
    $
    98ExpensesProduction and Mineral
Taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Transportation and Selling
    
    
    6
    
    
    
    20
    %
    
    
    5
    
    
    
    17
    %
    
    
    6Operating
    
    
    18
    
    
    
    64
    %
    
    
    11
    
    
    
    10
    %
    
    
    10Depreciation, Depletion
and Amortization
    
    
    74
    
    
    
    90
    %
    
    
    39
    
    
    
    7
    %
    
    
    42Segment Income
    
    $
    (4
    )
    
    
    112
    %
    
    $
    33
    
    
    
    18
    %
    
    $
    40Volumes (barrels per day)
    
    
    9,231
    
    
    
    5
    %
    
    
    9,733
    
    
    
    10
    %
    
    
    10,821
 In 2003, total revenues, net of royalties for crude oil, increased $299
million, or 26 percent, over 2002. The improvement is attributable to
increased production volumes, a full year of post Merger volumes and higher
average realized commodity prices offset by increased losses related to
financial hedging. Crude oil revenues were reduced by a loss of
approximately $206 million resulting from financial commodity and currency
hedging. This compares with a loss of $33 million in 2002 and a gain of $20
million in 2001. M11




---



##### 



North American crude oil sales volumes averaged 142,326 barrels per day
compared to 117,218 barrels per day in 2002. The improvement in North
American sales volumes reflects the inclusion of a full year of post Merger
volumes, increased production at Foster Creek including completion of the
Phase 1 expansion and a full year of commercial production at Christina
Lake combined with continued development at Suffield and Pelican Lake.
Sales volumes in 2002 were higher than 2001 volumes of 80,272 primarily due
to the inclusion of nine months of post Merger results. Ecuador crude oil sales volumes increased by 56 percent in 2003 to 46,521
barrels per day compared to volumes of 29,740 barrels per day in 2002
primarily 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, partially
offset by the requirement to provide line fill for OCP of approximately
3,213 barrels per day. Sales volumes during the fourth quarter of 2003
averaged 77,352 barrels per day compared with 35,900 barrels per day in the
same period in 2002. The Company has a shipping commitment of approximately
108,000 barrels per day on the OCP Pipeline and currently does not have
transportation capacity constraints on its production. The Companys
shipping commitment was based on estimated gross production volumes which
included the royalty portion taken in-kind by the Ecuadorian government.
The Ecuadorian government subsequently decided to transport its royalty
volumes on the SOTE pipeline. As a result of this decision the Company
incurs additional transportation costs of approximately $0.80 to $1.10 per
barrel on the current level of volumes transported through the OCP
Pipeline. Acquisition of additional interests in the Scott and Telford fields was the
major contributor to higher crude oil volumes of 13,665 barrels per day
from the U.K. central North Sea in the fourth quarter of 2003 compared to
7,151 barrels per day in the same period in 2002. Crude oil volumes for
2003 averaged 9,231 barrels per day compared to 9,733 barrels per day and
10,821 barrels per day in 2002 and 2001 respectively. The overall decrease
in 2003 average volumes resulted from natural declines and unscheduled
downtime partially offset by the additional ownership interests. Per Unit Results  Crude Oil North America
    
    Ecuador
    
    United Kingdom($ per barrel)
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Price, net of royalties
    
    $
    22.29
    
    
    $
    20.08
    
    
    $
    17.35
    
    
    $
    24.21
    
    
    $
    22.57
    
    
    $
    
    
    
    $
    28.11
    
    
    $
    24.76
    
    
    $
    24.62ExpensesProduction and mineral taxes
    
    
    0.09
    
    
    
    0.43
    
    
    
    0.71
    
    
    
    1.47
    
    
    
    1.24
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Transportation and selling
    
    
    1.31
    
    
    
    0.82
    
    
    
    0.55
    
    
    
    2.56
    
    
    
    2.00
    
    
    
    
    
    
    
    1.97
    
    
    
    1.69
    
    
    
    1.68Operating
    
    
    5.80
    
    
    
    4.69
    
    
    
    5.24
    
    
    
    4.84
    
    
    
    4.86
    
    
    
    
    
    
    
    5.09
    
    
    
    3.28
    
    
    
    2.69Netback excluding hedging
    
    $
    15.09
    
    
    $
    14.14
    
    
    $
    10.85
    
    
    $
    15.34
    
    
    $
    14.47
    
    
    $
    
    
    
    $
    21.05
    
    
    $
    19.79
    
    
    $
    20.25Financial hedge
    
    
    (3.97
    )
    
    
    (0.76
    )
    
    
    0.60
    
    
    
    
    
    
    
    (0.01
    )
    
    
    
    
    
    
    
    
    
    
    (0.06
    )
    
    
    0.46Netback including hedging
    
    $
    11.12
    
    
    $
    13.38
    
    
    $
    11.45
    
    
    $
    15.34
    
    
    $
    14.46
    
    
    $
    
    
    
    $
    21.05
    
    
    $
    19.73
    
    
    $
    20.71
 Average realized crude oil prices in 2003 increased approximately 10
percent over 2002 and approximately 14 percent in 2002 when compared to
2001. Continuing concerns over tensions in the Middle East combined with
strong Asian demand and OPECs management of its production quotas were the
primary reasons for the overall increase in 2003 offset by increased crude
oil price differentials. The change in 2002 over 2001 reflects the average
price weightings of additional volumes from the Merger. North American per unit production and mineral taxes were $0.09 per barrel
compared to $0.43 per barrel in 2002. North American 2003 per unit
production and mineral taxes include the impact of mineral tax amendments,
related to prior years and recorded in the third quarter of 2003, which
reduced mineral taxes by approximately $16 million or $0.30 per barrel.
Production and mineral taxes in Ecuador increased $0.23 per barrel, or 19
percent, in 2003 over 2002. This is due to the increased production from
the Tarapoa block and higher realized prices from the Tarapoa volumes. The
Company is required to pay the Ecuadorian government a percentage of
revenue from this block based on realized prices over a base price. Per unit transportation and selling costs in North America were higher by
$0.49 per barrel, or 60 percent, over 2002. The increase resulted primarily
from increased heavy crude oil volumes which attract a 20 percent premium
transportation charge over light oil combined with annual tariff increases.
Compared to 2002, higher per unit transportation and selling costs in
Ecuador reflect the higher unit costs on the OCP Pipeline in 2003 compared
to the SOTE pipeline system resulting from the ship or pay obligations on
the system requiring the Company to M12




---



##### 



pay for a prescribed amount of capacity at a fixed rate. Per unit
transportation and selling costs in the U.K. increased 17 percent in 2003
compared to 2002, primarily as a result of the strengthening of the British
pound relative to the U.S. dollar. The increase in North American unit operating expenses for crude oil of
$1.11 per barrel over 2002 is attributable to the increase in the
U.S./Canadian dollar exchange rate, higher maintenance costs, increased
production of heavy oil volumes from SAGD projects at Foster Creek and
Christina Lake, combined with higher fuel and electricity costs resulting
from the rise in natural gas prices. The U.K. 2003 per unit operating
expenses increased 55 percent over 2002 due to unscheduled maintenance
costs, acquisition related costs as well as the strengthening of the
British pound relative to the U.S. dollar. Midstream & Marketing Operations Financial Results(1) Midstream
    
    Marketing
    
    Total($ millions)
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues
    
    $
    1,084
    
    
    $
    440
    
    
    $
    154
    
    
    $
    2,803
    
    
    $
    2,154
    
    
    $
    777
    
    
    $
    3,887
    
    
    $
    2,594
    
    
    $
    931ExpensesTransportation and selling
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    55
    
    
    
    87
    
    
    
    11
    
    
    
    55
    
    
    
    87
    
    
    
    11Operating
    
    
    261
    
    
    
    174
    
    
    
    142
    
    
    
    63
    
    
    
    13
    
    
    
    12
    
    
    
    324
    
    
    
    187
    
    
    
    154Purchased product
    
    
    762
    
    
    
    169
    
    
    
    
    
    
    
    2,693
    
    
    
    2,031
    
    
    
    739
    
    
    
    3,455
    
    
    
    2,200
    
    
    
    739Depreciation, depletion and amortization
    
    
    40
    
    
    
    24
    
    
    
    9
    
    
    
    8
    
    
    
    12
    
    
    
    1
    
    
    
    48
    
    
    
    36
    
    
    
    10$
    21
    
    
    $
    73
    
    
    $
    3
    
    
    $
    (16
    )
    
    $
    11
    
    
    $
    14
    
    
    $
    5
    
    
    $
    84
    
    
    $
    17
  (1)
    
    Excludes financial results related to discontinued operations as described in Note 5 to the Consolidated Financial Statements. Revenues from continuing Midstream & Marketing operations increased by
$1,293 million in 2003 from 2002 due primarily to higher commodity prices
and the inclusion of a full year of post Merger results. Despite higher
revenues in 2003, financial results were negatively impacted by short-term
market factors. Narrower summer/ winter price spreads resulted in lower
revenues from third-party gas storage contracts and reduced margins from
optimization activities. In addition, natural gas processing margins
decreased due to relatively higher feedstock prices and reduced seasonal
demand for propane. The change in operations between 2002 and 2001 was
mostly the result of the addition of AEC midstream assets which included
gas storage facilities and natural gas processing to the existing midstream
segment. Midstream operating expenses increased in 2003 due to the inclusion of a
full year of post Merger results and the effect of the change in the
U.S./Canadian dollar on the Canadian operations as well as he higher cost
of natural gas and increased throughput volumes for NGL processing. The
higher costs reflected in 2002 over 2001 was due to the inclusion of nine
months of post Merger activity. Marketing Financial Results
on a Product Basis(1) Gas
    
    Crude Oil and NGLs
    
    Total($ millions)
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues
    
    $
    1,442
    
    
    $
    931
    
    
    $
    385
    
    
    $
    1,361
    
    
    $
    1,223
    
    
    $
    392
    
    
    $
    2,803
    
    
    $
    2,154
    
    
    $
    777ExpensesTransportation and selling
    
    
    10
    
    
    
    37
    
    
    
    
    
    
    
    45
    
    
    
    50
    
    
    
    11
    
    
    
    55
    
    
    
    87
    
    
    
    11Operating
    
    
    49
    
    
    
    5
    
    
    
    7
    
    
    
    14
    
    
    
    8
    
    
    
    5
    
    
    
    63
    
    
    
    13
    
    
    
    12Purchased product
    
    
    1,396
    
    
    
    862
    
    
    
    366
    
    
    
    1,297
    
    
    
    1,169
    
    
    
    373
    
    
    
    2,693
    
    
    
    2,031
    
    
    
    739Depreciation, depletion and amortization
    
    
    3
    
    
    
    6
    
    
    
    1
    
    
    
    5
    
    
    
    6
    
    
    
    
    
    
    
    8
    
    
    
    12
    
    
    
    1$
    (16
    )
    
    $
    21
    
    
    $
    11
    
    
    $
    
    
    
    $
    (10
    )
    
    $
    3
    
    
    $
    (16
    )
    
    $
    11
    
    
    $
    14
  (1)
    
    Excludes financial results related to discontinued operations as described
in Note 5 to the Consolidated Financial Statements. EnCanas Marketing operations include marketing activities to
optimize the value from the Companys proprietary production,
the purchase of third party product primarily for the
optimization of midstream assets and optimization of
transportation commitments not fully utilized for the Companys
own production. The increase in 2003 revenues reflects higher
commodity prices experienced in the energy industry for the
year. The increased revenue is comparatively M13




---



##### 



offset by the change in product purchased. The change in Marketings
operating expense in 2003 is primarily due to the $20 million settlement
related to the discontinued Merchant Energy operations, discussed in the
Contractual Obligations and Contingencies section of this MD&A, and the
inclusion of a full year of post Merger results. CorporateCorporate Items 2003 vs
    
    
    
    
    
    2002 vs($ millions)
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001Administration
    
    $
    173
    
    
    
    45
    %
    
    $
    119
    
    
    
    120
    %
    
    $
    54Interest, net
    
    
    287
    
    
    
    1
    %
    
    
    290
    
    
    
    753
    %
    
    
    34Foreign exchange (gain) loss
    
    
    (601
    )
    
    
    4193
    %
    
    
    (14
    )
    
    
    217
    %
    
    
    12Income tax expense
    
    
    445
    
    
    
    22
    %
    
    
    366
    
    
    
    13
    %
    
    
    419
 The increase in administrative expense in 2003 reflected the inclusion of
the full year of post Merger operations, the effect of the change in the
U.S./Canadian dollar exchange rate, higher governance costs and increased
salary and consultant expenses. On a per unit basis, excluding discontinued
operations volumes, administrative costs were $0.73 per barrel of oil
equivalent for 2003 compared with $0.63 per barrel of oil equivalent for
2002 and $0.54 per barrel of oil equivalent for 2001. Net interest expense remained relatively unchanged in 2003 compared to
2002. The higher net interest expense in 2002 over 2001 resulted primarily
from the additional expense associated with the comparatively higher
average debt level outstanding as a result of the Merger and redemption of
capital securities. The majority of the foreign exchange gain of $601 million resulted from the
change in the U.S./Canadian dollar period end exchange rate applied to U.S.
dollar denominated debt issued in Canada. Under Canadian GAAP, the Company
is required to translate long-term debt borrowed 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. The effective tax rate for 2003 was 17 percent compared to 33 percent for
2002 and 33 percent for 2001. The decrease in the effective tax rate
included the impact of a $359 million reduction in future income taxes
resulting from the reductions in the Canadian federal and Alberta corporate
income tax rates which were enacted in 2003 and related changes to the
Canadian federal resource allowance deduction. The Canadian federal tax
rate, which was reduced in other industries in 2000, is to be reduced by
seven percentage points over the period 2003-2007 from 28 percent to 21
percent. In addition, the Canadian federal resource allowance deduction is
to be phased out and replaced with a deduction for crown royalties paid
over the same period. The Alberta tax rate was reduced by one half of one
percentage point from 13 percent to 12.5 percent. The decrease also
reflects the tax treatment of realized and unrealized Canadian capital
gains of $581 million derived from a weakening of the U.S. dollar in
relation to the Canadian dollar and the utilization of previously
unrecognized capital losses. Income tax expense also reflects the
translation of Canadian taxes denominated in Canadian dollars utilizing the
increased average U.S./Canadian dollar exchange rate. Current income tax expense was a recovery of $56 million for 2003, a
recovery of $38 million for 2002, and an expense of $324 million for 2001.
Current income tax expense was abnormally low in 2003 and 2002 in large
part as a result of the merger with AEC, the subsequent business
reorganization of the Companys business units at the end of 2002 and early
2003 and the amalgamation with AEC on January 1, 2003. The recovery relates
principally to a shift of approximately $90 million of previously
anticipated current income tax expense in 2003 to 2004.
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. LIQUIDITY AND CAPITAL RESOURCES Company expectations are that existing credit facilities and present and
forecast capital resources will be sufficient to support its capital
investment programs and future growth prospects in addition to enabling the
Company to meet all other current and expected financial requirements.
Fluctuations in commodity prices, product demand, foreign exchange rates,
interest rates and various other risks may impact capital resources but
have been partially mitigated through the risk management program detailed
in Note 17 of the Consolidated Financial Statements and discussed in the
Risk Management section of this MD&A. EnCanas cash flow from continuing operations was $4,420 million in 2003 up
$2,153 million, or 95 percent, compared with $2,267 million in 2002 and
$1,463 million in 2001. The increase in cash flow from continuing
operations was primarily the result of higher revenues from increases in
commodity prices, inclusion of a full year of post Merger results and
growth in sales volumes, partially offset by higher operating expenses. M14




---



##### 



EnCanas net debt, adjusted for working capital, was $5,931 million as at
December 31, 2003 compared with $3,933 million at December 31, 2002 and
$1,446 million at December 31, 2001. Working capital was $157 million at
December 31, 2003, compared to $1,118 million at December 31, 2002. The
2002 working capital balance included $1,055 million related to the net
assets and liabilities of Discontinued Operations. Cash flow together with
proceeds from the dispositions of the Syncrude interest, Cold Lake and
Express Pipeline Systems interests and other asset dispositions were used
for the purchase of shares under the Companys Normal Course Issuer Bid,
capital expenditures and acquisitions. The cash shortfall as a result of
these activities and working capital changes increased net debt in 2003 by
$1,998 million. On October 2, 2003, the Company issued $500 million notes due in 10 years
at 4.75 percent. The proceeds from this issue were used primarily to repay
existing bank and commercial paper indebtedness. Net debt to capitalization was 34 percent, up from 31 percent at December
31, 2002. Net debt to Earnings Before Interest, Taxes, Depreciation,
Depletion and Amortization (EBITDA) was 1.3 times the trailing 12-month
cash flow at the end of the year. EBITDA is a measure that has no
standardized meaning prescribed by Canadian GAAP and is considered a
non-GAAP measure. Therefore, the measure may not be comparable to similar
measures presented by other issuers. This measure is described and
presented in this MD&A, in order to provide shareholders and potential
investors with additional information regarding the Companys liquidity and
ability to generate funds to finance its operations. Management calculates
net debt to EBITDA for credit analysts who use the measure to gauge a
Companys ability to generate sufficient funds to cover its net debt. As at December 31, 2003, the Company had available unused committed bank
credit facilities in the amount of $1,575 million. On December 31, 2003, the Company had $418 million of preferred securities
recorded as long-term debt on its Consolidated Balance Sheet. Due to the
adoption of the new Canadian accounting standard for liabilities and equity
as discussed in the Accounting Policy Changes section of this MD&A these
preferred securities were reclassified from equity to liabilities
retroactively and, accordingly, all prior periods have been restated to
reflect this change. In October 2003, EnCana received approval from the Toronto Stock Exchange
to purchase, for cancellation, common shares under a Normal Course Issuer
Bid. Under the bid, EnCana is entitled to purchase for cancellation up to
23.2 million of its common shares over a 12-month period ending October 21,
2004. In 2003, combined purchases under the current bid and a previous bid
were 23.8 million shares at an average price of C$49.65 per share. These
purchases more than offset the approximately 5.5 million shares issued in
2003 as a result of the exercise of share purchase options. In 2004, EnCana
has purchased for cancellation 2.5 million of its shares at an average
price of C$54.52 per share under its current Normal Course Issuer Bid,
approximately equal to share option exercises. In February 2004, the Company announced its intention to redeem, on March
23, 2004, all of its Coupon Reset Subordinated Term Securities, Series A
(Term Securities) which have an aggregate principal amount of
approximately C$126 million. The redemption price of the Term Securities is
the principal amount plus accrued and unpaid interest to the redemption
date. As at December 31, 2003, the Term Securities have been included as
part of the Current Portion of Long-Term Debt in the Consolidated Financial
Statements. Goodwill At December 31, 2003, the Company had $1,911 million in goodwill (2002 
$1,563 million) recorded on its Consolidated Balance Sheet as a result of
the merger with AEC. As disclosed in Note 4 to the Consolidated Financial
Statements, there were no transactions creating additional goodwill during
2003. The increase in goodwill results from the change in the year end

rates to convert Canadian dollars to U.S. dollars. CAPITAL EXPENDITURES Capital Investment 2003 vs
    
    
    
    
    
    2002 vs($ millions)
    
    2003(1)
    
    2002
    
    2002
    
    2001
    
    2001UpstreamCanada
    
    $
    3,198
    
    
    
    130
    %
    
    $
    1,388
    
    
    
    51
    %
    
    $
    919United States
    
    
    968
    
    
    
    18
    %
    
    
    1,176
    
    
    
    746
    %
    
    
    139Ecuador
    
    
    265
    
    
    
    58
    %
    
    
    168
    
    
    
    
    
    
    
    United Kingdom
    
    
    223
    
    
    
    172
    %
    
    
    82
    
    
    
    78
    %
    
    
    46Other Countries
    
    
    78
    
    
    
    33
    %
    
    
    117
    
    
    
    179
    %
    
    
    42Total Upstream
    
    $
    4,732
    
    
    
    61
    %
    
    $
    2,931
    
    
    
    156
    %
    
    $
    1,146Midstream &
Marketing
    
    
    276
    
    
    
    487
    %
    
    
    47
    
    
    
    51
    %
    
    
    96Corporate
    
    
    107
    
    
    
    149
    %
    
    
    43
    
    
    
    153
    %
    
    
    17Total
    
    $
    5,115
    
    
    
    69
    %
    
    $
    3,021
    
    
    
    140
    %
    
    $
    1,259
  (1)
    
    Includes acquisitions of $613 million but excludes
dispositions on continuing operations of approximately $315 million. M15




