##### Table of Contents



SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C.
20549
 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2004
    
    Commission file number: 0-12014
 IMPERIAL OIL LIMITED (Exact name of registrant as specified in its charter)
 CANADA
    
    98-0017682(State or other jurisdiction of
    
    (I.R.S. Employerincorporation or organization)
    
    Identification No.)
 111 ST. CLAIR AVENUE WEST, TORONTO, ONT., CANADA
    
    M5W 1K3(Address of principal executive offices)
    
    (Zip Code)
 Registrants telephone number, including area code:  Securities registered pursuant to Section 12(b) of the Act: Name of each exchange onTitle of each class
    
    which registeredNone
    
    None
 Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)  (Title of Class)
 The registrant (1) has filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 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 Disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. Yesþ
Noo The registrant is an accelerated filer (as defined in Rule 12 b-2 of the Securities Exchange
Act of 1934). Yesþ
Noo As of the last business day of the 2004 second fiscal quarter, the aggregate market value of
the voting stock held by non-affiliates of the registrant was Canadian $ 6,768,415,742 based upon
the reported last sale price of such stock on the Toronto Stock Exchange on that date. The number of common shares outstanding, as of February 18, 2005, was 342,365,873.




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PagePART IItem 1. Business
    
    
    3Financial Information by Operating Segments
    
    
    3Natural Resources
    
    
    4Petroleum and Natural Gas Production
    
    
    4Land Holdings
    
    
    9Exploration and Development
    
    
    9Petroleum Products
    
    
    11Supply
    
    
    11Refining
    
    
    11Distribution
    
    
    12Marketing
    
    
    12Chemicals
    
    
    13Research
    
    
    13Environmental Protection
    
    
    13Human Resources
    
    
    13Competition
    
    
    13Government Regulation
    
    
    14The Company Online
    
    
    14Item 2. Properties
    
    
    15Item 3. Legal Proceedings
    
    
    15Item 4. Submission of Matters to a Vote of Security Holders
    
    
    15PART IIItem 5.
Market for Registrants Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity  Securities
    
    
    15Item 6. Selected Financial Data
    
    
    16Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operation
    
    
    16Item 7A. Quantitative and Qualitative Disclosures About Market Risk
    
    
    26Item 8. Financial Statements and Supplementary Data
    
    
    26Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    
    
    31Item 9A. Controls and Procedures
    
    
    31PART IIIItem 10. Directors and Executive Officers of the Registrant
    
    
    32Item 11. Executive Compensation
    
    
    35Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    
    
    43Item 13. Certain Relationships and Related Transactions
    
    
    44Item 14. Principal Accountant Fees and Services
    
    
    44PART IVItem 15. Exhibits and Financial Statement Schedules
    
    
    45Index to Financial Statements
    
    
    F-1Managements Report on Internal Control over Financial Reporting
    
    
    F-2Auditors Report
    
    
    F-2
  All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated.
The following table sets forth (i) the rates of exchange for the Canadian dollar, expressed in
U.S. dollars, in effect at the end of each of the periods indicated, (ii) the average of exchange
rates in effect on the last day of each month during such periods, and (iii) the high and low
exchange rates during such periods, in each case based on the noon buying rate in New York City for
cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank
of New York. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(Dollars)Rate at end of period
    
    
    0.8310
    
    
    
    0.7738
    
    
    
    0.6329
    
    
    
    0.6279
    
    
    
    0.6669Average rate during period
    
    
    0.7702
    
    
    
    0.7186
    
    
    
    0.6368
    
    
    
    0.6444
    
    
    
    0.6725High
    
    
    0.8493
    
    
    
    0.7738
    
    
    
    0.6619
    
    
    
    0.6697
    
    
    
    0.6969Low
    
    
    0.7158
    
    
    
    0.6349
    
    
    
    0.6200
    
    
    
    0.6241
    
    
    
    0.6410
 On February 28, 2005, the noon buying rate in New York City for cable transfers in Canadian
dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.8133 U.S.
= $1.00 Canadian. 2




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##### Table of Contents



This report contains forward looking information on future production, project start ups and
future capital spending. Actual results could differ materially as a result of market conditions or
changes in law, government policy, operating conditions, costs, project schedules, operating
performance, demand for oil and natural gas, commercial negotiations or other technical and
economic factors. 
 PART I 
 Item 1. Business.
     Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under
the Canada Business Corporations Act (the CBCA) by certificate of continuance dated April 24,
1978. The head and principal office of the Company is located at 111 St. Clair Avenue West,
Toronto, Ontario, Canada M5W 1K3; telephone 1-800-567-3776. Exxon Mobil Corporation owns
approximately 69.6 percent of the outstanding shares of the Company with the remaining shares being
publicly held, with the majority of shareholders having Canadian addresses of record. In this
report, unless the context otherwise indicates, reference to the Company includes Imperial Oil
Limited and its subsidiaries.
     The Company is Canadas largest integrated oil company. It is active in all phases of the
petroleum industry in Canada, including the exploration for, and production and sale of, crude oil
and natural gas. In Canada, it is one of the largest producers of crude oil and natural gas liquids
and a major producer of natural gas, and the largest refiner and marketer of petroleum products. It
is also a major supplier of petrochemicals.
     The Companys operations are conducted in three main segments: natural resources (upstream),
petroleum products (downstream) and chemicals. Natural resources operations include the
exploration for, and production of, crude oil and natural gas, including upgraded crude oil and
crude bitumen. Petroleum products operations consist of the transportation, refining and blending
of crude oil and refined products and the distribution and marketing thereof. The chemicals
operations consist of the manufacturing and marketing of various petrochemicals. 
 Financial Information by Operating Segments (under U.S. GAAP) 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)External revenues (1):Natural resources
    
    $
    3,734
    
    
    $
    3,424
    
    
    $
    2,677
    
    
    $
    3,155
    
    
    $
    3,262Petroleum products
    
    
    17,545
    
    
    
    14,764
    
    
    
    13,396
    
    
    
    13,105
    
    
    
    13,788Chemicals
    
    
    1,216
    
    
    
    994
    
    
    
    955
    
    
    
    930
    
    
    
    945Corporate and other
    
    
    (35
    )
    
    
    26
    
    
    
    14
    
    
    
    63
    
    
    
    56$
    22,460
    
    
    $
    19,208
    
    
    $
    17,042
    
    
    $
    17,253
    
    
    $
    18,051Intersegment sales:Natural resources
    
    $
    2,891
    
    
    $
    2,224
    
    
    $
    2,217
    
    
    $
    2,166
    
    
    $
    2,638Petroleum products
    
    
    1,666
    
    
    
    1,294
    
    
    
    1,038
    
    
    
    1,300
    
    
    
    1,332Chemicals
    
    
    293
    
    
    
    238
    
    
    
    209
    
    
    
    245
    
    
    
    228Total revenues:Natural resources
    
    $
    6,625
    
    
    $
    5,648
    
    
    $
    4,894
    
    
    $
    5,321
    
    
    $
    5,900Petroleum products
    
    
    19,211
    
    
    
    16,058
    
    
    
    14,434
    
    
    
    14,405
    
    
    
    15,120Chemicals
    
    
    1,509
    
    
    
    1,232
    
    
    
    1,164
    
    
    
    1,175
    
    
    
    1,173Corporate and other
    
    
    (35
    )
    
    
    26
    
    
    
    14
    
    
    
    63
    
    
    
    56Net income (2):Natural resources
    
    $
    1,487
    
    
    $
    1,143
    
    
    $
    1,042
    
    
    $
    941
    
    
    $
    1,165Petroleum products
    
    
    500
    
    
    
    407
    
    
    
    127
    
    
    
    353
    
    
    
    313Chemicals
    
    
    100
    
    
    
    37
    
    
    
    52
    
    
    
    23
    
    
    
    59Corporate and other (3) /eliminations
    
    
    (35
    )
    
    
    118
    
    
    
    (7
    )
    
    
    (94
    )
    
    
    (129
    )$
    2,052
    
    
    $
    1,705
    
    
    $
    1,214
    
    
    $
    1,223
    
    
    $
    1,408Identifiable assets at December 31 (4):Natural resources
    
    $
    6,875
    
    
    $
    6,418
    
    
    $
    6,014
    
    
    $
    5,390
    
    
    $
    5,294Petroleum products
    
    
    5,570
    
    
    
    5,290
    
    
    
    5,127
    
    
    
    4,425
    
    
    
    4,829Chemicals
    
    
    498
    
    
    
    440
    
    
    
    428
    
    
    
    384
    
    
    
    381Corporate and other/eliminations
    
    
    1,084
    
    
    
    189
    
    
    
    434
    
    
    
    689
    
    
    
    762$
    14,027
    
    
    $
    12,337
    
    
    $
    12,003
    
    
    $
    10,888
    
    
    $
    11,266Capital and exploration expenditures:Natural resources
    
    $
    1,113
    
    
    $
    1,007
    
    
    $
    986
    
    
    $
    746
    
    
    $
    434Petroleum products
    
    
    283
    
    
    
    478
    
    
    
    589
    
    
    
    339
    
    
    
    232Chemicals
    
    
    15
    
    
    
    41
    
    
    
    25
    
    
    
    30
    
    
    
    13Corporate and other
    
    
    34
    
    
    
    33
    
    
    
    12
    
    
    
    
    
    
    
    $
    1,445
    
    
    $
    1,559
    
    
    $
    1,612
    
    
    $
    1,115
    
    
    $
    679
   (1)
    
    Export sales are reported in note 2 to the
consolidated financial statements on page F-11.(2)
    
    These amounts are presented as if each segment were a separate business entity
and, accordingly, include the financial effect of transactions between the segments. Intersegment sales are made essentially at prevailing market prices.(3)
    
    Includes primarily
interest charges on the debt obligations of the Company, interest income on investments and
intersegment consolidating adjustments.(4)
    
    The identifiable assets in each operating segment represent the net book value of the tangible
and intangible assets attributed to such segment. 3




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##### Table of Contents



Natural Resources 
 Petroleum and Natural Gas Production
     The Companys average daily production of crude oil and natural gas liquids during the five
years ended December 31, 2004, was as follows: 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(thousands a day)Conventional (including natural gas liquids):Cubic metres  Gross (1)
    
    
    12.1
    
    
    
    11.8
    
    
    
    12.4
    
    
    
    13.2
    
    
    
    14.3  Net (2)
    
    
    9.4
    
    
    
    9.1
    
    
    
    9.5
    
    
    
    10.2
    
    
    
    11.0Barrels           Gross (1)
    
    
    76
    
    
    
    74
    
    
    
    78
    
    
    
    83
    
    
    
    90 Net (2)
    
    
    59
    
    
    
    57
    
    
    
    60
    
    
    
    64
    
    
    
    69Oil Sands (Cold Lake):Cubic metres  Gross (1)
    
    
    20.0
    
    
    
    20.5
    
    
    
    17.8
    
    
    
    20.4
    
    
    
    18.9 Net (2)
    
    
    17.7
    
    
    
    18.4
    
    
    
    16.9
    
    
    
    19.2
    
    
    
    16.2Barrels            Gross (1)
    
    
    126
    
    
    
    129
    
    
    
    112
    
    
    
    128
    
    
    
    119 Net (2)
    
    
    112
    
    
    
    116
    
    
    
    106
    
    
    
    121
    
    
    
    102Tar Sands (Syncrude):Cubic metres  Gross (1)
    
    
    9.5
    
    
    
    8.4
    
    
    
    9.1
    
    
    
    8.9
    
    
    
    8.1 Net (2)
    
    
    9.4
    
    
    
    8.3
    
    
    
    9.1
    
    
    
    8.3
    
    
    
    6.7Barrels           Gross (1)
    
    
    60
    
    
    
    53
    
    
    
    57
    
    
    
    56
    
    
    
    51 Net (2)
    
    
    59
    
    
    
    52
    
    
    
    57
    
    
    
    52
    
    
    
    42Total:Cubic metres  Gross (1)
    
    
    41.6
    
    
    
    40.7
    
    
    
    39.3
    
    
    
    42.5
    
    
    
    41.3 Net (2)
    
    
    36.5
    
    
    
    35.8
    
    
    
    35.5
    
    
    
    37.7
    
    
    
    33.9Barrels           Gross (1)
    
    
    262
    
    
    
    256
    
    
    
    247
    
    
    
    267
    
    
    
    260 Net (2)
    
    
    230
    
    
    
    225
    
    
    
    223
    
    
    
    237
    
    
    
    213
   (1)
    
    Gross production of crude oil is the Companys share of production from conventional
wells, Syncrude tar sands and Cold Lake oil sands, and gross production of natural gas liquids
is the amount derived from processing the Companys share of production of natural gas
(excluding purchased gas), in each case before deduction of the mineral owners or governments
share or both.(2)
    
    Net production is gross production less the mineral owners or governments share or both. From 2000 through 2003, conventional production has declined due to the sale of oil and
gas producing properties and the natural decline in the productivity of the Companys conventional
oil fields. In 2004, conventional production increased primarily due to increased natural gas
liquids production from the Wizard Lake gas cap. In 2001, Cold Lake net production increased mainly
due to the timing of steaming cycles and lower royalties and Syncrude production increased mainly
due to the start up of the Aurora mine during the second half of 2000 and fewer disruptions in
upgrading operations than the previous year. In 2002, Cold Lake production decreased mainly due to
the timing of steaming cycles and Syncrude net production increased mainly due to lower royalties.
In 2003, Cold Lake net production increased as a result of a full year of production of stages 11
to 13, which was offset in part by the timing of steaming cycles and higher royalties. Syncrude
production decreased in 2003 due to extended maintenance of upgrading facilities. In 2004, Cold
Lake production declined due to the timing of steaming cycles and higher royalty, and Syncrude
production increased due to fewer disruptions in upgrading operations than in 2003. 4




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The Companys average daily production and sales of natural gas during the five years ended
December 31, 2004 are set forth below. All gas volumes in this report are calculated at a pressure
base of, in the case of cubic metres, 101.325 kilopascals absolute at 15 degrees Celsius and, in
the case of cubic feet, 14.73 pounds per square inch at 60 degrees Fahrenheit. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions a day)Sales (1):Cubic metres
    
    
    14.7
    
    
    
    13.0
    
    
    
    14.1
    
    
    
    14.2
    
    
    
    11.9Cubic feet
    
    
    520
    
    
    
    460
    
    
    
    499
    
    
    
    502
    
    
    
    419Gross Production (2):Cubic metres
    
    
    16.1
    
    
    
    14.5
    
    
    
    15.0
    
    
    
    16.2
    
    
    
    14.9Cubic feet
    
    
    569
    
    
    
    513
    
    
    
    530
    
    
    
    572
    
    
    
    526Net Production (2):Cubic metres
    
    
    14.7
    
    
    
    12.9
    
    
    
    13.1
    
    
    
    13.2
    
    
    
    13.0Cubic feet
    
    
    518
    
    
    
    457
    
    
    
    463
    
    
    
    466
    
    
    
    459
   (1)
    
    Sales are sales of the Companys share of production (before deduction of the mineral
owners and/or governments share) and sales of gas purchased, processed and/or resold.(2)
    
    Gross production of natural gas is the Companys share of production (excluding purchases)
before deducting the shares of mineral owners or governments or both. Net production excludes
those shares. Production data include amounts used for internal consumption with the exception
of amounts reinjected. In 2001, natural gas production increased primarily due to gas production from the Sable
Offshore Energy Project, which went into production at the end of 1999, and increased production
from gas caps overlaying two former oil fields, both in Alberta. In 2002 and 2003, natural gas
production decreased primarily due to the depletion of gas caps in Alberta and in 2003 also due to
increased maintenance activity at gas processing facilities. In 2004 natural gas production
increased primarily due to increased production from the Wizard Lake gas cap.
     Most of the Companys natural gas sales are made under short term contracts.
     The Companys average sales price and production (lifting) costs for conventional and Cold
Lake crude oil and natural gas liquids and natural gas for the five years ended December 31, 2004,
were as follows: 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Average Sales Price:Crude oil and natural gas liquids:Per cubic metre
    
    $
    207.26
    
    
    $
    181.92
    
    
    $
    174.72
    
    
    $
    134.16
    
    
    $
    190.02Per barrel
    
    
    32.95
    
    
    
    28.92
    
    
    
    27.78
    
    
    
    21.33
    
    
    
    30.21Natural gas:Per thousand cubic metres
    
    $
    239.34
    
    
    $
    232.99
    
    
    $
    141.91
    
    
    $
    201.92
    
    
    $
    176.15Per thousand cubic feet
    
    
    6.78
    
    
    
    6.60
    
    
    
    4.02
    
    
    
    5.72
    
    
    
    4.99Average Production (Lifting) Costs Per
Unit of Net Production (1):Per cubic metre
    
    $
    60.38
    
    
    $
    63.85
    
    
    $
    48.81
    
    
    $
    46.17
    
    
    $
    47.36Per barrel
    
    
    9.60
    
    
    
    10.15
    
    
    
    7.76
    
    
    
    7.34
    
    
    
    7.53
   (1)
    
    Average production (lifting) costs do not include depreciation and depletion of
capitalized acquisition, exploration and development costs. Administrative expenses are
included. Average production (lifting) costs per unit of net production were computed after
converting gas production into equivalent units of oil on the basis of relative energy content. Canadian crude oil prices are mainly determined by international crude oil markets which
are volatile. 
     Canadian natural gas prices are determined by North American gas markets and are also
volatile. Prices for Canadian natural gas increased significantly in 2000 and again in early 2001
and 2003, in line with tighter North American market conditions. Canadian natural gas prices
decreased in 2002 primarily due to a weaker U.S. economy and warmer weather.
     In 2001, average production (lifting) costs decreased mainly due to higher net production at
Cold Lake. In 2002, average production (lifting) costs increased mainly due to lower net production
at Cold Lake. In 2003, average production (lifting) costs increased mainly due to higher costs of purchased natural gas at Cold Lake. In 2004, average production (lifting)
costs decreased mainly due to higher production from the Wizard Lake gas cap.
     The Company has interests in a large number of facilities related to the production of crude
oil and natural gas. Among these facilities are 27 plants that process natural gas to produce
marketable gas and recover natural gas liquids or sulphur. The Company is the principal owner and
operator of 11 of the plants.
     The Companys production of conventional and Cold Lake crude oil and natural gas is derived
from wells located exclusively in Canada. The total number of producing wells in which the Company
had interests at December 31, 2004, is set forth in the following table. The statistics in the
table are determined in part from information received from other operators. 5




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##### Table of Contents



Crude Oil
    
    
    Natural Gas
    
    
    TotalGross (1)
    
    
    
    Net (2)
    
    
    Gross (1)
    
    
    
    Net (2)
    
    
    Gross (1)
    
    
    
    Net (2)Conventional wells
    
    
    2,322
    
    
    
    1,292

    
    
    
    4,326
    
    
    
    2,275
    
    
    
    6,648
    
    
    
    3,567Oil Sands (Cold Lake) wells
    
    
    3,815
    
    
    
    3,815
    
    
    
    
    
    
    
    
    
    
    
    3,815
    
    
    
    3,815
   (1)
    
    Gross wells are wells in which the Company owns a working interest.(2)
    
    Net wells are the sum of the fractional working interests owned by the Company in gross
wells, rounded to the nearest whole number. Conventional Oil and Gas
     The Company has major interests in the Norman Wells oil field in the Northwest Territories and
the West Pembina oil field in Alberta. Together they currently account for approximately 60 percent
of the Companys net production of conventional crude oil (approximately 65 percent of gross
production).
     Norman Wells is the Companys largest producing conventional oil field. In 2004, net
production of crude oil and natural gas liquids was about 2,400 cubic metres (14,800 barrels) per
day and gross production was about 3,500 cubic metres (22,000 barrels) per day. The Government of
Canada has a one-third carried interest and receives a production royalty of five percent in the
Norman Wells oil field. The Government of Canadas carried interest entitles it to receive payment
of a one-third share of an amount based on revenues from the sale of Norman Wells production, net
of operating and capital costs. Under a shipping agreement, the Company pays for the construction,
operating and other costs of the 870 kilometre (540 mile) pipeline which transports the crude oil
and natural gas liquids from the project. In 2004, those costs were about $35 million. Most of the
larger oil fields in the Western Provinces have been in production for several decades, and the
amount of oil that is produced from conventional fields is declining. In some cases, however,
additional oil can be recovered by using various methods of enhanced recovery. The Companys
largest enhanced recovery projects are located at the West Pembina oil field.
     The Company produces natural gas from a large number of gas fields located in the Western
Provinces, primarily in Alberta.
     The Company has a nine percent interest in a project to develop natural gas reserves in the
Sable Island area off the coast of the Province of Nova Scotia. About $4 billion has been spent by
the participants to the end of 2004 on the project. Production from the Sable Offshore Energy
Project began at the end of 1999 and is expected to average about 12 million cubic metres (420
million cubic feet) per day of natural gas and 3,200 cubic metres (20,000 barrels) per day of
natural gas liquids through the end of the decade. Cold Lake
     The Company holds about 78,000 leased hectares (192,000 acres) of oil sands near Cold Lake,
Alberta. This oil sands deposit contains a very heavy crude oil (crude bitumen). To develop the
technology necessary to produce this oil commercially, the Company has conducted experimental pilot
operations since 1964 to recover the crude bitumen from wells by means of new drilling and
production techniques including steam injection. Research at, and operation of, the Cold Lake
pilots is continuing.
     In late 1983, the Company commenced the development, in stages, of its oil sands resources at
Cold Lake. During 2004, average net production at Cold Lake was about 17,700 cubic metres (111,500
barrels) per day and gross production was about 20,000 cubic metres (125,800 barrels) per day.
     To maintain production at Cold Lake, capital expenditures for additional production wells and
associated facilities will be required periodically. In 2004, the Company spent $127 million on a
development drilling program of 218 wells on existing stages. In 2005, a development drilling
program of more than 150 wells is planned within the currently approved development area to enhance
productivity from existing Cold Lake stages. In addition, opportunities are also being evaluated to
improve utilization of the existing infrastructure.
     In 2004, the Company received regulatory approval for further expansion of its operations at
Cold Lake. Production is expected to begin in 2006 from part of the approved expansion, the
development of which is expected to cost about $300 million and is expected to have gross
production of about 4,770 cubic metres (30,000 barrels) per day by the end of the decade.
Development plans for the remainder of the approved expansion are being examined to reduce
development costs through increased integration with existing infrastructure. Most of the
production from Cold Lake is sold to refineries in the northern United States. The remainder of the
Cold Lake production is shipped to certain of the Companys refineries and to a heavy oil upgrader
in Lloydminster, Saskatchewan. 6




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##### Table of Contents



The Province of Alberta, in its capacity as lessor of the Cold Lake oil sands leases, is
entitled to a royalty on production from the Cold Lake production project. In late 2000, the
Company entered into an agreement with the Province of Alberta, effective January 1, 2000, on a
transitional royalty arrangement that will apply to all of the Companys current and proposed
operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for
royalties that apply to all other oil sands development in the Province will take effect. This
transition is expected to be royalty neutral. The effective royalty on gross production was 11
percent in 2004, 10 percent in 2003, five percent in 2002 and 2001, and 14 percent in 2000. The
Company expects that after 2007 the royalty will be the greater of one percent of gross revenue or
25 percent of an amount based on revenue net of operating and capital costs for the Cold Lake
production project and the pilot operations. Other Oil Sands Activity
     The Company has interests in other oil sands leases in the Athabasca and Peace River areas of
northern Alberta. Evaluation wells completed on these leased areas established the presence of very
heavy crude oil in place. The Company continues to evaluate these leases to determine their
potential for future development.
     The Company holds varying interests in lands totalling about 68,000 leased net hectares
(168,000 net acres) in the Athabasca area where the oil sands are buried too deeply to permit
recovery by surface mining methods. The Company, as part of an industry consortium and several
joint ventures, has been involved in recovery research and pilot studies and in evaluating the
quality and extent of the oil sands. Syncrude Mining Operations
      The Company holds a 25 percent participating interest in Syncrude, a joint venture established
to recover shallow deposits of tar sands using open-pit mining methods, to extract the crude
bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The
Syncrude operation, located near Fort McMurray, Alberta, exploits a portion of the Athabasca Oil
Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil
is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. The
pipeline is currently being expanded to accommodate increased Syncrude production. Since startup in
1978, Syncrude has produced about 1.5 billion barrels of synthetic crude oil.
     Syncrude has an operating license issued by the Province of Alberta which is effective until
2035. This license permits Syncrude to mine tar sands and produce synthetic crude oil from approved
development areas on tar sands leases. Syncrude holds eight tar sands leases covering about 102,000
hectares (252,000 acres) in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta, the
leases are automatically renewable as long as tar sands operations are ongoing or the leases are
part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven
reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within a
development plan approved by the Province of Alberta. There were no known previous commercial
operations on these leases prior to the start-up of operations in 1978.
     As of January 1, 2002, a greater of 25 percent deemed net profit royalty or one percent gross
royalty applies to all Syncrude production after the deduction of new capital expenditures.
     The Government of Canada had issued an order that expired at the end of 2003 which provided
for the remission of any federal income tax otherwise payable by the participants as the result of
the non-deductibility from the income of the participants of amounts receivable by the Province of
Alberta as a royalty or otherwise with respect to Syncrude. That remission order excluded royalty
payable on production for the Aurora project.
     Operations at Syncrude involve three main processes: open pit mining, extraction of crude
bitumen and upgrading of crude bitumen into synthetic crude oil. In the Base mine (lease 17), the
mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. In the
North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and
hydrotransport systems are used. The extraction facilities, which separate crude bitumen from sand,
are capable of processing approximately 495,000 tonnes (545,000 tons) of tar sands a day, producing
about 18 million cubic metres (110 million barrels) of crude bitumen a year. This represents
recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands. 7




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##### Table of Contents



Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through
a combination of carbon removal in two large, high temperature, fluid coking vessels and by
hydrogen addition in high temperature, high pressure, hydrocracking vessels. These processes remove
carbon and sulphur and reformulate the crude into a low viscosity, low sulphur, high quality
synthetic crude oil product. In 2004, the upgrading process yielded 0.855 cubic metres of synthetic
crude oil per cubic metre of crude bitumen (0.855 barrels of synthetic crude oil per barrel of
crude bitumen). In 2004, about 45 percent of the synthetic crude oil was processed by Edmonton area
refineries and the remaining 55 percent was pipelined to refineries in eastern Canada or exported
to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating
plant and a 80 megawatt electricity generating plant, both located at Syncrude. The generating
plants are owned by the Syncrude participants. The Companys 25 percent share of net investment in
plant, property and equipment, including surface mining facilities, transportation equipment and
upgrading facilities is about $2.8 billion.
     In 2004, Syncrudes net production of synthetic crude oil was about 37,500 cubic metres
(235,600 barrels) per day and gross production was about 37,800 cubic metres (238,000 barrels) per
day. The Companys share of net production in 2004 was about 9,400 cubic metres (58,900 barrels)
per day.
     In 2000, Syncrude completed development of the first stage of the Aurora mine. The Aurora
investment involved extending mining operations to a new location about 35 km from the main
Syncrude site and expanding upgrading capacity. In 2001, the Syncrude owners approved another major
expansion of upgrading capacity and further development of the Aurora mine. The second Aurora
mining and extraction development became fully operational in 2004. The increased upgrading
capacity is expected to be available in 2006. These projects are expected to lead to a total
production capacity of about 56,500 cubic metres (355,000 barrels) of synthetic crude oil a day
when completed. The Companys share of project costs is expected to be about $2 billion of which
about $1.6 billion has been incurred to the end of 2004.
     The following table sets forth certain operating statistics for the Syncrude operations: 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Total mined volume (1)millions of cubic metres
    
    
    76.6
    
    
    
    83.5
    
    
    
    77.9
    
    
    
    90.3
    
    
    
    65.0millions of cubic yards
    
    
    100.3
    
    
    
    109.2
    
    
    
    102.0
    
    
    
    118.3
    
    
    
    85.1Mined volume to tar sands ratio (1)
    
    
    0.94
    
    
    
    1.15
    
    
    
    1.05
    
    
    
    1.15
    
    
    
    0.96Tar sands
minedmillions of tonnes
    
    
    170.9
    
    
    
    152.4
    
    
    
    156.5
    
    
    
    164.8
    
    
    
    142.2millions of tons
    
    
    188.0
    
    
    
    168.0
    
    
    
    172.1
    
    
    
    181.2
    
    
    
    156.4Average bitumen grade (weight percent)
    
    
    11.1
    
    
    
    11.0
    
    
    
    11.2
    
    
    
    11.0
    
    
    
    11.0Crude bitumen in mined tar sandsmillions of tonnes
    
    
    19.0
    
    
    
    16.8
    
    
    
    17.5
    
    
    
    18.1
    
    
    
    15.6millions of tons
    
    
    20.9
    
    
    
    18.5
    
    
    
    19.2
    
    
    
    19.9
    
    
    
    17.2Average extraction recovery (percent)
    
    
    87.3
    
    
    
    88.6
    
    
    
    89.9
    
    
    
    87.0
    
    
    
    89.7Crude bitumen production (2)millions of cubic metres
    
    
    16.4
    
    
    
    14.7
    
    
    
    15.5
    
    
    
    15.5
    
    
    
    13.8millions of barrels
    
    
    103.3
    
    
    
    92.3
    
    
    
    97.8
    
    
    
    97.6
    
    
    
    86.8Average upgrading yield (percent)
    
    
    85.5
    
    
    
    86.0
    
    
    
    86.3
    
    
    
    84.5
    
    
    
    84.3Gross synthetic crude oil producedmillions of cubic metres
    
    
    14.1
    
    
    
    12.5
    
    
    
    13.5
    
    
    
    13.1
    
    
    
    11.6millions of barrels
    
    
    88.4
    
    
    
    78.4
    
    
    
    84.8
    
    
    
    82.4
    
    
    
    73.2Companys net share (3)millions of cubic metres
    
    
    3
    
    
    
    3
    
    
    
    3
    
    
    
    3
    
    
    
    2millions of barrels
    
    
    22
    
    
    
    19
    
    
    
    21
    
    
    
    19
    
    
    
    15
   (1)
    
    Includes pre-stripping of mine areas and reclamation volumes.(2)
    
    Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the
average extraction recovery and the appropriate conversion factor.(3)
    
    Reflects the Companys 25 percent interest in production, less applicable royalties
payable to the Province of Alberta. Other Tar Sands Activity
     The Company holds a 100 percent interest in approximately 16,500 hectares (40,700 acres) of
surface mineable tar sands in the Kearl area in the Athabasca area of northern Alberta. A 400 well

delineation drilling program to better define the available resource was begun in 2003 and is
expected to be completed in 2005. The Company is assessing a potential phased project with another
company to jointly develop mineable bitumen, which may have the potential to produce up to
approximately 47,700 cubic metres (300,000 barrels) per day. The Company plans on filing a
regulatory application with the Alberta Energy and Utilities Board for the Kearl oil sands project
in 2005. 8




