Exhibit
99.2   PETRO-CANADA MANAGEMENT'S
DISCUSSION AND ANALYSIS


MANAGEMENTS DISCUSSION AND ANALYSIS  This
Managements Discussion and Analysis (MD&A), dated effective as of February 16,
2005, should be read in conjunction with the audited Consolidated Financial
Statements and Notes for the year ended December 31, 2004, included in the
2004 Annual Report and the 2004 Annual Information Form. 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 natural gas production and
reserves volumes are stated before deduction of royalties, unless otherwise
indicated. Graphs accompanying the text
identify our value drivers, the key measures of performance in each segment
of our business.  Glossary of financial terms and ratios can be found on
the inside back cover of this report.  NON-GAAP
MEASURES  Cash flow, which is expressed
before changes in non-cash working capital, is used by the Company to analyze
operating performance, leverage and liquidity. Earnings from operations, which
represent net earnings excluding gains or losses on foreign currency
translation, disposal of assets and unrealized gains or losses on the
mark-to-market of the derivative contracts associated with the Buzzard
acquisition, are used by the Company to evaluate operating performance. Cash
flow and earnings from operations do not have a standardized meaning prescribed
by Canadian GAAP and therefore may not be comparable with the calculation of similar
measures for other companies.  Q:What is
  Petro-Canadas outlook for the business environment?A:Signs point to commodity markets which have rising demand and
  continued price volatility.  Business Environment  Economic factors influencing
Petro-Canadas upstream businesses financial performance include crude oil and
natural gas prices and foreign exchange rates, particularly the Canadian
dollar/U.S. dollar exchange rate. Prices for energy commodities are primarily
affected by market supply and demand, weather and political events. Performance
in Petro-Canadas Downstream business is influenced mainly by the level and
volatility of crude oil prices, industry refining margins, movement in crude
oil price differentials, demand for refined petroleum products and the degree
of market competition.  BUSINESS
ENVIRONMENT IN 2004  The year 2004 was an
extraordinary year in the history of energy commodity prices. International
light crude oil prices for North Sea Brent (Brent) and West Texas Intermediate
(WTI) reached average annual prices not seen since 1982. Light/heavy crude
price differentials widened to unprecedented levels. North American natural gas
prices attained their highest level since price deregulation in 1986.  2


The factors driving high oil
prices were: a strong surge in global oil demand (led by China); slower growth
in Russian production; continued interruption of Iraqi exports; and the impact
of Hurricane Ivan on the U.S. Gulf of Mexico production. At the same time,
increased production from the Organization of the Petroleum Exporting Countries
(OPEC) and Mexico led to the supply of heavier grades of crude growing at a
faster rate than the refining conversion capacity that was available for processing.
The result was the widest light/heavy crude price differential on record.  Continued
weakening of the U.S. dollar throughout 2004 resulted in the highest
Canada/U.S. exchange rate in the past 10 years. The elevated exchange rate
lowered the positive impact of higher international commodity prices. The
Canadian dollar rose from 77.4 cents US on December 31, 2003, to 83.1
cents US on December 31, 2004, an increase of 7%.  The stronger
Canadian dollar dampened the impact of higher commodity prices in 2004.  CANADA/U.S.
EXCHANGE RATE  (US
cent/Cdn $, January 1990 to January 2005)    North American natural gas
prices enjoyed another year of buoyancy, despite record levels of storage gas
due to weaker demand and better-than-anticipated production volumes. Concern
regarding the underlying strength of production growth in North America and the
impact of Hurricane Ivan on U.S. Gulf of Mexico production helped maintain
Henry Hub monthly average gas prices at levels above $5.00 US per million
British thermal units (MMBtu). Average Canadian natural gas prices mirrored the
performance of prices south of the border, up from 2003 despite a substantial
widening of the price differential between the Henry Hub and the AECO-C spot
price.  In
the Canadian downstream sector, refined petroleum product sales grew by about
4%, compared to 4.8% in 2003. Refining margins improved again in 2004, largely
in response to bottlenecks in the North American refining system. The system
continues to be stretched to its limit by a combination of growing refined
product demand and increasingly stringent mandated product specifications. As
well, record light/heavy crude price differentials contributed to downstream
margin improvements.  Commodity Price Indicators and Exchange Rates  (averages for the years
  indicated)
  
