Imperial Oil Annual Report 2004

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FY2004 Annual Report · Imperial Oil

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125 years of
energy leadership

125Annual report to shareholders 2004

The importance of energy

• Energy is essential for world economic and social development.

• Hydrocarbons will remain a dominant source of the

world’s energy for a long time to come.

• Energy demand is rising worldwide, and new supplies

of petroleum are required to meet this demand.

• Canada is uniquely positioned to participate in this

growing market.

The International Energy Agency (IEA) has stated that oil and gas currently account for
about 60 percent of all the energy consumed worldwide and, given the projected growth
in demand, that is not expected to change significantly over the next few decades.

Contents
Letter to shareholders

2
4 Year in review
6 Natural resources
10
13 Chemicals
14
16 Caring for our communities

Petroleum products

Principled people and practices

Financial section

19
20 Management’s discussion and analysis
Frequently used financial terms
32
36 Management and auditors’ reports
37
Financial statements, accounting policies and notes
57 Natural resources segment – supplemental information
60 Share ownership, trading and performance
61 Quarterly financial and stock-trading data
62

Information for investors
Directors, senior management and officers

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.

Annual report 2004

5010015020025035030001971OilGasCoalOther**Other energy sources include solar, wind, nuclear, hydro, biomass and waste Source: International Energy Agency2020201020022030World energy demand grows 1.7 percent a year millions of oil-equivalent barrels a dayThe Imperial Oil advantage

• The leading resource position in Canada with a diverse asset base

• A consistent management approach and a disciplined investment strategy

• A record of continually improving base operations

• Financial strength unparalleled in the industry

• A leader in the development and use of technology

• High-performing, principled employees

• Industry-leading return on capital employed

• Imperial has provided superior returns to shareholders – in 2004, the total return was more

than 25 percent and has averaged almost 20 percent a year for the past 10 years.

Financial highlights

Net income (millions of dollars)
Net income per share (dollars) (a) – diluted
Return on average shareholders’ equity (percent) (b)
Return on average capital employed (percent) (c)
Annual shareholders’ return (percent) (d)

2004

2 052
5.74
34.6
27.7
25.3

2003

1 705
4.58
32.6
25.3
30.5

2002

1 214
3.20
26.5
20.0
3.2

2001

1 223
3.11
28.8
22.3
14.5

2000

1 408
3.37
32.7
26.5
30.2

(a) Calculated by reference to the average number of shares outstanding, weighted monthly (page 60).
(b) Net income divided by average shareholders’ equity (page 39).
(c) A definition of return on average capital employed can be found on page 33.
(d) Includes share appreciation and dividends.

Imperial Oil Limited

Value of $100 invested on December 31, 1993Source: Bloomberg600500400300200100094959697989900S&P/TSX CompositeS&P/TSX EnergyImperial Oil01020304Sustained increase in shareholder value 10-year cumulative total returns2004 increase121086420Production* Before year-end price/cost revisionsProved reserves*Non- proved resources• Significant resource base• Long-life reserves• Non-proved resource of 11.5 billion oil-equivalent barrels• 2004 net increase in oil-sands resourceResource base an enabler for growth billions of oil-equivalent barrels – 2004Tim J. Hearn, chairman, president and chief executive officer

Letter to shareholders

Imperial’s ongoing strategy
is to increase long-term
shareholder value by
continually improving base
operations while investing
in attractive growth
opportunities.

The company had another excellent
year in 2004. A new record was set
for earnings at $2,052 million or
$5.74 a share, return on average
capital employed was 28 percent and
return on shareholders’ equity was
35 percent. Regular per-share dividend
payments increased for the 10th year
in a row, and almost $1.2 billion was
returned to shareholders through
dividend payments and the share-
buyback program. The total return
to shareholders including dividends
paid and share-price appreciation
was 25 percent.

Higher commodity prices and strong
refining and petrochemical margins
were major factors in Imperial’s
improved earnings. The company’s
operations were also solid. Safety
performance was the best on record,
operating reliability improved and
record volumes were achieved in
several areas. Looking ahead,
because of the cyclical nature of the
business, which is strongly influenced
by the changing fundamentals of
supply and demand, it would not be

prudent to expect 2004 prices
and margins to be sustained over a
long period. For this reason, Imperial’s
business model remains focused
on sound financial management,
a disciplined investment strategy
and improving those things we
can control.

The company maintained its strong
financial position while making capital
and exploration expenditures of
more than $1.4 billion. Major natural
resources opportunities were
advanced. A significant development
drilling program was undertaken at
our oil-sands operations at Cold Lake,
Alberta; work on the major upgrader
expansion at Syncrude was advanced;
the main regulatory applications for
the Mackenzie gas project were filed;
and delineation drilling proceeded at
the Kearl oil-sands site in northeastern
Alberta. In petroleum products, work
began on modifying refineries to
produce low-sulphur diesel fuel to
meet future regulatory requirements
and further reduce smog-forming
emissions.

Annual report 2004

Overall, Imperial is well positioned
for long-term earnings growth. The
company’s diverse base of oil and gas
resources in Canada, which exceeds
13 billion oil-equivalent barrels, is the
largest in this country, and we have
access to world-leading research,
technology and project expertise.
With these advantages, together
with excellent financial strength, a
consistent management approach
and a disciplined investment strategy,
I believe Imperial will remain an
industry leader in both downstream
and upstream operations for many
years to come. Moving our head
office to Calgary in 2005 will further
strengthen the company’s strategic
focus, while improving organizational
effectiveness and productivity.

Imperial’s resources and capabilities
will be key in producing new Canadian
supplies of oil and gas. In the coming
decades, economic and population
growth are projected to increase
significantly both global and Canadian
demand for all forms of energy.
Hydrocarbons will remain the dominant
source of energy as well as the main
feedstock for countless chemical
products that are vital to modern life.
Canada has abundant oil and gas
resources, but developing them at
acceptable costs and with minimal
impact on the environment present
challenges that must be addressed.

We are determined to continue to
meet the evolving energy needs of
Canadians while remaining committed
to safety, environmental responsibility
and the highest standards of ethics
and integrity. This year marks the
125th anniversary of Imperial’s
founding, and those commitments
have remained constant throughout
the company’s history.

Ensuring that nobody gets hurt
governs all operations. And the
company is committed to delivering
superior environmental performance –
to drive environmental incidents with
real impact to zero, through the
continuous raising of standards and
improvements to our operations.

Imperial is also committed to
maintaining the long-standing tradition
of ethical business behaviour,
including clear and straightforward
reporting of operating and financial
results. In particular, we remain fully
confident in the integrity of our
process for assessing and reporting
oil and gas reserves. We will continue
to make operating and investment
decisions based on internal
assessments of resources and their
potential to provide future growth in
production and earnings.

The company remains deeply
committed to Canada and Canadians,
and this is reflected in many of
our initiatives. For example, we
believe the key to the economic
and environmentally responsible
development of Canada’s oil sands
is to turn the best scientific minds
to the challenge of developing new,
innovative technologies. For this

reason, in 2004 Imperial committed to
contribute $10 million over five years
to the University of Alberta to support
oil-sands research.

Another major cornerstone of the
company’s success over its long
history has been the collective talents,
capability, dedication and extraordinary
performance of our employees. For
their steadfast willingness to meet
the challenges of a difficult and
competitive industry, they deserve
the gratitude of shareholders for a
job well done, every year.

I would also note that one of the
longest-standing nonemployee
members of Imperial’s board of
directors will not stand for re-election
this spring. Pierre Des Marais II joined
the board in April 1977. On behalf of
his fellow directors, shareholders and
employees, I want to express our
appreciation for his many years of
outstanding service to the company
and wish him well for the future.

For the last 125 years, Imperial has
grown and prospered by pursuing
excellence in all operations, while
meeting both the needs of Canadians
for secure energy supplies and their
expectations for good corporate
citizenship. These considerations
remain in the forefront as we move
into a future of long-term growth for
shareholders.

Tim J. Hearn
February 16, 2005

For the last 125 years, Imperial has grown and
prospered by meeting the evolving energy needs
of Canadians. We were here yesterday, and
we will be here for the long term.

Imperial Oil Limited

Year in review

Operating highlights

• The best recorded safety

performance for both employees
and contractors was achieved; the
results showed improvement over
the company’s industry-leading
record performance in 2003.

• Reliability in the company’s

operations was excellent. By
actively managing those aspects
under its direct control, Imperial
continued to improve its base
operations.

•

Increased volumes were achieved
in upstream and downstream
business segments.

• Production records were set at
the company’s refineries and its
polyethylene and aromatics plants
in Sarnia.

• Substantial progress was made

on major upstream projects, which
are focused on developing oil-sands
leases in Alberta, natural gas in
the Mackenzie Delta region of the
Northwest Territories and offshore
resources on Canada’s East Coast.

• Relentless pursuit of lower costs
continued to be a priority. All key
Imperial business units have either
achieved industry-leading unit costs
or are within first-quartile ranking
for their cost structures.

• The company continues to
maintain an industry-leading
research program at its two
research facilities in Sarnia and
Calgary. Total research expenditures
in Canada were $38 million in 2004;
three patents were awarded and
180 new or reformulated products
were commercialized during the
year. In addition, through its
relationship with Exxon Mobil
Corporation, Imperial had access
to more than $800 million of
leading-edge research worldwide.

•

In October, $10 million was
committed over the next five
years to fund the Imperial Oil
Centre for Oil Sands Innovation
at the University of Alberta. The
centre is dedicated to finding
more efficient, economically viable
and environmentally responsible
ways to develop Canada’s
oil-sands resources.

From left to right:
Working at the Dartmouth, N.S., refinery; the company’s oil-sands research facility in
Calgary; delineation drilling at the Kearl oil-sands lease in northeastern Alberta;
performing field work for the Mackenzie gas project.

Annual report 2004

Financial highlights

• The highest earnings in the

• Regular per-share dividend

• Capital and exploration

company’s history were achieved,
$2,052 million, up from the record
$1,705 million in 2003. Earnings per
share were $5.74.

• Return on average capital employed
continued at its pace-setting level in
the industry – 28 percent, up from
25 percent in 2003.

•

In 2004, the total return on shares,
including capital appreciation and
dividends, was more than
25 percent (TSX), exceeding
the returns of Standard & Poor’s
(S&P) TSX composite index. Over
the past 10 years, the total return
on Imperial shares has averaged
almost 20 percent a year.

payments increased for the
10th consecutive year.

•

In 2004, total distributions to
shareholders were almost
$1.2 billion, including $872 million
to buy back about 14 million shares.

• An exceptionally strong balance
sheet was maintained. Debt as
a percentage of total capital was
below 20 percent; interest coverage
was 83 times earnings and more
than 100 times cash flow. The
“AAA” rating on Canadian debt
from S&P was maintained; Imperial
remains the only Canadian industrial
company with this rating. At year-
end, the balance of cash was
$1,279 million.

expenditures for 2004 were
$1,445 million. Investments
included advancing major upstream
projects and funding significant
refinery upgrades to reduce sulphur
levels in diesel fuel, thereby further
reducing smog-forming emissions.
For the fourth consecutive year,
more than $1 billion was spent
on capital expenditures and
exploration. In 2005, the company
expects to spend about $1.6 billion,
financed entirely from internally
generated funds, with about
$1 billion to be spent in the upstream.

Imperial Oil Limited

Net earnings millions of dollars Return on average capital employed (ROCE) percent1 7502 0002 2501 0001 2501 5007505002500253035%10152050Net earningsReturn on average capital employed (ROCE) (%)ROCE of Canadian integrated oil companies (%)0001020304 Investing in growth opportunities millions of dollars1 4001 6002004006008001 0001 2000Capital and exploration expendituresOutlook000102030405Long-term use of cash five-year total (2000-2004), $10.9 billion$3.7 billion$1.6 billion$5.6 billionInvestments (net)DividendsShare purchasesThe company’s Cold Lake development is one of the largest thermal heavy-oil-recovery operations in the world.

Natural resources

Imperial has a leading resource position with
diversified holdings in Northern, Western and Eastern
Canada. The company’s total resource base, which
includes reserves of oil, natural gas and natural gas
liquids, was 13 billion oil-equivalent barrels at the end of
2004. These assets will provide the source for Imperial’s
future growth.

The upstream business continued its
record of superior performance in
2004. Strong operations and excellent
reliability contributed to a four-percent
increase in production volumes for a
total of 357,000 oil-equivalent barrels
a day before royalties. Earnings after
tax were a record $1,487 million, and
return on average capital employed
was 39 percent. Cash flow from
operating activities and asset sales
was $2.4 billion, of which about
$1.1 billion was reinvested in the
business. Expenditures for 2005
are again expected to be more than
$1 billion, most of which will be
directed to investment in the oil sands.

Oil-sands operations
With more than 460,000 acres of
developed and undeveloped land
holdings, the company has a
significant lease position in the Alberta
oil sands. More than $800 million was
invested in the oil sands in 2004 to
increase production from existing
operations and advance new projects.
In addition, activities on the oil-sands
leases, most notably delineation

Annual report 2004

enhance the capacity of the operation,
reduce unit operating costs and allow
for additional development within
the existing infrastructure before
significant new investment is made
at the site.

In 2004, following U.S. Security and
Exchange Commission guidelines,
oil and gas reserves were assessed
using year-end pricing, which resulted
in a downward adjustment in Cold
Lake reserves. This was solely
because heavy-oil prices were
considerably lower on the last day
of 2004 than they had been during
most of the year. The company
believes that the method of assessing
reserves using a single price point
does not accurately reflect the long-
term production potential of the
resource. Imperial does not use this
single-price-point assessment in any
of its operating or investment
decisions. Bitumen values are highly
variable due to a number of factors.
Using either 2004 year-average pricing
or average prices in early 2005, there
would have been no downward
adjustment to Cold Lake reserves.

Production from Imperial’s 25-percent
share in Syncrude operations was a
record 60,000 barrels of synthetic
crude oil a day before royalties in
2004, up from 53,000 barrels a day in
2003. This included production from
the Aurora 2 mine, which was
completed in 2003. Disappointingly,
the cost estimates for the current
upgrader expansion project were
substantially increased in 2004,
and the construction schedule was
extended. A new coker, used to
convert heavy oils into lighter

drilling at the company’s leases at
Kearl, will increase Imperial’s non-
proved resources by almost 2.5 billion
barrels, bringing the company’s
total resource base to 13 billion
oil-equivalent barrels.