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##### Table of Contents



Land Holdings
     At December 31, 2004 and 2003, the Company held the following oil and gas rights, and tar sands
leases: Hectares
    
    
    AcresDeveloped
    
    
    Undeveloped
    
    
    Total
    
    
    Developed
    
    
    Undeveloped
    
    
    Total2004
    
    
    2003
    
    
    2004
    
    
    2003
    
    
    2004
    
    
    2003
    
    
    2004
    
    
    2003
    
    
    2004
    
    
    2003
    
    
    2004
    
    
    2003(thousands)Western Provinces
Conventional Gross (1)
    
    
    1,080
    
    
    
    1,101
    
    
    
    173
    
    
    
    187
    
    
    
    1,253
    
    
    
    1,288
    
    
    
    2,669
    
    
    
    2,721
    
    
    
    427
    
    
    
    462
    
    
    
    3,096
    
    
    
    3,183Net (2)
    
    
    446
    
    
    
    450
    
    
    
    118
    
    
    
    127
    
    
    
    564
    
    
    
    577
    
    
    
    1,102
    
    
    
    1,112
    
    
    
    292
    
    
    
    314
    
    
    
    1,394
    
    
    
    1,426Oil Sands (Cold Lake
and other) Gross (1)
    
    
    42
    
    
    
    42
    
    
    
    193
    
    
    
    175
    
    
    
    235
    
    
    
    217
    
    
    
    104
    
    
    
    104
    
    
    
    477
    
    
    
    432
    
    
    
    581
    
    
    
    536Net (2)
    
    
    41
    
    
    
    41
    
    
    
    104
    
    
    
    104
    
    
    
    145
    
    
    
    145
    
    
    
    101
    
    
    
    101
    
    
    
    257
    
    
    
    257
    
    
    
    358
    
    
    
    358Tar Sands (Syncrude
and other) Gross (1)
    
    
    45
    
    
    
    41
    
    
    
    73
    
    
    
    77
    
    
    
    118
    
    
    
    118
    
    
    
    111
    
    
    
    101
    
    
    
    180
    
    
    
    190
    
    
    
    291
    
    
    
    291Net (2)
    
    
    11
    
    
    
    10
    
    
    
    31
    
    
    
    32
    
    
    
    42
    
    
    
    42
    
    
    
    27
    
    
    
    25
    
    
    
    77
    
    
    
    79
    
    
    
    104
    
    
    
    104Canada Lands (3):Conventional Gross (1)
    
    
    31
    
    
    
    31
    
    
    
    321
    
    
    
    321
    
    
    
    352
    
    
    
    352
    
    
    
    77
    
    
    
    77
    
    
    
    793
    
    
    
    793
    
    
    
    870
    
    
    
    870Net (2)
    
    
    3
    
    
    
    4
    
    
    
    98
    
    
    
    98
    
    
    
    101
    
    
    
    102
    
    
    
    7
    
    
    
    10
    
    
    
    242
    
    
    
    242
    
    
    
    249
    
    
    
    252Atlantic Offshore
Conventional Gross (1)
    
    
    17
    
    
    
    17
    
    
    
    2,603
    
    
    
    1,329
    
    
    
    2,620
    
    
    
    1,346
    
    
    
    42
    
    
    
    42
    
    
    
    6,432
    
    
    
    3,284
    
    
    
    6,474
    
    
    
    3,326Net (2)
    
    
    2
    
    
    
    2
    
    
    
    832
    
    
    
    565
    
    
    
    834
    
    
    
    567
    
    
    
    5
    
    
    
    5
    
    
    
    2,056
    
    
    
    1,396
    
    
    
    2,061
    
    
    
    1,401Total (4):Gross (1)
    
    
    1,215
    
    
    
    1,232
    
    
    
    3,363
    
    
    
    2,089
    
    
    
    4,578
    
    
    
    3,321
    
    
    
    3,003
    
    
    
    3,045
    
    
    
    8,309
    
    
    
    5,161
    
    
    
    11,312
    
    
    
    8,206Net (2)
    
    
    503
    
    
    
    507
    
    
    
    1,183
    
    
    
    926
    
    
    
    1,686
    
    
    
    1,433
    
    
    
    1,242
    
    
    
    1,253
    
    
    
    2,924
    
    
    
    2,288
    
    
    
    4,166
    
    
    
    3,541
   (1)
    
    Gross hectares or acres include the interests of others.(2)
    
    Net hectares or acres exclude the interests of others.(3)
    
    Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and Other Northwest
Territories, Nunavut and the Yukon.(4)
    
    Certain land holdings are subject to modification under agreements whereby others may earn
interests in the Companys holdings by performing certain exploratory work (farmout) and whereby
the Company may earn interests in others holdings by performing certain exploratory work
(farmin). 
 Exploration and Development
     The Company has been involved in the exploration for and development of petroleum and natural
gas in the Western Provinces, in the Canada Lands (which include the Arctic Islands, the Beaufort
Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon) and in the Atlantic
Offshore.   2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Western and Atlantic Provinces:ConventionalExploratory Oil
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Gas
    
    
    2
    
    
    
    3
    
    
    
    1
    
    
    
    1
    
    
    
    3Dry Holes
    
    
    1
    
    
    
    1
    
    
    
    2
    
    
    
    
    
    
    
    1Development Oil
    
    
    3
    
    
    
    4
    
    
    
    1
    
    
    
    17
    
    
    
    18Gas
    
    
    207
    
    
    
    89
    
    
    
    42
    
    
    
    68
    
    
    
    49Dry Holes
    
    
    1
    
    
    
    3
    
    
    
    3
    
    
    
    
    
    
    
    Oil Sands (Cold Lake and other)Development Oil
    
    
    218
    
    
    
    118
    
    
    
    332
    
    
    
    307
    
    
    
    112Total
    
    
    432
    
    
    
    218
    
    
    
    381
    
    
    
    393
    
    
    
    183
 The 218 oil sands development wells in 2004 were related to productivity maintenance in
existing stages at Cold Lake. In 2004, there was an increase in gas development wells related to an
increase in drilling in shallow gas fields.
     At December 31, 2004, the Company was participating in the drilling of 17 gross (11 net)
exploratory and development wells. 9




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##### Table of Contents



Western Provinces
     In 2004, the Company had a working interest in seven gross (three net) exploratory wells and
483 gross (211 net) development wells, while retaining an overriding royalty in an additional 11
gross exploratory wells drilled by others. The majority of the exploratory wells were directed
toward extending reserves around existing fields. Beaufort Sea/Mackenzie Delta
     Substantial quantities of gas have been found by the Company and others in the Beaufort
Sea/Mackenzie Delta.
     In 1999, the Company and three other companies entered into an agreement to study the
feasibility of developing Mackenzie Delta gas. The four companies are participating in development
planning for onshore natural gas resources totaling approximately 170 billion cubic metres (six
trillion cubic feet). The Companys share of these resources is about 50 percent 
     The commercial viability of these natural gas resources, and the pipeline required to transport this natural gas
to markets, is dependent on a number of factors. These factors include natural gas markets, support from northern parties, regulatory approvals, environmental considerations,
pipeline participation, fiscal terms, and the cost of constructing, operating and abandoning the
field production and pipeline facilities. There are complex issues to be resolved and many
interested parties to be consulted, before any development could proceed.
     In October 2001, the four companies and the Aboriginal Pipeline Group (APG), which
represents aboriginal peoples of the Northwest Territories, signed a memorandum of understanding to
pursue economic and timely development of a Mackenzie Valley pipeline. In 2002, the four companies
completed a preliminary study of the feasibility of developing existing discoveries of Mackenzie
Delta gas and based on the results of the study announced together with the APG their intention to
begin preparing the regulatory applications needed to develop the gas resources, including
construction of a Mackenzie Valley pipeline. In 2003, the Preliminary Information Package for the
Mackenzie Gas Project was submitted to the regulatory authorities, and funding and participation
agreements between the four companies, the APG and TransCanada PipeLines Limited were reached for
the proposed Mackenzie Valley pipeline. In late 2004, the four companies and the APG signed
agreements covering the development and operations of the Mackenzie Valley pipeline. In October
2004, the main regulatory applications and environmental impact statement for the project were
filed with the National Energy Board and other boards, panels and agencies responsible for
assessing and regulating energy developments in the Northwest Territories. The regulatory review
process is expected to take up to 24 months. The initial cost for the project is estimated to be
about $7 billion with the Companys share of the cost estimated to be about $3 billion.
     Other land holdings include majority interests in 20 and minority interests in six
significant discovery licences granted by the Government of Canada as the result of previous oil
and gas discoveries, all of which are managed by the Company and majority interests in two and
minority interests in 16 other significant discovery licences and one production licence, managed
by others. Arctic Islands
     The Company has an interest in 16
significant discovery licences and one production licence
granted by the Government of Canada in the Arctic Islands. These licences are managed by another
company on behalf of all participants. The Company has not participated in wells drilled in this
area since 1984. Atlantic Offshore
     The Company manages five significant discovery licences granted by the Government of Canada
in the Atlantic offshore. The Company also has minority interests in 27 significant discovery
licences, and five production licences, managed by others.
     In 2004 the Companys nine percent working interest in an exploration licence for about
74,000 gross hectares (183,000 gross acres) in the Sable Island area off the coast of the
Province of Nova Scotia expired.
     In 1998, the Company acquired a 20 percent interest in an exploration licence for about 23,500
gross hectares (58,100 gross acres) in the Sable Island area. One exploratory well was completed in
2004 in that area, without commercial success.
     In 1999, the Company acquired a 20 percent interest in six exploration licences for about
217,000 gross hectares (536,000 gross acres) in the Sable Island area. One exploratory well was
completed in 2000 in that area, without commercial success. In 2004, five of these exploration
licences totalling about 196,000 gross hectares (484,000 gross acres) were allowed to expire. Also
in 1999, the Company acquired a 100 percent interest in two exploration licences for about 225,000
gross hectares (556,000 gross acres) farther offshore in deeper water. A 3-D seismic evaluation
program was begun in 2000 in that area, and was completed in 2001, and in 2002 there were 3-D
seismic and geological evaluations. In 2002, the Company signed a farmout agreement with another
company whereby that company earned a 30 percent interest in these licences by participating in the
first exploration well. In 2003, one exploratory well was drilled on these licences, without
commercial success. In 2004, the Company allowed the undrilled licence to expire while retaining
its 70 percent interest in the other exploration licence for about 113,000 gross hectares (279,000
gross acres). In early 2001, the Company acquired about a 17 percent interest in three additional
deep water exploration licences for about 475,000 gross hectares (1,174,000 gross acres). In 2004, these licences were allowed to expire. The Company is not
planning further exploration in these areas. 10




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##### Table of Contents



In early 2004, the Company acquired a 25 percent interest in
eight deep water exploration licences offshore Newfoundland in the Orphan Basin for about 2,125,000
gross hectares (5,251,000 gross acres). In February of 2005, the
Company reduced its interest to 15% through an agreement with another
company. The Companys share of proposed exploration spending is
about $100 million with a minimum commitment of about $25 million. In 2004, the Company
participated in a 3-D seismic survey in this area.
      In 2004, the Company converted nine exploration permits in the Laurentian basin area offshore
Newfoundland and Labrador to a single exploration licence for about 192,000 gross hectares (474,000
gross acres). The Company holds a 100 percent interest in this licence. 
 Petroleum Products 
 Supply
      To supply the requirements of its own refineries and condensate requirements for blending with
crude bitumen, the Company supplements its own production with substantial purchases from others.
      The Company purchases domestic crude oil at freely negotiated prices from a number of sources.
Domestic purchases of crude oil are generally made under 30-day contracts. There are no domestic
purchases of crude oil under contracts longer than 60 days.
      Crude oil from foreign sources is purchased by the Company at competitive prices mainly
through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil
throughout the world). 
 Refining
      The Company owns and operates four refineries. Two of these, the Sarnia refinery and the
Strathcona refinery, have lubricating oil production facilities. The Strathcona refinery processes
Canadian crude oil, and the Dartmouth, Sarnia and Nanticoke refineries process a combination of
Canadian and foreign crude oil. In addition to crude oil, the Company purchases finished products
to supplement its refinery production.
      In 2004, capital expenditures of about $159 million were made at the Companys refineries. About
60 percent of those expenditures were on new facilities required to meet Government of Canada
regulations on the sulphur level in motor fuels with the remaining expenditures being on safety and
efficiency improvements, and environmental control projects.
      The approximate average daily volumes of refinery throughput during the five years ended
December 31, 2004, and the daily rated capacities of the refineries at December 31, 1999 and 2004,
were as follows: Average Daily Volumes of
    
    
    Daily RatedRefinery Throughput (1)
    
    
    Capacities atYear Ended December 31
    
    
    December 31 (2)2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000
    
    
    2004
    
    
    1999(thousands of cubic metres)Strathcona, Alberta
    
    
    27.1
    
    
    
    27.6
    
    
    
    26.0
    
    
    
    25.4
    
    
    
    27.0
    
    
    
    29.8
    
    
    
    28.6Sarnia, Ontario
    
    
    17.2
    
    
    
    14.7
    
    
    
    16.5
    
    
    
    16.5
    
    
    
    16.2
    
    
    
    19.2

    
    
    
    19.2Dartmouth, Nova Scotia
    
    
    12.7
    
    
    
    13.0
    
    
    
    12.5
    
    
    
    12.3
    
    
    
    11.2
    
    
    
    13.1
    
    
    
    13.1Nanticoke, Ontario
    
    
    17.3
    
    
    
    16.3
    
    
    
    16.2
    
    
    
    17.2
    
    
    
    17.2
    
    
    
    17.8
    
    
    
    17.8Total
    
    
    74.3
    
    
    
    71.6
    
    
    
    71.2
    
    
    
    71.4
    
    
    
    71.6
    
    
    
    79.9
    
    
    
    78.7
 Average Daily Volumes of
    
    
    Daily RatedRefinery Throughput (1)
    
    
    Capacities atYear Ended December 31
    
    
    December 31 (2)2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000
    
    
    2004
    
    
    1999(thousands of barrels)Strathcona, Alberta
    
    
    170
    
    
    
    174
    
    
    
    163
    
    
    
    160
    
    
    
    170
    
    
    
    187
    
    
    
    180Sarnia, Ontario
    
    
    108
    
    
    
    92
    
    
    
    104
    
    
    
    104
    
    
    
    102
    
    
    
    121
    
    
    
    121Dartmouth, Nova Scotia
    
    
    80
    
    
    
    82
    
    
    
    78
    
    
    
    77
    
    
    
    70
    
    
    
    82
    
    
    
    82Nanticoke, Ontario
    
    
    109
    
    
    
    102
    
    
    
    102
    
    
    
    108
    
    
    
    108
    
    
    
    112
    
    
    
    112Total
    
    
    467
    
    
    
    450
    
    
    
    447
    
    
    
    449
    
    
    
    450

    
    
    
    502
    
    
    
    495
   (1)
    
    Refinery throughput is the volume of crude oil and feedstocks that is processed in
the refinery atmospheric distillation units.(2)
    
    Rated capacities are based on definite specifications as to types of crude oil and
feedstocks that are processed in the refinery atmospheric distillation units, the products to be
obtained and the refinery process, adjusted to include an estimated allowance for normal
maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities
due to changes in refinery operation and the type of crude oil available for processing. Refinery throughput was 93 percent of capacity in 2004, three percent higher than the previous
year. 11




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##### Table of Contents



Distribution
      The Company maintains a nation-wide distribution system, including 30 primary terminals, to
handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker,
rail and road transport. The Company owns and operates crude oil, natural gas liquids and products
pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products
and three crude oil pipeline companies.
      At December 31, 2004, the Company owned and operated two barges. These vessels are used
primarily for domestic transportation of refined petroleum products.  
 Marketing
 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(thousands a day)Gasolines:Cubic metres
    
    
    33.2
    
    
    
    33.0
    
    
    
    32.9
    
    
    
    32.3
    
    
    
    32.0Barrels
    
    
    209
    
    
    
    208
    
    
    
    207
    
    
    
    203
    
    
    
    201Heating, Diesel and Jet Fuels:Cubic metres
    
    
    27.3
    
    
    
    26.2
    
    
    
    25.0
    
    
    
    26.5
    
    
    
    27.5Barrels
    
    
    172
    
    
    
    165
    
    
    
    157
    
    
    
    166
    
    
    
    173Heavy Fuel Oils:Cubic metres
    
    
    5.9
    
    
    
    5.4
    
    
    
    4.9
    
    
    
    5.4
    
    
    
    5.1Barrels
    
    
    37
    
    
    
    34
    
    
    
    31
    
    
    
    34
    
    
    
    32Lube Oils and Other Products (1):Cubic metres
    
    
    7.0
    
    
    
    5.8
    
    
    
    6.4
    
    
    
    5.4
    
    
    
    5.0Barrels
    
    
    44
    
    
    
    36
    
    
    
    41
    
    
    
    34
    
    
    
    31Net petroleum product sales:Cubic metres
    
    
    73.4
    
    
    
    70.4
    
    
    
    69.2
    
    
    
    69.6
    
    
    
    69.6Barrels
    
    
    462
    
    
    
    443
    
    
    
    436
    
    
    
    437
    
    
    
    437Sales under purchase and sale agreements:Cubic metres
    
    
    14.2
    
    
    
    14.6
    
    
    
    13.9
    
    
    
    11.6
    
    
    
    10.7Barrels
    
    
    89
    
    
    
    92
    
    
    
    87
    
    
    
    73
    
    
    
    67Total:Cubic metres
    
    
    87.6
    
    
    
    85.0
    
    
    
    83.1
    
    
    
    81.2
    
    
    
    80.3Barrels
    
    
    551
    
    
    
    535
    
    
    
    523
    
    
    
    510
    
    
    
    504
   (1)
    
    Includes 1.0 thousand cubic metres (6 thousand barrels) per day of butane commencing in
2002. Butane is not included in prior years. The total domestic sales of petroleum products as a percentage of total sales of
petroleum products during the five years ended December 31, 2004, were as follows: 2004
    
    2003
    
    2002
    
    2001
    
    200093.0%
    
    93.3%
    
    91.5%
    
    93.4%
    
    94.0%
 The Company continues to evaluate and adjust its Esso service station and distribution
system to increase productivity and efficiency.
      During 2004, the Company closed or debranded about 140 Esso service stations, about 60 of
which were Company owned, and added about 50 sites. The Companys average annual throughput in 2004
per Esso service station was 3.4 million litres, the same as for 2003. Average throughput per
Company owned Esso service station was 5.5 million litres in 2004, an increase of about 0.3 million
litres from 2003. 12




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##### Table of Contents



Chemicals
      The Companys Chemicals operations manufacture and market ethylene, benzene, aromatic and
aliphatic solvents, plasticizer intermediates and polyethylene resin. Its major petrochemical and
polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the Companys petroleum refinery. There is also a heptene and octene plant located in Dartmouth,
Nova Scotia.
      The Companys average daily sales of petrochemicals during the five years ended December 31,
2004, were as follows: 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(thousands a day)Petrochemicals:Tonnes
    
    
    3.3
    
    
    
    3.3
    
    
    
    3.5
    
    
    
    3.3
    
    
    
    3.1Tons
    
    
    3.6
    
    
    
    3.6
    
    
    
    3.9
    
    
    
    3.6
    
    
    
    3.4
 
 Research
      In 2004, the Companys research expenditures in Canada, before deduction of investment tax
credits, were $40 million, as compared with $36 million in 2003 and $50 million in 2002. Those
funds were used mainly for developing improved heavy crude oil recovery methods and better
lubricants.
      A research facility to support the Companys natural resources operations is located in
Calgary, Alberta. Research in these laboratories is aimed at developing new technology for the
production and processing of crude bitumen. About 40 people were involved in this type of research
in 2004. The Company also participated in bitumen recovery and processing research for tar sands
development through its interest in Syncrude, which maintains research facilities in Edmonton,
Alberta and through research arrangements with others.
      In Company laboratories in Sarnia, Ontario, research is mainly conducted on the development
and improvement of lubricants and fuels. About 120 people were employed in this type of research at
the end of 2004. Also in Sarnia, there are about 15 people engaged in new product development for
the Companys and Exxon Mobil Corporations polyethylene injection and rotational molding
businesses.
      The Company has scientific research agreements with affiliates of Exxon Mobil Corporation
which provide for technical and engineering work to be performed by all parties, the exchange of
technical information and the assignment and licensing of patents and patent rights. These
agreements provide mutual access to scientific and operating data related to nearly every phase of
the petroleum and petrochemical operations of the parties. 
 Environmental Protection
      The Company is concerned with and active in protecting the environment in connection with its
various operations. The Company works in cooperation with government agencies and industry
associations to deal with existing and to anticipate potential environmental protection issues. In
the past five years, the Company has spent about $825 million on environmental protection and
facilities. In 2004, the Companys capital expenditures relating to environmental protection
totaled approximately $130 million, and are expected to be about $350 million in 2005. The
increased environmental expenditures over the past three years primarily reflect spending on two
major projects. One project completed in 2004, costing $600 million, reduced sulphur in motor
gasolines, meeting a requirement of the Government of Canada a year in advance. The second project
underway in 2004 is to meet a new Government of Canada regulation requiring ultra-low sulphur
on-road diesel fuel commencing in 2006 and which is to be fully implemented in 2007. In 2004, there
were capital expenditures of about $90 million on this second project, which is expected to cost
about $500 million when completed. Capital expenditures on safety related projects in 2004 were
approximately $20 million. 
 Human Resources
      At December 31, 2004, the Company employed full-time approximately 6,100 persons compared with
about 6,300 at the end of 2003 and 6,500 at the end of 2002. About eight percent of those employees
are members of unions. The Company continues to maintain a broad range of benefits, including
illness, disability and survivor benefits, a savings plan and pension plan. 
 Competition
      The Canadian petroleum, natural gas and chemical industries are highly competitive.
Competition includes the search for and development of new sources of supply, the construction and
operation of crude oil and refined products pipelines and the refining, distribution and marketing
of petroleum products and chemicals. The petroleum industry also competes with other industries in
supplying energy, fuel and other needs of consumers. 13




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##### Table of Contents



Government Regulation
      Petroleum and Natural Gas Rights
      Most of the Companys petroleum and natural gas rights were acquired from governments, either
federal or provincial. Reservations, permits or licences are acquired from the provinces for cash
and entitle the holder to obtain leases upon completing specified work. Leases may also be acquired
for cash. A lease entitles the holder to produce petroleum or natural gas from the leased lands.
The holder of a licence relating to Canada Lands and the Atlantic Offshore is generally required to
make cash payments or to undertake specified work or amounts of exploration expenditures in order
to retain the holders interest in the land and may become entitled to produce petroleum or natural
gas from the licenced land. Crude Oil
      Production
      The maximum allowable gross production of crude oil from wells in Canada is subject to
limitation by various regulatory authorities on the basis of engineering and conservation
principles. Exports
      Export contracts of more than one year for light crude oil and petroleum products and two
years for heavy crude oil (including crude bitumen) require the prior approval of the National
Energy Board (the NEB) and the Government of Canada. Natural Gas
      Production
      The maximum allowable gross production of natural gas from wells in Canada is subject to
limitation by various regulatory authorities on the basis of engineering and conservation
principles. A permit is required from the Alberta Energy and Utilities Board, subject to the
approval of the Province of Alberta, for the removal from Alberta of natural gas produced in that
province. Exports
      The Government of Canada has the authority to regulate the export price for natural gas and
has a gas export pricing policy which accommodates export prices for natural gas negotiated between
Canadian exporters and U.S. importers.
      Exports of natural gas from Canada require approval by the NEB and the Government of Canada.
The Government of Canada allows the export of natural gas by NEB order without volume limitation
for terms not exceeding 24 months. Royalties
      The Government of Canada and the provinces in which the Company produces crude oil and natural
gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they
do not own the mineral rights.
      Different royalties are imposed by the Government of Canada and each of the producing provinces.
Royalties imposed by the producing provinces on crude oil vary depending on well production
volumes, selling prices, recovery methods and the date of initial production. Royalties imposed by
the producing provinces on natural gas and natural gas liquids vary depending on well production
volumes, selling prices and the date of initial production. For information with respect to royalty
rates for Norman Wells, Cold Lake and Syncrude, see Natural Resources  Petroleum and Natural Gas
Production. Investment Canada Act
      The Investment Canada Act requires Government of Canada approval, in certain cases, of the
acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In
certain circumstances, the acquisition of natural resource properties may be considered to be a
transaction that constitutes an acquisition of control of a Canadian business requiring Government
of Canada approval. The Act requires notification of the establishment of new unrelated businesses
in Canada by entities not controlled by Canadians, but does not require Government of Canada
approval except when the new business is related to Canadas cultural heritage or national
identity. By virtue of the majority stock ownership of the Company by Exxon Mobil Corporation, the
Company is considered to be an entity which is not controlled by Canadians. 
 The Company Online
      The Companys website www.imperialoil.cacontains a variety of corporate and investor
information which are available free of charge, including the Companys annual report on Form 10-K,
quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports.
These reports are made available as soon as reasonably practicable after they are filed or
furnished to the U.S. Securities and Exchange Commission. 14




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##### Table of Contents



Item 2. Properties.
      Reference is made to Item 1 above, and for the reserves of the Syncrude mining operations and
oil and gas producing activities, reference is made to Item 8 of this report. 
 Item 3. Legal Proceedings.
      Not applicable. 
 Item 4. Submission of Matters to a Vote of Security Holders.
      Not applicable. 
 PART II 
  Item 5.
    Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Information for Security Holders Outside Canada
      Cash dividends paid to shareholders resident in countries with which Canada has an income tax
convention are usually subject to a Canadian nonresident withholding tax of 15 percent.
      The withholding tax is reduced to five percent on dividends paid to a corporation resident in
the United States that owns at least 10 percent of the voting shares of the Company.
      The Company is a qualified foreign corporation for purposes of the new reduced U.S. capital
gains tax rates (15 percent and 5 percent for certain individuals) which are applicable to
dividends paid by U.S. domestic corporations and qualified foreign corporations.
      There is no Canadian tax on gains from selling shares or debt instruments owned by
nonresidents not carrying on business in Canada. Quarterly Financial and Stock Trading Data 2004
    
    
    2003three months ended
    
    
    three months endedMar. 31
    
    
    June 30
    
    
    Sept. 30
    
    
    Dec. 31
    
    
    Mar. 31
    
    
    June 30
    
    
    Sept. 30
    
    
    Dec. 31Per-share information(dollars)Dividends (declared quarterly)
    
    
    0.22
    
    
    
    0.22
    
    
    
    0.22
    
    
    
    0.22
    
    
    
    0.21
    
    
    
    0.22
    
    
    
    0.22
    
    
    
    0.22Share prices(dollars)Toronto Stock ExchangeHigh
    
    
    64.45
    
    
    
    64.25
    
    
    
    66.76
    
    
    
    73.65
    
    
    
    47.80
    
    
    
    47.40
    
    
    
    53.49
    
    
    
    58.22Low
    
    
    56.42
    
    
    
    58.40
    
    
    
    59.50
    
    
    
    65.28
    
    
    
    43.48
    
    
    
    43.20
    
    
    
    45.62
    
    
    
    50.16Close
    
    
    58.87
    
    
    
    62.40
    
    
    
    65.48
    
    
    
    71.15
    
    
    
    47.35
    
    
    
    47.10
    
    
    
    50.80
    
    
    
    57.53American Stock Exchange ($U.S.)High
    
    
    48.70
    
    
    
    47.13
    
    
    
    52.22
    
    
    
    62.45
    
    
    
    32.20
    
    
    
    34.99
    
    
    
    38.79
    
    
    
    44.75Low
    
    
    42.34
    
    
    
    43.17
    
    
    
    45.50
    
    
    
    51.43
    
    
    
    28.25
    
    
    
    29.94
    
    
    
    33.04
    
    
    
    37.24Close
    
    
    44.84
    
    
    
    46.82
    
    
    
    51.71
    
    
    
    59.37
    
    
    
    32.14
    
    
    
    34.92
    
    
    
    37.21
    
    
    
    44.42
 The Companys shares are listed on the Toronto Stock Exchange and are admitted to
unlisted trading on the American Stock Exchange in New York. The symbol on these exchanges for the
Companys common shares is IMO. Share prices were obtained from stock exchange records.
      As of February 28, 2005, there were 14,868 holders of record of common shares of the Company.
      During the period October 1, 2004 to December 31, 2004, the Company issued 85,925 common shares for
$46.50 per share as a result of the exercise of stock options by the holders of the stock options,
who are all employees or former employees of the Company, in sales of those common shares outside
the U.S.A. which were not registered under the Securities Act in reliance on Regulation S
thereunder. Issuer purchases of equity securities (1) (a) Total number
    
    
    
    
    
    
    
    (c) Total number of shares
    
    
    (d) Maximum number (or approximateof shares
    
    
    (b) Average price
    
    
    purchased as part
    
    
    dollar value) or shares that(or units)
    
    
    paid per share
    
    
    of publicly announced
    
    
    may yet be purchased underPeriod
    
    
    purchased
    
    
    (or unit)
    
    
    plans or programs
    
    
    the plans or programsOctober 2004
(October 1 - October 31)
    
    
    
    909,277
    
    
    
    $
    69.34
    
    
    
    
    909,277
    
    
    
    
    12,981,800November 2004
(November 1 - November 30)
    
    
    
    2,043,336
    
    
    
    $
    70.61
    
    
    
    
    2,043,336
    
    
    
    
    10,903,650December 2004
(December 1 - December 31)
    
    
    
    1,198,579
    
    
    
    $
    70.25
    
    
    
    
    1,198,579
    
    
    
    
    9,670,839
   (1)
    
    The purchases were pursuant to a 12 month normal course share purchase program
that was renewed on June 23, 2004 under which the Company may purchase up to 17,864,398 of its
outstanding common shares less any shares purchased by the employee savings plan and Company
pension fund. If not previously terminated, the program will terminate on June 22, 2005. 15




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##### Table of Contents



Item 6. Selected Financial Data. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Total revenues
    
    $
    22,460
    
    
    $
    19,208
    
    
    $
    17,042
    
    
    $
    17,253
    
    
    $
    18,051Net income
    
    
    2,052
    
    
    
    1,705
    
    
    
    1,214
    
    
    
    1,223
    
    
    
    1,408Total assets
    
    
    14,027
    
    
    
    12,337
    
    
    
    12,003
    
    
    
    10,888
    
    
    
    11,266Long term debt
    
    
    367
    
    
    
    859
    
    
    
    1,466
    
    
    
    1,029
    
    
    
    1,037Other long term obligations
    
    
    1,525
    
    
    
    1,314
    
    
    
    1,822
    
    
    
    1,303
    
    
    
    1,110(dollars)Net income/share  basic
    
    
    5.75
    
    
    
    4.58
    
    
    
    3.20
    
    
    
    3.11
    
    
    
    3.37Net income/share  diluted
    
    
    5.74
    
    
    
    4.58
    
    
    
    3.20
    
    
    
    3.11
    
    
    
    3.37Cash dividends/share
    
    
    0.88
    
    
    
