Exhibit 2  Managements Discussion & Analysis  Managements Discussion and Analysis (MD&A) should be read in
conjunction with the Financial Statements and Notes included in this annual
report. Financial data has been prepared in accordance with Canadian generally
accepted accounting principles (GAAP), unless otherwise specified. All dollar
values are Canadian dollars, unless otherwise indicated. All oil and gas
production and reserves volumes are stated before deduction of royalties,
unless otherwise indicated. Graphs accompanying the text identify our value
drivers, key measures of performance in each component of our business.  RESULTS OF OPERATIONS  Shareholder Value  Shareholder value grew 31.5 per cent through share price appreciation
and dividends in 2003.    One-year
return(per cent)  Three-year
average return(per cent)  Shareholder
value measures the change in the Petro-Canada share price plus dividend
returns.  ANALYSIS OF CONSOLIDATED
EARNINGS AND CASH FLOW  Consolidated Financial Results  (millions of dollars,
  unless otherwise indicated)
  
  2003
  
  2002
  
  2001Earnings from operations(1),(3)
  
  $
  1
  401
  
  $
  1
  024
  
  $
  912Gain (loss) on foreign currency translation
  
  239
  
  (52
  )
  (96
  )Gain on disposal of assets
  
  29
  
  2
  
  30Net earnings
  
  $
  1
  669
  
  $
  974
  
  $
  846Earnings per share (dollars)
   basic
  
  $
  6.30
  
  $
  3.71
  
  $
  3.19 diluted
  
  6.23
  
  3.67
  
  3.16Cash flow(2),(3)
  
  3
  372
  
  2
  276
  
  1
  688Cash flow per share (dollars)
  
  12.73
  
  8.66
  
  6.37Debt
  
  2
  229
  
  3
  057
  
  1
  401Cash and cash equivalents
  
  635
  
  234
  
  781Average capital employed
  
  $
  9
  392
  
  $
  7
  826
  
  $
  6
  259Return on capital employed (per
  cent)
  
  18.9
  
  13.9
  
  14.8Operating return on capital employed (per cent)
  
  16.1
  
  14.5
  
  15.8Return on equity (per cent)
  
  24.7
  
  18.3
  
  18.1  
 (1)Earnings from operations, which
represents net earnings excluding gains or losses on
foreign currency translation and on disposal of assets, is used by the Company
to evaluate operating performance. (2)Cash flow, which is expressed
before changes in non-cash working capital items, is used by the Company to
analyze operating performance, leverage and liquidity. (3)Earnings from operations and
cash flow do not have any standardized meaning prescribed by Canadian generally
accepted accounting principles (GAAP) and, therefore, may not be comparable
with the calculation of similar measures for other companies.  This Managements Discussion and Analysis (MD&A)
contains forward-looking statements. Such statements are generally identifiable
by the terminology used, such as plan, anticipate, intend, expect,
estimate, budget or other similar wording. Forward looking statements
include but are not limited to: references to future capital and other
expenditures; drilling plans; construction activities; the submission of
development plans; seismic activity; refining margins; oil and gas production
levels and the sources of growth thereof; results of exploration activities and
dates by which certain areas may be developed or may come on-stream; retail
throughputs; pre-production and operating costs; reserves estimates; reserves
life; natural gas export capacity; and environmental matters. These
forward-looking statements are subject to known and unknown risks and uncertainties
and other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. Such factors include, but are not limited to: general economic,
market and business conditions; industry capacity; competitive action by other
companies; fluctuations in oil and gas prices; refining and marketing margins;
the ability to produce and transport crude oil and natural gas to markets; the
results of exploration and development drilling and related activities;
fluctuation in interest rates and foreign currency exchange rates; the ability
of suppliers to meet commitments; actions by governmental authorities including
increases in taxes; decisions or approvals of administrative tribunals; changes
in environmental and other regulations; risks attendant with oil and gas
operations; and other factors, many of which are beyond the control of
Petro-Canada. These factors are discussed in greater detail in filings made by
Petro-Canada with the Canadian provincial securities commissions and the United
States Securities and Exchange Commission (SEC).  Petro-Canadas staff of qualified reserves evaluators generate the reserves
estimates used by this corporation. Our reserves staff and management are not
considered independent of the corporation for purposes of the Canadian
provincial securities commissions. The use of terms such as probable,
possible, recoverable or potential reserves and resources does not meet
the guidelines of the SEC for inclusion in documents filed with the SEC.
Petro-Canada has obtained an exemption from certain Canadian reserves
disclosure requirements to permit it to make disclosure in accordance with SEC
standards in order to provide comparability with U.S. and other international
issuers. Therefore, Petro-Canadas reserves data and other oil and gas formal
disclosure is made in accordance with U.S. disclosure requirements and
practices and may differ from Canadian domestic standards and practices. Where
the term boe (barrel of oil equivalent) is used in this MD&A it may be
misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:
1 bbl is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the wellhead.  Readers are
cautioned that the foregoing list of important factors affecting
forward-looking statements is not exhaustive. Furthermore, the forward-looking
statements contained herein are made as of the date of this MD&A, and
Petro-Canada does not undertake any obligation to update publicly or to revise
any of the included forward-looking statements, whether as a result of new
information, future events or otherwise. The forward-looking statements contained
in this MD&A are expressly qualified by this cautionary statement.  1 
   2003 COMPARED WITH 2002  Stronger commodity prices and margins combined with higher production
volumes to boost earnings from operations to a record $1 401 million in 2003.
Net earnings, including gains on foreign currency translation and disposals of
assets, and cash flow rose to record levels. The improved financial performance
reflected higher prices for natural gas, an additional four months of
operations from International assets acquired in May 2002, increased production
from East Coast Oil, higher refinery cracking margins and positive adjustments
for income tax rate changes and International provisions. Offsetting factors
included after-tax charges of $151 million for the consolidation of Eastern
Canada refinery operations, $82 million for the write-off of costs related to
the original Edmonton refinery conversion plan and a
$46 million provision related to the impending sale of a non-core asset in
Kazakhstan.  Earnings from Operations and
Cash Flow  Earnings from operations were $1.4 billion in 2003.    Earnings
from operations($ millions)  Cash
flow($ millions)  Earnings
from operations do not include gains or losses on foreign currency translation
and on disposal of assets.  Earnings from Operations
Variance Factors - 2003 compared with 2002  (millions of dollars, after tax)2002 Earnings from operations
  
  $
  1 024Higher Upstream commodity
  prices(1)
  
  338Increased Upstream production
  volumes(2),(3)
  
  279Increased Downstream margins
  
  143Adjustment to International
  provisions
  
  45Decrease in the provision for
  future income taxes(4)
  
  45Decrease in depreciation,
  depletion and amortization, and exploration expense(3),(5)
  
  31Increased operating and G&A
  costs(6)
  
  (183
  )Costs related to the planned
  shutdown of Oakville refinery
  
  (151
  )Costs related to revised
  Edmonton refinery feedstock conversion plan
  
  (82
  )Asset impairment in Kazakhstan
  
  (46
  )Other
  
  (42
  )2003 Earnings from operations
  
  $
  1 401  
 (1)The major portion relates to
higher natural gas price realizations in Canada. (2)Reflects four additional months
of International activity, 10 additional months of MacKay River operations and significant
volume gains at Hibernia and Terra Nova. (3)The impact of higher volumes on
depreciation, depletion and amortization expense is included in production
volume variance. (4)Reflects income tax adjustments
related to federal and provincial rate changes. (5)Excludes depreciation,
depletion and amortization related to costs associated with the Oakville
shutdown, the Edmonton refinery feedstock conversion and the Kazakhstan asset
impairment. (6)Reflects four additional months
of International activity and 10 additional months of MacKay River operations.  Operating Return on Capital
Employed  Operating return on capital employed reflected higher earnings due to a
stronger business environment.    Operating
return on capital employed (per cent)  Earnings
from operations do not include gains or losses on foreign currency translation
and on disposal of assets.  Consolidated 2003 cash flow was $3 372 million compared with $2 276
million in 2002. Cash flow in 2003 reflected the higher operating earnings,
about $120 million of net deferrals of current income taxes related to earnings
of the Petro-Canada Oil and Gas Partnership (PCOG) and about a $25 million
decrease in current income taxes resulting from the inventory valuation method
prescribed for income tax purposes in the Downstream. In 2002, net deferrals
related to earnings of PCOG increased current taxes by about $50 million and
the inventory valuation method increased current taxes by about $85 million.  The increased returns on equity and capital
employed resulted primarily from the 71 per cent improvement in net earnings.  QUARTERLY INFORMATION  Consolidated Quarterly Financial Results  (millions of dollars, unless otherwise indicated)
  
  2003
  
  2002Quarter 1
  
  Quarter 2
  
  Quarter 3
  
  Quarter 4
  
  Quarter 1
  
  Quarter 2
  
  Quarter 3
  
  Quarter 4Total revenue
  
  $
  3 507
  
  $
  2 826
  
  $
  2 959
  
  $
  2 929
  
  $
  1 708
  
  $
  2 437
  
  $
  2 767
  
  $
  3 005Net earnings
  
  583
  
  585
  
  301
  
  200
  
  88
  
  321
  
  209
  
  356Earnings per share (dollars) basic
  
  2.21
  
  2.21
  
  1.13
  
  0.75
  
  0.34
  
  1.22
  
  0.79
  
  1.35 diluted
  
  $
  2.18
  
  $
  2.18
  
  $
  1.12
  
  $
  0.75
  
  $
  0.33
  
  $
  1.21
  
  $
  0.79
  
  $
  1.34  2 
   Variances from quarter to quarter in revenues and net earnings resulted
mainly from: fluctuations in commodity prices and refinery cracking margins;
the acquisition of international producing properties effective May 2, 2002;
the impact on production and processed volumes from maintenance and other
shutdowns at major facilities; and the level of exploration drilling activity,
particularly in high-cost frontier and offshore areas. Other significant
factors affecting 2003 net earnings included after-tax charges of $46 million
in the first quarter related to the pending Kazakhstan asset sale, $136 million
in the third quarter for the consolidation of our Eastern Canada refinery
operations, and $82 million in the fourth quarter related to the revised
Edmonton refinery conversion plan. Income tax rate changes increased first
quarter earnings by $96 million and decreased fourth quarter earnings by $51
million in 2003. In addition, gains on foreign currency translation were also a
significant factor, particularly in the first and second quarters of 2003.  For further analysis of quarterly results,
refer to Petro-Canadas quarterly reports to shareholders available on the Web
site at www.petro-canada.ca.  BUSINESS ENVIRONMENT  Economic factors influencing Petro-Canadas Upstream
financial performance include crude oil and natural gas prices, and foreign
exchange rates, particularly the Canadian dollar/U.S. dollar rate. Factors of
supply and demand, weather, political events and the level of industry product
inventories affect prices for energy commodities. Factors influencing Downstream performance include the level and volatility of
crude oil prices, industry refining margins, movements in light/heavy crude oil
price differentials, demand for refined petroleum products and the degree of
market competition.  The stronger Canadian dollar dampened the impact of higher commodity
prices in 2003.  Business Environment in 2003  During 2003, U.S. dollar-denominated international crude oil prices
reached their highest annual average since 1982. The strength of international
crude prices in 2003 was due to a confluence of geopolitical and market
factors. OPEC decision-making, supported by production discipline among member
nations, continued to be the major factor in keeping prices high. Additionally,
a general strike in Venezuela, the war in Iraq and political unrest in Nigeria
reduced crude oil supplies. As well, a very cold winter in the Northern
Hemisphere and the resumption of economic growth in key consuming areas led to
a tight global supply/demand situation. The strengthening of the Canadian
dollar throughout 2003 dampened the impact of increased international oil
prices on Canadian prices.  The value of
the Canadian dollar rose from 63.3 cents US on
December 31, 2002 to 77.4 cents US on December 31, 2003, an unprecedented
12-month increase of 14.1 cents US or 22.3 per cent.  Colder-than-normal weather in North America
during the first quarter of 2003 led to rising natural gas prices. Strong gas
injection activity to replenish depleted storage levels lent support to prices
from April through October. In the fourth quarter, gas prices lost some of
the gains made during the injection season as the heating season began with
close-to-normal levels of gas in storage.  In the Canadian industrys downstream sector,
refined product sales in 2003 grew by approximately 4.7 per cent compared with
0.8 per cent in 2002. Refining margins also noticeably improved, reflecting the
strong refined product sales and substantially wider light-heavy crude price
differentials.  Commodity Price Indicators and Exchange Rates  (averages for the years indicated)
  