  2004
  
  2003Crude oil price indicators(per
  barrel):Dated Brent at Sullom Voe
  
  US$
  38.21
  
  28.84WTI at Cushing
  
  US$
  41.40
  
  31.04WTI/Brent price
  differential
  
  US$
  3.19
  
  2.20Brent/Maya price differential
  
  US$
  8.20
  
  4.60Edmonton Light
  
  Cdn$
  52.78
  
  43.77Edmonton Light/Lloydminster
  Blend (heavy) price differential
  
  Cdn$
  17.07
  
  12.68Natural gas price
  indicators:Henry Hub  per MMBtu
  
  US$
  6.09
  
  5.44AECO-C spot  per Mcf
  
  Cdn$
  7.08
  
  6.99Henry Hub-AECO-C basis
  differential  per MMBtu
  
  US$
  0.87
  
  0.70New York Harbor 3-2-1
  refinery crack spread  per bbl
  
  US$
  7.02
  
  5.31US$ per Cdn$ exchange rate
  
  US$
  0.768
  
  0.714  3


OUTLOOK FOR
BUSINESS ENVIRONMENT IN 2005  Prices for energy commodities
are expected to remain volatile in 2005, reflecting the vagaries of weather,
the changing level of industry inventories, and political and natural events.
Slower global oil demand growth combined with non-OPEC production gains are
expected to ease the upward pressure experienced by oil prices during 2004. The
extent of the anticipated price correction depends on OPEC decisions on
production cuts designed to prevent prices from declining as global demand
conditions weaken.  The
North American natural gas supply/demand balance is also expected to slacken in
2005. Little or no demand growth is forecast as a result of unseasonably warm
winter weather and strong inter-fuel competition in the industrial and power
generation sectors. These factors, combined with the industrys ability to slow
anticipated production declines in North America, will maintain North American
gas in storage at higher than historical levels. These dynamics are anticipated
to relieve some of the upward pressure on natural gas prices experienced in
2004.  In
the industrys downstream sector, refining margins are unlikely to remain at
the high levels experienced in 2004. This is because refined product demand
growth is expected to slow. Also, refineries are expected to rebuild product
inventories as supply bottlenecks are dealt with and progress is made to meet
mandated product specifications.  While
volatility in the market will continue, a number of factors are expected to put
downward pressure on strong crude oil and natural gas prices, as well as
refining margins in 2005.  ECONOMIC
SENSITIVITIES  The following table shows the
estimated after-tax effects that changes in certain factors would have had on
Petro-Canadas 2004 net earnings, had these changes occurred. These
calculations are based on business conditions, production and sales volumes
realized in 2004.  Sensitivities
Affecting Net Earnings  Factor(1),(2)
  
  Change (+)
  
  Annual Net
  Earnings Impact
  
  Annual Net
  Earnings Impact(millions of dollars)
  
  ($ per share)UpstreamPrice received for crude
  oil and liquids(3)
  
  $
  1.00/bbl
  
  45
  
  0.17Price received for natural
  gas
  
  $
  0.25/Mcf
  
  33
  
  0.12Exchange rate: $Cdn per $US
  refers to impact on upstream earnings from operations
  
  $
  0.01
  
  (22
  )
  (0.08
  )Crude oil and liquids
  production
  
  1,000 b/d
  
  5
  
  0.02Natural gas production
  
  10 MMcf/d
  
  9
  
  0.03Buzzard derivative
  contracts (unrealized)(4)
  
  $
  1.00/bbl
  
  (17
  )
  (0.06
  )DownstreamNew York Harbor 3-2-1 crack
  spread
  
  $
  0.10 US/bbl
  
  4
  
  0.02Light/heavy crude price
  differential
  
  $
  1.00/bbl
  
  11
  
  0.04CorporateExchange rate: $Cdn per $US
  refers to impact of the revaluation of U.S. dollar-denominated, long-term
  debt(5)
  
  $
  0.01
  
  9
  
  0.03  
 (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. (2)The impact of these factors is illustrative. (3)This sensitivity is based upon an equivalent
change in the price of WTI and North Sea Brent. (4)This refers to gains or losses on the forward
sales contracts for the future sale of 35.8 million barrels of Brent crude oil
that were entered into in connection with the Companys acquisition of an
interest in the Buzzard field in the U.K. sector of the North Sea. (5)This refers to gains or losses on $869 million
US of the Companys U.S. denominated long-term debt and interest costs on U.S.
denominated debt. Gains or losses on $1 billion US of the Companys U.S.
denominated long-term debt, associated with the self-sustaining International
business segment and the U.S. Rockies operations included in the North American
Natural Gas business segment, are deferred and included as part of shareholders
equity.  4


Q: What capabilities does
Petro-Canada have that makes the Company confident it can execute its business
strategy and differentiate itself from its peers?  A: Petro-Canada
has a unique breadth of skills due to its integrated portfolio of businesses.
The Company continues to strengthen its capabilities through a focus on Q1
initiatives.  Internal Capabilities  As an integrated oil and gas
company, Petro-Canada has a diverse set of skills and capabilities, the depth
and breadth of which are somewhat unique for its size. To continue to improve
and expand on this competitive advantage, the Company is committed to a Q1
(first quartile) mindset, action plans and performance measures. Petro-Canada
defines Q1 as:  improving operating performance to first
quartile levels (top 25%) relative to benchmarked peers and best-in-class
practices; efficiently
using resources to manage controllable costs despite the growing complexity and
scope of the business; seeking
integration opportunities across businesses and functional areas for added
value; and providing
leadership which creates the work environment required for employees to excel.  Each of the businesses and
Shared Services areas has Q1 action plans and performance measures. For example
in East Coast Oil, a best practices initiative identifies process and technical
opportunities to improve performance at Terra Nova. In the Downstream business,
where the Q1 mindset originated, a scorecard is a key tool in maintaining
employee focus on Q1 performance. Similar initiatives are also in the other
business units.  The
Finance unit was the first area of Shared Services to implement a Q1
initiative. The goal of this initiative is to be a value adding partner and
trusted advisor for the business units and Shared Services units. In 2004, the
Human Resources and Environment, Health and Safety units also started formal Q1
initiatives.  The
Company recognizes it must continue to add breadth and depth of capability to
sustain the base business and ensure profitable growth. To this end, the Human
Resources Strategy addresses three key areas: effectively managing talent,
improving human resources operational excellence, and supporting international
and domestic business growth.  The
Companys stated values are to be results-focused, decisive, trustworthy,
professional and respectful. Petro-Canada believes it is important to build and
maintain principle-based relationships with stakeholders. The Company works
toward this goal with an active and ongoing stakeholder consultation process
based on open, two-way communication with a genuine interest in understanding
stakeholder interests and concerns.  This
Q1 commitment, from improving capability to seeking integration opportunities,
is embedded in Petro-Canadas business strategy.  5