    0.87
    
    
    
    0.84
    
    
    
    0.83
    
    
    
    0.78
 Reference is made to the table setting forth exchange rates for the Canadian dollar,
expressed in U.S. dollars, on page 2 of this report. 
 Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operation. Overview
      While commodity prices remain volatile on a short term basis depending upon supply and demand,
the Companys investment decisions are based on long term outlooks. The corporate plan is a
fundamental annual management process that is the basis for setting near term operating and capital
objectives in addition to providing the longer term economic assumptions used for investment
evaluation purposes. Annual plan volumes are based on individual field production profiles updated
annually. Prices for natural gas and other products used for investment evaluation purposes are
based on corporate plan assumptions that are developed annually. Potential investment opportunities
are tested over a wide range of economic scenarios to establish the resiliency of each opportunity.
Once investments are made, a reappraisal process is completed. Business environment and outlook 
Natural resources
      The Company produces crude oil and natural gas for sale into large North American
markets. Economic and population growth are expected to remain the primary drivers of energy
demand. The Company expects the global economy to grow at an average rate of about three percent
per year through 2030. World energy demand should grow by about two percent per year, and oil and
gas are expected to account for about 60 percent of world energy supply by 2030. Over the same
period, the Canadian economy is expected to grow at an average rate of two percent per year, and
Canadian demand for energy at a rate of about one percent per year. Oil and gas are expected to
continue to supply two-thirds of Canadian energy demand.
It is expected that Canada will also be a growing supplier of energy to U.S. markets through this
period.
      Oil products are the transportation fuel of choice for the worlds fleet of cars, trucks,
trains, ships and airplanes. Primarily because of increased demand in developing countries, oil
production is expected to increase by 50 percent or nearly 30 million barrels per day over the next
three decades. Canadas oil sands represent an important additional source of supply.
      Natural gas is expected to be the fastest growing primary energy source globally, capturing
about one-third of all incremental energy growth and approaching one quarter of global energy
supplies. Natural gas production from mature established regions in the United States and Canada is
not expected to meet increasing demand, strengthening the market opportunities for new gas supply
from Canadas frontier areas.
      Crude oil and natural gas prices are determined by global and North America markets and are
subject to changing supply and demand conditions. These can be influenced by a wide range of
factors including economic conditions, international political developments and weather. In the
past, crude oil and natural gas prices have been volatile and the Company expects that volatility
to continue.
      The Company has a large and diverse portfolio of oil and gas resources, both developed and
undeveloped, in Canada, which helps reduce the risks of dependence on potentially limited supply
sources in the upstream. With the relative maturity of conventional production in the established
producing areas of Western Canada, the Companys production is expected to come increasingly from
frontier and unconventional sources, particularly oil sands and natural gas from the Far North,
where the Company has large undeveloped resource opportunities. 16




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##### Table of Contents



Petroleum products
      The downstream continues to experience ongoing volatility in industry margins. Refining
margins are the difference between what a refinery pays for its raw materials (primarily crude oil)
and the wholesale market prices for the range of products produced (primarily gasoline, diesel
fuel, heating oil, jet fuel and fuel oil). Crude oil and many products are widely traded with
published international prices. Prices for those commodities are determined by the marketplace,
often an international marketplace, and are impacted by many factors, including global and regional
supply/demand balances, inventory levels, refinery operations, import/export balances, seasonality
and weather. Canadian wholesale prices in particular are largely determined by wholesale prices in
adjacent U.S. regions. These prices and factors are continually monitored and provide input to
operating decisions about which raw materials to buy, facilities to operate and products to make.
However, there are no reliable indicators of future market factors that accurately predict changes
in margins from period to period.
      The Companys downstream strategies are to provide customers with quality service at the
lowest total cost offer, have the lowest unit costs amongst the Companys competitors, ensure
efficient and effective use of capital and capitalize on integration with the Companys other
businesses. The Company owns and operates four refineries in Canada with distillation capacity of
502,000 barrels a day and lubricant manufacturing capacity of 9,000 barrels a day. The Companys
fuels marketing business includes retail operations across Canada serving customers through about
2,000 Esso-branded service stations, of which about 720 are Company owned or leased, and wholesale
and industrial operations through a network of 30 distribution terminals. Chemicals
      Although the current business environment is favourable, the North American petrochemical
industry is cyclical. The Companys strategy for its chemicals business is to reduce costs and
maximize value by continuing to increase the integration of its chemicals plants at Sarnia and
Dartmouth with the refineries. The Company also benefits from its integration within ExxonMobils
North American chemicals businesses, enabling the Company to maintain a leadership position in its
key market segments. Results of operations
      Net income in 2004 was $2,052 million or $5.74 a share  the best year on record  compared
with $1,705 million or $4.58 a share in 2003 (2002  $1,214 million or $3.20 a share). Higher
realizations for crude oil, stronger industry refining and petrochemical margins, and higher
volumes of Syncrude production, natural gas and petroleum products contributed positively to net
income, partly offset by lower marketing margins. Compared with 2003, these favourable
operating results were partly offset by the combined negative effects of a higher Canadian
dollar on resource and product prices of about $260 million, the absence of favourable foreign
exchange effects on the Companys U.S. dollar denominated debt of about $110 million, and lower
benefits from tax matters of about $100 million.
      Total revenues were $22.5 billion, up about 17 percent from 2003. Natural Resources
      Net income from natural resources was a record $1,487 million, up from $1,143 million in
2003 (2002 $1,042 million). The positive earnings effects of improved realizations for crude oil
and natural gas, combined with higher Syncrude, natural gas and natural gas liquids (NGLs) volumes
were partly offset by lower Cold Lake bitumen production, lower benefits from tax matters and the
negative effects of a higher Canadian dollar.
      Resource revenues were $6.6 billion, up from $5.6 billion in 2003 (2002  $4.9 billion). The
main reasons for the increase were higher prices for crude oil and increased natural gas and
Syncrude volumes. Financial statistics 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Net income
    
    $
    1,487
    
    
    $
    1,143
    
    
    $
    1,042
    
    
    $
    941
    
    
    $
    1,165Revenues
    
    
    6,625
    
    
    
    5,648
    
    
    
    4,894
    
    
    
    5,321
    
    
    
    5,900
 U.S. dollar world oil prices were considerably higher in 2004 than in the previous year.
The annual average price of Brent crude oil, the most actively traded North Sea crude and a common
benchmark of world oil markets, was $38 (U.S.) a barrel in 2004, a more than 30 percent increase
over the average price of $29 in 2003 (2002  $25).
      However, increases in the Companys Canadian dollar realizations for conventional crude oil
and Cold Lake bitumen were dampened by the effects of a higher Canadian dollar. Average
realizations for conventional crude oil during the year were $48.96 (Cdn) a barrel, an increase of
22 percent from that of $40.10 in 2003 (2002  $36.81). 17




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##### Table of Contents



Average prices for Canadian heavy crude oil were higher in 2004, but by less than the relative
increase in light crude oil prices, as increased supply of heavy crude oil widened the average
spread between light and heavy crude. The price of Bow River, a benchmark Canadian heavy crude oil,
increased by 15 percent in 2004, much less than the increase in prices for Canadian light crude
oil. Cold Lake bitumen realizations in U.S. dollars averaged 19 percent higher in 2004 than in
2003. Average realizations for Cold Lake bitumen were only about 10 percent higher than the
previous year, reflecting the effect of the higher Canadian dollar.
      Prices for Canadian natural gas in 2004 were essentially unchanged from the previous year. The
average of 30 day spot prices for natural gas at the AECO hub in Alberta was about $6.80 a thousand
cubic feet in 2004, compared with $6.70 in 2003 (2002  $4.10).
      The Companys average realizations on natural gas sales were $6.78 a thousand cubic feet,
compared with $6.60 in 2003 (2002  $4.02). Average realizations and prices 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Conventional crude oil realizations (a barrel)
    
    $
    48.96
    
    
    $
    40.10
    
    
    
    $36.81
    
    

    
    $35.56
    
    
    $
    41.52Natural gas liquids realizations (a barrel)
    
    
    33.78
    
    
    
    32.09
    
    
    
    23.38
    
    
    
    29.31
    
    
    
    29.57Natural gas realizations (a thousand cubic feet)
    
    
    6.78
    
    
    
    6.60
    
    
    
    4.02
    
    
    
    5.72
    
    
    
    4.99Par crude oil price at Edmonton (a barrel)
    
    
    53.26
    
    
    
    43.93
    
    
    
    40.44
    
    
    
    39.64
    
    
    
    45.02Heavy crude oil price at Hardisty (Bow River,
a barrel)
    
    
    37.98
    
    
    
    33.00
    
    
    
    31.85
    
    
    
    25.11
    
    
    
    34.49
 Gross production of crude oil and NGL increased to 262,000 barrels a day from 256,000
barrels in 2003 (2002  247,000).
      Gross bitumen production at the Companys wholly owned facilities at Cold Lake decreased to
126,000 barrels a day from 129,000 barrels in 2003 (2002  112,000), due to the cyclic nature of
production at Cold Lake.
      Production from the Syncrude operation, in which the Company has a 25 percent interest,
increased during 2004 as a result of reduced turnaround activities. Gross production of upgraded
crude oil increased to a record 238,000 barrels a day from 211,000 barrels in 2003 (2002 
229,000). The Companys share of average gross production increased to 60,000 barrels a day from
53,000 barrels in 2003 (2002  57,000).
      Gross production of conventional oil decreased to 43,000 barrels a day from 46,000 barrels in
2003 (2002  51,000) as a result of the natural decline in Western Canadian reservoirs.
      Gross production of NGLs available for sale averaged 33,000 barrels a day in 2004, up from
28,000 barrels in 2003 (2002  27,000).
      Gross production of natural gas increased to 569 million cubic feet a day from 513 million in
2003 (2002  530 million). Higher natural gas and NGL volumes were mainly a result of the full year
production of natural gas from the Wizard Lake gas cap in Alberta, which began in the third quarter
of 2003. Crude oil and NGLs  production and sales (a) 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000gross
    
    
    net
    
    
    gross
    
    
    net
    
    
    gross
    
    
    net
    
    
    gross
    
    
    net
    
    
    gross
    
    
    net(thousands of barrels a day)Conventional crude oil
    
    
    43
    
    
    
    33
    
    
    
    46
    
    
    
    35
    
    
    
    51
    
    
    
    39
    
    
    
    55
    
    
    
    42
    
    
    
    60
    
    
    
    46Cold Lake
    
    
    126
    
    
    
    112
    
    
    
    129
    
    
    
    116
    
    
    
    112
    
    
    
    106
    
    
    
    128
    
    
    
    121
    
    
    
    119
    
    
    
    102Syncrude
    
    
    60
    
    
    
    59
    
    
    
    53
    
    
    
    52
    
    
    
    57
    
    
    
    57
    
    
    
    56
    
    
    
    52
    
    
    
    51
    
    
    
    42Total crude oil production
    
    
    229
    
    
    
    204
    
    
    
    228
    
    
    
    203
    
    
    
    220
    
    
    
    202
    
    
    
    239
    
    
    
    215
    
    
    
    230
    
    
    
    190NGLs available for sale
    
    
    33
    
    
    
    26
    
    
    
    28
    
    
    
    22
    
    
    
    27
    
    
    
    21
    
    
    
    28
    
    
    
    22
    
    
    
    30
    
    
    
    23Total crude oil and NGL production
    
    
    262
    
    
    
    230
    
    
    
    256
    
    
    
    225
    
    
    
    247
    
    
    
    223
    
    
    
    267
    
    
    
    237
    
    
    
    260
    
    
    
    213Cold Lake sales, including diluent (b)
    
    
    167
    
    
    
    
    
    
    
    170
    
    
    
    
    
    
    
    145
    
    
    
    
    
    
    
    167
    
    
    
    
    
    
    
    156NGL sales
    
    
    42
    
    
    
    
    
    
    
    39
    
    
    
    
    
    
    
    40
    
    
    
    
    
    
    
    43
    
    
    
    
    
    
    
    42
 Natural gas  production and sales (a) 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000gross
    
    
    net
    
    
    gross
    
    
    net
    
    
    gross
    
    
    net
    
    
    gross
    
    
    net
    
    
    gross
    
    
    net(millions of cubic feet a day)Production (c)
    
    
    569
    
    
    
    518
    
    
    
    513
    
    
    
    457
    
    
    
    530
    
    
    
    463
    
    
    
    572
    
    
    
    466
    
    
    
    526
    
    
    
    459Sales
    
    
    520
    
    
    
    
    
    
    
    460
    
    
    
    
    
    
    
    499
    
    
    
    
    
    
    
    502
    
    
    
    
    
    
    
    419
   (a)
    
    Daily volumes are calculated by dividing total volumes for the year by the number of
days in the year. Gross production is the Companys share of production (excluding purchases)
before deducting the shares of mineral owners or governments or both. Net production excludes
those shares.(b)
    
    Includes natural gas condensate added to the Cold Lake bitumen to facilitate transportation
to market by pipeline.(c)
    
    Production of natural gas includes amounts used for internal consumption with the exception
of amounts reinjected. Operating costs increased by seven percent in 2004. The main factor was higher
depreciation and depletion expenses in line with higher production volumes. 18




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##### Table of Contents



Petroleum Products 
 Financial statistics 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Net income
    
    $
    500
    
    
    $
    407
    
    
    $
    127
    
    
    $
    353
    
    
    $
    313Revenues
    
    
    19,211
    
    
    
    16,058
    
    
    
    14,434
    
    
    
    14,405
    
    
    
    15,120
 Sales of petroleum products 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions of litres a day (a))Gasolines
    
    
    33.2
    
    
    
    33.0
    
    
    
    32.9
    
    
    
    32.3
    
    
    
    32.0Heating, diesel and jet fuels
    
    
    27.3
    
    
    
    26.2
    
    
    
    25.0
    
    
    
    26.5
    
    
    
    27.5Heavy fuel oils
    
    
    5.9
    
    
    
    5.4
    
    
    
    4.9
    
    
    
    5.4
    
    
    
    5.1Lube oils and other products
    
    
    7.0
    
    
    
    5.8
    
    
    
    6.4
    
    
    
    5.4
    
    
    
    5.0Net petroleum products sales
    
    
    73.4
    
    
    
    70.4
    
    
    
    69.2
    
    
    
    69.6
    
    
    
    69.6Sales under purchase and sale agreements
    
    
    14.2
    
    
    
    14.6
    
    
    
    13.9
    
    
    
    11.6
    
    
    
    10.7Total sales of petroleum products
    
    
    87.6
    
    
    
    85.0
    
    
    
    83.1
    
    
    
    81.2
    
    
    
    80.3Total domestic sales of petroleum products
(percent)
    
    
    93.0
    
    
    
    93.3
    
    
    
    91.5
    
    
    
    93.4
    
    
    
    94.0
 Refinery utilization 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions of litres a day (a))Total refinery throughput (b)
    
    
    74.3
    
    
    
    71.6
    
    
    
    71.2
    
    
    
    71.4
    
    
    
    71.6Refinery capacity at December 31
    
    
    79.9
    
    
    
    79.9
    
    
    
    79.4
    
    
    
    79.1
    
    
    
    78.7Utilization of total refinery capacity (percent)
    
    
    93
    
    
    
    90
    
    
    
    90
    
    
    
    90
    
    
    
    91
   (a)
    
    Volumes a day are calculated by dividing total volumes for the year by the number of
days in the year.(b)
    
    Crude oil and feedstocks sent directly to atmospheric distillation
units. Margins were stronger in the refining segment of the industry in 2004 compared with those
in 2003, as international wholesale product prices increased more than raw material costs. However,
the effects of higher international margins were reduced partially by a higher Canadian dollar. Retail margins in the fuels marketing area were lower in 2004, reflecting the impact
of highly competitive markets.
      Throughput at the refineries has increased with refinery capacity utilization averaging a
record 93 percent during 2004, compared with 90 percent in 2003 (2002  90 percent).
      The Companys total sales volumes, including those resulting from reciprocal supply agreements
with other companies, were 87.6 million litres a day, compared with 85 million litres in 2003 (2002
 83.1 million). Excluding sales resulting from reciprocal agreements, sales were 73.4 million litres a day,
compared with 70.4 million litres in 2003 (2002  69.2 million).
      Operating costs increased by about two percent in 2004 from the previous year, mainly because
of higher energy, environmental and depreciation costs. Chemicals
      Net income from chemical operations was $100 million in 2004, compared with $37 million in
2003 (2002  $52 million). Strong industry polyethylene and benzene margins were the main factors
contributing to the improvement. Financial statistics 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Net income
    
    $
    100
    
    
    $
    37
    
    
    $
    52
    
    
    $
    23
    
    
    $
    59Revenues
    
    
    1,509
    
    
    
    1,232
    
    
    
    1,164
    
    
    
    1,175
    
    
    
    1,173
 19




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##### Table of Contents



Sales volumes 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(thousands of tonnes a day
(a))Polymers & basic chemicals
    
    
    2.7
    
    
    
    2.4
    
    
    
    2.5
    
    
    
    2.4
    
    
    
    2.2Intermediates and other
    
    
    0.6
    
    
    
    0.9
    
    
    
    1.0
    
    
    
    0.9
    
    
    
    0.9Total chemicals
    
    
    3.3
    
    
    
    3.3
    
    
    
    3.5
    
    
    
    3.3
    
    
    
    3.1
   (a)
    
    Volumes a day are calculated by dividing total volumes for the year by the number of
days in the year. Total revenues from chemical operations were $1,509 million, compared with $1,232 million
in 2003 (2002  $1,164 million). Higher prices for polyethylene, intermediate chemicals and
aromatics were the contributing factors.
      The average industry price of polyethylene was $1,584 a tonne in 2004, up 12 percent from
$1,415 a tonne in 2003 (2002  $1,229). Margins were higher as demand for polyethylene products
grew.
      Sales of chemicals were 3,300 tonnes a day, unchanged from 2003 (2002  3,500 tonnes), while
polyethylene and benzene sales were up three percent and 32 percent respectively over 2003.
      Operating costs in the chemicals segment for 2004 were about the same as 2003. Higher energy
costs were offset by lower depreciation expense. A significant portion of the property, plant and
equipment currently used in production and manufacturing, has been fully depreciated. Corporate and other
      Net income from corporate and other accounts was negative $35 million in 2004, compared with
positive $118 million in 2003 (2002  negative $7 million). Lower net income in 2004 was mainly due
to the absence of the favourable foreign exchange effects on the Companys U.S. dollar denominated
debt, which was replaced with Canadian dollar denominated debt in June and July of 2003. Net income for 2004 also included a nonrecurring after-tax write-down of $42
million on a north Toronto property, which was acquired in 1991 to be the Companys future Toronto
headquarters site. The remeasurement at fair value of this property reflected a change in its
intended use and managements commitment to sell following the announcement of the relocation of
the Companys headquarters to Calgary. Liquidity and capital resourcesSources and uses of cash 2004
    
    
    2003(millions of dollars)Cash provided by/(used in)Operating activities
    
    
    3,312
    
    
    
    2,227Investing activities
    
    
    (1,306
    )
    
    
    (1,426
    )Financing activities
    
    
    (1,175
    )
    
    
    (1,119
    )Increase/(decrease) in cash and cash equivalents
    
    
    831
    
    
    
    (318
    )Cash and cash equivalents at end of year
    
    
    1,279
    
    
    
    448
 Although the Company issues long term debt from time to time, internally generated funds
cover the majority of its financial requirements. The management of cash that may be temporarily
available as surplus to the Companys immediate needs is carefully controlled, both to ensure that
it is secure and readily available to meet the Companys cash requirements as they arise and to
optimize returns on cash balances.
      Cash flows from operating activities are highly dependent on crude oil and natural gas prices
and product margins. In addition, the Company will need to continually find and develop new
resources, and continue to develop and apply new technologies and recovery processes to existing
fields, in order to maintain or increase production and resulting cash flows in future periods.
Projects are in place, or underway, to increase production capacity. However, these volume
increases are subject to a variety of risks including project execution, operational outages,
reservoir performance and regulatory changes.
      The Companys financial strength enables it to make large, long term capital expenditures. The
Companys large and diverse portfolio of development opportunities and the complementary nature of
its business segments help mitigate the overall risks of the Company and associated cash flow.
Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the
risk associated with failure or delay of any single project would not have a significant impact on
the Companys liquidity or ability to generate sufficient cash flows for operations and its fixed
commitments. Cash flow from operating activities
      Cash provided by operating activities was $3,312 million, up from $2,227 million in 2003
(2002  $1,688 million). The increased cash inflow was mainly due to higher net income, timing of
scheduled income tax payments and the additional funding contributions to the employee pension plan
in 2003. 20




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##### Table of Contents



Capital and exploration expenditures



     Total capital and exploration expenditures were $1,445 million in 2004, down slightly
from $1,559 million in 2003 (2002  $1,612 million).


     The funds were used mainly to invest in growth opportunities in the oil sands and the
Mackenzie gas project, to upgrade refineries to meet low sulphur diesel requirements and to enhance
the Companys retail network. About $150 million was spent on projects related to reducing the
environmental impact of its operations and improving safety including about $90 million on the $500
million capital project to produce low sulphur diesel.


     The following table shows the Companys capital and exploration expenditures for natural
resources during the five years ending December 31, 2004: 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Exploration
    
    $
    60
    
    
    $
    57
    
    
    $
    39
    
    
    $
    49
    
    
    $
    56Production
    
    
    234
    
    
    
    181
    
    
    
    143
    
    
    
    109
    
    
    
    110Heavy oil
    
    
    819
    
    
    
    769
    
    
    
    804
    
    
    
    588
    
    
    
    268Total
    
    $
    1,113
    
    
    $
    1,007
    
    
    $
    986
    
    
    $
    746
    
    
    $
    434
 For the natural resources segment, about 90 percent of the capital and exploration
expenditures in 2004 was focused on growth opportunities. The single largest investment during the
year was the Companys share of the Syncrude expansion. Construction on the upgrader expansion made
good progress since the first quarter of 2004 when cost estimates were substantially increased and
the construction schedule was extended. At year end, the project was tracking to the revised cost
and construction schedule. The remainder of 2004 investment was directed to advancing the Mackenzie
gas project and drilling at Cold Lake and in conventional fields in Eastern and Western Canada.


     For the Mackenzie gas project, in October 2004, the main regulatory applications and
environmental impact statement were filed with the National Energy Board and other boards, panels
and agencies responsible for assessing and regulating energy developments in the Northwest
Territories. The regulatory review process is expected to take up to 24 months. A decision to
proceed with the project will be made by the co-venturers of the project after approvals are
received and any conditions attached to the approvals are assessed.


     Planned capital and exploration expenditures in natural resources are expected to be about $1
billion in 2005, with nearly 90 percent of the total focused on growth opportunities. Much of the
expenditure will be directed to the expansion now underway at Syncrude. Investments are also
planned for the ongoing development drilling at Cold Lake, the Mackenzie gas project and further
development drilling in Western Canada. Planned expenditures for exploration and development
drilling, as well as capacity additions in conventional oil and gas operations, are expected to be
about $355 million.


     The following table shows the Companys capital expenditures in the petroleum products segment
during the five years ending December 31, 2004: 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Marketing
    
    $
    85
    
    
    $
    91
    
    
    $
    133
    
    
    $
    171
    
    
    $
    121Refining and supply
    
    
    178
    
    
    
    369
    
    
    
    399
    
    
    
    118
    
    
    
    100Other (a)
    
    
    20
    
    
    
    18
    
    
    
    57
    
    
    
    50
    
    
    
    11Total
    
    $
    283
    
    
    $
    478
    
    
    $
    589
    
    
    $
    339
    
    
    $
    232
   (a)
    
    Consists primarily of purchases of real estate. For the petroleum products segment, capital expenditures decreased to $283 million in
2004, compared with $478 million in 2003 (2002  $589 million), primarily because of the completion
of the project to significantly reduce sulphur content in gasoline, which began in 2001. New
investments in 2004 included about $90 million spent on the initial phases of a three year project
to reduce sulphur content in diesel. In addition, $24 million was spent on other refinery projects
to improve energy efficiency and increase yield. Major investments were also made to upgrade the
network of Esso service stations during the year.


     Capital expenditures for the petroleum products segment in 2005 are expected to be about $550
million. Major items include additional investment in refining facilities to reduce the sulphur
content in diesel to meet regulatory requirements and continued enhancements to the Companys
retail network.


     The following table shows the Companys capital expenditures for the chemicals operations
during the five years ending December 31, 2004. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Chemicals
    
    $
    15
    
    
    $
    41
    
    
    $
    25
    
    
    $
    30
    
    
    $
    13
 Of the capital expenditures for chemicals in 2004, the major investment focused on
improving energy efficiency, yields and process control technology. 21




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##### Table of Contents



Planned capital expenditures for chemicals in 2005 will be about $20 million.


     Total capital and exploration expenditures for the Company in 2005, which will focus mainly on
growth and productivity improvements, are expected to total about $1.6 billion and will be financed
from internally generated funds. Cash flow from financing activities



     In June, the Company renewed the normal course issuer bid (share repurchase program) for
another 12 months. During 2004, the Company purchased about 14 million shares for $872 million
(2003  16 million shares for $799 million). Since the Company initiated its first share repurchase
program in 1995, the Company has purchased 233 million shares  representing about 40 percent of
the total outstanding at the start of the program  with resulting distributions to shareholders of
$6.8 billion.


     The Company declared dividends totalling 88 cents a share in 2004, up from 87 cents in 2003
(2002   84 cents). Regular per share dividends paid have increased in each of the past 10 years
and, since 1986, payments per share have grown by more than 65 percent.


     Total debt outstanding at the end of 2004, excluding the Companys share of equity Company
debt, was $1,443 million, compared with $1,432 million at the end of 2003 (2002  $1,538 million).
Debt represented 19 percent of the Companys capital structure at the end of 2004, compared with 21
percent at the end of 2003 (2002  24 percent).


     Debt related interest incurred in 2004, before capitalization of interest, was $37 million,
down from $38 million in 2003 (2002  $40 million). The average effective interest rate on the
Companys debt was 2.8 percent in 2004, compared with 2.9 percent in 2003 (2002  2.1 percent).


     On May 6, 2004, the Company filed a final short form shelf prospectus in Canada in connection
with the issuance of medium term notes over the 25 month period that the shelf prospectus remains
valid. The unsecured notes will be issued from time to time at the discretion of the Company in an
aggregate amount not to exceed $1 billion. The Company has not issued any notes under this shelf
prospectus. Financial percentages and ratios 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Total debt as a percentage of capital (a)
    
    
    19
    
    
    
    21
    
    
    
    24
    
    
    
    26
    
    
    
    25Interest coverage ratiosEarnings basis (b)
    
    
    83
    
    
    
    64
    
    
    
    46
    
    
    
    26
    
    
    
    23Cash flow basis (c)
    
    
    108
    
    
    
    80
    
    
    
    63
    
    
    
    36
    
    
    
    29
   (a)
    
    Current and long term portions of debt (page F-5) divided by debt and shareholders equity
(page F-5).(b)
    
    Net income (page F-3), debt related interest expense before capitalization (page F-20, note 15)
and income taxes (page F-3) divided by debt related interest expense before capitalization.(c)
    
    Cash flow from net income adjusted for the cumulative effect of accounting change and other
non-cash items (page F-4), current income tax expense (page F-12, note 4) and debt related interest
expense before capitalization divided by debt related interest expense before capitalization. Contractual obligations



     To more fully explain the Companys financial position, the following table shows the
Companys contractual obligations outstanding at December 31, 2004. It brings together, for easier
reference, data from the consolidated balance sheet and from individual notes to the consolidated
financial statements. Financial
    
    
    
    Payment due by periodstatement note
    
    
    
    
    
    
    2006 to
    
    
    2010 and
    
    
    Totalmillions of dollars
    
    reference
    
    
    2005
    
    
    2009
    
    
    beyond
    
    
    amountLong term debt and capital leases
    
    note 3
    
    $
    995
    
    
    $
    334
    
    
    $
    33
    
    
    $
    1,362Companys share of equity Company debt
    
    
    
    
    
    
    56
    
    
    
    
    
    
    
    
    
    
    
    56Operating leases
    
    note 12
    
    
    62
    
    
    
    181
    
    
    
    91
    
    
    
    334Unconditional purchase obligations (a)
    
    note 12
    
    
    102
    
    
    
    168
    
    
    
    55
    
    
    
    325Firm capital commitments (b)
    
    note 12
    
    
    119
    
    
    
    52
    
    
    
    
    
    
    
    171Pension obligations (c)
    
    note 7
    
    
    371
    
    
    
    91
    
    
    
    297
    
    
    
    759Asset retirement obligations (d)
    
    note 8
    
    
    36
    
    
    
    116
    
    
    
    176
    
    
    
    328Other long term agreements (e)
    
    note 12
    
    
    241
    
    
    
    378
    
    
    
    198
    
    
    
    817
   (a)
    
    Unconditional purchase obligations mainly pertain to pipeline throughput agreements.(b)
    
    Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled
approximately $171 million at the end of 2004, compared with $189 million at year end 2003. The
largest commitment outstanding at year end 2004 was associated with the Companys share of upstream capital projects of $112 million at
Syncrude and offshore Canadas East Coast. (Table continued on following page) 22




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##### Table of Contents



(c)
    
    The amount by which accumulated benefit obligations (ABO) exceeded the fair value of
fund assets at year end (page F-13, note 7). For funded pension plans, this difference was $446
million at December 31, 2004. For unfunded plans, this was the ABO amount of $313 million. The
payments by period include expected contributions to funded pension plans in 2005 and estimated
benefit payments for unfunded plans in all years.(d)
    
    Asset retirement obligations represent the discounted present value of legal obligations
associated with site restoration on the retirement of assets with determinable useful lives.(e)
    
    Other long term agreements include primarily raw material supply and transportation services
agreements. The Company was contingently liable at December 31, 2004, for a maximum of $175 million
relating to guarantees for purchasing operating equipment and other assets from its rural marketing
associates upon expiry of the associate agreement or the death or resignation of the associate. The
Company expects that the fair value of the operating equipment and other assets so purchased would
cover the maximum potential amount of future payment under the guarantees.


     Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. Based on a
consideration of all relevant facts and circumstances, the Company does not believe the ultimate
outcome of any currently pending lawsuits against the Company will have a material adverse effect
upon the Companys operations or financial condition. There are no events or uncertainties known to
management beyond those already included in reported financial information that would indicate a
material change in future operating results or financial condition. Recently issued Statement of Financial Accounting Standards



     In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement
of Financial Accounting Standards No. 123 (SFAS 123R), Share Based Payments. SFAS 123R requires
compensation costs related to share based payment arrangements to employees to be recognized in the
income statement over the period that an employee provides service in exchange for the award. The
amount of the compensation cost will be measured based on the grant date fair value of the
instruments issued. In addition, liability awards will be remeasured each reporting period through
settlement. SFAS 123R is effective as of July 1, 2005 for all awards granted or modified after that
date and for those awards granted prior to that date for which the requisite employee service has
not yet been rendered. SFAS 123R will have no impact on the Company because in 2003 the Company
adopted a policy of expensing all share based payments that is consistent with the provisions of
SFAS 123R and the requisite employee service for all prior year outstanding stock options has been
rendered. Emerging accounting and reporting issues Accounting for purchases and sales of inventory with the same counterparty


     At its November 2004 meeting, the Emerging Issues Task Force (EITF) of FASB began
discussion of Issue 04-13, Accounting for Purchases and Sales of Inventory with the Same
Counterparty. This Issue addresses the question of when it is appropriate to measure purchases and
sales of inventory at fair value and record them in cost of sales and revenues and when they should
be recorded as an exchange measured at the book value of the item sold. The EITF did not reach a
consensus on this issue, but requested the FASB staff to further explore the alternative views.