  2003
  
  2002Crude oil price indicators(per
  barrel):Dated Brent at Sullom Voe
  
  US$
  28.84
  
  US$
  24.98West Texas Intermediate (WTI) at
  Cushing
  
  US$
  31.04
  
  US$
  26.08WTI/Brent price differential
  
  US$
  2.20
  
  US$
  1.10Brent/Maya price differential
  
  US$
  4.61
  
  US$
  4.08Edmonton Light
  
  Cdn$
  43.77
  
  Cdn$
  40.41Edmonton Light/Bow River (heavy)
  price differential
  
  Cdn$
  11.67
  
  Cdn$
  8.90Natural gas price indicators:At Henry Hub  per million
  British thermal units (mmbtu)
  
  US$
  5.44
  
  US$
  3.25AECO spot  per thousand cubic
  feet (mcf)
  
  Cdn$
  6.99
  
  Cdn$
  4.24Henry Hub-AECO-C basis
  differential  per mmbtu
  
  US$
  0.70
  
  US$
  0.66New York Harbor 3-2-1 refinery
  crack spread  per barrel
  
  US$
  5.31
  
  US$
  3.36US$ per Cdn$ exchange rate
  
  US$
  0.714
  
  US$
  0.637  3 
   Petro-Canadas businesses are managed for the long term.  Outlook for Business Environment in 2004  Prices for energy commodities are expected to remain volatile in 2004,
reflecting the vagaries of weather, the level of industry inventories, and
political and natural events. Current low global crude inventories combined
with cold winter weather, uncertainty about the reliability of Iraqs oil
infrastructure and the political stability of Venezuela and Nigeria are
expected to maintain international oil prices near record levels. Given the
current low level of oil inventories worldwide and continuing growth in demand,
the upward pressure on world oil prices is likely to be amplified by the recent
OPEC decision to lower its production ceiling by one million barrels per day
starting April 1, 2004.  We expect the North American natural gas
supply/demand balance to remain tight in 2004, as low-cost supplies from
conventional areas continue to decline despite very high drilling activity. In
the absence of increased supplies, natural gas prices are expected to rise to
the levels necessary to ration demand and re-balance the market.  In the industrys downstream sector, refined
product margins are expected to face continued pressure from high and volatile
crude oil costs, particularly during the first half of 2004, resulting in lower
margins than in 2003. Expectations of improving economic conditions lead
management to anticipate, weather trends aside, another year of positive growth
in domestic sales of refined products.  Economic Sensitivities  The following table shows the estimated after-tax effects that changes
in certain factors would have had on Petro-Canadas 2003 net earnings, had
these changes occurred. These calculations are based on business conditions,
production and sales volumes realized in 2003.  Sensitivities Affecting Net
Earnings  Factor(1)
  
  2003 Averages
  
  Increase
  
  Impact on
  Net Earnings(millions
  of
  Canadian dollars)UpstreamPrice received for crude oil and
  liquids
  
  $38.80/bbl
  
  $1.00/bbl
  (2)
  $
  48Price received for natural gas
  
  $6.16/mcf
  
  $0.25/mcf
  
  36Production of crude oil and
  liquids
  
  319 900 barrels per day (b/d
  )
  1 000 b/d
  
  4Production of natural gas
  available for sale
  
  868 million cubic feet per day
  
  10 mmcf/d
  
  6(mmcf/d
  )Exchange rate (impact on
  Upstream earnings):Cdn$ per US$
  
  Cdn $1.401
  
  Cdn $0.01
  
  (39
  )DownstreamNew York Harbor 3-2-1 crack
  spread(3)
  
  US$5.31/bbl
  
  US$0.10/bbl
  
  4Light/heavy crude price
  differential(4)
  
  $11.67/bbl
  
  $1.00/bbl
  
  11CorporateExchange rate: Cdn$ per US$(5)
  
  Cdn $1.401
  
  Cdn $0.01
  
  $
  9  
 (1)The impact of a change in one
factor may be compounded or offset by changes in other factors. This table does
not consider the impact of any inter-relationship among the factors. The
application of these factors may not necessarily lead to an accurate prediction
of future results of operations. We may undertake risk management initiatives
from time to time that affect these sensitivities. (2)This sensitivity is based upon
an equivalent change in the price of WTI and North Sea Brent. In 2003, WTI
averaged US$31.04 per barrel (bbl) and North Sea Brent averaged US$28.84/bbl. (3)New York Harbor 3-2-1 crack
spread applies mainly to Eastern Canada markets. (4)This refers to the spread
between the prices of benchmark Edmonton Light and Bow River (heavy) crude
oils. (5)This refers to gains or losses
on a portion (US$873 million) of the Companys long-term debt. Gains or loses
on foreign currency denominated long-term debt associated with the self-sustaining
International business segment are deferred and included as part of
shareholders equity.  4 
   UPSTREAM  Petro-Canadas Upstream operations consist of four business segments:
North American Gas, with current production in Western Canada; East Coast Oil,
with three major developments offshore Newfoundland; Oil Sands operations in
northeastern Alberta; and International, where we are active in three core
areas: Northwest Europe, North Africa/Near East; and Northern Latin America.
Our diverse asset base provides a balanced portfolio and a platform for
longer-term growth.  In 2003,
Petro-Canadas worldwide production before royalties averaged 319 900 barrels
per day (b/d) of oil and liquids and 868 million cubic feet per day (mmcf/d) of
natural gas, or a record 464 500 barrels of oil equivalent per day (boe/d). A
significant portion of the 21 per cent increase from the 2002 level of 382 400
boe/d is related to the additional four months of International operations.  Oil and Gas Production  Production increased due to an additional four months of International
operations and higher East Coast Oil and Oil Sands production.    Upstream
production (thousands of barrels of oil equivalent per day)  Production
  
  North
  American Gas
  
  East
  Coast Oil
  
  Oil Sands
  
  International
  
  Total2002 Average Daily VolumesCrude oil, NGL and bitumen (b/d)net before royalties
  
  18 900
  
  71 900
  
  1 100
  
  125 500
  
  217 400net after royalties
  
  14 200
  
  70 900
  
  1 000
  
  75 200
  
  161 300Synthetic crude oil(b/d)net before royalties
  
  
  
  
  
  27 500
  
  
  
  27 500net after royalties
  
  
  
  
  
  27 200
  
  
  
  27 200Natural gas(mmcf/d)net before royalties
  
  722
  
  
  
  
  
  103
  
  825net after royalties
  
  558
  
  
  
  
  
  80
  
  638Total volumes(boe/d)net before royalties
  
  139 200
  
  71 900
  
  28 600
  
  142 700
  
  382 400net after royalties
  
  107 200
  
  70 900
  
  28 200
  
  88 500
  
  294 8002003 Average Daily VolumesCrude oil, NGL and bitumen(b/d)net before royalties
  
  16 900
  
  86 100
  
  10 700
  
  180 800
  
  294 500net after royalties
  
  12 600
  
  84 000
  
  10 600
  
  115 600
  
  222 800Synthetic crude oil(b/d)net before royalties
  
  
  
  
  
  25 400
  
  
  
  25 400net after royalties
  
  
  
  
  
  25 100
  
  
  
  25 100Natural gas(mmcf/d)net before royalties
  
  693
  
  
  
  
  
  175
  
  868net after royalties
  
  521
  
  
  
  
  
  149
  
  670Total volumes(boe/d)net before royalties
  
  132 300
  
  86 100
  
  36 100
  
  210 000
  
  464 500net after royalties
  
  99 500
  
  84 000
  
  35 700
  
  140 400
  
  359 600  5 
   North American Gas  Western Canada Operating and
Overhead Costs  Cost per unit was up due to lower volumes and higher utility and labour
costs.    Unit
operating and overhead costs($ per thousand cubic feet of gas equivalent)  Includes
Western Canada gas, conventional oil and liquids.  North American Gas Financial Results  (millions of dollars)
  
  2003
  
  2002
  
  2001Earnings from operations
  
  $
  479
  
  $
  180
  
  $
  463Gain (loss) on sale of assets
  
  33
  
  (1
  )
  29Net earnings
  
  $
  512
  
  $
  179
  
  $
  492Cash flow
  
  $
  985
  
  $
  534
  
  $
  651Expenditures on property, plant
  and equipment and exploration
  
  $
  560
  
  $
  530
  
  $
  548Total assets
  
  $
  2 301
  
  $
  2 240
  
  $
  2 129  2003 COMPARED WITH 2002  Higher prices for natural gas and
solid operating performance boosted earnings from operations for North American
Gas to a record $479 million in 2003, 166 per cent higher than in the previous
year.  The exceptional financial result also reflected a $60 million pre-tax
decrease in exploration expense due to reduced activity in the Mackenzie
Delta/Corridor and the Scotian Slope.  Petro-Canadas natural gas price realizations
averaged $6.50/mcf, up 62 per cent from $4.01/mcf in 2002, due to tighter
market conditions for natural gas for a large part of the year. Natural gas
production averaged 693 mmcf/d in 2003, down from 722
mmcf/d in 2002, as additional volumes from ongoing development were
insufficient to offset declines in older fields. Production of conventional
crude oil and natural gas liquids production in Western Canada averaged 16 900
b/d, down from 18 900 b/d in 2002, mainly as the result of non-core asset
sales. The asset sales, representing production of about 10 mmcf/d of natural
gas and 2 000 b/d of oil and natural gas liquid, resulted in an after-tax gain
of $33 million. Operating and overhead costs in 2003 were $0.67 per thousand
cubic feet of gas equivalent (mcfe), up from $0.57/mcfe in the previous year,
reflecting lower volumes and higher utility and labour costs.  Our strategy in North American Gas is to sustain long-term
profitability.  STRATEGY  Petro-Canada is
one of the larger producers of natural gas in Western Canada. Our goal is to
maintain exceptional profitability in Western Canada, while positioning
ourselves for longer-term opportunities. Our strategy is to:  Capitalize on opportunities in the Western
Canada Sedimentary Basin, balancing profitability with production growth. Maintain focus on capital investment
performance and operating efficiency. Optimize existing core properties and add
new core areas through focused exploration and acquisitions. For the longer term, pursue high-potential
exploration in the Mackenzie Delta/Corridor, on the Scotian Slope and in
Alaska.  Executing the strategy  Capital expenditures in 2003 included $472 million for exploration and
development of natural gas in Western Canada and $58 million for other natural
gas opportunities in North America, principally in the Mackenzie
Delta/Corridor. Capital spending was above plan due to increased development
drilling activity and a $30 million acquisition of a 60 per cent interest in
the Savanna Creek gas field in southwest Alberta. Exploration and development
drilling activity in Western Canada in 2003 resulted in 421 gross successful
wells, for a success rate of 92 per cent.  In Western Canada we are focused on four core
areas  the Alberta Foothills, northeastern British Columbia, southeastern
Alberta, and west-central Alberta. In the Foothills, we have developed a strong
technical competency in finding, developing and operating deep sour gas. A key
feature of our strategy has been concentric exploitation in and around existing
developments and infrastructure, such as the area surrounding the Petro-Canada
operated Hanlan gas plant in the northern Foothills. Through the successful
drilling of multiple Turner Valley structures, combined with successful sweet
gas exploration  6 
   and development in the Narraway area, we have increased production in the
Hanlan region from an average of 105 mmcf/d in 2000 to 138 mmcf/d exiting 2003.
Results from the 2003 drilling program included 10 successful Turner Valley
wells. Additionally, follow-up drilling in 2003 on a 2002 Wabamum discovery has
resulted in four horizontal wells, each capable of about 10 mmcf/d of gross
production. Drilling plans for the Hanlan area in 2004 include the drilling of
a further six Turner Valley wells and additional wells in the Wabamum.  In the shallow gas region of southeastern
Alberta our annual drilling program resulted in 322 gross (204 net) successful
wells, raising gas production to 70 mmcf/d at 2003 year end.
To further support production volumes, we are reviewing opportunities to double
the well spacing in our properties from the current four wells per section.  For longer-term growth, we continue to pursue
frontier opportunities. Activity in 2003 included the initial drilling of our
fifth exploration well in the Mackenzie Delta. The Nuna I-30, about 10
kilometres southwest of the successful Tuk M-18 well, was spudded in
mid-February, later than originally planned due to an unseasonably warm start
to winter weather. The well was suspended in April before reaching its
target depth of 3 500 metres because of the onset of spring break-up. Offshore
Nova Scotia, we continue to evaluate the results of an
1 800 square kilometre 3-D seismic program shot over a deep-water area
northeast of Sable Island during 2003. In Alaska, we continue to review the
prospectivity of our land position in the foothills area north of the Brooks
mountain range. While our acreage is close to a proposed pipeline route to
southern markets, we do not expect the region to be serviced by a pipeline this
decade.  OUTLOOK  2004
production expectations: Western Canada production to average 640
mmcf/d of natural gas and 13 000 b/d of crude oil and natural gas liquids.  Growth plans: Increase Western Canada exploration over
time to improve reserves replacement. Pursue exploration and development prospects
in North America. Drill over 100 exploration and development
wells and over 300 shallow gas wells in Western Canada. Advance exploration programs in the
Mackenzie Delta/Corridor, Scotian Slope and Alaska.  2004 capital spending plans: $460 million for Western Canada. $35 million for Alaska and Mackenzie
Delta/Corridor.  Were looking beyond core
producing areas for new natural gas opportunities.  About $460 million will be invested in new and existing Western Canada
exploration and development opportunities. The $35 million allocated to Alaska
and the Mackenzie Delta/Corridor will enable us to assess future opportunities.
While we continue to invest substantial amounts in Western Canada, this is
proving to be insufficient to achieve 100 per cent reserves replacement because
of the maturing nature of the region. Going forward, our strategy will continue
to emphasize profitability through concentric exploitation of existing assets
but will also include an expanded focus outside of existing core areas. Of the
funding planned for 2004, $170 million will target exploration opportunities.  We do not plan any natural gas drilling in
Canadas frontier regions in 2004. In the Mackenzie Delta, the ongoing program
has secured our most prospective acreage for future exploration and allowed us
to make a non-binding nomination of 30 mmcf/d from our
share of the Tuk gas pool to support the development proposal for the Mackenzie
Valley pipeline. Pending further pipeline developments, our strategy is to
defer any major activity in the Mackenzie Delta over the 2004 winter drilling
season and re-evaluate our program next year. In Alaska, we will continue the
technical analysis of our prospects and exploitation strategy.  7 
   East Coast Oil  East Coast Oil Operating and
Overhead Costs  Operating and overhead costs were lower due to high production volumes.    Unit
operating and overhead costs ($ per barrel)  East Coast Oil Financial Results  (millions of dollars)
  