Operations at Cold Lake contributed
production of 126,000 barrels a day
before royalties from about 3,800
wells. The production process for this
thermal operation is cyclic by nature.
At the beginning of a cycle, steam is
injected into the subterranean
reservoir to heat the bitumen until it
flows. After a “soaking” period, the
bitumen is produced. When
production decreases, the cycle is
repeated. Cycle times range from six

months for new wells to 36 months
for mature wells. On average, annual
production has increased about four
percent a year since 1992, but
variations in year-to-year production
occur depending on the cycles. In
the last quarter of 2004, production
at Cold Lake averaged 144,000 barrels
a day.

A development drilling program of
more than 200 new wells from new
pads was completed in 2004 at Cold
Lake within the existing operating
areas. In March, regulatory approval
was received for operations in two
new expansion areas, and drilling will
begin in 2005 in one of these areas.
Work was also completed in 2004 to

Natural resources at a glance

Net income (millions of dollars)
Cash flow from operating activities

and asset sales (millions of dollars)

Gross crude oil and NGL production (thousands of barrels a day)
Gross natural gas production (millions of cubic feet a day)
Capital employed at December 31 (millions of dollars)
Return on average capital employed (percent)

2004

1 487

2 364
262
569
3 839
39.3

2003

1 143

1 668
256
513
3 725
32.8

2002

1 042

1 258
247
530
3 252
35.8

2001

941

1 226
267
572
2 573
39.7

2000

1 165

1 911
260
526
2 162
49.9

Imperial Oil Limited

Crude oil and NGL gross production by source thousands of barrels a day3002001000Cold LakeSyncrudeConventional and NGLs0001020304Natural gas gross production millions of cubic feet a day6005004003002001000In 2004, gross natural gas production was 569 million cubic feet a day, up 11 percent from 2003. 0001020304Natural resources

components, is expected to start
operating in late 2005, with production
of higher-quality synthetic crude oil to
begin by mid-2006. Once complete,
this expansion is expected to add
an additional 27,000 barrels a day
to Imperial’s volumes. A team of
experts from the project owners and
Syncrude has taken intervention steps
to ensure the remaining project work
is adequately managed to achieve the
updated cost target and schedule.
At year-end, the project was tracking
to the revised cost and construction
schedule.

The company continued to evaluate
its oil-sands opportunity at Kearl,
70 km north of Fort McMurray,
Alberta. An initial drilling program
was completed in early 2004. A
second program began in December
to further evaluate this high-quality
resource. Imperial would hold a
70-percent interest and, if
development is pursued, would
act as operator in the potential joint
project with ExxonMobil Canada. The
property would be developed using a
phased approach, with projected initial
bitumen production of 100,000 barrels
a day. Drilling results indicate that the
combined leases hold the potential
for up to 300,000 barrels a day, with
production estimated to last in excess
of 40 years. A regulatory filing is
planned for 2005. A decision to fund
and construct the project would be
made after all approvals are received
and project plans are finalized.

Mackenzie gas project
The Mackenzie gas project includes
the development of three anchor
natural gas fields (Taglu, Parsons Lake
and Niglintgak) in the Mackenzie Delta
region of the Northwest Territories, a
gas-gathering pipeline system, a gas-
processing plant and a 1,220-km
pipeline system to link northern
producing wells to southern markets.
The project is proposed by Imperial,
ConocoPhillips Canada, Shell Canada,
ExxonMobil Canada and the Aboriginal
Pipeline Group (APG). The APG was
formed in 2000 to represent the
ownership interest of the Aboriginal
Peoples of the Northwest Territories
in the proposed Mackenzie Valley
natural gas pipeline.

In October, Imperial, on behalf of
the project co-venturers, filed the
main regulatory applications and
environmental impact statement for
the proposed project 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 currently underway and is
expected to take up to 24 months. A
decision to proceed with the project
will be made by the co-venturers after
approvals are received and any
conditions attached to the approvals
are assessed. Construction would
then take three to four years.

The project would bring to market
natural gas from three previously
discovered onshore anchor fields,
including Imperial’s wholly owned
Taglu field. Taglu covers an area of
32 km2 and is estimated to have a
recoverable resource of about three
trillion cubic feet, with a projected
initial production rate of 400 million
cubic feet a day. This field represents
about one-half of the discovered
onshore gas that the Mackenzie
gas project would develop.

The project would use conventional,
proven technology and construction
methods that minimize environmental
impact. The proposed pipeline would
run along the Mackenzie Valley from
Inuvik, N.W.T., and link with an
existing pipeline in northern Alberta.
A separate natural gas liquids line,
with a capacity of 24,000 barrels a
day, would run from Inuvik to Norman
Wells, N.W.T., where it would join
an existing liquids line. Based on
discussions with potential shippers,
the pipeline was proposed with an
initial design capacity of 1.2 billion
cubic feet a day and is expandable to
1.9 billion cubic feet a day with
additional compression facilities.

The initial cost for the project is
estimated to be about $7 billion,
which includes $3.8 billion for the
main pipeline system. The gas-
gathering system, including a gas-
processing plant at Inuvik, would
cost about $1.6 billion, and the
development of the three anchor

Proved reserves of crude oil and natural gas (a)

year ended

2000
2001
2002
2003
2004 (b)

Crude oil and NGLs

millions of barrels

Natural gas

Synthetic
crude oil

billions of cubic feet

millions of barrels

Conventional

Cold Lake

Total

Syncrude

gross

233
197
175
151
134

net

196
165
146
126
110

gross

net

gross

net

gross

net

gross

972
926
895
853
783

851
807
801
763
702

1 205
1 123
1 070
1 004
917

1 047
972
947
889
812

1 852
1 670
1 445
1 204
1 034

1 572
1 414
1 224
1 023
880

679
914
893
874
835

net

610
821
800
781
757

(a) Gross reserves are the company’s share of reserves before deducting the shares of mineral owners or governments or both. Net reserves exclude these shares.
(b) Before year-end price/cost revisions.

Annual report 2004

The company also holds an interest in
exploration leases in the area offshore
of Nova Scotia in the vicinity of the
Sable project. In 2004, Imperial
participated in the drilling of an
exploration well on the Scotian Shelf,
which was non-commercial. During
2004, Imperial relinquished its
interests in nine of 13 licences.
Remaining opportunities on the
Scotian Shelf appear to be small and
high-risk, but industry activity in the
region will continue to be monitored.

In early 2004, a 25-percent interest
was acquired in the exploration rights
for eight deepwater parcels in the
Orphan Basin region off the east
coast of Newfoundland. This is a
large, unexplored frontier basin with
favourable attributes for hydrocarbons.
A 3-D seismic program was conducted
from July to September on three of
the eight parcels, and assessment of
the data acquired will continue
through early 2005. More 3-D seismic
is planned on three additional blocks
for the summer of 2005.

fields is estimated to cost about
$1.6 billion. Imperial’s share of the
cost, including development of the
Taglu field and the company’s share
of the gas-gathering and processing
system, is estimated to be about
$3 billion.

The company is working to advance
the project in four key areas:

• continuing the regulatory process,
with applications for required land-
and water-use licences to be filed
in early 2005

• working on commercial agreements

with potential shippers

• completing benefits and access

agreements with landowners and
Aboriginal groups across whose
land the pipeline would run

• continuing engineering work on the
technical aspects of the project.

Conventional Western Canada
Production from conventional
operations, centred in Western
Canada, accounted for 43 percent
of the company’s total production
before royalties. The company
maintains a diligent focus on costs,
and in 2004 unit operating costs were
held flat. These assets, while mature,
are highly profitable and deliver
excellent returns.

In 2004, gross natural gas production
was 569 million cubic feet a day, up
11 percent from 2003. A significant
gas development drilling program
began in 2004 near Medicine Hat
in southeastern Alberta, resulting
in additional production to Imperial
of nine million cubic feet a day at
year-end. The program will continue
in 2005.

In addition, the company is selectively
producing accumulated natural gas
caps from oil reservoirs that have
been economically depleted. In 2004,
production of natural gas from these
“blowdowns” reached 220 million
cubic feet a day and is expected to
continue through 2006.

East Coast
Imperial’s nine-percent interest in the
Sable offshore energy project, which
produces natural gas offshore of Nova
Scotia, contributed volumes of
37 million cubic feet a day before
royalties. The project produces from
five fields, with the newest field,
called South Venture, coming
onstream in late 2004 to help
maintain production. In 2005, drilling
on two additional production wells is
planned at the South Venture field,
and construction will begin on
compression facilities that will
increase production from all fields.
These facilities are expected to be
complete by 2006 and will bring
volumes to 44 million cubic feet a day.

THENANDNOW

Production

1947

2005

On February 13, 1947, in a
farmer’s field about 30 km south
of Edmonton, an exploratory oil
well was brought into production
in the presence of more than 500
invited guests. Imperial’s historic
discovery of oil at Leduc marked
the beginning of Canada’s role as
a major oil producer.

Imperial remains a leader in liquids production,
most notably at its wholly owned Cold Lake
bitumen-recovery operation, shown here, where
more than 200 new wells were completed in 2004.
The company is advancing projects on many fronts
to develop Canada’s vast natural resources and
meet energy needs. A delineation drilling program
at Kearl, about 70 km north of Fort McMurray,
Alberta, will help evaluate this high-quality oil-
sands resource. Work is progressing on the
Mackenzie gas project, and opportunities on
Canada’s East Coast are continually assessed.

Imperial Oil Limited

Imperial processes more than 74 million litres of crude oil a day in its four
refineries across Canada, including the Dartmouth refinery, shown here.

Petroleum products

Imperial continued to be the largest producer and
marketer of petroleum products in Canada, with the
leading market share position in every major market
segment it serves. Increased sales of petroleum
products during a period of strong industry margins,
coupled with sound cost management, were key
to delivering record earnings in 2004.

Downstream operations performed
very well in 2004, with improved
refinery reliability. Refinery utilization
in 2004 was at 93 percent, total
refinery throughput was up four
percent, and total petroleum product
sales were 87.6 million litres a day,
up three percent from 2003. The
company’s petroleum products
operations achieved record earnings
in 2004 of $500 million after tax,
up from a record year in 2003
($407 million), reflecting improved
refining margins and higher
volumes, as well as sound cost
management. Return on average
capital employed was 20 percent,
and cash flow from operating
activities and asset sales was
$901 million, of which $283 million
was reinvested in the business.
Generally stronger economic
conditions in Canada and worldwide
created growing demand for
petroleum products and higher
refining margins.

Annual report 2004

The majority of these sites provide an
expanded service offer to customers,
including a one-stop shopping
convenience store, car wash and
Tim Hortons outlet. The network of
about 400 car-wash facilities remains
the largest in the industry. In 2004,
total convenience-store sales were up
4.6 percent from 2003, and same-
store sales were up 7.8 percent. For
convenience, customers can pay at
the pump with credit or debit cards,
or use the popular Speedpass. Also in
2004, the company expanded the
number of sites with pump-mounted
television screens from five pilot
locations to more than 100 sites.
These provide news headlines,
weather information, stock reports
and in-store specials. Plans are in
place to introduce these in more
markets in 2005.

The Esso customer loyalty program
was enhanced in 2004 with the
introduction of Aeroplan. Customers
can now choose to collect Aeroplan
Miles or Esso Extra points. The
Esso loyalty offer is now the
most comprehensive program
available in Canada, offering a choice
of immediate rewards such as
car washes and convenience
products, or longer-term travel
rewards through Aeroplan.

Imperial is committed to having
the lowest unit costs in all its key
business segments. The retail
gasoline business achieved this
in 2002 and maintained this position
in 2004. The company’s primary
distribution terminal operations

In addition to a strong operating
performance and solid reliability,
earnings growth and operating
improvements in the downstream
businesses were achieved with a
relentless focus on three areas:

• providing customers with

their lowest total cost offer

• having industry-leading

unit costs, benchmarked
against competitors

• ensuring the efficient and
effective use of capital.

In the retail gasoline business, the
focus is on providing customers with
the products they want quickly and
conveniently. The company continued
its program of upgrading its network
of service stations in major urban
markets, which has contributed to
increased site productivity. In 2004,
five new sites were built, 10 were
rebuilt and 14 were upgraded. The
company now operates a network
of 720 company-owned sites across
Canada with an average productivity
of 5.6 million litres a year, up almost
eight percent from 2003.

Petroleum products at a glance

Net income (millions of dollars)
Cash flow from operating activities
and asset sales (millions of dollars)
Refinery throughput (millions of litres a day)
Petroleum product sales (millions of litres a day)
Capital employed at December 31 (millions of dollars)
Return on average capital employed (percent)

2004

500

901
74.3
87.6
2 410
20.0

2003

407

567
71.6
85.0
2 601
16.7

2002

127

409
71.2
83.1
2 266
5.8

2001

353

834
71.4
81.2
2 095
16.2

2000

313

521
71.6
80.3
2 263
14.0

Imperial Oil Limited

1 1

Esso service stationsaverage number25002000150010005000Company-owned or leasedDealer-owned orleased0001020304Throughput – company-owned and leased service stations millions of litres per site6543210Average productivity at company- owned and leased service stations was 5.6 million litres a year in 2004, upalmost eight percent from 2003.0001020304Petroleum products

reached this goal in 1998 and have
sustained that position to date.
Refining, lubricants and specialties,
and other fuels marketing businesses
continued to improve during 2004 and
now rank well within the best quartile.
Solid plans are in place for each of
these units to reach industry-leading
cost performance in 2005.

A relentless focus on cost management
has reduced unit costs (excluding
inflation) over the past 10 years by
22 percent. This has resulted in
favourable earnings while unit margins
continually declined, decreasing
12 percent over the same period.

As part of ongoing efforts to improve
capital productivity, a focus on the
efficient and effective use of working
capital as well as on capital additions
continued. The number of days that
product is held in inventory was
reduced by a further four percent
in 2004. Since 1992, reductions in
working capital have released about
$1.5 billion of cash for more
productive use.

Efforts to reduce energy use in all
operations continued in 2004. The
company’s Energy Intensity Index
(EII), an internationally recognized
metric for energy efficiency for
petroleum refineries, improved by
four percent over 2003. During the
past 10 years, Imperial’s EII value has
improved by 16 percent, as a result of
applying best operating practices and
targeted capital spending.

