Exhibit 2  MANAGEMENTS DISCUSSION
& ANALYSIS  Managements Discussion and Analysis (MD&A) should be
read in conjunction with the Financial Statementsand Notes included in this
annual report. Graphs accompanying the text identify our value drivers, keymeasures of
performance in each component of our business.  RESULTS OF OPERATIONS  Summarized
Financial Results  Consolidated
Financial Results  (millions of dollars, unless
  otherwise indicated)
  
  2002
  
  2001(1)
  
  2000(1)Earnings
  from operations(2)
  
  $
  1 024
  
  $
  912
  
  $
  879Loss
  on foreign currency translation
  
  (52
  )
  (96
  )
  (53
  )Gain
  on disposal of assets
  
  2
  
  30
  
  71Reorganization
  costs
  
  
  
  
  
  (38
  )Net
  earnings
  
  $
  974
  
  $
  846
  
  $
  859Earnings
  per share(dollars)
  -
  basic
  
  $
  3.71
  
  $
  3.19
  
  $
  3.15- diluted
  
  3.67
  
  3.16
  
  3.13Cash
  flow(3)
  
  2 276
  
  1
  688
  
  1
  870Cash
  flow per share(dollars)
  
  8.66
  
  6.37
  
  6.87Debt
  
  3 057
  
  1
  401
  
  1
  774Cash
  and short-term investments
  
  234
  
  781
  
  1
  415Average
  capital employed
  
  $
  7 826
  
  $
  6
  259
  
  $
  5
  883Return
  on capital employed(per cent)
  
  13.9
  
  14.8
  
  16.0Operating
  return on capital employed(2)(per cent)
  
  14.5
  
  15.8
  
  16.4Return
  on equity(per cent)
  
  18.3
  
  18.1
  
  20.7  
 (1)
  Effective January 1, 2002
  the Company adopted, retroactively, the recommendations of the Canadian
  Institute of Chartered Accountants on accounting for foreign currency
  translation of long-term debt and, as a result, prior year comparative
  figures have been restated to conform with the current years presentation.(2)
  Earnings from operations
  are earnings before gains or losses on foreign currency translation and on
  disposal of assets. In 2000, earnings from operations are before
  reorganization costs.(3)
  Before changes in non-cash
  working capital items.   Shareholder
Value  Shareholder value grew 25.2
per cent through share price appreciation and dividends.    Shareholder value measures the change in the Petro-Canada share price
plus dividend returns.  This MD&A contains
forward-looking statements, including, but not limited to, references to:
future capital and other expenditures (including the amount, nature and sources
of funding thereof ); oil and gas production levels and the sources of their
growth; tax and royalty rates; oil and gas prices; the Canadian dollar exchange
rate; interest rates; refining and marketing margins; demand for refined
petroleum products; planned facilities construction and expansion; retail site
throughputs; pre-production and operating costs; reserve estimates; reserves
life; natural gas export capacity; plans for and results of exploration and
development activities; environmental matters; drilling plans; acquisition and
disposition of resource properties; and the dates by which certain areas and
facilities will be developed or will come on-stream. Undue reliance should not
be placed on these forward-looking statements, which are based upon
Petro-Canadas assumptions and 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 foreign currency exchange rates and interest 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; the availability of capital markets;
risks attendant with oil and gas operations; and other factors, many of which
are beyond the control of Petro-Canada. Petro-Canada undertakes no obligation
to update publicly or revise any forward-looking statements contained herein,
and such statements are expressly qualified by this cautionary statement.  6 
   2002
COMPARED WITH 2001  Earnings from
operations climbed 12 per cent to a record $1 024 million in 2002. The
improvement reflected a substantial increase in Upstream earnings, with partial
offsets from a decline in the Downstream and an increase in the net cost of
Shared Services. Net earnings and cash flow also climbed to record levels in
2002, reflecting the impact of Petro-Canadas new Upstream International
segment, established following the acquisition of most of the oil and gas
businesses of Veba Oil & Gas GmbH on May 2, 2002. This new business
contributed $225 million to earnings in 2002. The record cash flow includes
contributions of $1 417 million from Upstream Canada and $583 million from
Upstream International. A $431 million increase in the current portion of the
provision for income taxes, affecting cash flow, was largely related to
Upstream International business operations.  While
return on equity improved to 18.3 per cent from 18.1 in 2001, the operating
return on capital employed declined to 14.5 per cent from 15.8, reflecting a
weaker business environment and additional investment for future upstream
growth.  Business
Conditions  Economic factors influencing
Petro-Canadas Upstream financial performance include crude oil and natural gas
prices as well as the Canadian/U.S. dollar and Canadian dollar /euro exchange
rates. Prices for energy commodities are primarily affected by supply and
demand, weather, political events and the level of industry inventories.  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.  Earnings
from Operations and Cash Flow  Earnings from operations
topped $1 billion in 2002.    Earnings from operations do not include gains or losses on foreign
currency translation and on disposal of assets. In 2000, earnings from
operations are before reorganization costs.  Operating
Return on Capital Employed  Operating return on capital
employed reflected a weaker business environment and additional investment for
future upstream growth.    Earnings from operations do not include gains
or losses on foreign currency translation and on disposal of assets. In 2000,
earnings from operations are before reorganization costs.  BUSINESS
CONDITIONS IN 2002  The evolution
of oil prices in 2002 was again marked by major swings in response to changes
in market fundamentals as well as political developments with a major bearing
on global oil markets. Major political developments having a significant
influence on oil prices in 2002 included the persistent threat of war with Iraq
and, late in the year, political instability in Venezuela.  The evolution of North
American natural gas prices was also subject to considerable volatility. The
combination of softening demand and production growth during 2001 resulted in a
massive build-up of working gas in storage as we entered the 2001/02 winter
season. The year 2002 started with abundant gas in storage and
warmer-than-normal winter conditions prevailed across the continent. This led
to substantially weaker prices than those that characterized the 2000/2001
winter season and provided little opportunity for any significant strengthening
in prices until the onset of winter weather late in the year.  Sales
of Canadian refined petroleum products increased in 2002 by approximately 0.8
per cent compared with a decline of 1.0 per cent in 2001. For most of 2002,
refining margins were softer and light/heavy oil price differentials were narrower
than in the previous year.  Commodity Price Indicators and Exchange Rates  (averages for the years indicated)
  
  2002
  
  2001Crude
  oil price indicators (per barrel):North
  Sea Brent
  
  US$
  
  24.98
  
  US$
  
  24.46West
  Texas Intermediate (WTI) at Cushing
  
  US$
  
  26.08
  
  US$
  
  25.90WTI/Brent
  price differential
  
  US$
  
  1.10
  
  US$
  
  1.44Brent/Maya
  price differential
  
  US$
  
  4.08
  
  US$
  
  7.31Edmonton
  Light
  
  Cdn$
  
  40.41
  
  Cdn$
  
  39.58Edmonton
  Light/Bow River (heavy) price differential
  
  Cdn$
  
  8.90
  
  Cdn$
  
  14.97Natural
  gas price indicators:At
  Henry Hub  per million British thermal units (mmbtu)
  
  US$
  
  3.25
  
  US$
  
  4.38AECO
  spot  per thousand cubic feet (mcf)
  