Q: What is Petro-Canadas
business strategy?  A: The Companys
strategy is to create shareholder value by improving the profitability of the
base business and by delivering long-term, profitable growth.  Business Strategy  The Company is improving the
profitability of the base business by selecting the right assets and driving for
Q1 performance. Long-term, profitable growth will be delivered by:  expanding
and exploiting the current portfolio of assets; targeting
acquisitions and new opportunities with a focus on long-life assets; and developing
an exploration program which balances risks and rewards to replace reserves
over time.  In applying this strategy,
Petro-Canada remains financially disciplined to retain the capacity and
flexibility to sustain and grow the business.  In
the upstream businesses, the Company believes it is unlikely rising North
American demand for natural gas will be completely met through conventional
production in the future. Petro-Canada is developing new sources of North
American natural gas supply  unconventional gas, gas to fill the proposed northern
pipelines and gas supplied through liquefied natural gas (LNG) technology. The
East Coast Oil and Oil Sands businesses are also contributing volumes to meet
North American demand. Petro-Canada is stepping out from established
international platforms to access undeveloped reserves to supply growing global
markets. In the Downstream business, the Company is leveraging the shift to
cleaner fuels and a heavier oil supply by converting refineries to produce
low-sulphur products from heavier crude slates and continuing to develop
high-quality lubricants.  Petro-Canadas
balanced portfolio provides opportunities for growth, a natural hedge against
changing circumstances and integration among businesses for greater potential
value. The Company applies its diverse set of internal skills to implement the
business strategy.  Over
time, the Company expects that the outcomes of implementing its business
strategy will be:  a
continued focus on profitability; a
shift to higher netback production; longer-life
assets that will increase reserve life; a balanced
exploration program; long-term
upstream production growth; and a
solid balance sheet with financial flexibility.  6


Risk Management  PETRO-CANADAS
RISK PROFILE  Petro-Canadas results are
impacted by managements strategy for handling risks in the business. These
risks fall into four broad categories: business risks; operational risks;
political risks; and market risks.  Management
believes each major risk requires a unique response based on Petro-Canadas
business strategy and financial tolerance. While some risks can be effectively
managed through internal controls and business processes, others are managed
through insurance and hedging. The Audit, Finance and Risk Committee of the
Board of Directors has responsibility to oversee 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 the ability to offset natural declines as
reserves are produced. Reserves can be added through successful exploration or
acquisitions; however, as basins mature, replacement of reserves becomes more
challenging and expensive. In some areas, the Company may choose to allow
reserves to decline if replacement is uneconomic. In 2004, the Company replaced
96% of its production on a proved reserves basis, compared to 59% in 2003. The
Company targets to fully replace proved reserves over a five-year period. Petro-Canadas
five-year proved replacement ratio was 150%.(1)  There
is no assurance Petro-Canada will successfully replace all produced reserves in
any given year.  ReservesEstimates  Estimates of economically
recoverable oil and gas reserves are based upon a number of variables and
assumptions that include geo-scientific interpretation, commodity prices,
operating and capital costs, and historical production from properties.  Petro-Canada
has well-established, corporate-wide reserves booking practices that have been
continuously improved for more than a decade. PricewaterhouseCoopers LLP, as
contract internal auditor, has tested the non-engineering control processes
used in establishing reserves. As well, independent engineering firms assess a
significant portion of reserves estimates every year. Over time, this means all
of Petro-Canadas reserves estimates are assessed by external evaluators. The
Board of Directors also reviews and approves the Companys annual reserves
filings. More information on reserves booking practices can be found in the
Companys Annual Information Form.  Project
Execution  Petro-Canada manages a number
of different-sized projects to support continuing operations and future growth.
Many projects are influenced by external factors beyond the Companys control.
These include items such as material costs, labour productivity, timely
availability of skilled labour and currency fluctuations.  While
Petro-Canada cannot control all project inputs, the Company is committed to
continuing to improve its project management capability. Petro-Canadas goal is
to consistently and predictably deliver projects on time and on budget, and
achieve defined expectations. Enhanced project management capability is
expected to improve all elements of project execution including safety and
environmental performance, quality, cycle-time and cost. Leveraging experience
gained from major project developments, the Company established project
management best practices.  
 (1)Proved reserves replacement ratio is calculated
by dividing the year-over-year net change in proved reserves before deducting
production by the annual production during the year. The reserves replacement
ratio is a general indicator of the Companys reserves growth. It is only one
of a number of metrics which can be used to analyze a companys upstream
business.  7


Non-Operated
Interests  Other companies may manage
the construction or operation of assets in which Petro-Canada has a significant
interest. Business assets in which Petro-Canada has a major interest, but does
not operate, include Hibernia (20% interest), Syncrude (12% interest), White
Rose (27.5%) and the newly acquired Buzzard (29.9% interest). Major projects
are managed through different forms of joint-venture executive committees,
resulting in Petro-Canada having some ability to influence these projects. As
well, Petro-Canada has joint-venture or other operating agreements which
specify its expectations from third-party operators. Nevertheless, third-party
operation and management of the Companys assets could adversely affect
Petro-Canadas financial performance.  Environmental
Regulations  Environmental risks in the
oil and gas industry are significant. This is because related laws and
regulations are becoming more stringent in Canada, and in other countries where
Petro-Canada operates. Due to increased regulations, Petro-Canada is investing
additional capital to satisfy new product specifications and/or address
environmental issues. In 2005, the Company will invest $635 million of its
capital program toward regulatory compliance, most of which will be to modify
refineries to produce low-sulphur distillate. Other environmental regulations
may result in future increased operating costs as a result of creating a future
liability when dismantling or remediating assets.  Petro-Canada
conducts Life-Cycle Value Assessments (LCVA) to integrate and balance
environmental, social and economic decisions related to major projects. A key
component of the LCVA process is to assess and plan for all life-cycle stages
involved in constructing, manufacturing, distributing and eventually abandoning
an asset or a product. This process encourages more comprehensive exploration
of alternatives. The LCVA is a useful technique; however, its predictive
capability is limited by the reliance on the current regulatory regime or one
that can be reasonably expected.  Emission of
Greenhouse Gases  The Kyoto Protocol, ratified
by the Government of Canada in December 2002 and effective as of February 16,
2005, requires signatory nations to reduce their emissions of carbon dioxide
and other greenhouse gases. As a result, Petro-Canada may be required to reduce
emissions of greenhouse gases from operations or purchase emission trading
credits. While the details of implementation of the Kyoto Protocol in Canada
have not been finalized, the impact to Petro-Canada could be higher capital
expenditures and operating expenses. The Government of Canada may also impose
higher vehicle fuel efficiency standards. The impact of this action could be to
decrease the demand for gasoline and diesel fuels sold by Petro-Canada and
depress the Companys margins for refined products.  Petro-Canada
is committed to reducing emissions. Additional detail will be available in the
Report to the Community in the second quarter of 2005. The Report will be
posted on www.petro-canada.ca. Through industry organizations, Petro-Canada
continues to work with a number of regulatory groups and government associations
to find a cost-effective approach which will minimize the negative financial
impact of the Kyoto Protocol on the Company while still reducing emissions. The
level of influence these discussions and cooperative efforts have on the
Government of Canadas implementation plan may be quite limited.  8