Capital investment in the company’s
petroleum products operations
totalled about $283 million in 2004,
about a third of which was directed
to projects to further reduce sulphur
levels in diesel fuel, thereby reducing
smog-forming emissions. In 2005,
Imperial plans to invest about
$550 million in its petroleum
products operations, which, in
addition to completing the low-
sulphur diesel project, will be used
to improve the company’s customer
offer and incrementally increase
refinery capacity at low capital cost.

THENANDNOW

Service stations

1916

2005

Customers fill-up a Ford at this
1916 service station. Demand for
gasoline, once a minor byproduct
of the refining process, increased
exponentially with the growing
popularity of automobiles. The
first motorists bought gasoline in
cans or open buckets from grocery
or hardware stores. Imperial
opened Canada’s first service
station in 1907 in Vancouver.

Imperial operates a network of 1,978 Esso service
stations across Canada. The majority of company-
owned sites provide a range of services to
customers, including a one-stop shopping
convenience store, car wash and Tim Hortons
outlet. Imperial has the largest network of car
washes in the industry. The Esso Extra loyalty
program was enhanced in 2004 to introduce
Aeroplan – customers can now choose between
collecting Aeroplan Miles or Esso Extra points.

Annual report 2004

Refinery utilizationpercent95859075800Refinery utilization in 2004 was a record 93 percent, up from 90 percent during the past three years.0001020304Chemicals

The focus for many years has been on increasing the integration of the Sarnia
and Dartmouth chemicals plants within the refineries. This reduces costs and
maximizes value for both operations. The strategy has proven effective in making
Imperial’s chemicals business a leader in cost and productivity. The company
also benefits from its integration within ExxonMobil’s North American chemicals
businesses, which has resulted in a leadership position in the key market
segments served.

The polyethylene plant in Sarnia has
been expanded five times since it
began operations in 1983, with
innovative technology applied
to all stages of the operation to
increase output at a small fraction
of the cost of a new facility. Annual
capacity is now 450,000 tonnes, up
about 230 percent since 1983. In
2004, the business ran with excellent
reliability and achieved an all-time
production record in August. This
plant remains one of the most cost-
competitive in the world.

Record production levels of benzene
were also achieved in the aromatics
business, in a period of record-high
industry margins.

In 2004, the business cycles for two
main products – polyethylene and
benzene – were quite favourable,
with increased demand for products
and strong margins. Chemicals
earnings after tax were $100 million,
up 170 percent from 2003. Cash flow
from operating activities and asset
sales was $126 million, $15 million of
which was reinvested in the business.
Average return on capital employed
was almost 47 percent.

Imperial remains one of Canada’s
leading producers of chemical
products, with the largest market
share in domestic solvents in Canada,
the largest market share in North
America for polyethylene used in
rotational molding and the second-
largest market share in injection
molding. The company’s Sarnia
chemicals plant is located within one
day’s trucking of 70 percent of the
demand for polyethylene in North
America. Total sales of petrochemical
products were 3,300 tonnes a day,
unchanged from 2003.

Chemicals at a glance

Net income (millions of dollars)
Cash flow from operating activities
and asset sales (millions of dollars)

Chemicals sales volumes (thousands of tonnes a day)
Capital employed at December 31 (millions of dollars)
Return on average capital employed (percent)

2004

100

126
3.3
205
46.8

2003

22
3.3
222
19.9

2002

93
3.5
150
30.8

2001

9
3.3
188
14.1

2000

(6)
3.1
138
54.1

Imperial Oil Limited

1 3

Polyethylene sales volumes thousands of tonnes6005004003002001000Sales of purchased polyethyleneSales from our own production0001020304Imperial’s cash balance at the end of 2004 was almost $1.3 billion and is
managed by treasurer’s department employees in the cash operations group.

Principled people and practices

Imperial has a long tradition of sound corporate
governance and high ethical standards, which ensure
the integrity of its businesses and operations. The
company’s formula for maintaining this tradition is
simple: strong leadership, along with discipline and
commitment by employees at all levels of the
organization.

For more than 30 years, the company
has had a comprehensive business
ethics policy, which applies to
directors and all employees and
guides how all business is conducted.

Governance practices are fully
disclosed in the proxy circular and
meet the requirements of both the
Toronto Stock Exchange and the
American Stock Exchange. In addition,
governance practices meet the
corporate governance guidelines in
the proposed National Policy 58-201,
published by the Ontario Securities
Commission in October 2004.

Sound governance practices are
evident throughout the organization.
Imperial has a straightforward capital
structure and consistently reports
results using transparent accounting
practices. It does not use special-
purpose entities, special adjustments
or pro forma reporting. Neither does
it use derivatives to speculate or
hedge on the future direction of
commodity prices, nor sell forward
future production.

Annual report 2004

The company’s method of reporting
reserves meets all regulatory
requirements, including those of
the U.S. and Canadian securities
commissions and of Canadian National
Instrument NI 51-101. Rigorous internal
reserves management processes
include disciplined and regular
technical assessments, which are
performed by qualified professionals
and are subject to management
review and endorsement, consistent
with all asset management decisions.
Notably, technical and other
professionals involved in the process
are not compensated based on the
levels of proved reserves bookings.

All requirements of the U.S. Sarbanes-
Oxley Act have been met since it was
introduced in 2002. The fact that the
company was able to do so with
minimal changes to its controls
procedures and processes testifies
to the high standard of Imperial’s
governance systems. Chief among
them is the long-standing Controls
Integrity Management System

(CIMS), which provides a structured
approach for assessing financial
control risks and procedures for
mitigating concerns, monitoring
conformance with standards and
reporting results to management.
CIMS is consistent with the internal
controls framework recommended
by the Committee of Sponsoring
Organizations of the Treadway
Commission, a voluntary private-
sector organization dedicated to
improving the quality of financial
reporting.

The majority of the company’s board
are nonemployee directors. All board
committees are made up solely of
these independent directors. All
directors and committees have the
right to engage an outside adviser
at the company’s expense, and
nonemployee directors meet regularly
in the absence of the company’s
management. Full disclosure of all
corporate governance practices is
made in the proxy circular.

High-performing, principled
employees
The people Imperial employs provide
a competitive advantage. High-
performing, principled people from
diverse backgrounds are hired and
developed. At year-end 2004, the
company had 6,083 employees,
183 of whom were hired during the
year. Every employee is involved in
a structured development process,
which includes rigorous training in
business ethics. The company’s
association with ExxonMobil gives
it a considerable training advantage,
providing an opportunity for
employees to work with business
units around the world to gain
valuable global experience.

The company seeks to be the
employer of choice for the most
capable and highest-performing
graduates of Canadian universities
and community colleges. In 2004,
69 graduates were hired through
the company’s campus recruitment
program.

Employees

Number of full-time employees at December 31
Total payroll and benefits (millions of dollars) (a)

2004

6 083
1 200

2003

6 256
1 188

2002

6 460
1 034

2001

6 740
902

2000

6 704
814

(a) Includes both the company’s payroll and benefits costs and its share of the Syncrude joint-venture payroll and benefits costs.

From left to right:
Employees performing a leak-detection assessment; monitoring a control panel at Cold Lake;
working safely at the Nanticoke refinery.

Imperial Oil Limited

1 5

Training, jobs and environmental protection are discussed at an open house in
Yellowknife for residents to learn more about the Mackenzie gas project.

Caring for our communities

Founded on principles of integrity and community
responsibility, Imperial has a long-standing record of good
corporate citizenship. Throughout the past 125 years, the
company has been fulfilling its primary responsibility to
supply Canadians and others with reliable, affordable
energy, as well as petroleum and petrochemical products.
These products provide heat, light and mobility to
Canadians and are vital to the manufacture of a multitude
of items key to daily life, from computer components and
health-care equipment to fertilizers and packaging.

The demand for energy will continue
to grow as populations and standards
of living increase. Imperial is committed
to meeting the growing demand
for energy in an environmentally,
economically and socially responsible
manner.

Nothing is more important than
operating our facilities safely and
protecting employees, contractors,
customers, the public and the
environment. The company works
to drive environmental incidents
with real impact to zero through a
process of continuous improvement,
and to have a workplace where
nobody gets hurt.

The Operations Integrity Management
System (OIMS) is the primary tool the
company uses to manage its
operations and assess and improve
its safety, health and environmental
performance. Lloyd’s Register Quality
Assurance, a respected international

Annual report 2004

information is available) by more than
seven percent over 2002, reflecting
the company’s focus on continuous
improvement in all areas of its
operations.

The company tracks and works to
reduce the greenhouse-gas intensity
of its operations by improving energy
efficiency, reducing flaring and
investing in cogeneration facilities.
In 2003 (the most recent year for
which information is available),
greenhouse-gas emissions from
operations were 0.5 percent lower than
in 2002, despite increased volumes of
crude oil production and petroleum-
product sales.

Engaging communities
Imperial places great value on its
relationships with Canadian
communities. From working with
Pollution Probe to help develop future
environmental managers to working
with Aboriginal groups to share ideas
about protecting the land, these
relationships take many forms. But
the goal remains the same – to work
with communities today to build a
better tomorrow.

The company meets regularly with
community leaders, governmental and
non-governmental organizations and
others interested in Imperial’s
operations, including local residents,
businesses and schools. For example,
in developing the Mackenzie gas
project, the company is working
with Aboriginal communities in the
Northwest Territories to understand
and address the concerns of
residents. More than 1,000 meetings
with community members have been
held to date throughout the
Mackenzie Valley. Community input
has enabled the project team to better
understand the traditional knowledge
of the Aboriginal peoples and has also
resulted in changes to the proposed
pipeline route.

authority, has attested that OIMS
meets the ISO 14001 Environmental
Management Systems Standard.
Lloyd’s also stated: “We further
believe Imperial Oil to be among
the industry leaders in the extent to
which environmental management
considerations have been integrated
into its business processes for
ongoing operations and for the
planning and development of
new projects.”

Safety performance continues to
be among the best in Canadian
industry; Imperial’s 2004 performance
surpassed that of 2003, which had
been the best on record.

In 2004, seven environmental
incidents occurred with associated
costs of more than $65,000, up from
five in 2003. The most serious of
these involved the accidental release
of ketone into the St. Clair River from
the Sarnia refinery. A preventive
measures action plan was submitted
to the Ontario Ministry of the
Environment and has been
implemented. All operating incidents
are rigorously investigated, and
measures are instituted to prevent
similar incidents in the future.

In 2004, $150 million was invested in
projects related to further improving
safety and environmental performance.
These included $90 million as part of
a $500-million investment that will
enable Imperial’s refineries across
Canada to produce ultra low-sulphur
diesel fuel. This follows a $650-million
refinery investment, completed in
2003, that reduced sulphur levels in
gasoline by more than 90 percent a
year ahead of regulated requirements.
In conjunction with 2007 vehicle
engines, these initiatives will reduce
smog-causing nitrogen oxides and
particulate-matter emissions by
almost 90 percent.

Examples of other 2004
environmental initiatives include
a project at the Nanticoke, Ont.,
refinery to improve the quality of
water effluent, and another at the
Norman Wells operations to install an
improved liquid-waste handling facility.

Each year since 1993, Environment
Canada has collected information from
industries on releases of substances
for its National Pollutant Release
Inventory (NPRI). Imperial’s releases
of NPRI substances decreased in
2003 (the most recent year for which

Imperial Oil Limited

1 7

Employee and contractor safety leadership total recordable incidents per 200,000 work hours3210EmployeesContractors0001020304Upstream flaringmillions of cubic feet of gas a day43210Imperial continues to reduceemissions by recovering natural gas associated with crude oil production that would otherwise be flared or vented into the air.0001020304Imperial and the community

Supporting the evolving needs
of Canadian communities
In 2004, more than $10.4 million
was contributed to help Canadian
communities meet important needs.
Focusing on areas across Canada
where it has a presence, the company
gives the majority of its contributions
through the Imperial Oil Foundation.

In 2004, the foundation contributed
more than $6 million to about 415
organizations, with the largest portion
being directed toward programs that
support youth and education. For
example, the company is providing:

• $500,000 over five years to the

University of Manitoba to support
the development of the Imperial Oil
Academy for the Learning of Math,
Science and Technology

• $250,000 over five years to the

St. Joseph Health Centre in Toronto
to build a children’s health centre

• $125,000 over five years to

Halifax’s St. Mary’s University
to fund Cosmic Rays in the
Classroom, a program aimed at
piquing elementary school
students’ interest in science

• $140,000 over four years to the

Nature Conservancy of Canada in
Quebec to support the educational
component of its St. Lawrence
River conservation project.

Imperial contributes significantly to
research at Canadian universities. In
2004, through its University Research
Awards program, the company
awarded 30 grants totalling $650,000
to 15 universities to fund research
into areas of interest to Imperial,
including engineering, chemical,
physical, computing, social and
environmental science. This program
has been maintained continuously for
more than 50 years.

Also in 2004, the company announced
that it would contribute $10 million
over five years to the University of
Alberta to fund the Imperial Oil Centre
for Oil Sands Innovation. The centre
will be dedicated to finding more
efficient, economically viable and
environmentally responsible ways to
develop Canada’s vast oil-sands
resources.

In addition, Imperial contributed
$200,000 over five years to Petroleum
Research Atlantic Canada for research
and technology development in this
region.

More information on Imperial’s
corporate citizenship activities can
be found in the corporate citizenship
section of the company’s Web site,
www.imperialoil.ca. Imperial’s 2003
corporate citizenship report, A partner
in the Canadian community, is also
available on-line.

From left to right:
The University of Alberta in Edmonton, to which the company announced it would donate
$10 million over five years to fund the Imperial Oil Centre for Oil Sands Innovation;
an Imperial employee from Norman Wells, N.W.T., answers questions on the Mackenzie gas
project during a call-in show on local radio; the Nature Conservancy of Canada will receive
$140,000 over four years from Imperial to support education on its St. Lawrence River
conservation project.