  Cdn$
  
  4.24
  
  Cdn$
  
  6.57Henry
  Hub-AECO-C basis differential  per mmbtu
  
  US$
  
  0.66
  
  US$
  
  0.27New
  York Harbor 3-2-1 refinery crack spread  per barrel
  
  US$
  
  3.36
  
  US$
  
  4.44Exchange
  rates
  
  US$ per Cdn$
  
  US$
  
  0.637
  
  US$
  
  0.646 euro per Cdn$
  
  euro
  
  0.674
  
  euro
  
  0.721   7 
   OUTLOOK FOR
BUSINESS CONDITIONS IN 2003  Although business conditions are expected to remain volatile in 2003,
Petro-Canada's business is managed for the long term.  The global energy outlook in
2003 remains clouded by the uncertainties arising from a delayed global
economic recovery and, at time of writing, the continuing threat of a U.S.-led
military intervention in Iraq and the political crisis in Venezuela. Given
these conditions, Petro-Canada expects volatility in oil prices to continue
through 2003. Given current low levels of crude oil stocks globally, worries
about potential supply disruptions arising from a war in Iraq and from
political instability in Venezuela will continue to dominate the behaviour of
oil prices during the first half of the year and possibly beyond. These
concerns are being reinforced by doubts about OPECs ability to make up for the
potential loss of Venezuelan and Iraqi barrels.  In North America, the energy
outlook during 2003 is complicated further by the rapid tightening of the
natural gas supply/demand balance, due to unseasonably cold winter weather in
key consuming markets at a time of a very poor supply performance across the
continent. This has led to much faster rates of gas withdrawals from storage
than anticipated. If, as a consequence, the heating season closes with low
levels of natural gas inventories, there will be increased need for gas
injections to replenish storage levels before next winter. Thus, natural gas
prices across North America are expected to remain strong but highly volatile
in 2003 as the rapid depletion of natural gas in storage reduces the ability of
inventories to cushion unexpected swings in supply and/or demand. Moreover, the
continuing weak outlook for production growth in 2003, due to the maturity of
traditional basins in the United States and the Western Canada Sedimentary
Basin, will continue to provide support to gas prices during the remainder of
the year.  Only a modest improvement in
the volume of domestic sales of refined products and refinery margins is
anticipated for 2003, as external business conditions that have a major
influence on downstream operations are expected to remain more or less similar
to those that prevailed in 2002.  ECONOMIC
SENSITIVITIES  The following table shows the estimated after-tax effects that changes
in certain factors would have had on Petro-Canadas 2002 net earnings had these
changes occurred. We base these calculations on business conditions, production
and sales volumes realized in 2002.  Sensitivities Affecting Net Earnings  Factor
  
  2002
  Averages
  
  Change
  (+/-)
  
  Approximate
  Change (+/-)
  in Net Earnings(1)(millions of
  Canadian dollars)Total UpstreamPrice received for crude oil and liquids
  
  $38.50/bbl
  
  Cdn$1.00/bbl
  (2)
  34Price received for natural gas
  
  $4.07/mcf
  
  $0.25/mcf
  
  38Production of crude oil and liquids
  
  244 900 barrels per day (b/d)
  
  1 000 b/d
  
  4Production of natural gas available for
  sale
  
  825 million cubic feet per day (mmcf/d)
  
  10 mmcf/d
  
  3DownstreamNew York Harbor 3-2-1 crack spread(3)
  
  US$3.36/bbl
  
  US$0.10/bbl
  
  5Light/heavy crude price differential(4)
  
  $8.90/bbl
  
  $1.00/bbl
  
  13CorporateExchange rate: US$ per Cdn$(5)
  
  US$0.637
  
  US$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 2002
  WTI averaged US$26.08/bbl and North Sea Brent averaged US$24.98/bbl.(3)
  New York Harbor 3-2-1 crack
  spread applies mainly to Eastern Canada markets.(4)
  The spread between the
  prices of benchmark Edmonton Light and Bow River (heavy) crude oils.(5)
  A strengthening Canadian
  dollar versus the U.S. dollar has a negative effect on Petro-Canadas
  earnings.  8 
   Upstream  Petro-Canadas Upstream
operations are diversified both in resource type and geographically. In Canada,
we have three Upstream core businesses: East Coast offshore oil; Oil Sands in
northeastern Alberta; and North American natural gas, with current production
in Western Canada. Internationally, as a result of a major acquisition of oil
and gas assets in 2002, we are active in three core areas: Northwest Europe;
North Africa/Near East; and Northern Latin America.  Petro-Canadas
portfolio offers a platform for long-term growth in crude oil and natural gas.
Our goal is superior profitability and profitable growth. Our strategy combines
a drive for first quartile operating performance with a strict discipline as to
where and how we invest.  In
2002, Petro-Canadas Upstream operating return on capital employed was 17.6 per
cent, down from 20.9 per cent in 2001, reflecting lower natural gas prices and
additional investment for future growth in Canada and internationally.  Total
Upstream production in 2002 consisted of an average 244 900 b/d of oil and liquids
and 825 mmcf/d of natural gas, or a record 382 400 barrels of oil equivalent
per day (boe/d), almost double the 196 500 boe/d achieved in 2001. (Natural gas
is converted at the rate of 6 000 cubic feet to one barrel of oil equivalent).
The contribution to 2002 production from Upstream Canada averaged 239 700 boe/d
and from Upstream International 142 700 boe/d. At 2002 year-end, proved
reserves totalled 1 290 million boe (mmboe), up 57 per cent from a year
earlier. The impact of the newly-acquired international assets combined with
additions from drilling at Hibernia and Terra Nova and development of
Syncrudes Aurora Mine more than offset production in the year. During 2002,
independent petroleum reservoir engineering consultants Sproule Associates Limited
and DeGolyer and MacNaughton conducted evaluations, technical audits and
reviews of Petro-Canadas hydrocarbon reserves. Based on the results of this
work, we conclude that the Companys year-end 2002 reserves estimates are
reasonable. In addition, PricewaterhouseCoopers LLP, as contract internal
auditor, tested the non-engineering management control processes used in
establishing Canadian reserves.  Oil
and Gas Production  Production increased due to
the international acquisition, the start-up of Terra Nova and higher volumes
from Hibernia.    Reserves
Replacement  Total
conventional oil and gas reserves replacement increased in 2002.    Excludes acquisitions and
divestitures.  Excludes Syncrude and
MacKay River.  Upstream
Canada  Upstream Canada Financial Results  (millions of dollars)
  