Government
Regulations  Petro-Canadas operations are
regulated by, and could be intervened upon by, a variety of governments around
the world. Governments could impact contracting of exploration and production
interests, impose specific drilling obligations, and possibly expropriate or
cancel contract rights. Governments may also regulate prices of commodities or
refined products, or intervene through taxes, royalties and exploration rights.  Petro-Canada
tries to mitigate the impact of government regulations by selecting operating
environments with stable governments. To date, Petro-Canada has had a
cooperative relationship with its regulators and the governments in the
countries in which it operates. Most of the contact with regulators occurs
through the Companys management, regulatory affairs personnel in each business
unit and a centralized corporate government relations function. Petro-Canada
aims to have regular, constructive communication with regulators and
governments so issues can be resolved in a mutually acceptable fashion. The
Company also has a strong record of regulatory compliance within the
jurisdictions it operates. Petro-Canada operates in many different
jurisdictions and derives revenue from several categories of products. This
diversification makes financial performance less sensitive to the action of any
single government. Nevertheless, Petro-Canada has limited ability to influence
regulations which may have a material adverse effect on the Company.  Counterparties  In the normal course of
business, Petro-Canada is exposed to credit risk resulting from the uncertainty
of business partners or counterparties ability to fulfill their obligations.
The Company has established internal credit policies and procedures that
include financial assessments, exposure limits and processes to monitor and
minimize the exposures against these limits. Where appropriate, Petro-Canada
also uses netting and collateral arrangements to minimize risk.  OPERATIONAL
RISKS  Exploring for, developing,
producing, refining, transporting and marketing oil, natural gas and refined
products involve significant operational hazards. These risks include well
blowouts, fires, explosions, gaseous leaks, migration of harmful substances and
oil spills. Any of these operational incidents could cause personal injury,
environmental contamination, or damage and destruction of the Companys assets.
These incidents could also interrupt production.  Petro-Canada
manages operational risks primarily through a Total Loss Management (TLM)
system and a corporate insurance program. TLM is an internally developed
management system based on external best practices with standards for
preventing operational incidents. Regular TLM audits test compliance with these
standards. The corporate insurance program transfers the impact of some
operational risks to third-party insurers worldwide. 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 used to
manage total premium cost. Although Petro-Canada maintains insurance in line
with customary industry practices, the Company cannot fully insure against all
risks. Losses resulting from operational incidents could have a material
adverse impact on the Company.  9


POLITICAL
RISKS  Petro-Canada operates in a
number of countries that have varying political, economic and social systems.
As a result, the Companys operations and related assets are subject to
potential risks from actions by governmental authorities or internal unrest.
Petro-Canada also operates in OPEC-member countries and production in those
countries is constrained by OPEC quotas.  The
Company continually evaluates exposure in any one country in the context of
total operations. Investment may be limited to avoid excessive exposure in any
one country or region. The Company also uses financial products to partially
mitigate some political risks.  MARKET RISKS  More detailed quantification
of the impact of some of the following risks can be found in the earnings
sensitivity chart on page 4 of the Business Environment in the MD&A.  Commodity Prices  In Petro-Canadas upstream
businesses, a significant market risk exposure is the changing commodity prices
of crude oil and natural gas. Commodity prices are volatile and influenced by
factors such as supply and demand fundamentals, geopolitical events, OPEC
decisions and weather. In 2004, the monthly average Brent crude oil price
ranged between $30.83 US/bbl and $49.64 US/bbl, and the AECO-C hub index ranged
between $5.93/Mcf and $8.35/Mcf. These commodity prices also impact the refined
products margins realized by the Downstream business, another significant
market risk. In 2004, the benchmark monthly average New York Harbor 3-2-1
refinery crack spread per bbl ranged from $4.23 US to $11.41 US. Petro-Canadas
ability to maintain product margins in an environment of higher feedstock costs
is contingent upon the Companys ability to flow higher costs through to
customers.  Petro-Canada
generally does not hedge large volumes of production. Management believes
commodity prices are volatile and difficult to predict. The business is managed
so that the Company can substantially withstand the impact of a lower price
environment, while maintaining the opportunity to capture significant upside
when the price environment is higher. However, commodity prices and margins may
be hedged occasionally to capture opportunities that represent extraordinary
value and to ensure the economic value of an acquisition. For example, as part
of the Companys acquisition of an interest in the Buzzard field in the U.K.
sector of the North Sea, the Company entered into a series of derivative
contracts related to the future sale of Brent crude oil (see Derivative
Instruments page 11 of the MD&A). Certain Downstream physical transactions
are routinely hedged for operational needs and to facilitate sales to
customers.  10