Annual report 2004

Community investment$3 779 000$984 000$472 000$278 000$4 927 000Community services*EducationOther*includes contributions to community investment programs at Syncrude and SableArts and cultureHockeyFinancial section

20 Management’s discussion and analysis
32
Frequently used financial terms
36 Management and auditors’ reports
37
Financial statements, accounting policies and notes
57 Natural resources segment – supplemental information
60
61
62

Share ownership, trading and performance
Quarterly financial and stock-trading data
Information for investors
Directors, senior management and officers

Imperial Oil Limited

1 9

Financial summary (under U.S. GAAP)

millions of dollars
Revenues

Net income by segment:
Natural resources
Petroleum products
Chemicals
Corporate and other

Net income

Total assets

Long-term debt
Total debt
Other long-term obligations

Capital employed

Cash flow from operating activities and asset sales

Per-share information (dollars)

Net income per share – basic
Net income per share – diluted
Dividends

2004
22 460

1 487
500
100
(35)
2 052

2003
19 208

1 143
407
37
118
1 705

2002
17 042

1 042
127
52
(7)
1 214

2001
17 253

941
353
23
(94)
1 223

2000
18 051

1 165
313
59
(129)
1 408

14 027

12 337

12 003

10 888

11 266

367
1 443
1 525

7 821

3 414

5.75
5.74
0.88

859
1 432
1 314

7 029

2 283

4.58
4.58
0.87

1 466
1 538
1 822

6 498

1 749

3.20
3.20
0.84

1 029
1 489
1 303

5 784

2 050

3.11
3.11
0.83

1 037
1 412
1 110

5 662

2 363

3.37
3.37
0.78

Management’s discussion and analysis of financial condition and results of operations

Overview

The following discussion and analysis of Imperial’s financial results, as well as the accompanying financial statements and related
notes to consolidated financial statements to which they refer, are the responsibility of the management of Imperial Oil Limited.
Beginning in 2004, the company reported its financial results based on generally accepted accounting principles (GAAP) in the
United States. The differences between U.S. and Canadian GAAP are small for Imperial and an explanation of them as they apply
to the company, including a tabular reconciliation of net income reported under U.S. GAAP and under Canadian GAAP, is included
as a note to the financial statements on page 46. Supplemental financial information based on Canadian GAAP pertaining to
management’s discussion and analysis of Imperial’s financial results is also provided, on page 34.

The company’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining
and marketing of hydrocarbons and hydrocarbon-based products. The company’s business involves the production (or purchase),
manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical
movement of goods.

This straightforward approach extends to the financing of the business. In evaluating business or investment opportunities, the
company views as economically equivalent any debt obligation, whether included on the face of the consolidated balance sheet or
disclosed as other debt-like obligations in the notes to the financial statements. The company does not use financial structures for
the purpose of removing debt from the balance sheet. Nor does it use derivative markets to speculate on the future direction of
currency or commodity prices or sell forward any part of production from any business segment. This consistent, conservative
approach to financial management has helped Imperial to sustain its high credit quality.

With its extensive resource base in Canada, financial strength, disciplined investment approach and technology portfolio, Imperial
is well positioned to participate in substantial investments to develop new energy supplies. While commodity prices remain volatile
on a short-term basis depending upon supply and demand, Imperial’s investment decisions are based on long-term outlooks, using a
disciplined approach in selecting and pursuing the most attractive investment opportunities. 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 that are 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

Annual report 2004

completed to ensure relevant lessons are learned and improvements are incorporated into future projects. Imperial views return on
capital employed as the best measure of historical capital productivity.

Business environment and outlook

Natural resources

Imperial 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 will 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 American 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.

Imperial has a large and diverse portfolio of oil and gas resources in Canada, both developed and undeveloped, 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, Imperial’s production is expected to come increasingly from frontier and
unconventional sources, particularly oil sands and natural gas from the Far North, where Imperial has large undeveloped resource
opportunities.

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 affected 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.

Imperial’s downstream strategies are to provide customers with quality service at the lowest total cost offer, have the lowest unit
costs among our competitors, ensure efficient and effective use of capital and capitalize on integration with the company’s other
businesses. Imperial 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. Imperial’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 Imperial to maintain a leadership position in its key market segments.

Imperial Oil Limited

2 1

Management’s discussion and analysis of financial condition and results of operations (continued)

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.

The return on average capital employed was 28 percent, compared with 25 percent in 2003 (2002 – 20 percent).

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.

Return on average capital employed was 39 percent for the natural resources segment, compared with 33 percent in 2003 (2002 –
36 percent), reflecting higher net income.

Financial statistics
millions of dollars
Net income
Revenues
Cash flow from operating activities and asset sales
Capital employed at December 31
Return on average capital employed (percent)

2004
1 487
6 625
2 364
3 839
39.3

2003
1 143
5 648
1 668
3 725
32.8

2002
1 042
4 894
1 258
3 252
35.8

2001
941
5 321
1 226
2 573
39.7

2000
1 165
5 900
1 911
2 162
49.9

Annual report 2004

Factors affecting Imperial’s 2004 net incomemillions of dollars1705200320042052Higher resource realizationsHigher product marginsHigher volumesHigher Canadian dollarLower tax benefits and otherHigher volume- related costs, energy prices and other expenses560260175(370)(180)(98)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 $40.10 in 2003 (2002 – $36.81).

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
Canadian dollars
Conventional crude oil realizations (a barrel)
Natural gas liquids realizations (a barrel)
Natural gas realizations (a thousand cubic feet)
Par crude oil price at Edmonton (a barrel)
Heavy crude oil price at Hardisty (Bow River, a barrel)

2004
48.96
33.78
6.78
53.26
37.98

2003
40.10
32.09
6.60
43.93
33.00

2002
36.81
23.38
4.02
40.44
31.85

2001
35.56
29.31
5.72
39.64
25.11

2000
41.52
29.57
4.99
45.02
34.49

Gross production of crude oil and NGLs 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). Imperial’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.

Imperial Oil Limited

2 3

Crude oil prices U.S. dollars a barrel – quarterly averageBrent crudeCanadian heavy oil (Bow River)504030201002515453550001020304Natural gas average prices dollars a thousand cubic feet – AECO hub 30-day spot121086420Prices for Canadian natural gas in 2004 were essentially unchanged from the previous year.0001020304Management’s discussion and analysis of financial condition and results of operations (continued)

Crude oil and NGLs – production and sales (a)
thousands of barrels a day

Conventional crude oil
Cold Lake
Syncrude
Total crude oil production
NGLs available for sale
Total crude oil and NGL production
Cold Lake sales, including diluent (b)
NGL sales

Natural gas – production and sales (a)
millions of cubic feet a day

Production (c)
Sales

2004

2003

2002

2001

2000

net
33
112
59
204
26
230

gross
43
126
60
229
33
262
167
42

net
35
116
52
203
22
225

gross
46
129
53
228
28
256
170
39

net
39
106
57
202
21
223

gross
51
112
57
220
27
247
145
40

gross
55
128
56
239
28
267
167
43

net
42
121
52
215
22
237

gross
60
119
51
230
30
260
156
42

2004

2003

2002

2001

2000

gross
569
520

net
518

gross
513
460

net
457

gross
530
499

net
463

gross
572
502

net
466

gross
526
419

net
46
102
42
190
23
213

net
459

(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.

Petroleum products
Net income from petroleum products was a record $500 million or 1.6 cents a litre in 2004, up from $407 million or 1.3 cents a litre
in 2003 (2002 – $127 million or 0.4 cents a litre). Improved earnings were mainly due to stronger international refining margins,
partly offset by lower fuels marketing margins and the negative impact of a higher Canadian dollar. Sales volumes of petroleum
products were higher, due in part to higher industry demand.

Revenues were $19.2 billion, up from $16.1 billion in 2003 (2002 – $14.4 billion).

Return on average capital employed was 20 percent for the petroleum products segment, compared with 17 percent in 2003 (2002 – six percent).

Financial statistics
millions of dollars
Net income
Revenues
Cash flow from operating activities and asset sales
Capital employed at December 31
Return on average capital employed (percent)

Sales of petroleum products
millions of litres a day (a)
Gasolines
Heating, diesel and jet fuels
Heavy fuel oils
Lube oils and other products
Net petroleum products sales
Sales under purchase and sale agreements
Total sales of petroleum products
Total domestic sales of petroleum products (percent)

Refinery utilization
millions of litres a day (a)
Total refinery throughput (b)
Refinery capacity at December 31
Utilization of total refinery capacity (percent)

2004
500
19 211
901
2 410
20.0

2004
33.2
27.3
5.9
7.0
73.4
14.2
87.6
93.0

2004
74.3
79.9
93

2003
407
16 058
567
2 601
16.7

2003
33.0
26.2
5.4
5.8
70.4
14.6
85.0
93.3

2003
71.6
79.9
90

2002
127
14 434
409
2 266
5.8

2002
32.9
25.0
4.9
6.4
69.2
13.9
83.1
91.5

2002
71.2
79.4
90

2001
353
14 405
834
2 095
16.2

2001
32.3
26.5
5.4
5.4
69.6
11.6
81.2
93.4

2001
71.4
79.1
90

2000
313
15 120
521
2 263
14.0

2000
32.0
27.5
5.1
5.0
69.6
10.7
80.3
94.0

2000
71.6
78.7
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.

One thousand litres is approximately 6.3 barrels.

Annual report 2004

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.

Operating performance of the company’s four refineries was solid. Throughput at the
refineries has increased, with refinery capacity utilization averaging a record 93 percent
in 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 chemicals 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
millions of dollars
Net income
Revenues
Cash flow from operating activities and asset sales
Capital employed at December 31
Return on average capital employed (percent)

Sales volumes
thousands of tonnes a day (a)
Polymers and basic chemicals
Intermediates and other
Total chemicals

2004
100
1 509
126
205
46.8

2004
2.7
0.6
3.3

2003
37
1 232
22
222
19.9

2003
2.4
0.9
3.3

2002
52
1 164
93
150
30.8

2002
2.5
1.0
3.5

2001
23
1 175
9
188
14.1

2001
2.4
0.9
3.3

2000
59
1 173
(6)
138
54.1

2000
2.2
0.9
3.1

(a) Volumes a day are calculated by dividing total volumes for the year by the number of days in the year.

One tonne is approximately 1.1 short tons or 0.98 long tons.

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.

Return on average capital employed was 47 percent for the chemicals segment, compared with 20 percent in 2003 (2002 – 31 percent).

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.

Imperial Oil Limited

2 5

Average refining margins Canadian cents a litreNewYork Harbor product prices minus Brent crude; reflects Imperial’s product mix.781234560Management’s discussion and analysis of financial condition and results of operations (continued)

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 non-recurring after-tax writedown 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 resources

Sources and uses of cash
millions of dollars
Cash provided by/(used in)
Operating activities
Investing activities
Financing activities

Increase/(decrease) in cash and cash equivalents

Cash and cash equivalents at end of year

2004

3 312
(1 306)
(1 175)
831

1 279

2003

2 227
(1 426)
(1 119)
(318)

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. Imperial’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.

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:

millions of dollars
Exploration
Production
Heavy oil
Total capital and exploration expenditures

2004
60
234
819
1 113

2003
57
181
769
1 007

2002
39
143
804
986

2001
49
109
588
746

2000
56
110
268
434

Annual report 2004

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:

millions of dollars
Marketing
Refining and supply
Other (a)
Total capital expenditures

(a) Consists primarily of real estate purchases.

2004
85
178
20
283

2003
91
369
18
478

2002
133
399
57
589

2001
171
118
50
339

2000
121
100
11
232

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 its chemicals operations during the five years ending
December 31, 2004:

millions of dollars
Capital expenditures

2004
15

2003
41

2002
25

2001
30

2000
13

Of the capital expenditures for chemicals in 2004, the major investment focused on improving energy efficiency, yields and process
control technology.

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 Imperial 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.

Imperial Oil Limited

2 7

Management’s discussion and analysis of financial condition and results of operations (continued)

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, ratios and credit rating

Total debt as a percentage of capital (a)

Interest coverage ratios
Earnings basis (b)
Cash-flow basis (c)

Long-term unsecured debt rating

Local currency (DBRS / S&P) (d)

2004
19

83
108

2003
21

64
80

2002
24

46
63

2001
26

26
36

2000
25

23
29

AA/AAA

(a) Current and long-term portions of debt (page 39), divided by debt and shareholders’ equity (page 39).
(b) Net income (page 37), debt-related interest before capitalization (page 56, note 15) and income taxes (page 37) divided by debt-related interest before capitalization.
(c) Cash flow from net income adjusted for the cumulative effect of accounting change and other non-cash items (page 38), current income tax expense (page 47,

note 4) and debt-related interest before capitalization (page 56, note 15) divided by debt-related interest before capitalization.

(d) Dominion Bond Rating Service (DBRS) and Standard & Poor’s Corporation (S&P) are debt-rating agencies.

The company’s financial strength, as evidenced by the above financial ratios, represents a competitive advantage of strategic
importance. The company’s sound financial position gives it the opportunity to access the world’s capital markets in the full range
of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing
shareholder value.

Contractual obligations
To more fully explain Imperial’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.

millions of dollars
Long-term debt and capital leases
Imperial’s share of equity company debt
Operating leases
Unconditional purchase obligations (a)
Firm capital commitments (b)
Pension obligations (c)
Asset retirement obligations (d)
Other long-term agreements (e)

Financial
statement
note reference
Note 3

Note 12
Note 12
Note 12
Note 7
Note 8
Note 12

Payment due by period
2006 to
2009
334
–
181
168
52
91
116
378

2010 and
beyond
33
–
91
55
–
297
176
198

Total
amount
1 362
56
334
325
171
759
328
817

2005
995
56
62
102
119
371
36
241

(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.

(c) The amount by which accumulated benefit obligations (ABO) exceeded the fair value of fund assets at year-end (page 48, 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.

Annual report 2004

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.

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. Imperial 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 41 to 43.

Imperial Oil Limited

2 9

Management’s discussion and analysis of financial condition and results of operations (continued)

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 59. 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 reserves 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

Annual report 2004

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 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 asset’s 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 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 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 58 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 51. At Imperial, 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.

Imperial Oil Limited

3 1

Management’s discussion and analysis of financial condition and results of operations (continued)

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.

Market risks and other uncertainties

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 impact on
Imperial 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.

Earnings sensitivities (a)
millions of dollars after tax
Four dollars (U.S.) a barrel change in crude oil prices
Sixty cents a thousand cubic feet change in natural gas prices
One cent a litre change in sales margins for total petroleum products
One cent (U.S.) a pound change in sales margins for polyethylene
One-quarter percent decrease (increase) in short-term interest rates
Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar

+ (–)
+ (–)
+ (–)
+ (–)
+ (–)
+ (–)

$ 200
$
20
$ 170
7
$
$
2
$ 260

(a) 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.