  2003
  
  2002
  
  2001Earnings from operations and net
  earnings
  
  $
  593
  
  $
  430
  
  $
  168Cash flow
  
  $
  869
  
  $
  687
  
  $
  338Expenditures on property, plant
  and equipment and exploration
  
  $
  344
  
  $
  289
  
  $
  279Total assets
  
  $
  2 247
  
  $
  2 209
  
  $
  2 090  2003 COMPARED WITH 2002  East Coast earnings from
operations in 2003, at $593 million, were up 38 per cent from 2002 due to
production gains, strong operating performance and crude oil price
improvements.  Petro-Canadas share of East Coast production before royalties rose to
86 100 b/d from 71 900 b/d the previous year, reflecting significant
improvements at both Hibernia (Petro-Canada  20 per cent working interest) and
Terra Nova (Petro-Canada  34 per cent working interest), despite severe
weather conditions during the first quarter. The improvement at Hibernia, where
gross field production climbed above 200 000 b/d for the first time, resulted
from additional drilling and outstanding reservoir performance with lower than
expected increases in the gas-oil and water-oil ratios. Approval by the
Canada-Newfoundland Offshore Petroleum Board (CNOPB) to increase the average
daily gross field production rate to 220 000 b/d enabled the production
improvement. At Terra Nova, gross field production averaged 134 000 b/d
(Petro-Canada share  45 500 b/d), up from 105 400 b/d (Petro-Canada share  35
800 b/d), in 2002, mainly due to the approval of an increase in the average
daily gross field production rate from 100 000 b/d to 180 000 b/d by the CNOPB.
Continued focus on reservoir management/optimization will enable us to maintain
high reservoir production capability. The average price realized for our East
Coast oil production in 2003 was $39.91/bbl, up from $38.84/bbl in 2002.  East Coast Oil operating and overhead costs
averaged $2.74/bbl in 2003, down from $3.32/bbl in 2002. Hibernia operating
costs were unchanged, while Terra Nova costs fell, reflecting the transition
from start-up to steady state operations.  STRATEGY  We believe the
East Coast offers exceptional opportunities for profitable growth in both the
near term and the long term. Key features of our strategy are:  Profitably expand reserves and production
base. Continue to strive for top quartile safety
and operating performance. Pursue high-potential exploration
opportunities.  Terra Nova and Hibernia continued to exceed production expectations in
2003.  Executing the strategy  Petro-Canadas capital expenditures for exploration and development of
crude oil offshore Canadas East Coast in 2003 amounted to $344 million, with
half related to the development of the White Rose oil field (Petro-Canada 
27.5 per cent working interest). Solid progress in 2003 kept the White Rose
project on track for production start-up in early 2006. Key components of the
project have either been completed or remain on schedule, except construction
of the topsides for the projects Floating Production, Storage and Offloading
vessel (FPSO). Concrete steps have been taken to make up for earlier delays in
topsides and engineering and procurement and still deliver first oil in early
2006. At year-end 2003, construction of the FPSO, which has a planned gross
production capacity of 100 000 b/d, was approximately two-thirds complete.
Progress also was made during 2003 on fabrication of the subsea production
systems. The first of the subsea wellhead assemblies was completed in November.  White Rose field development activity in 2003
included completion of three glory holes  nine-metre-deep excavations to
protect the subsea wellheads and associated production equipment against
icebergs, and commencement of the development drilling program. The White Rose
development plan  8 
   includes the drilling of 19 to 21 wells to recover an estimated 200 million to
250 million barrels of oil over a 10- to 12-year time frame. Ten wells  five
producing, four water injection and one gas injection  will be drilled prior
to start-up. Petro-Canadas estimate of the projects total pre-production
cost, including the first 10 wells, is $2.3 billion. Estimated peak gross
production from the project of 90 000 b/d is believed sustainable for about
four years. Encouraging results from 2003 delineation drilling in a previously
undrilled fault block south of the main reservoir indicate potential for incremental
oil reserves.  Our plans to extend plateau
production at Hibernia and Terra Nova focus on expanding existing developments,
while also evaluating the potential for subsea tiebacks of smaller discoveries
and prospects to the Hibernia and Terra Nova facilities. At Hibernia, assessment of the development
potential of the Ben Nevis Avalon continues. A comprehensive evaluation is
underway on the results of the B-44 appraisal well, drilled late in 2002.
Analysis of the reservoir will determine if additional delineation drilling is
necessary before further development is started or pursued.  At Terra Nova, our near-term goals are to
optimize reservoir performance and delineate field limits. Activity in 2003
included drilling one injection and three production wells. We are evaluating
development options for the adjoining Far East block, where a 2001 well
encountered 80 metres of oil-bearing net pay in the Jeanne dArc sands. Two
subsequent wells were dry and abandoned. We are currently evaluating drilling
results and reprocessed seismic data to better understand the options, as well
as drilling requirements and timing.  With an overall focus on base business
profitability, good progress continued to be made towards top quartile safety
and operating performance at each of our East Coast developments. Hibernia has
already achieved top quartile operating performance and Terra Nova is
incorporating lessons learned from Hibernia and North Sea operations in a
planned process to achieve the same results. Opportunities to capture synergies
between Hibernia, Terra Nova and White Rose are also being pursued to reduce
costs and improve efficiency.  In deeper waters 450 kilometres off
Newfoundland, two high-risk, high-potential exploration wells drilled in the
Flemish Pass basin in 2003 failed to encounter commercial quantities of
hydrocarbons. These wells were abandoned, with the related costs written off
against earnings in 2003. Information gained from the wells, together with
other exploration data, continue to be evaluated to
determine our future plans for the area.  Our strategy is to extend profitable East Coast oil production.  OUTLOOK  2004
production expectations: Petro-Canadas East Coast oil production to
average 80 000 b/d.  Our production
outlook takes into account a six-day potential shutdown at Terra Nova and a
10-day potential shutdown at Hibernia. We are investigating ways to minimize
the duration of shutdowns at both fields.  Growth plans: Complete White Rose development by early
2006. Extend plateau production at both Hibernia
and Terra Nova.  2004 capital spending plans: $180 million for development of White Rose. $140 million for ongoing Hibernia and Terra
Nova drilling and development.  The ongoing high level of
spending at White Rose, Hibernia and Terra Nova underscores the importance of
these world-class projects to our long-term growth plans. Development spending
at Hibernia and Terra Nova in 2004 will include drilling 14 wells  eight at
Hibernia and six at Terra Nova. No exploratory drilling is planned for this
offshore region in 2004.  9 
   Oil Sands  Syncrude Operating and
Overhead Costs  Operating and overhead costs increased due to lower reliability and
production volumes.    Unit
operating and overhead costs ($ per barrel)  Oil Sands Financial Results  (millions of dollars)
  
  2003
  
  2002
  
  2001Earnings (loss) from operations
  and net earnings (loss)
  