---



##### 



The Companys consolidated capital expenditures increased 69 percent, or
$2,094 million, compared to 2002 and 140 percent, or $1,762 million, when
comparing 2002 over 2001. The majority of expenditures in both 2003 and
2002 were directed towards natural gas exploration and development in North
America. The Companys capital investment was funded by cash flow in excess
of amounts paid for purchases under the Normal Course Issuer Bid, proceeds
received on the dispositions of the Syncrude interest and interests in the
Cold Lake and Express Pipeline Systems as well as debt. Total cash proceeds
received for dispositions, including the Syncrude interest and the Cold
Lake and Express Pipeline Systems, amounted to $1,900 million compared to
$423 million in 2002 and $134 million in 2001. Dispositions on continuing
operations include the amount received for the 22.5 percent interest in the
Llano oil discovery in the Gulf of Mexico which was exchanged for an
additional 14 percent ownership in both the Scott and Telford fields of the
U.K. central North Sea. Upstream Capital Expenditures Upstream capital expenditures in 2003 were higher by 61 percent, or $1,801
million, over 2002 and 156 percent, or $1,785 million, higher in 2002 over
2001. Increases in capital spending reflect the full twelve months of post
Merger results in 2003 and nine months of post Merger results in 2002,
increased operating activity, as well as the impact of the increase in the
U.S./Canadian dollar exchange rate in 2003. The majority of 2003
expenditures related to North American properties, with spending in Canada
directed primarily towards exploration and development of southern Alberta
shallow gas projects as well as natural gas properties at Greater Sierra
and Cutbank Ridge in northeast British Columbia. The higher Canadian
capital expenditures over 2002 was the result of increased property
acquisitions, inclusion of a full year of post Merger expenditures, the
Cutbank Ridge land purchase and associated drilling, expansion of the
Greater Sierra drilling program, acceleration of the 2004 capital program
into 2003, and the effect of the change in the U.S./Canadian dollar
exchange rate on Canadian denominated expenditures. Capital expenditures in
the United States focused primarily on natural gas exploration and
development at Jonah and Mamm Creek. Capital spending in the United States
included $138 million in property acquisitions in 2003 compared to $656
million in 2002. Excluding property acquisitions, capital spending in the
United States increased 60 percent to $830 million from $520 million as a
result of increased drilling activity. Capital spending on international
interests, excluding acquisitions, focused on production expansion in
Ecuador and the U.K central North Sea as well as evaluating various other
prospects in Africa, Australia, Brazil, Greenland and the Middle East. Also
included is the purchase of an additional 14 percent ownership in both the
Scott and Telford fields in the U.K. central North Sea in exchange for the
22.5 percent interest in the Llano oil discovery in the Gulf of Mexico and
other minor property acquisitions. In addition to the Upstream capital
expenditures in the table above are corporate acquisitions where the
Company acquired additional interests in Ecuador for $116 million and
acquired interests in developed and undeveloped reserves, landholdings and
natural gas production in North Texas for $91 million. U.K.  Buzzard DevelopmentIn 2003, the Company received approval of the
plan to develop the Buzzard oilfield located 53 kilometres off the coast of
Scotland in the United Kingdom including approval of the environmental
impact assessments. The Companys U.K. subsidiary is the operator of the
project and holds a 43.2 percent interest. The field is expected to start
production in late 2006 and reach a plateau by mid 2007 of 75,000 barrels
per day of crude oil net to EnCana. As of December 31, 2003, the Company
had invested approximately $90 million in the project and estimates future
development costs to be an additional $770 million. The next phase of
development in 2004 includes fabrication of the offshore platform and the
start of pipeline installation. Canadian East CoastIn 2003, the Company, along with its partners,
completed the drilling of five exploratory wells in the Canadian East Coast
region. EnCana was the operator of three of these wells. Two of these
exploration wells drilled near the Deep Panuke discovery (100 percent owned
Margaree and 24.5 percent owned MarCoh) have increased the Companys
confidence in the commercial potential of this discovery. During 2003, the
Company withdrew the original development application for Deep Panuke filed
in March 2002 with the National Energy Board and the Canada-Nova Scotia
Offshore Petroleum Board. Further examination of the potential economic
viability of the Deep Panuke project will be undertaken prior to the
preparation of a revised development plan. As of December 31, 2003, the
Company had invested approximately $340 (C$500) million on its Canadian
East Coast assets including Deep Panuke. Until assessments of the economics
are complete, the timing of any potential start of production and amount of
additional costs which may be incurred are not determinable. Western Canada  Cutbank RidgeDuring 2003, the Company 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. The Company purchased either 100 percent or a
majority interest in 39 parcels of land totalling roughly 350,000 net acres
for approximately $270 (C$369) million. The Company had previously acquired
about 150,000 net acres through purchases and land swaps with other
companies and Crown land sales. In 2003, the Company drilled 19 wells which
produced 14 million cubic feet per day in December. As of December 31, M16




---



##### 



2003, the Company had invested approximately $360 (C$500) million on
Cutbank Ridge and estimates 2004 spending to be approximately $125 (C$160)
million. In 2004, the Company plans to drill 40 net natural gas wells at
Cutbank Ridge. Western Canadian Basin  Coalbed MethaneIn 2003, the Company expanded
coalbed methane development on its 700,000 acres of 100 percent owned fee
title lands in southern Alberta. During 2003, the Company drilled
approximately 270 wells, increasing current production from the commercial
demonstration project to 10 million cubic feet per day. As of December 31,
2003, the Company had invested approximately $60 (C$80) million on coalbed
methane development in southern Alberta and estimates 2004 spending to be
approximately $100 (C$130) million. Over the next 5 years, the Company
expects to increase natural gas production from coal seams to more than 200
million cubic feet per day. Gulf of MexicoThe Companys operating partner completed drilling four
appraisal wells in 2003 at the Tahiti oilfield which is located 304
kilometres southwest of New Orleans. As of December 31, 2003, the Company
had invested approximately $301 million in the Gulf of Mexico including
Tahiti. The Company holds a 25 percent interest in the Tahiti project. The
next phase of development in 2004 includes the front end engineering and
design of the project. Until completion of this phase and assessments of
the economics are complete, the timing of any potential start of production
and amount of additional costs which may be incurred are difficult to
determine. RESERVES Proved Reserves by Country Constant Prices After Royalties Natural Gas
    
    Crude Oil and NGLs(2)
    
    Total (1)2003 vs
    
    
    
    
    
    2002 vsAs at December 31
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2002
    
    2001
    
    2001(billions of cubic feet)
    
    (millions of barrels)
    
    (millions of barrels of oil equivalent)Canada
    
    
    5,256
    
    
    
    5,073
    
    
    
    3,504
    
    
    
    629
    
    
    
    542
    
    
    
    287
    
    
    
    1,505
    
    
    
    8
    %
    
    
    1,388
    
    
    
    59
    %
    
    
    871United States
    
    
    3,129
    
    
    
    2,573
    
    
    
    236
    
    
    
    42
    
    
    
    41
    
    
    
    20
    
    
    
    564
    
    
    
    20
    %
    
    
    470
    
    
    
    696
    %
    
    
    59Ecuador
    
    
    
    
    
    
    
    
    
    
    
    
    
    

    162
    
    
    
    156
    
    
    
    
    
    
    
    162
    
    
    
    4
    %
    
    
    156
    
    
    
    
    
    
    
    United Kingdom
    
    
    26
    
    
    
    20
    
    
    
    7
    
    
    
    124
    
    
    
    97
    
    
    
    21
    
    
    
    128
    
    
    
    28
    %
    
    
    100
    
    
    
    356
    %
    
    
    22Total
    
    
    8,411
    
    
    
    7,666
    
    
    
    3,747
    
    
    
    957
    
    
    
    836
    
    
    
    328
    
    
    
    2,359
    
    
    
    12
    %
    
    
    2,114
    
    
    
    122
    %
    
    
    952
  (1)
    
    Natural gas converted to barrels of oil equivalent at 6 thousand cubic feet
= 1 barrel of oil equivalent.  (2)
    
    Includes condensate. EnCanas policy is to retain independent qualified reserves
evaluators to prepare reports on 100 percent of its oil and gas
reserves. The reserves for both 2003 and 2002 were independently
evaluated. The reserves for 2001 were internally evaluated. The
Company has a Reserves Committee comprised entirely of
independent directors which oversees the selection,
qualifications and reporting procedures of the independent
engineering consultants. Proved Reserves Reconciliation by Country Constant Prices After Royalties Natural Gas
    
    Crude Oil and Natural Gas Liquids (2)As atDecember 31, 2003
    
    Canada
    
    USA
    
    UK
    
    Other
    
    Total
    
    Canada
    
    USA
    
    Ecuador
    
    UK
    
    Other
    
    Total
    
    Total(billions of cubic feet)
    
    (millions of barrels)
    
    (MMBOE) (1)Start of year
    
    
    5,073
    
    
    
    2,573
    
    
    
    20
    
    
    
    
    
    
    
    7,666
    
    
    
    542
    
    
    
    41
    
    
    
    156
    
    
    
    97
    
    
    
    
    
    
    
    836
    
    
    
    2,114Revisions and
improved recovery
    
    
    73
    
    
    
    1
    
    
    
    3

    
    
    
    
    
    
    
    77
    
    
    
    32
    
    
    
    1
    
    
    
    
    
    
    
    24
    
    
    
    
    
    
    
    57
    
    
    
    70Extensions and
discoveries
    
    
    867
    
    
    
    706
    
    
    
    
    
    
    
    90
    
    
    
    1,663
    
    
    
    111
    
    
    
    7
    
    
    
    12
    
    
    
    
    
    
    
    1
    
    
    
    131
    
    
    
    408Acquisitions
    
    
    9
    
    
    
    152
    
    
    
    8
    
    
    
    
    
    
    
    169
    
    
    
    1
    
    
    
    1
    
    
    
    17
    
    
    
    7
    
    
    
    
    
    
    
    26
    
    
    
    55Divestitures
    
    
    (60
    )
    
    
    (88
    )
    
    
    
    
    
    
    (90
    )
    
    
    (238
    )
    
    
    
    
    
    
    (5
    )
    
    
    (5
    )
    
    
    
    
    
    
    (1
    )
    
    
    (11
    )
    
    
    (51
    )Production
    
    
    (706
    )
    
    
    (215
    )
    
    
    (5
    )
    
    
    
    
    
    
    (926
    )
    
    
    (57
    )
    
    
    (3
    )
    
    
    (18
    )
    
    
    (4
    )
    
    
    
    
    
    
    (82
    )
    
    
    (237
    )End of year
    
    
    5,256
    
    
    
    3,129
    
    
    
    26
    
    
    
    
    
    
    
    8,411
    
    
    
    629
    
    
    
    42
    
    
    
    162
    
    
    
    124
    
    
    
    
    
    
    
    957
    
    
    
    2,359
  (1)
    
    MMBOE represents millions of barrels of oil equivalent. Natural gas is converted to barrels of oil equivalent at 6 thousand cubic feet = 1 barrel of oil equivalent.  (2)
    
    Includes condensate. M17




---



##### 



During 2003, the Company added approximately 482 million barrels of oil
equivalent, or 203 percent of its production, to its proved reserves
through drilling successes, acquisitions of selected properties and
revisions net of property dispositions. EnCanas proved reserves as at
December 31, 2003, on a constant price basis, after royalties, totalled
2,359 million barrels of oil equivalent representing a reserve life index
of approximately 10 years based on 2003 production volumes. Midstream & Marketing Capital Expenditures Expenditures in 2003 related primarily to ongoing improvements to midstream
facilities, the construction of the Countess gas storage facility and the
expansion of the Wild Goose storage facility. Approximately $91 million was
spent in 2003 on the Countess facility and $65 million on expansion of the
Wild Goose facility. Capital spending also included approximately $53
million related to equipment operating lease buyouts. The Company has completed gas injections into the first 10 billion cubic
feet of new storage capacity at Countess. The second and third phases of
the Countess storage facility are expected to take total capacity to about
40 billion cubic feet by the second quarter of 2005. As of November 2003,
the expansion of the Wild Goose storage facility had increased withdrawal
capability from 200 million cubic feet per day to 320 million cubic feet
per day. By April 2004, withdrawal capacity is expected to be further
increased to 480 million cubic feet per day while injection capacity is
expected to rise from 80 million to 450 million cubic feet per day and
total working gas inventory capacity will increase from 14 billion cubic
feet to 24 billion cubic feet. In early July, a subsidiary of the Company increased its equity interest in
the OCP Pipeline in Ecuador from 31.4 percent to 36.3 percent. The OCP
Pipeline completed performance testing in October 2003. As at December 31,
2003, OCP was shipping approximately 220,000 barrels per day and is
expected to increase shipping volumes as field productivity increases in
coming years. The shippers have ship or pay commitments of 350,000 barrels
per day. The Company currently is transporting all of its Ecuadorian
production through the OCP Pipeline. Prior to completion, the OCP asset was
considered part of the Companys Midstream & Marketing division. Since the
completion, the Companys equity interest in the OCP Pipeline has been
transferred to the Upstream business segment and is included as part of the
Ecuadorian region results. Corporate Capital Expenditures Corporate capital expenditures related primarily to spending on business
information systems, the buyout of operating leases, leasehold improvements
and furniture and office equipment. Expenditures in 2002 and 2001 related
primarily to spending on business information systems. 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. As at December 31, 2003, there were 460.6 million
outstanding common shares compared to 478.9 million and 254.9 million at
the end of 2002 and 2001 respectively. 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. 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). Beginning in 2004, it is the
Companys intention that most stock options granted will have an associated
Tandem Share Appreciation Right (TSAR) and employees may elect to
exercise either the stock option or the associated TSAR. PSUs and TSARs
will result in cash payments by the Company and Common Shares will not be
issued. These cash payments will be accounted for as expenses of the
Company and equity dilution will not occur. As previously detailed in the liquidity and capital section of this MD&A,
the Company obtained regulatory approval under Canadian securities laws to
purchase Common Shares under two consecutive Normal Course Issuer Bids
which commenced in October 2002 and may continue until October 21, 2004.
Under the terms of the bids, the Company repurchased for cancellation 23.8
million Common Shares during 2003, and as of December 31, 2003, was
entitled to purchase for cancellation an additional 19.6 million Common
Shares. M18




---



##### 



OFF BALANCE SHEET ARRANGEMENTS LEASES During 2003, the Company exercised buyout options and closed out a number
of operating leases that were in place at the prior year end. These
operating leases were on a variety of moveable field equipment, natural gas
storage equipment and aircraft, which required periodic lease payments and
were recorded as operating or administrative costs. The leases of the
equipment and aircraft were financed by variable interest entities that
were sponsored by various financial institutions. During 2003, the Company
paid $262 million to close out these lease obligations by purchasing the
related equipment which was included in the 2003 total capital spending
figures discussed earlier in the MD&A. As a normal course of business, the Company leases office space for
personnel who support field operations and corporate purposes. VARIABLE
INTEREST ENTITIES In December 2003, the Financial Accounting Standards Board (FASB) in the
United States issued Interpretation Number 46R Consolidation of Variable
Interest Entities, an interpretation of Accounting Research Bulletin No.
51. The standard mandates that variable interest entities be consolidated
by their primary beneficiary. The standard is effective the first reporting
period ending after March 15, 2004 for all entities with the exception of
special purpose entities as defined in prior accounting guidance. The
standard is effective for the first period ending after December 15, 2003
for previously defined special purpose entities. In Canada, the Accounting
Standards Board (AcSB) has suspended the effective dates for Accounting
Guideline AcG15, Consolidation of Variable Interest Entities in order to
amend the guideline to harmonize with the corresponding U.S. guidance. The
AcSB plans to issue an exposure draft in the immediate future with an
effective period beginning on or after November 1, 2004.

At December 31, 2003, the Company did not have any variable interests in
variable interest entities where the Company was the primary beneficiary. 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, 2003: Contractual Obligations(1) Expected Payment Date2005 to
    
    2007 to($ millions)
    
    2004
    
    2006
    
    2008
    
    2009+
    
    TotalLong-Term Debt
    
    $
    287
    
    
    $
    221
    
    
    $
    713
    
    
    $
    3,257
    
    
    $
    4,478Asset Retirement Obligations
    
    
    13
    
    
    
    10
    
    
    
    
    
    
    
    3,200
    
    
    
    3,223Operating Leases (2)
    
    
    44
    
    
    
    85
    
    
    
    74
    
    
    
    211
    
    
    
    414Pipeline Transportation
    
    
    449
    
    
    
    717
    
    
    
    627
    
    
    
    2,116
    
    
    
    3,909Capital Commitments
    
    
    259
    
    
    
    43
    
    
    
    
    
    
    
    38
    
    
    
    340Purchase of Goods and Services
    
    
    297
    
    
    
    225
    
    
    
    14
    
    
    
    
    
    
    
    536Product Purchases
    
    
    142
    
    
    
    79
    
    
    
    49
    
    
    
    157
    
    
    
    427Total Contractual Obligations
    
    $
    1,491
    
    
    $
    1,380
    
    
    $
    1,477
    
    
    $
    8,979
    
    
    $
    13,327
  (1)
    
    In addition, the Company has made commitments related to its risk
management program. See Note 17 in the Consolidated Financial Statements.
The Company also has an obligation to fund its Pension Plan as disclosed in
Note 16 of the Consolidated Financial Statements.  (2)
    
    Related to office space and computer lease obligations. In addition to the long-term debt payments outlined above, at December 31,
2003, the Company had $1,814 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. M19




---



##### 



As at December 31, 2003, EnCana had entered into long-term, fixed price,
physical contracts with a current delivery of approximately 69 million
cubic feet per day with varying terms and volumes through 2017. The total
volume to be delivered within the terms of these contracts is 200 billion
cubic feet at a weighted average price of $3.48 per thousand cubic feet. At
December 31, 2003, these transactions had an unrealized loss of $108
million. 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 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. Several 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 the New York lawsuits were consolidated in New York District
Court by the plaintiffs application. 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. The Gallo complaint claims damages in excess of $30 million,
before potential trebling under California laws. 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 CRITICAL ACCOUNTING POLICIES 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 Canadian Institute of Chartered Accountants guideline
on full cost accounting in the oil and gas industry to account for oil and
gas properties. Under this method, all costs 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 depreciation, depletion and amortization. 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. M20




---



##### 



Goodwill Goodwill, which represents the excess of purchase price over fair value of
net assets acquired and was the result of the Merger with AEC, is assessed
by the Company for impairment at least annually. Goodwill was allocated to
the business segments at the time of the Merger 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. Oil and Gas Reserves EnCanas proved oil and gas reserves are 100 percent evaluated and reported
on by independent petroleum engineering consultants. 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. The Company expects that its
estimates of reserves will change to reflect updated information. 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
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 reserves; andii)
    
    the costs of unproved properties that have been subject to a separate
impairment test. Foreign Currency Translation The accounts of self-sustaining operations are translated using the current
rate method, whereby assets and liabilities are translated at year-end
exchange rates, while revenues and expenses are translated using average
annual rates. 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. 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. Realized gains and losses from these
derivative financial instruments are recognized in oil and gas revenues as
the related production occurs. 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. M21




---



##### 



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. Hedging Relationships The Canadian Institute of Chartered Accountants (CICA) modified Accounting
Guideline 13 (AcG 13) Hedging Relationships, effective January 1, 2004,
to clarify circumstances in which hedge accounting is appropriate. In
addition, the CICA simultaneously amended EIC 128, Accounting for Trading,
Speculative or Non Trading Derivative Financial Instruments to require that
all derivative instruments that do not qualify as a hedge under AcG 13, or
are not designated as a hedge, be recorded in the balance sheet as either an
asset or liability with changes in fair value recognized in earnings. In
2004, the Company has elected not to designate any of its current price risk
management activities as accounting hedges under AcG13 and accordingly, will
account for all derivatives using the mark-to-market accounting method. The
impact on the Companys financial statements at January 1, 2004 is an
increase in assets of $145 million, an increase in liabilities of $380
million and a deferred loss of $235 million which will be recognized as the
contracts expire. Pensions 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 10% 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. 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. CHANGES IN ACCOUNTING PRINCIPLES AND PRACTICES As at December 31, 2003, the Company has adopted the following changes in
accounting principles and practices: Change in the Companys Reporting Currency The Company has adopted the U.S. dollar as its reporting currency as a
result of its revenues being closely tied to the value of the U.S. dollar
and to facilitate direct comparisons to most other North American upstream
exploration and development companies. The change results in all
self-sustaining financial results being translated from Canadian dollars to
U.S. dollars using the current rate method, as described earlier under
Accounting Guidelines in this MD&A, with exchange gains and losses reported
as a separate component of shareholders equity. Monetary assets and
liabilities denominated in currencies, other than the applicable functional
currency (as described in the Overview section of this MD&A), are
translated at the year-end exchange rate with gains and losses recorded in
the Consolidated Statement of Earnings. Stock Based Compensation The Company early adopted the fair value recognition for stock based
compensation as required by the CICA accounting standard Handbook section
3870, Stock-Based Compensation and Other Stock-Based Payments. This
standard requires an option pricing model be used to determine the fair
value of each option granted and the amount recognized over the vesting
period of the option. Previously, the Company used the intrinsic value
method to account for such compensation which resulted in no expense being
recognized in the Companys financial results. As a result of early
adopting, the Company can implement the new standard prospectively. The
impact on the Companys 2003 net earnings has been disclosed in Note 2 of
the Consolidated Financial Statements. M22




---



##### 



Asset Retirement Obligations At December 31, 2003, the Company retroactively early adopted the Canadian
accounting standard for accounting for asset retirement obligations as
outlined in the CICA Handbook section 3110. The standard requires that the
fair value of an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made.
The present value of the estimated asset retirement cost is capitalized as
part of the carrying amount of the long-lived asset. The depreciation of
the capitalized asset retirement cost will be determined on a basis
consistent with depreciation, depletion and amortization. With the passage
of time, accretion will increase the carrying amount of the asset
retirement obligation. Previously the Company used the unit of production
method to match estimated future retirement costs with the revenues
generated from the producing assets. The impact of this change has been
disclosed in Note 2 of the Consolidated Financial Statements. Preferred Securities The Company retroactively adopted the new Canadian accounting standard for
liabilities and equity as outlined in the CICA Handbook section 3860,
whereby the preferred securities issued by the Company are now recorded as
a liability. All prior periods have been restated. Full Cost Accounting The Company early adopted Accounting Guideline AcG-16, Oil and Gas
Accounting-Full Cost. The new guideline has modified how the ceiling test
is performed, which requires cost centres be tested for recoverability
using undiscounted future cash flows which are determined by using forward
indexed prices applied to proved reserves. When the carrying amount of a
cost centre is not recoverable, the cost centre would be written down to
its fair value. Fair value is estimated using accepted present value
techniques which incorporate risks and other uncertainties as well as the
future value of reserves when determining expected cash flows. Additional
disclosures are also required as provided in Note 11 of the Consolidated
Financial Statements. There is no impact on the Companys reported
financial results as a result of applying the new Accounting Guideline
other than additional required disclosure. RISK MANAGEMENT EnCanas results are impacted by external market risks associated with
fluctuations in commodity prices, foreign exchange rates and interest rates
in addition to credit, operational and safety and environmental risks. The
Company partially mitigates its exposure to market 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. The following table summarizes the unrecognized gains/(losses) on the Companys
risk management activities discussed below. Contract Maturity2006 andAs at December 31, 2003 ($ millions)
    