Frequently used financial terms

Listed below are definitions of four of Imperial’s frequently used financial performance measures. The definitions are provided to
facilitate understanding of the terms and how they are calculated.

Capital employed
Capital employed is a measure of net investment. When viewed from the perspective of how capital is used by the business, it
includes the company’s property, plant and equipment and other assets, less liabilities, excluding both short-term and long-term
debt. When viewed from the perspective of the sources of capital employed for the whole company, it includes total debt and
shareholders’ equity. Both of these views include the company’s share of amounts applicable to equity companies.

millions of dollars
Business uses: asset and liability perspective
Total assets
Less: total current liabilities excluding short-term debt and

current portion of long-term debt

Less: total long-term liabilities excluding long-term debt
Add: Imperial’s share of equity company debt
Total capital employed

2004

2003

2002

14 027

12 337

12 003

(3 582)
(2 680)
56
7 821

(2 817)
(2 543)
52
7 029

(2 671)
(2 883)
49
6 498

Annual report 2004

millions of dollars
Total company sources: debt and equity perspective
Short-term debt and current portion of long-term debt
Long-term debt
Shareholders’ equity
Add: Imperial’s share of equity company debt
Total capital employed

2004

1 076
367
6 322
56
7 821

2003

573
859
5 545
52
7 029

2002

72
1 466
4 911
49
6 498

Return on average capital employed (ROCE)
ROCE is a financial performance ratio. For each of the company’s business segments, ROCE is annual business-segment net income
divided by average business-segment capital employed (an average of the beginning- and end-of-year amounts). Segment net
income includes Imperial’s share of segment net income of equity companies, consistent with the definition used for capital
employed, and excludes the cost of financing. The company’s total ROCE is net income excluding the after-tax cost of financing
divided by total average capital employed. The company has consistently applied its ROCE definition for many years and views it
as the best measure of historical capital productivity in a capital-intensive, long-term industry to both evaluate management’s
performance and demonstrate to shareholders that capital has been used wisely over the long term.

millions of dollars
Net income
Financing costs (after tax), including Imperial’s share of equity companies
Net income excluding financing costs

Average capital employed
Return on average capital employed (percent)

2004
2 052
3
2 055

7 425
27.7

2003
1 705
3
1 708

6 764
25.3

2002
1 214
15
1 229

6 141
20.0

Operating costs
Operating costs are the combined total of production, manufacturing, selling, general, exploration, depreciation and depletion
expenses from the consolidated statement of income and Imperial’s share of similar costs for equity companies. Operating costs are
the costs incurred during the period to produce, manufacture and otherwise prepare the company’s products for sale – including
energy costs, staffing, maintenance, and other costs to explore for and produce oil and gas and operate refining and chemical
plants. Delivery costs to customers and marketing expenses are also included. Operating costs exclude the cost of raw materials
and those costs incurred in bringing inventory to its existing condition and final storage prior to delivery to a customer. These
expenses are on a before-tax basis. While Imperial’s management is responsible for all revenue and expense elements of net
income, operating costs, as defined below, represent the expenses most directly under management’s control.

millions of dollars
Expenses (from page 37)

Exploration
Production and manufacturing
Selling and general
Depreciation and depletion
Subtotal

Imperial’s share of equity company expenses
Total operating costs

2004

59
2 883
1 218
908
5 068
52
5 120

2003

55
2 782
1 269
755
4 861
56
4 917

2002

30
2 320
1 222
708
4 280
49
4 329

Cash flow from operating activities and asset sales
Cash flow from operating activities and asset sales is the sum of the net cash provided by operating activities and proceeds from
asset sales reported in the consolidated statement of cash flows. This cash flow is the total source of cash both from operating the
company’s assets and from the divesting of assets. The company employs a long-standing, disciplined regular review process to
ensure that all assets are contributing to the company’s strategic and financial objectives. Assets are divested when they no longer
meet these objectives or are worth considerably more to others. Because of the regular nature of this activity, management believes
it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash
available for investment in the business and financing activities, including shareholder distributions.

millions of dollars
Cash from operating activities
Proceeds from asset sales
Total cash flow from operating activities and asset sales

2004
3 312
102
3 414

2003
2 227
56
2 283

2002
1 688
61
1 749

Imperial Oil Limited

3 3

Management’s discussion and analysis of financial condition and results of operations (continued)

Supplemental information based on generally accepted accounting principles (GAAP) in Canada

The company’s financial summary and management’s discussion and analysis, under Canadian GAAP, are not materially different from
those reported under U.S. GAAP as shown on pages 20 to 33, except for the following:

Financial summary
millions of dollars
Net income by segment:
Natural resources
Petroleum products
Chemicals
Corporate and other

Net income

Total assets

Other long-term obligations

Capital employed

Cash flow from operating activities and asset sales

Per-share information (dollars)

Net income per share – basic
Net income per share – diluted

2004

1 487
500
100
(54)
2 033

2003

1 139
407
37
99
1 682

2002

1 056
127
52
(11)
1 224

2001

957
353
23
(78)
1 255

2000

1 177
313
59
(139)
1 410

13 992

12 361

11 894

10 781

11 244

1 010

8 137

3 380

5.70
5.69

972

7 262

2 250

4.52
4.52

1 207

6 803

1 737

3.23
3.23

1 098

5 841

2 050

3.19
3.19

1 104

5 635

2 363

3.38
3.38

Results of operations
Net income in 2004 was $2,033 million or $5.69 a share – the best year on record – compared with $1,682 million or $4.52 a share
in 2003 (2002 – $1,224 million or $3.23 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.

The return on average capital employed was 26 percent, compared with 24 percent in 2003 (2002 – 20 percent).

Natural resources
Net income from natural resources was $1,487 million, up from $1,139 million in 2003 (2002 – $1,056 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.

Return on average capital employed was 39 percent for the natural resources segment, compared with 32 percent in 2003 (2002 –
36 percent), reflecting higher net income.

Financial statistics
millions of dollars
Net income
Capital employed at December 31
Return on average capital employed (percent)

2004
1 487
3 920
38.6

2003
1 139
3 784
32.0

2002
1 056
3 325
35.8

2001
957
2 580
40.5

2000
1 177
2 142
51.0

Annual report 2004

Petroleum products
Return on average capital employed was 18 percent for the petroleum products segment, compared with 16 percent in 2003
(2002 – six percent).

Financial statistics
millions of dollars
Capital employed at December 31
Return on average capital employed (percent)

2004
2 660
18.4

2003
2 784
15.5

2002
2 484
5.5

2001
2 148
15.9

2000
2 280
13.9

Chemicals
Return on average capital employed was 41 percent for the chemicals segment, compared with 18 percent in 2003 (2002 – 28 percent).

Financial statistics
millions of dollars
Capital employed at December 31
Return on average capital employed (percent)

2004
242
41.0

2003
246
17.5

2002
178
27.9

2001
195
13.7

2000
140
53.4

Corporate and other
Net income from corporate and other accounts was negative $54 million in 2004, compared with positive $99 million in 2003 (2002 –
negative $11 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 non-recurring after-tax writedown 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 intended use of the property and management’s commitment to sell following the announcement of the relocation of the
company’s headquarters to Calgary.

Capital and exploration expenditures
Total capital and exploration expenditures were $1,411 million in 2004, down slightly from $1,526 million in 2003 (2002 – $1,600 million).

Imperial Oil Limited

3 5

Management report

The accompanying consolidated financial statements and all
information in this annual report are the responsibility of
management. The financial statements have been prepared in
accordance with accounting principles generally accepted in
the United States of America and Canada and include certain
estimates that reflect management’s best judgments. Financial
information contained throughout this annual report is
consistent with the financial statements prepared under
United States generally accepted accounting principles.
Supplemental information based on Canadian generally
accepted accounting principles is provided on page 34.

Management has established and maintains a system of
internal controls that provides reasonable assurance that all
transactions are accurately recorded, that the financial
statements fairly report the company’s operating and financial
results and that the company’s assets are safeguarded. The
company’s internal audit unit reviews and evaluates the
adequacy of and compliance with the company’s internal
control standards. It is also the company’s policy to maintain
the highest standard of ethics in all its activities.

Imperial’s board of directors has approved the information
contained in the financial statements. The board fulfills its
responsibility regarding the financial statements mainly

Auditors’ report

To the shareholders of Imperial Oil Limited

We have audited the consolidated balance sheets of Imperial
Oil Limited as at December 31, 2004 and 2003 and the
consolidated statements of income, cash flows and
shareholders’ equity for each of the three years in the period
ended December 31, 2004. These financial statements are the
responsibility of the company’s management. Our responsibility
is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with Canadian
generally accepted auditing standards. Those standards
require that we plan and perform an audit to obtain reasonable
assurance whether the financial statements are free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation.

through its audit committee, which is composed of the
nonemployee directors. The audit committee reviews the
company’s annual and quarterly financial statements,
accounting practices, business and financial controls, and
internal audit program and its findings. It also recommends
the external auditors to be appointed by the shareholders at
each annual meeting, reviews their audit work plan and
approves their fees.

PricewaterhouseCoopers LLP, an independent firm of
chartered accountants, was appointed by a vote of shareholders
at the company’s last annual meeting to examine the
consolidated financial statements and provide an independent
professional opinion.

T.J. Hearn

P.A. Smith

February 16, 2005

In our opinion, these consolidated financial statements present
fairly, in all material respects, the financial position of the
company as at December 31, 2004 and 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 accordance with
accounting principles generally accepted in the United States
of America and Canada.

Chartered Accountants
Toronto, Ontario

February 16, 2005

Annual report 2004

Consolidated statement of income

millions of Canadian dollars
For the years ended December 31
Revenues
Operating revenues (a)
Investment and other income (note 11)
Total revenues

Expenses
Exploration
Purchases of crude oil and products
Production and manufacturing
Selling and general
Federal excise tax (a)
Depreciation and depletion
Financing costs (note 15)
Total expenses

Under United States GAAP
2004
2002
2003

Under Canadian GAAP
2003

2004

2002

22 408
52
22 460

59
13 094
2 883
1 218
1 264
908
7
19 433

19 094
114
19 208

55
10 823
2 782
1 269
1 254
755
(120)
16 818

16 890
152
17 042

30
9 723
2 320
1 222
1 231
708
20
15 254

22 408
52
22 460

59
13 094
2 883
1 218
1 264
903
41
19 462

19 094
114
19 208

55
10 823
2 782
1 269
1 254
750
(87)
16 846

16 890
152
17 042

30
9 723
2 297
1 222
1 231
705
32
15 240

Income before income taxes

3 027

2 390

1 788

2 998

2 362

1 802

Income taxes (note 4)
Income before cumulative effect

of accounting change

Cumulative effect of accounting change,

after income tax

975

689

574

965

680

578

2 052

1 701

1 214

2 033

1 682

1 224

–

Net income (note 2)

2 052

1 705

1 214

2 033

1 682

1 224

(a) Operating revenues include federal

Per-share information (dollars)
Net income per common share – basic (note 13)

Income before cumulative effect

of accounting change

Cumulative effect of accounting change,

after income tax

Net income (note 2)

Net income per common share – diluted (note 13)

Income before cumulative effect

of accounting change

Cumulative effect of accounting change,

after income tax

Net income (note 2)

Dividends

5.75

–
5.75

5.74

–
5.74

0.88

4.57

0.01
4.58

4.57

0.01
4.58

0.87

3.20

–
3.20

3.20

–
3.20

0.84

5.70

5.69

0.88

4.52

–
4.52

4.52

–
4.52

0.87

3.23

–
3.23

3.23

–
3.23

0.84

excise tax of $1,264 million
(2003 – $1,254 million,
2002 – $1,231 million).

The information on pages 41 through 56
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.

Imperial Oil Limited

3 7

Consolidated statement of cash flows

millions of Canadian dollars, inflow/(outflow)
For the years ended December 31
Operating activities
Net income
Cumulative effect of accounting change, after tax
Adjustments for non-cash items:
Depreciation and depletion
(Gain)/loss on asset sales, after tax
Deferred income taxes and other

Changes in operating assets and liabilities:

Accounts receivable
Inventories and prepaids
Income taxes payable
Accounts payable
All other items – net (a)

Cash from operating activities (note 2)

Investing activities
Additions to property, plant and equipment

and intangibles

Proceeds from asset sales
Loans to equity company
Cash from/(used in) investing activities (note 2)

Financing activities
Short-term debt – net
Long-term debt issued
Repayment of long-term debt
Issuance of common shares under stock option plan
Common shares purchased (note 13)
Dividends paid
Cash from/(used in) financing activities

Increase/(decrease) in cash
Cash at beginning of year
Cash at end of year (b)

(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.