  2002
  
  2001
  
  2000Earnings
  from operations
  
  $
  689
  
  $
  690
  
  $
  685(Loss)
  gain on sale of assets
  
  (1
  )
  29
  
  113Net
  earnings
  
  $
  688
  
  $
  719
  
  $
  798Cash
  flow
  
  $
  1 417
  
  $
  1
  125
  
  $
  1
  460Expenditures
  on property, plant and equipment and exploration
  
  $
  1 281
  
  $
  1
  131
  
  $
  884Total
  assets
  
  $
  5 922
  
  $
  5
  118
  
  $
  4
  811  2002
COMPARED WITH 2001  Petro-Canada's production of oil and gas nearly doubled in 2002 to a
record 382 400 barrels of oil equivalent per day.  Earnings from operations in
2002 were virtually unchanged from the previous year, as a $251 million
increase in operating revenues combined with a $19 million decrease in income
taxes was offset by a $48 million increase in operating costs, a $140 million
increase in depreciation, depletion and amortization expense and a $52 million
rise in exploration expense. The revenue gain reflected increased East Coast
crude oil production, with a partial offset from lower prices for natural gas.
Total crude oil and natural gas liquids production from Canadian operations in
2002 averaged 119 400 b/d, up 59 per cent from 75 100 b/d in 2001, with the
increase resulting from the start-up of Terra Nova, averaging 35 800 b/d, and a
6 400 b/d improvement at Hibernia. Natural gas production averaged 722 mmcf/d,
up from 714 mmcf/d in 2001. The average price received for Upstream Canada
crude oil and other liquids production was $37.95/bbl in 2002, compared with
$37.24/bbl a year earlier. Canadian natural gas prices averaged $4.01/mcf, down
from $6.00/mcf in the previous year. The increases in operating costs and
depreciation, depletion and amortization expense mainly reflect the start-up of
Terra Nova. The rise in exploration expense was due in large part to increased
drilling in the Mackenzie Delta and the Scotian Slope. Current income taxes,
affecting cash flow, decreased $88 million from the prior year. The decrease
relates in part to net deferrals of current income taxes, mainly related to
earnings of the Petro-Canada Oil and Gas partnership. The deferrals increased
current taxes by about $50 million in 2002 compared to an increase of about
$100 million in 2001.  9 
   Upstream
Canada Review & Outlook  EAST COAST
OIL  Strategy Continue to profitably add reserves and production through the
development of White Rose and field extensions at Terra Nova and Hibernia.  Pursue exploration opportunities in the largely unexplored deeper
waters off the Grand Banks.  Executing
the strategy  2002 began with the world-class start-up of Terra Nova. Both Terra Nova
and Hibernia exceeded production expectations.  Our share of East Coast oil production more
than doubled to 71 900 b/d in 2002 as a result of production start-up at Terra
Nova and solid gains at Hibernia. Terra Nova came on stream January 20, 2002,
and the performance of the production system was outstanding throughout the
first year of operation. Production uptime, including a planned three-week
maintenance shutdown, was 86 per cent, exceptional for a start-up year. As a
result, production for the year averaged 105 400 b/d (35 800 b/d net to
Petro-Canada), well above planned volumes. Operating costs in 2002, averaging
$4.25/bbl, are not a good indicator of costs going forward, as they are founded
on a build-up of production volumes over less than a full year of operations
and one-time start-up costs, as well as the three-week maintenance shutdown. In
2003, we expect to reduce operating costs to below $2.70/bbl. Field activity at
Terra Nova in 2002 included the drilling of five production and injection
wells.  Production from Hibernia in
2002 rose to a new record of 180 500 b/d (36 100 b/d net to Petro-Canada), up
from 148 500 b/d (29 700 b/d net to Petro-Canada) in the previous year, despite
a two-week planned maintenance shutdown of the production platform. Operating
costs in 2002 averaged $2.16/bbl, down from $2.62/bbl in 2001, with the
per-unit improvement driven mainly by the volume gain. Drilling in 2002 added
eight wells. Further strengthening our position on the East Coast in 2002, we
began development of the White Rose oil field (Petro-Canada  27.5 per cent
interest). The project includes construction of a Floating Production Storage
and Offloading vessel (FPSO) with a production capacity of 100 000 barrels of
oil per day and a subsea production system. Field development plans anticipate
19 to 21 wells to recover an estimated 200 million to 250 million barrels of
oil. Our Terra Nova experience has been incorporated into White Rose planning,
reducing risk and uncertainty. Petro-Canadas estimate of the projects gross
pre-production cost, including the first 10 wells, is $2.3 billion.  Hibernia
Operating and Overhead Costs  Operating and overhead costs
per barrel continued to decline.    Outlook 2003 Production expectations: East Coast conventional crude oil production to average 79 000 b/d.  Growth plans: Extend the production plateau at both Hibernia and Terra Nova. Complete White Rose development by late 2005. Test the exploration potential of the Flemish Pass.  2003 Capital spending plans: $170 million for development of the White Rose project. $140 million for ongoing Hibernia and Terra Nova drilling and
development programs. $40 million for exploratory drilling.  In addition to development of White Rose, our
Grand Banks mid-term growth focus includes extensions to existing reservoirs
and evaluation of potential subsea tiebacks of smaller discoveries and
prospects to the Hibernia and Terra Nova facilities. While the Hibernia
reservoir currently provides most of the reserves and production for the
Hibernia project, significant reserves potential also exists in the Ben Nevis
Avalon formation. The reservoir quality of these sandstones does not match that
of the prolific Hibernia reservoir but a substantial portion may be
economically accessible. Results of an appraisal well drilled in late 2002 to
test the extent of the Ben Nevis Avalon structure continue to be evaluated and
further appraisal drilling may be required. At Terra Nova, where development is
currently focused on the Graben and East Flank segments of the reservoir, we
are continuing to assess the potential of the adjacent Far East block. A first
Far East well, drilled in 2001, encountered 80 metres of oil-bearing net pay in
the Jeanne dArc sands. Results of a second delineation well, completed in late
2002, are being analysed. At least one delineation well is scheduled for 2003.
Project plans for White Rose anticipate production start-up in late 2005 and a
field life of 10 to 12 years, with peak annual average production of 90 000 b/d
(24 700 b/d net to Petro-Canada) sustainable for about four years.  10 
   Our
regional exploration work has identified a number of prospects in the Flemish
Pass and Salar Basins. These two basins are located in average water depths of
1 100 and 1 500 metres, respectively, compared to water depths of less than 100
metres for the Jeanne dArc basin, where all major oil discoveries to date have
been made. In early February 2003, we commenced drilling the Mizzen L-11 well
(Petro-Canada  33.34 per cent working interest) in the Flemish Pass region. It
is the first of two wells planned for the region in 2003.  OIL SANDS  Strategy Continue reliability improvements and pursue profitable long-term
growth from expansion of Syncrude. Capture the full value of in situbitumen
production through staged development integrated with our Edmonton refinery.  Executing
the strategy  We celebrated the on-time and on-budget start-up of the MacKay River in
situ oil sands project in 2002.  The successful completion in 2002 of our 100
per cent owned, 30 000 b/d, MacKay River in
situdevelopment, on schedule and on budget, was a significant
milestone in our long-term oil sands plans. Start-up began late in the third
quarter with initial steaming of the reservoir, followed by first bitumen
production in November. Petro-Canada expects production to climb from an
average 9 400 b/d in December 2002 to plant capacity of 30 000 b/d by the end
of 2003. We believe we can sustain production at capacity for 25 years. The
MacKay River production process uses steam-assisted gravity drainage (SAGD), a
technology Petro-Canada helped to develop, which can economically recover over
60 per cent of the bitumen in place. SAGD combines horizontal drilling with
thermal steam injection. Steam is injected into the reservoir through the top
well of a horizontal well pair to mobilize the bitumen, which flows to the
lower producing well. Initial development at MacKay River includes 25
horizontal well pairs. The water used to generate steam comes from underground,
with more than 90 per cent recycled  a key feature of the facilitys
environmental efficiency. Total capital expenditures at MacKay River came in at
$274 million.  With the knowledge gained from participation
in a SAGD pilot project at an adjacent test facility, our operating technical
risks at MacKay River are minimized. The result is high capital efficiency,
reservoir confidence and lower operating cost. On completion of a 165 megawatt
co-generation facility currently being constructed by TransCanada Energy
Limited, we expect MacKay River operating costs to average about $2.25 plus one
mcf of gas per barrel, which will be at the lower end of heavy oil supply costs
in Canada. The co-generation plant, planned for start-up late in 2003, will
provide MacKay River with a long-term assured supply of low-cost power and
steam and reduce related greenhouse gas emissions by about 50 per cent when
compared to the equivalent steam and electricity produced without
co-generation. The facility will be owned by TransCanada Energy but operated as
part of the MacKay River project.  Petro-Canadas
12 per cent share of Syncrude, the worlds largest oil sands mining operation,
forms another cornerstone of our oil sands growth plans. In 2002,
Petro-Canadas share of Syncrude production averaged 27 500 b/d, up from 26 800
b/d in 2001. Syncrude management is directing increased resources towards
resolving outstanding reliability concerns in an effort to fully realize
Syncrudes production potential, and reduce operating costs. Unit operating