    2004
    
    2005
    
    beyond
    
    TotalNatural Gas
    
    $
    (29
    )
    
    $
    38
    
    
    $
    48
    
    
    $
    57Crude Oil
    
    
    (275
    )
    
    
    (4
    )
    
    
    
    
    
    
    (279
    )Gas Storage
    
    
    (25
    )
    
    
    
    
    
    
    
    
    
    
    (25
    )Power
    
    
    4
    
    
    
    
    
    
    
    
    
    
    
    4Foreign Currency
    
    
    7
    
    
    
    
    
    
    
    
    
    
    
    7Interest Rates
    
    
    22
    
    
    
    14
    
    
    
    8
    
    
    
    44Total
    
    $
    (296
    )
    
    $
    48
    
    
    $
    56
    
    
    $
    (192
    )
 COMMODITY PRICES As a means of mitigating exposure to commodity price volatility, the
Company has entered into various financial instrument agreements and
physical contracts as disclosed in Note 17 of the Consolidated Financial
Statements. Derivative financial instruments are used by the Company to help manage its
exposure to market risks related 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 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. M23




---



##### 



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. Gains or
losses from these derivative financial instruments are recognized in oil
and gas revenues in the period in which the related production occurs.
Effective January 1, 2004, the Company adopted AcG 13 of the CICA and will
use the mark-to-market accounting method as described earlier in this MD&A
under Hedging Relationships. NATURAL GAS Produced Gas The Company entered into swaps which fix the AECO and NYMEX prices and
collars 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. AECO production area prices may be
negatively impacted as large amounts of contracted capacity on pipelines
moving gas to downstream markets come up for renewal over the next several
years. As of December 31, 2003, the total unrecognized gain related to all
significant natural gas risk management contracts was $40 million. Purchased Gas 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. These contracts had an unrecognized gain of $17
million at December 31, 2003. CRUDE OIL Produced Crude Oil The Company has partially mitigated its exposure to the WTI NYMEX price for
a portion of its oil production with fixed price swaps, costless collars
and 3 way put spreads. As of December 31, 2003, the total unrecognized loss
related to all significant crude oil risk management contracts was $279
million. Purchased Crude Oil As part of the crude oil marketing activities, the Company partially
mitigated its exposure to the risk around crude oil inventory and third
party margins through the use of futures and options. As at December 31,
2003, there was no gain or loss related to these contracts. GAS STORAGE OPTIMIZATION As part of its gas storage optimization program, the Company has entered
into financial instruments and physical contracts at various locations and
terms over the next 9 months to manage the price volatility of the
corresponding physical transactions and inventories. The financial
instruments used include futures, fixed for floating swaps and basis swaps.
As of December 31, 2003, the unrecognized loss related to these contracts
was $25 million. POWER PURCHASE ARRANGEMENTS The Company has an electricity contract that expires in 2005. This contract
was entered into as part of a cost management strategy. At December 31,
2003, this contract had an unrecognized gain of $4 million. FOREIGN CURRENCY As a means of mitigating the exposure to fluctuations in the U.S. to
Canadian exchange rate, the Company has entered into foreign exchange
contracts in the amount of $88 million at an average exchange rate of
US$0.715 for the period to June 2004. The unrecognized loss with respect to
these contracts was $7 million at December 31, 2003. The Company has also
entered 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. INTEREST RATES The Company has entered into various interest rate and cross currency
interest rate swap transactions as a means of mitigating its exposure to
the interest rates on debt instruments. The unrealized gain with respect to
these transactions was $44 million at December 31, 2003. 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 of Directors 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. M24




---



##### 



OPERATIONAL, SAFETY AND ENVIRONMENTAL RISK Operational risks are partially mitigated through a comprehensive insurance
program designed to protect the Company from significant losses arising
from the risk exposures. Safety and environment 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. KYOTO PROTOCOL The Kyoto Accord (Accord) becomes effective once ratification from at
least 55 Parties to the Convention representing 55 percent of Annex 1 Party
emissions (developed countries) is obtained. Currently there is uncertainty
surrounding whether or not the Accord will enter into force. The USA is
notable in that it has rejected the protocol. Regardless, several states in
the USA have begun initiatives to better manage greenhouse gas emissions.
The initiatives in the USA are not expected have a material impact on
EnCanas operations in the foreseeable future. In December 2002, the Canadian Federal Government ratified the Accord
committing Canada to reducing greenhouse gas emissions to 6 percent below
1990 levels over the period 2008  2012. It is premature to predict what
impact the resulting potential regulations could have on the sector but it
is possible that the Company would face minor increases in operating costs
in order to comply with a greenhouse gas emissions reduction target. The
federal government has also committed to several important principles that
will continue to protect the competitiveness of the oil and gas industry
beyond 2012, including a limit to the costs levied against excess
emissions, a ten-year target lock-in period for new projects and additional
flexibility mechanisms for achieving compliance. ALBERTA ENERGY AND UTILITIES BOARD (AEUB) RULING The Companys 2003 production volumes, primarily from the Primrose Block in
north eastern Alberta, were affected by an AEUB decision, in September, to
shut-in natural gas production that put at risk the recovery of bitumen
resources in the area. The decision resulted in EnCanas annualized natural
gas production in the region to decline by approximately three million
cubic feet per day. The future impact of this decision is not known at this
time but is not expected to be material. OUTLOOK Outlook Volumes 2004 vs2004
    
    2003 (2)
    
    2003Produced Gas (million cubic feet per day)
    
    
    2,700 to 2,850
    
    
    
    8
    %
    
    
    2,566Crude Oil and NGLs (barrels per day)
    
    
    240,000 to 260,000
    
    
    
    12
    %
    
    
    222,544Total (barrels of oil equivalent per day)(1)
    
    
    690,000 to 735,000
    
    
    
    10
    %
    
    
    650,211
  (1)
    
    Natural gas converted to barrels of oil equivalent at 6 thousand cubic feet
= 1 barrel of oil equivalent.(2)
    
    Percentage growth based on mid-point of guidance and excludes discontinued
operations. 2004 Capital Investment ($ millions)Upstream
    
    $

    3,700 to $4,000Midstream & Marketing and Corporate
    
    $
    145Core Capital
    
    $

    $3,845 to $4,145Divestitures
    
    $
    (365
    )Net Capital
    
    $

    3,480 to $3,780
 M25




---



##### 



EnCana plans to continue to focus on growing natural gas production and
storage capacity in North America and crude oil production in Canada,
Ecuador and the U.K. central North Sea to deliver near term growth, with
the Gulf of Mexico oil and Canadian East Coast gas growth platforms adding
to longer term growth. The Company also plans to continue its efforts to
expand its medium and long-term growth prospects through focussed
international new ventures exploration. Strong 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 2003. The outlook for
2004 and beyond will be principally impacted by weather, timing of new
production and economic activity. Volatility in crude oil prices is expected to continue in 2004 as a result
of market uncertainties over the reintegration of Iraqi production, lower
than expected inventory levels in the U.S., OPEC compliance with production
quotas and the overall state of the world economies. The Company expects its 2004 core capital investment program, of between
$3,845 million and $4,145 million, to be funded from cash flow, proceeds
from the divestitures of non-core assets and long-term debt. 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 2004 of the sensitivity of the Companys 2004 net
earnings and cash flow to changes in commodity prices and the U.S./Canadian
dollar exchange rate. Sensitivity of 2004 Net Earnings and Cash Flow (Including Hedges)(1) Net
    
    Cash($ millions)
    
    Earnings
    
    Flow$0.25 per million British thermal units increase in the NYMEX gas price
    
    
    75
    
    
    
    75$1.00 per barrel increase in the WTI oil price
    
    
    10
    
    
    
    10$0.01 decrease in the U.S./Canadian dollar exchange rate
    
    
    (20
    )
    
    
    (5
    )
  (1)
    
    Hedge position as at January 31, 2004. Sensitivity of 2004 Net Earnings and Cash Flow (Excluding Hedges) Net
    
    Cash($ millions)
    
    Earnings
    
    Flow$0.25 per million British thermal units increase in the NYMEX gas price
    
    
    145
    
    
    
    145$1.00 per barrel increase in the WTI oil price
    
    
    40
    
    
    
    40$0.01 decrease in the U.S./Canadian dollar exchange rate
    
    
    (15
    )
    
    
    1
 These estimates are based on managements assumptions utilized for 2004
planning purposes, as discussed in this section. Assumptions include
certain levels and profiles of capital expenditures, 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 36 percent. This tax rate is itself affected in varying
degrees by the assumptions referred to in the preceding paragraph. In
addition, it has been assumed that marginal income in Canada will be taxed
at marginal income tax rates, and that marginal income in the U.S.A. will
be subject to Alternative Minimum Tax. Marginal rates in other
jurisdictions are not expected to be material. In November 2003, EnCana provided guidance for 2004 cash taxes in the range
of $585 million to $730 million. Subsequently, in determining current
income tax expense for 2003, approximately $90 million of current income
tax was shifted to 2004 and, accordingly, the previous guidance has been
increased by the same amount (i.e., revised guidance $675 million to $820
million). This guidance is also based on assumptions utilized for 2004
planning purposes, as discussed in this section, including natural gas
prices based on NYMEX of approximately $4.90 per MMbtu, crude oil prices
based on WTI of approximately $26.50 per barrel and a U.S. dollar to
Canadian dollar exchange rate of $0.73. February 6, 2004 M26




---



##### 



ENCANA CORPORATION Consolidated Financial Statements For the Year Ended December 31, 2003




---



##### 



EnCana Corporation 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 judgements. Financial information contained
throughout the annual report is consistent with these financial statements. The Company 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. -s- Gwyn Morgan
    
    -s- John D. WatsonGwyn Morgan
    
    John D. WatsonPresident &
    
    Executive Vice-President &Chief Executive Officer
    
    Chief Financial OfficerFebruary 6, 2004
 F1




---



##### 



EnCana
Corporation

AUDITORS REPORT TO THE SHAREHOLDERS OF ENCANA CORPORATION We have audited the Consolidated Balance Sheets of EnCana Corporation as at
December 31, 2003 and December 31, 2002 and the Consolidated Statements of
Earnings, Retained Earnings and Cash Flows for each of the years in the
three-year period ended December 31, 2003. 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, 2003 and December 31, 2002 and the results of its operations and its
cash flows for each of the years in the three-year period ended December
31, 2003 in accordance with Canadian generally accepted accounting
principles. -s- PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada February 6, 2004 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 6, 2004 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. -s- PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada February 6, 2004 F2




---



##### 



EnCana
Corporation

CONSOLIDATED STATEMENT OF EARNINGS For the years ended
December 31 ($ millions, except per share amounts)
    
    
    
    2003
    
    2002
    
    2001(restated 
    
    (restated Note 2)
    
    Note 2)REVENUES, NET OF ROYALTIES
    
    (Note 4)
    
    $
    10,216
    
    
    $
    6,276
    
    
    $
    3,244EXPENSES
    
    (Note 4)Production and mineral taxes
    
    
    
    
    189
    
    
    
    119
    
    
    
    77Transportation and selling
    
    
    
    
    545
    
    
    
    364
    
    
    
    111Operating
    
    
    
    
    1,297
    
    
    
    813
    
    
    
    448Purchased product
    
    
    
    
    3,455
    
    
    
    2,200
    
    
    
    739Depreciation, depletion and amortization
    
    
    
    
    2,222
    
    
    
    1,304
    
    
    
    510Administrative
    
    
    
    
    173
    
    
    
    119
    
    
    
    54Interest, net
    
    (Note 7)
    
    
    287
    
    
    
    290
    
    
    
    34Accretion of asset retirement obligation
    
    (Note 14)
    
    
    19
    
    
    
    13
    
    
    
    8Foreign exchange (gain) loss
    
    (Note 8)
    
    
    (601
    )
    
    
    (14
    )
    
    
    12Stock-based compensation
    
    (Note 2)
    
    
    18
    
    
    
    
    
    
    
    Gain on corporate disposition
    
    (Note 6)
    
    
    
    
    
    
    (33
    )
    
    
    7,604
    
    
    
    5,175
    
    
    
    1,993NET EARNINGS BEFORE INCOME TAX
    
    
    
    
    2,612
    
    
    
    1,101
    
    
    
    1,251Income tax expense
    
    (Note 9)
    
    
    445
    
    
    
    366
    
    
    
    419NET EARNINGS FROM CONTINUING OPERATIONS
    
    
    
    
    2,167
    
    
    
    735
    
    
    
    832NET EARNINGS FROM DISCONTINUED
OPERATIONS
    
    (Note 5)
    
    
    193
    
    
    
    77
    
    
    
    22NET EARNINGS
    
    
    
    $
    2,360
    
    
    $
    812
    
    
    $
    854NET EARNINGS FROM CONTINUING OPERATIONS
PER COMMON SHARE
    
    (Note 18)Basic
    
    
    
    $
    4.57
    
    
    $
    1.76
    
    
    $
    3.26Diluted
    
    
    
    $
    4.52
    
    
    $
    1.74
    
    
    $
    3.21NET EARNINGS PER COMMON SHARE
    
    (Note 18)Basic
    
    
    
    $
    4.98
    
    
    $
    1.94
    
    
    $
    3.34Diluted
    
    
    
    $
    4.92
    
    
    $
    1.92
    
    
    $
    3.30
 CONSOLIDATED STATEMENT OF RETAINED EARNINGS For the years ended
December 31 ($ millions)
    
    
    
    2003
    
    2002
    
    2001(restated 
    
    (restated Note 2)
    
    Note 2)RETAINED EARNINGS, BEGINNING OF YEARAs previously reported
    
    
    
    $
    3,457
    
    
    $
    2,787
    
    
    $
    2,806Retroactive adjustment for changes
in accounting policies
    
    (Note 2)
    
    
    66
    
    
    
    32
    
    
    
    10As restated
    
    
    
    
    3,523
    
    
    
    2,819
    
    
    
    2,816Net Earnings
    
    
    
    
    2,360
    
    
    
    812
    
    
    
    854Dividends on Common Shares
    
    (Note 18)
    
    
    (139
    )
    
    
    (108
    )
    
    
    (818
    )Charges for Normal Course Issuer Bid
    
    (Note 15)
    
    
    (468
    )
    
    
    
    
    
    
    Other
    
    (Note 18)
    
    
    
    
    
    
    
    
    
    
    (33
    )RETAINED EARNINGS, END OF YEAR
    
    
    
    $
    5,276
    
    
    $
    3,523
    
    
    $
    2,819
 See accompanying notes to Consolidated Financial Statements. F3




---



##### 



EnCana
Corporation

CONSOLIDATED BALANCE SHEET As at December 31 ($ millions)
    
    
    
    2003
    
    2002(restated Note 2)ASSETSCurrent AssetsCash and cash equivalents
    
    
    
    $
    148
    
    
    $
    116Accounts receivable and accrued revenues
    
    
    
    
    1,367
    
    
    
    1,258Inventories
    
    (Note 10)
    
    
    573
    
    
    
    281Assets of discontinued operations
    
    (Note 5)
    
    
    
    
    
    
    2,1552,088
    
    
    
    3,810Property, Plant and Equipment, net
    
    (Notes 4, 11)
    
    
    19,545
    
    
    
    14,247Investments and Other Assets
    
    (Note 12)
    
    
    566
    
    
    
    292Goodwill
    
    
    
    
    1,911
    
    
    
    1,563(Note 4)
    
    $
    24,110
    
    
    $
    19,912LIABILITIES SHAREHOLDERS EQUITYCurrent LiabilitiesAccounts payable and accrued liabilities
    
    
    
    $
    1,579
    
    
    $
    1,445Income tax payable
    
    
    
    
    65
    
    
    
    13Current portion of long-term debt
    
    (Note 13)
    
    
    287
    
    
    
    134Liabilities of discontinued operations
    
    (Note 5)
    
    
    
    
    
    
    1,1001,931
    
    
    
    2,692Long-Term Debt
    
    (Note 13)
    
    
    6,088
    
    
    
    5,051Other Liabilities
    
    
    
    
    21
    
    
    
    54Asset Retirement Obligation
    
    (Note 14)
    
    
    430
    
    
    
    309Future Income Taxes
    
    (Note 9)
    
    
    4,362
    
    
    
    3,08812,832
    
    
    
    11,194Shareholders EquityShare capital
    
    (Note 15)
    
    
    5,305
    
    
    
    5,511Share options, net
    
    
    
    
    55
    
    
    
    84Paid in surplus
    
    
    
    
    18
    
    
    
    51Retained earnings
    
    
    
    
    5,276
    
    
    
    3,523Foreign currency translation adjustment
    
    
    
    
    624
    
    
    
    (451
    )11,278
    
    
    
    8,718$
    24,110
    
    
    $
    19,912Commitments and Contingencies
    
    (Note 19)
 See accompanying notes to Consolidated Financial Statements. Approved by the Board -s- David P. O'Brien
    
    -s- Barry W. HarrisonDavid P. OBrien
    
    Barry W. HarrisonDirector
    
    Director
 F4




---



##### 



EnCana
Corporation

CONSOLIDATED STATEMENT OF CASH FLOWS For the years ended
December 31 ($ millions)
    
    
    
    
    
    2003
    
    2002
    
    2001(restated 
    
    (restated Note 2)
    
    Note 2)OPERATING ACTIVITIESNet earnings from continuing operations
    
    
    
    
    
    $
    2,167
    
    
    $
    735
    
    
    $
    832Depreciation, depletion and amortization
    
    
    
    
    
    
    2,222
    
    
    
    1,304
    
    
    
    510Future income taxes
    
    (Note 9)
    
    
    501
    
    
    
    404
    
    
    
    95Unrealized foreign exchange (gain) loss
    
    (Note 8)
    
    
    (545
    )
    
    
    (23
    )
    
    
    35Accretion of asset retirement obligation
    
    (Note 14)
    
    
    19
    
    
    
    13
    
    
    
    8Other
    
    
    
    
    
    
    56
    
    
    
    (166
    )
    
    
    (17
    )Cash flow from continuing operations
    
    
    
    
    
    
    4,420
    
    
    
    2,267
    
    
    
    1,463Cash flow from discontinued operations
    
    
    
    
    
    
    39
    
    
    
    152
    
    
    
    31Cash flow
    
    
    
    
    
    
    4,459
    
    
    
    2,419
    
    
    
    1,494Net change in other assets and liabilities
    
    
    
    
    
    
    (84
    )
    
    
    (17
    )
    
    
    (40
    )Net change in non-cash working capital from
continuing operations
    
    (Note 18)
    
    
    (81
    )
    
    
    (853
    )
    
    
    350Net change in non-cash working capital from
discontinued operations
    
    
    
    
    
    
    17
    
    
    
    64
    
    
    
    (29
    )4,311
    
    
    
    1,613
    
    
    
    1,775INVESTING ACTIVITIESCapital expenditures
    
    (Note 4)
    
    
    (5,115
    )
    
    
    (3,021
    )
    
    
    (1,259
    )Proceeds on disposal of property, plant and equipment
    
    
    
    
    
    
    301
    
    
    
    363
    
    
    
    31Corporate (acquisitions) and dispositions
    
    (Note 6)
    
    
    (193
    )
    
    
    60
    
    
    
    56Business combination with Alberta Energy
Company Ltd.
    