Under United States GAAP
2004
2002
2003

Under Canadian GAAP
2002

2003

2004

2 052
–

908
(32)
(90)

(311)
(32)
462
308
47
3 312

(1 376)
102
(32)
(1 306)

9
–
(8)
13
(872)
(317)
(1 175)

831
448
1 279

1 705
(4)

755
(10)
(59)

33
31
38
74
(336)
2 227

(1 482)
56
–
(1 426)

–
818
(818)
2
(799)
(322)
(1 119)

(318)
766
448

1 214
–

708
(4)
(148)

(356)
51
(225)
323
125
1 688

(1 564)
61
–
(1 503)

(388)
500
(71)
–
(13)
(319)
(291)

(106)
872
766

2 033
–

903
(32)
(100)

(311)
(32)
462
308
47
3 278

(1 342)
102
(32)
(1 272)

9
–
(8)
13
(872)
(317)
(1 175)

831
448
1 279

1 682
–

750
(10)
(68)

33
31
38
74
(336)
2 194

(1 449)
56
–
(1 393)

–
818
(818)
2
(799)
(322)
(1 119)

(318)
766
448

1 224
–

705
(4)
(144)

(356)
51
(225)
323
102
1 676

(1 552)
61
–
(1 491)

(388)
500
(71)
–
(13)
(319)
(291)

(106)
872
766

Annual report 2004

Consolidated balance sheet

millions of Canadian dollars
At December 31
Assets
Current assets

Cash
Accounts receivable, less estimated

doubtful amounts

Inventories of crude oil and products (note 14)
Materials, supplies and prepaid expenses
Deferred income tax assets (note 4)

Total current assets
Investments and other long-term assets (note 2)
Property, plant and equipment, less accumulation,

depreciation and depletion (notes 1, 2)

Goodwill (note 1)
Other intangible assets, net (note 2)
Total assets (notes 1, 2)

Liabilities
Current liabilities

Short-term debt
Accounts payable and accrued liabilities (note 16)
Income taxes payable
Current portion of long-term debt

Total current liabilities
Long-term debt (note 3)
Other long-term obligations (notes 2, 8)
Deferred income tax liabilities (notes 2, 4)
Commitments and contingent liabilities (note 12)
Total liabilities

Shareholders’ equity
Common shares at stated value (note 13)
Earnings reinvested (note 2)
Accumulated other nonowner changes in equity (note 2)
Total shareholders’ equity

Under United States GAAP
2004
2003

Under Canadian GAAP
2003

2004

1 279

1 626
432
112
448
3 897
130

9 647
204
149
14 027

81
2 525
1 057
995
4 658
367
1 525
1 155

448

1 315
407
105
353
2 628
97

9 267
204
141
12 337

72
2 222
595
501
3 390
859
1 314
1 229

1 279

1 626
432
112
448
3 897
270

9 569
204
52
13 992

81
2 525
1 057
995
4 658
367
1 010
1 319

448

1 315
407
105
353
2 628
259

9 218
204
52
12 361

72
2 222
595
501
3 390
859
972
1 362

7 705

6 792

7 354

6 583

1 801
4 889
(368)
6 322

1 859
3 952
(266)
5 545

1 801
4 837
–
6 638

1 859
3 919
–
5 778

Total liabilities and shareholders’ equity (note 2)

14 027

12 337

13 992

12 361

Approved by the directors

T.J. Hearn
Chairman, president and
chief executive officer

P.A. Smith
Controller and senior vice-president,
finance and administration

Imperial Oil Limited

3 9

Consolidated statement of shareholders’ equity

millions of Canadian dollars
At December 31
Common shares at stated value (note 13)

At beginning of year
Issued under the stock option plan
Share purchases at stated value
At end of year

Earnings reinvested
At beginning of year
Net income for the year
Share purchases in excess of stated value
Dividends
At end of year

Accumulated other nonowner changes in equity

At beginning of year
Minimum pension liability adjustment (note 7)
At end of year

Under United States GAAP
2004
2002
2003

Under Canadian GAAP
2003

2004

2002

1 859
13
(71)
1 801

3 952
2 052
(801)
(314)
4 889

(266)
(102)
(368)

1 939
2
(82)
1 859

3 287
1 705
(717)
(323)
3 952

(315)
49
(266)

1 941
–
(2)
1 939

2 402
1 214
(11)
(318)
3 287

(77)
(238)
(315)

1 859
13
(71)
1 801

3 919
2 033
(801)
(314)
4 837

–
–
–

1 939
2
(82)
1 859

3 277
1 682
(717)
(323)
3 919

–
–
–

1 941
–
(2)
1 939

2 382
1 224
(11)
(318)
3 277

–
–
–

Shareholders’ equity at end of year

6 322

5 545

4 911

6 638

5 778

5 216

Nonowner changes in equity for the year

Net income for the year
Other nonowner changes in equity (note 7)

Total nonowner changes in equity for the year

2 052
(102)
1 950

1 705
49
1 754

1 214
(238)
976

Annual report 2004

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. A description of the differences between GAAP in Canada and in the United States as they apply to the company, including a
reconciliation of net income, cash flows and impacted balance sheet line items, is provided in note 2. 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.

Imperial Oil Limited

4 1

Summary of significant accounting policies (continued)

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.

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.

Annual report 2004

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.

The characteristics of these transactions are indistinguishable from those of any other monetary sales transaction. 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. 02-3.” While Issue 03-11 addresses the issue of gross versus
net classification for derivative instruments, it also provides guidance for purchase/sale transactions 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
Net income as shown in financial statements
Add: stock-based compensation expense as reported, net of tax
Deduct: stock-based compensation expense, net of tax, determined under fair-value-based method
Pro forma net income

Net income per share (dollars)
As reported – basic

Pro forma

– diluted
– basic
– diluted

Consumer taxes

2004
2 052
84
(86)
2 050

5.75
5.74
5.74
5.73

2003
1 705
76
(81)
1 700

4.58
4.58
4.57
4.57

2002
1 214
24
(41)
1 197

3.20
3.20
3.16
3.16

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.

Imperial Oil Limited

4 3

Notes to consolidated financial statements

Business segments

accounting change

Cumulative effect of accounting change,

after income tax

Net income
Capital and exploration expenditures (e)
Property, plant and equipment
Cost
Accumulated depreciation and depletion
Net property, plant and equipment (f) (g)
Total assets (h)

millions of dollars
Revenues
External sales (c)
Intersegment sales
Investment and other income
Total revenues
Expenses
Exploration
Purchases of crude oil and products
Production and manufacturing
Selling and general (d)
Federal excise tax
Depreciation and depletion
Financing costs (note 15)
Total expenses
Income before income taxes
Income taxes (note 4)
Current
Deferred
Total income tax expense
Income before cumulative effect of accounting change
Cumulative effect of accounting change, after income tax
Net income
Capital and exploration expenditures (e)
Property, plant and equipment
Cost
Accumulated depreciation and depletion
Net property, plant and equipment (f) (g)
Total assets (h)

Natural resources (a)
2002
2003

2004

Petroleum products
2004
2003

2002

3 689
2 891
45
6 625

59
2 110
1 608
27
–
633
1
4 438
2 187

3 390
2 224
34
5 648

55
1 873
1 577
28
–
517
1
4 051
1 597

2 573
2 217
104
4 894

30
1 599
1 228
21
–
477
1
3 356
1 538

763
(63)
700

535
(77)
458

517
(21)
496

1 487

1 139

1 042

–
1 487
1 113

13 538
7 337
6 201
6 875

4
1 143
1 007

12 610
6 813
5 797
6 418

–
1 042
986

11 612
6 269
5 343
6 013

17 503
1 666
42
19 211

–
14 769
1 092
1 098
1 264
257
2
18 482
729

299
(70)
229

500

–
500
283

14 710
1 294
54
16 058

–
11 822
1 054
1 123
1 254
211
2
15 466
592

66
119
185

407

–
407
478

13 362
1 038
34
14 434

–
10 781
954
1 076
1 231
203
1
14 246
188

172
(111)
61

127

–
127
589

6 078
2 959
3 119
5 570

6 069
2 856
3 213
5 290

5 827
2 867
2 960
5 127

Corporate and other
2004
2003

2002

Chemicals
2003

994
238
–
1 232

–
882
153
118
–
22
–
1 175
57

13
7
20

–
37
41

609
401
208
440

2002

955
209
–
1 164

–
806
139
115
–
23
–
1 083
81

40
(11)
29

–
52
25

579
383
196
428

2004

1 216
293
–
1 509

–
1 064
184
93
–
13
–
1 354
155

59
(4)
55

100

–
100
15

682
459
223
498

Consolidated (b)
2003

2002

2004

–
–
(35)
(35)

–
–
–
–
–
5
4
9
(44)

(18)
9
(9)
(35)
–
(35)
34

205
101
104
1 382

–
–
26
26

–
–
–
–
–
5
(123)
(118)
144

(4)
30
26
118
–
118
33

145
96
49
497

–
–
14
14

–
–
–
10
–
5
18
33
(19)

(11)
(1)
(12)
(7)
–
(7)
12

112
91
21
787

22 408
–
52
22 460

59
13 094
2 883
1 218
1 264
908
7
19 433
3 027

1 103
(128)
975
2 052
–
2 052
1 445

19 094
–
114
19 208

55
10 823
2 782
1 269
1 254
755
(120)
16 818
2 390

610
79
689
1 701
4
1 705
1 559

16 890
–
152
17 042

30
9 723
2 320
1 222
1 231
708
20
15 254
1 788

718
(144)
574
1 214
–
1 214
1 612

20 503
10 856
9 647
14 027

19 433
10 166
9 267
12 337

18 130
9 610
8 520
12 003

Annual report 2004

(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

Total revenues
Total expenses
Net income, after income tax

Total current assets
Long-term assets
Total current liabilities
Other long-term obligations

Cash flow from operating activities
Cash (used in) investing activities

2004

2 744
1 598
780

367
4 140
948
330

1 188
(858)

2003

2 494
1 577
664

302
3 553
913
322

883
(754)

2002

2 357
1 520
557

321
3 038
669
293

615
(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
Purchases of crude oil and products
Operating expenses

Total intersegment sales

Intersegment receivables and payables

millions of dollars

Natural resources
Petroleum products
Chemicals
Total export sales

2004
4 849
1
4 850
298

2004
1 301 360
791 01 074
56678
3 112

2003
3 754
2

3 756

308

2003

1 304
792
567

2 663

2002
3 463
1

3 464

352

2002

942
723
520

2 185

(d) Consolidated operating, 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.

Imperial Oil Limited

4 5

Notes to consolidated financial statements (continued)

Differences between United States and Canadian generally accepted accounting principles
Effective 2004, the company prepares its financial statements in accordance with the generally accepted accounting principles (GAAP) of
the United States. Prior to 2004, the company’s financial statements were prepared in conformity with Canadian GAAP. A reconciliation
of the differences between GAAP in Canada and in the United States as they apply to the company is provided below:

Consolidated statement of income
Net income for 2004 (millions of dollars)
Net income per common share (dollars)

Basic
Diluted

Net income for 2003 (millions of dollars)
Net income per common share (dollars)

Basic
Diluted

Net income for 2002 (millions of dollars)
Net income per common share (dollars)

Basic
Diluted

Consolidated statement of cash flows
millions of dollars
Cash from operating activities for 2004
Cash from/(used in) investing activities for 2004

Cash from operating activities for 2003
Cash from/(used in) investing activities for 2003

Cash from operating activities for 2002
Cash from/(used in) investing activities for 2002

Consolidated balance sheet
millions of dollars
As at December 31, 2004
Investments and other long-term assets
Property, plant and equipment
Other intangible assets
Total assets

Other long-term obligations
Deferred income tax liabilities
Earnings reinvested
Accumulated other nonowner changes in equity
Total liabilities and shareholders’ equity

As at December 31, 2003
Investments and other long-term assets
Property, plant and equipment
Other intangible assets
Total assets

Other long-term obligations
Deferred income tax liabilities
Earnings reinvested
Accumulated other nonowner changes in equity
Total liabilities and shareholders’ equity

Reported
under
U.S.
GAAP
2 052

Increase/(decrease) due to

Capitalized
interest
(19)

Accounting
change
–

Reported
under
Canadian
GAAP
2 033

5.75
5.74

1 705

4.58
4.58

1 214

3.20
3.20

Reported
under
U.S.
GAAP
3 312
(1 306)

2 227
(1 426)

1 688
(1 503)

Reported
under
U.S.
GAAP

130
9 647
149
14 027

1 525
1 155
4 889
(368)
14 027

97
9 267
141
12 337

1 314
1 229
3 952
(266)
12 337

(0.05)
(0.05)

(19)

(0.05)
(0.05)

(4)

(0.01)
(0.01)

–
–

(4)

(0.01)
(0.01)

0.04
0.04

Increase/(decrease) due to

Capitalized
interest
(34)
34

(33)
33

(12)
12

Increase/(decrease) due to

Capitalized
interest

Minimum
pension
liabilities

–
(78)
–
(78)

–
(26)
(52)
–
(78)

–
(49)
–
(49)

–
(16)
(33)
–
(49)

140
–
(97)
43

(515)
190
–
368
43

162
–
(89)
73

(342)
149
–
266
73

5.70
5.69

1 682

4.52
4.52

1 224

3.23
3.23

Reported
under
Canadian
GAAP
3 278
(1 272)

2 194
(1 393)

1 676
(1 491)

Reported
under
Canadian
GAAP

270
9 569
52
13 992

1 010
1 319
4 837
–
13 992

259
9 218
52
12 361

972
1 362
3 919
–
12 361

Annual report 2004

Under U.S. GAAP, interest costs related to major capital projects under construction are required to be capitalized as part of property,
plant and equipment. Under Canadian GAAP, the company did not capitalize interest costs for the same projects.

Under U.S. GAAP, the cumulative effect of accounting change for the adoption of the standard on accounting for asset retirement
obligations in 2003 was reflected in the consolidated net income for 2003. Under Canadian GAAP, financial statements of prior periods
were restated to reflect the effect of the same accounting change.

Under U.S. GAAP, the accumulated benefit obligation (ABO) is the actuarial present value of benefits attributed to employee service
rendered up to the end of the year and is based on current compensation levels. Since the amount by which the ABO less the fair value
of plan assets was greater than the liability previously recognized in the consolidated balance sheet, an additional minimum pension
liability was required. The minimum pension liability has no impact on net income and because this adjustment was non-cash, its effect
has been excluded from the accompanying consolidated statement of cash flows. No such adjustment is required under Canadian GAAP.

Long-term debt

issued
2003

2003
Long-term debt (b)
Capital leases (c)
Total long-term debt (d) (e)

maturity date
$250 million due May 26, 2005, and
$250 million due August 26, 2005 (a)
January 19, 2006 (a)

interest rate

Variable
Variable

2004

2003

millions of dollars

–
318
318
49
367

500
318
818
41
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.

Income taxes
millions of dollars
Current income tax expense
Deferred income tax expense (a)
Total income tax expense (b)
Statutory corporate tax rate (percent)
Increase/(decrease) resulting from:

Non-deductible royalty payments to governments
Resource allowance in lieu of royalty deduction
Manufacturing and processing credit
Enacted tax-rate and tax-law changes
Other

Effective income tax rate

2004
1 103
(128)
975
37.0

3.9
(7.0)
–
(1.8)
0.1
32.2

2003
610
79
689
38.5

5.0
(7.5)
0.2
(3.1)
(4.3)
28.8

2002
718
(144)
574
42.0

5.4
(11.8)
(0.3)
(0.9)
(2.3)
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).