     The Company records certain purchases and sales entered into contemporaneously with the same
counterparty as cost of sales and revenues, measured at fair value as agreed upon by a
willing buyer and a willing seller. These transactions occur under contractual arrangements
that establish the agreement terms either jointly, in a single contract, or separately, in
individual contracts. Should the EITF reach a consensus on this issue, requiring these transactions
to be recorded as exchanges measured at book value, the reported amounts in operating revenues
and purchases of crude oil and products on the consolidated statement of income would be lower by
equal amounts with no impact on net income. The Company has not yet determined the amount by which
operating revenues and purchases of crude oil and products would be lower under this
interpretation. A special effort is needed to identify purchase/sale transactions from other
monetary purchases and monetary sales. A best effort estimate based on this undertaking is expected
to be available in the second quarter of 2005. The Company will disclose this information, if
material, once it is available. Critical accounting policies



     The Companys financial statements have been prepared in accordance with United States
generally accepted accounting principles (GAAP) and include estimates that reflect managements
best judgments. The Companys accounting and financial reporting fairly reflect its straightforward
business model. The Company does not use financing structures for the purpose of altering
accounting outcomes or removing debt from the balance sheet. The following summary provides further
information about the critical accounting policies and the estimates that are made by the Company
to apply those policies. It should be read in conjunction with pages F-7 to F-9. 23




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##### Table of Contents



Hydrocarbon reserves



     Proved oil, gas and synthetic crude oil reserve quantities are used as the basis of
calculating unit of production rates for depreciation and evaluating for impairment. Proved oil and
gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that
geological and engineering data demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs and deposits under existing economic and operating conditions.
Estimates of synthetic crude oil reserves are based on detailed geological and engineering
assessments of in place crude bitumen volume, the mining plan, historical extraction recovery and
upgrading yield factors, installed plant operating capacity and operating approval limits.


     The estimation of proved reserves is controlled by the Company through long standing approval
guidelines. Reserve changes are made with a well established, disciplined process driven by senior
level geoscience and engineering professionals (assisted by a central reserves group with
significant independent technical experience) culminating in reviews with and approval by senior
management and the Companys board of directors. Key features of the estimation include rigorous
peer reviewed technical evaluations and analysis of well and field performance information, and a
requirement that management make a commitment toward the development of the reserves prior to
booking. Notably, technical and other professionals involved in the process are not compensated
based on the levels of proved reserves bookings.


     Although the Company is reasonably certain that proved reserves will be produced, the timing
and ultimate recovery can be affected by a number of factors including completion of development
projects, reservoir performance and significant changes in long term oil and gas price levels.


     In compliance with the United States Securities and Exchange Commission regulatory guidance,
the Company has reported 2004 reserves on the basis of the day of December 31, 2004, prices and
costs (year end prices). Resultant changes in Cold Lake bitumen and the associated natural gas
reserves from the year end 2003 estimates, which were based on long term projections of oil and gas
prices consistent with those used in the Companys investment decision-making process, are shown in the line titled Year end price/cost revisions on page
29. The requirement to use year end prices for reserves estimation introduces single day price
focus and volatility in the valuation of reserves to be produced over the next 20 to 30 years. The
Company believes that this approach is inconsistent with the long term nature of the natural
resources business. The use of prices from a single date is not relevant to the investment
decisions made by the Company and annual variations in reserves based on such year end prices are
not of consequence in how the business is managed.


     The impact of year end prices on reserve estimation is most clearly shown at Cold Lake where
proved bitumen and associated natural gas reserves were reduced by about 485 million oil equivalent
barrels as a result of using December 31, 2004 prices, which were unusually low. Prices of Cold
Lake bitumen were strong for most of 2004, however, they began to deteriorate in the middle of the
fourth quarter and ended on December 31, 2004, 70 percent below the years average. Prices quickly
rebounded from December 31, and through January 2005 returned to levels that have restored the
reserves to the proved category.


     Performance related revisions can include upward or downward changes in previously estimated
volumes of proved reserves for existing fields due to the evaluation or revaluation of (1) already
available geologic, reservoir or production data, or (2) new geologic or reservoir data.
Performance related revisions can also include changes associated with the performance of improved
recovery projects and significant changes in either development strategy or production
equipment/facility capacity.


     The Company uses the successful efforts method to account for its exploration and production
activities. Under this method, costs are accumulated on a field by field basis with certain
exploratory expenditures and exploratory dry holes being expensed as incurred. The Company
continues to carry as an asset the cost of drilling exploratory wells that find sufficient
quantities of reserves to justify their completion as producing wells if the required capital
expenditure is made and drilling of additional exploratory wells is underway or firmly planned for
the near future. Once exploration activities demonstrate that sufficient quantities of commercially
producible reserves have been discovered, continued capitalization is dependent on project reviews,
which take place at least annually, to ensure that satisfactory progress toward ultimate
development of the reserves is being achieved. Exploratory well costs not meeting these criteria
are charged to expense. Capitalized exploratory drilling costs pending the determination of proved
reserves or the amount of suspended exploratory well costs were negligible, $2 million and $13
million at December 31, 2004, 2003 and 2002 respectively. Costs of productive wells and development
dry holes are capitalized and amortized on the unit of production method for each field. The
Company uses this accounting policy instead of the full cost method because it provides a more
timely accounting of the success or failure of the Companys exploration and production activities. Impact of reserves on depreciation



     The calculation of unit of production depreciation is a critical accounting estimate that
measures the depreciation of natural resources assets. It is the ratio of (1) actual volumes
produced to (2) total proved developed reserves (those reserves recoverable through existing wells
with existing equipment and operating methods) applied to (3) the asset cost. The volumes produced
and asset cost are known and while proved developed reserves have a high probability of
recoverability, they are based on estimates that are subject to some variability. This variability
has generally resulted in net upward revisions of proved reserves in existing fields, as more
information becomes available through research and production. Revisions have averaged 16 million
oil equivalent barrels per year over the last five years and have resulted from effective reservoir 24




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##### Table of Contents



management and the application of new technology. While the upward revisions the Company has made
over the last five years are an indicator of variability, they have had little impact on the unit
of production rates of depreciation because they have been small compared to the large proved
reserves base. Impact of reserves and prices on testing for impairment



     Proved oil and gas properties held and used by the Company are reviewed for impairment
whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets
are grouped at the lowest level for which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets.


     The Company estimates the future undiscounted cash flows of the affected properties to judge
the recoverability of carrying amounts. In general, impairment analyses are based on proved
reserves. Where probable reserves exist, an appropriately risk adjusted amount of these reserves
may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash
flows were less than its carrying value. Impairments are measured by the amount by which the
carrying value exceeds its fair value.


     The impairment evaluation triggers include a significant decrease in current and projected
prices or reserve volumes, an accumulation of project costs significantly in excess of the amount
originally expected, and historical and current negative operating losses.


     In general, the Company does not view temporarily low oil prices as a triggering event for
conducting the impairment tests. The markets for crude oil and natural gas have a history of
significant price volatility. Although prices will occasionally drop precipitously, the relative
growth/decline in supply versus demand will determine industry prices over the long term and these
cannot be accurately predicted. Accordingly, any impairment tests that the Company performs make
use of the Companys long term price assumptions for the crude oil and natural gas markets,
petroleum products and chemicals. These are the same price assumptions that are used in the
Companys annual planning and budgeting processes and are also used for capital investment
decisions.


     The standardized measure of discounted future cash flows on page 30 is based on the year end
2004 price applied for all future years, as required under Statement of Financial Accounting
Standards No. 69 (SFAS 69). Future prices used for any impairment tests will vary from the one used
in the SFAS 69 disclosure, and could be lower or higher for any given year. Retirement benefits



     The Companys pension plan is managed in compliance with the requirements of governmental
authorities and meets funding levels as determined by independent third party actuaries. Pension
accounting requires explicit assumptions regarding, among others, the discount rate for the benefit
obligations, the expected rate of return on plan assets and the long term rate of future
compensation increases. All pension assumptions are reviewed annually by senior management. These
assumptions are adjusted only as appropriate to reflect long term changes in market rates and
outlook. The long term expected rate of return on plan assets of 8.25 percent used in 2004 compares
to actual returns of 10.7 percent and 10.1 percent achieved over the last 10 and 20 year periods
ending December 31, 2004. If different assumptions are used, the expense and obligations could
increase or decrease as a result. The Companys potential exposure to changes in assumptions is
summarized in note 7 to the consolidated financial statements on page F-13. At the Company,
differences between actual returns on plan assets versus long term expected returns are not
recorded in the year the differences occur, but rather are amortized in pension expense as
permitted by GAAP, along with other actuarial gains and losses over the expected remaining service
life of employees. The Company uses the fair value of the plan assets at year end to determine the
amount of the actual gain or loss that will be amortized and does not use a moving average value of
plan assets. Pension expense represented about one percent of total expenses in 2004. Asset retirement obligations and other environmental liabilities



     Legal obligations associated with site restoration on the retirement of assets with
determinable useful lives are recognized when they are incurred, which is typically at the time the
assets are installed. The obligations are initially measured at fair value and discounted to
present value. Over time, the discounted asset retirement obligation amount will be accreted for the
change in its present value, with this effect included in operating expense. As payments to settle
the obligations occur on an ongoing basis and will continue over the lives of the operating assets,
which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long
term changes in market rates and outlook. For 2004, the obligations were discounted at six
percent and the accretion expense was $22 million, which was significantly less than one percent of
total expenses in the year. There would be no material impact on the Companys reported financial
results if a different discount rate had been used.


     Asset retirement obligations are not recognized for assets with an indeterminate useful life.
For these and non-operating assets, the Company accrues provisions for environmental liabilities
when it is probable that obligations have been incurred and the amount can be reasonably estimated. 25




---



##### Table of Contents



Asset retirement obligations and other environmental liabilities are based on engineering
estimated costs, taking into account the anticipated method and extent of remediation consistent
with legal requirements, current technology and the possible use of the location. Since these
estimates are specific to the locations involved, there are many individual assumptions underlying
the Companys total asset retirement obligations and provision for other environmental liabilities.
While these individual assumptions can be subject to change, none of them is individually
significant to the Companys reported financial results. 
 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.



     The Company is exposed to a variety of financial, operating and market risks in the course of
its business. Some of these risks are within the Companys control, while others are not. For those
risks that can be controlled, specific risk management strategies are employed to reduce the
likelihood of loss. Other risks, such as changes in international commodity prices and currency
exchange rates, are beyond the Companys control.


     Although the Government of Canada in ratifying the Kyoto Protocol agreed to restrictions of
greenhouse gas emissions by the period 2008-2012, it has not determined what measures it will
impose on companies. Consequently, attempts to assess any impact on the Company can only be
speculative. The Company will continue to monitor the development of legal requirements in this
area.


     The Companys size, strong financial position and the complementary nature of its natural
resources, petroleum products and chemicals segments help mitigate the Companys exposure to
changes in these other risks. The Companys potential exposure to these types of risk is summarized
in the table below.


     The Company does not use derivative markets to speculate on the future direction of currency
or commodity prices and does not sell forward any part of production from any business segment.


     The following table shows the estimated annual effect, under current conditions, of certain
sensitivities of the Companys after tax net income. millions of dollars after taxFour dollars (U.S.) a barrel change in crude oil prices
    
    
    +(-
    )
    
    
    200Sixty cents a thousand cubic feet change in natural gas prices
    
    
    +(-
    )
    
    
    20One cent a litre change in sales margins for total petroleum products
    
    
    +(-
    )
    
    
    170One cents (U.S.) a pound change in sales margins for polyethylene
    
    
    +(-
    )
    
    
    7One quarter percent decrease (increase) in short term interest rates
    
    
    +(-
    )
    
    
    2Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar
    
    
    +(-
    )
    
    
    260
 The amount quoted to illustrate the impact of each sensitivity represents a change of
about 10 percent in the value of the commodity or rate in question at the end of 2004. Each
sensitivity calculation shows the impact on net income that results from a change in one factor,
after tax and royalties and holding all other factors constant. While these sensitivities are applicable
under current conditions, they may not apply proportionately to larger fluctuations.


     The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar
decreased from year end 2003 by about $10 million (after tax) a year for each one cent change. This
is primarily due to the unusually low year end prices for Cold Lake bitumen, which is sold in U.S.
dollars. 
 Item 8. Financial Statements and Supplementary Data.



     Reference is made to the Index to Financial Statements on page F-1 of this report. Syncrude Mining Operations



     Syncrudes crude bitumen is contained within the unconsolidated sands of the McMurray
Formation. Ore bodies are buried beneath 15 to 45 metres (50 to 150 feet) of overburden, have
bitumen grades ranging from 4 to 14 weight percent and ore thickness of 35 to 50 metres (115 to 160
feet). Estimates of synthetic crude oil reserves are based on detailed geological and engineering
assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and
upgrading yield factors, installed plant operating capacity and operating approval limits. The
in-place volume, depth and grade are established through extensive and closely spaced core
drilling. Proven reserves include the operating Base and North mines and the Aurora mine. In
accordance with the approved mining plan, there are an estimated 1,865 million tonnes (2,055
million tons) of extractable tar sands, in the Base and North mines, with an average bitumen grade
of 10.6 weight percent. In addition, at the Aurora mine, there are an
estimated 4,060 million
tonnes (4,470 million tons) of extractable tar sands at an average bitumen grade of 11.1 weight
percent. After deducting royalties payable to the Province of Alberta, the Company estimates its 25
percent net share of proven reserves is equivalent to 120 million cubic metres (757 million
barrels) of synthetic crude oil. 26




---



##### Table of Contents



The following table sets forth the Companys share of net proven reserves of Syncrude after
deducting royalties payable to the Province of Alberta: Synthetic Crude OilBase Mine andNorth Mine
    
    
    Aurora Mine
    
    
    Total(millions of cubic metres)Beginning of year 2002
    
    
    58
    
    
    
    73
    
    
    
    131Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (3
    )
    
    
    (1
    )
    
    
    (4
    )End of year 2002
    
    
    55
    
    
    
    72
    
    
    
    127Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (2
    )
    
    
    (1
    )
    
    
    (3
    )End of year 2003
    
    
    53
    
    
    
    71
    
    
    
    124Revision of previous estimate
    
    
    (16
    )
    
    
    16
    
    
    
    0Production
    
    
    (2
    )
    
    
    (2
    )
    
    
    (4
    )End of year 2004
    
    
    35
    
    
    
    85
    
    
    
    120
 Synthetic Crude OilBase Mine andNorth Mine
    
    
    Aurora Mine
    
    
    Total(millions of barrels)Beginning of year 2002
    
    
    358
    
    
    
    463
    
    
    
    821Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (14
    )
    
    
    (7
    )
    
    
    (21
    )End of year 2002
    
    
    344
    
    
    
    456
    
    
    

    800Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (13
    )
    
    
    (6
    )
    
    
    (19
    )End of year 2003
    
    
    331
    
    
    
    450
    
    
    
    781Revision of previous estimate
    
    
    (103
    )
    
    
    100
    
    
    
    (3
    )Production
    
    
    (11
    )
    
    
    (10
    )
    
    
    (21
    )End of year 2004
    
    
    217
    
    
    
    540
    
    
    
    757
 Oil and Gas Producing Activities



     The following information is provided in accordance with the United States Statement of Financial
Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities. Results of operations 2004
    
    
    2003
    
    
    2002(millions of dollars)Sales to customers
    
    $
    2,160
    
    
    $
    2,067
    
    
    $
    1,485Intersegment sales
    
    
    976
    
    
    
    665
    
    
    
    797Total sales (1) (2)
    
    $
    3,136
    
    
    $
    2,732
    
    
    $
    2,282Production expenses (2)
    
    
    915
    
    
    
    926
    
    
    
    736Exploration expenses
    
    
    44
    
    
    
    55
    
    
    
    30Depreciation and depletion
    
    
    565
    
    
    
    463
    
    
    
    426Income taxes
    
    
    532
    
    
    
    364
    
    
    
    350Results of operations
    
    $
    1,080
    
    
    $
    924
    
    
    $
    740
 Capital and exploration expenditures 2004
    
    
    2003
    
    
    2002(millions of dollars)Property costs (3)Proved
    
    $
    
    
    
    $
    
    
    
    $
    13Unproved
    
    
    1
    
    
    
    2
    
    
    
    5Exploration costs
    
    
    43
    
    
    
    55
    
    
    
    34Development costs
    
    
    408
    
    
    
    339
    
    
    
    469Total capital and exploration expenditures
    
    $
    452
    
    
    $
    396
    
    
    $
    521
 (Table continued on following page) 27




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##### Table of Contents



Property, plant and equipment 2004
    
    
    2003(millions of dollars)Property costs (3)Proved
    
    $
    3,328
    
    
    $
    3,332Unproved
    
    
    141
    
    
    
    163Producing assets
    
    
    6,099
    
    
    
    5,775Support facilities
    
    
    122
    
    
    
    125Incomplete construction
    
    
    235
    
    
    
    200Total cost
    
    $
    9,925
    
    
    $
    9,595Accumulated depreciation and depletion
    
    
    6,514
    
    
    
    6,012Net property, plant and equipment
    
    $
    3,411
    
    
    $
    3,583
   (1)
    
    Sales of crude oil to consolidated affiliates are at market value, using posted field
prices. Sales of natural gas liquids to consolidated affiliates are at prices estimated to be
obtainable in a competitive, arms length transaction. Total sales exclude the sale of natural gas
and natural gas liquids purchased for resale.(2)
    
    Beginning in 2004, fuel consumed in operations, previously netted against total sales, has been
reclassified as production expenses. Prior period amounts have been reclassified for comparative
purposes. This reclassification has no impact on the results of operations.(3)
    
    Property costs are payments for rights to explore for petroleum and natural gas and for
purchased reserves (acquired tangible and intangible assets such as gas plants, production
facilities, and producing well costs are included under Producing assets). Proved represents
areas where successful drilling has delineated a field capable of production. Unproved represents
all other areas. Net proved developed and undeveloped reserves (1) Crude oil and natural gas liquidsConventional
    
    
    Cold Lake
    
    
    Total
    
    
    Natural Gas(millions of cubic metres)
    
    
    (billions ofcubic metres)Beginning of year 2002
    
    
    26
    
    
    
    128
    
    
    
    154
    
    
    
    40Revisions of previous estimates and improved recovery
    
    
    
    
    
    
    5
    
    
    
    5
    
    
    
    (Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (3
    )
    
    
    (6
    )
    
    
    (9
    )
    
    
    (5
    )End of year 2002
    
    
    23
    
    
    
    127
    
    
    
    150
    
    
    
    35Revisions of previous estimates and improved recovery
    
    
    
    
    
    
    1
    
    
    
    1
    
    
    
    (1
    )(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (3
    )
    
    
    (7
    )
    
    
    (10
    )
    
    
    (5
    )End of year 2003
    
    
    20
    
    
    
    121
    
    
    
    141
    
    
    
    29Performance related revisions and improved recovery
    
    
    1
    
    
    
    (3
    )
    
    
    (2
    )
    
    
    1(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (3
    )
    
    
    (6
    )
    
    
    (9
    )
    
    
    (5
    )Total before year end price/cost revisions
    
    
    18
    
    
    
    112
    
    
    
    130
    
    
    
    25Year end price/cost revisions
    
    
    0
    
    
    
    (75
    )
    
    
    (75
    )
    
    
    (3
    )End of year 2004
    
    
    18
    
    
    
    37
    
    
    
    55
    
    
    
    22
   (1)
    
    Net reserves are the Companys share of reserves after deducting the shares of mineral
owners or governments or both.All reported reserves are located in Canada. Reserves of natural gas are calculated at a
pressure of 101.325 kilopascals absolute at 15 degrees Celsius. 28




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##### Table of Contents



Crude oil and natural gas liquidsConventional
    
    
    Cold Lake
    
    
    Total
    
    
    Natural Gas(millions of barrels)
    
    
    (billions ofcubic feet)Beginning of year 2002
    
    
    165
    
    
    
    807
    
    
    
    972
    
    
    
    1,414Revisions of previous estimates and improved recovery
    
    
    3
    
    
    
    33
    
    
    
    36
    
    
    
    (26
    )(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3Production
    
    
    (22
    )
    
    
    (39
    )
    
    
    (61
    )
    
    
    (169
    )End of year 2002
    
    
    146
    
    
    
    801
    
    
    
    947
    
    
    
    1,224Revisions of previous estimates and improved recovery
    
    
    1
    
    
    
    5
    
    
    
    6
    
    
    
    (40
    )(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6Production
    
    
    (21
    )
    
    
    (43
    )
    
    
    (64
    )
    
    
    (167
    )End of year 2003
    
    
    126
    
    
    
    763
    
    
    
    889
    
    
    
    1,023Performance related revisions and improved recovery
    
    
    6
    
    
    
    (20
    )
    
    
    (14
    )
    
    
    57(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13
    )Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3Production
    
    
    (22
    )
    
    
    (41
    )
    
    
    (63
    )
    
    
    (190
    )Total before year end price/cost revisions
    
    
    110
    
    
    
    702
    
    
    
    812
    
    
    
    880Year end price/cost revisions
    
    
    5
    
    
    
    (470
    )
    
    
    (465
    )
    
    
    (89
    )End of year 2004
    

    
    115
    
    
    
    232
    
    
    
    347
    
    
    
    791
   (1)
    
    Net reserves are the Companys share of reserves after deducting the shares of mineral
owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a
pressure of 14.73 pounds per square inch at 60°F.  29




---



##### Table of Contents



Reserves data do not include certain resources of crude oil and natural gas such as those
discovered in the Beaufort Sea-Mackenzie Delta and the Arctic islands, or the resources contained
in oil sands other than those attributable to the Cold Lake Leming plant and stages 1 through 13 of
Cold Lake production operations.


     Oil equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB
conversion ratio of 6,000 cubic feet to one barrel is based on an energy-equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the
well head. No independent qualified reserves evaluator or auditor was involved in the
preparation of the reserves data. Net Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas (1) 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Crude Oil:Conventional:Cubic metres
    
    
    18
    
    
    
    20
    
    
    
    23
    
    
    
    26
    
    
    
    31Barrels
    
    
    115
    
    
    
    126
    
    
    
    146
    
    
    
    165
    
    
    
    196Oil Sands (Cold Lake crude bitumen):Cubic metres
    
    
    37
    
    
    
    121
    
    
    
    127
    
    
    
    128
    
    
    
    135Barrels
    
    
    232
    
    
    
    763
    
    
    
    801
    
    
    
    807
    
    
    
    851Total:Cubic metres
    
    
    55
    
    
    
    141
    
    
    
    150
    
    
    
    154
    
    
    
    166Barrels
    
    
    347
    
    
    
    889
    
    
    
    947
    
    
    
    972
    
    
    
    1,047Natural Gas:
    
    
    
    
    
    
    
    
    
    (billions)Cubic metres
    
    
    22
    
    
    
    29
    
    
    
    35
    
    
    
    40
    
    
    
    45Cubic feet
    
    
    791
    
    
    
    1,023
    
    
    
    1,224
    
    
    
    1,414
    
    
    
    1,572
 Net Proved Developed Reserves of Crude Oil and Natural Gas (1) 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(millions)Crude Oil:Conventional:Cubic metres
    
    
    18
    
    
    
    19
    
    
    
    22
    
    
    
    25
    
    
    
    28Barrels
    
    
    111
    
    
    
    121
    
    
    
    139
    
    
    
    157
    
    
    
    175Oil Sands (Cold Lake crude bitumen):Cubic metres
    
    
    37
    
    
    
    63
    
    
    
    49
    
    
    
    34
    
    
    
    40Barrels
    
    
    232
    
    
    
    398
    
    
    
    308
    
    
    
    216
    
    
    
    250Total:Cubic metres
    
    
    55
    
    
    
    82
    
    
    
    71
    
    
    
    59
    
    
    
    68Barrels
    
    
    343
    
    
    
    519
    
    
    
    447
    
    
    
    373
    
    
    
    425Natural Gas:
    
    
    
    
    
    
    
    
    
    (billions)Cubic metres
    
    
    20
    
    
    
    24
    
    
    
    27
    
    
    
    30
    
    
    
    35Cubic feet
    
    
    704
    
    
    
    859
    
    
    
    959
    
    
    
    1,060
    
    
    
    1,233
   (1)
    
    Net reserves are the Companys share of reserves after deducting the shares
of mineral owners or governments or both. Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves



     As required by the Financial Accounting Standards Board, the standardized measure of
discounted future net cash flows is computed by applying year end prices, costs and legislated tax
rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes
costs for future dismantlement, abandonment and rehabilitation obligations. The Company believes
the standardized measure does not provide a reliable estimate of the Companys expected future cash
flows to be obtained from the development and production of its oil and gas properties or of the
value of its proved oil and gas reserves. The standardized measure is prepared on the basis of
certain prescribed assumptions including year end prices, which represent a single point in time
and therefore may cause significant variability in cash flows from year to year as prices change.
The table below excludes the Companys interest in Syncrude. 2004
    
    
    2003
    
    
    2002(millions)Future cash flows
    
    $
    11,625
    
    
    $
    27,611
    
    
    $
    35,811Future production costs
    
    
    (3,123
    )
    
    
    (10,871
    )
    
    
    (8,940
    )Future development costs
    
    
    (1,492
    )
    
    
    (3,084
    )
    
    
    (3,117
    )Future income taxes
    
    
    (2,260
    )
    
    
    (5,543
    )
    
    
    (9,107
    )Future net cash flows
    
    
    4,750
    
    
    
    8,113
    
    
    
    14,647Annual discount of 10 percent for estimated timing of cash flows
    
    
    (1,433
    )
    
    
    (3,375
    )
    
    
    (6,446
    )Discounted future net cash flows
    
    $
    3,317
    
    
    $
    4,738
    
    
    $
    8,201
 30




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##### Table of Contents



Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and
Gas Reserves 2004
    
    
    2003
    
    
    2002(millions)Balance at beginning of year
    
    $
    4,738
    
    
    $
    8,201
    
    
    $
    2,789Changes resulting from:Sales and transfers of oil and gas produced, net of
production costs
    
    
    (2,240
    )
    
    
    (2,075
    )
    
    
    (1,645
    )Net changes in prices, development costs and
production costs
    
    
    (3,692
    )
    
    
    (4,395
    )
    
    
    9,276Extensions, discoveries, additions and improved recovery,
less related costs
    
    
    (43
    )
    
    
    22
    
    
    
    34Purchase/(sales) of minerals in place
    
    
    
    
    
    
    
    
    
    
    4Development costs incurred during the year
    
    
    345
    
    
    
    281
    
    
    
    432Revisions of previous quantity estimates
    
    
    1,838
    
    
    
    (368
    )
    
    
    111Accretion of discount
    
    
    663
    
    
    
    1,108
    
    
    
    423Net change in income taxes
    
    
    1,708
    
    
    
    1,964
    
    
    
    (3,223
    )Net change
    
    
    (1,421
    )
    
    
    (3,463
    )
    
    
    5,412Balance at end of year
    
    $
    3,317
    
    
    $
    4,738
    
    
    $
    8,201
    
 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.  
 Item 9A. Controls and Procedures. As indicated in the certifications in Exhibit 31.1 and 31.2 of this report, the Companys
principal executive officer and principal financial officer have evaluated the Companys disclosure
controls and procedures as of December 31, 2004. Based on that evaluation, these officers have
concluded that the Companys disclosure controls and procedures are appropriate and effective for
the purpose of ensuring that material information relating to the Company, including its
consolidated subsidiaries, is made known to them by others within those entities, particularly
during the period in which this annual report is being prepared.    31




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##### Table of Contents



PART III 
 Item 10. Directors and Executive Officers of the Registrant.    Last majorposition or office with theName and current principal
    
    
    Company or Exxon Mobiloccupation or employment
    
    
    Corporation
    
    
    Director since
    
    
    Holdings(1)(2)B.J. (Brian) Fischer
    
    
    Senior vice-president,
    
    
    September 1, 1992
    
    
    Common shares of
    
    
    33,963Senior vice-president,
    
    
    Chemicals division,
    
    
    
    
    
    Imperial Oil Limitedproducts and chemicals
    
    
    Imperial Oil Limiteddivision,
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    20,047Imperial Oil Limited
    
    
    
    
    
    
    
    
    Imperial Oil LimitedRestricted stock units of
    
    
    82,600Imperial Oil LimitedShares of
    
    
    0Exxon Mobil CorporationT.J. (Tim) Hearn
    
    
    President,
    
    
    January 1, 2002
    
    
    Common shares of
    
    
    25,291Chairman, president and
    
    
    Imperial Oil Limited

    
    
    
    
    
    Imperial Oil Limitedchief executive officer,Imperial Oil Limited
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    100Imperial Oil LimitedRestricted stock units of
    
    
    174,400Imperial Oil LimitedShares of
    
    
    9,453Exxon Mobil CorporationJ.M. (Jack) Mintz
    
    
    
    
    
    
    
    
    Common shares of
    
    
    100President and chief
    
    
    
    
    
    
    
    
    Imperial Oil Limitedexecutive officer,C.D. Howe Institute
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    0(public policy institute) and
    
    
    
    
    
    
    
    
    Imperial Oil Limitedprofessor, Joseph L. RotmanSchool of Management,
    
    
    
    
    
    
    
    
    Restricted stock units of
    
    
    0University of Toronto
    
    
    
    
    
    
    
    
    Imperial Oil LimitedShares of
    
    
    0Exxon Mobil CorporationR. (Roger) Phillips
    
    
    
    
    
    April 23, 2002
    
    
    Common shares of
    
    
    3,000Retired president and
    
    
    
    
    
    
    
    
    Imperial Oil Limitedchief executive officer,IPSCO Inc.
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    3,334(steel manufacturing)
    
    
    
    
    
    
    
    
    Imperial Oil LimitedRestricted stock units of
    
    
    2,750Imperial Oil LimitedShares of
    
    
    2,000Exxon Mobil CorporationJ.F. (Jim) Shepard
    
    
    
    
    
    October 21, 1997
    
    
    Common shares of
    
    
    3,000Retired chairman and
    
    
    
    
    
    
    
    
    Imperial Oil Limitedchief executive officer,Finning International Inc.
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    5,932(sale, lease, repair and
    
    
    
    
    
    
    