costs declined to $19.50/bbl in 2002 from $19.91/bbl in the previous year. An
extended planned maintenance program in the summer of 2002 impacted unit costs.  Syncrude
Operating and Overhead Costs  Reliability of
operations is being addressed.    Outlook 2003
Production expectations: Petro-Canadas share of Syncrude production to average 27 900 b/d. MacKay River bitumen production to average 22 000 b/d.  Growth
plans: Continue participation in the expansion program at Syncrude. Develop our second in situbitumen
production project at Meadow Creek. Advance our development plans for a large-scale, fully integrated
project linking the production and refining of bitumen.  2003
Capital spending plans: $255 million for our share of Syncrudes expenditures. About $400 million for our proposed Edmonton refinery bitumen feed
conversion and Meadow Creek development.  11 
   At Syncrude,
engineering and construction is currently underway on the third stage of a
multi-stage expansion program. Stage 3 includes a second Aurora mine and an
upgrading expansion. This stage is expected to increase production capacity by
100 000 b/d to a total of 360 000 b/d (over 43 000 b/d net to Petro-Canada) by
2005.  Over the next decade,
assuming an appropriate regulatory climate concerning environmental issues
including the Kyoto Protocol, we expect oil sands will be a major engine of
growth for Petro-Canada. With interests in about 300 000 net acres of oil sands
leases considered prospective for in situ development, we are well positioned
to pursue this growth opportunity.  Completion of the MacKay
River project was the first step in creating a large-scale, fully integrated
bitumen production and refining operation. Our next step will be a second in
situ development at Meadow Creek (owned 75 per cent by Petro-Canada), 45
kilometres south of Fort McMurray. Meadow Creek will have a bitumen production
capacity of 80 000 b/d, more than twice that of MacKay River. Extensive seismic
evaluation and delineation drilling on the property have confirmed significant
bitumen resources. The property is well situated on existing infrastructure
corridors. Development could begin by late 2004, with initial production by
year-end 2007, giving us time to optimize the MacKay River development and
incorporate our experience into the design and plans for Meadow Creek.  Timelines for start-up at
Meadow Creek will be coordinated with the first phase of a major conversion to
enable the Edmonton refinery to replace its existing light crude oil feedstock
with bitumen. The initial conversion will provide upgrading and refining
capability for about 85 000 b/d of bitumen. At a later date, we have plans for
a third in situ development and a doubling of bitumen processing capacity at
the Edmonton refinery. Complete implementation of our integrated oil sands
strategy could take bitumen production to 170 000 b/d by 2012. Linkage of
bitumen production with refining provides considerable insulation from heavy
oil price fluctuations, eliminates bitumen marketing risks and provides
Petro-Canada with a competitive advantage over non-integrated bitumen
producers. Our staged approach to these capital-intensive projects will
facilitate cost management, while allowing us to benefit from evolving
technology.  Our
application for the Meadow Creek development is under review. Regulatory
approval for the feed conversion project at the Edmonton refinery is
anticipated in early 2003. Decisions to proceed with these plans will only be
made following regulatory approvals and continuing economic evaluations,
particularly with respect to the impact of the federal governments Kyoto
Protocol implementation plan. While both the federal and provincial governments
have stated that the oil sands economic opportunity must be maintained,
Petro-Canada is seeking further certainty as to the specifics of Kyoto Protocol
implementation and its impact on economics.  NORTH
AMERICAN NATURAL GAS  Strategy Maximize profitability through consistent top quartile performance in
finding and development costs and in the efficient operation of our production
facilities. For longer term growth, pursue high potential exploration in the
Mackenzie Delta, offshore Nova Scotia and Alaska.  Executing
the strategy  Petro-Canadacontinues to be one ofthe most
profitableproducers of naturalgas in
WesternCanada, with strongperformance
inoperating and finding&
developmentcosts.  Natural gas production averaged 722 mmcf/d in 2002, up from 714 mmcf/d
in 2001, as additional volumes from ongoing development and reduced gas plant
turnarounds more than offset natural declines. Natural gas price realizations
averaged $4.01/mcf, down 33 per cent from the previous year, due to soft market
conditions for a large part of the year. Our conventional crude oil and natural
gas liquids production in Western Canada averaged 18 900 b/d, up from 18 600
b/d in 2001. Operating and overhead costs in 2002 were $0.57 per thousand cubic
feet of gas equivalent (mcfe), down from $0.60/mcfe in the previous year,
partly reflecting the reduced turnarounds.  Exploration and development drilling in Western Canada resulted in 351
successful wells, for a success rate of 93 per cent. At 2002 year-end,
Petro-Canadas proved natural gas reserves in Western Canada totalled 2 181
bcf, compared with 2 228 bcf at the close of 2001. Proved crude oil and natural
gas liquids reserves, at 55 million barrels, were up from 54 million barrels a
year earlier. Exploration and development successes added 247 billion cubic
feet equivalent (bcfe) of natural gas and associated liquids to proved
reserves, replacing 86 per cent of 2002 production.  12 
   The shortfall from our
target of full reserves replacement reflects our focus on profitability and the
challenging environment for economic reserves additions in the increasingly
mature Western Canada Sedimentary Basin. As a result of strict investment
discipline, our three-year average finding and development cost for natural gas
and associated liquids remained highly competitive at $1.39/mcfe.  The success of our natural
gas business over the past several years has resulted from a strategy of
exploitation within our three core areas  the Alberta Foothills, northeastern
British Columbia and southeastern Alberta  especially in the Foothills, where
we have developed a strong technical competency in finding, developing and
operating deep sour gas. In the Wildcat Hills area alone, the application of
this competency over the past five years has resulted in 50 successful wells
and a more than 300 per cent increase in area production. Drilling successes in
2002 included the Wildcat Hills 8-32 well  our best well ever in this area.
This vertical well has net pay of 194 metres and is on production at 20 mmcf/d.  In the shallow
gas region of Medicine Hat in southern Alberta, we completed our first winter
drilling program, which continued into the summer months and resulted in 271
gross (164 net) successful wells. Reflecting the success of this ongoing
development program, production from the area rose to 68 mmcf/d late in the year.  For longer term growth, we
are continuing to pursue frontier opportunities. In early 2002, an aggressive
exploration program in the Mackenzie Delta was rewarded with a significant
natural gas discovery. The Tuk M-18 well (Petro-Canada  50 per cent interest)
tested at restricted rates up to 30 mmcf/d, with sustained deliverability
estimated at 60 to 80 mmcf/d. Recoverable gas from the field is estimated at
200 bcf to 300 bcf. Tuk M-18 was one of three wells drilled during the winter
of 2001/02; the remaining two were dry and aban-doned. Offshore Nova Scotia, we
participated in the Newburn H-23 exploratory well (Petro-Canada  43 per cent
interest) on the Scotian Slope, only the fifth industry well to test this deep
water play. The well found non-commercial quantities of gas. In Alaska, where
our focus is the foothills area north of the Brooks mountain range, a field
geological study has confirmed that the geology and prospectivity of the area
is similar to the Alberta Foothills, where Petro-Canada has developed
considerable expertise and has had significant success finding gas. At
year-end, we held 100 per cent interests in over 400 000 acres. While it is
unlikely the region will be serviced by a pipeline for some time,
Petro-Canadas acreage is close to a proposed pipeline route to southern
markets.  Western Canada Operating
and Overhead Costs  Costs per unit were down marginally from
the previous year.    Includes Western Canada
gas, conventional oil and liquids.  Natural
Gas and Associated Liquids Finding and Development Costs in Western Canada  Finding and
development costs remained competitive despite rising service and supply costs.    Three-year rolling average
for proved reserves.  Excludes acquisitions and
divestitures.  Outlook 2003 Production
expectations: Western Canada natural gas production to average 690 mmcf/d.  Growth
plans: Continue pursuit of attractive prospects in the Western Canada
Sedimentary Basin while focusing on profitability rather than volume gain. Advance exploration programs in the Mackenzie Delta, Scotian Slope and
Alaska.  2003
Capital spending plans: Continue substantial funding with investment plans totalling $455
million, including drilling in the Western Canada Sedimentary Basin and in the
Mackenzie Delta.  Our plans for the Mackenzie Delta in 2003 include at least one
exploration well that will test the same trend where we had success with Tuk
M-18. In January 2002, the Mackenzie Delta Producers Group, led by Imperial Oil
Limited, completed preliminary feasibility studies on development of a
Mackenzie Valley pipeline and began work on applications for regulatory
approval. In July, the group called for non-binding nomina-tions. Petro-Canada
nominated 30 mmcf/d from its share of the Tuk gas pool. Given the long-term
nature of Arctic development, as well as the antic-ipated lengthy regulatory
review and approval process, a pipeline to southern markets is unlikely to be
in place before the end of this decade. Our plans for offshore Nova Scotia
include a 3-D seismic survey over additional licensed exploratory acreage,
which could lead to an exploratory well in 2005.   13 
   Upstream International  Upstream International Financial Results  (millions of dollars)
  