Foreign
Exchange  As energy commodity prices
are primarily priced in U.S. dollars, a large portion of Petro-Canadas revenue
stream is affected by the Canada/U.S. exchange rate. As a result, the Companys
earnings are negatively affected by a strengthening Canadian dollar. The
Company is also exposed to fluctuations in other foreign currencies, such as
the Euro and the British Pound.  Generally,
Petro-Canada does not hedge foreign exchange exposures, although the Company
partially mitigates the U.S. dollar exposure by denominating the majority of
its debt obligations in U.S. dollars. Foreign exchange exposure related to
asset acquisitions or divestitures, or project capital expenditures, may be
hedged on a case-by-case basis.  Interest
Rates  Petro-Canada targets a blend
of fixed and floating rate debt. Generally, this enables the Company to take
advantage of lower interest rates on floating debt, while matching overall debt
maturities with the life of cash-generating assets. The Company is exposed to
fluctuations in the rate of interest it pays on floating rate debt.  This
interest rate exposure is within the Companys risk tolerance.  Derivative 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 and the effectiveness of the derivative instrument
in offsetting a change in the value of the hedged exposure is assessed on a
regular basis.  Effective
January 1, 2004, the Company elected to discontinue hedge accounting for
certain hedging programs. All derivatives that do not qualify as a hedge, or
are not designated as a hedge, are accounted for using the mark-to-market
accounting method. These derivatives are recorded in the balance sheet as
either an asset or liability, with the fair value recognized in earnings. As a
result, the realized and unrealized values of these transactions are recognized
in Investment and Other Income.  During
2004, as part of the Companys acquisition of an interest in the Buzzard field,
the Company entered into a series of derivative contracts related to the future
sale of Brent crude oil. The purpose of these transactions was to ensure
value-adding returns to Petro-Canada on this investment, even in the event of a
material decrease in oil prices. These contracts effectively lock in an average
forward price of approximately $26 US/bbl on a volume of 35,840,000 barrels.
This volume represents approximately 50% of the Companys share of estimated
plateau production in the 2007 to 2010 time frame. As at December 31, this
hedge had a mark-to-market unrealized loss of $205 million after-tax which was
recognized in net earnings in 2004.  In
2004, other commodity hedges in place for refining supply and product purchases
resulted in a net decrease in earnings of about $1 million after-tax, which
included a mark-to-market unrealized gain as at December 31 of $3 million
after-tax. This compared with a net decrease in earnings of about $30 million
in 2003, which related to commodity hedges, interest rate hedges and currency
hedges.  11


Q: What was Petro-Canadas
financial performance in 2004?  A: In 2004,
Petro-Canada achieved record earnings from operations of $1.9 billion and
record cash flow of $3.7 billion.  Shareholder
Value  Shareholder value measures the change in the Petro-Canada share price
plus dividend returns.    Consolidated Financial
Results  ANALYSIS OF
CONSOLIDATED EARNINGS AND CASH FLOW  Consolidated
Financial Results  (millions of dollars, unless
  otherwise indicated)
  
  2004
  
  2003
  
  2002Net earnings
  
  $
  1,757
  
  $
  1,650
  
  $
  955Gain (loss) on foreign
  currency translation
  
  63
  
  239
  
  (52
  )Unrealized loss on Buzzard
  derivative contracts
  
  (205
  )
  
  
  Gain on sale of assets
  
  11
  
  29
  
  2Earnings from operations(1),(3)
  
  $
  1,888
  
  $
  1,382
  
  $
  1,005Income tax adjustment
  
  13
  
  45
  
  Edmonton refinery
  conversion provision
  
  
  
  (82
  )
  Kazakhstan impairment
  
  
  
  (46
  )
  International provisions
  
  
  
  45
  
  Oakville closure costs
  
  (46
  )
  (151
  )
  Terra Nova insurance
  proceeds
  
  31
  
  17
  
  Earnings from operations
  excluding adjustments for one-time and unusual items
  
  $
  1,890
  
  $
  1,554
  
  $
  1,005Earnings per share(dollars)
   basic
  
  $
  6.64
  
  $
  6.23
  
  $
  3.63 diluted
  
  6.55
  
  6.16
  
  3.59Cash flow from operating
  activities before changes in non-cash working capital(2), (3)
  
  3,747
  
  3,372
  
  2,276Cash flow from operating
  activities before changes in non-cash working capital per share(dollars)
  
  14.16
  
  12.73
  
  8.66Debt
  
  2,580
  
  2,229
  
  3,057Cash and cash equivalents
  
  170
  
  635
  
  234Average capital employed
  
  $
  10,533
  
  $
  9,268
  
  $
  7,722Return on capital employed (%)
  
  17.5
  
  19.0
  
  13.8Operating return on capital
  employed(%)
  
  18.8
  
  16.1
  
  14.5Return on equity(%)
  
  21.5
  
  24.9
  
  18.3  
 (1)Earnings from operations, which represent net
earnings excluding gains or losses on foreign currency translation and on
disposal of assets and the unrealized gains or losses associated with the Buzzard
derivative contracts, is used by the Company to evaluate operating performance. (2)Cash flow, which is expressed before changes
in non-cash working capital items relating to operating activities, 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 GAAP and, therefore, may
not be comparable with the calculation of similar measures for other companies.  12