    
    Imperial Oil Limitedfinancing of heavyequipment)
    
    
    
    
    
    
    
    
    Restricted stock units of
    
    
    2,750Imperial Oil LimitedShares of
    
    
    0Exxon Mobil Corporation
 32




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##### Table of Contents



Last majorposition or office with theName and current principal
    
    
    Company or Exxon Mobiloccupation or employment
    
    
    Corporation
    
    
    Director since
    
    
    Holdings(1)(2)P.A. (Paul) Smith
    
    
    Corporate finance
    
    
    February 1, 2002
    
    
    Common shares of
    
    
    4,302Controller and
    
    
    manager, Exxon
    
    
    
    
    
    Imperial Oil Limitedsenior vice-president,
    
    
    Mobil Corporationfinance and
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    0administration,
    
    
    
    
    
    
    
    
    Imperial Oil LimitedImperial Oil LimitedRestricted stock units of
    
    
    48,500Imperial Oil LimitedShares of
    
    
    1,190Exxon Mobil CorporationS.D. (Sheelagh) Whittaker
    
    
    
    
    
    April 19, 1996
    
    
    Common shares of
    
    
    3,000Vice-president, Electronic
    
    
    
    
    
    
    
    
    Imperial Oil LimitedData SystemsCorporation (EDS)
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    8,400of Plano, Texas and
    
    
    
    
    
    
    
    
    Imperial Oil Limitedmanaging director,public sector business,
    
    
    
    
    
    
    
    
    Restricted stock units of
    
    
    2,750Electronic Data Systems
    
    
    
    
    
    
    
    
    Imperial Oil LimitedLimited(business and information
    
    
    
    
    
    
    
    
    Shares of
    
    
    0technology services)
    
    
    
    
    
    
    
    
    Exxon Mobil CorporationJ.M. (Michael) Yeager
    
    
    Vice-president, Africa,
    
    
    August 1, 2004
    
    
    Common shares of
    
    
    5,006Senior vice-president,
    
    
    ExxonMobil Production
    
    
    
    
    
    Imperial Oil Limitedresources division,
    
    
    CompanyImperial Oil Limited
    
    
    
    
    
    
    
    
    Deferred share units of
    
    
    Imperial Oil LimitedRestricted stock units of
    
    
    Imperial Oil LimitedShares of
    
    
    105,809Exxon Mobil CorporationV.L. (Victor) Young
    
    
    
    
    
    April 23, 2002
    
    
    Common shares of
    
    
    3,000Corporate director of
    
    
    
    
    
    
    
    
    Imperial Oil Limitedseveral corporationsDeferred share units of
    
    
    1,080Imperial Oil LimitedRestricted stock units of
    
    
    2,750Imperial Oil LimitedShares of Exxon Mobil
    
    
    0Corporation
   (1)
    
    The information includes the beneficial ownership of common shares of Imperial Oil
Limited and shares of Exxon Mobil Corporation, which information not being within the knowledge
of the Company, has been provided by the nominees individually.(2)
    
    The Companys plans for deferred share units and restricted stock units for selected
employees and nonemployee directors are described on pages 38 and 39. Pierre Des Marais II is currently a director and has been a director of the Company since
April 22, 1977. He holds 1,560 common shares of the Company, 5,031 deferred share units and 2,750
restricted stock units.  33




---



##### Table of Contents



Jack Mintz is a director of Brascan Corporation and CHC Helicopter Corporation, Roger Phillips
is a director of Canadian Pacific Railway Limited, Cleveland  Cliffs Inc., and The Toronto
Dominion Bank, and Victor L. Young is a director of Royal Bank of Canada and BCE Inc., which
companies are subject to reporting requirements under the U.S. Securities Exchange Act of 1934.  The following table provides information on the senior executives of the Company. Name and Office
    
    Office held sinceTimothy J. Hearn
    
    April 23, 2002chairman of the board, president andchief executive officerBrian J. Fischer
    
    February 1, 1994senior vice-president,products and chemicals divisionPaul A. Smith
    
    February 1, 2002controller and senior vice-president,finance and administrationJ. Michael Yeager
    
    August 1, 2004senior vice-president,resources divisionJohn F. Kyle
    
    June 1, 1991vice-president andtreasurer
 All of the above senior executives have been engaged for more than five years at their current
occupations or in other executive capacities with the Company or its affiliates. All senior
executives hold office until their appointment is rescinded by the directors, or by the chief
executive officer. Audit committee  Audit committee financial expert  Code of ethics  34




---



##### Table of Contents



Item 11. Executive Compensation. Directors compensation    Senior executive compensationSummary compensation table  35




---



##### Table of Contents



Annual Compensation
    
    
    Long Term CompensationAwards
    
    
    PayoutsSecurities
    
    
    Shares or UnitsUnder
    
    
    Subject to ResaleName and
    
    
    
    
    
    
    
    
    
    
    
    Other Annual
    
    
    Options/SARs
    
    
    Restricted
    
    
    LTIP
    
    
    All OtherPrincipal
    
    
    
    
    
    Salary
    
    
    Bonus (2)
    
    
    Compensation (3)
    
    
    Granted (4)
    
    
    (5) (6) (7)
    
    
    Payouts
    
    
    Compensation (9)Position
    
    
    Year
    
    
    ($)
    
    
    ($)
    
    
    ($)
    
    
    (#)
    
    
    (#)
    
    
    (8) ($)
    
    
    ($)T.J. Hearn
    
    
    2004
    
    
    1,000,000
    
    
    872,266
    
    
    246,249
    
    
    
    
    
    64,400
    
    
    750,000
    
    
    30,000Chairman, president
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    restricted stock unitsand chief executive
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    100officer
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    deferred share units2003
    
    
    825,000
    
    
    750,000
    
    
    182,072
    
    
    
    
    
    60,000
    
    
    738,000
    
    
    24,750U.S. 293,450
    
    
    
    
    
    restricted stock units0deferred share units2002
    
    
    668,333
    
    
    442,000
    
    
    71,777
    
    
    65,000
    
    
    50,000
    
    
    
    
    
    20,050U.S. 328,796
    
    
    stock options
    
    
    restricted stock units0deferred share unitsP.A. Smith
    
    
    2004
    
    
    378,333
    
    
    193,600
    
    
    67,022
    
    
    
    
    
    19,300
    
    
    183,000
    
    
    22,700Controller and Senior
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    restricted stock unitsVice-president, finance
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0and administration
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    deferred share units2003
    
    
    357,917
    
    
    183,000
    
    
    11,083
    
    
    
    
    
    16,700
    
    
    204,510
    
    
    21,475U.S. 72,891
    
    
    
    
    
    restricted stock units0deferred share units2002
    
    
    331,667
    
    
    94,500
    
    
    U.S. 100,390
    
    
    25,000
    
    
    12,500
    
    
    
    
    
    19,900stock options
    
    
    restricted stock units0deferred share unitsB.J. Fischer
    
    
    2004
    
    
    551,667
    
    
    392,775
    
    
    99,744
    
    
    
    
    
    34,200
    
    
    357,000
    
    
    33,100Senior vice-president,
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    restricted stock unitsproducts and
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    275chemicals division
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    deferred share units2003
    
    
    530,833
    
    
    357,000
    
    
    24,815
    
    
    
    
    
    26,700
    
    
    486,000
    
    
    31,850restricted stock units341deferred share units2002
    
    
    505,000
    
    
    216,000
    
    
    0
    
    
    50,000
    
    
    21,700
    
    
    
    
    
    30,300stock options
    
    
    restricted share units353deferred share unitK.C. Williams (1)
    
    
    2004
    
    
    U.S. 257,083
    
    
    U.S. 
    
    
    U.S. 204,682
    
    
    
    
    
    
    
    
    U.S. 158,010
    
    
    U.S. 17,475Senior vice-president
resources division
    
    
    2003
    
    
    U.S. 431,667
    
    
    U.S. 260,900
    
    
    U.S. 530,391
    
    
    
    
    
    
    
    
    U.S. 197,490
    
    
    U.S. 27,900until July 31, 2004
    
    
    2002
    
    
    U.S. 412,500
    
    
    U.S. 158,000
    
    
    U.S. 363,932
    
    
    
    
    
    
    
    
    U.S. 197,450
    
    
    U.S. 26,750J.M. Yeager (1)
    
    
    2004
    
    
    U.S. 170,833
    
    
    U.S. 277,000
    
    
    U.S. 48,831
    
    
    
    
    
    
    
    
    U.S. 0
    
    
    U.S. 10,250Senior Vice-president,
Resources division
From Aug. 1, 2004J.F. Kyle
    
    
    2004
    
    
    359,583
    
    
    172,105
    
    
    74,585
    
    
    
    
    
    13,200
    
    
    171,000
    
    
    21,575Vice-president
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    restricted stock unitsand treasurer
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0deferred share units2003
    
    
    355,000
    
    
    171,000
    
    
    41,391
    
    
    
    
    
    11,400
    
    
    261,000
    
    
    21,300restricted stock units0deferred share units2002
    
    
    345,000
    
    
    110,000
    
    
    13,077
    
    
    29,000
    
    
    10,600
    
    
    
    
    
    20,700stock options
    
    
    restricted stock units0deferred share units
 36




---



##### Table of Contents



(1)
    
    K.C. Williams was on a loan assignment from Exxon Mobil Corporation until July 31, 2004
and J.M. Yeager is from August 1, 2004. Their compensation was paid to them directly by Exxon
Mobil Corporation in United States dollars, and is disclosed in United States dollars. Also,
they received employee benefits under Exxon Mobil Corporations employee benefit plans, and not
under the Companys employee benefit plans. The Company reimburses Exxon Mobil Corporation for
the compensation paid and employee benefits provided to them.(2)
    
    Any part of bonus elected to be received as deferred share units is excluded.(3)
    
    Amounts under Other Annual Compensation, except for K.C. Williams and J.M. Yeager, consist
of interest paid in respect of deferred payments for long term incentive compensation, other
than the Companys plan for deferred share units for selected
executives, described on pages 37
to 39, dividend equivalent payments on restricted stock units, interest paid in respect of
deferred payments of bonuses and reimbursement for any income tax paid as a result of use of
company aircraft. The amounts also include an earned benefits allowance which in 2004 was
$90,000 for T.J. Hearn, $45,000 for P.A. Smith, $45,000 for B.J. Fischer and $35,000 for J.F.
Kyle. For T.J. Hearn and P.A. Smith, the U.S. dollar amounts were payments by the Company on
account of U.S. income taxes incurred while on assignment in the U.S.A. For K.C. Williams and
J.M. Yeager, the amounts are the net payments by Exxon Mobil Corporation on account of Canadian
income taxes and other compensation for assignment outside of the United States. Each year,
while on assignment, T.J. Hearn and P.A. Smith paid to the Company and K.C. Williams and J.M. Yeager paid to Exxon
Mobil Corporation amounts that were approximate to the income taxes that would have been
imposed if they were resident in their originating country of employment.(4)
    
    In 2002, the Company granted stock options which are described on page 38.(5)
    
    These include the number of units granted under the Companys plan for deferred share units
for selected executives described on page 38. The values and number of these units, as at the
end of 2004, were $7,034 for 100 units for T.J. Hearn, nil for P.A. Smith and J.F. Kyle and $1,426,373 for 20,047 units for B.J. Fischer.
These amounts include no deferred share units elected to be received in lieu of bonus for
2004, 2003 and 2002 for B.J. Fischer, P.A. Smith and J.F. Kyle, and 100 deferred share
units based on $7,034 of bonus elected to be received as deferred share units for 2004 for
T.J. Hearn.(6)
    
    These also include restricted stock units granted under the Companys plan for restricted
stock units for selected key employees and nonemployee directors described on pages 38 and 39.
The values and number of these units, as at the end of 2004, were $12,408,560 for 174,400 units
for T.J. Hearn, $3,450,775 for 48,500 units for P.A. Smith, $5,876,990 for 82,600 units for B.J.
Fischer, and $2,504,480 for 35,200 units for J.F. Kyle. The values of these units granted for
2004, as at the end of 2004 being the date of grant, were $4,582,060 for T.J. Hearn, $1,373,195
for P.A. Smith, $2,433,330 for B.J.
Fischer, and $939,180 for J.F. Kyle. The values of these units granted for 2003, as at the
end of 2003 being the date of grant, were $3,451,800 for T.J. Hearn, $960,751 for P.A.
Smith, $1,536,051 for B.J. Fischer, and $655,842 for J.F. Kyle. The values of these units
granted for 2002, as at the end of 2002 being the date of grant, were $2,243,000 for T. J.
Hearn, $560,750 for P.A. Smith, $973,462 for B.J. Fischer and $475,516 for J.F. Kyle.(7)
    
    K.C. Williams and J.M. Yeager participate in Exxon Mobil Corporations restricted stock plan
which is similar to the Companys restricted stock unit plan. The value and number of these
units for K.C. Williams, as at the end of the year, were U.S. $2,398,968 for 46,800 units. The
value and number of these units for J.M. Yeager, as at the end of the
year, were U.S. $4,170,924
for 81,368 units. Under that plan, K.C. Williams was granted 23,400 units in 2003 whose value on
the date of grant was U.S. $959,400 and 23,400 units in 2002 whose value on the date of grant
was U.S. $810,576. Under that plan, J.M. Yeager was granted 31,400 units in 2004, whose value on
the date of grant was U.S. $1,609,564.(8)
    
    Payouts were from 2003 earnings bonus units that reached maximum value of $3.00 per unit in
2004. That plan is described on page 38.(9)
    
    Amounts under All Other Compensation, except for K.C. Williams and J.M. Yeager, are the
Companys contributions to the savings plan, which is a plan available to all employees. Under
one of the options of that plan to which the senior executives subscribe, except for K.C.
Williams and J.M. Yeager, the Company matched employee contributions up to six percent of base
salary per year; however, an employee may elect to receive an enhanced pension under the
Companys pension plan by foregoing three percent of the Companys matching contributions. The
plan is intended to be primarily for retirement savings, although employees may withdraw their
contributions prior to retirement. For K.C. Williams and J.M. Yeager, the amounts are Exxon
Mobil Corporations contributions to its employee savings plan. Long term incentive compensation Consistent with the Companys compensation philosophy of being performance driven, long term
incentive compensation is granted to retain selected employees and reward them for high
performance. The compensation has generally been in the form of units.   37




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In 1998, an additional form of long term incentive compensation (deferred share units) was
made available to selected executives whereby they could elect to receive all or part of their
performance bonus compensation in the form of such units. The number of units granted to an
executive is determined by dividing the amount of the executives bonus elected to be received as
deferred share units by the average of the closing prices of the Companys shares on the Toronto
Stock Exchange for the five consecutive trading days (average closing price) immediately prior to
the date that the bonus would have been paid to the executive. Additional units will be granted to
recipients of these units based on the cash dividend payable on the Company shares divided by the
average closing price immediately prior to the payment date for that dividend and multiplying the
resulting number by the number of deferred share units held by the recipient. An executive may not
exercise these units until after termination of employment with the Company and must exercise the
units no later than December 31 of the year following termination of employment with the Company.
The units held must all be exercised on the same date. On the date of exercise, the cash value to
be received for the units will be determined by multiplying the number of units exercised by the
average closing price immediately prior to the date of exercise.          38




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##### Table of Contents



There are 927,908 common shares issuable upon future exercise of restricted stock units, which
represent about 0.27 percent of the Companys currently outstanding common shares. The Companys
directors, officers and vice-presidents have available as a group 22 percent of the common shares
issuable under outstanding restricted stock units.     Earnings bonus unit plan  awards in most recently completed financial year  PerformanceSecurities
    
    
    
    or Other
    
    
    
    Estimated Future Payouts UnderUnits or
    
    
    
    Period Until
    
    
    
    Non-Securities-Price Based PlansOther Rights
    
    
    
    Maturation or
    
    
    
    Threshold
    
    
    
    Target
    
    
    
    MaximumName
    
    
    (#)
    
    
    
    Payout (1)
    
    
    
    ($)
    
    
    
    ($)(2)
    
    
    
    ($)(2)T.J. Hearn
    
    
    
    232,000
    
    
    
    Nov. 17, 2009
    
    
    
    0
    
    
    
    
    3.75
    
    
    
    
    3.75P.A. Smith
    
    
    
    51,500
    
    
    
    Nov. 17, 2009
    
    
    
    0
    
    
    
    
    3.75
    
    
    
    
    3.75B.J. Fischer
    
    
    
    104,700
    
    
    
    Nov. 17, 2009
    
    
    
    0
    
    
    
    
    3.75
    
    
    
    
    3.75K.C. Williams
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    J.M. Yeager (3)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    J.F. Kyle
    
    
    
    45,700
    
    
    
    Nov. 17, 2009
    
    
    
    0
    
    
    
    
    3.75
    
    
    
    
    3.75
   (1)
    
    Payment will be made earlier when the cumulative net income per outstanding common share
reach the maximum settlement value per unit prior to the fifth anniversary of the grant date.(2)
    
    This is the maximum settlement value payable per earnings bonus unit granted in 2004.(3)
    
    J.M. Yeager participates in Exxon Mobil Corporations earnings bonus unit plan which is similar
to the Companys earnings bonus unit plan. In 2004, J.M. Yeager was granted 85,230 units under that plan for
which the maximum settlement value payable per earnings bonus unit is
U.S. $3.25. 39




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##### Table of Contents



Aggregated option/SAR exercises during the most recently completed financial year and
financial year end option/SAR values
     The following table provides information on the exercise in 2004 and the aggregate holdings at the
end of 2004 of incentive share units (referred to in the table as SARs) by the named senior
executives. Value ofUnexercisedUnexercised
    
    
    
    in-the-MoneySecurities
    
    
    Aggregate
    
    
    
    
    Options/SARs
    
    
    
    Options/SARsAcquired
    
    
    Value
    
    
    
    
    at Financial
    
    
    
    at Financialon Exercise
    
    
    Realized
    
    
    
    
    Year End
    
    
    
    Year EndName
    
    
    (#)
    
    
    ($)
    
    
    
    
    (#)
    
    
    
    ($)Exercisable
    
    
    
    Unexercisable (1)
    
    
    Exercisable
    
    
    
    Unexercisable (1)T.J. Hearn
    
    
    
    
    
    
    369,375
    
    
    
    
    50,000
    
    
    
    0
    
    
    
    1,607,500
    
    
    
    0P.A. Smith
    
    
    
    
    
    
    686,100
    
    
    
    
    67,000
    
    
    
    0
    
    
    
    2,571,250
    
    
    
    0B.J. Fischer
    
    
    
    
    
    
    125,120
    
    
    
    
    152,000
    
    
    
    0
    
    
    
    5,885,400
    
    
    
    0K.C. Williams
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    J.M. Yeager
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    


    
    
    

J.F. Kyle
    
    
    
    
    
    
    0
    
    
    
    
    89,000
    
    
    
    0
    
    
    
    3,455,250
    
    
    
    0
   (1)
    
    Unexercisable units are units for which the conditions for exercise have not been met. The following table provides information on the exercise in 2004 and the aggregate
holdings at the end of 2004 of stock options by the named senior executives. Value ofUnexercisedUnexercised
    
    
    
    in-the-MoneySecurities
    
    
    Aggregate
    
    
    Options/SARs
    
    
    
    Options/SARsAcquired
    
    
    Value
    
    
    at Financial
    
    
    
    at Financialon Exercise
    
    
    Realized
    
    
    Year End
    
    
    
    Year EndName
    
    
    (#)
    
    
    ($)
    
    
    (#)
    
    
    
    ($)Exercisable
    
    
    Unexercisable (3)
    
    
Exercisable
    
    
Unexercisable (3)T.J. Hearn
    
    
    
    
    
    126,059
    
    
    
    43,750
    
    
    
    
    16,250
    
    
    
    
    1,078,438
    
    
    
    
    400,563P.A. Smith
    
    
    
    
    
    0
    
    
    
    18,750
    
    
    
    
    6,250
    
    
    
    
    462,188
    
    
    
    
    154,063B.J. Fischer
    
    
    
    
    
    0
    
    
    
    37,500
    
    
    
    
    12,500
    
    
    
    
    924,375
    
    
    
    
    308,125K.C. Williams (1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    J.M. Yeager (2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    J.F. Kyle
    
    
    
    
    
    0
    
    
    
    21,750
    
    
    
    
    7,250
    
    
    
    
    536,138
    
    
    
    
    178,713
   (1)
    
    At the end of 2004, K.C. Williams held options to acquire 373,064 Exxon Mobil
Corporation shares of which all options were exercisable. The values of K.C. Williamss
exercisable options were U.S. $5,708,941 at the end of 2004. In 2004, he exercised 49,000
options and realized an aggregate value of U.S. $1,369,859.(2)
    
    At the end of 2004, J.M. Yeager held options to acquire 378,176 Exxon Mobil
Corporation shares of which all options were exercisable. The values of J. M. Yeagers
exercisable options were U.S. $6,383,064 at the end of 2004. In 2004, J.M. Yeager
exercised 10,560 options and realized an aggregate value of U.S. $322,430.(3)
    
    Unexercisable units are units for which the conditions for exercise have not been met. 40




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##### Table of Contents



Payments to employees who retire
Pension plan table Remuneration for
    
    Estimated undiscounted paymentsdetermining payments
    
    on retirement at the age of 65 after years of service indicated below ($)on retirement($)

    
    20 Years
    
    
    
    25 Years
    
    
    
    30 Years
    
    
    
    35 Years
    
    
    
    40 Years100,000
    
    
    
    32,000
    
    
    
    
    40,000
    
    
    
    
    48,000
    
    
    
    
    56,000
    
    
    
    
    64,000200,000
    
    
    
    64,000
    
    
    
    
    80,000
    
    
    
    
    96,000
    
    
    
    
    112,000
    
    
    
    
    128,000300,000
    
    
    
    96,000
    
    
    
    
    120,000
    
    
    
    
    144,000
    
    
    
    
    168,000
    
    
    
    
    192,000400,000
    
    
    
    128,000
    
    
    
    
    160,000
    
    
    
    
    192,000
    
    
    
    
    224,000
    
    
    
    
    256,000500,000
    
    
    
    160,000
    
    
    
    
    200,000
    
    
    
    
    240,000
    
    
    
    
    280,000
    
    
    
    
    320,000600,000
    
    
    
    192,000
    
    
    
    
    240,000
    
    
    
    
    288,000
    
    
    
    
    336,000
    
    
    
    
    384,000800,000
    
    
    
    256,000
    
    
    
    
    320,000
    
    
    
    
    384,000
    
    
    
    
    448,000
    
    
    
    
    512,0001,000,000
    
    
    
    320,000
    
    
    
    
    400,000
    
    
    
    
    480,000
    
    
    
    
    560,000
    
    
    
    
    640,0001,500,000
    
    
    
    480,000
    
    
    
    
    600,000
    
    
    
    
    720,000
    
    
    
    
    840,000
    
    
    
    
    960,0002,000,000
    
    
    
    640,000
    
    
    
    
    800,000
    
    
    
    
    960,000
    
    
    
    
    1,120,000
    
    
    
    
    1,280,0002,500,000
    
    
    
    800,000
    
    
    
    
    1,000,000
    
    
    
    
    1,200,000
    
    
    
    
    1,400,000
    
    
    
    
    1,600,0003,000,000
    
    
    
    960,000
    
    
    
    
    1,200,000
    
    
    
    
    1,440,000
    
    
    
    
    1,680,000
    
    
    
    
    1,920,000
 The Companys pension plan applies to almost all employees. The plan provides an annual
pension of a specific percentage of an employees final three year average earnings, multiplied
by the employees years of service, subject to certain requirements concerning age and length of
service. An employee may elect to forego three of the six percent of the Companys contributions to
the savings plan under one of the options of that plan (except for K.C. Williams and J.M. Yeager),
to receive an enhanced pension equal to 0.4 percent of the employees final three year average
earnings, multiplied by the employees years of service while foregoing such Company
contributions. In addition to the pension payable under the plan, the Company has paid and may
continue to pay a supplemental retirement income to employees who have earned a pension in excess
of the maximum pension under the Income Tax Act. The pension plan table on this page shows
estimated undiscounted annual payments, consisting of pension and supplemental retirement income,
payable on retirement to employees including the senior executives in specified classifications of
remuneration and years of service currently applicable to that group.
      The remuneration used to determine the payments on retirement to the individuals named in the
summary compensation table on pages 36 and 37, corresponds generally to the salary, bonus
compensation, and bonus compensation amount elected to be received as deferred share units in that
table, and the aggregate maximum settlement value that could be paid for earnings bonus units
granted shown in the table on page 39 is included in the employees final three year average
earnings for the year of grant of such units. As of February 18, 2005, the number of completed
years of service with Imperial Oil Limited used to determine payments on retirement were 38 for
T.J. Hearn, 36 for B.J. Fischer, 25 for P.A. Smith and 28 for J.F. Kyle.
      K.C. Williams and J.M. Yeager are not members of the Companys pension plan but are members
of Exxon Mobil Corporations pension plan. Under that plan, J.M. Yeager has 23 years of service and
he will receive a pension payable in U.S. dollars. The remuneration used to determine the payment
on retirement to him also corresponds generally to his salary and bonus compensation in the summary
compensation table on pages 36 and 37, which remuneration may be applied to the pension plan table
above but with the dollars in that table representing U.S. rather than Canadian dollars. Composition of the Companys compensation committee
     The executive resources committee of the board of directors, composed of the nonemployee
directors, is responsible for decisions on the compensation of senior management above the level of vice-president including all officers of the Company, and for reviewing the executive
development system, including specific succession plans for senior management positions. It also
reviews corporate policy on compensation. During 2004, the membership of the executive resources
committee was as follows: P. Des Marais II  Chair
R. Phillips  Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young
T.J. Hearn periodically attends meetings at the request of the committee. 41




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##### Table of Contents



Executive resources committee report on executive compensation
      The Companys executive compensation policy is designed to reinforce the Companys orientation
toward career employment and its emphasis on performance as the primary determinant of advancement.
This acknowledges the long term nature of the Companys business and its philosophy that the
experience, skill and motivation of its senior executives are significant determinants of future
business success. The compensation program emphasizes competitive salaries and performance based
incentives as the primary instruments to develop and retain key personnel.
      In establishing levels of compensation for its senior executives, the executive resources
committee relies on market comparisons to other leading Canadian employers, typically in the group
of major companies with revenues in excess of $1 billion a year. These market comparisons are
prepared by independent external compensation consultants. On a case by case basis, depending on
the scope of market coverage represented by a particular comparison, compensation is targeted to a
range between the mid-point and the upper quartile of comparable employers, reflecting the
Companys emphasis on quality of management.
      The Companys senior executive compensation policy has three main elements: base salary, short
term and long term incentive compensation. While these elements are related to the extent that
compensation policy is compared in total to the competitive practices of other major Canadian
employers, individual decisions on base salary, short term and long term incentive compensation are
made independently of each other. Base salary
     The Companys salary ranges for executives were increased by three percent in 2003, two and
one half percent in 2004 and one and one half percent in 2005. High performing executives, and
those recently promoted, whose salaries were low relative to their level of responsibility, were
given limited additional salary increases. This included senior executives.
      T.J. Hearns salary is currently assessed to be within the range of the competitive target for
the Companys chief executive officer which is between the median and upper quartile. The target is
consistent with the executive resources committees view that the chief executive officers salary
should be above the average of salaries for chief executive officers of major Canadian companies,
reflecting the Companys executive development philosophy and the significance placed on experience
and judgment in leading a large, complex operation. Cash bonus
     Cash bonuses are typically granted to about 80 executives at the end of each year, based on
individual performance. The bonuses are drawn from an aggregate bonus amount established annually
by the executive resources committee based on the Companys financial performance, and are granted
in tandem with the Companys earnings bonus units, which are described on page 38.
     In 2004, the executive resources committee increased the bonus awards including the grant of
earnings bonus units to reflect the Companys record financial results and in response to
comparisons to other leading Canadian employers.
     In the case of T.J. Hearn, the committees approach to cash bonuses is based on the Companys
financial and operating performance and on the committees assessment of T.J. Hearns effectiveness in leading the organization. The continuing progress being made in
focussing the organization on advancing key strategic interests, safety, environmental performance,
productivity, cost effectiveness and asset management were primary considerations in determining a
cash bonus for the chief executive officer. T.J. Hearns bonus including the grant of earnings
bonus units was increased in 2004 to reflect his effectiveness in the position, the Companys
record financial results, and comparisons to other leading Canadian employers. Long term incentive compensation
     Each year, the executive resources committee has approved long term incentive awards for
selected key employees. These awards were an added incentive to promote individual contribution to
sustained improvement in business performance and shareholder value, and to encourage key employees
to remain with the Company. Individual awards reflected both level of responsibility and
performance, with an emphasis on ability to influence longer term results. In each case, including
senior executives and the chief executive officer, award amounts took into account the competitive
practices of other major Canadian employers and were not influenced by prior years results or by
an individuals holdings of unexercised long term incentive compensation units.
     Incentive awards also have been awarded selectively to the general managerial, professional
and technical (non-executive) workforce as a way of delivering added financial incentive to
selected high performing employees. 42




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##### Table of Contents



For selected executives, the executive resources committee allows cash bonus awards to be
elected to be received in the form of deferred share units and also awards earnings bonus units as
a means of providing additional incentive to promote the Companys long term financial performance.
Eligibility to participate in the deferred share unit and earnings bonus plans is restricted to
those executives whose decisions are considered to have a direct effect on the long term financial
performance of the Company. In 2004, one executive elected to receive deferred share units and 77
executives were awarded earnings bonus units.
     For many years, the Companys long term incentive compensation programs have been cash based
programs tied to earnings and share performance, and incentive awards have been reported as
expenses in the consolidated statement of earnings. In 2002, to meet competitive practices, the
Company introduced a stock option program. However, recognizing current concerns over stock option
incentive programs and their proper accounting treatment, the Company decided to return to
straightforward, cash based incentive compensation programs that will again be reported as expenses
against earnings. There are no plans to issue stock options in the future.
     A total of 575 employees, including executives, were granted restricted stock units in 2004. Submitted on behalf of the executive resources committee:
P. Des Marais II  Chair
R. Phillips  Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young 
 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
     To the knowledge of the management of the Company, the only shareholder who, as of February
18, 2005, owned beneficially, or exercised control or direction over, more than five percent of the
outstanding common shares of the Company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard,
Irving, Texas 75039-2298, which owns beneficially 242,453,672 common shares, representing 69.6
percent of the outstanding voting shares of the Company.
     Reference is made to the security ownership information under the preceding Items 10 and 11.
As of February 18, 2005, John F. Kyle was the owner of 3,774 common shares of the Company and held
options to acquire 29,000 common shares of the Company and restricted share units to acquire 12,300
common shares of the Company.
     The directors and the senior executives of the Company consist of 10 persons, who, as a group,
own beneficially 85,896 common shares of the Company,
being approximately 0.02 percent of the total number of outstanding shares of the Company, and
118,452 shares of Exxon Mobil Corporation. This
information not being within the knowledge of the Company has been provided by the directors and
the senior executives individually. As a group, the directors and senior executives of the Company
held options to acquire 163,000 common shares of the Company and held restricted stock units to
acquire 127,950 common shares of the Company, as of February 18, 2005. Equity Compensation Plan Information as of December 31, 2004 Number of securitiesWeighted-average
    
    
    remaining available for futureNumber of securities to
    
    
    exercise price of
    
    
        issuance under equitybe issued upon exercise
    
    
    outstanding options,
    
    
    compensation plans (excludingof outstanding options,

    
    
    warrants and rights

    
    
    securities reflected inwarrants and rights
    
    
    ($)
    
    
    column (a))Plan category
    
    
        (a)
    