Imperial Oil Limited

4 7

Notes to consolidated financial statements (continued)

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
Depreciation and amortization
Successful drilling and land acquisitions
Pension and benefits (a)
Site restoration
Net tax loss carryforwards (b)
Capitalized interest
Other
Deferred income tax liabilities

LIFO inventory valuation
Other
Deferred income tax assets
Valuation allowance
Net deferred income tax liabilities

2004
1 287
403
(343)
(158)
(57)
26
(3)
1 155

(343)
(105)
(448)
–
707

2003
1 233
495
(286)
(167)
(57)
16
(5)
1 229

(268)
(85)
(353)
–
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.

Reporting of fuel consumed in operations
Beginning in 2004, fuel consumed in operations, previously included in purchases of crude oil and products, has been reclassified as
production and manufacturing expenses in the consolidated statement of income. Prior period amounts have been reclassified for
comparative purposes. This reclassification has no impact on total expenses and net income or on the cash-flow profile of the company.

Headquarters relocation
On September 29, 2004, the company announced its intention to relocate its head office from Toronto, Ontario, to Calgary, Alberta.
Completion of the move is expected by August 2005. Severance, relocation and other costs associated with the relocation are expected
to be recorded in 2005, consistent with management decisions and the spending profile of these costs.

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.

Annual report 2004

Details of the employee retirement benefits plans are as follows:

millions of dollars
Components of net benefit cost:
Current service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Recognized actuarial loss/(gain)
Net benefit cost (a)

Change in benefit obligation
Benefit obligation at January 1
Current service cost
Interest cost
Amendments
Actuarial loss/(gain)
Benefits paid
Benefit obligation at December 31

Pension benefits
2003

2004

2002

64
222
(191)
25
34
154

76
237
(223)
27
68
185

3 761
76
237
37
405
(256)
4 260

71
219
(179)
25
69
205

3 530
71
219
–
171
(230)
3 761

Accumulated benefit obligation at December 31

3 743

3 347

Change in plan assets
Fair value of plan assets at January 1
Actual return on plan assets
Company contributions
Payments directly to participants
Benefits paid
Fair value of plan assets at December 31

Excess/(deficiency) of plan assets

over benefit obligation

Unrecognized net actuarial (gain)/loss (b)
Unrecognized prior service cost (b)
Net amount recognized

Amount recognized in the consolidated balance sheet consists of:
Accrued benefit cost (note 8)
Intangible assets
Accumulated other nonowner changes in equity,

minimum pension liability adjustment

Net amount recognized

Assumptions

2 786
315
114
25
(256)
2 984

(1 276)
1 073
99
(104)

(759)
97

558
(104)

2 104
377
511
24
(230)
2 786

(975)
829
89
(57)

(561)
89

415
(57)

Other post-retirement benefits
2003

2004

2002

6
24
–
–
47

–

5
22
–
–
19

–

4
21
–
–
25

–

(43)
34

(16)

(24)
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:

Asset category (percent)
Equities
Bonds
Other
Total

Target
allocation
2005
50 – 75
25 – 50
0 – 10

Percentage of plan assets
at December 31

2004
62
38
–
100

2003
62
38
–
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.

Cash flows
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

millions of dollars
2005
2006
2007
2008
2009
Years 2010 – 2014

Pension
benefits
230
234
238
244
251
1 398

Other
post-retirement
benefits
20
22
24
26
28
161

Annual report 2004

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.

millions of dollars
Increase/(decrease) in accumulated other nonowner

changes in equity, before tax

Deferred income tax (charge)/credit (note 4)
Increase/(decrease) in accumulated other nonowner

changes in equity, after tax

2004

(143)
41

(102)

Pension benefits
2003

106
(57)

2002

(393)
155

(238)

A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:

millions of dollars
For funded pension plans with accumulated benefit

obligations in excess of plan assets:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
Accumulated benefit obligation less fair value of plan assets

For unfunded plans covered by book reserves:

Projected benefit obligation
Accumulated benefit obligation

Pension benefits

2004

2003

3 876
3 430
2 984
446

384
313

3 464
3 126
2 786
340

297
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)
millions of dollars
Rate of return on plan assets:
Effect on net benefit costs

Discount rate:
Effect on net benefit costs
Effect on benefit obligations

Rate of pay increases:
Effect on net benefit costs
Effect on benefit obligations

One-percent
increase

One-percent
decrease

(30)

(45)
(525)

30
160

50
645

(25)
(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)
millions of dollars
Effect on service and interest cost components
Effect on other post-retirement benefit obligations

One-percent
increase
4
45

One-percent
decrease
(3)
(40)

Imperial Oil Limited

5 1

Notes to consolidated financial statements (continued)

Other long-term obligations
millions of dollars
Employee retirement benefits (note 7) (a)
Asset retirement obligations and other environmental liabilities (b)
Other obligations
Total other long-term obligations

2004
1 052
380
93
1 525

2003
847
393
74
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

Asset retirement obligations liability at January 1
Additions
Accretion
Settlement

Asset retirement obligations liability at December 31

2004

327
16
22
(37)

328

2003

341
–
20
(34)

327

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.

Annual report 2004

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 43. 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

Granted

Exercised

Cancelled
or adjusted

Outstanding at

Expensed in
period
December 31 (millions of dollars)

Obligations
outstanding at
December 31
(millions of dollars)

Incentive share units

2004
2003
2002

Deferred share units

2004
2003
2002

Earnings bonus units

2004
2003
2002

Incentive stock options

2004
2003
2002

Restricted stock units

2004
2003
2002

–
–
7 000

4 899
8 253
7 479

1 889 740
2 221 580
1 036 500

–
–
3 210 200

987 480
872 085
791 890

(1 619 907)
(1 142 145)
(812 550)

–
(49 486)
(9 853)

(1 139 160)
(1 156 370)
–

(274 250)
(49 050)
–

–
(3 300)
–

(3 000)
19 225
(5 325)

–
(379)
–

–
–
–

(7 400)
(11 500)
(13 500)

(5 710)
(120)
–

11.

Investment and other income
Investment and other income includes gains and losses on asset sales as follows:
millions of dollars
Proceeds from asset sales
Book value of assets sold
Gain/(loss) on asset sales, before tax
Gain/(loss) on asset sales, after tax

5 266 423
6 889 330
8 012 250

48 810
43 911
85 523

3 984 830
3 234 250
2 169 040

2 854 500
3 136 150
3 196 700

2 642 325
1 660 555
791 890

2004
102
59
43
32

94
109
39

1
1
–

7
3
3

–
–
–

31
11
–

2003
56
44
12
10

245
216
142

4
3
4

6
3
3

–
–
–

41
11
–

2002
61
56
5
4

Imperial Oil Limited

5 3

Notes to consolidated financial statements (continued)

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 1. 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:

millions of dollars
Operating leases (a)
Unconditional purchase obligations (b)
Firm capital commitments (c)
Other long-term agreements (d)

2005
62
102
119
241

2006
55
42
24
196

2007
47
42
8
62

2008
41
42
13
61

2009
38
42
7
59

After
2009
91
55
–
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 42). 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.

Year
1995 to 2002
2003
2004
Cumulative purchases to date

Purchased
shares
202 661 201
16 259 538
13 606 712
232 527 451

Millions of
dollars
5 169
799
872
6 840

Exxon Mobil Corporation’s participation in the above maintained its ownership interest in Imperial at 69.6 percent.

Annual report 2004

The company’s common share activities are summarized below:

Balance as at January 1, 2002
Issued for cash under the stock option plan
Purchases
Balance as at December 31, 2002
Issued for cash under the stock option plan
Purchases
Balance as at December 31, 2003
Issued for cash under the stock option plan
Purchases
Balance as at December 31, 2004

Thousands
of shares
379 159
–
(296)
378 863
49
(16 259)
362 653
274
(13 607)
349 320

At stated value,
millions
of dollars
1 941
–
(2)
1 939
2
(82)
1 859
13
(71)
1 801

The following table provides the calculation of basic and diluted earnings per share:

Net income per common share – basic
Income before cumulative effect of accounting change (millions of dollars)
Net income (millions of dollars)

2004

2 052
2 052

2003

1 701
1 705

2002

1 214
1 214

Weighted average number of common shares outstanding (thousands of shares)

356 834

372 011

378 875

Net income per common share (dollars)

Income before cumulative effect of accounting change
Cumulative effect of accounting change, after income tax

Net income

Net income per common share – diluted
Income before cumulative effect of accounting change (millions of dollars)
Net income (millions of dollars)

Weighted average number of common shares outstanding (thousands of shares)
Effect of employee stock-based awards (thousands of shares)
Weighted average number of common shares outstanding,

assuming dilution (thousands of shares)

Net income per common share (dollars)

Income before cumulative effect of accounting change
Cumulative effect of accounting change, after income tax

Net income

14. Miscellaneous financial information

5.75
–
5.75

2 052
2 052

356 834
818

4.57
0.01
4.58

1 701
1 705

372 011
143

3.20
–
3.20

1 214
1 214

378 875
1

357 652

372 154

378 876

5.74
–
5.74

4.57
0.01
4.58

3.20
–
3.20

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
Crude oil
Petroleum products
Chemical products
Natural gas and other
Total inventories of crude oil and products

2004
165
190
59
18
432

2003
161
175
57
14
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).

Imperial Oil Limited

5 5

Notes to consolidated financial statements (continued)

15.

Financing costs
millions of dollars
Debt-related interest
Capitalized interest
Net interest expense
Other interest
Total interest expense (a)
Foreign-exchange expense/(gain) on long-term debt
Total financing costs

2004
37
(34)
3
4
7
–
7

2003
38
(33)
5
4
9
(129)
(120)

2002
40
(12)
28
2
30
(10)
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
Total revenues
Purchases of crude oil and products
Total expenses

2004
1 580
3 133
43

2003
950
2 464
14

2002
1 036
2 134
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
Current income tax expense (note 4)
Federal excise tax
Property taxes included in expenses
Payroll and other taxes included in expenses
GST/QST/HST collected (a)
GST/QST/HST input tax credits (a)
Other consumer taxes collected for governments
Crown royalties
Total paid or payable to governments
Less investment tax credits and other receipts
Net paid or payable to governments
Net payments to:

Federal government
Provincial governments
Local governments

Net paid or payable to governments

2004
1 103
1 264
85
50
2 297
(1 948)
1 670
472
4 993
14
4 979

2 472
2 422
85
4 979

2003
610
1 254
80
52
2 015
(1 705)
1 662
418
4 386
30
4 356

2 061
2 215
80
4 356

2002
718
1 231
85
51
1 717
(1 368)
1 589
314
4 337
12
4 325

2 171
2 069
85
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.

Annual report 2004

Natural resources segment – supplemental information

Pages 57 to 59 provide information about the natural resources segment (see note 1, page 44). The information excludes items not
related to oil and natural gas extraction such as administrative and general expenses, pipeline operations, gas plant processing fees and
gains or losses on asset sales.

In addition to proved oil and gas reserves, the company has a 25-percent interest in proved synthetic crude oil reserves in the Syncrude
project. For internal management purposes, the company views these reserves and their development as an integral part of its total
natural resources operations. However, for financial reporting purposes, these reserves are required to be reported separately from the
oil and gas reserves as shown on page 59.

The synthetic crude oil reserves are not considered in the standardized measure of discounted future cash flows for oil and gas reserves
on page 58. The company’s share of Syncrude’s results of operations, capital and exploration expenditures and property, plant and
equipment is also excluded from the following tables on this page.

Results of operations

millions of dollars
Sales to customers
Intersegment sales
Total sales (a)
Production expenses
Exploration expenses
Depreciation and depletion
Income taxes
Results of operations

Capital and exploration expenditures

millions of dollars
Property costs (b)

Proved
Unproved
Exploration costs
Development costs
˜
Total capital and exploration expenditures

Property, plant and equipment

millions of dollars
Property costs (b)

Proved
Unproved
Producing assets
Support facilities
Incomplete construction
Total cost
Accumulated depreciation and depletion
Net property, plant and equipment

2002
1 485
797
2 282
736
30
426
350
740

2002

13
5
34
469
521

Oil and gas
2003
2 067
665
2 732
926
55
463
364
924

Oil and gas
2003

Oil and gas

–
2
55
339
396

2003

3 332
163
5 775
125
200
9 595
6 012
3 583

2004
2 160
976
3 136
915
44
565
532
1 080

2004

–
1
43
408
452

2004

3 328
141
6 099
122
235
9 925
6 514
3 411

(a) 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, as well as royalty
payments. These items are reported gross in note 1 in ”total revenues” and in ”purchases of crude oil and products.”

(b) ”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.

Imperial Oil Limited

5 7

Natural resources segment – supplemental information (continued)

Standardized measure of discounted future cash flows
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.

Standardized measure of discounted future net cash flows related to proved oil and gas reserves

millions of dollars
Future cash flows
Future production costs
Future development costs
Future income taxes
Future net cash flows
Annual discount of 10 percent

for estimated timing of cash flows

Discounted future cash flows

2004
11 625
(3 123)
(1 492)
(2 260)
4 750

(1 433)
3 317

Oil and gas
2003
27 611
(10 871)
(3 084)
(5 543)
8 113

(3 375)
4 738

Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves

millions of dollars
Balance at beginning of year
Changes resulting from:

Sales and transfers of oil and gas produced, net of production costs
Net changes in prices, development costs and production costs
Extensions, discoveries, additions and improved recovery, less related costs
Purchases/(sales) of minerals in place
Development costs incurred during the year
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes

Net change
Balance at end of year

2004
4 738

(2 240)
(3 692)
(43)
–
345
1 838
663
1 708
(1 421)
3 317

Oil and gas
2003
8 201

(2 075)
(4 395)
22
–
281
(368)
1 108
1 964
(3 463)
4 738

2002
35 811
(8 940)
(3 117)
(9 107)
14 647

(6 446)
8 201

2002
2 789

(1 645)
9 276
34
4
432
111
423
(3 223)
5 412
8 201

Annual report 2004

Net proved developed and undeveloped reserves (a)

Beginning of year 2002

Revisions of previous estimates and improved recovery
(Sale)/purchase of reserves in place
Discoveries and extensions
Production
End of year 2002

Revisions of previous estimates and improved recovery
(Sale)/purchase of reserves in place
Discoveries and extensions
Production
End of year 2003

Performance-related revisions and improved recovery
(Sale)/purchase of reserves in place
Discoveries and extensions
Production
Total before year-end price/cost revisions

Year-end price/cost revisions
End of year 2004

Crude oil and NGLs
millions of barrels
Cold Lake
807

Conventional
165

3
–
–
(22)
146

1
–
–
(21)
126

6
–
–
(22)
110

5
115

33
–
–
(39)
801

5
–
–
(43)
763

(20)
–
–
(41)
702

(470)
232

Natural gas
billions of cubic feet

1 414

(26)
2
3
(169)
1 224

(40)
–
6
(167)
1 023

57
(13)
3
(190)
880

(89)
791

Total
972

36
–
–
(61)
947

6
–
–
(64)
889

(14)
–
–
(63)
812

(465)
347

Synthetic
crude oil
millions of barrels
Syncrude
821

–
–
–
(21)
800

–
–
–
(19)
781

(3)
–
–
(21)
757

–
757

(a) 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 degrees Fahrenheit.