  $
  (50
  )
  $
  79
  
  $
  59Cash flow
  
  $
  127
  
  $
  196
  
  $
  136Expenditures on property, plant
  and equipment and exploration
  
  $
  448
  
  $
  462
  
  $
  304Total assets
  
  $
  1 746
  
  $
  1 473
  
  $
  899  2003 COMPARED WITH 2002  Oil Sands suffered a loss from
operations in 2003. The loss was due to an $82 million after-tax write off of
costs related to the original Edmonton refinery conversion plan, a start-up
phase operating loss from Petro-Canadas 100 per cent owned in situ
bitumen project at MacKay River and reliability problems at Syncrude.  The contribution to earnings from Petro-Canadas 12 per cent interest in
Syncrude was down from the previous year due to lower production volume and an
increase in operating costs, partially offset by higher oil prices. Our share
of Syncrude production averaged 25 400 b/d before royalties, down from 27 500
b/d in 2002. The volume decline was due to extended maintenance turnarounds at
the Aurora mine and one of the upgrader coking units and an unscheduled
turnaround on the other coking unit in the fourth quarter. Our average price
realized for synthetic crude oil production in 2003 was $42.67/bbl, up from
$40.66/bbl in 2002. Average unit operating costs increased to $23.64/bbl in
2003, compared with $19.50/bbl in the previous year, due to higher natural gas
costs, lower production volumes and increased maintenance costs.  The MacKay River project, a
steam-assisted gravity drainage (SAGD) operation, worked through
technical issues during its start-up year. The operating loss in 2003 was due
to a longer start-up phase than originally envisaged, which resulted in lower
production and higher operating costs. A major factor was a six-week shutdown
of steam generation to allow for process modifications to resolve a water
treating issue. The producing formation cooled during the shutdown, further
delaying the initial production build-up. In the fourth quarter, with water
treatment under control, production regained momentum, rising steadily to a
December average of 18 600 b/d. Reflecting the setback, bitumen production
for the year was less than half of the expected volume, averaging 10 700 b/d.
The average price realized for MacKay River bitumen in 2003 was $16.69/bbl.
While start-up phase operating costs averaged $22.11/bbl in 2003, they are
expected to decline going forward as performance improves and volumes grow.  MacKay River SAGD production ramped up in 2003.  STRATEGY  Petro-Canadas
Oil Sands assets include about 300 000 net acres of leases considered
prospective for in situ development of bitumen reserves. These are
long-life resources that can deliver production for well over 30 years. Our
strategy for profitable growth includes:  Phased and integrated development of
reserves, incorporating the benefits of our learnings as we go. Disciplined capital investment to ensure
these long-life projects are value creating.  Our staged
approach to development of capital-intensive Oil Sands projects ensures
vigorous cost management, while allowing us to benefit from evolving
technology.  10 
   Executing the strategy  Oil Sands capital expenditures of $448 million in 2003 included $292
million for Syncrude (mainly for the Stage 3 expansion), $112 million for
reconfiguration of the Edmonton refinery (a portion of which, relating to
feedstock conversion, was written off in 2003) and $44 million for the MacKay
River in situ project and other Oil Sands work.  At Syncrude, progress continued on the
construction of the third stage of a multi-stage expansion program. Stage 3
includes a second Aurora mine and an upgrading expansion. The Aurora 2 mine was
commissioned in the fourth quarter of 2003 and is contributing to the overall
bitumen supply.  At MacKay River, reliability improved
significantly in the fourth quarter of 2003 and the plant is on track to reach
30 000 b/d around mid-2004. With the reservoir responding well to steam
injection, we expect to sustain plateau production of 25 000 to 30 000 b/d for
25 to 30 years after accounting for turnarounds and unplanned events. Starting
in 2004, a 165-megawatt co-generation facility completed by TransCanada Energy
Limited will contribute to operating cost reduction, as well as increase steam
capacity at MacKay River. By converting waste heat from an existing gas
turbine, the co-generation facility is expected to improve overall energy
efficiency and reduce MacKay River gas consumption by about 10 to 15 per cent.  Following start-up of MacKay River in 2002,
our plans anticipated creation of a large-scale, fully-integrated bitumen
production and refining operation centered around our best-in-class
Edmonton refinery. However, over the past year, as we completed our basic
engineering for conversion of the Edmonton refinery, we could foresee the same
significant cost escalations as were taking place in all other large bitumen
upgrading projects within the industry. Our disciplined project management
processes prevented us from proceeding with the project at an uneconomic level
but required the write-off against earnings of the engineering costs incurred
to that date. After evaluating our options, we formulated a new, scaled-down
plan for upgrading and refining oil sands feedstock at Edmonton.  The new plan retains our longer-term objective
of a fully integrated bitumen production and refining operation, while also
providing the flexibility to pace the upstream portion of our strategy without
having to move in lockstep with refinery projects. The plan builds on the $1.4
billion strategic investments we are already making in the refinery for
long-term positioning and gasoline/diesel desulphurization. Key elements of the
new plan (with new investment estimated at $1.2 billion) include building new
crude and vacuum units, expanding the capacity of the existing coker and
building additional sulphur and hydrogen capability. The new configuration will
allow the refinery to directly upgrade approximately 26 000 b/d of bitumen and
process 48 000 b/d of sour synthetic crude oil. These lower-cost feedstocks
will replace the conventional feedstock that is refined today. The refinery
will also continue to process about 50 000 b/d of sweet synthetic crude through
its synthetic train.  Petro-Canada has a staged and integrated approach to oil sands
development.  OUTLOOK  2004
production expectations: Our share of Syncrude production to average
28 000 b/d. MacKay River bitumen production to average 25 000 b/d.  Growth plans: Continued participation in Syncrude Stage 3
expansion. Optimize reliability and performance of
MacKay River. Continue prospect evaluation for next in
situ bitumen project.  2004 capital spending plans: $305 million for our share of Syncrudes
Stage 3 expansion, sustaining capital for both Syncrude and MacKay River,
delineation of future bitumen resources and other expenses.  11 
   The Syncrude upgrader expansion is behind schedule. More information on
the schedule and costs to complete Stage 3 is expected in the first half
of 2004. Completion of Stage 3 will enable Petro-Canadas share of Syncrude
production capacity to rise by 13 000 b/d. Syncrude management continues to
direct considerable resources towards improving plant reliability to secure
more consistent achievement of production targets and lower unit operating
costs.  Initially, on completion of the Edmonton
refinery reconfiguration in 2008, Petro-Canada will fill out the refinerys
bitumen processing capability through the purchase of 26 000 b/d of bitumen
from other producers. This external feedstock will be replaced in due course by
supply from our next in situ SAGD development. Another important element
of our plan is an agreement with Suncor Energy Inc. that takes effect in 2008,
subject to regulatory approval. Under the agreement, Suncor will process a
minimum 27 000 b/d of our MacKay River bitumen production, on a fee-for-service
basis, to produce an estimated 22 000 b/d of sour synthetic. This sour crude,
combined with an additional 26 000 b/d of sour synthetic crude purchased from
Suncor, will complete our feedstock requirements. Both the processing and sales
components of the bitumen agreement will be for minimum 10-year terms.  During 2003, the federal governments
implementation plan for the Kyoto Protocol became clearer. The government has
given assurances that its commitment to climate change action will not jeopardize
economic growth and that it understands the importance of the issue to oil
sands development. Petro-Canada remains committed to seeking improvements to in
situ technology that will further improve its energy efficiency.  As part of our revised strategy, earlier plans
for development of Meadow Creek (owned 75 per cent by Petro-Canada) as our next
in situ bitumen production project were suspended. Under the revised
strategy, we believe smaller plants similar to MacKay River will enable us to
leverage knowledge gained through MacKay River operations and benefit from
rapidly changing technology advances. Our oil sands winter drilling evaluation
program is therefore focusing on delineation of sweet spots at Meadow Creek
and evaluation of expansion potential at MacKay River. Our revised plan
anticipates our next in situ project coming on-stream late in this
decade.  In December 2003, Petro-Canada announced a new plan to upgrade
bitumen at the Edmonton refinery.  International  International Financial Results  (millions of dollars)
  
  2003
  
  2002
  
  2001Earnings (loss) from operations
  
  $
  297
  
  $
  225
  
  $
  (27
  )Gain on sale of assets
  
  10
  
  
  
  Net earnings (loss)
  
  $
  307
  
  $
  225
  
  $
  (27
  )Cash flow
  
  $
  890
  
  $
  583
  
  $
  27Expenditures on property, plant
  and equipment and exploration
  
  $
  525
  
  $
  221
  
  $
  153Total assets
  
  $
  3 883
  
  $
  3 544
  
  $
  186  2003 COMPARED WITH 2002  The solid improvement in
International earnings from operations in 2003 mainly reflects an additional
four months contribution from assets acquired in 2002, and higher commodity
prices. Positive adjustments related to the clarification of production rights
and the settlement of a tax issue associated with a former operation also
contributed to the improvement.  Offsetting factors included a $46 million impairment provision related
to the impending sale of assets in Kazakhstan. This sale was completed in
February 2004. Petro-Canadas International production of crude oil and
natural gas in 2003 averaged 210 000 boe/d, essentially unchanged from an
average of 212 000 boe/d over the last eight months of 2002.  12 
   STRATEGY  Petro-Canadas
International operations are currently focused on three core exploration and
production regions: Northwest Europe; North Africa/Near East; and Northern
Latin America. The Company is positioning itself to become a larger
international player. Our strategy is to build a platform to deliver long-term
profitable growth. This strategy includes the following key elements:  Expand and exploit the existing portfolio of
assets. Target
new theatres of operation and acquisitions. Develop
a balanced exploration program.  International is a solid
business focused on three core areas.  Executing the strategy  Over the past two years, we have established a platform for successful
international growth. In 2003, International capital expenditures amounted to
$525 million, exceeding original plans due to the acquisition of additional
assets in the U.K. North Sea, partially offset by exploration program
reductions and lower spending in Libya. By core area, spending totalled $362
million in Northwest Europe, $137 million in North Africa/Near East, and $26
million in Northern Latin America.  Northwest Europe  In Northwest Europe, we have a solid foothold in the highly profitable
North Sea with production from the U.K. and Netherlands sectors. We also have
exploration programs in Denmark and the Faroe Islands. While the region is
mature, we believe small- to mid-size reserves can be produced economically,
especially if tied back to existing infrastructure. In 2003, Petro-Canadas
production from Northwest Europe averaged 37 700 b/d of crude oil and natural
gas liquids and 80 mmcf/d of natural gas, compared with averages of 40 500 b/d
and 90 mmcf/d respectively over the last eight months of 2002. The lower
volumes mainly reflected extended maintenance shutdowns at the Triton FPSO and
Scott platform in the U.K. North Sea.  In 2003, Petro-Canada expanded its position in
the U.K. North Sea through the exchange and acquisition of property interests.
The property acquisitions are in and around the Triton FPSO and include
increased interests in the Guillemot West and Northwest producing fields and a
100 per cent working interest in block 21/23b. This block contains the
undeveloped Pict oil discovery (previously named Grebe), which is similar in
size to our Clapham field (Petro-Canada  100 per cent working interest).
Development of Clapham in 2003 included the tie-back of two production and two
injector wells and subsea facilities to the Triton FPSO via the Guillemot West
subsea infrastructure. Field production came on stream in November and
reached a planned peak of 15 000 b/d prior to year-end.  In the Netherlands sector, development of a
prior year natural gas discovery on Block L5b (Petro-Canada  30 per cent
working interest) was completed ahead of schedule, with first gas on stream in
October. At year-end, Petro-Canadas share of production had reached a peak of 18 mmcf/d. In a strategic realignment of our Netherlands
holdings during 2003 we divested non-core acreage and acquired additional
exploration assets, licences F6 and L6a, concentric to our remaining holdings
and infrastructure.  North Africa/Near East  Our interests in this core region, particularly in Syria and Libya,
provide a significant base of production as well as considerable re-development
potential. In 2003, Petro-Canadas North Africa/Near East production of crude
oil and natural gas liquids averaged 143 100 b/d and 32 mmcf/d for natural gas,
compared with averages of 145 400 b/d and 44 mmcf/d, respectively, over the
last eight months of 2002. The lower volumes reflected a production decline in
Syria with some offset from increased volumes from Libya, including new
production from the En Naga block which came on stream in February 2003.  In mid-2003, Petro-Canada, together with Syria
Shell Petroleum Development B.V., finalized an agreement with the Syrian
government that extends rights to deep and lateral reserves on existing
acreage. The agreement supplements the three existing Production Sharing
Contracts under which the companies operate, through the Al Furat Petroleum
Company joint venture. The new agreement is of particular significance as
production from this area will partially offset the production declines we are
seeing from existing fields.  13 
   Furthering our plans for a balanced International exploration program
for longer-term growth, we have expanded our portfolio of operated exploration
assets in Tunisia, Syria and Algeria. In Tunisia, subject to final government
approval, we have farmed in to the 845 000-acre (3 420-square-kilometre)
Melitta Exploration Permit, located mainly offshore in the Mediterranean Sea.
In northeast Syria, we were awarded the 1 680 000-acre (6 800-square-kilometre)
exploration Block II. In Algeria, subject to final government approval, we have
been awarded the 691 000-acre (2 800-square-kilometre)
Zotti 431b block, located in the Amguid Messaoud basin.  Northern Latin America  In Trinidad, Petro-Canadas 17 per cent working interest share of
production from the North Coast Marine Area-1 offshore gas project averaged 63 mmcf/d before royalties, up from 32 mmcf/d for the period
from start-up to the end of 2002. Natural gas is delivered to the Atlantic LNG
facility at Point Fortin for liquefaction and sale into United States markets.
During the second half of 2003, operating results exceeded expectations
following start-up of the new Train 3. Contributing factors included better
than expected productivity and performance from wells and the Hibiscus
production platform, and the LNG facility, which consistently exceeded design
capacity. In 2003, a successful exploration well drilled from the Hibiscus
platform in 2003 was completed as a production well, providing additional gas
volumes to the project.  Late in 2003, discussions concerning the
potential acquisition of the Cerro Negro heavy oil assets in Venezuela were
terminated, as pre-emptive rights held by other joint owners could not be
resolved.  Were targeting new International opportunities to add profitable
long-term growth.  OUTLOOK  2004
production expectations: Northwest
Europe oil and gas production to average 54 000 boe/d. North
Africa/Near East oil and gas production to average 133 000 boe/d. Northern
Latin America natural gas production to average 60 mmcf/d.  Growth plans: Development
of De Ruyter and Pict in the North Sea. Exploration
in Syria, Tunisia and Algeria. Identify
and develop growth opportunities in new areas.  2004 capital
spending plans: $240 million on existing assets. $400 million
for new developments and exploration.  Planned expenditures on existing assets in 2004 will focus primarily on
Syria, Libya and the U.K. New development investments will include Pict in the
U.K. and De Ruyter in the Netherlands. In Venezuela, an extended production
test will be undertaken to evaluate the commercial viability of the La Ceiba
crude oil discovery (Petro-Canada  50 per cent working interest). Exploration
and new venture plans anticipate work on Block II in Syria, Melitta in Tunisia,
Zotti in Algeria and concentric exploration associated with existing ventures.  14 
   RESERVES  Reserves Inventory  Our large reserves inventory provides a strong base for future growth.    Proved
reserves (millions of barrels of oil equivalent)  At year-end 2003, proved reserves before royalties (including synthetic
crude oil from oil sands mining) totalled 1 220 million barrels of oil
equivalent (mmboe), down five per cent from a year earlier. As part of our
long-term reserves replacement strategy, we have added exploration capability
and funding  especially internationally  to develop a balanced exploration
program aimed at increasing our reserves base over time. In particular, we will
target long-life reserves and aim for greater Petro-Canada operatorship. Our
goal is a growth portfolio that provides a balanced range of risk/reward
opportunities. The new exploration acreage recently acquired in Syria, Tunisia
and Algeria are early examples of initiatives in the
International business. In Canada, Petro-Canada continues to pursue
opportunities off the East Coast and North of 60 while in Western Canada, we plan to gradually increase our exploration
program over time to improve reserves replacement.  In order to harmonize its oil and gas
disclosure in both Canada and the U.S., Petro-Canada applied for, and received,
certain exemptions to reserves disclosure requirements as set out in National
Instrument 51-101; Standards of Disclosure for Oil and Gas Activities(NI
51-101), which was adopted in 2003 by the securities regulatory authorities in
Canada. These exemptions permit Petro-Canada to use its own staff of qualified
reserves evaluators to prepare the Companys reserves estimates and to use U.S.
Securities Exchange Commission (SEC) and Financial Accounting Standards Board
(FASB) standards when reporting reserves.  Petro-Canada strongly believes that its use of
its own staff of qualified reserves evaluators who are familiar with the
Companys oil and gas assets as a result of working with them on a day-to-day
basis, combined with independent third party evaluation/audit of both its reserves
processes and its reserves estimates, provides a level of confidence in its
reserves data that is at least as good as would be provided if the work was
done solely by a third party.  Petro-Canadas staff of
qualified reserves evaluators determine the Companys reserves data and
reserves quantities based on corporate-wide policies, procedures and practices.
These reserves policies, procedures and practices conform with
the requirements of Canadian as well as SEC regulations and the Association of
Professional Engineers, Geologists and Geophysicists of Alberta Standard of
Practice for the Evaluation of Oil and Gas Reserves for Public Disclosure. To
confirm the quality of the reserves policies, procedures and practices and the
internally-generated reserves estimates, Petro-Canada employs the services of
independent engineering evaluators/auditors. During 2003, independent petroleum
reservoir engineering consultants Sproule Associates Limited (Sproule) and
Gaffney, Cline & Associates Ltd. (GCA) conducted evaluations, technical
audits and reviews of Petro-Canadas hydrocarbon reserves. GCA completed an
independent audit of 70 per cent of the Companys proved crude oil, natural gas
and natural gas liquids reserves outside of Canada. Similarly, Sproule audited
Petro-Canadas proved oil and gas reserves estimates for Hibernia and Terra
Nova, evaluated 54 per cent of Western Canada proved conventional oil and gas
reserves and reviewed the balance of Western Canada, White Rose and Syncrude.
The independent auditors/evaluators reports concluded that the Companys
year-end 2003 proved reserves estimates are reasonable.  Sproule and GCA also audited Petro-Canadas
reserves policies, procedures and practices and concluded that Petro-Canadas
reserve booking standards meet applicable disclosure regulations,
that management is complying with those standards and the reserves
process is performed in a manner and standard consistent with the auditors
practices. In addition, PricewaterhouseCoopers LLP, as contract internal
auditor, tested the non-engineering management control processes used in
establishing reserves.  Detailed information about Petro-Canadas
reserves of crude oil, natural gas liquids, natural gas, bitumen and synthetic
crude oil is available on pages 60-63 of this Annual Report.  Petro-Canada reserves processes and estimates are audited by independent
consultants.  15 
   DOWNSTREAM  Downstream Operating,
Marketing and General Costs  Per-litre costs reflected increased costs for the planned closure of the
Oakville refinery and the incident at the Lubricants plant.    Unit
operating, marketing 
and general costs(cents per litre)  Our Downstream operations include
three refineries with a total rated capacity of 49 800 cubic metres (313 000
barrels) per day, and a lubricants plant that is the largest producer of
lubricant base stocks in Canada and the largest producer of white oils in the
world. In 2003, Petro-Canada accounted for about 17 per cent of the Canadian
industrys total refining capacity and our product sales represented about 17
per cent of total petroleum products sold in Canada.  Downstream Financial Results  (millions of dollars)
  