2004
COMPARED WITH 2003  Earnings from operations
adjusted for one-time and unusual items rose 22% to $1,890 million in 2004.
Earnings were positively impacted by strong commodity prices and refining
margins, as well as lower exploration expense and interest charges. These
factors were partially offset by lower upstream volumes, higher operating costs
and a stronger Canadian dollar.  In 2004, earnings from
operations included a number of one-time and unusual items: a $46 million
charge for additional depreciation and other charges related to the
consolidation of Eastern Canada refinery operations and the closure of the
Oakville refinery; $31 million of insurance proceeds related to the delayed
start-up of Terra Nova; and a $13 million positive adjustment to future income
taxes reflecting announced changes to Canadian provincial income tax rates.  In
2003, earnings from operations included a number of one-time and unusual items:
a $151 million charge for additional depreciation and other charges related to
the consolidation of Eastern Canada refinery operations and the closure of the
Oakville refinery; an $82 million charge related to the original conversion
plan at the Edmonton refinery; a $46 million provision related to the
impairment of assets in Kazakhstan; a $45 million positive adjustment in
International related to the clarification of production rights and a tax
provision of a former operation; a $45 million net positive adjustment to
future income taxes reflecting announced changes to Canadian federal and
provincial income tax rates; and $17 million of insurance proceeds related to
the delayed start-up of Terra Nova.  Net
earnings in 2004 were $1,757 million, up 6% from $1,650 million in 2003. Net
earnings include gains or losses on foreign currency translation and on
disposal of assets and an unrealized loss on Buzzard derivative contracts.  Operating
Return on Capital Employed  Operating
return on capital employed increased by 2.7% in 2004.    2004 VERSUS
2003 FACTOR ANALYSIS  Earnings
from Operations Excluding Adjustments for One-time and Unusual Items    
 (1) Other
mainly includes interest expense and changes in effective tax rates and
upstream inventory levels.  Consolidated 2004 cash flow
was $3,747 million, compared with $3,372 million in 2003. The increase in cash
flow reflects higher earnings from operations partially offset by higher
current income taxes.  13


QUARTERLY
INFORMATION  Consolidated
Quarterly Financial Results  2004
  
  2003(millions of dollars, unless otherwise indicated)
  
  Quarter 1
  
  Quarter 2
  
  Quarter 3
  
  Quarter 4
  
  Quarter 1
  
  Quarter 2
  
  Quarter 3
  
  Quarter 4Total revenue
  
  $
  3,473
  
  $
  3,565
  
  $
  3,622
  
  $
  3,717
  
  $
  3,722
  
  $
  2,957
  
  $
  3,118
  
  $
  3,102Earnings from operations
  
  517
  
  471
  
  461
  
  439
  
  485
  
  451
  
  296
  
  150Net earnings
  
  513
  
  393
  
  410
  
  441
  
  579
  
  584
  
  289
  
  198Cash flow from operating
  activities before changes in non-cash working capital
  
  921
  
  885
  
  895
  
  1,046
  
  991
  
  874
  
  879
  
  628Earnings per share(dollars) basic
  
  $
  1.93
  
  $
  1.48
  
  $
  1.54
  
  $
  1.69
  
  $
  2.19
  
  $
  2.20
  
  $
  1.09
  
  $
  0.75 diluted
  
  $
  1.90
  
  $
  1.46
  
  $
  1.52
  
  $
  1.67
  
  $
  2.16
  
  $
  2.17
  
  $
  1.08
  
  $
  0.74  Variances from quarter to
quarter in revenues and net earnings resulted mainly from: fluctuations in
commodity prices and refinery cracking margins; the impact on production and
processed volumes from maintenance and other shutdowns at major facilities; and
the level of exploration drilling activity. For further analysis of quarterly
results, refer to Petro-Canadas quarterly reports to shareholders available on
the Companys Web site at www.petro-canada.ca.  Q: How does Petro-Canada manage
its financial affairs?  A: Petro-Canada
maintains its financial strength and flexibility by targeting its debt levels
at 25% to 35% of total capital and a ratio of less than 2.0 times debt to cash
flow.  Liquidity and Capital
Resources  Summary of
Cash Flows  (millions of dollars)
  
  2004
  
  2003
  
  2002Net cash
  inflows (outflows) before changes in non-cash working capital:Operating activities
  
  $
  3,747
  
  $
  3,372
  
  $
  2,276Investing activities
  
  (4,709
  )
  (2,297
  )
  (4,141
  )Financing activities
  
  (19
  )
  (604
  )
  1,560(981
  )
  471
  
  (305
  )(Increase)
  decrease in non-cash working capital and other
  
  516
  
  (70
  )
  (242
  )Increase
  (decrease) in cash and cash equivalents
  
  $
  (465
  )
  $
  401
  
  $
  (547
  )Cash and
  cash equivalents at end of year
  
  $
  170
  
  $
  635
  
  $
  234  The Company
maintains solid investment-grade credit ratings.  14


The
improvement in cash flow before changes in non-cash working capital to $3,747
million in 2004 was primarily from higher earnings from operations partially
offset by higher current taxes.  The
increased cash outflow on investing activities reflected the Buzzard and U.S.
Rockies acquisitions.  The $117 million
decrease in non-cash working capital reflected higher accounts payable and
accrued liabilities along with income taxes payable, partially offset by higher
accounts receivable.  INVESTING
ACTIVITIES  Capital and
Exploration Expenditures  (millions of dollars)
  
  2005
  Outlook
  
  2004
  
  2003
  
  2002Upstream(1)North American Natural Gas
  
  $
  760
  
  $
  724
  
  $
  560
  
  $
  530East Coast Oil
  
  315
  
  278
  
  344
  
  289Oil Sands
  
  400
  
  399
  
  448
  
  462International
  
  825
  
  1,824
  (2)
  525
  
  2212,300
  
  3,225
  
  1,877
  
  1,502DownstreamRefining and Supply
  
  780
  
  656
  
  296
  
  210Sales and Marketing
  
  105
  
  171
  
  117
  
  118Lubricants
  
  35
  
  12
  
  11
  
  16920
  
  839
  
  424
  
  344Shared
  Services
  
  15
  
  9
  
  14
  
  15Total
  property, plant and equipment and exploration
  
  3,235
  
  4,073
  
  2,315
  
  1,861Deferred
  charges and other assets
  
  
  