  2002
  
  2001
  
  2000Earnings
  (loss) from operations
  
  $
  225
  
  $
  (27
  )
  $
  19Loss
  on sale of assets
  
  
  
  
  
  (41
  )Net
  earnings (loss)
  
  $
  225
  
  $
  (27
  )
  $
  (22
  )Cash
  flow
  
  $
  583
  
  $
  27
  
  $
  78Expenditures
  on property, plant and equipment and exploration
  
  $
  221
  
  $
  153
  
  $
  43Total
  assets
  
  $
  3 544
  
  $
  186
  
  $
  148  The substantial improvement in financial
performance in 2002 reflects the impact of a major acquisition, completed on
May 2. In 2001, international operations were limited to modest activity in
Algeria, Libya and Tunisia.  Averaged
over the full year, production from International operations in 2002 equated to
142 700 boe/d. Production of crude oil and gas liquids averaged 125 500 b/d and
natural gas 103 mmcf/d. Upstream International crude oil and liquids prices
averaged $39.53/bbl and natural gas prices averaged $4.52/mcf.  Upstream
International Review & Outlook  Strategy Exploit the existing reserve base and pursue new exploration and
development opportunities, leveraging off existing relationships, skills and
infrastructure. Establish a significant portfolio of growth opportunities, well
balanced as to technical risk and economic return.  Executing
the strategy  International is a new core business that contributed 25 per cent of
Petro-Canadas operating earnings and cash flow in the second half of 2002.  Petro-Canada gained a new platform for
longer-term growth on May 2, 2002, with the acquisition of significant
international oil and gas operations, while securing an immediate and
substantial contribution to earnings. In addition to expanding our position in
North Africa/Near East, a region of considerable underdeveloped potential, the
new international properties provided Petro-Canada with solid footholds in the
highly profitable North Sea and the highly prospective Northern Latin America
region. Integration of the new operations was essentially completed prior to
2002 year-end. Rights of first refusal were exercised by third parties with
respect to assets in Norway and Egypt. From May 2 to December 31, 2002,
production from the acquired assets averaged 210 000 boe/d, with performance
boosted by completion of development projects in the United Kingdom and
Trinidad.  Northwest
Europe In Northwest Europe, our
production comes from the U.K. and Netherlands sectors of the North Sea, with
exploration programs extending into Denmark and the Faroe Islands. In the U.K.
sector, Petro-Canadas operations are centred around existing infrastructure,
principally the Scott platform in the Outer Moray Firth and the Triton FPSO,
located further south in the central North Sea, 190 kilometres east of
Aberdeen. We hold interests in the Scott and Telford oil fields, the Guillemot
West and Northwest oil fields, and the Bittern oil field. The Guillemot and
Bittern fields are tied in to the Triton facilities. Production from the
Netherlands sector includes natural gas from blocks L8b and L5c and oil from
the Petro-Canada operated Hanze field. Over the last eight months of 2002,
Petro-Canadas share of production from Northwest Europe averaged 40 500 b/d
for crude oil and natural gas liquids and 89.5 mmcf/d for natural gas.  North
Sea activity in 2002 included the tieback of a new subsea satellite at the
western extension of the Guillemot West oil field to the Triton FPSO. This
project, adding initial production of 18 000 barrels of oil per day net to
Petro-Canada, typifies the profitable North Sea investment opportunities we are
pursuing. Drilling results offering opportunities for development included a successful
appraisal well at Clapham (Petro-Canada  100 per cent working interest) in the
U.K. North Sea and a gas discovery in block L5b (Petro-Canada  30 per cent
working interest) in the Netherlands.  14 
   North
Africa/Near East In the North Africa/Near East region, which
provides the major portion of Petro-Canadas international production, our
previously modest position in Algeria, Libya and Tunisia has been significantly
expanded with the addition of new interests in Syria, Libya and Kazakhstan. In
Syria, Petro-Canadas interests in three production sharing contracts are
consolidated under the umbrella of a joint venture firm, Al Furat Petroleum
Company (AFPC), which produces about 55 per cent of Syrian production. Our
share of production for the period from May 2 to December 31, 2002 averaged 107
200 boe/d. With the emphasis on improved recovery from existing fields, AFPC
has established a technical Study Centre dedicated to the integrated study of
the latest technologies, including underbalanced drilling, 4-D seismic and
high-resolution seismic stratigraphy.  In
Libya, Petro-Canada is one of the largest producers and well positioned to play
a significant role in the countrys drive to expand reserves and production.
Our major holding is a 49 per cent interest in a joint venture with the
National Oil Company (NOC), which combines the operations of more than 20
fields. Our share of production over the last eight months of 2002 averaged 43
400 barrels of oil per day. Under a separate production sharing arrangement
with NOC, development of two oil fields on the En Naga block was progressing
towards completion at 2002 year-end. Production from this project (Petro-Canada
working interest  50 per cent) is expected to come on-stream in 2003 at an
average annual rate of 6 800 b/d. Libya is a member of the Organization of the
Petroleum Exporting Countries (OPEC). As such, production in that country may
be constrained from time to time by OPEC quotas.  In
Kazakhstan, initial production was achieved during the second half of 2002 from
a small oil field development on the Temir licence (Petro-Canada  40 per cent
working interest). Early in 2003, following completion of a central production
facility, we expect production to build to capacity of 12 000 b/d (4 800 b/d
net to Petro-Canada).  Northern
Latin America Petro-Canadas
interests in Northern Latin America are focused on natural gas in Trinidad and
crude oil in Venezuela. In Trinidad, we hold a 17.3 per cent working interest
in the North Coast Marine Area-1 (NCMA-1) offshore gas project. In August 2002,
NCMA-1 achieved first production from initial development of the Hibiscus,
Poinsettia and Chaconia natural gas fields. The 2002 program included
commissioning the Hibiscus production platform and drilling of production
wells. Our share of production from start-up to 2002 year-end averaged 32
mmcf/d. Production is delivered to the Atlantic LNG facility at Point Fortin
for liquefaction and sale into United States markets. Late in 2002,
Petro-Canada completed the acquisition of a 50 per cent working interest in the
La Ceiba block, which straddles the eastern shores of Lake Maracaibo in
Venezuela. This property was initially excluded from the Veba acquisition
pending resolution of pre-emptive rights. Commercial development of discoveries
on the block continues to be evaluated. A right of first refusal concerning
Vebas Cerro Negro heavy oil operations in Venezuela was still unresolved at
year-end.  Outlook  Our International acquisition establishes a platform for longer-term
growth.  2003
Production expectations: Total International production to average 210 000 boe/d. Northwest Europe to average 44 000 boe/d. North Africa/Near East to average 157 000 boe/d. Trinidad to average 48 mmcf/d.  Growth
plans: In the North Sea, acquire resources adjacent to infrastructure. Advance opportunities to improve reserve recovery rates in Syria and
Libya through the application of modern technology. Exploitation and concentric exploration in underdeveloped areas of
Libya and Syria. Identify and develop growth opportunities in new areas.  2003
Capital spending plans: $260 million to sustain existing production. $190 million for new developments, including the Clapham project in the
North Sea. $95 million for exploration opportunities.  In Northwest Europe, our key strategy is
focused exploration and development on low-risk opportunities in the North Sea,
centred on existing infrastructure. While the region is a mature play, even
small developments are attractive. We are focusing on low-cost development of
small and mid-size pools that can be rapidly brought into production. Our plans
include expanding our presently modest exploration portfolio with the emphasis
on securing licence operatorships or high working interests.  15 
   Our goal is to sustain profitable production
over the medium term. The near-term focus includes development of a gas
discovery on block L5b in the Netherlands sector, where first production is
expected early in 2004 at an anticipated rate of 12 mmcf/d. In the U.K.,
development plans for the Clapham field include drilling two producing wells
and two injectors and tie-in to the Triton production facility. Production from
this new field is expected to rise rapidly to an anticipated peak of 15 000
boe/d in 2004.  In
North Africa/Near East, our strategy is to exploit the large underdeveloped
reserves potential in this region. In Syria, AFPCs near term goal is to
sustain gross production at the 300 000 boe/d level for the next few years. For
the longer term, we are assessing exploration opportunities. In Libya, we see
an opportunity for the future in the application of modern technology to
further improve reserves recovery.  In
Northern Latin America, our expectations for production growth are currently
focused on Trinidad, where Atlantic LNG is building an additional production
train to serve the NCMA-1 project. When the train comes on stream in mid-2003,
we expect our share of production to grow to 60 mmcf/d. For the longer term, we
are looking at emerging exploration opportunities.  Downstream  Downstream Financial Results  (millions of dollars)
  