  2003
  
  2002
  
  2001Earnings from operations
  
  $
  264
  
  $
  254
  
  $
  300(Loss) gain on sale of assets
  
  (15
  )
  3
  
  1Net earnings
  
  $
  249
  
  $
  257
  
  $
  301Cash flow
  
  $
  601
  
  $
  380
  
  $
  589Expenditures on property, plant
  and equipment
  
  $
  424
  
  $
  344
  
  $
  383Total assets
  
  $
  3 838
  
  $
  3 841
  
  $
  3 556  2003 COMPARED WITH 2002  Downstream financial performance
in 2003 reflected improved revenues from higher cracking margins, lower income
taxes, and a one-time charge for a refinery closure.  The lower income taxes reflect a $34 million net positive adjustment resulting
primarily from changes in income tax rates. The one-time charge for the
refinery closure, amounting to $151 million after tax, relates to the planned
closure of Petro-Canadas Oakville refinery. Net earnings of $249 million in
2003 are after deduction of a $15 million loss on asset sales mainly related to
the selective rationalization of marketing networks in Eastern Canada. The
increase in cash flow reflects the higher earnings before the non-cash charge
for Oakville and lower current taxes resulting from the inventory accounting
method required for income tax purposes. This method resulted in a $25 million
decrease in current taxes in 2003, compared with an $85 million increase in
2002.  Strong performance in Refining and Supply
mainly resulted from higher refinery crack spreads and wider light/heavy crude
oil price differentials, which more than offset the effects of a one per cent
decline in overall crude capacity utilization at our three refineries. Total
crude oil processed in 2003 averaged 49 900m3/d, down from 50 400 m3/d
in 2002. The decline reflected unplanned shutdowns and the impact on the
Oakville refinery of a major power outage in Ontario in August.  Sales and Marketing results also improved, as
sales of refined products, boosted by strong wholesale distillate sales,
increased to a record 56 800 cubic metres per day (m3/d) from 55 700
m3/d in 2002. Additionally, the contribution from non-petroleum
product sales continued to demonstrate strong growth with convenience store
sales rising 16 per cent from the previous year. The strong performance was
achieved despite a challenging business environment for much of the year,
including concerns over SARS, which reduced travel in important urban markets,
the power outage in Ontario and problems in the beef and lumber industries that
affected distillate sales. Additionally, high crude prices continued to place
considerable pressure on product margins. Total Downstream operating, marketing
and general unit costs, at 6.3 cents per litre, were up from 5.8 cents per
litre in 2002. The increase mainly reflected the de-commissioning and
employee-related costs associated with the planned closure of the Oakville
refinery, and a partial shutdown of the Lubricants plant following the
August power outage.  In September 2003, Petro-Canada announced the planned closure of
the Oakville refinery.  STRATEGY  Our Downstream
strategies are focused on strengthening the foundations for improved
profitability through effective capital investment and discipline over controllable
factors. Our goal is superior returns and growth, including a minimum 12 per
cent return on capital employed, based on a mid-cycle
business environment. Key features of our strategy include:  Achieving
and maintaining first-quartile operating performance. Advancing Petro-Canada as the brand of choice for
Canadian gasoline consumers. Building on our marketplace strengths and
increasing sales of high-margin specialty lubricants.  16 
   Executing the strategy  Refinery Utilization  Lower refinery utilization was due to unplanned shutdowns.    Crude
capacity utilization (per cent)  Our
rated refinery crude capacity was increased in 2001 following process
improvements.  In 2003, Petro-Canada advanced two key strategic initiatives that will
position Refining and Supply operations for long-term profitability.  In the third quarter of 2003, plans were
finalized for the consolidation of our Eastern Canada refining operations at
the Montreal refinery. These plans include shutting down the Oakville refinery
by the end of 2004 and expanding the existing Oakville terminal facilities and
the Montreal refinery. The changes will enable the transition from a
refining-focused operation to a supply and logistics centered function where
best-in-class performance is achievable. We will complete the project in time
to meet compliance with federal legislation lowering limits for sulphur in
gasoline, effective January 1, 2005.  The second key initiative is a new plan for
upgrading and refining oil sands feedstock at our Edmonton refinery. Details
are outlined in the Oil Sands section of this MD&A.  Plant reliability, a critical component of
success in the refining business, fell below our target in 2003, due to unplanned
shutdowns at our refineries and Lubricants plant. Going forward, we will
intensify our efforts to optimize operations and maintenance procedures to
achieve first quartile performance based on Solomon & Associates
benchmarking. As part of our efforts to reduce costs and greenhouse gas
emissions, we remain committed to reduce energy consumption by an average of
one per cent per year through 2005.  Downstream capital expenditures on property,
plant and equipment were $424 million in 2003, marginally below plan as reduced
spending on the Oakville refinery was essentially offset by acquisitions in the
home heating business. A major portion of 2003 spending was directed at meeting
the federal regulatory requirement of 30 parts per million of sulphur in gasoline
by 2005.  The new gasoline
desulphurization unit at the Montreal refinery was completed and successfully
commissioned in the fourth quarter of 2003. Construction of the Edmonton
gasoline desulphurization unit is ongoing and it will be operational ahead of
the legislated date.  In Sales and Marketing, we continued to take
steps to grow the profitability of our retail network by focusing on two key
areas. The first involved leveraging all aspects of the Petro-Canada brand and
product service to be the brand of choice for Canadians. In 2003, this resulted
in:  16
per cent overall growth in convenience store sales (including nine per cent
growth in same store sales) 10
per cent growth in the number of Petro-Points loyalty program members; and the growing success of our first-in-the-industry prepaid card program,
particularly in the business to business segment.  Product Sales  Total Downstream sales per retail site continued to grow in 2003.  Secondly, we focused on achieving appropriate Petro-Canada representation
to generate high site throughputs and profitable share of market. In 2003, this
resulted in the sale of Petro-Canadas Newfoundland and Labrador retail network
and the selective rationalization of our Eastern Canada retail network. The
impact of reduced product sales resulting from these divestitures was offset by
growth initiatives such as the continued roll-out of Petro-Canadas successful
new-image service stations. At year-end, the program of converting all
Company-controlled sites that meet our economic return criteria was about 80
per cent complete. Significant progress was also made in the number of
independent retailers participating in the new-image program. About 40 per cent
of our retail sites are independent and, at year-end, over 30 per cent of these
retailers were operating with the new-image standard. This program has been
instrumental in driving incremental increases in throughputs and profitability.
In 2003, total throughput from our retail network of 1 432 sites averaged 4.2
million litres per site, compared with 4.1 million litres in the previous year.
Average annual throughputs from re-imaged sites averaged in excess of seven
million litres, representing a significant competitive advantage.    Retail
throughput per site(millions of litres per year)  Petroleum
product sales(thousands of cubic metres per day)  In the Wholesale business, the focus has been
on growing profitability in high-value channels. Examples include acquisitions
in the home heat business in Ontario and the launch of a new innovative product
in Eastern Canada called ThermaClean®, a higher-value proprietary furnace fuel
that helps lessen the impact of home heating on the environment while helping
prolong furnace life. In the commercial road transport business, Petro-Canada
is maintaining its best-in-class position. With our Petro-Pass network of 210
truck stop facilities and our premiere fleet management card, Petro-Canada is
the market leader in serving Canadas commercial road transport industry. In
2003, we focused on enhancing our leadership position by further upgrading our
network and increasing volume through sales efforts in this high-value channel.  In Lubricants, financial performance in 2003
was impacted by a difficult business environment, including softness in some
key export markets, particularly the United States where a weak economy
dampened sales. Other factors included high natural gas prices and the regional
power outage in August.  17 
   While Lubricants sales in 2003 were unchanged from the 768 million
litres achieved in 2002, the high-margin product component rose five per cent,
reflecting strong growth in automotive sales, drilling industry sales and
higher-value base oils. At year-end, high-margin sales accounted for over 65
per cent of total lubricants sold. About two-thirds of our manufactured
lubricants, specialty fluids and greases are currently sold outside of Canada.
We continue to target accelerated growth in international markets to take
advantage of increasing global demand for higher-quality base oils. An
improving high-margin sales mix, cost-reduction initiatives in the areas of
energy and distribution, and delivery on plans to achieve efficient and
reliable plant operations will position Lubricants for continued profitable
growth.  In 2004 we will focus on improving plant reliability.  OUTLOOK  Growth plans: Improve plant reliability. Implement key strategic initiatives in
Refining and Supply. Secure further reductions in operating
costs. Maximize
benefits from retail site re-imaging program. Capitalize
on the increasing demand for higher quality base oils.  2004 capital spending plans: $705
million for Refining and Supply. $150
million for Sales and Marketing. $10 million for Lubricants.  While a substantial portion of our planned Downstream
investments in 2004 will be directed towards lessening the environmental impact
of our operations and products, we remain focused on positioning Petro-Canada
for improved profitability. Estimated capital expenditures for Refining and
Supply include about $445 million for refinery reconfigurations to meet new
lower limits for sulphur in gasoline and diesel at our Edmonton and Montreal
locations; about $135 million to consolidate our Eastern Canada refinery
operations at Montreal, including the conversion of our Oakville facility; and
$50 million for engineering, site preparation and other costs associated with
the new feedstock conversion plans for the Edmonton refinery. Sales and Marketing
expenditures include $100 million for retail growth initiatives, including the
continued roll-out of the new-image service station program, and $30 million
for wholesale growth initiatives to further develop our Petro-Pass network.  SHARED SERVICES  Shared Services include investment income, interest expense, foreign
currency translation and general corporate revenue and expenses.  Shared Services Financial Results  (millions of dollars)
  