    (Note 3)
    
    
    
    
    
    
    (80
    )
    
    
    Equity investments
    
    
    
    
    
    
    (161
    )
    
    
    
    
    
    
    Net change in investments and other
    
    
    
    
    
    
    (63
    )
    
    
    43
    
    
    
    19Net change in non-cash working capital from
continuing operations
    
    (Note 18)
    
    
    (83
    )
    
    
    186
    
    
    
    55Discontinued operations
    
    
    
    
    
    
    1,585
    
    
    
    (146
    )
    
    
    6(3,729
    )
    
    
    (2,595
    )
    
    
    (1,092
    )FINANCING ACTIVITIESIssuance of short-term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    281Repayment of short-term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (439
    )Issuance of long-term debt
    
    
    
    
    
    
    1,609
    
    
    
    1,506
    
    
    
    990Repayment of long-term debt
    
    
    
    
    
    
    (963
    )
    
    
    (1,206
    )
    
    
    (256
    )Issuance of common shares
    
    (Note 15)
    
    
    114
    
    
    
    88
    
    
    
    31Purchase of common shares
    
    (Note 15)
    
    
    (868
    )
    
    
    
    
    
    
    (4
    )Dividends on common shares
    
    (Note 18)
    
    
    (139
    )
    
    
    (108
    )
    
    
    (818
    )Other
    
    
    
    
    
    
    (13
    )
    
    
    (53
    )
    
    
    Net change in non-cash working capital
from continuing operations
    
    (Note 18)
    
    
    2
    
    
    
    (7
    )
    
    
    1Discontinued operations
    
    
    
    
    
    
    (282
    )
    
    
    271
    
    
    
    (540
    )
    
    
    491
    
    
    
    (214
    )DEDUCT: FOREIGN EXCHANGE LOSS (GAIN)
ON CASH AND CASH EQUIVALENTS
HELD IN FOREIGN CURRENCY
    
    
    
    
    
    
    10
    
    
    
    (2
    )
    
    
    (5
    )INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS
    
    
    
    
    
    
    32
    
    
    
    (489
    )
    
    
    474CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR
    
    
    
    
    
    
    116
    
    
    
    605
    
    
    
    131CASH AND CASH EQUIVALENTS, END OF YEAR
    
    
    
    
    
    $
    148
    
    
    $
    116
    
    
    $
    605Supplemental Cash Flow Information
    
    (Note 18)
 See accompanying notes to Consolidated Financial Statements. F5




---



##### 



ENCANA FINANCIAL PERFORMANCE Prepared using Canadian generally accepted accounting principles.All amounts in US$ millions, unless otherwise indicated.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTSFor the year ended December 31, 2003 NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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. In
these Consolidated Financial
Statements, unless otherwise
indicated, all dollar amounts are
expressed in United States (U.S.)
dollars. All references to US$ or
to $ are to United States dollars
and references to C$ are to
Canadian dollars. The Company is in the business of
exploration, production and
marketing of natural gas, natural
gas liquids and crude oil, as well
as natural gas storage operations,
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, 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 the
Companys proportionate share of
revenues, expenses, assets and
liabilities are included in the
accounts. Investments in companies and
partnerships in which the Company
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
year-end exchange rates, while
revenues and expenses are
translated using average annual
rates. 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
financial statements in conformity
with Canadian generally accepted
accounting principles requires that
Management make estimates and
assumptions and use judgement
regarding assets, liabilities,
revenues and expenses. Such
estimates primarily relate to
unsettled transactions and events
as of the date of the 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 oil and
natural gas reserves and future
costs required to develop those
reserves. By their nature, these
estimates of reserves and the
related future cash flows are
subject to measurement uncertainty,
and the impact on the financial
statements of future periods could
be material. 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. F6




---



##### 



D) Revenue Recognition Revenues associated with the sales
of the Companys natural gas,
natural gas liquids (NGLs) and
crude oil owned by the Company are
recognized when title passes from
the Company to its customer. Crude
oil and natural gas produced and
sold by the Company 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. Marketing revenues and purchased
product are recorded on a gross
basis as the Company takes title to
product and has the risks and
rewards of ownership. Revenues
associated with the services
provided where the Company 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 the title is
transferred to the customer. E)
Employee Benefit Plans

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
10% 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 plan. Pension expense for the defined
contribution pension plans is
recorded as the benefits are earned
by the employees covered by the
plans. F) Income Taxes The Company follows the liability
method of accounting for income
taxes. Under this method, the
Company records future income
taxes 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. G) 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 common 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. H) 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. I) 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. J) Property, Plant and Equipment Upstream The Company accounts for crude oil
and natural gas 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 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. F7




---



##### 



Costs accumulated within each cost
centre are depreciated, depleted
and amortized using the
unit-of-production method based on
estimated proved reserves. 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% 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. 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 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 and
contain no probable reserves. 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. K) 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. L) 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. M) 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. N) 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
estimated fair value of the asset
retirement obligation, is
capitalized as part of the cost of
the related long-lived asset. 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 on 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. O) Stock-based Compensation The Company 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 (see Note 2). F8




---



##### 



Obligations for cash payments under
the Companys share appreciation
rights, deferred share units and
performance share units are accrued
as compensation expense over the
vesting period. Fluctuations in the
price of the Companys common
shares will change the accrued
compensation expense and are
recognized when they occur. P) 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 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 also identifies all
relationships between hedging
instruments and hedged items, as
well as its risk management
objective and the strategy for
undertaking hedge transaction. This
would include linking the
particular derivative to specific
assets and liabilities on the
balance sheet or to specific firm
commitments or forecasted
transactions. Where specific hedges
are executed, the Company assesses,
both at the inception of the hedge
and on an ongoing basis, whether
the derivative used in the
particular hedging transaction is
effective in offsetting changes in
fair values or cash flows of the
hedged item. 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. Gains and losses from
these derivative financial
instruments are recognized in oil
and gas revenues as the related
production occurs. 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 also 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 may also purchase
foreign exchange forward contracts
to hedge anticipated sales to
customers in the United States and
the related accounts receivable.
Foreign exchange translation gains
and losses on these instruments are
recognized as an adjustment of the
revenues when the sale is recorded. Q) Reclassification Certain information provided for
prior years has been reclassified
to conform to the presentation
adopted in 2003. R) Recently Issued Accounting Pronouncements During 2003, the following amended standard was issued: Hedging Relationships The Canadian Institute of Chartered
Accountants (CICA) modified
Accounting Guideline 13 (AcG 
13) Hedging Relationships,
effective January 1, 2004, to
clarify circumstances in which
hedge accounting is appropriate. In
addition, the CICA simultaneously
amended EIC 128, Accounting for
Trading, Speculative or Non Trading
Derivative Financial Instruments
to require that all derivative
instruments that do not qualify as
a hedge under AcG  13, or are not
designated as a hedge, be recorded
in the balance sheet as either an
asset or liability with changes in
fair value recognized in earnings.
For 2004, the Company has elected
not to designate any of its current

price risk management activities as
accounting hedges under AcG  13
and, accordingly, will account for
all derivatives using the
mark-to-market accounting method.
The impact on the Companys
financial statements at January 1,
2004, is an increase in assets of
$145 million, an increase in
liabilities of $380 million and a
deferred loss of $235 million which
will be recognized as the contracts
expire ($162 million, net of tax). F9




---



##### 



NOTE 2 CHANGES IN ACCOUNTING POLICIES AND PRACTICES A) Reporting Currency The Company has adopted the United
States 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. The Company
uses the current rate method for
foreign currency translations. All
prior periods have been restated to
reflect the United States dollar as
the reporting currency. B) Preferred Securities The Company has retroactively
adopted the amendments made to CICA
Handbook section 3860, Financial
Instruments  Disclosure and
Presentation. As a result, the
preferred securities issued by the
Company are now recorded as a
liability and included in long-term
debt. The effect on the Companys
Consolidated Statement of Earnings
was to increase net earnings by $6
million (2002  $2 million
decrease; 2001  $3 million
decrease). The effect to the
Companys Consolidated Balance
Sheet is to increase current
portion of long-term debt by $97
million, increase long-term debt by
$321 million and decrease
shareholders equity by $418
million (2002  $369 million
increase to long-term debt; $289
million decrease to preferred
securities of subsidiary; $80
million decrease to shareholders
equity). C) Asset Retirement Obligations The Company has retroactively early
adopted the Canadian accounting
standard outlined in CICA Handbook
section 3110, Asset Retirement
Obligations. This new section
requires liability recognition for
retirement obligations associated
with tangible long-lived assets,
such as producing well sites,
offshore production platforms and
natural gas processing plants. The
obligations included within the
scope of this section are those for
which a company faces a legal
obligation for settlement or has
made promissory estoppel. The
initial measurement of the asset
retirement obligation is at fair
value, defined as the price that
an entity would have to pay a
willing third party of comparable
credit standing to assume the
liability in a current transaction
other than in a forced or
liquidation sale. The asset retirement cost, equal to
the fair value of the retirement
obligation, is capitalized as part
of the cost of the related
long-lived asset and allocated to
expense on a basis consistent with
depreciation, depletion and
amortization. The Company previously estimated
costs of dismantlement, removal,
site reclamation and other similar
activities and recorded them into
earnings on a unit-of production
basis over the remaining life of
the proved reserves and accumulated
a liability on the
Consolidated Balance Sheet. Upon
adoption, all prior periods have
been restated for the change in
accounting policy. The change
results in an increase in net
earnings of $36 million for the
year ended December 31, 2003 (2002
 $34 million; 2001  $22 million).
The effect of this change on the
December 31, 2003 Consolidated
Balance Sheet is an increase in
property, plant and equipment of
$142 million (2002  $94 million),
no change in the assets of
discontinued operations (2002  $11
million decrease), an increase in
liabilities of $22 million (2002 
$16 million), an increase to
retained earnings of $102 million
(2002 $66 million) and an increase
in foreign currency translation
adjustment of $18 million (2002 
$1 million). D) Stock-based Compensation The Company has early adopted the
Canadian accounting standard as
outlined in CICA Handbook section
3870, Stock-based Compensation and
Other Stock-based Payments. As
allowed by the section, this policy
has been adopted prospectively,
meaning all prior years have not
been restated. The adoption of the new accounting
standard for stock-based
compensation resulted in the
Company recognizing an expense of
$18 million in 2003. F10




---



##### 



E) Full Cost Accounting The Company has early adopted the new CICA Accounting Guideline AcG  16,
Oil and Gas Accounting  Full Cost. The new guideline modifies how the
ceiling test is performed, and requires cost centres be tested for
recoverability using undiscounted future cash flows from proved reserves
which are determined by using forward indexed prices. When the carrying
amount of a cost centre is not recoverable, the cost centre would be written
down to its fair value. Fair value is estimated using accepted present value
techniques which incorporate risks and other uncertainties when determining
expected cash flows (see Note 1). Additional disclosures are also required
as provided in Note 11. There is no impact on the Companys reported
financial results as a result of applying the new Accounting Guideline AcG 
16. F) Employee Future Benefits The Company has early adopted the amendments made to disclosure requirements
in the CICA Handbook section 3461, Employee Future Benefits (see Note 16).
There is no impact on the Companys reported financial results as a result
of applying these increased disclosure requirements. G) Summary of Changes in Accounting Policies and Practices The following table summarizes the effect of the changes in accounting
policies: 2003
    
    2002As
    
    
    
    
    
    As
    
    As
    
    
    
    
    
    AsAs at and for the years ended December 31
    
    
    
    
    
    Reported
    
    Change
    
    Restated
    
    Reported
    
    Change
    
    RestatedConsolidated Balance SheetAssetsAssets of discontinued operations
    
    
    (C)
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    2,166
    
    
    $
    (11
    )
    
    $
    2,155Property, plant and equipment, net
    
    
    (C)
    
    
    
    19,403
    
    
    
    142
    
    
    
    19,545
    
    
    
    14,153
    
    
    
    94
    
    
    
    14,247LiabilitiesLiabilities of discontinued
operations
    
    
    (C)
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    1,113
    
    
    $
    (13
    )
    
    $
    1,100Current portion of long-term debt
    
    
    (B)
    
    
    
    190
    
    
    
    97
    
    
    
    287
    
    
    
    134
    
    
    
    
    
    
    
    134Long-term debt
    
    
    (B)
    
    
    
    5,767
    
    
    
    321
    
    
    
    6,088
    
    
    
    4,682
    
    
    
    369
    
    
    
    5,051Preferred securities of subsidiary
    
    
    (B)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    289
    
    
    
    (289
    )
    
    
    Other liabilities & asset
retirement obligation
    
    
    (C)
    
    
    
    473
    
    
    
    (22
    )
    
    
    451
    
    
    
    357
    
    
    
    6
    
    
    
    363Future income taxes
    
    
    (C)
    
    
    
    4,318
    
    
    
    44
    
    
    
    4,362
    
    
    
    3,065
    
    
    
    23
    
    
    

    3,088Shareholders EquityPreferred securities
    
    
    (B)
    
    
    $
    418
    
    
    $
    (418
    )
    
    $
    
    
    
    $
    80
    
    
    $
    (80
    )
    
    $
    Paid in surplus
    
    
    (D)
    
    
    
    
    
    
    
    18
    
    
    
    18
    
    
    
    51
    
    
    
    
    
    
    
    51Retained earnings
    
    
    (C)
    
    
    
    5,192
    
    
    
    84
    
    
    
    5,276
    
    
    
    3,457
    
    
    
    66
    
    
    
    3,523Foreign currency translation
adjustment
    
    
    (C)
    
    
    
    606
    
    
    
    18
    
    
    
    624
    
    
    
    (452
    )
    
    
    1
    
    
    
    (451
    )Consolidated Statement of EarningsNet Earnings
    
    
    (B),(C),(D)
    
    
    $
    2,336
    
    
    $
    24
    
    
    $
    2,360
    
    
    $
    780
    
    
    $
    32
    
    
    $
    812Net Earnings perCommon Share  Diluted
    
    
    (B),(C),(D)
    
    
    $
    4.88
    
    
    $
    0.04
    
    
    $
    4.92
    
    
    $
    1.84
    
    
    $
    0.08
    
    
    $
    1.92
 F11




---



##### 



NOTE 3 BUSINESS COMBINATION WITH ALBERTA ENERGY COMPANY LTD. On January 27, 2002, PanCanadian Energy Corporation (PanCanadian) and
Alberta Energy Company Ltd. (AEC) announced plans to combine the
companies. The transaction was accomplished through 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. The transaction closed April 5, 2002,
and PanCanadian changed its name to EnCana Corporation. This business combination has been accounted for using the purchase method
with the results of operations of AEC included in the Consolidated
Financial Statements from the date of acquisition.

The calculation of the purchase price and the allocation to assets and
liabilities acquired as of April 5, 2002 is shown below: Calculation 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)
    
    
    
    
    
    
    105Transaction Costs
    
    
    
    
    
    
    94Total purchase price
    
    
    
    
    
    
    5,480Plus: Fair value of liabilities assumedCurrent liabilities
    
    
    
    
    
    
    1,120Long-term debt (including preferred securities)
    
    
    
    
    
    
    3,714Other non-current liabilities
    
    
    
    
    
    
    180Future income taxes
    
    
    
    
    
    
    1,665Total Purchase Price and Liabilities Assumed
    
    
    
    
    
    $
    12,159Fair Value of Assets Acquired:Current assets
    
    
    
    
    
    $
    946Property, plant and equipment, net
    
    
    
    
    
    
    8,897Other non-current assets
    
    
    
    
    
    
    381Goodwill
    
    
    
    
    
    
    1,935Total Fair Value of Assets Acquired
    
    
    
    
    
    $
    12,159Goodwill Allocation:Upstream
    
    
    
    
    
    $
    1,504Midstream & Marketing
    
    
    
    
    
    
    491,553Discontinued Operations
    
    
    
    
    
    
    382Total Goodwill Allocation
    
    
    
    
    
    $
    1,935
 F12




---



##### 



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, natural gas liquids and crude oil and
other related activities. The majority of the Companys Upstream
operations are located in Canada, the United States, the United
Kingdom and Ecuador. International new venture exploration is mainly
focused on opportunities in Africa, South America and the Middle East.
    
    Midstream & Marketing includes natural gas storage operations, natural
gas liquids processing and power generation operations, as well as
marketing activities. These marketing activities include the sale and
delivery of produced product, and the purchasing of third party product
primarily for the optimization of midstream assets, as well as the
optimization of transportation arrangements not fully utilized for the
Companys own production. Midstream & Marketing purchases 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. In 2003, the Company redefined its business segments to those described
above. All prior periods have been restated to conform to the current
presentation. Operations that have been discontinued are disclosed in Note 5. Results of Operations (for the years ended December 31) Upstream
    
    Midstream & Marketing2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues, Net of Royalties
    
    $
    6,327
    
    
    $
    3,674
    
    
    $
    2,315
    
    
    $
    3,887
    
    
    $
    2,594
    
    
    $
    931ExpensesProduction and mineral taxes
    
    
    189
    
    
    
    119
    
    
    
    77
    
    
    
    
    
    
    
    
    
    
    
    Transportation and selling
    
    
    490
    
    
    
    277
    
    
    
    100
    
    
    
    55
    
    
    
    87
    
    
    
    11Operating
    
    
    973
    
    
    
    626
    
    
    
    294
    
    
    
    324
    
    
    
    187
    
    
    
    154Purchased product
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,455
    
    
    
    2,200
    
    
    
    739Depreciation, depletion and amortization
    
    
    2,133
    
    
    
    1,233
    
    
    
    478
    
    
    
    48
    
    
    
    36
    
    
    
    10Segment Income
    
    $
    2,542
    
    
    $
    1,419
    
    
    $
    1,366
    
    
    $
    5
    
    
    $
    84
    
    
    $
    17
 Corporate
    
    Consolidated2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues, Net of Royalties
    
    $
    2
    
    
    $
    8
    
    
    $
    (2
    )
    
    $
    10,216
    
    
    $
    6,276
    
    
    $
    3,244ExpensesProduction and mineral taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    189
    
    
    
    119
    
    
    
    77Transportation and selling
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    545
    
    
    
    364
    
    
    
    111Operating
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,297
    
    
    
    813
    
    
    
    448Purchased product
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,455
    
    
    
    2,200
    
    
    
    739Depreciation, depletion and amortization
    
    
    41
    
    
    
    35
    
    
    
    22
    
    
    
    2,222
    
    
    
    1,304
    
    
    
    510Segment Income
    
    $
    (39
    )
    
    $
    (27
    )
    
    $
    (24
    )
    
    
    2,508
    
    
    
    1,476
    
    
    
    1,359Administrative
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    173
    
    
    
    119
    
    
    
    54Interest, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    287
    
    
    
    290
    
    
    
    34Accretion of asset retirement obligation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19
    
    
    
    13
    
    
    
    8Foreign exchange (gain) loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (601
    )
    
    
    (14
    )
    
    
    12Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18
    
    
    
    
    
    
    
    Gain on corporate disposition
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (33
    )
    
    
    (104
    )
    
    
    375
    
    
    
    108Net Earnings Before Income Tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,612
    
    
    
    1,101
    
    
    
    1,251Income tax expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    445
    
    
    
    366
    
    
    
    419Net Earnings from Continuing Operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    2,167
    
    
    $
    735
    
    
    $
    832
 F13




---



##### 



Geographic and Product Information (for the years ended December 31) UPSTREAM North AmericaProduced Gas and NGLsCanada
    
    United States
    
    Crude Oil2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues, Net of Royalties
    
    $
    3,523
    
    
    $
    1,971
    
    
    $
    1,598
    
    
    $
    1,143
    
    
    $
    454
    
    
    $
    59
    
    
    $
    951
    
    
    $
    825
    
    
    $
    523ExpensesProduction and mineral taxes
    
    
    52
    
    
    
    50
    
    
    
    48
    
    
    
    108
    
    
    
    35
    
    
    
    7
    
    
    
    4
    
    
    
    20
    
    
    
    22Transportation and selling
    
    
    274
    
    
    
    151
    
    
    
    72
    
    
    
    86
    
    
    
    59
    
    
    
    
    
    
    
    69
    
    
    
    35
    
    
    
    16Operating
    
    
    342
    
    
    
    255
    
    
    
    112
    
    
    
    60
    
    
    
    35
    
    
    
    11
    
    
    
    300
    
    
    
    201
    
    
    
    153Depreciation, depletion and amortization
    
    
    1,075
    
    
    
    625
    
    
    
    261
    
    
    
    293
    
    
    
    202
    
    
    
    31
    
    
    
    436
    
    
    
    237
    
    
    
    124Segment Income
    
    $
    1,780
    
    
    $
    890
    
    
    $
    1,105
    
    
    $
    596
    
    
    $
    123
    
    
    $
    10
    
    
    $
    142
    
    
    $
    332
    
    
    $
    208
 Ecuador
    
    U.K. North Sea
    
    Other
    
    Total Upstream2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues, Net
of Royalties
    
    $
    412
    
    
    $
    245
    
    
    $
    
    
    
    $
    118
    
    
    $
    103
    
    
    $
    111
    
    
    $
    180
    
    
    $
    76
    
    
    $
    24
    
    
    $
    6,327
    
    
    $
    3,674
    
    
    $
    2,315ExpensesProduction and
mineral taxes
    
    
    25
    
    
    
    14
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    189
    
    
    
    119
    
    
    
    77Transportation
and selling
    
    
    45
    
    
    
    21
    
    
    
    
    
    
    
    16
    
    
    
    11
    
    
    
    12
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    490
    
    
    
    277
    
    
    
    100Operating
    
    
    83
    
    
    
    53
    
    
    
    
    
    
    
    18
    
    
    
    11
    
    
    
    10
    
    
    
    170
    
    
    
    71
    
    
    
    8
    
    
    
    973
    
    
    
    626
    
    
    
    294Depreciation,
depletion and
amortization
    
    
    159
    
    
    
    79
    
    
    
    
    
    
    
    74
    
    
    
    39
    
    
    
    42
    
    
    
    96
    
    
    
    51
    
    
    
    20
    
    
    
    2,133
    
    
    
    1,233
    
    
    
    478Segment Income
    
    $
    100
    
    
    $
    78
    
    
    $
    
    
    
    $
    10
    
    
    $
    42
    
    
    $
    47
    
    
    $
    (86
    )
    
    $
    (46
    )
    
    $
    (4
    )
    
    $
    2,542
    
    
    $
    1,419
    
    
    $
    1,366
 MIDSTREAM & MARKETING Total MidstreamMidstream
    
    Marketing
    
    Marketing2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues
    
    $
    1,084
    
    
    $
    440
    
    
    $
    154
    
    
    $
    2,803
    
    
    $
    2,154
    
    
    $
    777
    
    
    $
    3,887
    
    
    $
    2,594
    
    
    $
    931ExpensesTransportation and selling
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    55
    
    
    
    87
    
    
    
    11
    
    
    
    55
    
    
    
    87
    
    
    
    11Operating
    
    
    261
    
    
    
    174
    
    
    
    142
    
    
    
    63
    
    
    
    13
    
    
    
    12
    
    
    
    324
    
    
    
    187
    
    
    
    154Purchased product
    
    
    762
    
    
    
    169
    
    
    
    
    
    
    
    2,693
    
    
    
    2,031
    
    
    
    739
    
    
    
    3,455
    
    
    
    2,200
    
    
    
    739Depreciation, depletion and amortization
    
    
    40
    
    
    
    24
    
    
    
    9
    
    
    
    8
    
    
    
    12
    
    
    
    1
    
    
    
    48
    
    
    
    36
    
    
    
    10Segment Income
    
    $
    21
    
    
    $
    73
    
    
    $
    3
    
    
    $
    (16
    )
    
    $
    11
    
    
    $
    14
    
    
    $
    5
    
    
    $
    84
    
    
    $
    17
 F14




---



##### 



Capital Expenditures For the years ended December 31
    
    2003
    
    2002
    
    2001UpstreamCanada
    
    $
    3,198
    
    
    $
    1,388
    
    
    $
    919United States
    
    
    968
    
    
    
    1,176
    
    
    
    139Ecuador
    
    
    265
    
    
    
    168
    
    
    
    United Kingdom
    
    
    223
    
    
    
    82
    
    
    
    46Other Countries
    
    
    78
    
    
    
    117
    
    
    
    424,732
    
    
    
    2,931
    
    
    