    
    (b)
    
    
    (c)Equity compensation
    
    
    
    2,854,500
    
    
    
    
    46.50
    
    
    
    
    0plans approved by
security holders (1)Equity compensation
    
    
    
    927,908
    
    
    
    
    
    
    
    
    
    2,572,092plans not approved
by security holders (2)Total
    
    
    
    3,782,408
    
    
    
    
    46.50
    
    
    
    
    2,572,092
   (1)
    
    This is the stock option plan, which is described on page 38 of this report.(2)
    
    This is the restricted stock unit plan, which is described on pages 38 and 39 of this report. 43




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##### Table of Contents



Item 13. Certain Relationships and Related Transactions.
     On June 23, 2003, the Company implemented another 12-month normal course share-purchase
program under which it purchased 15,511,833 of its outstanding shares between June 23, 2003, and
June 22, 2004. On June 23, 2004, another 12-month normal course program was implemented under
which the Company may purchase up to 17,864,398 of its outstanding shares, less any shares
purchased by the employee savings plan and Company pension fund. Exxon Mobil Corporation
participated by selling shares to maintain its ownership at 69.6 percent. In 2004, such purchases
cost $872 million, of which $594 million was received by ExxonMobil.
     During 2003, the Company borrowed $818 million from Exxon Overseas Corporation under two long
term loan agreements at interest equivalent to Canadian market rates. Interest paid on the loans in
2004 was $20 million. The average effective interest rates for the loans was 2.45 percent for 2004.
     The amounts of purchases and sales by the Company and its subsidiaries for other transactions
in 2004 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $3,176 million
and $1,580 million, respectively. These transactions were conducted on terms as favorable as they
would have been with unrelated parties, and primarily consisted of the purchase and sale of crude
oil, petroleum and chemical products, as well as transportation, technical and engineering
services. Transactions with Exxon Mobil Corporation also include amounts paid and received in
connection with the Companys participation in a number of natural resources activities conducted
jointly in Canada. The Company has agreements with affiliates of Exxon Mobil Corporation to provide
computer and customer support services to the Company and to share common business and operational
support services to allow the companies to consolidate duplicate work and systems. 
 Item 14. Principal Accountant Fees and Services. Audit Fees
     The aggregate fees of the Companys auditors for professional services rendered for the audit
of the Companys financial statements and other services for the fiscal years ended December 31,
2004 and December 31, 2003 were as follows: Dollars (thousands)
    
    2004
    
    
    2003Audit Fees
    
    
    1,112
    
    
    
    767Audit-Related Fees
    
    
    92
    
    
    
    62Tax Fees
    
    
    545
    
    
    
    395All Other Fees
    
    Nil
    
    NilTotal Fees
    
    
    1,749
    
    
    
    1,224
 Audit fees include the audit of the Companys annual financial statements, audit of
managements report on internal control over financial reporting and a review of the first three
quarterly financial statements in 2004.
     Audit-related fees include other assurance services including the audit of the Companys
retirement plan, the Imperial Oil Foundation, and royalty statement audits for oil and gas
producing entities.
     Tax fees are mainly tax services for employees on foreign loan assignments.
     The Company did not engage the auditors for any other services.
     The audit committee recommends the external auditors to be appointed by the shareholders,
fixes their remuneration and oversees their work. The audit committee also approves the proposed
current year audit program of the auditors, assesses the results of the program after the end of
the program period and approves in advance any non-audit services to be performed by the auditors
after considering the effect of such services on their independence.
     All of the services rendered by the auditors to the Company were approved by the audit
committee. 44




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##### Table of Contents



PART IV 
 Item 15. Exhibits and Financial Statement Schedules.
     Reference is made to the Index to Financial Statements on page F-1 of this report.
     The following exhibits numbered in accordance with Item 601 of Regulation S-K are filed as part
of this report: (3)
    
    (i)
    
    Restated certificate and articles of incorporation of the Company (Incorporated herein byreference to Exhibit (3) to the Companys Quarterly Report on Form 10-Q for the quarter endedJune 30, 1998 (File No. 0-12014)).(ii)
    
    By-laws of the Company (Incorporated herein by reference to Exhibit (3)(ii) tothe Companys Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (FileNo. 0-12014)).
 (4
    )
    
    The Companys long term debt authorized under any instrument does not exceed 10 percent of the
Companys consolidated assets. The Company agrees to furnish to the Commission upon request a copy
of any such instrument.
 (10)(ii)  (1)
    
    Alberta Crown Agreement, dated February 4, 1975, relating to theparticipation of the Province of Alberta in Syncrude (Incorporated herein by reference toExhibit 13(a) of the Companys Registration Statement on Form S-1, as filed with theSecurities and Exchange Commission on August 21, 1979 (File No. 2-65290)).(2
    )
    
    Amendment to Alberta Crown Agreement, dated January 1, 1983 (Incorporatedherein by reference to Exhibit (10)(ii)(2) of the Companys Annual Report onForm 10-K for the year ended December 31, 1983 (File No. 2-9259)).(3
    )
    
    Syncrude Ownership and Management Agreement, dated February 4, 1975(Incorporated herein by reference to Exhibit 13(b) of the Companys RegistrationStatement on Form S-1, as filed with the Securities and Exchange Commission onAugust 21, 1979 (File No. 2-65290)).(4
    )
    
    Letter Agreement, dated February 8, 1982, between the Government of Canadaand Esso Resources Canada Limited, amending Schedule C to the SyncrudeOwnership and Management Agreement filed as Exhibit (10)(ii)(2) (Incorporatedherein by reference to Exhibit (20) of the Companys Annual Report on Form 10-Kfor the year ended December 31, 1981 (File No. 2-9259)).(5
    )
    
    Norman Wells Pipeline Agreement, dated January 1, 1980, relating to theoperation, tolls and financing of the pipeline system from the Norman Wellsfield (Incorporated herein by reference to Exhibit 10(a)(3) of the CompanysAnnual Report on Form 10-K for the year ended December 31, 1981 (File No.2-9259)).(6
    )
    
    Norman Wells Pipeline Amending Agreement, dated April 1, 1982 (Incorporatedherein by reference to Exhibit (10)(ii)(5) of the Companys Annual Report onForm 10-K for the year ended December 31, 1982 (File No. 2-9259)).(7
    )
    
    Letter Agreement clarifying certain provisions to the Norman Wells PipelineAgreement, dated August 29, 1983 (Incorporated herein by reference to Exhibit(10)(ii)(7) of the Companys Annual Report on Form 10-K for the year endedDecember 31, 1983 (File No. 2-9259)).(8
    )
    
    Norman Wells Pipeline Amending Agreement, made as of February 1, 1985,relating to certain amendments ordered by the National Energy Board(Incorporated herein by reference to Exhibit (10)(ii)(8) of the Companys AnnualReport on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).(9
    )
    
    Norman Wells Pipeline Amending Agreement, made as of April 1, 1985, relatingto the definition of Operating Year (Incorporated herein by reference toExhibit (10)(ii)(9) of the Companys Annual Report on Form 10-K for the yearended December 31, 1986 (File No. 0-12014)).(10
    )
    
    Norman Wells Expansion Agreement, dated October 6, 1983, relating to theprices and royalties payable for crude oil production at Norman Wells(Incorporated herein by reference to Exhibit (10)(ii)(8) of the Companys AnnualReport on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).(11
    )
    
    Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to theroyalties payable and the assurances given in respect of the Cold Lakeproduction project (Incorporated herein by reference to Exhibit (10)(ii)(11) ofthe Companys Annual Report on Form 10-K for the year ended December 31, 1986(File No. 0-12014)).(12
    )
    
    Amendment to Alberta Crown Agreement, dated January 1, 1986 (Incorporatedherein by reference to Exhibit (10)(ii)(12) of the Companys Annual Report onForm 10-K for the year ended December 31, 1987 (File No. 0-12014)).(13
    )
    
    Amendment to Alberta Crown Agreement, dated November 25, 1987 (Incorporatedherein by reference to Exhibit (10)(ii)(13) of the Companys Annual Report onForm 10-K for the year ended December 31, 1987 (File No. 0-12014)).
 45




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##### Table of Contents



(14
    )
    
    Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982(Incorporated herein by reference to Exhibit (10)(ii)(14) of the Companys Annual Reporton Form 10-K for the year ended December 31, 1989 (File No. 0-12014)).(15
    )
    
    Amendment to Alberta Crown Agreement, dated August 1, 1991 (Incorporated herein byreference to Exhibit (10)(ii)(15) of the Companys Annual Report on Form 10-K for theyear ended December 31, 1991 (File No. 0-12014)))(16
    )
    
    Norman Wells Settlement Agreement,
dated July 31, 1996. (Incorporated herein by reference to
Exhibit(10)(ii) (16) of the Companys Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0‐12014)).(17
    )
    
    Amendment to Alberta Crown Agreement, dated January 1, 1997. (Incorporated hereinby reference to Exhibit (10)(ii)(17) of the Companys Annual Report on Form 10-K for theyear ended December 31, 1996 (File No. 0-12014)).(18
    )
    
    Norman Wells Pipeline Amending Agreement, dated December 12, 1997. (Incorporatedherein by reference to Exhibit (10)(ii)(18) of the Companys Annual Report on Form 10-Kfor the year ended December 31, 1998 (File No. 0-12014)).(19
    )
    
    Norman Wells Pipeline 1999 Amending Agreement, dated May 1, 1999. (Incorporatedherein by reference to Exhibit (10)(ii)(19) of the Companys Annual Report on Form 10-Kfor the year ended December 31, 1999 (File No. 0-12014)).(20
    )
    
    Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to theroyalties payable in respect of the Cold Lake production project and terminating theAlberta Cold Lake Crown Agreement. (Incorporated herein by reference to Exhibit(10)(ii)(20) of the Companys Annual Report on Form 10-K for the year ended December 31,2001 (File No. 0-12014)).(21
    )
    
    Amendment to Alberta Crown Agreement effective January 1, 2001 (Incorporated hereinby reference to Exhibit (10)(ii)(21) of the Companys Quarterly Report on Form 10-Q forthe quarter ended June 30, 2002 (File No. 0-12014)).(22
    )
    
    Amendment to Syncrude Ownership and Management Agreement effective January 1, 2001(Incorporated herein by reference to Exhibit (10)(ii)(22) of the Companys QuarterlyReport on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).(23
    )
    
    Amendment to Syncrude Ownership and Management Agreement effective September 16,1994 (Incorporated herein by reference to Exhibit (10)(ii)(23) of the CompanysQuarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).(24
    )
    
    Amendment to Alberta Crown Agreement dated November 29, 1995 (Incorporated hereinby reference to Exhibit (10)(ii)(24) of the Companys Quarterly Report on Form 10-Q forthe quarter ended June 30, 2002 (File No. 0-12014)).(iii)(A)(1)
    
    Form of Letter relating to Supplemental Retirement Income (Incorporated herein by referenceto Exhibit (10)(c)(3) of the Companys Annual Report on Form 10-K for the year endedDecember 31, 1980 (File No. 2-9259)).(2
    )
    
    Incentive Share Unit Plan and Incentive Share Units granted in 2001 are incorporatedherein by reference to Exhibit (10)(iii)(A)(2) of the Companys Annual Report on Form 10-K for theyear ended December 31, 2001. Units granted in 2000 are incorporated herein by reference to Exhibit(10)(iii)(A)(2) of the Companys Annual Report on Form 10-K for the year ended December 31, 2000(File No. 0-12014); units granted in 1999 are incorporated herein by reference to Exhibit(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year ended December 31, 1999(File No. 0-12014); units granted in 1998 are incorporated herein by reference to Exhibit(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year ended December 31, 1998(File No. 0-12014); units granted in 1997 are incorporated herein by reference to Exhibit(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year ended December 31, 1997(File No. 0-12014); units granted in 1996 are incorporated herein by reference to Exhibit(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year ended December 31, 1996(File No. 0-12014); units granted
in 1995 are incorporated herein by reference to Exhibit
(10)(iii)(A)(3) ofthe Companys Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 0-12014); andunits granted in 1994 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the CompanysAnnual Report on Form 10-K for the year ended December 31, 1994 (File No. 0-12014).(3
    )
    
    Deferred Share Unit Plan. (Incorporated herein by reference toExhibit(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the year endedDecember 31, 1998 (File No. 0-12014)).
 46




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##### Table of Contents



(4
    )
    
    Deferred Share Unit Plan for
Nonemployee Directors. (Incorporated herein by reference to Exhibit
(10)(iii)(A)(6) of the Companys Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0‐12014)).(5
    )
    
    Form of Earnings Bonus Units
(Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the
Companys Annual Report on Form 10-K for the year ended December
31, 2003 (File No. 0-12014)) and Earnings Bonus Unit Plan
(Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).(6
    )
    
    Incentive Stock Option Plan and
Incentive Stock Options granted in 2002 (Incorporated herein by
reference to Exhibit (10)(iii)(A)(6) of the Companys Quarterly
Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).(7
    )
    
    Restricted Stock Unit Plan and
Restricted Stock Units granted in 2002 (Incorporated herein by
reference to Exhibit (10)(iii)(A)(7) of the Companys Annual
Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).(8
    )
    
    Restricted Stock Unit Plan and
Restricted Stock Units granted in 2003 (Incorporated herein by
reference to Exhibit (10)(iii)(A)(8) of the Companys Annual
Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)).(9
    )
    
    Restricted Stock Unit Plan and
general form for Restricted Stock Unites, as amended effective
December 31, 2004 (Incorporated herein by reference to Exhibit 99.1
of the Companys Form 8-K dated December 31, 2004 (File No. 0-12014)).
 (21
    )
    
    Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial Oil
Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all incorporated in Canada, are
wholly-owned subsidiaries of the Company. The names of all other subsidiaries of the
Company are omitted because, considered in the aggregate as a single subsidiary, they
would not constitute a significant subsidiary as of December 31, 2004.
 (23)(ii)
    
    (A)   Consent of PricewaterhouseCoopers LLP.(B)   Consent of Chief Engineering Officer.(31.1)
    
    Certification by principal
executive officer of Periodic Financial Report pursuant to Rule 13a-14(a).(31.2)
    
    Certification by principal
financial officer of Periodic Financial Report pursuant to Rule 13a-14(a).(32.1)
    
    Certification by chief executive
officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.(32.2)
    
    Certification by chief  financial
officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.
 Copies of Exhibits may be acquired upon written request of any shareholder to the investor
relations manager, Imperial Oil Limited, 111 St. Clair Avenue West, Toronto, Ontario, Canada M5W
1K3, and payment of processing and mailing costs. 47




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##### Table of Contents



SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf on March 9, 2005 by
the undersigned, thereunto duly authorized. Imperial
Oil LimitedBy

/s/
T. J. Hearn(Timothy J. Hearn, Chairman of the Board,President and Chief Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below on March 9, 2005 by the following persons on behalf of the registrant and in the
capacities indicated. Signature
    
    TitleChairman of the Board, President,/s/ T. J. Hearn
    
    Chief Executive Officer and Director(Principal Executive Officer)(Timothy J. Hearn)Controller and Senior Vice-President,/s/ Paul A. Smith
    
    Finance and Administration and Director(Principal Accounting Officer and Principal Financial Officer)(Paul A. Smith)/s/ Pierre Des Marais II
    
    Director(Pierre Des Marais II)/s/ Brian J. Fischer
    
    Director(Brian J. Fischer)/s/ Roger Phillips
    
    Director(Roger Phillips)/s/ J. Shepard
    
    Director(James F. Shepard)/s/ Sheelagh D. Whittaker
    
    Director(Sheelagh D. Whittaker)/s/ J. Michael Yeager
    
    Director(J. Michael Yeager)/s/ Victor L. Young
    
    Director(Victor L. Young)
 48




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##### Table of Contents



INDEX TO FINANCIAL STATEMENTS Pages in thisReportManagements report on internal control over financial reporting
    
    F-2Auditors
report
    
    F-2Financial statements:Consolidated statement of income for the years 2002, 2003 and 2004
    
    F-3Consolidated statement of cash flows for the years 2002, 2003 and 2004
    
    F-4Consolidated balance sheet as at December 31, 2002, 2003 and 2004
    
    F-5Consolidated statement of shareholders equity as at December 31, 2002, 2003 and 2004
    
    F-6Notes to the consolidated financial statements
    
    F-7  F20
 F-1




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MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management, including the Companys chief executive officer and principal accounting officer and
principal financial officer, is responsible for establishing and maintaining adequate internal
control over the Companys financial reporting. Management conducted an evaluation of the
effectiveness of internal control over financial reporting based on the Internal Control 
Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this evaluation, management concluded that Imperial Oil Limiteds internal
control over financial reporting was effective as of December 31, 2004. Managements assessment of the effectiveness of internal control over financial reporting as of
December 31, 2004, was audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which is included herein. /s/ T.
J. Hearn
    
    /s/ Paul A. SmithTimothy J. Hearn
    
    Paul A. SmithChairman of the Board,
    
    Controller and Senior Vice-President,President and Chief Executive Officer
    
    Finance and Administration(Principal Accounting Officer and Principal Financial Officer)
 
 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders of Imperial Oil Limited: We have completed an integrated audit of Imperial Oil Limiteds 2004 consolidated financial
statements and of its internal control over financial reporting as of December 31, 2004, and audits
of its 2003 and 2002 consolidated financial statements in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are
presented below. Consolidated financial statements
     In our opinion, the accompanying consolidated balance sheets and the related consolidated
statements of income, shareholders equity and cash flows appearing on pages F-3 through F-20 of
this Annual Report present fairly, in all material respects, the financial position of Imperial Oil
Limited and its subsidiaries at December 31, 2004 and 2003, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 2004 in conformity with
accounting principles generally accepted in the United States of America. 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 of these
statements in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. An audit of
financial statements includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion. Internal control over financial reporting
     Also, in our opinion, management s assessment, included in the accompanying Management s Report on Internal Control Over Financial Reporting, that the Company maintained
effective internal control over financial reporting as of December 31, 2004
based on criteria established in Internal Control  
Integrated Frame workissued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in
our opinion, the Company maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on criteria established in Internal Control    Integrated Frameworkissued by the COSO. The Company s
management is responsible for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on managements assessment
and on the effectiveness of the Company s internal control over financial reporting based
on our audit. We conducted our audit of internal control over
financial reporting in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects . An audit of internal control over financial reporting
includes obtaining an understanding of internal control over financial reporting,
evaluating management s assessment, testing and evaluating the design and operating
effectiveness of internal control, and performing such other procedures as we consider
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. 
 /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
Chartered Accountants
Toronto, Ontario, Canada
March 9, 2005 F-2




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##### Table of Contents



Consolidated statement of income millions of Canadian dollarsFor the years ended December 31
    
    2004
    
    
    2003
    
    
    2002RevenuesOperating revenues (a)
    
    
    22 408
    
    
    
    19 094
    
    
    
    16 890Investment and other income (note 11)
    
    
    52
    
    
    
    114
    
    
    
    152Total revenues
    
    
    22 460
    
    
    
    19 208
    
    
    
    17 042ExpensesExploration
    
    
    59
    
    
    
    55
    
    
    
    30Purchases of crude oil and products
    
    
    13 094
    
    
    
    10 823
    
    
    
    9 723Production and manufacturing
    
    
    2 883
    
    
    
    2 782
    
    
    
    2 320Selling and general
    
    
    1 218
    
    
    
    1 269
    
    
    
    1 222Federal excise tax (a)
    
    
    1 264
    
    
    
    1 254
    
    
    
    1 231Depreciation and depletion
    
    
    908
    
    
    
    755
    
    
    
    708Financing costs (note 15)
    
    
    7
    
    
    
    (120
    )
    
    
    20Total expenses
    
    
    19 433
    
    
    
    16 818
    
    
    
    15 254Income before income taxes
    
    
    3 027
    
    
    
    2 390
    
    
    
    1 788Income taxes
    
    
    975
    
    
    
    689
    
    
    
    574Income before cumulative effect
of accounting change
    
    
    2 052
    
    
    
    1 701
    
    
    
    1 214Cumulative effect of accounting change,
after income tax
    
    
    
    
    
    
    4
    
    
    
    Net income
    
    
    2 052
    
    
    
    1 705
    
    
    
    1 214Per-share information(dollars)Net income per common share  basic (note 13)Income before cumulative effect
of accounting change
    
    
    5.75
    
    
    
    4.57
    
    
    
    3.20Cumulative effect of accounting change,
after income tax
    
    
    
    
    
    
    0.01
    
    
    
    Net income
    
    
    5.75
    
    
    
    4.58
    
    
    
    3.20Net income per common share  diluted (note 13)Income before cumulative effect
of accounting change
    
    
    5.74
    
    
    
    4.57
    
    
    
    3.20Cumulative effect of accounting change,
after income tax
    
    
    
    
    
    
    0.01
    
    
    
    Net income
    
    
    5.74
    
    
    
    4.58
    
    
    
    3.20Dividends
    
    
    0.88
    
    
    
    0.87
    
    
    
    0.84
   (a)
    Operating
revenues include
federal excise tax of
$1,264 million (2003
 $1,254 million,
2002  $1,231
million). The information on
pages F-7 through F-20
is part of these
consolidated financial
statements. Certain
figures for prior
years have been
reclassified in the
financial statements
to conform with the
current years
presentation. F-3




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Consolidated statement of cash flows millions of Canadian dollars, inflow/(outflow)For the years ended December 31
    
    2004
    
    
    2003
    
    
    2002Operating activitiesNet income
    
    
    2 052
    
    
    
    1 705
    
    
    
    1 214Cumulative effect of accounting change, after tax
    
    
    
    
    
    
    (4
    )
    
    
    Adjustments for non-cash items:Depreciation and depletion
    
    
    908
    
    
    
    755
    
    
    
    708(Gain)/loss on asset sales, after tax
    
    
    (32
    )
    
    
    (10
    )
    
    
    (4
    )Deferred income taxes and other
    
    
    (90
    )
    
    
    (59
    )
    
    
    (148
    )Changes in operating assets and liabilities:Accounts receivable
    
    
    (311
    )
    
    
    33
    
    
    
    (356
    )Inventories and prepaids
    
    
    (32
    )
    
    
    31
    
    
    
    51Income taxes payable
    
    
    462
    
    
    
    38
    
    
    
    (225
    )Accounts payable
    
    
    308
    
    
    
    74
    
    
    
    323All other items  net (a)
    
    
    47
    
    
    
    (336
    )
    
    
    125Cash from
operating activities (note 14)
    
    
    3 312
    
    
    
    2 227
    
    
    
    1 688Investing activitiesAdditions to property, plant and equipment
and intangibles
    
    
    (1 376
    )
    
    
    (1 482
    )
    
    
    (1 564
    )Proceeds from asset sales
    
    
    102
    
    
    
    56
    
    
    
    61Loans to equity company
    
    
    (32
    )
    
    
    
    
    
    
    Cash from/(used in) investing activities
    
    
    (1 306
    )
    
    
    (1 426
    )
    
    
    (1 503
    )Financing activitiesShort-term debt  net
    
    
    9
    
    
    
    
    
    
    
    (388
    )Long-term debt issued
    
    
    
    
    
    
    818
    
    
    
    500Repayment of long-term debt
    
    
    (8
    )
    
    
    (818
    )
    
    
    (71
    )Issuance of common shares under stock option plan
    
    
    13
    
    
    
    2
    
    
    
    Common shares purchased (note 13)
    
    
    (872
    )
    
    
    (799
    )
    
    
    (13
    )Dividends paid
    
    
    (317
    )
    
    
    (322
    )
    
    
    (319
    )Cash from/(used in) financing activities
    
    
    (1 175
    )
    
    
    (1 119
    )
    
    
    (291
    )Increase/(decrease) in cash
    
    
    831
    
    
    
    (318
    )
    
    
    (106
    )Cash at beginning of year
    
    
    448
    
    
    
    766
    
    
    
    872Cash at end of year(b)
    
    
    1 279
    
    
    
    448
    
    
    
    766
   (a)
    Includes
contribution to
registered pension
plans of $114 million
(2003 - $511 million,
2002  $19 million).(b)
    Cash is composed
of cash in bank and
cash equivalents at
cost. Cash equivalents
are all highly liquid
securities with a
maturity of three
months or less when
purchased. The information on
pages F-7 through F-20
is part of these
consolidated financial
statements. Certain
figures for prior
years have been
reclassified in the
financial statements
to conform with the
current years
presentation. F-4




---



##### Table of Contents



Consolidated balance sheet millions of Canadian dollarsAt December 31
    
    2004
    
    
    2003AssetsCurrent assetsCash
    
    
    1 279
    
    
    
    448Accounts receivable, less estimated
doubtful amounts
    
    
    1 626
    
    
    
    1 315Inventories of crude oil and products (note 14)
    
    
    432
    
    
    
    407Materials, supplies and prepaid expenses
    
    
    112
    
    
    
    105Deferred income tax assets (note 4)
    
    
    448
    
    
    
    353Total current assets
    
    
    3 897
    
    
    
    2 628Investments and other long-term assets
    
    
    130
    
    
    
    97Property, plant and equipment, less accumulation,
depreciation and depletion (note 2)
    
    
    9 647
    
    
    
    9 267Goodwill (note 2)
    
    
    204
    
    
    
    204Other intangible assets, net
    
    
    149
    
    
    
    141Total assets(note 2)
    
    
    14 027
    
    
    
    12 337LiabilitiesCurrent liabilitiesShort-term debt
    
    
    81
    
    
    
    72Accounts payable and accrued liabilities (note 16)
    
    
    2 525
    
    
    
    2 222Income taxes payable
    
    
    1 057
    
    
    
    595Current portion of long-term debt
    
    
    995
    
    
    
    501Total current liabilities
    
    
    4 658
    
    
    
    3 390Long-term debt (note 3)
    
    
    367
    
    
    
    859Other long-term obligations (note 8)
    
    
    1 525
    
    
    
    1 314Deferred income tax liabilities (note 4)
    
    
    1 155
    
    
    
    1 229Commitments and contingent liabilities (note 12)Total liabilities
    
    
    7 705
    
    
    
    6 792Shareholders equityCommon shares at stated value (note 13)
    
    
    1 801
    
    
    
    1 859Earnings reinvested
    
    
    4 889
    
    
    
    3 952Accumulated other nonowner changes in equity
    
    
    (368
    )
    
    
    (266
    )Total shareholders equity
    
    
    6 322
    
    
    
    5 545Total liabilities and shareholders equity
    
    
    14 027
    
    
    
    12 337
 The information
on pages F-7 through
F-20 is part of these
consolidated
financial statements.
Certain figures for prior
years have been
reclassified in the
financial statements
to conform with the
current years
presentation. Approved by the directors/s/
T. J. Heam
    
    /s/ P. A. SmithChairman, president and
    
    Controller and senior vice-president,chief executive officer
    
    finance and administration
 F-5




---



##### Table of Contents



Consolidated statement of shareholders equity millions of Canadian dollarsAt December 31
    
    2004
    
    
    2003
    
    
    2002Common shares at stated value(note 13)At beginning of year
    
    
    1 859
    
    
    
    1 939
    
    
    
    1 941Issued under the stock option plan
    
    
    13
    
    
    
    2
    
    
    
    Share purchases at stated value
    
    
    (71
    )
    
    
    (82
    )
    
    
    (2
    )At end of year
    
    
    1 801
    
    
    
    1 859
    
    
    
    1 939Earnings reinvestedAt beginning of year
    
    
    3 952
    
    
    
    3 287
    
    
    
    2 402Net income for the year
    
    
    2 052
    
    
    
    1 705
    
    
    
    1 214Share purchases in excess of stated value
    
    
    (801
    )
    
    
    (717
    )
    
    
    (11
    )Dividends
    
    
    (314
    )
    
    
    (323
    )
    
    
    (318
    )At end of year
    
    
    4 889
    
    
    
    3 952
    
    
    
    3 287Accumulated other nonowner changes in equityAt beginning of year
    
    
    (266
    )
    
    
    (315
    )
    
    
    (77
    )Minimum pension liability adjustment (note 7)
    
    
    (102
    )
    
    
    49
    
    
    
    (238
    )At end of year
    
    
    (368
    )
    
    
    (266
    )
    
    
    (315
    )Shareholders equity at end of year
    
    
    6 322
    
    
    
    5 545
    
    
    
    4 911Nonowner changes in equity for the yearNet income for the year
    
    
    2 052
    
    
    
    1 705
    
    
    
    1 214Other nonowner changes in equity (note 7)
    
    
    (102
    )
    
    
    49
    
    
    
    (238
    )Total nonowner changes in equity for the year
    
    
    1 950
    
    
    
    1 754
    
    
    
    976
 The information on
pages F-7 through F-20
is part of these
consolidated financial
statements. Certain
figures for prior
years have been
reclassified in the
financial statements
to conform with the
current years
presentation. F-6




---



##### Table of Contents



Notes to consolidated financial statements 1. Summary of significant accounting policies The companys principal business is energy, involving the exploration, production, transportation
and sale of crude oil and natural gas and the manufacture, transportation and sale of petroleum
products. Imperial is also a major manufacturer and marketer of petrochemicals.
The consolidated financial statements have been prepared in accordance with generally accepted
accounting principles (GAAP) in the United States of America. The financial statements include
certain estimates that reflect managements best judgment. All amounts are in Canadian dollars
unless otherwise indicated.Principles of consolidation
The consolidated financial statements include the accounts of Imperial Oil Limited and its
subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those
companies in which Imperial has both an equity interest and the continuing ability to unilaterally
determine strategic operating, investing and financing policies. Significant subsidiaries included
in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil
Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum
Inc. All of the above companies are wholly owned. A
significant portion of the companys activities in natural resources is conducted jointly with
other companies. The accounts reflect the companys share of undivided interest in such activities,
including its 25-percent interest in the Syncrude joint venture and its nine-percent interest in
the Sable offshore energy project.Segment reporting
The company operates its business in Canada in the following segments:Natural resources includes the exploration for and production of
crude oil and natural gas.Petroleum products comprises the refining of crude oil into petroleum products and the distribution
and marketing of these products.Chemicals includes the manufacturing and marketing of various
hydrocarbon-based chemicals and chemical products.
The above functions have been defined as the operating segments of the company because they are the
segments (a) that engage in business activities from which revenues are earned and expenses are
incurred; (b) whose operating results are regularly reviewed by the companys chief operating
decision-maker to make decisions about resources to be allocated to the segment and assess its
performance; and (c) for which discrete financial information is
available.Corporate and other includes assets and liabilities that do not specifically relate to business
segments  primarily cash and long-term debt. Net income in this segment primarily includes
financing costs and interest income.
Segment accounting policies are the same as those described in this summary of significant
accounting policies. Natural resources, petroleum products and chemicals expenses include amounts
allocated from the corporate and other segment. The allocation is based on a combination of fee
for service, proportional segment expenses and a three-year average of capital expenditures.
Transfers of assets between segments are recorded at book amounts. Items included in capital
employed that are not identifiable by segment are allocated according to their nature.
Inventories