  2003
  
  2002
  
  2001Net expenses from operations
  
  $
  (182
  )
  $
  (144
  )
  $
  (51
  )Foreign currency translation
  
  239
  
  (52
  )
  (96
  )Gain on sale of assets
  
  1
  
  
  
  Net earnings (expense)
  
  $
  58
  
  $
  (196
  )
  $
  (147
  )Cash flow
  
  $
  (100
  )
  $
  (104
  )
  $
  (53
  )  2003 COMPARED WITH 2002  The rise in net expenses from operations in 2003 primarily reflects
higher income taxes including increases resulting from changes in federal and
provincial income tax rates. The 2003 foreign currency translation gain on U.S.
dollar-denominated long-term debt reflects the significant improvement in the
strength of the Canadian dollar versus the U.S. dollar. The foreign currency
translation loss of $52 million in 2002 includes a one-time $63 million
exchange loss from the translation of the International business segment and an
$11 million gain on translation of U.S.-dollar-denominated debt.  18 
   LIQUIDITY AND CAPITAL RESOURCES  Summary of Cash Flows  (millions of dollars)
  
  2003
  
  2002
  
  2001Net cash inflows (outflows)
  before changes in non-cash working capital:Cash flow
  
  $
  3 372
  
  $
  2 276
  
  $
  1 688Investing activities
  
  (2 297
  )
  (4 141
  )
  (1 564
  )Financing activities
  
  (604
  )
  1 560
  
  (909
  )471
  
  (305
  )
  (785
  )(Increase) decrease in
  non-cash working capital and other
  
  (70
  )
  (242
  )
  151Increase (decrease) in cash
  and cash equivalents
  
  $
  401
  
  $
  (547
  )
  $
  (634
  )Cash and cash equivalents at
  end of year
  
  $
  635
  
  $
  234
  
  $
  781  Petro-Canada has the financial strength and flexibility to pursue new
opportunities.  OPERATING ACTIVITIES  The improvement in cash flow before changes in non-cash working capital
to $3 372 million in 2003 resulted primarily from higher commodity prices,
production gains and improved refinery crack spreads, partially offset by an
increase in current income taxes. The reduced cash outflow on investing
activities reflects the acquisition of oil and gas assets from Veba Oil &
Gas GmbH in 2002. The net cash outflow on financing activities in 2003 results
primarily from the repayment of a substantial portion of the credit facility
set up to finance the Veba acquisition.  The $70 million increase in non-cash operating
working capital reflects decreases in accounts payable and accrued liabilities
and the current portion of long-term liabilities partially offset by a decrease
in accounts receivable and an increase in income taxes payable.  INVESTING ACTIVITIES  Capital and Exploration Expenditures  (millions of dollars)
  
  2003
  
  2002
  
  2001Upstream(1)North American Gas
  
  $
  560
  
  $
  530
  
  $
  548East Coast Oil
  
  344
  
  289
  
  279Oil Sands
  
  448
  
  462
  
  304International
  
  525
  
  221
  
  1531 877
  
  1 502
  
  1 284DownstreamRefining and Supply
  
  296
  
  210
  
  206Sales and Marketing
  
  117
  
  118
  
  156Lubricants
  
  11
  
  16
  
  21424
  
  344
  
  383Shared Services
  
  14
  
  15
  
  14Total property, plant and
  equipment and exploration
  
  2 315
  
  1 861
  
  1 681Deferred charges and other
  assets
  
  147
  
  72
  
  10Acquisition of oil and gas
  operations of Veba Oil & Gas GmbH
  
  
  
  2 234
  
  Total
  
  $
  2 462
  
  $
  4 167
  
  $
  1 691  
 (1)Includes exploration expenses
charged to earnings, totalling $271 million in 2003, $301 million in 2002 and
$245 million in 2001.  19 
   Petro-Canadas substantial capital spending on property, plant and
equipment and exploration in 2003 reflects our commitment to long-term
profitable growth and added value for shareholders. The 24 per cent increase in
expenditures to $2 315 million in 2003, primarily reflects an additional four
months of major international activity, the White Rose development and
increased spending in the Downstream to meet lower limits for sulphur in
gasoline. The increase in deferred charges and other assets includes higher
corporate expenditures resulting from the issuance and interest hedging costs
associated with the placement of U.S. dollar-denominated long-term debt.  Planned investments for 2004, totalling $2 645
million, reaffirm our growth commitment. Upstream expenditures are estimated at
$1 765 million, with $495 million allocated to North American Gas, $325 million
to East Coast Oil, $305 million to Oil Sands and $640 million to International.
Planned Downstream expenditures amount to $865
million, with $705 million for Refining and Supply, including a recent $50
million addition for anticipated spending on new feedstock conversion plans for
the Edmonton refinery, $150 million for Sales and Marketing and $10 million for
Lubricants. Additionally, $15 million is provided for corporate and other
purposes. We plan to fund the 2004 capital expenditure program from cash flow.  Capital investments are forecast to be $2 645 million in 2004.  FINANCING ACTIVITIES AND
DIVIDENDS  Sources of Capital Employed  (millions of dollars)
  
  2003
  
  2002
  
  2001Long-term debt, including
  current portion
  
  $
  2 229
  
  $
  3 057
  
  $
  1 401Shareholders equity
  
  7 721
  
  5 776
  
  4 877Total
  
  $
  9 950
  
  $
  8 833
  
  $
  6 278  The decrease in total debt to $2 229 million at December 31, 2003,
compared with $3 057 million the previous year-end, reflects $548 million of
net debt repayments and a $280 million reduction due to the revaluation of U.S.
dollar denominated long-term debt. During the year 2002, the Company borrowed
$2 100 million, by way of an acquisition credit facility, to finance the
funding of the purchase of the upstream assets of Veba Oil & Gas GmbH.
During 2002, the Company repaid $461 million from cash flow. During 2003, a
further $542 million was repaid from cash flow and $804 million was refinanced
by way of a long-term debt offering completed in June 2003.  In 2003, we repaid $548 million of debt.  Debt Offering  June 2003  Purpose of offering:
  
  To repay bank indebtedness incurred in the acquisition of oil and gas
  operations from Veba Oil & Gas GmbHSize of offering:
  
  US$600 millionForm of securities:
  
  US$300 million of 4.00% Notes and US$300 million of 5.35% NotesNet proceeds of issue:
  
  US$592 millionApplication of proceeds:
  
  Reduction of short-term, floating rate acquisition credit facility  20 
   Key Debt Ratios  With the repayment of $548 million of debt in 2003, the Company is well
positioned relative to its target levels.    Debt
to debt plus equity (per cent)  Debt
to cash flow(times)  The following table summarizes Petro-Canadas contractual obligations as
at December 31, 2003.  Contractual Obligations  Summary (millions
of dollars)  PAYMENTS DUE BY PERIODTotal
  
  2004
  
  2005-2006
  
  2007-2008
  
  2009 and
  thereafterUnsecured debentures and
  notes(1)
  
  $
  1 842
  
  $
  
  
  $
  
  
  $
  
  
  $
  1 842Acquisition credit facility(1)
  
  293
  
  
  
  293
  
  
  
  Capital lease obligations(1)
  
  94
  
  6
  
  15
  
  10
  
  63Operating leases
  
  687
  
  115
  
  168
  
  129
  
  275Transportation agreements
  
  1 357
  
  158
  
  302
  
  246
  
  651Product purchase/delivery
  obligations(2)
  
  1 216
  
  70
  
  150
  
  150
  
  846Exploration work commitments(3)
  
  71
  
  36
  
  27
  
  8
  
  Other long-term
  obligations(4),(5)
  
  102
  
  82
  
  4
  
  2
  
  14Total contractual obligations
  
  $
  5 662
  
  $
  467
  
  $
  959
  
  $
  545
  
  $
  3 691  
 (1)Obligations exclude related
interest. For further details see Note 16 to the 2003 Consolidated Financial
Statements. (2)Excludes supply purchase
agreements that are contracted at market prices where the products could
reasonably be resold into the market. (3)Excludes other amounts related
to the Companys expected future capital spending. Capital spending plans are
reviewed and revised annually to reflect the Companys strategy, operating
performance and economic conditions. For further information regarding future
capital spending plans refer to the business segment and investing activities
discussions in the previous sections of the 2003 MD&A. (4)Includes pension funding
obligations for the periods prior to the Companys next required pension plan
valuation. Obligations beyond the next required valuation date have been
excluded due to the uncertainty as to the amount or timing of these
obligations. (5)The Company is involved in
litigation and claims associated with normal operations. Management is of the
opinion that any resulting settlements would not materially affect the
financial position of the Company. The table excludes amounts for these contingencies
due to the uncertainty as to the amount or timing of any settlements.  Petro-Canada plans to meet remaining debt repayment commitments out of a
combination of cash flow and debt financing.  As a result of the substantial debt reduction
in 2003, our financial ratios have returned to pre-acquisition levels,
providing expanded financial capacity to fund continued growth and new
opportunities.  Interest Coverage  A positive interest coverage ratio demonstrates more than sufficient
earnings to cover interest charges on debt.    Interest
coverage ratio (times)  Calculated
on an EBITDAX basis.  Financial Ratios  2003
  
  2002
  
  2001Interest coverage (times):Earnings basis
  
  16.7
  
  10.5
  
  9.7EBITDAX basis
  
  26.3
  
  17.1
  
  15.1Cash flow basis
  
  25.4
  
  17.9
  
  15.6Debt to cash flow (times)
  
  0.7
  
  1.3
  
  0.8Debt to debt plus equity (per
  cent)
  