  36
  
  147
  
  72Acquisition
  of oil and gas operations of Veba Oil & Gas GmbH (Veba)
  
  
  
  
  
  
  
  2,234Acquisition
  of Prima Energy Corporation
  
  
  
  644
  
  
  
  Total
  
  $
  3,235
  
  $
  4,753
  
  $
  2,462
  
  $
  4,167  
 (1)Includes exploration expenses charged to
earnings, totaling $235 million in 2004, $271 million in 2003 and $301 million
in 2002. (2)Includes $1,218 million for the Buzzard
acquisition.  Capital spending on property,
plant and equipment and exploration in 2004 reflected Petro-Canadas commitment
to long-term profitable growth and adding value for shareholders. The 76%
increase in expenditures to $4,073 million, up from $2,315 million in 2003, was
mainly due to the Buzzard acquisition and costs associated with the development
of the Buzzard project, the investments related to upgrading refineries to
produce cleaner-burning fuels, increased spending for the pursuit of attractive
opportunities in Western Canada and the acceleration of the Companys retail
re-imaging program.  Planned
investment for 2005, totaling $3,235 million, reflects a building year for
Petro-Canada. The focus on growth initiatives is expected to deliver new
production in 2006 and 2007. The 2005 capital expenditure program is expected
to be funded from cash flow and existing credit facilities.  FINANCING
ACTIVITIES AND DIVIDENDS  Financial Ratios
  
  2004
  
  2003
  
  2002Interest
  coverage(times):Earnings
  basis
  
  20.9
  
  16.6
  
  10.4EBITDAX
  basis
  
  31.0
  
  26.3
  
  17.1Cash flow
  basis
  
  33.0
  
  25.4
  
  17.9Debt to cash
  flow(times)
  
  0.7
  
  0.7
  
  1.3Debt-to-debt
  plus equity(%)
  
  22.8
  
  22.7
  
  35.1  Petro-Canadas debt to cash
flow ratio, the key short-term leverage measure, was 0.7 times as of December 31,
2004, unchanged compared to the prior year. The Company expects to remain well
within the target range of no more than 2.0 times throughout 2005. Debt-to-debt
plus equity, the long-term measure for capital structure, was 22.8% at year-end
2004, up slightly from 22.7% at the prior year end. This is well within the
target range of 25% to 35%. Petro-Canada has controls in place to ensure
compliance with all financial covenants.    2005
Capital Program (millions
of dollars)  Capital
program by investment priority:  Regulatory
  compliance: 635Enhancing
  existing assets: 130Improving
  base business profitability: 120Reserves
  replacement in core areas: 950New growth
  projects: 1,130Exploration
  and new ventures: 270  Key debt
ratios have remained relatively unchanged from 2003 levels notwithstanding the
significant investment program in 2004.  Interest
Coverage  The Companys positive interest
coverage ratio demonstrates more than sufficient earnings to cover interest
charges on debt.    15


Key Debt
Ratios  Petro-Canada
has the financial strength and flexibility to manage changing market dynamics
and pursue new growth opportunities.    Sources of
Capital Employed  (millions of dollars)
  
  2004
  
  2003
  
  2002Short-term notes payable
  
  $
  299
  
  $
  
  
  $
  Long-term debt, including
  current portion
  
  2,281
  
  2,229
  
  3,057Shareholders equity
  
  8,739
  
  7,588
  
  5,662Total
  
  $
  11,319
  
  $
  9,817
  
  $
  8,719  Total debt increased to
$2,580 million at December 31, 2004, compared with $2,229 million at the
previous year end. The increase in debt was associated with the activities
outlined in the financing activities section and general operating needs,
offset by a reduction of $182 million due to revaluation of the U.S.
dollar-denominated long-term debt. Short-term notes payable consisted of $70
million of U.S. dollar-denominated Canadian commercial paper and $215 million
in Canadian dollar-denominated Canadian commercial paper.  2004 Financing Activities  Petro-Canadas balance sheet
was put to use in support of business growth initiatives in 2004. During the
second quarter, the Company borrowed $210 million US under the syndicated
operating credit facilities to partially fund the acquisition of a 29.9%
interest in the Buzzard oilfield. The balance of the $887 million US
acquisition cost was funded with existing cash balances. All advances under the
syndicated operating credit facilities were repaid in the third quarter.  During
the third quarter, the Company borrowed $400 million US under an acquisition
credit facility to acquire all of the outstanding shares of Prima Energy
Corporation (referred to as the U.S. Rockies). The remainder of the total
acquisition price of $644 million, net of acquired cash, was funded using cash
on hand and short-term borrowings.  In
the fourth quarter of 2004, the Company issued $400 million US of 10-year
senior notes. The net proceeds were used to repay the U.S. Rockies acquisition
credit facility.  Also
during the year, Petro-Canada sold $400 million under a new accounts receivable
securitization program. A portion of the proceeds was used to repay the
remaining $293 million of advances under the acquisition credit facility that
funded the purchase of Veba in 2002.  In
addition to financing growth, the Company also had the capacity to create value
by returning capital to shareholders during the year. The TSX approved
Petro-Canadas application to make a normal course issuer bid for the repurchase
of up to 21 million of its common shares over the 12-month period ending June 21,
2005, subject to certain conditions. By year-end 2004, the Company had
repurchased and cancelled a total of 6,868,082 shares at an average price of
$65.02 per share for a total cost of approximately $447 million. Petro-Canada
intends to continue to repurchase shares when there is an opportunity to create
value.  For
operating purposes, Petro-Canada had cash and cash equivalents of $170 million
at year-end 2004. During 2004, the Company put in place new syndicated
operating credit facilities totaling $1,500 million to be used for general
corporate purposes. There were no draws on these facilities at year end;
however, they provide liquidity support to Petro-Canadas Canadian commercial
paper program. The Company will continue to use its cash position and will draw
on bank lines and issue commercial paper, as necessary, to meet working capital
and other financing requirements.  Petro-Canada
plans to meet remaining debt repayment commitments out of a combination of cash
flow and debt refinancing.  At
year-end 2004, the Companys unsecured long-term debt securities were rated
Baa2 by Moodys Investors Services, BBB by Standard & Poors Rating
Services and A (low) by Dominion Bond Rating Service. These ratings remained
unchanged from year-end 2003.  Excluding
cash and cash equivalents, short-term notes payable and the current portion of
long-term debt, Petro-Canada had an operating working capital deficiency of
$777 million as at December 31, 2004, compared with an operating working
capital deficiency of $52 million at the end of 2003. The working capital
deficiency increase was primarily due to the accounts receivable securitization
program and higher accounts payable resulting from higher commodity prices and
capital accruals.  Off-balance
sheet activities are limited to matters such as the accounts receivable
securitization program, which does not meet the criteria for consolidation and
guarantees. None of these would have a material impact on the Companys
financial results, liquidity or capital resources.  At
year-end 2004, Petro-Canadas defined benefits pension plans were under-funded
by $330 million, compared with an under-funded position of $292 million at
year-end 2003. In 2004, Petro-Canada made  16