    1,146Midstream & Marketing
    
    
    276
    
    
    
    47
    
    
    
    96Corporate
    
    
    107
    
    
    
    43
    
    
    
    17Total
    
    $
    5,115
    
    
    $
    3,021
    
    
    $
    1,259
 Additions to Goodwill
There were no additions to goodwill during the year (see Note 3). Property, Plant and Equipment and Total Assets Property, Plantand Equipment
    
    Total AssetsAs at December 31
    
    2003
    
    2002
    
    2003
    
    2002Upstream
    
    $
    18,532
    
    
    $
    13,656
    
    
    $
    21,742
    
    
    $
    16,042Midstream & Marketing
    
    
    784
    
    
    
    470
    
    
    
    1,879
    
    
    
    1,403Corporate
    
    
    229
    
    
    
    121
    
    
    
    489
    
    
    
    312Assets of Discontinued Operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,155Total
    
    $
    19,545
    
    
    $
    14,247
    
    
    $
    24,110
    
    
    $
    19,912
 Export Sales Sales of natural gas, crude oil and natural gas liquids produced or
purchased in Canada made outside of Canada were $1,484 million
(2002 
$1,333 million; 2001  $785 million). Major Customers In connection with the marketing and sale of the Companys own and
purchased natural gas and crude oil, for the year ended December 31, 2003,
the Company had two customers which individually accounted for 10 percent
of its consolidated revenues, net of royalties (2002  none). One customer,
a major international integrated energy company with a high quality
investment grade credit rating, purchased approximately $1,362 million. The
second customer, a Canadian natural gas clearing exchange with substantial
credit controls, purchased approximately $1,056 million. 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. The majority of the Companys revenues in the United Kingdom is earned from
a single customer who has a high quality investment grade credit rating. NOTE 5 DISCONTINUED OPERATIONS 2003 On February 28, 2003, the Company completed the sale of its 10 percent
working interest in the Syncrude Joint Venture (Syncrude) to Canadian Oil
Sands Limited for net cash consideration of C$1,026 million ($690 million).
On July 10, 2003 the Company completed the sale of the remaining 3.75
percent interest in Syncrude and a gross overriding royalty for net cash
consideration of C$427 million ($309 million). This transaction completed
the Companys disposition of its interest in Syncrude and, as a result,
these operations have been accounted for as discontinued operations. There
was no gain or loss on this sale. F15




---



##### 



2002 On April 24, 2002, the Company adopted formal plans to exit from the
Houston-based merchant energy operation, which was included in the
Midstream & Marketing 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
C$1.6 billion ($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 a gain on sale of C$263 million
($ 169 million). For comparative purposes, the following tables present the effect of only
the Merchant Energy discontinued operations
on the Consolidated Financial Statements for the year ended December 31,
2001. The tables do not include any financial information related to
Midstream  Pipelines or Upstream  Syncrude for 2001 as EnCana did not own
these operations. Consolidated Statement of Earnings2003 UPSTREAM  SYNCRUDE For the years ended December 31
    
    2003
    
    2002Revenues, Net of Royalties
    
    $
    87
    
    
    $
    232ExpensesTransportation and selling
    
    
    2
    
    
    
    3Operating
    
    
    46
    
    
    
    105Depreciation, depletion and amortization
    
    
    7
    
    
    
    16Interest, net
    
    
    
    
    
    
    155
    
    
    
    125Net Earnings Before Income Tax
    
    
    32
    
    
    
    107Income tax expense
    
    
    8
    
    
    
    28Net Earnings from Discontinued Operations
    
    $
    24
    
    
    $
    79
 2002
MIDSTREAM & MARKETING Merchant Energy
    
    Midstream  Pipelines
    
    TotalFor the years ended December 31
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Revenues
    
    $
    
    
    
    $
    922
    
    
    $
    2,646
    *
    
    $
    
    
    
    $
    135
    
    
    $
    
    
    
    $
    
    
    
    $
    1,057
    
    
    $
    2,646ExpensesOperating
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    50
    
    
    
    
    
    
    
    
    
    
    
    50
    
    
    
    Purchased product
    
    
    
    
    
    
    931
    
    
    
    2,578
    *
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    931
    
    
    
    2,578Depreciation, depletion
and amortization
    
    
    
    
    
    
    
    
    
    
    4
    
    
    
    
    
    
    
    18
    
    
    
    
    
    
    
    
    
    
    
    18
    
    
    
    4Administrative
    
    
    
    
    
    
    22
    
    
    
    27
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    22
    
    
    
    27Interest, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19
    
    
    
    
    
    
    
    
    
    
    
    19
    
    
    
    Foreign exchange (gain)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3
    )
    
    
    
    
    
    
    
    
    
    
    (3
    )
    
    
    (Gain) loss on
discontinuance
    
    
    
    
    
    
    19
    
    
    
    
    
    
    
    (220
    )
    
    
    
    
    
    
    
    
    
    
    (220
    )
    
    
    19
    
    
    
    
    
    
    
    972
    
    
    
    2,609
    
    
    
    (220
    )
    
    
    84
    
    
    
    
    
    
    
    (220
    )
    
    
    1,056
    
    
    
    2,609Net Earnings (Loss) Before
Income Tax
    
    
    
    
    
    
    (50
    )
    
    
    37
    
    
    
    220
    
    
    
    51
    
    
    
    
    
    
    
    220
    
    
    
    1
    
    
    
    37Income tax expense
(recovery)
    
    
    
    
    
    
    (17
    )
    
    
    15
    
    
    
    51
    
    
    
    20
    
    
    
    
    
    
    
    51
    
    
    
    3
    
    
    
    15Net Earnings (Loss)
from Discontinued
Operations
    
    $
    
    
    
    $
    (33
    )
    
    $
    22
    
    
    $
    169
    
    
    $
    31
    
    
    $
    
    
    
    $
    169
    
    
    $
    (2
    )
    
    $
    22
  *
    
    Upon review of additional information related to 2001 sales and purchases
of natural gas by the U.S. marketing subsidiary, the Company has determined
certain revenue and expenses should have been reflected in the financial
statements on a net basis rather than included on a gross basis as revenues
and expenses  purchased product. The amendment had no effect on net
earnings or cash flow but revenues and expenses  purchased product have
been reduced by $727 million. F16




---



##### 



Consolidated Total For the years ended December 31
    
    2003
    
    2002
    
    2001Revenues, Net of Royalties
    
    $
    87
    
    
    $
    1,289
    
    
    $
    2,646ExpensesTransportation and selling
    
    
    2
    
    
    
    3
    
    
    
    Operating
    
    
    46
    
    
    
    155
    
    
    
    Purchased product
    
    
    
    
    
    
    931
    
    
    
    2,578Depreciation, depletion and amortization
    
    
    7
    
    
    
    34
    
    
    
    4Administrative
    
    
    
    
    
    
    22
    
    
    
    27Interest, net
    
    
    
    
    
    
    20
    
    
    
    Foreign exchange (gain)
    
    
    
    
    
    
    (3
    )
    
    
    (Gain) loss on discontinuance
    
    
    (220
    )
    
    
    19
    
    
    
    (165
    )
    
    
    1,181
    
    
    
    2,609Net Earnings Before Income Tax
    
    
    252
    
    
    
    108
    
    
    
    37Income tax expense
    
    
    59
    
    
    
    31
    
    
    
    15Net Earnings from Discontinued Operations
    
    $
    193
    
    
    $
    77
    
    
    $
    22
 Consolidated Balance Sheet As all discontinued operations have either been disposed of or wind up has
been completed, there are no remaining assets or liabilities at December
31, 2003. The balance sheet below shows the assets and liabilities of these
operations as at December 31, 2002. Merchant
    
    MidstreamAs at December 31, 2002
    
    Syncrude
    
    Energy
    
     Pipelines
    
    TotalAssetsCash and cash equivalents
    
    $
    18
    
    
    $
    
    
    
    $
    43
    
    
    $
    61Accounts receivable and accrued revenues
    
    
    41
    
    
    
    
    
    
    
    20
    
    
    
    61Inventories
    
    
    9
    
    
    
    
    
    
    
    1
    
    
    
    1068
    
    
    
    
    
    
    
    64
    
    
    
    132Property, plant and equipment, net
    
    
    884
    
    
    
    
    
    
    
    517
    
    
    
    1,401Investments and other assets
    
    
    
    
    
    
    
    
    
    
    237
    
    
    
    237Goodwill
    
    
    264
    
    
    
    
    
    
    
    121
    
    
    
    3851,216
    
    
    
    
    
    
    
    939
    
    
    
    2,155LiabilitiesAccounts payable and accrued liabilities
    
    
    68
    
    
    
    3
    
    
    
    25
    
    
    
    96Income tax payable
    
    
    (4
    )
    
    
    
    
    
    
    11
    
    
    
    7Short-term debt
    
    
    277
    
    
    
    
    
    
    
    
    
    
    
    277Current portion of long-term debt
    
    
    
    
    
    
    
    
    
    
    15
    
    
    
    15341
    
    
    
    3
    
    
    
    51
    
    
    
    395Long-term debt
    
    
    
    
    
    
    
    
    
    
    365
    
    
    
    365Future income taxes
    
    
    236
    
    
    
    
    
    
    
    104
    
    
    
    340577
    
    
    
    3
    
    
    
    520
    
    
    
    1,100Net Assets of Discontinued Operations
    
    $
    639
    
    
    $
    (3
    )
    
    $
    419
    
    
    $
    1,055
 F17




---



##### 



NOTE 6 CORPORATE (ACQUISITIONS) AND DISPOSITIONS For the years ended December 31
    
    2003
    
    2002
    
    2001AcquisitionsVintage
    
    $
    (116
    )
    
    $
    
    
    
    $
    Savannah
    
    
    (91
    )
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    
    
    
    
    (47
    )(207
    )
    
    
    
    
    
    
    (47
    )DispositionsEnCana Suffield Gas Pipeline Inc.
    
    
    
    
    
    
    60
    
    
    
    Other
    
    
    14
    
    
    
    
    
    
    
    10314
    
    
    
    60
    
    
    
    103$
    (193
    )
    
    $
    60
    
    
    $
    56
 On January 31, 2003, the Company acquired the Ecuadorian interests of
Vintage Petroleum Inc. (Vintage) for net cash consideration of $116
million. 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. These purchases were accounted for using the purchase method with the
results reflected in the consolidated results of EnCana from the dates of
acquisition. These acquisitions were accounted for as follows: Vintage
    
    SavannahWorking Capital
    
    $
    1
    
    
    $
    1Property, Plant and Equipment
    
    
    126
    
    
    
    110Future Income Taxes
    
    
    (11
    )
    
    
    (20
    )$
    116
    
    
    $
    91
 In 2002, the Company sold its investment in EnCana Suffield Gas Pipeline Inc.
for total proceeds of $60 million, with a gain on sale of $33 million. NOTE 7 INTEREST, NET For the years ended December 31
    
    2003
    
    2002
    
    2001Interest
Expense  Long-Term Debt
    
    $
    281
    
    
    $
    252
    
    
    $
    55Early Retirement of Long-Term Debt
    
    
    
    
    
    
    34
    
    
    
    Interest
Expense  Other
    
    
    20
    
    
    
    10
    
    
    
    Interest Income
    
    
    (14
    )
    
    
    (6
    )
    
    
    (21
    )$
    287
    
    
    $
    290
    
    
    $
    34
 The Company 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 2003 by $23 million
(2002 
$20 million; 2001  $11 million). Principal
    
    Indenture
    
    NetAmount
    
    Interest
    
    Swap to
    
    Effective Rate8.40% due December 15, 2004
C$100 million
    
    US$73 million
    
    C$ Fixed
    
    US$ Floating*
    
    3 month LIBOR less 41 basis points8.75% due November 9, 2005
C$200 million
    
    US$73 million
    
    C$ Fixed
    
    US$ Fixed*
    
    4.99%US$73 million
    
    C$ Fixed
    
    US$ Floating*
    
    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$ Fixed
    
    US$ Fixed*
    
    4.80%C$125 million
    
    C$ Fixed
    
    C$ Floating
    
    3 month Bankers Acceptance less 5 basis points7.00% due March 23, 2034
C$126 million
    
    C$126 million
    
    C$ Fixed
    
    C$ Floating
    
    3 month Bankers Acceptance plus 104 basis points
 * These instruments have been subject to multiple swap transactions. F18




---



##### 



NOTE 8 FOREIGN EXCHANGE (GAIN) LOSS For the years ended December 31
    
    2003
    
    2002
    
    2001Unrealized Foreign Exchange (Gain) Loss on Translation
of U.S. Dollar Debt Issued in Canada
    
    $
    (545
    )
    
    $
    (23
    )
    
    $
    35Other Foreign Exchange (Gains) Losses
    
    
    (56
    )
    
    
    9
    
    
    
    (23
    )$
    (601
    )
    
    $
    (14
    )
    
    $
    12
 NOTE 9 INCOME TAXES For the years ended December 31
    
    2003
    
    2002
    
    2001Provision for Income TaxesCurrentCanada
    
    $
    (136
    )
    
    $
    (26
    )
    
    $
    320United States
    
    
    39
    
    
    
    (31
    )
    
    
    1Ecuador
    
    
    39
    
    
    
    17
    
    
    
    Other
    
    
    2
    
    
    
    2
    
    
    
    3(56
    )
    
    
    (38
    )
    
    
    324Future
    
    
    860
    
    
    
    424
    
    
    
    148Future tax rate reductions
    
    
    (359
    )
    
    
    (20
    )
    
    
    (53
    )$
    445
    
    
    $
    366
    
    
    $
    419
 The net future income tax liability is comprised of: As at December 31
    
    2003
    
    2002Future Tax LiabilitiesCapital assets in excess of tax values
    
    $
    3,515
    
    
    $
    2,821Timing of Partnership items
    
    
    1,162
    
    
    
    513Future Tax AssetsNet operating losses carried forward
    
    
    (174
    )
    
    
    (203
    )Other
    
    
    (141
    )
    
    
    (43
    )Net Future Income Tax Liability
    
    $
    4,362
    
    
    $
    3,088
 The following table reconciles income taxes calculated at the Canadian
statutory rate with actual income taxes: For the years ended December 31
    
    2003
    
    2002
    
    2001Net Earnings Before Income Tax
    
    $
    2,612
    
    
    $
    1,101
    
    
    $
    1,251Canadian Statutory Rate
    
    
    40.95
    %
    
    
    42.3
    %
    
    
    42.8
    %Expected Income Taxes
    
    
    1,070
    
    
    
    467
    
    
    
    536Effect on Taxes Resulting from:Non-deductible Canadian crown payments
    
    
    231
    
    
    
    147
    
    
    
    74Canadian resource allowance
    
    
    (258
    )
    
    
    (200
    )
    
    
    (167
    )Large corporations tax
    
    
    27
    
    
    
    23
    
    
    
    9Statutory rate differences
    
    
    (50
    )
    
    
    (36
    )
    
    
    (12
    )Effect of tax rate changes
    
    
    (359
    )
    
    
    (20
    )
    
    
    (53
    )Non-taxable capital gains
    
    
    (119
    )
    
    
    (9
    )
    
    
    Previously unrecognized capital losses
    
    
    (119
    )
    
    
    
    
    
    
    Other
    
    
    22
    
    
    
    (6
    )
    
    
    32$
    445
    
    
    $
    366
    
    
    $
    419Effective Tax Rate
    
    
    17.0
    %
    
    
    33.2
    %
    
    
    33.5
    %
 F19




---



##### 



The approximate amounts of tax pools available are as follows: As at December 31
    
    2003
    
    2002Canada
    
    $
    6,904
    
    
    $
    4,444United States
    
    
    2,112
    
    
    
    2,175Ecuador
    
    
    1,015
    
    
    
    831United Kingdom
    
    
    230
    
    
    
    123$
    10,261
    
    
    $
    7,573
 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 later year end than the
Company. NOTE 10 INVENTORIES As at December 31
    
    2003
    
    2002ProductUpstream
    
    $
    11
    
    
    $
    34Midstream & Marketing
    
    
    546
    
    
    
    239Parts and Supplies
    
    
    16
    
    
    
    8$
    573
    
    
    $
    281
 NOTE 11 PROPERTY, PLANT AND EQUIPMENT, NET 2003
    
    2002Accumulated
    
    
    
    
    
    
    
    
    
    AccumulatedAs at December 31
    
    Cost
    
    DD&A*
    
    Net
    
    Cost
    
    DD&A*
    
    NetUpstreamCanada
    
    $
    20,607
    
    
    $
    (7,500
    )
    
    $
    13,107
    
    
    $
    14,077
    
    
    $
    (4,770
    )
    
    $
    9,307United States
    
    
    4,062
    
    
    
    (523
    )
    
    
    3,539
    
    
    
    3,184
    
    
    
    (262
    )
    
    
    2,922Ecuador
    
    
    1,442
    
    
    
    (188
    )
    
    
    1,254
    
    
    
    1,060
    
    
    
    (73
    )
    
    
    987United Kingdom
    
    
    752
    
    
    
    (231
    )
    
    
    521
    
    
    
    448
    
    
    
    (135
    )
    
    
    313Other Countries
    
    
    316
    
    
    
    (205
    )
    
    
    111
    
    
    
    225
    
    
    
    (98
    )
    
    
    127Total Upstream
    
    
    27,179
    
    
    
    (8,647
    )
    
    
    18,532
    
    
    
    18,994
    
    
    
    (5,338
    )
    
    
    13,656Midstream & Marketing
    
    
    915
    
    
    
    (131
    )
    
    
    784
    
    
    
    541
    
    
    
    (71
    )
    
    
    470Corporate
    
    
    320
    
    
    
    (91
    )
    
    
    229
    
    
    
    191
    
    
    
    (70
    )
    
    
    121$
    28,414
    
    
    $
    (8,869
    )
    
    $
    19,545
    
    
    $
    19,726
    
    
    $
    (5,479
    )
    
    $
    14,247
 * Depreciation, depletion and amortization Included
in Midstream is $97 million (2002  $47 million) related to
cushion gas, required to operate the gas storage facilities, which is not
subject to depletion. Included in the property, plant and equipment cost are asset retirement
costs of $245 million (2002  $175 million). Administrative costs have not
been capitalized as part of the capital expenditures. Upstream costs in respect of significant unproved properties and major
development projects excluded from depletable costs were: For the years ended December 31
    
    2003
    
    2002
    
    2001Canada
    
    $
    1,035
    
    
    $
    562
    
    
    $
    257United States
    
    
    604
    
    
    
    282
    
    
    
    116Ecuador
    
    
    89
    
    
    
    
    
    
    
    United Kingdom
    
    
    175
    
    
    
    112
    
    
    
    Other Countries
    
    
    111
    
    
    
    127
    
    
    
    88$
    2,014
    
    
    $
    1,083
    
    
    $
    461
 F20




---



##### 



The costs excluded from depletable costs in Other Countries represent 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, 2003, the Company completed its impairment review of
pre-production cost centres and determined that $85 million of costs should
be charged to the Consolidated Statement of Earnings (2002  $ nil). The prices used in the ceiling test evaluation of the Companys natural
gas, crude oil and natural gas liquids reserves at December 31, 2003 were: % decrease2004
    
    2005
    
    2006
    
    2007
    
    2008
    
    to 2015Natural Gas ($/mcf)Canada
    
    $
    4.05
    
    
    $
    3.87
    
    
    $
    3.28
    
    
    $
    3.37
    
    
    $
    3.69
    
    
    
    0.4
    %United States
    
    
    4.40
    
    
    
    4.18
    
    
    
    3.41
    
    
    
    3.51
    
    
    
    3.95
    
    
    
    0.4
    %United Kingdom
    
    
    1.76
    
    
    
    1.57
    
    
    
    1.44
    
    
    
    1.44
    
    
    
    1.44
    
    
    
    Crude Oil ($/barrel)Canada
    
    $
    17.41
    
    
    $
    16.03
    
    
    $
    14.42
    
    
    $
    13.86
    
    
    $
    13.67
    
    
    
    1.6
    %Ecuador
    
    
    18.26
    
    
    
    16.18
    
    
    
    14.28
    
    
    
    14.35
    
    
    
    14.36
    
    
    
    United Kingdom
    
    
    26.82
    
    
    
    24.88
    
    
    
    21.01
    
    
    
    20.44
    
    
    
    20.41
    
    
    
    0.1
    %Natural Gas Liquids ($/barrel)Canada
    
    $
    23.25
    
    
    $
    21.40
    
    
    $
    19.10
    
    
    $
    19.09
    
    
    $
    19.20
    
    
    
    0.4
    %United States
    
    
    23.62
    
    
    
    21.84
    
    
    
    19.91
    
    
    
    19.53
    
    
    
    19.36
    
    
    
    0.2
    %United Kingdom
    
    
    20.05
    
    
    
    18.57
    
    
    
    16.83
    
    
    
    16.71
    
    
    
    16.67
    
    
    
    0.2
    %
 NOTE 12 INVESTMENTS AND OTHER ASSETS As at December 31
    
    2003
    
    2002Equity Investments
    
    $
    217
    
    
    $
    62Value Added Tax Recoverable
    
    
    112
    
    
    
    56Marketing Contracts
    
    
    22
    
    
    
    27Deferred Financing Costs
    
    
    31
    
    
    
    28Deferred Pension Costs
    
    
    53
    
    
    
    15Other
    
    
    131
    
    
    
    104$
    566
    
    
    $
    292
 Equity Investments Included in Equity Investments is the following:  i.
    
    Included in Midstream & Marketing is a 36% indirect equity investment in
Oleoducto Transandino (OTA), which owns a crude oil pipeline that ships
crude oil from the producing areas of Argentina to refineries in Chile.ii.
    