  2002
  
  2001
  
  2000Earnings
  from operations
  
  $
  254
  
  $
  300
  
  $
  273Gain
  (loss) on sale of assets
  
  3
  
  1
  
  (1
  )Net
  earnings
  
  $
  257
  
  $
  301
  
  $
  272Cash
  flow
  
  $
  380
  
  $
  589
  
  $
  434Expenditures
  on property, plant and equipment
  
  $
  344
  
  $
  383
  
  $
  264Total
  assets
  
  $
  3 841
  
  $
  3
  556
  
  $
  3
  609  2002
COMPARED WITH 2001  Strong operating performance
throughout the Downstream in 2002 yielded solid results in a difficult business
environment. Total sales of refined products, buoyed by an uplift in retail
fuel and asphalt sales, increased to a record 55 700 cubic metres per day (m3/d)
from 54 500 m3/d in 2001. Despite rising feedstock costs, the
earnings contribution from Lubricants operations was up significantly in large
part due to a further increase in high-margin sales. Despite the operating
performance improvements, Downstream net earnings declined, mainly due to the
adverse effects on Refining and Supply of lower refining margins, particularly
for distillate, and narrower light/heavy oil price differentials. Downstream
operating return on capital employed declined to 10.8 per cent in 2002 from
13.3 per cent in 2001 for the same reasons. Total Downstream operating,
marketing and overhead unit costs, at 5.8 cents per litre, were unchanged from
2001. Current income taxes, affecting cash flow, increased to $242 million in
2002 from $90 million in the previous year, mainly due to the net deferral of
current taxes, resulting from the inventory accounting method required for
income tax purposes. This method resulted in an $85 million increase in current
taxes in 2002, compared to a $98 million reduction in 2001.  Downstream
Review & Outlook  Strategy Generate superior returns by focusing on first-quartile refining
performance, advancing Petro-Canada as the brand of choice for Canadian
gasoline consumers, and increasing sales of high-margin specialty lubricants.  Operating
strategies are focused on strengthening the foundations for improved
profitability through effective capital investment and discipline over
controllable factors. The target is a minimum 12 per cent return on capital
employed, based on a mid-cycle business environment. Petro-Canadas three
refineries, strategically located in the major markets of Alberta (Edmonton),
Ontario (Oakville) and Quebec (Montreal), account for about 17 per cent of Canadas
total refining capacity. The refineries and lubricants plant are already
benefiting from restructuring and planning initiatives  16 
   implemented over the past two years. A
reorganization of the Sales and Marketing group during 2002 has further
improved cost structure and is part of the drive towards top quartile
Downstream performance.  Executing
the strategy  In the Downstream, profitability improvement initiatives are delivering
results.  In 2002, our three refineries ran at full
capacity, processing a record average 50 400 m3/d of crude oil, a
six per cent increase over 2001 volumes. Improved plant reliability spearheaded
the improvement. The overall crude capacity utilization rate was 101 per cent,
compared to 96 per cent in 2001. To optimize operations and maintenance
procedures, we have implemented Solomon & Associates best practices. As
part of efforts to reduce both costs and greenhouse gas emissions, Petro-Canada
is committed to reduce energy consumption by an average of at least one per
cent per year through 2005.  The
capability of the Oakville and Montreal refineries to process heavy oil allows
us to lower feedstock costs and gives us a strong position in the asphalt
markets in eastern Canada. In 2002, asphalt produced from these heavy crudes
totalled a record 1.6 billion litres; however, the financial benefit was
moderated by weak industry margins.  In
2002, modifications were completed at the Oakville refinery to reduce sulphur
in gasoline to 150 parts per million (ppm) gasoline pool average, as required
by the federal government. Construction of desulphurization units for the
regulatory requirement of 30 ppm gasoline limit by 2005 has begun at the
Edmonton and Montreal refineries. Engineering of the technology solution for
sulphur reduction to 30 ppm at Oakville is underway. We expect to meet
government timelines in the legislative requirements for low-sulphur gasoline
supply.  In
Sales and Marketing, the throughput from Petro-Canadas retail network of 1 537
sites averaged 4.1 million litres per site, compared with 3.8 million litres in
2001. The improvement reflects the success of new-image sites, which are
achieving annual throughputs averaging in excess of seven million litres.
Fast-tracking the re-imaging program has enabled us to capitalize on this
compelling market advantage.  Retail
site re-imaging and successful sales and marketing programs have generated
substantial growth in sales of non-petroleum products and services. Convenience
store sales, which were up 30 per cent in 2002 compared with 2001, have grown
more than 150 per cent since 1998. In recognition of the quality and success of
our convenience store business, Petro-Canada was named 2002 Convenience Store
Chain of the Year by leading U.S. trade journal Convenience Store Decisions. The award identified
outstanding performance in all eight fields of measurement: product quality;
customer service; marketing innovation; operating efficiency; management
effectiveness; community involvement; image enhancement; and sales and profit
performance. This is the first time a non-U.S. retailer has won the award,
considered the most prestigious in the North American convenience store
industry.  Petro-Canadas growing
achievements in retail sales and marketing also include an expanding membership
in Petro-Points, Petro-Canadas branded customer loyalty program. At year-end
2002, about 6.6 million Canadian households were Petro-Points members, up 20
per cent from a year earlier. The strong membership growth is being driven by
continued program improvements, including points exchange with Presidents
Choice Financial points program and the acceptance of Sears credit cards, which
complements the existing points exchange with the Sears points program. The
newly launched Petro-Canada Pre-Paid Card, which can be used to purchase any
product or service at Petro-Canada locations across the country, is also
proving to be a valuable product as well as an additional reward option for
Petro-Point members. The Pre-Paid Card is the first of its kind to be offered
by a major oil and gas company in Canada.  In
the wholesale channel, key strategic initiatives have been implemented, all
focused on maintaining our best-in-class position. The Petro-Pass network of 208
truck stop facilities is the leading national marketer of fuel in the
commercial road transport segment in Canada. These facilities provide 24-hour
access to high speed pumps for faster fueling, as well as a range of enhanced
services to meet the needs of the trucking industry. In 2002, we focused on
enhancing our leadership position through network expansion and additional
wholesale site re-imaging based on the successful retail design. In bulk fuels,
new logistics technology was implemented and consolidations were completed to
further improve the efficiency of our network.  In
Lubricants, our strategy is focused on growing volume in high-margin channels.
Petro-Canada enjoys worldwide recognition for its state-of-the-art base oil
manufacturing technology, the result of more than 20 years of pioneering work.  17 
   The lubricants plant produces the highest
quality hydro-treated products as well as low-cost pharmaceutical grade white
oils and high viscosity index oils. Products include premium quality lubricants
for high-end industrial applications, next-generation engine oils and
transmission fluids. In 2002, Lubricants sales totalled 768 million litres, an
increase of over three per cent in comparison with sales volume of 744 million
litres in 2001, reflecting strong growth in higher value base oils and sales to
the automotive sector. In total, high-margin sales rose 10 per cent and now
represent over 60 per cent of total Lubricants sales.  Downstream
Operating, Marketing and General Costs  Per-litre costs
were unchanged from 2001.    Refinery
Utilization  Refinery
utilization increased reflecting continued reliable operations at the Companys
refineries.    Our rated refinery crude capacity increased in 2001 following process
improvements.  Product
Sales  Total Downstream
sales and sales per retail site continued to grow in 2002.    Outlook Plans for
improved profitability: Maximize refinery plant reliability. Increase product value from refinery feedstock slates. Secure further reductions in operating costs. Continue roll-out of and maximize benefits from retail site re-imaging
program. Capitalize on the increasing demand for higher quality base oils.  2003
Capital spending plans: $360 million for Refining and Supply. $125 million for Sales and Marketing. $15 million for Lubricants.  The 2003 capital expenditure
plans are focused on positioning Petro-Canada for continued profitability,
while lessening the environmental impact of our operations and products. The
major portion of expenditures in Refining and Supply will focus on refinery
reconfigurations to meet new lower limits for sulphur in gasoline. Expenditures
in Sales and Marketing will provide for the continued roll-out of Petro-Canadas
successful new-image service station program and further development of the
Petro-Pass network. At year-end 2002, we were 70 per cent of the way through
the retail site re-imaging program, which is focused on converting only those
Company-controlled sites that meet economic return criteria. The goal is to
complete the program by the end of 2005.  Petro-Canada
currently sells over two-thirds of its 350 manufactured lubricants, specialty
fluids and greases outside of Canada and the increasing global demand for
higher quality base oils offers significant opportunity for long-term growth.
As both performance and environmental standards get tougher, the demand for
Petro-Canadas finished products and base fluids is expected to continue to
grow. By 2005, Lubricants target is to achieve over 75 per cent of total sales
in the higher-margin channel.  Shared Services  Shared Services Financial Results  (millions of dollars)
  
  2002
  
  2001
  
  2000Net
  expenses from operations(1)
  
  $
  (144
  )
  $
  (51
  )
  $
  (98
  )Foreign
  currency translation loss
  
  (52
  )
  (96
  )
  (53
  )Net
  expenses(1)
  
  $
  (196
  )
  $
  (147
  )
  $
  (151
  )Cash
  flow(1)
  