  22.4
  
  34.6
  
  22.3  Petro-Canadas debt to cash flow ratio, our key short-term leverage
measure, strengthened to 0.7 times at December 31, 2003, compared with 1.3
times at the end of 2002. We expect to remain well within our target range of
no more than 2.0 times through 2004. Debt to debt plus equity, our long-term
measure for capital structure, improved to 22.4 per cent from 34.6 per cent at
the prior year-end. Our target range is from 25 to 30 per cent. Petro-Canada
has controls in place to ensure compliance with all financial covenants.  For operating purposes, Petro-Canada had cash
and cash equivalents of $635 million and undrawn committed bank credit
facilities totalling $1 159 million at 2003 year-end. Petro-Canada will
continue to use its cash position and will draw on bank lines and issue
commercial paper if necessary to meet working capital and other financing
requirements.  The Companys unsecured long-term debt
securities are rated Baa2 by Moodys Investors Service, BBB by Standard &
Poors Rating Services and A (low) by Dominion Bond Rating Service. The
Companys long-term debt ratings remain unchanged from year-end 2002.  21 
   Excluding cash and cash equivalents and the current portion of long-term
debt, Petro-Canada had an operating working capital deficiency of $52 million
at the end of 2003 compared with operating working capital of $36 million as at
December 31, 2002.  Petro-Canada does not currently have any
off-balance sheet accounting in place to structure any of its financial
arrangements. Off-balance sheet activities are limited to matters such as
guarantees, none of which would have a material impact on the Companys
financial results, liquidity or capital resources.  At 2003 year-end, Petro-Canadas defined
benefits pension plans were under-funded by $292 million, compared with an
under-funded position of $279 million at the end of 2002. In 2003, Petro-Canada
made cash contributions of $86 million to the pension plans and recorded a
pension expense of $72 million before tax. This compares with $22 million and
$28 million, respectively, for 2002. In 2004, the Company expects to make a
contribution of approximately $86 million and record an expense of about $65
million.  Petro-Canada reviews its dividend strategy
from time to time to ensure the alignment of dividend policy with shareholder
expectations and our financial and growth objectives. Currently, our first
priority for available cash is to fund growth opportunities. Our second
priority is to return funds to shareholders. In 2003, when the quarterly
dividend was $0.10 per share, Petro-Canada paid $106 million in dividends,
compared with $105 million in 2002. The quarterly dividend payable on
April 1, 2004, to shareholders of record on March 3, 2004, has been
increased to $0.15 per share.  Petro-Canada announced a 50 per cent dividend increase in  January 2004.  RISK MANAGEMENT  Petro-Canadas results are impacted by managements strategy for
handling risks inherent in the underlying business, which fall into four broad
categories: business risks; operational risks; political risks; and market
risks.  Management believes each major risk requires a
unique response within our broad business strategy and Petro-Canadas financial
tolerance. While some risks can be effectively managed through internal
controls and business processes, others are managed through insurance. The
Audit, Finance and Risk Committee of the Board of Directors has
oversight responsibility for risk management. The following describes
Petro-Canadas approach to managing major risks.  BUSINESS RISKS  Exploration  Petro-Canadas future cash flows are highly dependent on our ability to
replace natural decline as reserves are produced. Reserves can be added through
successful exploration or acquisition. However, as basins mature, replacement
of reserves becomes more challenging and expensive, and we may choose to allow
reserves to decline in some areas if replacement is uneconomic. Petro-Canada
maintains an extensive exploration program in Canada and internationally. To
support this program, we have entered into a variety of alliances with
world-class suppliers. These alliances provide preferential access to
equipment, labour and advanced technology at competitive prices. There is no
assurance that we will successfully replace all reserves in any given year.  Reserve Estimates  Estimates of economically recoverable oil and gas reserves are based
upon a number of variables and assumptions such as geoscientific
interpretation, commodity prices, operating and capital costs, and production
forecasts, all of which may vary considerably from actual results.  22 
   Project Execution  Petro-Canada manages a variety of
small and large projects in support of continuing operations and future growth.
Many project risks, such as those involving material costs, labour productivity,
timely availability of skilled labour, and currency fluctuations are influenced
by external factors beyond our control. Petro-Canada is enhancing its project
management capability. We have built on our experience in major project
development to establish effective standardized processes, backed by
well-trained people, to manage projects across the organization. The goal is to
consistently and predictably deliver projects on time, on budget, and achieve
defined expectations, thereby improving all elements of project execution
including safety and environmental performance, quality, cycle time and cost.  Third Party Operator  Other companies may manage construction or operation of assets in which
Petro-Canada has an interest. The Company has limited ability to exercise
influence over operations of these assets or their associated costs, which
could adversely affect financial performance.  Environmental Regulations  Environmental risks inherent in the oil and gas industry are
increasingly significant as related laws and regulations become more stringent
in Canada and other countries where Petro-Canada operates. Increased
regulations may require the Company to invest additional capital to satisfy new
product specifications or address environmental issues, increase operating
costs by reducing the yield of desirable products, or create a future liability
for dismantling and remediating production facilities.  Petro-Canada conducts Life-Cycle Value
Assessment (LCVA) to integrate and balance environmental, social and economic
decisions related to major projects. A key component of the LCVA process is to
include in front-end planning all life-cycle stages involved in constructing,
manufacturing, distribution and eventually abandoning an asset or a product.
This process encourages more comprehensive exploration for alternatives.
Although LCVA is a useful technique, it relies on the current regulatory regime
or one that can be reasonably expected.  Government Regulations  The Company is subject to regulation and intervention by governments in
such matters as contracting of exploration and production interests, imposition
of specific drilling obligations, and possibly expropriation or cancellation of
contract rights. As well, governments may regulate or intervene with respect to
price, taxes, royalties and exploration. The Company has limited ability to
influence these regulations and they may have a material adverse effect on the
Company.  Counter-parties  In the normal course of business, Petro-Canada is exposed to credit risk
resulting from the uncertainty of a counter-partys ability to fulfill an
obligation in accordance with the terms and conditions of a contract. To
minimize credit exposure, we have established internal credit policies and
procedures that include financial assessments, exposure limits and processes to
monitor the exposures against these limits. Where appropriate, we use netting
and collateral arrangements to minimize risk.  Petro-Canada only transacts derivatives with
counter-parties who possess a minimum long-term credit rating of A (unless
otherwise approved by the Board) under a signed International Swap Dealers
Association agreement. Credit limits take into account both current and
potential exposure to a counter-party and limit concentration of risk.  23 
   OPERATIONAL RISKS  Production, refining, transporting and marketing oil and gas involve
significant operational hazards. We manage operational risks primarily through
our integrated Total Loss Management (TLM) system and a Corporate Insurance
Program. TLM is an internally developed management system with standards for
preventing operational incidents. A program of regular TLM audits tests
compliance to the standards. The Corporate Insurance Program transfers some
operational risks to third party insurers worldwide. Limits of insurance are
based on financial quantification of a maximum foreseeable exposure related
to major assets. Petro-Canada optimizes the program by evaluating deductibles,
limits and coverage. The Companys financial tolerance to withstand the impact
of a major isolated event may be utilized to manage total premium cost.
Although Petro-Canada maintains insurance in accordance with customary industry
practices, we cannot fully insure against all risks. Losses resulting from
operational incidents could have a material adverse impact on the Company.  POLITICAL RISKS  Internationally, Petro-Canada operates in numerous countries with
differing political, economic and social systems. Our operations and related
assets are subject to the risks of actions by governmental authorities,
insurgent groups or terrorists. Additionally, Petro-Canada operates in
OPEC-member countries and production in those countries may be constrained from
time to time by OPEC quotas. We evaluate our exposure in any one country in the
context of the Companys total operations, may limit investment to avoid
excessive exposure in any one country or region and may choose not to invest in
a country based on our assessment of risk.  MARKET RISKS  Commodity Prices  A significant market risk exposure for Petro-Canada is the commodity
price of crude oil, refined products and natural gas. International commodity
prices are volatile and are influenced by factors such as supply and demand
fundamentals, geo-political events, OPEC decisions and weather. Refining
margins are affected by North American supply and demand fundamentals and crude
oil prices. These risks may be positive in a higher-price environment and
negative in a lower-price environment.  Petro-Canada is generally averse to hedging
large volumes of production. Management believes commodity prices go through
price swings that are difficult to predict. We manage the business so that the
Company can withstand the impact of a lower price environment, and is also
fully exposed to capturing significant upside when the price environment is
higher. However, commodity prices and margins may be hedged occasionally to
capture opportunities that represent extraordinary value. Certain Downstream
physical transactions are routinely hedged for operational needs and to
facilitate sales to customers.  Foreign Exchange  As energy commodity prices are primarily priced in U.S. dollars, a large
portion of Petro-Canadas expense and revenue stream is affected by the U.S.
dollar/Canadian dollar exchange rate. Although there is a significant natural
offset to this exposure as a result of our integrated business, on a net basis
Petro-Canadas earnings are negatively affected by a strengthening Canadian
dollar. We do not hedge this exposure, but it is partially mitigated by issuing
U.S. dollar-denominated long-term debt. Foreign exchange exposure related to
asset acquisitions or divestitures, or project capital expenditures, may be
hedged on a case-by-case basis. Petro-Canada is also exposed to fluctuations in
other foreign currencies such as the euro and British pound.  Interest Rates  Petro-Canada targets a blend of fixed and floating rate debt that
enables the Company to take advantage of generally lower interest rates on
floating debt while generally matching overall debt maturity with the life of
cash generating assets. The Company is exposed to fluctuations in the rate of
interest it pays on floating rate debt. Managements perspective is that this
interest rate exposure is consistent with industry practice and it is within
the Companys risk tolerance.  24 
   FINANCIAL INSTRUMENTS  Petro-Canadas market risk and derivative policy prohibits the use of
derivative instruments for speculative purposes. Petro-Canada uses derivatives
primarily to hedge physical transactions for operational needs and to
facilitate sales to customers. The gains and losses associated with these
financial instruments essentially offset gains and losses on the physical
transactions. Except as specifically authorized by the Board of Directors, the
term of hedging instruments cannot exceed 18 months. Monitoring and reporting
of the derivatives portfolio includes periodic testing of the fair value of all
outstanding derivatives. Fair values are determined by obtaining independent
third party quotes for the value of each derivative instrument. The objectives
and strategies of all hedge transactions are documented, as well as an assessment
of the effectiveness of the derivative instrument in offsetting a change in the
value of the hedged exposure.  In 2003, commodity, currency and interest rate
hedges resulted in a net decrease in earnings of about $30 million after tax,
compared with a net decrease in earnings of about $22 million in 2002. As at
December 31, 2003, crude oil and natural gas contracts had been bought
forward to mitigate exposure on fixed-price natural gas and refined product
sales. Short-term hedge positions were also in place for refining supply and
product purchases. At year end, these instruments had a fair value of $9
million. In accordance with our derivative accounting policy, this value has
been deferred and will be recognized in the period in which the derivative instrument
is realized.  CRITICAL ACCOUNTING ESTIMATES  The preparation of the Companys financial statements requires
management to adopt accounting policies that involve the use of significant
estimates and assumptions. These estimates and assumptions are developed based
on the best available information and are believed by management to be
reasonable under the existing circumstances. New events or additional
information may result in the revision of these estimates over time. The Audit,
Finance and Risk Committee regularly reviews the Companys critical accounting
policies and any significant changes thereto. A summary of the significant
accounting policies used by Petro-Canada can be found in Note 1 to the 2003
Consolidated Financial Statements. The following discussion outlines what
management believes to be the most critical accounting policies involving the
use of significant estimates or assumptions.  PROPERTY, PLANT AND
EQUIPMENT/DEPRECIATION, DEPLETION AND AMORTIZATION  Investments in exploration and development activities are accounted for
under the successful efforts method. Under this method, the acquisition costs
of unproved acreage, the costs of exploratory wells pending determination of
proved reserves, the costs of wells which are assigned proved reserves, and
development costs including costs of all wells are capitalized. The cost of
unsuccessful wells and all other exploration costs, including geological and
geophysical costs, are charged to earnings as incurred. Capitalized costs of
oil and gas producing properties are depreciated and depleted using the unit of
production method based upon estimated reserves (see Estimated Oil and Gas
Reserves discussion below). Reserve estimates can have a significant impact on
net earnings, as they are a key component in the calculation of depreciation
and depletion related to the capitalized costs of property, plant and
equipment. A revision in reserve estimates could result in either
a higher or lower depreciation and depletion charge to net earnings. A downward
revision in reserves could result in a writedown of oil and gas producing
properties as part of the impairment assessment (see Asset Impairment
discussion below).  FUTURE REMOVAL AND SITE
RESTORATION COSTS  The Company currently provides for estimated future removal and site
restoration costs which are probable and can be reasonably determined on either
the unit of production method or the straight line method based on estimated
service lives of the related assets as appropriate. Future removal and site
restorations costs for inactive Downstream sites, net
of expected recoveries, are provided for at the time a decision is made to
decommission the site. Factors that can affect the provision include the
expected costs and the estimated reserves (see Estimated Oil and Gas Reserves
discussion below). Cost estimates  25 
   are influenced by factors such as the number and type of sites subject to
removal and restoration, the extent of site restoration work required and
changes in environmental legislation. A revision to the estimated costs or
reserves could result in an increase or decrease in future removal and site
restoration costs charged to net earnings.  ASSET IMPAIRMENT  Producing properties and significant unproved properties are assessed annually, or as economic events dictate, for potential
impairment. Impairment is assessed by comparing the estimated undiscounted
future cash flows to the carrying value of the asset. The cash flows used in
the impairment assessment require management to make assumptions and estimates
about recoverable reserves (see Estimated Oil and Gas Reserves discussion
below), future commodity prices and operating costs. Changes in any of the
assumptions, such as a downward revision in reserves, a decrease in future
commodity prices, or an increase in operating costs could result in an
impairment of an assets carrying value.  PURCHASE PRICE ALLOCATION  Business acquisitions are accounted for by the purchase method of
accounting. Under this method, the purchase price is allocated to the assets