    Included in Upstream  Ecuador is a 36% 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 a new export marine terminal.The Company is a shipper on the OCP Pipeline and pays commercial rates for
tariffs. F21




---



##### 



NOTE 13 LONG
 TERM DEBT As at December 31
    
    Note
    
    2003
    
    2002Canadian Dollar Denominated DebtRevolving credit and term loan borrowings
    
    
    B
    
    
    $
    1,425
    
    
    $
    879Unsecured notes and debentures
    
    
    C
    
    
    
    1,335
    
    
    
    1,155Preferred securities
    
    
    D
    
    
    
    252
    
    
    
    2063,012
    
    
    
    2,240U.S. Dollar Denominated DebtRevolving credit and term loan borrowings
    
    
    E
    
    
    
    417
    
    
    
    441U.S. unsecured notes and debentures
    
    
    F
    
    
    
    2,713
    
    
    
    2,284Preferred securities
    
    
    D
    
    
    
    150
    
    
    
    1503,280
    
    
    
    2,875Increase in Value of Debt Acquired
    
    
    G
    
    
    
    83
    
    
    
    70Current Portion of Long-Term Debt
    
    
    H
    
    
    
    (287
    )
    
    
    (134
    )$
    6,088
    
    
    $
    5,051
 A) Overview Revolving credit and term loan borrowings At December 31, 2003, the Company had in place a revolving credit and term
loan facility for $4 billion Canadian dollars or its equivalent amount in
U.S. dollars (US$3 billion). The facility consists of two tranches of C$2
billion (US$1.5 billion) each. One tranche is fully revolving for a 364-day
period with provision for annual extensions at the option of the lenders
and upon notice from the Company. If not extended, this tranche converts to
a non-revolving reducing loan for a term of one year. The second tranche is
fully revolving for a period of three years from the date of the agreement,
December 2002. 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. At December 31, 2003, a subsidiary of the Company had in place a credit
facility totalling $300 million
(C$388 million). The facility is guaranteed by EnCana Corporation and fully
revolving for three years from the date of the Agreement, December 2003.
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. One of the Companys partnerships has a credit agreement, consisting of a
term loan facility, senior secured notes and a levelization account,
relating to the construction of a cogeneration plant. The term loan bears
interest at the prevailing prime lending rate plus 0.25%. The notes bear
interest at the prevailing prime lending rate plus 1.25%. The partnership
also has an option under the credit agreement to use an average Bankers
Acceptance rate plus a margin that will vary during the term. The
levelization account accumulates interest at the yield rate of the most
recent Government of Canada bond issue with a 20-year maturity as of
January 20th each year. The term loan and senior notes are secured by the
project facilities. Revolving credit and term loan borrowings include Bankers Acceptances and
Commercial Paper of $1,749 million (2002  $871 million) maturing at
various dates with a weighted average interest rate of 2.55% and LIBOR
loans of $65 million (C$84 million) with a weighted average interest rate
of 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 2003 relating to revolving credit and term loan
agreements were approximately $3 million (2002  $3 million). 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 ($774
million) unutilized at December 31, 2003. The notes may be denominated in
Canadian dollars or in foreign currencies. The Company has in place a shelf prospectus for U.S. Unsecured Notes in the
amount of US$2.0 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, 2003, US$1.5 billion remains unutilized. F22




---



##### 



B) Canadian revolving credit and term loan borrowings C$ PrincipalAmount
    
    2003
    
    2002Bankers Acceptances
    
    $
    773
    
    
    $
    598
    
    
    $
    276Commercial Paper
    
    
    1,033
    
    
    
    799
    
    
    
    580Cogeneration Facility, matures March 31, 2016
    
    
    36
    
    
    
    28
    
    
    
    23$
    1,842
    
    
    $
    1,425
    
    
    $
    879
 C) Canadian unsecured notes and debentures C$ PrincipalAmount
    
    2003
    
    20028.15% due July 31, 2003
    
    $
    
    
    
    $
    
    
    
    $
    636.60% due on June 30, 2004
    
    
    50
    
    
    
    39
    
    
    
    327.00% due December 1, 2004
    
    
    100
    
    
    
    77
    
    
    
    635.95% due October 1, 2007
    
    
    200
    
    
    
    155
    
    
    
    1275.30% due December 3, 2007
    
    
    300
    
    
    
    232
    
    
    
    1895.95% due June 2, 2008
    
    
    100
    
    
    
    77
    
    
    
    635.80% due June 2, 2008
    
    
    125
    
    
    
    97
    
    
    
    795.80% due June 19, 2008
    
    
    100
    
    
    
    77
    
    
    
    636.10% due June 1, 2009
    
    
    150
    
    
    
    116
    
    
    
    957.15% due December 17, 2009
    
    
    150
    
    
    
    116
    
    
    
    958.50% due March 15, 2011
    
    
    50
    
    
    
    39
    
    
    
    327.10% due October 11, 2011
    
    
    200
    
    
    
    155
    
    
    
    1277.30% due September 2, 2014
    
    
    150
    
    
    
    116
    
    
    
    955.50% / 6.20% due June 23, 2028
    
    
    50
    
    
    
    39
    
    
    
    32$
    1,725
    
    
    $
    1,335
    
    
    $
    1,155
 D) Preferred securities C$ PrincipalAmount
    
    2003
    
    2002Canadian Dollar7.00% due on March 23, 2034
    
    $
    126
    
    
    $
    97
    
    
    $
    808.50% due September 30, 2048
    
    
    200
    
    
    
    155
    
    
    
    126$
    326
    
    
    
    252
    
    
    
    206U.S. Dollar9.50% due September 30, 2048
    
    
    
    
    
    
    150
    
    
    
    150$
    402
    
    
    $
    356
 The preferred securities are unsecured junior subordinated debentures.
Subject to certain conditions, the Company has the right to defer payments
of interest on the securities for up to 20 consecutive quarterly periods.
The Company may satisfy its obligation to pay deferred interest or the
principal amount by delivering sufficient equity securities to the Trustee. On March 23, 1999, the Company issued C$126 million of Coupon Reset
Subordinated Term Securities  Series A due March 23, 2034. Interest is
payable semi-annually at a rate of 7% per annum for the first five years
and is reset at the Five Year Government of Canada Yield plus 2% on each
fifth anniversary of the date of issuance. The securities are redeemable by
the Company, in whole or in part, at any time on or after March 23, 2004,
at par plus accrued and unpaid interest. With respect to these securities,
the Company entered a series of option transactions that result in an
effective floating interest rate equal to three-month Bankers Acceptance
rate plus 104 basis points on C$126 million. On February 4, 2004, the
Company announced its intention to repurchase these securities on March 23,
2004. The 8.50% and the 9.50% preferred securities were acquired in the business
combination with AEC. Interest on these securities is paid quarterly. These
securities are redeemable by the Company, in whole or in part, at any time
on or after August 9, 2004 and September 30, 2004 respectively at par plus
accrued and unpaid interest. F23




---



##### 



E) U.S. revolving credit and term loan borrowings 2003
    
    2002Commercial Paper
    
    $
    352
    
    
    $
    16LIBOR Loan
    
    
    65
    
    
    
    425$
    417
    
    
    $
    441
 F) U.S. unsecured notes and debentures C$ Amount
    
    2003
    
    2002Floating Rate5.50% due on March 17, 2003
    
    
    
    
    
    $
    
    
    
    $
    718.40% due December 15, 2004
    
    
    94
    *
    
    
    73
    
    
    
    738.75% due November 9, 2005
    
    
    94
    *
    
    
    73
    
    
    
    73Fixed Rate8.75% due November 9, 2005
    
    
    94
    *
    
    
    73
    
    
    
    737.50% due August 25, 2006
    
    
    94
    *
    
    
    73
    
    
    
    735.80% due June 2, 2008
    
    
    92
    *
    
    
    71
    
    
    
    717.65% due September 15, 2010
    
    
    
    
    
    
    200
    
    
    
    2006.30% due November 1, 2011
    
    
    
    
    
    
    500
    
    
    
    5004.75% due October 15, 2013
    
    
    
    
    
    
    500
    
    
    
    8.125% due September 15, 2030
    
    
    
    
    
    
    300
    
    
    
    3007.20% due November 1, 2031
    
    
    
    
    
    
    350
    
    
    
    3507.375% due November 1, 2031
    
    
    
    
    
    
    500
    
    
    
    500$
    2,713
    
    
    $
    2,284
  *
    
    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. G) Increase in value of debt acquired Certain of the notes and debentures of the Company were acquired in the
business combination described in Note 3 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 28 years. H) Current portion of long-term debt 2003
    
    20025.50% Medium Term Note due March 17, 2003
    
    $
    
    
    
    $
    718.15% Debenture due July 31, 2003
    
    
    
    
    
    
    637.00% Coupon Reset Subordinated Term Securities due March 23, 2034
    
    
    97
    
    
    
    6.60% Medium Term Note due June 30, 2004
    
    
    39
    
    
    
    7.00% Medium Term Note due December 1, 2004
    
    
    77
    
    
    
    8.40% Medium Term Note due December 15, 2004
    
    
    73
    
    
    
    Cogeneration Facility
    
    
    1
    
    
    
    $
    287
    
    
    $
    134
 I) Mandatory debt payments C$
    
    US$Principal
    
    Principal
    
    Total US$Amount
    
    Amount
    
    Equivalent2004
    
    $
    278
    
    
    $
    73
    
    
    $
    2872005
    
    
    2
    
    
    
    146
    
    
    
    1472006
    
    
    2
    
    
    
    73
    
    
    
    742007
    
    
    503
    
    
    
    
    
    
    
    3892008
    
    
    328
    
    
    
    71
    
    
    
    324Thereafter
    
    
    2,780
    
    
    
    2,917
    
    
    
    5,071Total
    
    $
    3,893
    
    
    $
    3,280
    
    
    $
    6,292
 The amount due in 2004 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. F24




---



##### 



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
    
    2003
    
    2002Asset Retirement Obligation, Beginning of Year
    
    $
    309
    
    
    $
    163Liabilities Incurred
    
    
    64
    
    
    
    146Liabilities Settled
    
    
    (23
    )
    
    
    (13
    )Accretion Expense
    
    
    19
    
    
    
    13Other
    
    
    61
    
    
    
    Asset Retirement Obligation, End of Year
    
    $
    430
    
    
    $
    309
 The total undiscounted amount of estimated cash flows required to settle the
obligation is $3,223 million (2002
   $2,516 million), which has been discounted using a credit-adjusted
risk free rate of 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 the time of removal. 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 2003
    
    2002Number
    
    
    
    
    
    NumberAs at December 31
    
    (millions)
    
    Amount
    
    (millions)
    
    AmountCommon Shares Outstanding, Beginning of Year
    
    
    478.9
    
    
    $
    5,511
    
    
    
    254.9
    
    
    $
    142Shares Issued to AEC Shareholders (Note 3)
    
    
    
    
    
    
    
    
    
    
    218.5
    
    
    
    5,281Shares Issued under Option Plans
    
    
    5.5
    
    
    
    114
    
    
    
    5.5
    
    
    
    88Shares Repurchased
    
    
    (23.8
    )
    
    
    (320
    )
    
    
    
    
    
    
    Common Shares Outstanding, End of Year
    
    
    460.6
    
    
    $
    5,305
    
    
    
    478.9
    
    
    $
    5,511
 Normal Course Issuer Bid Effective October 16, 2002, the Company received approval from the Toronto
Stock Exchange for a Normal Course Issuer Bid. Under the bid, the Company
could purchase for cancellation up to 23,843,565 of its Common Shares,
representing five percent of the 476,871,300 Common Shares outstanding as
at October 4, 2002. 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 may 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. The current Normal Course Issuer
Bid expires on October 21, 2004. In 2003, the Company purchased, for cancellation, 23,839,400 Common Shares
for total consideration of $868 million. Of the $868 million paid, $320
million was charged to share capital, $80 million was charged to paid in
surplus and $468 million was charged to retained earnings. Stock Options The Company 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 plan are generally fully exercisable after three
years and expire five years after the grant date. Options granted under
previous successor and/or related company replacement plans expire 10 years
from the date the options were granted. In conjunction with the business combination transaction 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 outstanding under the EnCana plan, becoming exercisable after the
close of business on April 5, 2002. F25




---



##### 



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. It is the Companys intent that all options issued in 2004 will have
an associated Tandem Share Appreciation Right (TSAR) attached to them. Canadian Pacific Limited Replacement Plan As part of the Canadian Pacific Limited (CPL) reorganization, as
described in Note 18, 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. The following tables summarize the information about options to purchase Common
Shares: 2003
    
    2002Weighted
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    AverageStock
    
    Exercise
    
    Stock
    
    ExerciseOptions
    
    Price
    
    Options
    
    PriceAs at December 31
    
    (millions)
    
    (C$)
    
    (millions)
    
    (C$)Outstanding, Beginning of Year
    
    
    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
    
    
    (5.5
    )
    
    
    29.11
    
    
    
    (5.5
    )
    
    
    25.20Forfeited
    
    
    (1.7
    )
    
    
    41.18
    
    
    
    (0.7
    )
    
    
    43.81Outstanding, End of Year
    
    
    28.8
    
    
    
    43.13
    
    
    
    29.6
    
    
    
    39.74Exercisable, End of Year
    
    
    15.6
    
    
    
    38.92
    
    
    
    17.7
    
    
    
    34.10
 Outstanding Options
    
    Exercisable OptionsWeightedNumber of
    
    Average
    
    Weighted
    
    Number of
    
    WeightedOptions
    
    Remaining
    
    Average
    
    Options
    
    AverageAs at December 31
    
    Outstanding
    
    Contractual
    
    Exercise
    
    Outstanding
    
    ExerciseRange of Exercise Price (C$)
    
    (millions)
    
    Life (years)
    
    Price (C$)
    
    (millions)
    
    Price (C$)13.50 to 19.99
    
    
    1.5
    
    
    
    0.9
    
    
    
    18.86
    
    
    
    1.5
    
    
    
    18.8620.00 to 24.99
    
    
    1.3
    
    
    
    1.5
    
    
    
    22.38
    
    
    
    1.3
    
    
    
    22.3825.00 to 29.99
    
    
    2.2
    
    
    
    1.5
    
    
    
    26.49
    
    
    
    2.2
    
    
    
    26.4930.00 to 43.99
    
    
    1.3
    
    
    
    2.2
    
    
    
    38.89
    
    
    
    1.2
    
    
    
    38.5244.00 to 53.00
    
    
    22.5
    
    
    
    3.7
    
    
    
    47.93
    
    
    
    9.4
    
    
    
    47.6328.8
    
    
    
    2.8
    
    
    
    43.13
    
    
    
    15.6
    
    
    
    38.92
 At December 31, 2003, there were 7.9 million Common Shares reserved for
issuance under stock option plans (2002  12.8 million). F26




---



##### 



As described in Note 2, the Company 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 2003 would have been
$2,326 million; $4.91 per common share  basic; $4.85 per
common share 
diluted (2002  $761 million; $1.82 per common share  basic; $1.80 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
 NOTE 16 COMPENSATION PLANS A) Pensions The most recent actuarial evaluation completed for the Company is dated
December 31, 2003. The Company sponsors both defined benefit and defined contribution plans
providing pension and other retirement and post-employment benefits to
substantially all of its employees. For the years ended December 31
    
    2003
    
    2002
    
    2001Total expense for defined contribution plans
    
    $
    12
    
    
    $
    9
    
    
    $
    6
 Information about defined benefit post-retirement benefit plans, in aggregate,
is as follows: As at December 31
    
    2003
    
    2002Accrued Benefit Obligation, Beginning of Year
    
    $
    167
    
    
    $
    85Plan acquisition
    
    
    
    
    
    
    55Current service cost
    
    
    6
    
    
    
    3Interest cost
    
    
    12
    
    
    
    8Benefits paid
    
    
    (11
    )
    
    
    (5
    )Actuarial loss
    
    
    13
    
    
    
    10Contributions
    
    
    1
    
    
    
    Special termination benefits
    
    
    
    
    
    
    2Changes as a result of curtailment
    
    
    
    
    
    
    1Plan amendments
    
    
    1
    
    
    
    8Foreign exchange
    
    
    39
    
    
    
    Accrued Benefit Obligation, End of Year
    
    $
    228
    
    
    $
    167
 As at December 31
    
    2003
    
    2002Fair Value of Plan Assets, Beginning of Year
    
    $
    117
    
    
    $
    84Plan acquisition
    
    
    
    
    
    
    53Transfers to defined contribution plan
    
    
    
    
    
    
    (6
    )Actual return on plan assets
    
    
    14
    
    
    
    (10
    )Employer contributions
    
    
    51
    
    
    
    1Employees contributions
    
    
    1
    
    
    
    Benefits paid
    
    
    (11
    )
    
    
    (5
    )Foreign exchange
    
    
    31
    
    
    
    Fair Value of Plan Assets, End of Year
    
    $
    203
    
    
    $
    117
 F27




---



##### 



As at December 31
    
    2003
    
    2002Funded
Status  Plan Assets less than Benefit Obligation
    
    $
    (25
    )
    
    $
    (50
    )Amounts Not RecognizedUnamortized Net Actuarial Loss
    
    
    66
    
    
    
    51Unamortized Past Service Cost
    
    
    13
    
    
    
    10Net Transitional Asset
    
    
    (9
    )
    
    
    (9
    )Accrued Benefit Asset
    
    $
    45
    
    
    $
    2
 As at December 31
    
    2003
    
    2002Prepaid Benefit Cost
    
    $
    53
    
    
    $
    15Accrued Benefit Cost
    
    
    (8
    )
    
    
    (13
    )Net Amount Recognized
    
    $
    45
    
    
    $
    2
 Included in the above accrued benefit obligation and fair value of plan
assets at year-end for EnCana Corporation are unfunded benefit obligations
of $14 million related to the Companys other post retirement benefit plan.
At the end of 2002, the Company had unfunded obligations of $34 million
related to three of the Companys defined benefit pension plans and the
other post retirement benefit plans. The weighted average assumptions used to determine benefit obligations are as
follows: As at December 31
    
    2003
    
    2002Discount Rate
    
    
    6.0
    %
    
    
    6.5
    %Rate of Compensation Increase
    
    
    4.75
    %
    
    
    3.5
    %
 The weighted average assumptions used to determine periodic expense are as
follows: For the years ended December 31
    
    2003
    
    2002Discount Rate
    
    
    6.5
    %
    
    
    6.5
    %Expected Long-term Rate of Return on Plan AssetsRegistered pension plans
    
    
    6.75
    %
    
    
    7.0
    %Supplemental pension plans
    
    
    3.375
    %
    
    
    3.5
    %Rate of Compensation Increase
    
    
    4.75
    %
    
    
    3.5
    %
 The periodic expense for benefits is as follows: For the years ended December 31
    
    2003
    
    2002
    
    2001Current Service Cost
    
    $
    6
    
    
    $
    3
    
    
    $
    2Interest Cost
    
    
    12
    
    
    
    8
    
    
    
    5Expected Return on Plan Assets
    
    
    (9
    )
    
    
    (8
    )
    
    
    (6
    )Amortization of Net Actuarial Loss
    
    
    4
    
    
    
    1
    
    
    
    Amortization of Transitional Obligation
    
    
    (2
    )
    
    
    (2
    )
    
    
    (2
    )Amortization of Past Service Cost
    
    
    1
    
    
    
    1
    
    
    
    1Curtailment Loss
    
    
    
    
    
    
    1
    
    
    
    Special Termination Benefits
    
    
    
    
    
    
    2
    
    
    
    Expense for Defined Contribution Plan
    
    
    12
    
    
    
    9
    
    
    
    6Net Benefit Plan Expense
    
    $
    24
    
    
    $
    15
    
    
    $
    6
 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 13 years. F28




---



##### 



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
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
    
    2003Health care cost trend rate for next year
    
    
    10
    %Rate that the trend rate gradually trends to
    
    
    5
    %Year that the trend rate reaches the rate which it is expected to remain at
    
    
    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
    
    OnePercentage
    
    PercentagePoint
    
    PointIncrease
    
    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 AssetsTarget Allocation %
    
    at December 31Expected Long-termAsset Category
    
    Normal
    
    Range
    
    2003
    
    2002
    
    Rate of ReturnDomestic Equity
    
    
    35
    
    
    
    25-45
    
    
    
    35
    
    
    
    32Foreign Equity
    
    
    30
    
    
    
    20-40
    
    
    
    29
    
    
    
    31Bonds
    
    
    30
    
    
    
    20-40
    
    
    
    27
    
    
    
    27Real Estate and Other
    
    
    5
    
    
    
    0-20
    
    
    
    9
    
    
    
    10Total
    
    
    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 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 2004.
Contributions by the participants to the pension and other benefits plans
were $1 million for the year ended December 31, 2003 (2002
 nil).
Estimated future payments for pension and other benefits are as follows: 2004
    
    $
    122005
    
    
    122006
    
    
    132007
    
    
    132008
    
    
    142009  2013
    
    
    84Total
    
    $
    148
 F29




---



##### 



B) Share Appreciation Rights The Company 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: 2003
    
    2002Weighted
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    AverageOutstanding
    
    Exercise
    
    Outstanding
    
    ExerciseAs at December 31
    
    SAR's
    
    Price ($)
    
    SAR's
    
    Price ($)Canadian Dollar Denominated (C$)Outstanding, beginning of year
    
    
    2,284,901
    
    
    
    35.56
    
    
    
    
    
    
    
    Granted
    
    
    
    
    
    
    
    
    
    
    600,000
    
    
    
    38.35Acquired April 5, in AEC acquisition
    
    
    
    
    
    
    
    
    
    
    2,637,421
    
    
    
    30.70Exercised
    
    
    (1,101,987
    )
    
    
    35.17
    
    
    
    (648,902
    )
    
    
    27.67Forfeited
    
    
    (7,844
    )
    
    
    46.28
    
    
    
    (303,618
    )
    
    
    39.08Outstanding, end of year
    
    
    1,175,070
    
    
    
    35.87
    
    
    
    2,284,901
    
    
    
    35.56Exercisable, end of year
    
    
    1,175,070
    
    
    
    35.87
    
    
    