  $
  (104
  )
  $
  (53
  )
  $
  (67
  )  
 (1)
  Before reorganization costs
  in 2000.  2002
COMPARED WITH 2001  Shared Services is structured as a cost
centre that includes investment income, interest expense, foreign currency
translation and general corporate revenues and expenditures. The rise in net
expenses in 2002 reflects a drop in investment and other income and an increase
in interest expense, both related to the financing of the Veba acquisition,
with a partial offset from a reduction in foreign currency translation loss.  The
foreign currency translation loss of $52 million in 2002 includes a $63 million
exchange loss from the translation of international subsidiaries. Effective
January 1, 2003, Petro-Canada commenced operating Upstream International on a
self-sustaining basis. As a consequence, the Company prospectively changed the
accounting for the foreign currency translation of its international subsidiaries,
whereby future gains or losses arising from the translation of financial
statements into Canadian dollars will be deferred and included as part of
shareholders equity.  18 
   LIQUIDITY
AND CAPITAL RESOURCES  Summary of Cash Flows  (millions
  of dollars)
  
  2002
  
  2001
  
  2000Net cash inflows (outflows) before changes in non-cash
  working capital:Cash
  flow
  
  $
  2 276
  
  $
  1
  688
  
  $
  1
  870Investing
  activities
  
  (4 141
  )
  (1
  564
  )
  (489
  )Financing
  activities
  
  1 560
  
  (909
  )
  (214
  )(305
  )
  (785
  )
  1
  167(Increase) decrease in non-cash working capital and other
  
  (242
  )
  151
  
  42(Decrease) increase in cash and short-term investments
  
  $
  (547
  )
  $
  (634
  )
  $
  1
  209Cash and short-term investments at year-end
  
  $
  234
  
  $
  781
  
  $
  1
  415  Operating
Activities  The reduction in net cash
outflow before changes in non-cash working capital primarily reflects the
impact of the Veba acquisition, with offsets from the related financing
arrangements and increased cash flow from operations.  The increase of $242 million
in non-cash operating working capital, excluding working capital relating to
acquisitions, was mainly due toan increase in accounts receivable and a decrease in income taxes
payable, partially offset by an increase in accounts payable and accrued
liabilities. The higher levels of accounts receivable and payable reflect the
significantly higher prices for both oil and natural gas at 2002 year-end
compared with 2001 year-end. The decrease in cash and short-term investments
reflects the use of funds towards financing the Veba acquisition, as well as to
repay $461 million of the related credit facilities.  Investing
Activities  Capital and
Exploration Expenditures  (millions
  of dollars)
  
  2002
  
  2001
  
  2000Acquisition of oil and gas operations of Veba Oil & Gas
  GmbH
  
  $
  2 234
  
  $
  
  
  $
  Upstream Canada(1)North
  American Natural Gas
  
  529
  
  554
  
  434East
  Coast Oil
  
  290
  
  273
  
  340Oil
  Sands
  
  462
  
  304
  
  1101 281
  
  1
  131
  
  884Upstream International(1)Northwest
  Europe
  
  93
  
  
  
  23North
  Africa/Near East
  
  108
  
  153
  
  20Northern
  Latin America
  
  20
  
  
  
  221
  
  153
  
  43DownstreamRefining
  and supply
  
  210
  
  206
  
  102Sales
  and marketing
  
  118
  
  156
  
  143Lubricants
  
  16
  
  21
  
  19344
  
  383
  
  264Shared Services
  
  15
  
  14
  
  12Total property, plant and equipment and exploration
  
  1 861
  
  1
  681
  
  1
  203Deferred charges and other assets
  
  72
  
  10
  
  8Total
  
  $
  4 167
  
  $
  1
  691
  
  $
  1
  211  
 (1)
  Includes exploration
  expenses charged to earnings, totalling $301 million in 2002, $245 million in
  2001 and $171 million in 2000.  19 
   2002
COMPARED WITH 2001  The substantial capital
spending in the Upstream reflects Petro-Canadas continuing commitment to
long-term profitable growth. Investments in Upstream Canada included $399
million for exploration and development of natural gas in Western Canada and
$110 million for other natural gas opportunities in North America, principally
in the Mackenzie Delta and offshore Nova Scotia. Major funding for exploration
and development of crude oil offshore Canadas East Coast included $82 million
to complete development of Terra Nova and $132 million towards development of
White Rose, mostly related to the fabrication of a new FPSO vessel. Oil sands
investments included $222 million for Syncrude, mainly for the Stage 3
expansion; $114 million to complete development of the MacKay River oil sands in situproject; $97 million for the
Edmonton refinery conversion and $29 million for other oil sands work,
principally drilling activity at Meadow Creek, Petro-Canadas planned second in situdevelopment project.  Expenditures in Upstream International
were incurred, for the most part, over the last eight months of the year
following the Veba acquisition, and largely related to ongoing programs in the
U.K. North Sea, Syria, Libya, Kazakhstan and Trinidad. Major investments in the
Downstream focused on the fast-track development of our new-image retail sites
and programs to comply with sulphur-in-gasoline regulations.  Petro-Canadas capital
expenditure budget for 2003 is $2 575 million, up 38 per cent from the $1 861
million of expenditures on property, plant and equipment and exploration in
2002, reaffirming our commitment to profitable growth and the creation of
long-term shareholder value. About $1 500 million of 2003 budgeted expenditures
are allocated to activities in Upstream Canada, $545 million to Upstream
International, $500 million to the Downstream, and $30 million for corporate
and other purposes. We plan to fund the 2003 capital expenditure program from
cash flow.  Financing
Activities and Dividends  Sources of
Capital Employed  (millions
  of dollars)
  
  2002
  
  2001
  
  2000Long-term
  debt, including current portion
  
  $
  3 057
  
  $
  1
  401
  
  $
  1
  774Shareholders
  equity
  
  5 776
  
  4
  877
  
  4
  465Total
  
  $
  8 833
  
  $
  6
  278
  
  $
  6
  239  We retired $461 million by year-end 2002 and
an additional $100 million in January 2003 of the $2.1 billion debt we assumed
to finance the International acquisition.  On May 2, 2002, Petro-Canada
acquired the majority of the international oil and gas businesses of Veba Oil
& Gas GmbH and, on December 10, 2002, Petro-Canada acquired from Veba a 50
per cent working interest in the La Ceiba block in Venezuela which had been
subject to rights of first refusal. The total acquisition cost, consisting of a
cash consideration and acquisition costs, was $2 234 million. This is
considerably lower than the previously announced $3 200 million, due to the
exercise of rights of first refusal affecting a number of properties included
in the original acquisition proposal and the unresolved right of first refusal
related to assets in Venezuela. Funds for the acquisition were provided from
new credit facilities arranged with certain banks (See Note 16 of Notes to
Consolidated Financial Statements) and from cash and short-term investments.
The net increase in debt at 2002 year-end reflects the drawdown of $2 100
million of the acquisition credit facility, less total debt repayments of $465
million during the year, and a new capital lease of $32 million. An additional
$100 million of the acquisition credit facility was repaid in January 2003.
Petro-Canada plans to meet remaining repayment commitments out of a combination
of cash flow and by accessing debt capital markets.  For operating purposes,
Petro-Canada has access to a portion of the new credit facilities and other undrawn
bank lines of credit for a total of $1 427 million. As of December 31, 2002,
Petro-Canada had cash and short-term investments of $234 million and no
commercial paper outstanding. Petro-Canada will continue to use its cash
position, and the issuance of short-term debt if necessary, to meet working
capital and other financing requirements.  While the debt taken on to
finance the acquisition significantly increased our financial leverage, we
expect debt to cash flow, our key leverage measure, to remain within our target
range of no more than two times. At December 31, 2002, this ratio stood at 1.3
times, up from 0.8 times at the end of 2001. Debt to debt plus equity, our
long-  20 
   term measure for capital structure, rose to
34.6 per cent at 2002 year-end compared with 22.3 per cent at the prior
year-end, but we expect to reduce this, over time, to our target level of 30
per cent.  Petro-Canada does not engage
in off-balance sheet accounting 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 2002 year-end,
Petro-Canadas defined benefits pension plans were under-funded for accounting
purposes by $279 million, up from $80 million at the end of 2001, mainly
reflecting the impact of weak capital markets on fundassets. As a consequence of the increased
deficit, Petro-Canada will make a cash contribution of about $30 million to the
fund during 2003 and we expect the pension expense to increase by approximately
$45 million before tax. On a per share basis, the after-tax expense increase
represents about $0.10 per share for the year.  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. In 2002,
Petro-Canada paid $105 million in dividends, compared with $106 million in
2001. The current quarterly dividend is $0.10 per share.  Financial
Ratios  2002
  