acquired and the liabilities assumed based on the fair value at the time of the
acquisition. The excess purchase price over the fair value of identifiable
assets and liabilities acquired is goodwill. The determination of fair value
often requires management to make assumptions and estimates about future
events. The assumptions and estimates with respect to determining the fair
value of property, plant and equipment acquired generally require the most
judgement and include estimates of reserves acquired (see Estimated Oil and Gas
Reserves discussion below), future commodity prices, and discount rates.
Changes in any of the assumptions or estimates used in determining the fair
value of acquired assets and liabilities could impact the amounts assigned to
assets, liabilities, and goodwill in the purchase price allocation. Future net
earnings can be affected as a result of changes in future depreciation and
depletion, asset impairment or goodwill impairment.  GOODWILL IMPAIRMENT  Goodwill is subject to impairment tests annually, or as economic events
dictate, by comparing the fair value of the reporting unit to its carrying
value, including goodwill. If the fair value of the reporting unit is less than
its carrying value, a goodwill impairment loss is recognized as the excess of
the carrying value of the goodwill over the fair value of the goodwill. The
determination of fair value requires management to make assumptions and
estimates about recoverable reserves (see Estimated Oil and Gas Reserves
discussion below), future commodity prices, operating costs, production
profiles, and discount rates. Changes in any of these assumptions, such as a
downward revision in reserves, a decrease in future commodity prices, an
increase in operating costs or an increase in discount rates could result in an
impairment of all or a portion of the goodwill carrying value in future
periods.  ESTIMATED OIL AND GAS RESERVES  Reserves estimates, although not reported as part of the Companys
financial statements, can have a significant effect on net earnings as a result
of their impact on depreciation and depletion rates, future removal and site
restoration provisions, asset impairments, and goodwill impairment (see
discussion of these items above). The Companys staff of qualified reserves
evaluators performs internal evaluations on all of its oil and gas reserves on
an annual basis using corporate-wide policies, procedures and practices.
Independent petroleum reservoir engineering consultants also conduct annual
evaluations, technical audits and reviews of a significant portion of the
Companys reserves. In addition, the Companys contract internal auditor tests
the non-engineering management control processes used in establishing reserves.
However, the estimation of reserves is an inherently complex process requiring
significant judgment. Estimates of economically recoverable oil and gas
reserves are based upon a number of variables and assumptions such as
geoscientific interpretation, commodity prices, operating and capital costs and
production forecasts, all of which may vary considerably from actual results.
These estimates are expected to be revised upward or downward over time, as
additional information such as reservoir performance becomes available, or as
economic conditions change.  26 
   EMPLOYEE FUTURE BENEFITS  The Company maintains defined benefit pension plans and provides certain
post-retirement benefits to qualifying retirees. Obligations under employee
future benefits plans are recorded net of plan assets where applicable. The
cost of pension and other post-retirement benefits are actuarially determined
by an independent actuary using the projected benefit method prorated based on
service. The determination of these costs requires management to estimate or
make assumptions regarding the expected plan investment performance, salary
escalation, retirement ages of employees, expected
health care costs, employee turnover, discount rates, and return on plan
assets. Changes in these estimates or assumptions could result in an increase
or decrease to the accrued benefit obligation and the related costs for both
pensions and other post-retirement benefits.  INCOME TAXES  The Company follows the liability method of accounting for income taxes
whereby future income taxes are recognized based on the differences between the
carrying amounts of assets and liabilities reported in the financial statements
and their respective tax bases. The determination of the income tax provision
is an inherently complex process requiring management to interpret continually
changing regulations and to make certain judgments. While income tax filings
are subject to audits and reassessments, management believes adequate provision
has been made for all income tax obligations. However, changes in the
interpretations or judgments may result in an increase or decrease in the
Companys income tax provision in the future.  CONTINGENCIES  The Company is involved in litigation and claims associated with normal
operations. Management is of the opinion that any resulting settlements would
not materially affect the financial position of the Company as at
December 31, 2003. However, the determination of contingent liabilities
relating to the litigation and claims is a complex process that involves
judgments as to the outcomes and interpretation of laws and regulations.
Changes in the judgments or interpretations may result in an increase or
decrease in the Companys contingent liabilities in the future.  ACCOUNTING CHANGES  ACCOUNTING CHANGES IN THE
CURRENT YEAR  During 2003 the Company revised its accounting policies, as described
below, with respect to the translation of its International segment and the
expensing of stock options. For details, refer to Note 2 of the 2003
Consolidated Financial Statements.  Translation of International Segment  Effective January 1, 2003 Petro-Canada commenced operating its
International segment on a self-sustaining (financially and operationally
independent) basis. As a consequence, the Company prospectively changed its
accounting for the foreign currency translation of its International business
segment, whereby gains and losses arising from the translation of the
International financial statements and associated long-term debt into Canadian
dollars are now deferred and included as part of shareholders equity.
Previously, these gains and losses were included in earnings in the period of
translation. The effect of this change for the year ended December 31,
2003 was a decrease in net earnings of $70 million.  27 
   Stock Options  During the fourth quarter of 2003, the Company elected to begin
prospectively expensing, effective January 1, 2003, the value of stock
options pursuant to transitional accounting provisions. As a result, the fair
value of stock options granted during 2003 is being charged to earnings over
the vesting period with a corresponding increase in contributed surplus. The effect
of this change for the year ended December 31, 2003 was a decrease in net
earnings of $9 million. For stock options granted in 2002, the Company elected
to continue accounting for these options based on the intrinsic value at the
grant date and to disclose the pro forma results as if the fair value method
has been used. Pro forma information is provided in Note 18 to the 2003
Consolidated Financial Statements.  FUTURE ACCOUNTING CHANGES  As a result of recent accounting pronouncements issued by the Canadian
Institute of Chartered Accountants the following changes, to be implemented
effective January 1, 2004, will affect the Companys reported results.  Asset Retirement Obligations  Beginning in 2004, asset retirement obligations will be recorded
pursuant to new accounting rules. Currently, asset retirement obligations are
accrued on an undiscounted unit of production or straight-line basis over the
life of the asset. The new accounting standard requires companies to record the
fair value of legal obligations associated with the retirement of tangible
long-lived assets. The obligations are recorded as liabilities on a discounted
basis when incurred and amounts recorded for the related assets are increased
by the amount of these liabilities. Over time the liabilities are accreted for
the change in their present value and the initial capitalized costs are
depreciated over the useful lives of the related assets. The new rules are to
be applied retroactively and the impact on the 2004 opening balance sheet is an
increase in property, plant and equipment of $184 million, an increase in
deferred credits and other liabilities of $391 million, a decrease in future
income taxes of $74 million, and a decrease in retained earnings of $133
million. Had the new standard been in effect for 2003, the effect would have
been a decrease in net earnings of $9 million.  Classification of Expenses  Beginning in 2004 the Company will begin accounting for certain
transportation costs, certain third-party gas purchases and diluent purchases
as expenses in the consolidated statement of earnings. Currently, these costs
and purchases are netted against revenue. The change in accounting represents a
reclassification of revenue and expenses and will have no effect on net
earnings.  RELATED PARTY TRANSACTIONS  As disclosed in Note 21 to the 2003 Consolidated Financial Statements,
transactions with the Government of Canada (which holds approximately 19% of
the Companys issued shares at December 31, 2003), its agencies and other
related parties, are in the normal course of business and are therefore on the
same terms as those accorded other non-related parties.  SHARE DATA  The authorized share capital of Petro-Canada consists of an unlimited
number of Common Shares and an unlimited number of preferred shares issuable in
series designated as either Senior Preferred Shares or Junior Preferred Shares.
As at February 29, 2004 there were 269 934 188 common
shares outstanding and no preferred shares outstanding. For details of
the Companys share capital and stock options outstanding refer to Note 18 of
the 2003 Consolidated Financial Statements.  28 
   CORPORATE RESPONSIBILITY  Petro-Canada is deeply committed to responsible business practices. This
commitment extends to corporate governance practices, environment, health and
safety performance and involvement with the communities where employees live
and work. Management, internal reporting and external disclosure systems have
evolved to ensure that corporate responsibility is part of day-to-day
decision-making. To review Petro-Canadas performance in these areas in more
detail, a Report to the Community is published annually to enable the public to
assess performance and ongoing efforts in the environmental, social and
economic aspects of sustainable development.  Petro-Canada is committed to maintaining the highest standards of
corporate governance.  CORPORATE GOVERNANCE  Petro-Canada strives to maintain the highest standards of corporate
governance, with a focus on a strong and diligent Board of Directors and
transparency for shareholders. The Corporation has solid governance and
disclosure practices, a commitment to continuously improve those practices, and
an ethical corporate culture. Our Code of Business Conduct is required reading
for all employees, who must acknowledge their awareness and understanding of
the Code every two years.  The Board of Directors is responsible for the
oversight of the management of the Corporations business and affairs. The
Board has the statutory authority and obligation to protect and enhance the
Corporations assets and the interest of all shareholders. Members of the Board
of Directors, along with management and employees, believe that good corporate
governance contributes to the creation of shareholder value.  Petro-Canadas corporate governance practices
are aligned with the Toronto Stock Exchange guidelines, and Petro-Canada
already satisfies the proposals of several provincial securities regulators
published in Multilateral Instrument 58-101, even though they are not yet in
effect. As a foreign issuer on the NYSE, Petro-Canada is also subject to the
many new rules, regulations and guidelines established by the SEC, NYSE and
Sarbanes-Oxley legislation. Petro-Canada is in compliance,
and in some cases goes beyond these new corporate governance requirements.  More information about Petro-Canadas
corporate governance procedures  including Director independence,
compensation, Board committee mandates and the integrity of communication with
stakeholders  can be viewed on our Web site at www.petro-canada.ca.  Greenhouse Gas Emissions
versus Production(1)  In 2002, our total Canadian GHG emissions rose 9 per cent above 1990
levels, mainly due to the start-up of Terra Nova. Petro-Canada remains
committed to improving energy efficiency to mitigate the impact of growing
production levels on GHG emissions.    Total
Canadian Upstream and Downstream production (million cubic metres of oil
equivalent/year)  GHG
emissions (kilotonnes/year)  
 (1)2003 data is not yet available; data is based
on reporting 100 per cent from Petro-Canada operated properties.  ENVIRONMENT, HEALTH AND SAFETY  Petro-Canada executives are accountable for the effective execution of
our Companys Total Loss Management policy and standards which set our
environment, health and safety expectations. Petro-Canada conducts a major
audit of each business unit or area every four years to assess the
implementation of the policy and standards. Our Executive Leadership Team
reviews environment, health and safety performance monthly. As well, the
Environment, Health and Safety Committee of the Board of Directors reviews critical issues and EHS performance throughout the
year.  In 2003, we invested $414 million in environmental
programs, including $96 million for operating expenses and $318 million in
capital expenditures. Some of the expenditures include site remediation,
environmental assessments, and pollution prevention and control equipment. We
expect environmental costs to remain high as we prepare to meet federal limits
for sulphur in gasoline and distillate, future fuel reformulation requirements,
and tighter environmental standards for oil and gas production.  Climate change is one of the most complex
issues facing Canadian industry, the Canadian public, and governments today. At
Petro-Canada, we support a balanced and responsible approach that promotes
action on the issue of climate change. This approach includes the application
of best practices and development of technology to reduce greenhouse gas
emissions while protecting competitiveness, jobs and prosperity.  Petro-Canada has renewed its commitment to
improve energy efficiency in the Upstream and Downstream sectors by an average
of one per cent per year from 2000 to 2005. Key components of these
improvements include reductions in fuel consumption and the corresponding
lowering of greenhouse gas emissions and operating costs.  29 
   In 2002, Petro-Canadas total Canadian greenhouse gas emissions
increased 34 per cent from the previous years level, from 5 643 to 7 546
kilotonnes per year. This increase in greenhouse gas emissions corresponds to
the large increase in production generated mainly by our Terra Nova facility
located off the East Coast of Canada. The total Canadian greenhouse gas
emissions in 2002 were nine per cent above 1990 levels, despite the fact that
combined Upstream and Downstream production grew by 51 per cent over the same
period.  Since 1990, Petro-Canada has improved energy
efficiency in the Downstream by 21 per cent and in the Canadian Upstream by 24
per cent. By implementing energy efficiency and emissions reduction projects,
our voluntary initiatives have eliminated almost 1.3 million tonnes of annual
greenhouse gas emissions since 1990.  Data for 2003 will be provided in this years
Report to the Community.  The safety and well-being of our employees and
those working on our behalf is an absolute business priority for Petro-Canada.
Our overall Employee Recordable Injury Frequency (per 200 000 person hours)
decreased to 0.69 in 2003 from 0.94 in 2002. Recordable injuries decreased to
33 in 2003 from 44 in 2002. Our Contractor Recordable Injury Frequency (per 200
000 person hours) decreased to 2.32 in 2003 from 3.22 in 2002. Contractor
recordable injuries decreased to 120 in 2003 from 139 in 2002. Petro-Canada
believes that all workplace injuries and illnesses are preventable, and that a
Zero Harm workplace is possible and our goal. To achieve the goal of Zero
Harm, Petro-Canada continues to innovate in the field of health and safety.  COMMUNITY INVOLVEMENT  Petro-Canadas success as an energy company depends on the support we
receive from our stakeholders. We are determined to continually earn that
support, not just through excellence in meeting our customers energy needs,
but by playing an active and important role in the communities where we live
and operate.  In 2003, Petro-Canada invested approximately
$15 million in over 400 Canadian non-profit organizations in four sectors 
education, the environment, health and community services, and arts and
culture. This included two unique in-kind contributions: we donated a corporate
aircraft and avionics shop, valued at $1.6 million, to the Southern Alberta
Institute of Technology; and turned over the Petro-Canada Research Laboratory,
valued at $6.9 million, to the University of Calgary. We contributed $630 000
to support Canadas Olympic team, including scholarships, the Podium Fund and the
Coaching Excellence Awards. Through our Volunteer Energy Program, we provided
430 grants of $500 each to non-profit organizations supported by employees and
retirees who give their time to the community. The total amount of grants,
given out since 1992, surpassed the $1 million mark in 2003.    Additional information relating to Petro-Canada may be found on the
SEDAR Web site at www.sedar.com.  March 4, 2004  30