The above information describes changes during the years and balances of proved oil and gas and synthetic crude oil reserves at year-end 2002, 2003 and
2004. The definitions used for oil and gas reserves are in accordance with the U.S. Securities and Exchange Commission’s (SEC) Rule 4-10 (a) of
Regulation S-X, paragraphs (2), (3) and (4).

Crude oil and natural gas reserve estimates, excluding Syncrude, are based on geological and engineering data, which have demonstrated with
reasonable certainty that these reserves are recoverable in future years from known reservoirs under existing economic and operating conditions; i.e.,
prices and costs as of the date the estimate is made. Reserves of crude oil at Cold Lake are those estimated to be recoverable from the Leming plant and
commercial phases 1 through 13. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place
crude bitumen volumes, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating
approval limits.

In compliance with SEC 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 reserves 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 ”Year-end price/cost revisions.” 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 reserves 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 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. During the past five years, performance-related revisions averaged an upward adjustment of 16 million oil-
equivalent barrels per year.

Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For conventional crude oil
(excluding enhanced oil-recovery projects) and natural gas, net proved reserves are based on estimated future royalty rates representative of those
existing as of the date the estimate is made. Actual future royalty rates may vary with production and price. For enhanced oil-recovery projects, Syncrude
and Cold Lake, net proved reserves are based on the company’s best estimate of average royalty rates over the life of each project. Actual future royalty
rates may vary with production, price and costs.

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 Syncrude, the Cold Lake Leming plant and phases 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.

Imperial Oil Limited

5 9

Share ownership, trading and performance

Share ownership

Average number outstanding,

weighted monthly (thousands)
Number of shares outstanding at
December 31 (thousands)

Shares held in Canada at December 31 (percent)
Number of registered shareholders

at December 31 (a)

Number of shareholders registered

in Canada

Shares traded (thousands)

Share prices (dollars)

Toronto Stock Exchange

High
Low
Close at December 31

American Stock Exchange ($U.S.)

High
Low
Close at December 31

Net income per share, under U.S. GAAP (dollars)

– basic
– diluted

Price ratios at December 31

Share price to net earnings (b)

Dividends declared (c)
Total (millions of dollars)
Per share (dollars)

2004

2003

2002

2001

2000

356 834

349 320
14.6

14 953

13 088

93 778

73.65
56.42
71.15

62.45
42.34
59.38

5.75
5.74

12.4

314
0.88

372 011

378 875

393 121

417 753

362 653
15.2

15 516

13 601

94 063

58.22
43.20
57.53

44.75
28.25
44.42

4.58
4.58

12.6

323
0.87

378 863
15.8

15 988

14 014

379 159
15.9

16 483

14 358

398 263
16.6

17 104

14 873

83 019

129 285

117 980

49.38
38.51
44.86

31.85
24.00
28.70

3.20
3.20

14.0

318
0.84

46.50
34.05
44.31

29.45
22.59
27.88

3.11
3.11

14.2

324
0.83

42.25
26.50
39.45

27.81
17.94
26.30

3.37
3.37

11.7

325
0.78

(a) Exxon Mobil Corporation owns 69.6 percent of Imperial’s shares.
(b) Closing share price at December 31 at the Toronto Stock Exchange, divided by net earnings per share – basic and diluted.
(c) The fourth-quarter dividend is paid on January 1 of the succeeding year.

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.

Imperial Oil Limited is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates (15 percent and five percent
for certain individuals) that are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations.

There is no Canadian tax on gains from selling shares owned by nonresidents not carrying on business in Canada.

Valuation day price
For capital gains purposes, Imperial’s common shares were quoted at $10.50 a share on December 31, 1971, and $15.29 on
February 22, 1994. Both amounts are restated for the 1998 three-for-one share split.

Annual report 2004

Quarterly financial and stock-trading data (a)

2004
three months ended
Sept. 30
June 30

Mar. 31

Dec. 31

Mar. 31

2003
three months ended
Sept. 30
June 30

Financial data, under U.S. GAAP (millions of dollars)

Total revenues
Total expenses
Income before income taxes
Income taxes
Cumulative effect of accounting change
Net income

5 067
4 347
720
(254)
–
466

Segmented net income, under U.S. GAAP (millions of dollars)
319
135
12
–
466

Natural resources
Petroleum products
Chemicals
Corporate and other
Net income

5 466
4 767
699
(195)
–
504

368
108
29
(1)
504

5 814
4 986
828
(284)
–
544

411
99
31
3
544

Segmented cash flows from operating activities, under U.S. GAAP (millions of dollars)

Natural resources
Petroleum products
Chemicals
Corporate and other
Cash flows from operating activities

Per share information, under U.S. GAAP (dollars)

Net income – basic
Net income – diluted
Dividends (declared quarterly)

Share prices (dollars) (b)
Toronto Stock Exchange

High
Low
Close

American Stock Exchange ($U.S.)

High
Low
Close

395
(4)
3
4
398

1.29
1.29
0.22

64.45
56.42
58.87

48.70
42.34
44.84

438
204
45
3
690

1.40
1.40
0.22

64.25
58.40
62.40

47.13
43.17
46.82

738
309
55
7
1 109

1.53
1.53
0.22

66.76
59.50
65.48

52.22
45.50
51.71

6 113
5 333
780
(242)
–
538

389
158
28
(37)
538

729
354
23
9
1 115

1.53
1.52
0.22

73.65
65.28
71.15

62.45
51.43
59.38

5 478
4 685
793
(253)
4
544

343
139
6
56
544

531
172
(1)
2
704

1.44
1.44
0.21

47.80
43.48
47.35

32.20
28.25
32.14

4 510
3 888
622
(162)
–
460

292
102
7
59
460

418
217
50
(4)
681

1.23
1.23
0.22

47.40
43.20
47.10

34.99
29.94
34.92

4 626
4 057
569
(189)
–
380

257
115
8
–
380

441
63
(11)
1
494

1.03
1.03
0.22

53.49
45.62
50.80

38.79
33.04
37.21

Dec. 31

4 594
4 188
406
(85)
–
321

251
51
16
3
321

269
68
(16)
27
348

0.88
0.88
0.22

58.22
50.16
57.53

44.75
37.24
44.42

Shares traded (thousands) (c)

26 559

21 640

22 132

23 447

21 350

23 171

21 434

28 108

(a) Quarterly data has not been audited or reviewed by the company’s independent auditors.
(b) Imperial’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 Imperial’s common shares is IMO. Share prices were obtained from stock exchange records.

Dividend and share-purchase information

Declaration date
Dividend record date
Dividend payment date
Share-purchase cutoff date (cheques for share purchase
must be dated and received no later than)
Investment date (dividend reinvestment and share-purchase
funds are invested by the company on)

2nd quarter, 2005
May 26, 2005
June 8, 2005
July 1, 2005

3rd quarter, 2005

4th quarter, 2005
August 17, 2005 November 16, 2005
December 1, 2005
January 1, 2006

September 1, 2005
October 1, 2005

1st quarter, 2006
February 15, 2006
March 3, 2006
April 1, 2006

June 16, 2005 September 16, 2005 December 14, 2005

March 17, 2006

July 4, 2005

October 3, 2005

January 3, 2006

April 3, 2006

The declaration of dividends and the dates shown are subject to change by the board of directors.
The company reserves the right to amend, suspend or terminate the dividend reinvestment and share-purchase plan at any time.
Share-purchase cheques should be made payable to CIBC Mellon Trust Company.
Dividend cheques are normally mailed three to five days prior to payment dates.
Quarterly statements for dividend reinvestment and share-purchase plan participants are normally mailed two weeks after the investment dates.

Imperial Oil Limited

6 1

Information for investors

Head office

Imperial Oil Limited
111 St. Clair Avenue West
Toronto, Ontario, Canada M5W 1K3

Annual meeting

The annual meeting of shareholders will be held on
Thursday, April 21, 2005, at 10:30 a.m. local time at the
Metro Toronto Convention Centre, 255 Front Street West,
Toronto, Ontario, Canada.

Shareholder account matters

To change your address, transfer shares, eliminate multiple
mailings, elect to receive dividends in U.S. funds or have
dividends deposited directly into accounts at financial
institutions in Canada that provide electronic fund-transfer
services, enrol in the dividend reinvestment and share
purchase plan, or enrol for electronic delivery of shareholder
reports, please contact CIBC Mellon Trust Company.

CIBC Mellon Trust Company
P.O. Box 7010
Adelaide Street Postal Station
Toronto, Ontario, Canada M5C 2W9
Telephone: 1-800-387-0825 (from Canada or U.S.A.)

or 416-643-5500
416-643-5660 or -5661
inquiries@cibcmellon.com

Fax:
E-mail:
www.cibcmellon.com

United States resident shareholders may transfer their
shares through Mellon Investor Services LLC.

Mellon Investor Services LLC
85 Challenger Road
Ridgefield Park, New Jersey, U.S.A. 07660
Telephone: 1-800-526-0801

Dividend reinvestment and share-purchase plan

This plan provides shareholders with two ways to add to
their shareholdings at a reduced cost. The plan enables
shareholders to reinvest their cash dividends in additional
shares at an average market price. Shareholders can also
invest between $50 and $5,000 each calendar quarter in
additional shares at an average market price.

Funds directed to the dividend reinvestment and share
purchase plan are used to buy existing shares on a stock
exchange rather than newly issued shares.

Imperial on-line

Imperial’s Web site contains a variety of corporate
and investor information, including:
• current stock prices
• annual and interim reports
• Form 10-K
• Information for Investors (a factbook that describes

the company and its operations in detail)

• investor presentations
• earnings and other news releases
• historical dividend information
• corporate citizenship practices
www.imperialoil.ca

Investor information

Information is also available by writing to the investor
relations manager at Imperial’s head office or by:
416-968-8145
Telephone:
416-968-5345
Fax:

Other contact numbers

Customer and other inquiries:
Telephone:
Fax:

1-800-567-3776
1-800-367-0585

Corporate secretary
Telephone:
Fax:

416-968-4966
416-968-5407

Version française du rapport

Pour obtenir la version française du rapport de la Compagnie
Pétrolière Impériale Ltée, veuillez écrire à la division des
Relations avec les investisseurs, Compagnie Pétrolière
Impériale Ltée, 111 St. Clair Avenue West, Toronto, Ontario,
Canada M5W 1K3.

Design:

Smith-Boake Designwerke Inc.

Photography: Jean Becq, Bernard Bohn, J. Christopher Lawson, Alan Marsh/First Light,

Prisma Productions, Imperial Oil archives

Printing:

Quebecor World MIL Inc.

Annual report 2004

Directors, senior management and officers

Board of directors (from left to right)

Other officers

John F. Kyle
Vice-president and treasurer

Brian W. Livingston
Vice-president, general counsel
and corporate secretary

Paul A. Smith
Controller and senior
vice-president, finance
and administration
Imperial Oil Limited
Toronto, Ontario

Jim F. Shepard
Retired chairman and
chief executive officer
Finning International Inc.
Vancouver, British Columbia

Brian J. Fischer
Senior vice-president, products
and chemicals division
Imperial Oil Limited
Toronto, Ontario

J. Michael Yeager
Senior vice-president,
resources division
Imperial Oil Limited
Calgary, Alberta

Pierre Des Marais II
President
Gestion PDM Inc.
Montreal, Quebec

Roger Phillips
Retired president and
chief executive officer
IPSCO Inc.
Regina, Saskatchewan

Victor L. Young
Corporate director of
several corporations
St. John’s, Newfoundland
and Labrador

Sheelagh D. Whittaker
Managing director,
Public Sector Business
Electronic Data Systems Limited
London, England

Tim J. Hearn
Chairman, president and
chief executive officer
Imperial Oil Limited
Toronto, Ontario

Imperial Oil Limited

Corporate profile

Imperial on-line

Imperial Oil Limited has been a leading
member of the Canadian energy industry for
125 years and is well positioned to deliver
long-term shareholder value by participating
in some of the industry’s most promising
growth opportunities.

One of the largest producers of crude oil
and natural gas liquids in Canada and a
major producer of natural gas, the company
is Canada’s largest refiner and marketer of
petroleum products – sold primarily under
the Esso brand name – and a major producer
of petrochemicals.

The company’s Web site contains a wealth of
information for investors and others seeking
to evaluate Imperial’s performance and
prospects: the latest news releases, the most
recent reports and presentations, information
about dividends and taxes, key dates, historical
share information, contact numbers and a
frequently updated stock-price feed from the
Toronto Stock Exchange (TSX) – all this and
more is gathered in one convenient location.

Information on products and services, career
opportunities, corporate citizenship, donations
and sponsorships, coast-to-coast operations
and the company’s history is also available by
visiting www.imperialoil.ca.

Imperial Oil Limited
111 St. Clair Avenue West
Toronto, Ontario
Canada M5W 1K3

www.imperialoil.ca

This report has been printed and bound to facilitate recycling.

Cover photos, from left to right:
Scientists conduct research in a 1940s lab in Sarnia; the company now
operates two industry-leading research facilities, in Sarnia and Calgary;
the Sarnia manufacturing site opens its petrochemical plant in 1950;
today, the site is the most integrated fuels, lubricating oil and chemicals
manufacturing facility in Canada; Imperial’s association with hockey dates
from the 1930s; the company continues to sponsor Canada’s national winter
sport at all levels; Imperial’s Leduc discovery in 1947 signals the beginning
of Canada’s role as a major oil producer; the company drills new wells at its
Cold Lake heavy-oil operations; customers fill-up with gasoline at a 1916
service station; today Esso service stations offer fast, friendly service,
quality products and one-stop convenience for busy customers on the go.

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