  2001
  
  2000Interest
  coverage(times):earnings
  basis
  
  10.5
  
  9.7
  
  10.0EBITDAX
  basis
  
  17.1
  
  15.1
  
  14.9cash
  flow basis
  
  17.9
  
  15.6
  
  15.2Debt
  to cash flow(times)
  
  1.3
  
  0.8
  
  0.9Debt
  to debt plus equity(per cent)
  
  34.6
  
  22.3
  
  28.4  Key
Debt Ratios  Despite debt taken on to
finance the International acquisition, we are well positioned relative to our
target levels.    Interest
Coverage  A positive interest coverage
ratio demonstrates more than sufficient earnings to cover interest charges on
debt.   Calculated on
an EBITDAX basis.  RISK MANAGEMENT  Petro-Canadas risk
management activities are conducted according to policies and guidelines
established by the Board of Directors, using insurance, selective hedging and
other techniques. Our risk management 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. Commodity prices and margins may be hedged occasionally to capture
opportunities that represent extraordinary value. Except as specifically
authorized by the Board, the term of hedging instruments cannot exceed 18
months. We transact derivatives with counterparties 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 current and potential exposure to losses due to non-performance of
a counterparty and reduce credit risk concentration with any single
counterparty. Monitoring and reporting of the derivatives portfolio includes
periodic testing of the fair value of all outstanding derivatives. Commodity,
currency and interest rate hedgesresulted in a net decrease in earnings of about $22 million after tax
in 2002, compared with a net increase in earnings of about $10 million in 2001.  As at December 31, 2002,
crude oil, natural gas and foreign exchange 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. Short duration Forward Rate Agreements have been implemented to
manage the interest rate exposure on floating debt and, in anticipation of
accessing debt capital markets in 2003, Petro-Canada has entered into interest
rate derivatives to hedge a portion of its exposure to adverse interest rate
fluctuations.  Petro-Canada has future
commitments to sell and transport natural gas associated with normal
operations. About four per cent of our estimated 2003 Upstream Canada natural
gas production is sold under future fixed-price commitments at an average plant
gate netback price of $2.73 per mcf. Sales under these contracts will drop by
about 40 per cent in 2004 compared to the 2003 level of sales.  Petro-Canada manages
operational risk through comprehensive risk assessment and loss  21 
   management processes, and
maintains adequate insurance coverage. We place insurance coverage globally,
with financially secure insurers. Limits of insurance are based on engineering
risk assessments and deductibles are set at levels that reflect our ability to
retain the risk.  We also employ high levels
of technical expertise and leading-edge technology to mitigate exploratory
risks. To secure strategic and competitive advantages, Petro-Canada has entered
into a variety of alliances with world-class suppliers of industry goods and
services. These alliances provide preferential access, reliability, advanced
technology, high quality and competitive prices, mitigating variability in costs
associated with exploration and development as industry conditions fluctuate.  CORPORATE RESPONSIBILITY  At Petro-Canada, we take pride in being a good corporate citizen.
Strong environment, health and safety performance is fundamental to our business
as an energy company.  While Petro-Canada is in
business to provide a competitive return to shareholders, we recognize that
economic performance is not the only criterion on which our company is
evaluated.  To review our performance in
environmental stewardship, health and safety and community involvement in more
detail than can be accommodated in the Annual Report, we publish an annual
Report to the Community. The report gathers data on key non-financial
performance measures, enabling the public to assess our ongoing efforts in
these areas. The Report to the Community can be viewed on our Web site at
www.petro-canada.ca, or obtained from Corporate Communications. The 2002
Report to the Community will be available in July 2003.  Corporate
Governance  Petro-Canada strives to
attain the highest standards of corporate governance. The company has evolved
its management and internal reporting systems to provide a high level of
assurance that corporate responsibility is part of our day-to-day business
decision-making process. These governance systems begin with the Board of
Directors and extend throughout the company.  Petro-Canada has a range of
tools to establish and enforce appropriate conduct for all employees, including
a Code of Business Conduct and Principles for Investment and Operations. Both
of these documents can be viewed on our Web site at www.petro-canada.ca.  The Companys Management
Proxy Circular, which is mailed to shareholders and is also available for
viewing online, includes a Statement of Corporate Governance Practices,
reference to the Corporate Governance Handbook, mandates and reports of Board
committees, and detail on Directors business background, tenure, committee
membership, remuneration and share ownership.  The Board of Directors has responsibility for
ensuring timely and appropriate information disclosure to security holders and
regulators. We believe the Corporation is well aligned with the guidelines
adopted by the Toronto Stock Exchange and the recently proposed disclosure
requirements under the Sarbanes-Oxley Act of 2002. For detailed information,
please refer to Appendix A in the Management Proxy Circular.  The Corporate Governance and
Nominating Committee, composed entirely of unrelated directors, oversees the
Corporations corporate governance process and is responsible for addressing
governance issues and proposing to the Board candidates for election to the
Board of Directors. The committee and management undertook an extensive review
following proclamation of the Sarbanes-Oxley Act of 2002, and recommended areas
of improvement in the Corporations current practices as well as highlighted
achievements.  Environment,
Health and Safety  Petro-Canada executives are
responsible for developing operational procedures and standards in compliance
with our environment, health and safety policies and Total Loss Management
standards under which we conduct a major review of each business unit every
four years. Our Executive Leadership Team reviews environment, health and
safety performance monthly. As well, critical issues and EHS performance are
reviewed by the Environment, Health and Safety Committee of the Board of
Directors three times per year.  In
2002, we invested $318 million in environmental programs, including $90 million
for operating expenses and $228 million in capital expenditures for facility
upgrades. Some of the expenditures include site remediation, environmental
assessments, and pollution prevention and control equipment. We expect
environmental  22 
   costs to remain high, as we
prepare to meet new federal limits for sulphur in gasoline, future fuel
reformulation requirements, and tighter environmental standards for oil and gas
production. The cost impact of the federal governments ratification of the
Kyoto Protocol on greenhouse gas emissions, particularly on large,
capital-intensive projects, has yet to be determined.  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.  Petro-Canada has renewed its
commitment to improve energy efficiency in each business sector 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.  Since 1990, Petro-Canada has
improved energy efficiency in the Downstream by 15 per cent and in the Upstream
by 52 per cent. By implementing energy efficiency and emissions reduction
projects, we have reduced ongoing annual greenhouse gas emissions by
approximately 1.2 million tonnes of CO2 equivalent, while
increasing overall production by 23 per cent. Data for 2002 will be provided in
this years Report to the Community.  The safety and well-being of
our employees is a high priority for Petro-Canada. Occupational health and
safety programs are designed to contribute to employee well-being and provide a
safe and healthy work environment. Our overall Employee Recordable Injury
Frequency (per 200 000 person hours) decreased to 0.94 in 2002 from 1.14 in
2001. Recordable injuries decreased to 44 in 2002 from 46 in 2001. Over the
past year, Petro-Canada has renewed efforts to introduce further initiatives
focused on injury reduction.  Greenhouse
Gas Emissions versus Production  Petro-Canada is committed to
reducing GHG emissions in our Upstream and Downstream operations, primarily by
improving energy efficiency.   
 *Year 2000 data has
been restated and is slightly higher than was reported in last years report.  2002 data is
not yet available; data is based on reporting 100 per cent from Petro-Canada
operated properties.  Community
Involvement  Petro-Canadas success
depends on the support of Canadians, so we actively invest and participate in
the communities where we work and live across the country.  In 2002, Petro-Canada
invested $5 million in 375 Canadian non-profit organizations in four sectors 
education, the environment, health and community services, and arts and
culture. We also contributed another $800 000 from our Olympic Torch
Scholarship Fund, and approximately $300 000 in in-kind contributions. Through
our Volunteer Energy Program, we provided 403 grants of $500 each to non-profit
organizations supported by employees and retirees who give their time to the
community.   23