    2,284,901
    
    
    
    35.56U.S. Dollar Denominated (US$)Outstanding, beginning of year
    
    
    1,346,437
    
    
    
    28.52
    
    
    
    
    
    
    
    Acquired April 5, in AEC acquisition
    
    
    
    
    
    
    
    
    
    
    1,711,095
    
    
    
    28.32Exercised
    
    
    (589,340
    )
    
    
    27.91
    
    
    
    (223,703
    )
    
    
    26.33Forfeited
    
    
    (3,680
    )
    
    
    30.73
    
    
    
    (140,955
    )
    
    
    29.88Outstanding, end of year
    
    
    753,417
    
    
    
    28.98
    
    
    
    1,346,437
    
    
    
    28.52Exercisable, end of year
    
    
    753,417
    
    
    
    28.98
    
    
    
    1,346,437
    
    
    
    28.52
 SAR's OutstandingWeightedAverage
    
    WeightedRemaining
    
    AverageAs at December 31, 2003
    
    Number
    
    Contractual
    
    ExerciseRange of Exercise Price ($)
    
    of SAR's
    
    Life (years)
    
    Price ($)Canadian Dollar Denominated (C$)20.00 to 29.99
    
    
    600,656
    
    
    
    1.05
    
    
    
    26.6930.00 to 39.99
    
    
    74,720
    
    
    
    2.82
    
    
    
    38.2240.00 to 49.99
    
    
    486,303
    
    
    
    2.20
    
    
    
    46.3950.00 to 60.00
    
    
    13,391
    
    
    
    2.32
    
    
    
    51.371,175,070
    
    
    
    1.65
    
    
    
    35.87U.S. Dollar Denominated (US$)20.00 to 29.99
    
    
    336,408
    
    
    
    1.75
    
    
    
    27.1030.00 to 40.00
    
    
    417,009
    
    
    
    1.83
    
    
    
    30.49753,417
    
    
    
    1.80
    
    
    
    28.98
 During the year, the Company recorded compensation costs of $12 million related to the outstanding SARs (2002
- $4 million). F30




---



##### 



C) 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 2003 vest over a three
year period. The following table summarizes the information about the DSUs: 2003
    
    2002Average
    
    
    
    
    
    AverageOutstanding
    
    Share Price
    
    Outstanding
    
    Share PriceAs at December 31
    
    DSUs
    
    (C$)
    
    DSUs
    
    (C$)Outstanding, Beginning of Year
    
    
    309,167
    
    
    
    48.69
    
    
    
    
    
    
    
    Acquired April 5, in AEC acquisition
    
    
    
    
    
    
    
    
    
    
    29,631
    
    
    
    47.29Granted, Directors
    
    
    37,149
    
    
    
    48.56
    
    
    
    22,500
    
    
    
    49.75Granted, Senior Executives
    
    
    1,976
    
    
    
    49.91
    
    
    
    260,000
    
    
    
    49.75Exercised
    
    
    (29,042
    )
    
    
    48.04
    
    
    
    (2,964
    )
    
    
    48.00Outstanding, End of Year
    
    
    319,250
    
    
    
    48.68
    
    
    
    309,167
    
    
    
    48.69Exercisable, End of Year
    
    
    80,645
    
    
    
    48.68
    
    
    
    49,167
    
    
    
    48.20
 During the year, the Company recorded compensation costs of $4 million related to the outstanding DSUs (2002
 $4 million). D) Performance Share Units During 2003, the Company put in place a program whereby certain employees
may be granted Performance Share Units (PSUs) which entitle the employee
to receive a cash payment, upon vesting, equal to the value of one Common
Share of the Company. Each PSU vests at the end of a three year period.
Their ultimate value will depend upon EnCanas performance measured over the
three year period. Performance will be measured by total stock price change
plus dividends relative to a fixed North American oil and gas comparison
group. If EnCanas performance is below the median of the comparison group,
the units awarded will be forfeited. If EnCanas performance is at or above
the median of 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 the market price of an equivalent number of EnCana Common Shares. The following table summarizes the information about the PSUs: AverageOutstanding
    
    Share PriceAs at December 31, 2003
    
    PSUs
    
    (C$)Outstanding, Beginning of Year
    
    
    
    
    
    
    Granted
    
    
    128,893
    
    
    
    46.52Exercised
    
    
    
    
    
    
    Forfeited
    
    
    (2,610
    )
    
    
    46.52Outstanding, End of Year
    
    
    126,283
    
    
    
    46.52Exercisable, End of Year
    
    
    
    
    
    
    
 During the year, the Company recorded compensation costs of $1 million
related to the outstanding PSUs (2002  $nil). F31




---



##### 



NOTE 17 FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Unrecognized gains (losses) on risk management activities were as follows: As at December 31
    
    Note
    
    2003
    
    2002Commodity Price Risk
    
    
    ACrude oil
    
    
    
    
    
    $
    (279
    )
    
    $
    (77
    )Natural gas
    
    
    
    
    
    
    57
    
    
    
    191Gas storage optimization
    
    
    
    
    
    
    (25
    )
    
    
    (27
    )Natural gas liquids
    
    
    
    
    
    
    
    
    
    
    (2
    )Power
    
    
    
    
    
    
    4
    
    
    
    (2
    )Foreign Currency Risk
    
    
    B
    
    
    
    7
    
    
    
    (57
    )Interest Rate Risk
    
    
    C
    
    
    
    44
    
    
    
    39$
    (192
    )
    
    $
    65
 A) Commodity Price Risk Crude Oil As at December 31, 2003, the Companys oil risk management activities had
an unrecognized loss of $279 million. The contracts were as follows: NotionalVolumes
    
    
    
    
    
    Average Price
    
    Unrecognized(bbls/d)
    
    Term
    
    (US$/bbl)
    
    Gain/(Loss)Fixed WTI NYMEX Price
    
    
    62,500
    
    
    
    2004
    
    
    
    23.13
    
    
    $
    (162
    )Collars on WTI NYMEX
    
    
    62,500
    
    
    
    2004
    
    
    
    20.00-25.69
    
    
    
    (115
    )3-way Put Spread
    
    
    10,000
    
    
    
    2005
    
    
    
    20.00/25.00/28.77
    
    
    
    (3
    )(280
    )Crude Oil
Marketing Financial Positions(1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2
    )Crude Oil Marketing Physical Positions(1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3$
    (279
    )
  (1)
    
    The crude oil marketing activities are part of the daily ongoing operations
of the Companys proprietary production management. F32




---



##### 



Natural Gas At December 31, 2003, the gas risk management activities had an
unrecognized gain of $57 million. The contracts were as follows: NotionalVolumes
    
    Physical/
    
    
    
    
    
    
    
    
    
    
    
    Unrecognized(MMcf/d)
    
    Financial
    
    Term
    
    Price
    
    
    
    Gain/(Loss)Fixed Price ContractsSales ContractsFixed AECO price
    
    
    453
    
    
    Financial
    
    
    2004
    
    
    
    6.20
    
    
    C$/mcf
    
    $
    5NYMEX Fixed price
    
    
    732
    
    
    Financial
    
    
    2004
    
    
    
    5.13
    
    
    US$/mcf
    
    
    (86
    )Chicago Fixed price
    
    
    40
    
    
    Financial
    
    
    2004
    
    
    
    5.41
    
    
    US$/mcf
    
    
    (1
    )AECO Collars
    
    
    71
    
    
    Financial
    
    
    2004
    
    
    
    5.34-7.52
    
    
    C$/mcf
    
    
    2NYMEX Collars
    
    
    50
    
    
    Physical
    
    
    2004
    
    
    
    2.46-4.90
    
    
    US$/mcf
    
    
    (16
    )NYMEX Collars
    
    
    50
    
    
    Physical
    
    
    2005
    
    
    
    2.46-4.90
    
    
    US$/mcf
    
    
    (13
    )NYMEX Collars
    
    
    46
    
    
    Physical
    
    
    2006-2007
    
    
    
    2.46-4.90
    
    
    US$/mcf
    
    
    (20
    )Basis ContractsSales ContractsFixed NYMEX to AECO basis
    
    
    343
    
    
    Financial
    
    
    2004
    
    
    
    (0.54
    )
    
    US$/mcf
    
    
    22Fixed NYMEX to Rockies basis
    
    
    255
    
    
    Financial
    
    
    2004
    
    
    
    (0.48
    )
    
    US$/mcf
    
    
    18Fixed NYMEX to Rockies basis
    
    
    413
    
    
    Physical
    
    
    2004
    
    
    
    (0.50
    )
    
    US$/mcf
    
    
    26Fixed NYMEX to San Juan basis
    
    
    60
    
    
    Financial
    
    
    2004
    
    
    
    (0.63
    )
    
    US$/mcf
    
    
    1Fixed NYMEX to San Juan basis
    
    
    50
    
    
    Physical
    
    
    2004
    
    
    
    (0.64
    )
    
    US$/mcf
    
    
    1Fixed NYMEX to CIG basis
    
    
    38
    
    
    Financial
    
    
    2004
    
    
    
    (0.10
    )
    
    US$/mcf
    
    
    Fixed NYMEX to AECO basis
    
    
    877
    
    
    Financial
    
    
    2005
    
    
    
    (0.66
    )
    
    US$/mcf
    
    
    6Fixed NYMEX to Rockies basis
    
    
    283
    
    
    Financial
    
    
    2005
    
    
    
    (0.49
    )
    
    US$/mcf
    
    
    16Fixed NYMEX to Rockies basis
    
    
    393
    
    
    Physical
    
    
    2005
    
    
    
    (0.47
    )
    
    US$/mcf
    
    
    26Fixed NYMEX to San Juan basis
    
    
    75
    
    
    Financial
    
    
    2005
    
    
    
    (0.63
    )
    
    US$/mcf
    
    
    (1
    )Fixed NYMEX to San Juan basis
    
    
    50
    
    
    Physical
    
    
    2005
    
    
    
    (0.64
    )
    
    US$/mcf
    
    
    (1
    )Fixed NYMEX to CIG basis
    
    
    50
    
    
    Financial
    
    
    2005
    
    
    
    (0.10
    )
    
    US$/mcf
    
    
    1Fixed NYMEX to AECO basis
    
    
    402
    
    
    Financial
    
    
    2006-2008
    
    
    
    (0.65
    )
    
    US$/mcf
    
    
    24Fixed NYMEX to Rockies basis
    
    
    175
    
    
    Financial
    
    
    2006-2008
    
    
    
    (0.57
    )
    
    US$/mcf
    
    
    13Fixed NYMEX to Rockies basis
    
    
    207
    
    
    Physical
    
    
    2006-2007
    
    
    
    (0.49
    )
    
    US$/mcf
    
    
    22Fixed NYMEX to San Juan basis
    
    
    62
    
    
    Financial
    
    
    2006
    
    
    
    (0.62
    )
    
    US$/mcf
    
    
    (1
    )Fixed NYMEX to San Juan basis
    
    
    42
    
    
    Physical
    
    
    2006
    
    
    
    (0.64
    )
    
    US$/mcf
    
    
    (1
    )Fixed NYMEX to CIG basis
    
    
    31
    
    
    Financial
    
    
    2006-2007
    
    
    
    (0.10
    )
    
    US$/mcf
    
    
    Purchase ContractsFixed NYMEX to AECO basis
    
    
    47
    
    
    Financial
    
    
    2004
    
    
    
    (0.80
    )
    
    US$/mcf
    
    
    (3
    )40Gas Marketing Financial Positions(1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2
    )Gas Marketing Physical Positions(1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19$
    57
  (1)
    
    The gas marketing activities are part of the daily ongoing operations of
the Companys proprietary production management. Gas Storage Optimization As part of the Companys gas storage optimization program, the Company has
entered into financial instruments at various locations and terms over the
next nine months to manage the price volatility of the corresponding
physical transactions and inventories. F33




---



##### 



As at December 31, 2003, the unrecognized loss on gas storage optimization
risk management activities was $25 million, which was as follows: NotionalVolumes
    
    Price
    
    Unrecognized(bcf)
    
    (US$/mcf)
    
    Gain/(Loss)Financial InstrumentsPurchases
    
    
    286.7
    
    
    
    5.63
    
    
    $
    109Sales
    
    
    312.4
    
    
    
    5.69
    
    
    
    (132
    )(23
    )Physical Contracts
    
    
    
    
    
    
    
    
    
    
    (2
    )$
    (25
    )
 At December 31, 2003, the unrecognized loss on physical contracts of $2
million was more than offset by unrealized gains on physical inventory in
storage. Power As part of the business combination with AEC, the Company acquired two
electricity contracts, one expiring in 2003 and the other in 2005. These
contracts were originally entered into as part of an electricity cost
management strategy. At December 31, 2003, the unrecognized gain on the
remaining contract was $4 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. The following forward foreign currency exchange contracts were in place to
hedge future commodity revenue streams as at December 31, 2003: AverageAmount
    
    ExchangeHedged
    
    Rate
    
    Unrecognized(US$)
    
    (C$/US$)
    
    Gain2004
    
    $
    88
    
    
    
    0.715
    
    
    $
    7
 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. The unrecognized gains on the outstanding financial instruments as at December
31, 2003 were: UnrecognizedGain5.80% Medium Term Notes
    
    $
    127.50% Medium Term Notes
    
    
    98.40% Medium Term Notes
    
    
    68.75% Debenture
    
    
    17$
    44
 At December 31, 2003, the increase or decrease in net earnings for each one
percent change in interest rates on floating rate debt amounts to $22
million (2002  $16 million). D) Fair Value of Financial Assets and Liabilities The fair values of financial instruments 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. F34




---



##### 



2003
    

2002Carrying
    
    Fair
    
    Carrying
    
    FairAs at December 31
    
    Amount
    
    Value
    
    Amount
    
    ValueFinancial AssetsCash and cash equivalents
    
    $
    148
    
    
    $
    148
    
    
    $
    116
    
    
    $
    116Accounts receivable
    
    
    1,367
    
    
    
    1,367
    
    
    
    1,258
    
    
    
    1,258Financial LiabilitiesAccounts payable, income taxes payable
    
    $
    1,644
    
    
    $
    1,644
    
    
    $
    1,458
    
    
    $
    1,458Long-term debt
    
    
    6,375
    
    
    
    6,767
    
    
    
    5,185
    
    
    
    5,461
 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. The majority of the proceeds from the sale of the Companys crude oil
production in Ecuador are received from one marketing company. Accounts
receivable on these sales are supported by letters of credit issued by a
major international financial institution. All foreign currency agreements
are with major financial institutions in Canada and the United States or
with counterparties having investment grade credit ratings. NOTE 18 SUPPLEMENTARY INFORMATION A) Per Share Amounts The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share. For the years ended December 31
    
    2003
    
    2002
    
    2001Weighted
Average Common Shares Outstanding  Basic
    
    
    474.1
    
    
    
    417.8
    
    
    
    255.6Effect of Stock Options and Other Dilutive Securities
    
    
    5.6
    
    
    
    4.8
    
    
    
    3.2Weighted
Average Common Shares Outstanding  Diluted
    
    
    479.7
    
    
    
    422.6
    
    
    
    258.8
 B) Net Change in Non-Cash Working Capital from Continuing Operations For the years ended December 31
    
    2003
    
    2002
    
    2001Operating ActivitiesAccounts receivable and accrued revenues
    
    $
    232
    
    
    $
    (253
    )
    
    $
    (8
    )Inventories
    
    
    (241
    )
    
    
    (56
    )
    
    
    19Accounts payable and accrued liabilities
    
    
    (118
    )
    
    
    (10
    )
    
    
    32Income taxes payable
    
    
    46
    
    
    
    (534
    )
    
    
    307$
    (81
    )
    
    $
    (853
    )
    
    $
    350Investing ActivitiesAccounts payable and accrued liabilities
    
    $
    (83
    )
    
    $
    186
    
    
    $
    55Financing ActivitiesAccounts payable and accrued liabilities
    
    $
    2
    
    
    $
    (7
    )
    
    $
    1
 C) Supplementary Cash Flow Information For the years ended December 31
    
    2003
    
    2002
    
    2001Interest Paid
    
    $
    288
    
    
    $
    265
    
    
    $
    47Income Taxes (Received) Paid
    
    $
    (195
    )
    
    $
    646
    
    
    $
    22
 F35




---



##### 



D) Corporate Reorganization of Canadian Pacific Limited On February 13, 2001, CPL announced a reorganization whereby its 85%
interest in PanCanadian Petroleum Limited (predecessor to PanCanadian
Energy Corporation) would be distributed to CPL common shareholders by a
Plan of Arrangement. Following shareholder and court approvals, the Plan of
Arrangement was implemented on October 1, 2001, and PanCanadian Petroleum
Limited became a wholly owned subsidiary of the new public company,
PanCanadian Energy Corporation. Effective January 1, 2002, these companies
were amalgamated and continued under the name of PanCanadian Energy
Corporation. As part of the CPL reorganization, the Company paid a Special Dividend of
C$1,180 million ($754 million), or C$4.60 per Common Share ($2.94 per
Common Share), on September 14, 2001. The amounts shown as dividends on the
Consolidated Statements of Retained Earnings and Cash Flows include both
the Special Dividend and the regular quarterly dividend. E) Related Party Transactions In 2001, the Company paid C$50 million ($33 million) relating to a
previously contracted purchase price adjustment in respect of C$200 million
of capital losses acquired in 1997 from a subsidiary of CPL (the majority
shareholder of the Company prior to the corporate reorganization as
described previously). The purchase price adjustment, which was contingent
on certain economic events, has been recorded as a charge to retained
earnings. Prior to the previously described corporate reorganization of CPL, the
Company purchased materials and utilized services from other companies with
which it was affiliated. All such transactions were conducted on an arms
length basis and were not material in relation to the Companys overall
activities. NOTE 19 COMMITMENTS AND CONTINGENCIES Commitments As at December 31, 2003
    
    2004
    
    2005
    
    2006
    
    2007
    
    2008
    
    Thereafter
    
    TotalPipeline Transportation
    
    $
    449
    
    
    $
    383
    
    
    $
    334
    
    
    $
    314
    
    
    $
    313
    
    
    $
    2,116
    
    
    $
    3,909Purchases of Goods
and Services
    
    
    297
    
    
    
    149
    
    
    
    76
    
    
    
    12
    
    
    
    2
    
    
    
    
    
    
    
    536Product Purchases
    
    
    142
    
    
    
    47
    
    
    
    32
    
    
    
    25
    
    
    
    24
    
    
    
    157
    
    
    
    427Operating Leases
    
    
    44
    
    
    
    43
    
    
    
    42
    
    
    
    40
    
    
    
    34
    
    
    
    211
    
    
    
    414Capital Commitments
    
    
    259
    
    
    
    27
    
    
    
    16
    
    
    
    
    
    
    
    
    
    
    
    38
    
    
    
    340Total
    
    $
    1,191
    
    
    $
    649
    
    
    $
    500
    
    
    $
    391
    
    
    $
    373
    
    
    $
    2,522
    
    
    $
    5,626Product Sales
    
    $
    502
    
    
    $
    113
    
    
    $
    69
    
    
    $
    62
    
    
    $
    65
    
    
    $
    359
    
    
    $
    1,170
 In addition to the above, the Company has made commitments related to its risk
management program (see Note 17). 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 business combination transaction 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. Several 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 the New York lawsuits were consolidated in New York District
Court by the plaintiffs application. 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 F36




---



##### 



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. The Gallo complaint claims damages in excess of $30 million,
before potential trebling under California laws. 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. Other 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 $430 million based
on current legislation and estimated costs. Actual costs may differ from
those estimated due to changes in legislation and changes in costs. 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
    
    2003
    
    2002
    
    2001Net Earnings  Canadian GAAP
    
    
    
    
    
    $
    2,360
    
    
    $
    812
    
    
    $
    854Less:Net Earnings from Discontinued Operations  Canadian GAAP
    
    
    
    
    
    
    193
    
    
    
    77
    
    
    
    22Net Earnings from Continuing Operations  Canadian GAAP
    
    
    
    
    
    
    2,167
    
    
    
    735
    
    
    
    832Increase (Decrease) under U.S. GAAP:Revenues, net of royalties
    
    
    B
    
    
    
    (205
    )
    
    
    (174
    )
    
    
    99Depreciation, depletion and amortization
    
    
    A,G
    
    
    
    14
    
    
    
    (41
    )
    
    
    (37
    )Accretion of asset retirement obligation
    
    
    G
    
    
    
    
    
    
    
    13
    
    
    
    8Additional depletion
    
    
    A
    
    
    
    
    
    
    
    
    
    
    
    (94
    )Interest expense, net
    
    
    B
    
    
    
    70
    
    
    
    126
    
    
    
    (11
    )Stock-based compensation
    
    
    C
    
    
    
    (1
    )
    
    
    (3
    )
    
    
    (10
    )Income taxes
    
    
    E,G
    
    
    
    45
    
    
    
    21
    
    
    
    6Net Earnings from Continuing Operations  U.S. GAAP
    
    
    
    
    
    
    2,090
    
    
    
    677
    
    
    
    793Net Earnings from Discontinued Operations  U.S. GAAP
    
    
    
    
    
    
    193
    
    
    
    77
    
    
    
    22Net Earnings before change in accounting policy  U.S. GAAP
    
    
    
    
    
    
    2,283
    
    
    
    754
    
    
    
    815Cumulative effect of change in accounting policy, net of income tax
    
    
    G
    
    
    
    66
    
    
    
    
    
    
    
    Net Earnings  U.S. GAAP
    
    
    
    
    
    $
    2,349
    
    
    $
    754
    
    
    $
    815Net Earnings per Common Share before change in accounting
policy  U.S. GAAPBasic
    
    
    
    
    
    $
    4.82
    
    
    $
    1.81
    
    
    $
    3.19Diluted
    
    
    
    
    
    $
    4.76
    
    
    $
    1.78
    
    
    $
    3.15Net Earnings per Common Share including cumulative effect of
change in accounting policy  U.S. GAAPBasic
    