Inventories are recorded at the lower of cost or net realizable value. The cost of crude oil
and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected
over the alternative first-in, first-out and average cost methods because it provides a better
matching of current costs with the revenues generated in the period.
Inventory costs include expenditures and other charges, including depreciation, directly or
indirectly incurred in bringing the inventory to its existing condition and final storage prior to
delivery to a customer. Selling and general expenses are reported as period costs and excluded from
inventory costs.
Investments
The principal investments in companies other than subsidiaries are accounted for using the
equity method. They are recorded at the original cost of the investment plus Imperials share of
earnings since the investment was made, less dividends received. Imperials share of the after-tax
earnings of these companies is included in investment and other income in the consolidated
statement of income. Other investments are recorded at cost. Dividends from these other investments
are included in investment and other income.
These investments represent interests in non-publicly traded pipeline companies that facilitate the
sale and purchase of crude oil and natural gas in the conduct of company operations. Other parties
who also have an equity interest in these companies share in the risks and rewards according to
their percentage of ownership. Imperial does not invest in these companies in order to remove
liabilities from its balance sheet.
Property, plant and equipment
Property, plant and equipment is recorded at cost. Investment tax credits and other similar
grants are treated as a reduction of the capitalized cost of the asset to which they apply.
The company uses the successful-efforts method to account for its exploration and production
activities. Under this method, costs are accumulated on a field-by-field basis with certain
exploratory expenditures and exploratory dry holes being expensed as incurred. The company
continues to carry as an asset the cost of drilling exploratory wells that find sufficient
quantities of reserves to justify their completion as producing wells if the required capital
expenditure is made and drilling of additional exploratory wells is underway or firmly planned for
the near future. Once exploration activities demonstrate that sufficient quantities of commercially
producible reserves have been discovered, continued capitalization is dependent on project reviews,
which take place at least annually, to ensure that satisfactory progress toward ultimate
development of the reserves is being achieved. Exploratory well costs not meeting these criteria
are charged to expense. Costs of productive wells and development dry holes are capitalized and
amortized on the unit-of-production method for each field. The company uses this accounting policy
instead of the full-cost method because it provides a more timely accounting of the success or
failure of the companys exploration and production activities. F-7




---



##### Table of Contents



Maintenance and repair costs, including planned major maintenance, are expensed as incurred.
Improvements that increase the capacity or prolong the service life of an asset are capitalized.Production costs are expensed as incurred. Production involves lifting the oil and gas to the
surface and gathering, treating, field processing and field storage of the oil and gas. The
production function normally terminates at the outlet valve on the lease or field production
storage tank. Production costs are those incurred to operate and maintain the companys wells and
related equipment and facilities. They become part of the cost of oil and gas produced. These
costs, sometimes referred to as lifting costs, include such items as labour costs to operate the
wells and related equipment; repair and maintenance costs on the wells and equipment; materials,
supplies and energy costs required to operate the wells and related equipment; and administrative
expenses related to the production activity.Depreciation and depletion for assets associated with producing properties begin at the time when
production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use.
Assets under construction are not depreciated or depleted. Depreciation and depletion are
calculated using the unit-of-production method for producing properties based on proved developed
reserves. Depreciation of other plant and equipment is calculated using the straight-line method,
based on the estimated service life of the asset. In general, refineries are depreciated over 25
years; other major assets, including chemical plants and service stations, are depreciated over 20
years.Proved oil and gas properties held and used by the company are reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amounts may not be recoverable.
Assets are grouped at the lowest level for which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets.The company estimates the future undiscounted cash flows of the affected properties to judge the
recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using
annually updated corporate plan investment evaluation assumptions for crude oil commodity prices
and foreign-currency exchange rates. Annual volumes are based on individual field production
profiles, which are also updated annually. Prices for natural gas and other products sold under
contract are based on corporate plan assumptions that are developed annually and also used for
investment evaluation purposes.In general, impairment analyses are based on proved reserves. Where probable reserves exist, an
appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation.
An asset would be impaired if the undiscounted cash flows were less than its carrying value.
Impairments are measured by the amount by which the assets carrying value exceeds its fair value.Gains or losses on assets sold are included in investment and other income in the consolidated
statement of income.Interest capitalization
Interest costs relating to major capital projects under construction are capitalized as part of
property, plant and equipment. Capitalization of interest ceases when the property, plant and
equipment is substantially complete and ready for its intended use.Goodwill and other intangible assets
Goodwill and intangible assets with indefinite lives are not subject to amortization. These
assets are tested for impairment annually or more frequently if events or circumstances indicate
the assets might be impaired. Impairment losses are recognized in current period earnings. The
evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill
and associated operating assets with the estimated present value of net cash flows from those
operating assets.Intangible assets with determinable useful lives are amortized over the estimated service lives of
the assets. Computer software development costs are amortized over a maximum of 15 years and
customer lists are amortized over a maximum of 10 years. The amortization is included in
depreciation and depletion in the consolidated statement of income.Asset retirement obligations and other environmental liabilities
Legal obligations associated with site restoration on the retirement of assets with
determinable useful lives are recognized when they are incurred, which is typically at the time the
assets are installed. The obligations are initially measured at fair value and discounted to
present value. A corresponding amount equal to that of the initial obligation is added to the
capitalized costs of the related asset. Over time the discounted asset retirement obligation amount
will be accreted for the change in its present value, and the initial capitalized costs will be
depreciated over the useful lives of the related assets.No asset retirement obligations are set up for assets with an indeterminate useful life, because
such potential obligations cannot be measured since it is not possible to estimate the settlement
dates. Provision for environmental liabilities of these and non-operating assets is made when it is
probable that obligations have been incurred and the amount can be reasonably estimated. These
liabilities are not discounted. Asset retirement obligations and other provisions for environmental
liabilities are determined based on engineering estimated costs, taking into account the
anticipated method and extent of remediation consistent with legal requirements, current technology
and the possible use of the location.Foreign-currency translation
Monetary assets and liabilities in foreign currencies have been translated at the rates
of exchange prevailing on December 31. Any exchange gains or losses are recognized in net
income.Financial instruments
The fair values of cash, accounts receivable and current liabilities approximate recorded
amounts because of the short period to receipt or payment of cash. The fair value of the companys
long-term debt is estimated based on quoted market prices for the same or similar issues or on the
current rates offered to the company for debt of the same duration to maturity. The fair values of
the companys other financial instruments, which are mainly long-term receivables, are estimated
primarily by discounting future cash flows, using current rates for similar financial instruments
under similar credit risk and maturity conditions.
 F-8




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##### Table of Contents



Notes to consolidated financial statements (continued)The company does not use financing structures for the purpose of altering accounting outcomes or
removing debt from the balance sheet. The company does not use derivative instruments to speculate
on the future direction of currency or commodity prices and does not sell forward any part of
production from any business segment.Revenues
Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and
other items are recorded when the products are delivered. Delivery occurs when the customer has
taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable
and collectibility is reasonably assured. The company does not enter into ongoing arrangements
whereby it is required to repurchase its products, nor does the company provide the customer with a
right of return.Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs
incurred up to the point of final storage prior to delivery to a customer are included in
purchases of crude oil and products in the consolidated statement of income. Delivery costs from
final storage to customer are recorded as a marketing expense in selling and general expenses.Revenues include the sales portion of certain transactions where the Company contemporaneously
negotiates purchases with the same counterparty under contractual arrangements that establish the
agreement terms either jointly, in a single contract, or separately in individual contracts. The
purchases are recorded in purchases of crude oil and products. These transactions are commonly
called purchase/sale transactions. Together with non-monetary exchanges as well as independently
transacted purchases and sales, purchase/sale transactions are used to ensure that the right crude
oil is at the appropriate refineries at the right time and the appropriate products are available
to meet consumer demands.Each purchase/sale transaction is composed of a separate purchase and a separate sale transaction
and therefore is accounted for as any other independently transacted monetary purchase or sale,
measured at fair value as agreed upon by a willing buyer and a willing seller. They are entered
into with our normal suppliers and customers for substantive business purposes and physical
delivery is required.This accounting practice has recently been addressed in EITF Issue 03-11, Reporting Realized Gains
and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for
Trading Purposes as Defined in Issue No. 02-03. While Issue 03-11 addresses the issue of gross
versus net classification for derivative instruments, it also provides guidance for purchase/sale
transaction that are not accounted for as derivative instruments. In Issue 03-11, the EITF
concluded that the determination of whether contracts not held for trading purposes should be
reported in the income statement on a gross or net basis is a matter of judgment that depends on
the relevant facts and circumstances. In the judgment of management, the relevant facts and
circumstances support accounting for these transactions in revenues, measured at fair value.Stock-based compensation
The company accounts for its stock-based compensation programs, except for the incentive stock
options granted in April 2002, by using the fair-value-based method. Under this method,
compensation expense related to the units of these programs is measured by the fair value of the
liabilities incurred and is recorded in the consolidated statement of income over the vesting
period. The fair value of liabilities is remeasured at the end of each reporting period through
settlement.As permitted by the Statement of Financial Accounting Standards No.123 (SFAS 123), the company
continues to apply the intrinsic-value-based method of accounting for the incentive stock options
granted in April 2002. Under this method, compensation expense is not recognized on the issuance of
stock options as long as the exercise price is equal to the market value at the date of grant.If the provisions of SFAS 123 had been adopted for all prior years, net income and net income per
share would have been as follows:
 millions of dollars
    
    2004
    
    
    2003
    
    
    2002Net income as shown in financial statements
    
    
    2 052
    
    
    
    1 705
    
    
    
    1 214Add: stock-based compensation expense as reported, net of tax
    
    
    84
    
    
    
    76
    
    
    
    24Deduct: stock-based compensation expense, net of tax, determined
under fair-value-based method
    
    
    (86
    )
    
    
    (81
    )
    
    
    (41
    )Pro forma net income
    
    
    2 050
    
    
    
    1 700
    
    
    
    1 197Net income per share (dollars)As reported  basic
    
    
    5.75
    
    
    
    4.58
    
    
    
    3.20 diluted
    
    
    5.74
    
    
    
    4.58
    
    
    
    3.20Pro forma  basic
    
    
    5.74
    
    
    
    4.57
    
    
    
    3.16 diluted
    
    
    5.73
    
    
    
    4.57
    
    
    
    3.16
 Consumer taxes
Taxes levied on the consumer and collected by the company are excluded from the consolidated
statement of income. These are primarily provincial taxes on motor fuels and the federal goods and
services tax. F-9




---



##### Table of Contents



2. Business segments Natural resources(a)
    
    
    Petroleum products
    
    
    Chemicalsmillions of dollars
    
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002RevenuesExternal sales (c)
    
    
        3 689
    
    
    
        3 390
    
    
    
        2 573
    
    
    
        17 503
    
    
    
        14 710
    
    
    
        13 362
    
    
    
        1 216
    
    
    
        994
    
    
    
        955Intersegment sales
    
    
        2 891
    
    
    
        2 224
    
    
    
        2 217
    
    
    
        1 666
    
    
    
        1 294
    
    
    
        1 038
    
    
    
        293
    
    
    
        238
    
    
    
        209Investment and other income
    
    
        45
    
    
    
        34
    
    
    
        104
    
    
    
        42
    
    
    
        54
    
    
    
        34
    
    
    
        
    
    
    
        
    
    
    
        Total revenues
    
    
        6 625
    
    
    
        5 648
    
    
    
        4 894
    
    
    
        19 211
    
    
    
        16 058
    
    
    
        14 434
    
    
    
        1 509
    
    
    
        1 232
    
    
    
        1 164ExpensesExploration
    
    
        59
    
    
    
        55
    
    
    
        30
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        Purchases of crude oil and products
    
    
        2 110
    
    
    
        1 873
    
    
    
        1 599
    
    
    
        14 769
    
    
    
        11 822
    
    
    
        10 781
    
    
    
        1 064
    
    
    
        882
    
    
    
        806Production and manufacturing
    
    
        1 608
    
    
    
        1 577
    
    
    
        1 228
    
    
    
        1 092
    
    
    
        1 054
    
    
    
        954
    
    
    
        184
    
    
    
        153
    
    
    
        139Selling and general (d)
    
    
        27
    
    
    
        28
    
    
    
        21
    
    
    
        1 098
    
    
    
        1 123
    
    
    
        1 076
    
    
    
        93
    
    
    
        118
    
    
    
        115Federal excise tax
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        1 264
    
    
    
        1 254
    
    
    
        1 231
    
    
    
        
    
    
    
        
    
    
    
        Depreciation and depletion
    
    
        633
    
    
    
        517
    
    
    
        477
    
    
    
        257
    
    
    
        211
    
    
    
        203
    
    
    
        13
    
    
    
        22
    
    
    
        23Financing costs (note 15)
    
    
        1
    
    
    
        1
    
    
    
        1
    
    
    
        2
    
    
    
        2
    
    
    
        1
    
    
    
        
    
    
    
        
    
    
    
        Total expenses
    
    
        4 438
    
    
    
        4 051
    
    
    
        3 356
    
    
    
        18 482
    
    
    
        15 466
    
    
    
        14 246
    
    
    
        1 354
    
    
    
        1 175
    
    
    
        1 083Income before income taxes
    
    
        2 187
    
    
    
        1 597
    
    
    
        1 538
    
    
    
        729
    
    
    
        592
    
    
    
        188
    
    
    
        155
    
    
    
        57
    
    
    
        81Income taxes(note 4)Current
    
    
        763
    
    
    
        535
    
    
    
        517
    
    
    
        299
    
    
    
        66
    
    
    
        172
    
    
    
        59
    
    
    
        13
    
    
    
        40Deferred
    
    
        (63
    )
    
    
        (77
    )
    
    
        (21
    )
    
    
        (70
    )
    
    
        119
    
    
    
        (111
    )
    
    
        (4
    )
    
    
        7
    
    
    
        (11
    )Total income tax expense
    
    
        700
    
    
    
        458
    
    
    
        496
    
    
    
        229
    
    
    
        185
    
    
    
        61
    
    
    
        55
    
    
    
        20
    
    
    
        29Income before cumulative effect of
accounting change
    
    
        1 487
    
    
    
        1 139
    
    
    
        1 042
    
    
    
        500
    
    
    
        407
    
    
    
        127
    
    
    
        100
    
    
    
        37
    
    
    
        52Cumulative effect of accounting change,
after income tax
    
    
        
    
    
    
        4
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        Net income
    
    
        1 487
    
    
    
        1 143
    
    
    
        1 042
    
    
    
        500
    
    
    
        407
    
    
    
        127
    
    
    
        100
    
    
    
        37
    
    
    
        52Capital and exploration expenditures(e)
    
    
        1 113
    
    
    
        1 007
    
    
    
        986
    
    
    
        283
    
    
    
        478
    
    
    
        589
    
    
    
        15
    
    
    
        41
    
    
    
        25Property, plant and equipmentCost
    
    
        13 538
    
    
    
        12 610
    
    
    
        11 612
    
    
    
        6 078
    
    
    
        6 069
    
    
    
        5 827
    
    
    
        682
    
    
    
        609
    
    
    
        579Accumulated depreciation and depletion
    
    
        7 337
    
    
    
        6 813
    
    
    
        6 269
    
    
    
        2 959
    
    
    
        2 856
    
    
    
        2 867
    
    
    
        459
    
    
    
        401
    
    
    
        383Net property, plant and equipment(f) (g)
    
    
        6 201
    
    
    
        5 797
    
    
    
        5 343
    
    
    
        3 119
    
    
    
        3 213
    
    
    
        2 960
    
    
    
        223
    
    
    
        208
    
    
    
        196Total assets(h)
    
    
        6 875
    
    
    
        6 418
    
    
    
        6 013
    
    
    
        5 570
    
    
    
        5 290
    
    
    
        5 127

    
    
    
        498
    
    
    
        440
    
    
    
        428
 Corporate and other
    
    
    Consolidated(b)millions of dollars
    
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002RevenuesExternal sales (c)
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        22 408
    
    
    
        19 094
    
    
    
        16 890Intersegment sales
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        Investment and other income
    
    
        (35
    )
    
    
        26
    
    
    
        14
    
    
    
        52
    
    
    
        114
    
    
    
        152Total revenues
    
    
        (35
    )
    
    
        26
    
    
    
        14
    
    
    
        22 460
    
    
    
        19 208
    
    
    
        17 042ExpensesExploration
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        59
    
    
    
        55
    
    
    
        30Purchases of crude oil and products
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        13 094
    
    
    
        10 823
    
    
    
        9 723Production and manufacturing
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        2 883
    
    
    
        2 782
    
    
    
        2 320Selling and general (d)
    
    
        
    
    
    
        
    
    
    
        10
    
    
    
        1 218
    
    
    
        1 269
    
    
    
        1 222Federal excise tax
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        1 264
    
    
    
        1 254
    
    
    
        1 231Depreciation and depletion
    
    
        5
    
    
    
        5
    
    
    
        5
    
    
    
        908
    
    
    
        755
    
    
    
        708Financing costs (note 15)
    
    
        4
    
    
    
        (123
    )
    
    
        18
    
    
    
        7
    
    
    
        (120
    )
    
    
        20Total expenses
    
    
        9
    
    
    
        (118
    )
    
    
        33
    
    
    
        19 433
    
    
    
        16 818
    
    
    
        15 254Income before income taxes
    
    
        (44
    )
    
    
        144
    
    
    
        (19
    )
    
    
        3 027
    
    
    
        2 390
    
    
    
        1 788Income taxes(note 4)Current
    
    
        (18
    )
    
    
        (4
    )
    
    
        (11
    )
    
    
        1 103
    
    
    
        610
    
    
    
        718Deferred
    
    
        9
    
    
    
        30
    
    
    
        (1
    )
    
    
        (128
    )
    
    
        79
    
    
    
        (144
    )Total income tax expense
    
    
        (9
    )
    
    
        26
    
    
    
        (12
    )
    
    
        975
    
    
    
        689
    
    
    
        574Income before cumulative effect of accounting change
    
    
        (35
    )
    
    
        118
    
    
    
        (7
    )
    
    
        2 052
    
    
    
        1 701
    
    
    
        1 214Cumulative effect of accounting change, after income tax
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        
    
    
    
        4
    
    
    
        Net income
    
    
        (35
    )
    
    
        118
    
    
    
        (7
    )
    
    
        2 052
    
    
    
        1 705
    
    
    
        1 214Capital and exploration expenditures(e)
    
    
        34
    
    
    
        33
    
    
    
        12
    
    
    
        1 445
    
    
    
        1 559
    
    
    
        1 612Property, plant and equipmentCost
    
    
        205
    
    
    
        145
    
    
    
        112
    
    
    
        20 503
    
    
    
        19 433
    
    
    
        18 130Accumulated depreciation and depletion
    
    
        101
    
    
    
        96
    
    
    

        91
    
    
    
        10 856
    
    
    
        10 166
    
    
    
        9 610Net property, plant and equipment(f) (g)
    
    
        104
    
    
    
        49
    
    
    
        21
    
    
    
        9 647
    
    
    
        9 267
    
    
    
        8 520Total assets(h)
    
    
        1 382
    
    
    
        497
    
    
    
        787
    
    
    
        14 027
    
    
    
        12 337
    
    
    
        12 003
 F-10




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##### Table of Contents



Notes to consolidated financial statements (continued)  (a)
    A significant portion of activities in the natural resources segment is conducted
jointly with other companies. The segment includes the companys share of undivided interest in
such activities as follows: millions of dollars
    
    2004
    
    
    2003
    
    
    2002Total revenues
    
    
    2 744
    
    
    
    2 494
    
    
    
    2 357Total expenses
    
    
    1 598
    
    
    
    1 577
    
    
    
    1 520Net income, after income tax
    
    
    780
    
    
    
    664
    
    
    
    557Total current assets
    
    
    367
    
    
    

    302
    
    
    
    321Long-term assets
    
    
    4 140
    
    
    
    3 553
    
    
    
    3 038Total current liabilities
    
    
    948
    
    
    
    913
    
    
    
    669Other long-term obligations
    
    
    330
    
    
    
    322
    
    
    
    293Cash flow from operating activities
    
    
    1 188
    
    
    
    883
    
    
    
    615Cash (used in) investing activities
    
    
    (858
    )
    
    
    (754
    )
    
    
    (601
    )
  (b)
    Information is presented as though each segment were a separate business activity. Intersegment
sales are made essentially at prevailing market prices. Consolidated amounts exclude intersegment
transactions, as follows: millions of dollars
    
    2004
    
    
    2003
    
    
    2002Purchases of crude oil and products
    
    
    4 849
    
    
    
    3 754
    
    
    
    3 463Operating expenses
    
    
    1
    
    
    
    2
    
    
    
    1Total intersegment sales
    
    
    4 850
    
    
    
    3 756
    
    
    
    3 464Intersegment receivables and payables
    
    
    298
    
    
    
    308
    
    
    
    352
  (c)
    Includes export sales to the United States, as follows: millions of dollars
    
    2004
    
    
    2003
    
    
    2002Natural resources
    
    
    1360
    
    
    
    1304
    
    
    
    942Petroleum products
    
    
    1074
    
    
    
    792
    
    
    
    723Chemicals
    
    
    678
    
    
    
    567
    
    
    
    520Total export sales
    
    
    3112
    
    
    
    2663
    
    
    
    2185
  (d)
    Consolidated production and manufacturing and selling and general expenses include delivery costs from final storage
areas to customers of $307 million (2003  $285 million, 2002  $216 million).(e)
    Capital and exploration expenditures of the petroleum products segment include non-cash capital
leases of $11 million in 2004 (2003  $22 million).(f)
    Includes property, plant and equipment under construction of $1,983 million (2003  $1,426
million).(g)
    With the announcement of the relocation of the companys headquarters to Calgary, management
has committed to a plan to sell a piece of property in north Toronto, Ontario, acquired in 1991 to
be the future Toronto headquarters site. Consistent with the commitment to sell and considering its
unique nature, this property, previously reported in the petroleum products segment, is now shown
in the corporate and other segment. This change is effective in 2004. Prior periods have not been
revised.(h)
    Goodwill was not amortized in the past three years. All goodwill has been assigned to the
petroleum products segment. There have been no goodwill acquisitions, impairment losses or
write-offs due to sales in the past three years. 3. Long-term debt 2004
    
    
    
    2003issued
    
    maturity date
    interest rate
    
    
    millions of dollars2003
    
    $250 million due May 26, 2005, and$250 million due August 26, 2005 (a)
    
    Variable
    
    
    
    
    
    
    5002003
    
    January 19, 2006     (a)
    
    Variable
    
    
    318
    
    
    
    318Long-term debt(b)
    
    
    
    
    
    
    318
    
    
    
    818Capital leases(c)
    
    
    
    
    
    
    49
    
    
    
    41Total long-term debt
(d) (e)
    
    
    
    
    
    
    367
    
    
    
    859
   (a)
    These are long-term variable-rate loans from Exxon Overseas
Corporation, an affiliated company of Exxon Mobil Corporation.(b)
    Average
effective interest rate was 2.5 percent for 2004 (2003  2.7 percent).(c)
    These obligations primarily relate to the capital lease for marine services, which are
provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional
five years. The average imputed interest rate was 10.3 percent in 2004 (2003  12.7 percent).(d)
    Principal payments on long-term loans of $318 million are due in 2006. Principal payments on
capital leases of approximately $4 million a year are due in each of the next five years.(e)
    These amounts exclude that portion of long-term debt, totalling $995 million (2003  $501
million), which matures within one year and is included in current liabilities. On May 6, 2004, the company filed a final short-form shelf prospectus in Canada in connection
with the issuance of medium-term notes over the 25-month period that the shelf prospectus remains
valid. The unsecured notes will be issued from time to time at the discretion of the company in an
aggregate amount not to exceed $1 billion. The company has not issued any notes under this shelf
prospectus. F-11




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##### Table of Contents



4. Income taxes millions of dollars
    
    2004
    
    
    2003
    
    
    2002Current income tax expense
    
    
    1 103
    
    
    
    610
    
    
    
    718Deferred income tax expense (a)
    
    
    (128
    )
    
    
    79
    
    
    
    (144
    )Total income tax expense(b)
    
    
    975
    
    
    
    689
    
    
    
    574Statutory corporate tax rate (percent)
    
    
    37.0
    
    
    
    38.5
    
    
    
    42.0Increase/(decrease) resulting from:Non-deductible royalty payments to
governments
    
    
    3.9
    
    
    
    5.0
    
    
    
    5.4Resource allowance in lieu of royalty
deduction
    
    
    (7.0
    )
    
    
    (7.5
    )
    
    
    (11.8
    )Manufacturing and processing credit
    
    
    
    
    
    
    0.2
    
    
    
    (0.3
    )Enacted tax-rate and tax-law changes
    
    
    (1.8
    )
    
    
    (3.1
    )
    
    
    (0.9
    )Other
    
    
    0.1
    
    
    
    (4.3
    )
    
    

    (2.3
    )Effective income tax rate
    
    
    32.2
    
    
    
    28.8
    
    
    
    32.1
 (a)
    The deferred income tax expense for the year is the difference in net deferred income tax
liabilities at the beginning and end of the year. The provisions for deferred income taxes include
net (charges)/credits for the effect of changes in tax laws and rates of $25 million in 2004 (2003
 $72 million; 2002  $15 million).(b)
    Cash outflow from income taxes, plus investment credits earned, was $641 million in 2004 (2003
 $573 million; 2002  $935 million). Deferred income taxes are based on differences between the accounting and tax values of
assets and liabilities. These differences in value are remeasured at each period-end using the
tax rates and tax laws expected to apply when those differences are realized or settled in the
future. Components of deferred income tax liabilities and assets as at December 31 were: millions of dollars
    
    2004
    
    
    2003Depreciation and amortization
    
    
    1 287
    
    
    
    1 233Successful drilling and land acquisitions
    
    
    403
    
    
    
    495Pension and benefits (a)
    
    
    (343
    )
    
    
    (286
    )Site restoration
    
    
    (158
    )
    
    
    (167
    )Net tax loss carryforwards (b)
    
    
    (57
    )
    
    
    (57
    )Capitalized interest
    
    
    26
    
    
    
    16Other
    
    
    (3
    )
    
    
    (5
    )Deferred income tax liabilities
    
    

    1 155
    
    
    
    1 229LIFO inventory valuation
    
    
    (343
    )
    
    
    (268
    )Other
    
    
    (105
    )
    
    
    (85
    )Deferred income tax assets
    
    
    (448
    )
    
    
    (353
    )Valuation allowance
    
    
    
    
    
    
    Net deferred income tax liabilities
    
    
    707
    
    
    
    876
   (a)
    Income taxes charged directly to shareholders equity related to minimum pension
liability adjustment were $41 million benefit in 2004 (2003  $57 million expense; 2002  $155
million benefit).(b)
    Tax losses can be carried forward indefinitely. The operations of the company are complex, and related tax interpretations, regulations and
legislation are continually changing. As a result, there are usually some tax matters in
question. The company believes the provision made for income taxes is adequate. 5. Reporting of fuel consumed in operations  6. Headquarters relocation  F-12




---



##### Table of Contents



Notes to consolidated financial statements (continued) 7.  Employee retirement benefits Retirement benefits, which cover almost all retired employees and their surviving spouses,
include pension-income and certain health-care and life-insurance benefits. They are met
through funded registered retirement plans and through unfunded supplementary benefits that are
paid directly to recipients. Funding of registered retirement plans complies with federal and
provincial pension regulations, and the company makes contributions to the plans based upon an
independent actuarial valuation. Pension-income benefits consist mainly of company-paid defined benefit plans that are based on
years of service and final average earnings. The company shares in the cost of health-care and
life-insurance benefits. The companys benefit obligations are based on the projected benefit
method of valuation that includes employee service to date and present compensation levels as
well as a projection of salaries and service to retirement. The expense and obligations for both funded and unfunded benefits are determined in accordance
with United States generally accepted accounting principles and actuarial procedures. The
process for determining retirement-income expense and related obligations includes making
certain long-term assumptions regarding the discount rate, rate of return on plan assets and
rate of compensation increases. The total obligation for retirement benefits exceeded the fair value of plan assets at December
31, 2004, by $1,712 million (2003  $1,357 million), $1,276 million (2003  $975 million) of
which was related to pension benefits and $436 million (2003  $382 million) to other
post-retirement benefits. The obligation and pension expense can vary significantly with
changes in the assumptions used to estimate the obligation and the expected return on plan
assets. Details of the employee retirement benefits plans are as follows: Other post-retirementPension benefits
    
    
    benefitsmillions of dollars
   
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Components of net benefit cost:Current service cost
    
    
    76
    
    
    
    71
    
    
    
    64
    
    
    
    6
    
    
    
    5
    
    
    
    4Interest cost
    
    
    237
    
    
    
    219
    
    
    
    222
    
    
    
    24
    
    
    
    22
    
    
    
    21Expected return on plan assets
    
    
    (223
    )
    
    
    (179
    )
    
    
    (191
    )
    
    
    
    
    
    
    
    
    
    
    Amortization of prior service cost
    
    
    27
    
    
    
    25
    
    
    
    25
    
    
    
    
    
    
    
    
    
    
    
    Recognized actuarial loss/(gain)
    
    
    68
    
    
    
    69
    
    
    
    34
    
    
    
    4
    
    
    
    3
    
    
    
    1Net benefit cost(a)
    
    
    185
    
    
    
    205
    
    
    
    154
    
    
    
    34
    
    
    
    30
    
    
    
    26Change in benefit obligationBenefit obligation at January 1
    
    
    3 761
    
    
    
    3 530
    
    
    
    
    
    
    
    382
    
    
    
    354Current service cost
    
    
    76
    
    
    
    71
    
    
    
    
    
    
    
    6
    
    
    
    5Interest cost
    
    
    237
    
    
    
    219
    
    
    
    
    
    
    
    24
    
    
    
    22Amendments
    
    
    37
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Actuarial loss/(gain)
    
    
    405
    
    
    
    171
    
    
    
    
    
    
    
    47
    
    
    
    19Benefits paid
    
    
    (256
    )
    
    
    (230
    )
    
    
    
    
    
    
    (23
    )
    
    
    (18
    )Benefit obligation at December 31
    
    
    4 260
    
    
    
    3 761
    
    
    
    
    
    
    
    436
    
    
    
    382Accumulated benefit obligation at December 31
    
    
    3 743
    
    
    
    3 347
    
    
    
    
    
    
    
    
    
    
    
    Change in plan assetsFair value of plan assets at January 1
    
    
    2 786
    
    
    