    
    
    
    
    $
    4.95
    
    
    $
    1.81
    
    
    $
    3.19Diluted
    
    
    
    
    
    $
    4.90
    
    
    $
    1.78
    
    
    $
    3.15
 F37




---



##### 



Consolidated Statement of
Earnings  U.S. GAAP For the years ended December 31
    
    Note
    
    2003
    
    2002
    
    2001Revenues, Net of Royalties
    
    
    B
    
    
    $
    10,011
    
    
    $
    6,102
    
    
    $
    3,343ExpensesProduction and mineral taxes
    
    
    
    
    
    
    189
    
    
    
    119
    
    
    
    77Transportation and selling
    
    
    
    
    
    
    545
    
    
    
    364
    
    
    
    111Operating
    
    
    
    
    
    
    1,297
    
    
    
    813
    
    
    
    448Purchased product
    
    
    
    
    
    
    3,455
    
    
    
    2,200
    
    
    
    739Depreciation, depletion and amortization
    
    
    A,G
    
    
    
    2,208
    
    
    
    1,345
    
    
    
    641Administrative
    
    
    C
    
    
    
    174
    
    
    
    122
    
    
    
    64Interest, net
    
    
    B
    
    
    
    217
    
    
    
    164
    
    
    
    45Accretion of asset retirement obligation
    
    
    G
    
    
    
    19
    
    
    
    
    
    
    
    Foreign exchange (gain) loss
    
    
    
    
    
    
    (601
    )
    
    
    (14
    )
    
    
    12Stock-based compensation
    
    
    
    
    
    
    18
    
    
    
    
    
    
    
    Gain on corporate disposition
    
    
    
    
    
    
    
    
    
    
    (33
    )
    
    
    Net Earnings Before Income Tax
    
    
    
    
    
    
    2,490
    
    
    
    1,022
    
    
    
    1,206Income tax expense
    
    
    E
    
    
    
    400
    
    
    
    345
    
    
    
    413Net Earnings
from Continuing Operations  U.S. GAAP
    
    
    
    
    
    
    2,090
    
    
    
    677
    
    
    
    793Net Earnings
from Discontinued Operations  U.S. GAAP
    
    
    
    
    
    
    193
    
    
    
    77
    
    
    
    22Net Earnings
before change in accounting policy  U.S. GAAP
    
    
    
    
    
    $
    2,283
    
    
    $
    754
    
    
    $
    815Cumulative effect of change in accounting policy, net of tax
    
    
    G
    
    
    
    66
    
    
    
    
    
    
    
    Net Earnings
 U.S. GAAP
    
    
    
    
    
    $
    2,349
    
    
    $
    754
    
    
    $
    815Net Earnings from Continuing Operations per Common Share
- U.S. GAAPBasic
    
    
    
    
    
    $
    4.41
    
    
    $
    1.62
    
    
    $
    3.10Diluted
    
    
    
    
    
    $
    4.36
    
    
    $
    1.60
    
    
    $
    3.06Net Earnings per Common Share before change in accounting
policy  U.S. GAAPBasic
    
    
    
    
    
    $
    4.82
    
    
    $
    1.81
    
    
    $
    3.19Diluted
    
    
    
    
    
    $
    4.76
    
    
    $
    1.78
    
    
    $
    3.15Net Earnings per Common Share including cumulative effect of
change in accounting policy  U.S. GAAPBasic
    
    
    
    
    
    $
    4.95
    
    
    $
    1.81
    
    
    $
    3.19Diluted
    
    
    
    
    
    $
    4.90
    
    
    $
    1.78
    
    
    $
    3.15
 Statement of Other Comprehensive Income For the years ended December 31
    
    Note
    
    2003
    
    2002
    
    2001Net Earnings
 U.S. GAAP
    
    
    
    
    
    $
    2,349
    
    
    $
    754
    
    
    $
    815Adoption of FAS 133, net of tax
    
    
    B,F
    
    
    
    
    
    
    
    
    
    
    
    (53
    )Change in Fair Value of Financial Instruments
    
    
    B,F
    
    
    
    4
    
    
    
    (7
    )
    
    
    49Foreign Currency Translation Adjustment
    
    
    D
    
    
    
    1,046
    
    
    
    136
    
    
    
    (210
    )Other
    
    
    
    
    
    
    6
    
    
    
    (6
    )
    
    
    Other Comprehensive Income
    
    
    
    
    
    $
    3,405
    
    
    $
    877
    
    
    $
    601
 F38




---



##### 



Condensed Consolidated Balance Sheet 2003
    
    2002As
    
    U.S.
    
    As
    
    U.S.As at December 31
    
    Note
    
    Reported
    
    GAAP
    
    Reported
    
    GAAPAssetsCurrent Assets
    
    
    
    
    
    $
    2,088
    
    
    $
    2,088
    
    
    $
    3,810
    
    
    $
    3,821Financial Assets
    
    
    B
    
    
    
    
    
    
    
    145
    
    
    
    
    
    
    
    127Property, Plant and Equipment, net
    
    
    A,G
    
    
    
    19,545
    
    
    
    19,419
    
    
    
    14,247
    
    
    
    14,038Investments and Other Assets
    
    
    B
    
    
    
    566
    
    
    
    569
    
    
    
    292
    
    
    
    299Goodwill
    
    
    
    
    
    
    1,911
    
    
    
    1,911
    
    
    
    1,563
    
    
    
    1,563$
    24,110
    
    
    $
    24,132
    
    
    $
    19,912
    
    
    $
    19,848Liabilities and Shareholders EquityCurrent Liabilities
    
    
    
    
    
    $
    1,931
    
    
    $
    1,931
    
    
    $
    2,692
    
    
    $
    2,705Financial Liabilities
    
    
    B
    
    
    
    
    
    
    
    380
    
    
    
    
    
    
    
    208Long-Term Debt
    
    
    
    
    
    
    6,088
    
    
    
    6,088
    
    
    
    5,051
    
    
    
    5,051Other Liabilities
    
    
    B
    
    
    
    21
    
    
    
    8
    
    
    
    54
    
    
    
    53Asset Retirement Obligation
    
    
    G
    
    
    
    430
    
    
    
    430
    
    
    
    309
    
    
    
    303Future Income Taxes
    
    
    E,G
    
    
    
    4,362
    
    
    
    4,223
    
    
    
    3,088
    
    
    
    2,99112,832
    
    
    
    13,060
    
    
    
    11,194
    
    
    
    11,311Share Capital
    
    
    C
    
    
    
    5,305
    
    
    
    5,318
    
    
    
    5,511
    
    
    
    5,524Share Options, net
    
    
    
    
    
    
    55
    
    
    
    55
    
    
    
    84
    
    
    
    84Paid in Surplus
    
    
    
    
    
    
    18
    
    
    
    18
    
    
    
    51
    
    
    
    51Retained Earnings
    
    
    
    
    
    
    5,276
    
    
    
    5,076
    
    
    
    3,523
    
    
    
    3,325Foreign Currency Translation Adjustment
    
    
    D
    
    
    
    624
    
    
    
    
    
    
    
    (451
    )
    
    
    Accumulated Other Comprehensive Income
    
    
    
    
    
    
    
    
    
    
    605
    
    
    
    
    
    
    
    (447
    )11,278
    
    
    
    11,072
    
    
    
    8,718
    
    
    
    8,537$
    24,110
    
    
    $
    24,132
    
    
    $
    19,912
    
    
    $
    19,848
 Condensed Consolidated
Statement of Cash Flows  U.S. GAAP For the years ended December 31
    
    2003
    
    2002
    
    2001Cash From Operating ActivitiesNet earnings from continuing operations
    
    $
    2,090
    
    
    $
    677
    
    
    $
    793Depreciation, depletion and amortization
    
    
    2,208
    
    
    
    1,345
    
    
    
    641Future income taxes
    
    
    456
    
    
    
    383
    
    
    
    89Accretion of asset retirement obligation
    
    
    19
    
    
    
    
    
    
    
    Foreign exchange (gain) loss
    
    
    (545
    )
    
    
    (23
    )
    
    
    35Unrealized loss (gain) on risk management contracts
    
    
    135
    
    
    
    48
    
    
    
    (88
    )Other
    
    
    57
    
    
    
    (163
    )
    
    
    (7
    )Cash flow from continuing operations
    
    
    4,420
    
    
    
    2,267
    
    
    
    1,463Cash flow from discontinued operations
    
    
    39
    
    
    
    152
    
    
    
    31Cash Flow
    
    
    4,459
    
    
    
    2,419
    
    
    
    1,494Net change in other assets and liabilities
    
    
    (84
    )
    
    
    (17
    )
    
    
    (40
    )Net change in non-cash working capital from continuing operations
    
    
    (81
    )
    
    
    (853
    )
    
    
    350Net change in non-cash working capital from discontinued operations
    
    
    17
    
    
    
    64
    
    
    
    (29
    )$
    4,311
    
    
    $
    1,613
    
    
    $
    1,775Cash Used in Investing Activities
    
    $
    (3,729
    )
    
    $
    (2,595
    )
    
    $
    (1,092
    )Cash (Used in) From Financing Activities
    
    $
    (540
    )
    
    $
    491
    
    
    $
    (214
    )
 F39




---



##### 



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 respect. 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%, 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
escalated pricing to determine whether impairment exists. However, the
impaired amount is measured using the fair value of 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. B) Derivative Instruments and Hedging 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 on 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
    
    2003
    
    2002
    
    2001Commodity Prices (Revenues, net of royalties)
    
    $
    (205
    )
    
    $
    (174
    )
    
    $
    99Interest and Currency Swaps (Interest, net)
    
    
    70
    
    
    
    126
    
    
    
    (11
    )Total Unrealized (Loss) Gain
    
    $
    (135
    )
    
    $
    (48
    )
    
    $
    88
 The adoption of FAS 133 at January 1, 2001 resulted in recognition of
derivative assets with a fair value of $572 million, derivative liabilities
with a fair value of $628 million, a $78 million ($53 million, net of tax)
charge to other comprehensive income and a $22 million ($15 million, net of
tax) increase to net earnings under U.S. GAAP. As at December 31, 2003, it is estimated that over the following 12 months,
$4 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
financials, which would be the same adjustment under U.S. GAAP, see Note
15. Under 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, as described in Note 18, an equity restructuring occurred
which resulted in CPL stock options being replaced with stock options
granted by PanCanadian 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. 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. F40




---



##### 



The following table provides a reconciliation of the statutory rate to the
actual tax rate: For the years ended December 31
    
    2003
    
    2002
    
    2001Using Canadian GAAPNet earnings before income tax
    
    $
    2,612
    
    
    $
    1,101
    
    
    $
    1,251Canadian Statutory Rate
    
    
    40.95
    %
    
    
    42.3
    %
    
    
    42.8
    %Expected Income Tax
    
    $
    1,070
    
    
    $
    467
    
    
    $
    536Effect on Taxes Resulting from:Non-deductible Canadian crown payments
    
    
    231
    
    
    
    147
    
    
    
    74Canadian resource allowance
    
    
    (258
    )
    
    
    (200
    )
    
    
    (167
    )Large corporations tax
    
    
    27
    
    
    
    23
    
    
    
    9Statutory rate differences
    
    
    (50
    )
    
    
    (36
    )
    
    
    (12
    )Effect of tax rate changes
    
    
    (359
    )
    
    
    (20
    )
    
    
    (53
    )Non-taxable capital gains
    
    
    (119
    )
    
    
    (9
    )
    
    
    Previously unrecognized capital losses
    
    
    (119
    )
    
    
    
    
    
    
    Other
    
    
    22
    
    
    
    (6
    )
    
    
    32445
    
    
    
    366
    
    
    
    419U.S. GAAP Adjustments to Net Earnings Before Income Tax
    
    
    (122
    )
    
    
    (79
    )
    
    
    (45
    )Expected Income Tax
    
    
    (50
    )
    
    
    (33
    )
    
    
    (19
    )Depletion
    
    
    
    
    
    
    
    
    
    
    2Other
    
    
    5
    
    
    
    12
    
    
    
    11(45
    )
    
    
    (21
    )
    
    
    (6
    )Income Tax
 U.S. GAAP
    
    $
    400
    
    
    $
    345
    
    
    $
    413Effective Tax Rate
    
    
    16.1
    %
    
    
    33.8
    %
    
    
    34.2
    %
 The net deferred income tax liability is comprised of: As at December 31
    
    2003
    
    2002Future Tax Liabilities
Property, plant and equipment in excess of tax values
    
    $
    3,416
    
    
    $
    2,714Timing of partnership items
    
    
    1,162
    
    
    
    513Future Tax AssetsNet operating losses carried forward
    
    
    (174
    )
    
    
    (203
    )Other
    
    
    (181
    )
    
    
    (33
    )Net Future Income Tax Liability
    
    $
    4,223
    
    
    $
    2,991
 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, 2003, accumulated
other comprehensive income related to these items was a loss of $9 million,
net of tax. G) Asset Retirement Obligation 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 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. F41




---



##### 



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: As
    
    
    
    
    
    AsAs at and for the years ended December 31
    
    Reported
    
    Change
    
    Restated2002 Consolidated Balance SheetAssetsCurrent assets
    
    $
    3,821
    
    
    $
    (11
    )
    
    $
    3,810Property, plant and equipment, net
    
    
    14,038
    
    
    
    94
    
    
    
    14,132LiabilitiesCurrent liabilities
    
    $
    2,705
    
    
    $
    (13
    )
    
    $
    2,692Other liabilities & asset retirement obligation
    
    
    356
    
    
    
    6
    
    
    
    362Future income taxes
    
    
    2,991
    
    
    
    23
    
    
    
    3,014Shareholders EquityRetained earnings
    
    $
    3,325
    
    
    $
    66
    
    
    $
    3,391Foreign currency translation adjustment
    
    
    (447
    )
    
    
    1
    
    
    
    (446
    )2002 Consolidated Statement of EarningsNet Earnings
    
    $
    754
    
    
    $
    34
    
    
    $
    788Net Earnings
per Common Share  Diluted
    
    $
    1.78
    
    
    $
    0.08
    
    
    $
    1.862001 Consolidated Statement of EarningsNet Earnings
    
    $
    815
    
    
    $
    22
    
    
    $
    837Net Earnings
per Common Share  Diluted
    
    $
    3.15
    
    
    $
    0.08
    
    
    $
    3.23
 H) Recent Accounting Pronouncements During 2003, the following new standard was issued: Variable Interest Entities In December 2003, the Financial Accounting Standards Board (FASB) in the
United States issued Interpretation Number 46R Consolidation of Variable
Interest Entities, an interpretation of Accounting Research Bulletin No.
51. The standard mandates that variable interest entities be consolidated
by their primary beneficiary. The standard is effective the first reporting
period ending after March 15, 2004 for all entities with the exception of
special purpose entities as defined in prior accounting guidance. The
standard is effective for the first period ending after December 15, 2003
for previously defined special purpose entities. In Canada, the Accounting
Standards Board (AcSB) has suspended the effective dates for Accounting
Guideline AcG15, Consolidation of Variable Interest Entities in order to
amend the guideline to harmonize with the corresponding U.S. guidance. The
AcSB plans to issue an exposure draft in the immediate future with an
effective period beginning on or after November 1, 2004. At December 31, 2003, the Company did not have any variable interest in
variable-interest entities. F42




---



##### 



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, 2003, 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
recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms.
|   
|    |  | 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, 2003, 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).

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).

40-F2



---



##### 



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 following table provides information about the fees billed to the
registrant for professional services rendered by PricewaterhouseCoopers LLP
during fiscal 2003 and 2002:

|                   |  |      |       |      |  |   |       | 
|------------------ |  | ---- | ----- | ---- |  | - | ----- | 
|(US$ thousands)    |  | 2003 |       | 2002
|                   |  |      |       |     
|Audit Fees         |  | $    | 1,977 |      |  | $ | 1,556 | 
|Audit-Related Fees |  |      | 127   |      |  |   | 158   | 
|Tax Fees           |  |      | 1,408 |      |  |   | 1,491 | 
|All Other Fees     |  |      | 26    |      |  |   | 592   | 
|                   |  |      |       |      |  |   |       | 
|Total              |  | $    | 3,538 |      |  | $ | 3,797 | 
|                   |  |      |       |      |  |   |       | 

Audit Fees.    Audit fees consist of fees for the audit of the registrants
annual financial statements or services that are normally provided in
connection with statutory and regulatory filings or engagements.

Audit-Related Fees.    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 registrants financial statements and are not reported as Audit
Fees. During fiscal 2003 and 2002, the services provided in this category
included due diligence reviews in connection with acquisitions, research of
accounting and audit-related issues, review of reserves disclosure and the
completion of audits required by contracts to which the registrant is a party.

Tax Fees.    Tax fees consist of fees for tax compliance services, tax advice and
tax planning. During fiscal 2003 and 2002, the services provided in this
category included assistance and advice in relation to the preparation of
corporate income tax returns, expatriate tax services and, in 2002 only,
shareholder tax assistance.

All Other Fees.    During fiscal 2003, the services provided in this category
included the review of the registrants Corporate Responsibility Report and the
payment of maintenance fees associated with a working paper documentation
package used by the registrants internal audit group. During fiscal 2002, the
services provided in this category included information technology consulting
services that were provided prior to the enactment of the Sarbanes-Oxley Act of
2002 and the adoption of rules thereunder.

40-F3



---



##### 



Pre-Approval Policies and Procedures.



|(a) |  | The registrant has adopted the following policies and procedures with
respect to
the pre-approval of audit and permitted non-audit services to be provided
by PricewaterhouseCoopers LLP:
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The audit committee of the board of directors
has established a budget for the provision of a specified
list of audit and permitted non-audit services that the audit
committee believes to be typical, recurring or otherwise
likely to be provided by PricewaterhouseCoopers LLP. The
budget generally covers the period between the adoption of
the budget and the next meeting of the audit committee, but
at the option of the audit committee it may cover a longer or
shorter period. The list of services is sufficiently
detailed as to the particular services to be provided to
ensure that (i) the audit committee knows precisely what
services it is being asked to pre-approve and (ii) it is not
necessary for any member of management to make a judgment as
to whether a proposed service fits within the pre-approved
services.          
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Subject to the next paragraph, the audit
committee has delegated authority to the Chairman of the
audit committee (or if the Chairman is unavailable, any other
member of the Committee) to pre-approve the provision of
permitted services by PricewaterhouseCoopers LLP and not
otherwise pre-approved by the audit committee, including the
fees and terms of the proposed services (Delegated
Authority). Any required determination about the Chairmans
unavailability is required to be made by the good faith
judgment of the applicable other member(s) of the audit
committee after considering all facts and circumstances
deemed by such member(s) to be relevant. All pre-approvals
granted pursuant to Delegated Authority must be presented by
the member(s) who granted the pre-approvals to the full audit
committee at its next meeting.
|
| |  |  | The fees payable in connection with any
particular service to be provided by PricewaterhouseCoopers
LLP that has been pre-approved pursuant to Delegated
Authority (i) may not exceed Cdn.$200,000, in the case of
pre-approvals granted by the Chairman of the audit committee,
and (ii) may not exceed Cdn.$50,000, in the case of
pre-approvals granted by any other member of the audit
committee.                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|
| |  |  | All proposed services or the fees payable in
connection with such services that have not already been
pre-approved must be pre-approved by either the audit
committee or pursuant to Delegated Authority. Prohibited
services may not be pre-approved by the audit committee or
pursuant to Delegated Authority.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            



|(b) |  | Of the fees reported in this Annual Report on Form 40-F under the heading
Principal Accountant Fees and Services, US$35,300 of the fees billed by
PricewaterhouseCoopers LLP in respect of tax services were approved by the
audit committee of the board of directors of the registrant pursuant to
the de
minimusexception provided by Section (c)(7)(i)(C) of Rule 2-01 of
Regulation S-X.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

40-F4



---



##### 



Off-Balance Sheet Arrangements.

The required disclosure is included in the section of this Annual Report on
Form 40-F entitled Principal Documents, 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, 2003.

Tabular Disclosure of Contractual Obligations.

The required disclosure is included in the section of this Annual Report on
Form 40-F entitled Principal Documents, 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, 2003.

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 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.

40-F5



---



##### 



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 2004 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-F6



---



##### 



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 March 5, 2004.



| | EnCana Corporation
| | ------------------



| | By: /s/ Thomas G. Hinton
Name:  Thomas G. Hinton
Title:    Treasurer
| | --------------------------------------------------------------------



| | By: /s/ Gerald T. Ince
Name:  Gerald T. Ince
Title:    Assistant Treasurer
| | --------------------------------------------------------------------------

40-F7



---



##### 



EXHIBIT INDEX

|        |  |                                                                                                                     
|------- |  | --------------------------------------------------------------------------------------------------------------------
|Exhibit |  | Description                                                                                                         
|        |  |                                                                                                                     
|99.1    |  | Certification of Chief Executive Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
|        |  |                                                                                                                     
|99.2    |  | Certification of Chief Financial Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
|        |  |                                                                                                                     
|99.3    |  | Section 1350 Certification of Chief Executive Officer                                                               
|        |  |                                                                                                                     
|99.4    |  | Section 1350 Certification of Chief Financial Officer                                                               
|        |  |                                                                                                                     
|99.5    |  | Consent of PricewaterhouseCoopers LLP                                                                               
|        |  |                                                                                                                     
|99.6    |  | Consent of McDaniel & Associates Consultants Ltd.                                                                   
|        |  |                                                                                                                     
|99.7    |  | Consent of Netherland, Sewell & Associates, Inc.                                                                    
|        |  |                                                                                                                     
|99.8    |  | Consent of Ryder Scott Company                                                                                      
|        |  |                                                                                                                     
|99.9    |  | Consent of DeGolyer and MacNaughton                                                                                 
|        |  |                                                                                                                     
|99.10   |  | Consent of Gilbert Laustsen Jung Associates Ltd.