    2 104Actual return on plan assets
    
    
    315
    
    
    
    377Company contributions
    
    
    114
    
    
    
    511Payments directly to participants
    
    
    25
    
    
    
    24Benefits paid
    
    
    (256
    )
    
    
    (230
    )Fair value of plan assets at December 31
    
    
    2 984
    
    
    
    2 786Excess/(deficiency) of plan assets
over benefit obligation
    
    
    (1276
    )
    
    
    (975
    )
    
    
    
    
    
    
    (436
    )
    
    
    (382
    )Unrecognized
net actuarial (gain)/loss (b)
    
    
    1073
    
    
    
    829
    
    
    
    
    
    
    
    95
    
    
    
    52Unrecognized
prior service cost (b)
    
    
    99
    
    
    
    89
    
    
    
    
    
    
    
    
    
    
    
    Net amount recognized
    
    
    (104
    )
    
    
    (57
    )
    
    
    
    
    
    
    (341
    )
    
    
    (330
    )Amount recognized in the consolidated balance
sheet consists of:Accrued benefit cost (note 8)
    
    
    (759
    )
    
    
    (561
    )
    
    
    
    
    
    
    (341
    )
    
    
    (330
    )Intangible assets
    
    
    97
    
    
    
    89
    
    
    
    
    
    
    
    
    
    
    
    Accumulated
other nonowner changes in equity, minimum pension liability adjustment
    
    
    558
    
    
    
    415
    
    
    
    
    
    
    
    
    
    
    
    Net amount recognized
    
    
    (104
    )
    
    
    (57
    )
    
    
    
    
    
    
    (341
    )
    
    
    (330
    )
 F-13




---



##### Table of Contents



Assumptions
    
    
    
    
    
    
    
    
    
    
    
    
    
    Other post-retirementPension benefits
    
    
    benefitsmillions of dollars
    
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Assumptions used to determine benefit obligations at December 31 (percent)Discount rate
    
    
    5.75
    
    
    
    6.25
    
    
    
    
    
    
    
    5.75
    
    
    
    6.25Long-term rate of compensation increase
    
    
    3.50
    
    
    
    3.50
    
    
    
    
    
    
    
    3.50
    
    
    
    3.50Assumptions used to determine net benefit cost for years ended December 31 (percent)Discount rate
    
    
    6.25
    
    
    
    6.25
    
    
    
    6.75
    
    
    
    6.25
    
    
    
    6.25
    
    
    
    6.75Long-term rate of compensation increase
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50Long-term rate of return on funded assets
    
    
    8.25
    
    
    
    8.25
    
    
    
    8.25
    
    
    
    
    
    
    
    
    
    
    
    
   (a)
    A summary of net benefit costs with elements of employee future benefit cost before and after adjustments to recognize the long-term nature of employee benefit cost is shown in the table below: Pension benefits
    
    
    Other post-retirement benefitsmillions of dollars
    
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Components of net benefit cost:Current service cost
    
    
    76
    
    
    
    71
    
    
    
    64
    
    
    
    6
    
    
    
    5
    
    
    
    4Interest cost
    
    
    237
    
    
    
    219
    
    
    
    222
    
    
    
    24
    
    
    
    22
    
    
    
    21Actual return on plan assets
    
    
    (315
    )
    
    
    (377
    )
    
    
    107
    
    
    
    
    
    
    
    
    
    
    
    Plan amendments for prior service
    
    
    37
    
    
    
    
    
    
    
    27
    
    
    
    
    
    
    
    
    
    
    
    Actuarial loss/(gain)
    
    
    405
    
    
    
    171
    
    
    
    196
    
    
    
    47
    
    
    
    19
    
    
    
    25Elements of employee future benefit costs before
adjustments to recognize the long-term nature of
employee future benefit costs
    
    
    440
    
    
    
    84
    
    
    
    616
    
    
    
    77
    
    
    
    46
    
    
    
    50Adjustments to recognize the long-term nature
of employee future benefit costs:Difference between expected return and actual return
on plan assets for the year
    
    
    92
    
    
    
    198
    
    
    
    (298
    )
    
    
    
    
    
    
    
    
    
    
    Difference between amortization of prior service costs
for the year and actual plan amendments for the year
    
    
    (10
    )
    
    
    25
    
    
    
    (2
    )
    
    
    
    
    
    
    
    
    
    
    Difference between actuarial (gain)/loss recognized
for the year and actuarial (gain)/loss on accrued
benefit obligation for the year
    
    
    (337
    )
    
    
    (102
    )
    
    
    (162
    )
    
    
    (43
    )
    
    
    (16
    )
    
    
    (24
    )Net benefit cost
    
    
    185
    
    
    
    205
    
    
    
    154
    
    
    
    34
    
    
    
    30
    
    
    
    26
  (b)
    Unrecorded assets/(liabilities) are amortized over the average remaining service life of employees, which for 2005 and subsequent years is 13 years
(2004  13 years; 2003  13.5 years). Plan assets The companys pension plan asset allocation at December 31, 2003 and 2004, and target allocation for 2005 are as follows: Target
    
    
    Percentage of plan assetsallocation
    
    
    at December 31Asset category (percent)
    
    2005
    
    
    2004
    
    
    2003Equities
    
    
    50  75
    
    
    
    62
    
    
    
    62Bonds
    
    
    25  50
    
    
    
    38
    
    
    
    38Other
    
    
    0  10
    
    
    
    
    
    
    
    Total
    
    
    
    
    
    
    100
    
    
    
    100
  The company establishes the long-term expected rate of return by developing a forward-looking
long-term return assumption for each asset class, taking into account factors such as the expected
real return for the specific asset class and inflation. A single, long-term rate of return is then
calculated as the weighted average of the target asset allocation and the long-term return
assumption for each asset class. The 2004 long-term expected return of 8.25 percent used in the
calculations of pension expense compares to an actual rate of return over the past decade of 10.7
percent.The companys investment strategy for benefit plan assets reflects a long-term view, a careful
assessment of the risks inherent in various asset classes and broad diversification to reduce the
risk of the total portfolio. The company primarily invests in funds that follow an index-based
strategy to achieve its objectives of diversifying risk while minimizing costs. The fund holds
Imperial Oil Limited common shares only to the extent necessary to replicate the relevant equity
index. Asset-liability studies, or simulations of the interaction of cash flows associated with
both assets and liabilities, are periodically used to establish the preferred target asset
allocation. The target asset allocation for equity securities reflects the long-term nature of the
liability. The balance of the fund is targeted to debt securities. F-14




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##### Table of Contents



Notes to consolidated
financial statements (continued)  Cash flows


The following benefit payments, which reflect expected future service, as appropriate, are
expected to be paid: OtherPension
    
    
    post-retirementmillions of dollars
    
    benefits
    
    
    benefits2005
    
    
    230
    
    
    
    202006
    
    
    234
    
    
    
    222007
    
    
    238
    
    
    
    242008
    
    
    244
    
    
    
    262009
    
    
    251
    
    
    
    28Years 2010
 2014
    
    
    1398
    
    
    
    161
  In 2005, the company expects to make cash contributions of about $350 million to its pension
plan.A summary of the change in other nonowner changes in equity related to the minimum pension
liability adjustment is shown in the table below. Pension benefitsmillions of dollars
    
    2004
    
    
    2003
    
    
    2002Increase/(decrease) in accumulated other nonowner
changes in equity, before tax
    
    
    (143
    )
    
    
    106
    
    
    
    (393
    )Deferred income tax (charge)/credit (note 4)
    
    
    41
    
    
    
    (57
    )
    
    
    155Increase/(decrease) in accumulated other nonowner
changes in equity, after tax
    
    
    (102
    )
    
    
    49
    
    
    
    (238
    )
  A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below: Pension benefitsmillions of dollars
    
    2004
    
    
    2003For funded pension plans with accumulated benefit
obligations in excess of plan assets:Projected benefit obligation
    
    
    3 876
    
    
    
    3 464Accumulated benefit obligation
    
    
    3 430
    
    
    
    3 126Fair value of plan assets
    
    
    2 984
    
    
    
    2 786Accumulated benefit obligation less fair value of plan assets
    
    
    446
    
    
    
    340For unfunded plans covered by book reserves:Projected benefit obligation
    
    
    384
    
    
    
    297Accumulated benefit obligation
    
    
    313
    
    
    
    221
  Additional expenses include contributions to defined contribution plans, primarily the employee savings plan, of $32 million
in 2004 (2003  $31 million; 2002  $30 million).The most recent independent actuarial valuation was as of June 30, 2004, and the next required valuation will be as of
June 30, 2005. The measurement date used to determine the fair value of plan assets and the benefit obligations was
December 31, 2004.A one-percent change in the assumptions at which retirement liabilities could be effectively settled is shown as follows: increase/(decrease)
    
    One-percent
    
    
    One-percentmillions of dollars
    
    increase
    
    
    decreaseRate of return on plan assets:Effect on net benefit costs
    
    
    (30
    )
    
    
    30Discount rate:Effect on net benefit costs
    
    
    (45
    )
    
    
    50Effect on benefit obligations
    
    
    (525
    )
    
    
    645Rate of pay increases:Effect on net benefit costs
    
    
    30
    
    
    
    (25
    )Effect on benefit obligations
    
    
    160
    
    
    
    (140
    )
  For measurement purposes, a five-percent health-care cost
trend rate was assumed for 2004 and thereafter. A one-percent change in the
assumed health-care cost trend rate would have the following effects: increase/(decrease)
    
    One-percent
    
    
    One-percentmillions of dollars
    
    increase
    
    
    decreaseEffect on service and interest cost components
    
    
    4
    
    
    
    (3
    )Effect on other post-retirement benefits obligations
    
    
    45
    
    
    
    (40
    )
 F-15




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##### Table of Contents



8.  Other long-term obligations millions of dollars
    
    2004
    
    
    2003Employee retirement benefits (note 7) (a)
    
    
    1 052
    
    
    
    847Asset retirement obligations and other environmental liabilities (b)
    
    
    380
    
    
    
    393Other obligations
    
    
    93
    
    
    
    74Total other long-term obligations
    
    
    1 525
    
    
    
    1 314
   (a)
    Total recorded employee retirement benefits obligations also include $48 million in current
liabilities (2003  $44 million).(b)
    Total asset retirement obligations and other environmental liabilities also include
$76 million in current liabilities (2003  $69 million). The estimated cash flows of asset
retirement obligations have been discounted at six percent. The total undiscounted amount
of the estimated cash flows required to settle the obligations is $970 million. Payments
to settle the obligations occur on an ongoing basis and will continue over the lives of
the operating assets, which can exceed 25 years. The change in asset retirement
obligations liability is as follows: millions of dollars
    
    2004
    
    
    2003Asset retirement obligations liability at January 1
    
    
    327
    
    
    
    341Additions
    
    
    16
    
    
    
    Accretion
    
    
    22
    
    
    
    20Settlement
    
    
    (37
    )
    
    
    (34
    )Asset retirement obligations liability at December 31
    
    
    328
    
    
    
    327
 9.  Derivatives and financial instruments  No significant energy derivatives, foreign-exchange forward contracts or currency and
interest-rate swaps were transacted in the past three years. The company maintains a system of
controls that includes a policy covering the authorization, reporting and monitoring of
derivative activity.The fair value of the companys financial instruments is determined by reference to various
market data and other appropriate valuation techniques. There are no material differences
between the fair values of the companys financial instruments and the recorded book value. 10.  Incentive compensation programs  Incentive compensation programs are designed to retain selected employees, reward them for high
performance and promote individual contributions to sustained improvement in the companys
future business performance and shareholder value.Incentive share units, deferred share units, earnings bonus units and restricted stock
units

Incentive share units have value if the market price of the companys common shares when
the unit is exercised exceeds the market value when the unit was issued. The issue price of
incentive share units is the closing price of the companys shares on the Toronto Stock
Exchange on the grant date. Up to 50 percent of the units may be exercised after one year from
issuance; an additional 25 percent may be exercised after two years; and the remaining 25
percent may be exercised after three years. Incentive share units are eligible for exercise up
to 10 years from issuance. The units may expire earlier if employment is terminated other than
by retirement, death or disability.The deferred share unit plan is made available to selected executives and nonemployee
directors. The selected executives can elect to receive all or part of their performance bonus
compensation in units, and the nonemployee directors can elect to receive all or part of their
directors fees in units. The number of units granted to executives is determined by dividing
the amount of the bonus elected to be received as deferred share units by the average of the
closing prices of the companys shares on the Toronto Stock Exchange for the five consecutive
trading days immediately prior to the date that the bonus would have been paid. The number of
units granted to a nonemployee director is determined at the end of each calendar quarter by
dividing the amount of directors fees for the calendar quarter that the nonemployee director
elected to receive as deferred share units by the average closing price of the companys shares
for the five consecutive trading days immediately prior to the last day of the calendar
quarter. Additional units are granted based on the cash dividend payable on the companys
 shares divided by the average closing price immediately prior to the payment date for that
dividend and multiplying the resulting number by the number of deferred share units held by the
recipient.Deferred share units cannot be exercised until after termination of employment with the company
or resignation as a director and must be exercised no later than December 31 of the year
following termination or resignation. On the exercise date, the cash value to be received for
the units is determined based on the average closing price of the companys shares for the five
consecutive trading days immediately prior to the date of exercise.The earnings bonus unit plan is available to selected executives. Each earnings bonus unit
entitles the recipient to receive an amount equal to the companys cumulative net earnings per
common share as announced each quarter beginning after the grant. Payout occurs on the fifth
anniversary of the grant or when the maximum settlement value per unit is reached, if earlier.
Earnings bonus units may expire if employment is terminated other than by death or disability. F-16




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##### Table of Contents



Notes to consolidated financial statements (continued)  Under the restricted stock unit plan, each unit entitles the recipient to the conditional right
to receive from the company, upon exercise, an amount equal to the closing price of the
companys common shares on the Toronto Stock Exchange on the exercise dates. Fifty percent of
the units are exercised three years following the grant date, and the remainder are exercised
seven years following the grant date. The units may be exercised early in the event of death or
disability.All units require settlement by cash payments with one exception. The restricted stock unit
plan was amended for units granted in 2003 and future years by providing that the recipient may
receive one common share of the company per unit or elect to receive the cash payment for the
units to be exercised on the seventh anniversary of the grant date. The maximum number of
common shares that may be issued under the restricted stock unit plan is 3.5 million.For deferred share units, a charge is made to expense in the year of grant equal to the cash
performance bonus payment and directors fees foregone. The company records expense for
incentive share, deferred share and restricted stock units based on changes in the price of
common shares in the year. Expense for earnings bonus units is recorded based on the cumulative
net earnings per outstanding common share from issue date, up to the maximum settlement value
for the units.Incentive stock options
In April 2002, incentive stock options were granted for the purchase of the companys
common shares at an exercise price of $46.50 per share. Up to 50 percent of the options may be
exercised on or after January 1, 2003, a further 25 percent may be exercised on or after
January 1, 2004, and the remaining 25 percent may be exercised on or after January 1, 2005. Any
unexercised options expire after April 29, 2012. The company has not issued incentive stock
options since 2002 and has no plans to issue incentive stock options in the future.The company does not recognize compensation expense on the issuance of stock options because
the exercise price is equal to the market value at the date of grant. If the fair-value-based
method of accounting had been adopted, the impact on net income and earnings per share would be
as shown in the summary of significant accounting policies on page F-9. The average fair value
of each option granted during 2002 was $12.70. The fair value was estimated at the grant date
using an option-pricing model with the following weighted average assumptions: risk-free
interest rate of 5.7 percent, expected life of five years, volatility of 25 percent and a
dividend yield of 1.9 percent.The company has purchased shares on the market to fully offset the dilutive effects from the
exercise of stock options. This practice is expected to continue.A summary of the incentive compensation programs is as follows: Number of units
    
    
    Expensed in
    
    
    Obligationsoutstanding atCancelled
    
    
    Outstanding at
    
    
    period
    
    
    December 31Granted
    
    
    Exercised
    
    
    or adjusted
    
    
    December 31
    
    
    (millions of dollars)
    
    
    (millions of dollars)Incentive share units2004
    
    
    
    
    
    
    (1 619 907
    )
    
    
    (3 000
    )
    
    
    5 266 423
    
    
    
    94
    
    
    
    2452003
    
    
    
    
    
    
    (1 142 145
    )
    
    
    19 225
    
    
    
    6 889 330
    
    
    
    109
    
    
    
    2162002
    
    
    7 000
    
    
    
    (812 550
    )
    
    
    (5 325
    )
    
    
    8 012 250
    
    
    
    39
    
    
    
    142Deferred share units2004
    
    
    4 899
    
    
    
    
    
    
    
    
    
    
    
    48 810
    
    
    
    1
    
    
    
    42003
    
    
    8 253
    
    
    
    (49 486
    )
    
    
    (379
    )
    
    
    43 911
    
    
    
    1
    
    
    
    32002
    
    
    7 479
    
    
    
    (9 853
    )
    
    
    
    
    
    
    85 523
    
    
    
    
    
    
    
    4Earnings bonus units2004
    
    
    1 889 740
    
    
    
    (1 139 160
    )
    
    
    
    
    
    
    3 984 830
    
    
    
    7
    
    
    
    62003
    
    
    2 221 580
    
    
    
    (1 156 370
    )
    
    
    
    
    
    
    3 234 250
    
    
    
    3
    
    
    
    32002
    
    
    1 036 500
    
    
    
    
    
    
    
    
    
    
    
    2 169 040
    
    
    
    3
    
    
    
    3Incentive stock options2004
    
    
    
    
    
    
    (274 250
    )
    
    
    (7 400
    )
    
    
    2 854 500
    
    
    
    
    
    
    
    2003
    
    
    
    
    
    
    (49 050
    )
    
    
    (11 500
    )
    
    
    3 136 150
    
    
    
    
    
    
    
    2002
    
    
    3 210 200
    
    
    
    
    
    
    
    (13 500
    )
    
    
    3 196 700
    
    
    
    
    
    
    
    Restricted stock units2004
    
    
    987 480
    
    
    
    
    
    
    
    (5 710
    )
    
    
    2 642 325
    
    
    
    31
    
    
    
    412003
    
    
    872 085
    
    
    
    (3 300
    )
    
    
    (120
    )
    
    
    1 660 555
    
    
    
    11
    
    
    
    112002
    
    
    791 890
    
    
    
    
    
    
    
    
    
    
    
    791 890
    
    
    
    
    
    
    
    
 F-17




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##### Table of Contents



11. Investment and other income  Investment and other income includes gains and losses on asset sales as follows: millions of dollars
    
    2004
    
    
    2003
    
    
    2002Proceeds from asset sales
    
    
    102
    
    
    
    56
    
    
    
    61Book value of assets sold

    
    
    59
    
    
    
    44
    
    
    
    56Gain/(loss) on asset sales, before tax
    
    
    43
    
    
    
    12
    
    
    
    5Gain/(loss) on asset sales, after tax
    
    
    32
    
    
    
    10
    
    
    
    4
  Investment and other income also includes a non-recurring loss of $53 million ($42 million
after income taxes) from the remeasurement at fair value of the north Toronto, Ontario, property
described in note 2. The change in intended use of the property, together with managements
commitment to sell, led to the remeasurement. The fair value of the property was determined using
valuation techniques consistent with a market approach, adjusted as appropriate for differences. 12. Commitments and contingent liabilities  At December 31, 2004, the company had commitments for noncancellable operating leases and other
long-term agreements that require the following minimum future payments: Aftermillions of dollars
    
    2005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    2009Operating leases (a)
    
    
    62
    
    
    
    55
    
    
    
    47
    
    
    
    41
    
    
    
    38
    
    
    
    91Unconditional purchase obligations(b)
    
    
    102
    
    
    
    42
    
    
    
    42
    
    
    
    42
    
    
    
    42
    
    
    
    55Firm capital commitments (c)
    
    
    119
    
    
    
    24
    
    
    
    8
    
    
    
    13
    
    
    
    7
    
    
    
    Other long-term agreements (d)
    
    
    241
    
    
    
    196
    
    
    
    62
    
    
    
    61
    
    
    
    59
    
    
    
    198
   (a)
    Total rental expense incurred for operating leases in 2004 was $104 million (2003  $124
million; 2002  $124 million), which included minimum
rental expenditures of $77 million (2003 
$93 million; 2002  $91 million). Related rental income was not material.(b)
    Unconditional purchase obligations are those long-term commitments that are noncancellable or cancellable only
under certain conditions. These mainly pertain to pipeline throughput agreements. Total payments
under unconditional purchase obligations were $117 million in
2004 (2003  $114 million; 2002 
$115 million).(c)
    Firm capital commitments related to capital projects, shown on an undiscounted
basis, totalled approximately $171 million at the end of 2004 (2003   $189 million). The largest
commitment outstanding at year-end 2004 was associated with the companys share of upstream capital
projects of $112 million at Syncrude and offshore Canadas East Coast.(d)
    Other long-term agreements include primarily raw material supply and transportation services agreements. Total
payments under other long-term agreements were $355 million in
2004 (2003  $332 million; 2002 
$288 million). Payments under other long-term agreements related to the companys share of
undivided interest in activities conducted jointly with other companies are approximately $37
million per year.  Other commitments arising in the normal course of business for operating and capital needs
do not materially affect the companys consolidated financial position.The company was contingently liable at December 31, 2004, for a maximum of $175 million relating to
guarantees for purchasing operating equipment and other assets from its rural marketing associates
upon expiry of the associate agreement or the death or resignation of the associate. The company
expects that the fair value of the operating equipment and other assets so purchased would cover
the maximum potential amount of future payments under the guarantees.The company provides in its financial statements for asset retirement obligations and other
environmental liabilities (see accounting policies on page F-8). Provision is not made with respect
to those manufacturing, distribution and marketing facilities with indeterminate useful lives,
because such potential obligations
cannot be measured since it is not possible to estimate the settlement dates. These are primarily
currently operated sites. These costs are not expected to have a material effect on the companys
current consolidated financial position.Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. Based on a
consideration of all relevant facts and circumstances, the company does not believe the ultimate
outcome of any currently pending lawsuits against the company will have a material adverse effect
upon the companys operations or financial condition. There are no events or uncertainties known to
management beyond those already included in reported financial information that would indicate a
material change in future operating results or financial condition. 13. Common shares  The number of authorized common shares of the company as at December 31, 2004, was 450,000,000,
unchanged from January 1, 2003.  From 1995 to 2003, the company purchased shares under nine 12-month normal course share-purchase
programs, as well as an auction tender. On June 23, 2004, another 12-month normal course
share-purchase program was implemented with an allowable purchase of 17.9 million shares (five
percent of the total at June 21, 2004), less any shares purchased by the employee savings plan and
company pension fund. The results of these activities are shown below. Purchased
    
    
    Millions ofYear
    
    shares
    
    
    dollars1995 to 2002
    
    
    202 661 201
    
    
    
    5 1692003
    
    
    16 259 538
    
    
    
    7992004
    
    
    13 606 712
    
    
    
    872Cumulative purchases to date
    
    
    232 527 451
    
    
    
    6 840
  Exxon Mobil Corporations participation in the above maintained its ownership interest in
Imperial at 69.6 percent. F-18




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##### Table of Contents



Notes to consolidated financial statements (continued)  The companys common share activities are summarized below: At stated value,Thousands
    
    
    millionsof shares
    
    
    of dollarsBalance as at January 1, 2002
    
    
    379 159
    
    
    
    1 941Issued for cash under the stock option plan
    
    
    
    
    
    
    Purchases
    
    
    (296
    )
    
    
    (2
    )Balance as at December 31, 2002
    
    
    378 863
    
    
    
    1 939Issued for cash under the stock option plan
    
    
    49
    
    
    
    2Purchases
    
    
    (16 259
    )
    
    
    (82
    )Balance as at December 31, 2003
    
    
    362 653
    
    
    
    1 859Issued for cash under the stock option plan
    
    
    274
    
    
    
    13Purchases
    
    
    (13 607
    )
    
    
    (71
    )Balance as at December 31, 2004
    
    
    349 320
    
    
    
    1 801
  The following table provides the calculation of basic and diluted earnings per share: 2004
    
    
    2003
    
    
    2002Net
income per common share  basicIncome before cumulative effect of accounting change (millions of dollars)
    
    
    2 052
    
    
    
    1 701
    
    
    
    1 214Net income (millions of dollars)
    
    
    2 052
    
    
    
    1 705
    
    
    
    1 214Weighted average number of common shares outstanding (thousands of shares)
    
    
    356 834
    
    
    
    372 011
    
    
    
    378 875Net income per common share (dollars)Income before cumulative effect of accounting change
    
    
    5.75

    
    
    
    4.57
    
    
    
    3.20Cumulative effect of accounting change, after income tax
    
    
    
    
    
    
    0.01
    
    
    
    Net income
    
    
    5.75
    
    
    
    4.58
    
    
    
    3.20Net
income per common share  dilutedIncome before cumulative effect of accounting change (millions of dollars)
    
    
    2 052
    
    
    
    1 701
    
    
    
    1 214Net income (millions of dollars)
    
    
    2 052
    
    
    
    1 705
    
    
    
    1 214Weighted average number of common shares outstanding (thousands of shares)
    
    
    356 834
    
    
    
    372 011
    
    
    
    378 875Effect of employee stock-based awards (thousands of shares)
    
    
    818
    
    
    
    143
    
    
    
    1Weighted average number of common shares outstanding,assuming dilution (thousands of shares)
    
    
    357 652
    
    
    
    372 154
    
    
    
    378 876Net income per common share (dollars)Income before cumulative effect of accounting change
    
    
    5.74
    
    
    
    4.57
    
    
    
    3.20Cumulative effect of accounting change, after income tax
    
    
    
    
    
    
    0.01
    
    
    
    Net income
    
    
    5.74
    
    
    
    4.58
    
    
    
    3.20
 14.  Miscellaneous financial information  In 2004, net income included an after-tax gain of
$23 million (2003  $9 million gain; 2002 
$2 million loss) attributable to the effect of changes in last-in, first-out (LIFO)
inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying
values at December 31, 2004, by $1,013 million (2003  $797 million). Inventories of crude oil
and products at year-end consisted of the following: millions of dollars
    
    2004
    
    
    2003Crude oil
    
    
    165
    
    
    
    161Petroleum products
    
    
    190
    
    
    
    175Chemical products
    
    
    59
    
    
    
    57Natural gas and other
    
    
    18
    
    
    
    14Total inventories of crude oil and products
    
    
    432
    
    
    
    407
  Research and development costs in 2004 were $70 million
(2003  $63 million; 2002  $64
million) before investment tax credits earned on these expenditures
of $7 million (2003  $10
million; 2002  $10 million). The net costs are included in expenses due to the uncertainty of
future benefits.Cash flow from operating activities included dividends of $18 million received from equity
investments in 2004 (2003  $15 million; 2002  $18 million). F-19




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15. Financing costs millions of dollars
    
    2004
    
    
    2003
    
    
    2002Debt-related interest
    
    
    37
    
    
    
    38
    
    
    
    40Capitalized interest
    
    
    (34
    )
    
    
    (33
    )
    
    
    (12
    )Net interest expense
    
    
    3
    
    
    
    5
    
    
    
    28Other interest
    
    
    4
    
    
    
    4
    
    
    
    2Total interest expense(a)
    
    
    7
    
    
    
    9
    
    
    
    30Foreign-exchange expense/(gain) on long-term debt
    
    
    
    
    
    
    (129
    )
    
    
    (10
    )Total financing costs
    
    
    7
    
    
    
    (120
    )
    
    
    20
   (a)
    Cash interest payments in 2004 were $41 million (2003  $38 million; 2002  $41
million). The weighted-average interest rate on short-term borrowings in 2004 was 2.3
percent (2003  3.1 percent). 16. Transactions with related parties  Revenues and expenses of the company also include the results of transactions with
Exxon Mobil Corporation and affiliated companies (ExxonMobil) in the normal course of
operations. These were conducted on terms as favourable as they would have been with
unrelated parties and primarily consisted of the purchase and sale of crude oil, petroleum
and chemical products, as well as transportation, technical and engineering services.
Transactions with ExxonMobil also included amounts paid and received in connection with
the companys participation in a number of natural resource activities conducted jointly
in Canada. The company has agreements with affiliates of Exxon Mobil Corporation to
provide computer and customer support services to the company and to share common business and operational support
services to allow the companies to consolidate duplicate work and systems. The amounts paid
or received have been reflected in the statement of income as shown below. millions of dollars
    
    2004
    
    
    2003
    
    
    2002Total revenues
    
    
    1 580
    
    
    
    950
    
    
    
    1 036Purchases of crude oil and products
    
    
    3 133
    
    
    
    2 464
    
    
    
    2 134Total expenses
    
    
    43
    
    
    
    14
    
    
    
    57
  Accounts payable due to Exxon Mobil Corporation at December 31, 2004, with respect to the
above transactions were $67 million (2003  $167 million).Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.During 2003, the company borrowed $818 million (Cdn) from Exxon Overseas Corporation under two
long-term loan agreements as presented in note 3. Interest paid on the loans in 2004 was $20
million (2003  $14 million).During 2004, the company extended loans of $32 million to Montreal Pipe Line Limited, in which the
company has an equity interest, for financing of the equity companys capital expenditure programs
and working capital requirements. 17. Net payments/payables to governments millions of dollars
    
    2004
    
    
    2003
    
    
    2002Current income tax expense (note 4)
    
    
    1 103
    
    
    
    610
    
    
    
    718Federal excise tax
    
    
    1 264
    
    
    
    1 254
    
    
    
    1 231Property taxes included in expenses
    
    
    85
    
    
    
    80
    
    
    
    85Payroll and other taxes included in expenses
    
    
    50
    
    
    
    52
    
    
    
    51GST/QST/HST collected (a)
    
    
    2 297
    
    
    
    2 015
    
    
    
    1 717GST/QST/HST input tax credits (a)
    
    
    (1 948
    )
    
    
    (1705
    )
    
    
    (1368
    )Other consumer taxes collected for governments
    
    
    1 670
    
    
    
    1 662
    
    
    
    1 589Crown royalties
    
    
    472
    
    
    
    418
    
    
    
    314Total paid or payable to governments
    
    
    4 993
    
    
    
    4 386
    
    
    
    4 337Less investment tax credits and other receipts
    
    
    14
    
    
    
    30
    
    
    
    12Net paid or payable to governments
    
    
    4 979
    
    
    
    4 356
    
    
    
    4 325Net payments to:Federal government
    
    
    2 472
    
    
    
    2 061
    
    
    
    2 171Provincial governments
    
    
    2 422
    
    
    
    2 215
    
    
    
    2 069Local governments
    
    
    85
    
    
    
    80
    
    
    
    85Net paid or payable to governments
    
    
    4 979
    
    
    
    4 356
    
    
    
    4 325
   (a)
    The abbreviations refer to the federal goods and services tax, the Quebec sales tax
and the federal/provincial harmonized sales tax, respectively. The HST is applicable in
the provinces of Nova Scotia, New Brunswick and Newfoundland and Labrador. F-20