cash
contributions of $93 million to the pension plans and recorded a pension
expense of $71 million before tax. This compares with $86 million of cash
contributions and $72 million of pension expense, respectively, for 2003. In
2005, the Company expects to make pension contributions of approximately $95
million.  The following table summarizes Petro-Canadas contractual obligations
as at December 31, 2004.  Contractual
Obligations  Summary  PAYMENTS DUE BY PERIOD(millions of dollars)
  
  Total
  
  2005
  
  2006-2007
  
  2008-2009
  
  2010 and
  thereafterUnsecured debentures and
  senior notes(1)
  
  $
  4,774
  
  $
  137
  
  $
  277
  
  $
  277
  
  $
  4,083Short-term notes payable(1)
  
  299
  
  299
  
  
  
  
  
  Capital lease
  obligations(1)
  
  178
  
  17
  
  34
  
  21
  
  106Operating leases
  
  650
  
  122
  
  182
  
  129
  
  217Transportation agreements
  
  1,302
  
  198
  
  329
  
  256
  
  519Product purchase/delivery
  obligations(2)
  
  1,561
  
  83
  
  234
  
  172
  
  1,072Exploration work
  commitments(3)
  
  119
  
  60
  
  53
  
  6
  
  Asset retirement
  obligations
  
  2,417
  
  72
  
  126
  
  55
  
  2,164Other long-term
  obligations(4),(5)
  
  2,059
  
  123
  
  7
  
  154
  
  1,775Total contractual obligations
  
  $
  13,360
  
  $
  1,111
  
  $
  1,242
  
  $
  1,070
  
  $
  9,936  
 (1)Obligations include related interest. For
further details see Note 17 to the 2004 Consolidated Financial Statements. (2)Excludes supply purchase agreements contracted
at market prices, where the products could reasonably be re-sold 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 Petro-Canada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
sections of the 2004 MD&A. (4)Includes processing agreement with Suncor
Energy Inc., receivables securitization program, pension funding obligations
for the periods prior to the Companys next required pension plan valuation and
other obligations. Pension obligations beyond the next required pension
valuation date were excluded due to the uncertainty as to the amount or timing
of these obligations. (5)Petro-Canada 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.  During 2004, Petro-Canadas
total contractual obligations increased by approximately $7,700 million, mainly
due to finalization of an agreement with Suncor Energy Inc. for the processing
of future bitumen production, an increase in debt levels associated with the
U.S. Rockies acquisition, obligations relating to the accounts receivable
securitization and the inclusion of obligations relating to interest and asset
retirements, which were previously excluded.  Dividend
Strategy  From time to time,
Petro-Canada reviews its dividend strategy to ensure the alignment of dividend
policy with shareholder expectations and financial and growth objectives.
Currently, the Companys first priority for available cash is to fund
profitable growth opportunities. The second priority is to return funds to
shareholders through dividends and share buyback programs. Commencing with the
second quarter dividend paid on April 1, 2004, the Company increased the
quarterly dividend 50% to $0.15 per share. Total dividends paid in 2004 were
$159 million, compared with $106 million in 2003.  Government Public Offering  In September 2004, the
Government of Canada completed the public offering of its remaining 19%
interest in the Company. The government sold approximately 49 million
Petro-Canada common shares at a price of $64.50 per share, resulting in total
gross proceeds to the government of approximately $3.2 billion.  UPSTREAM  Petro-Canadas
upstream operations consist of four business segments: North American Natural
Gas, with current production in Western Canada and the U.S. Rockies; East Coast
Oil, with three major developments offshore Newfoundland and Labrador; Oil Sands
operations in Northeastern Alberta; and International, where the Company is
active in three core areas: Northwest Europe; North Africa/Near East; and
Northern Latin America. The diverse asset base provides a balanced portfolio
and a platform for long-term growth.  Petro-Canada
increased its dividend by 50% in 2004.  17


Q: How is Petro-Canada going to
profitably replaceNorth
American Natural Gas production?  A: Our plans include continuing the
exploitation of our conventional assets, stepping out to unconventional
production, advancing our liquefied natural gas (LNG) strategy and developing
the frontier regions.  The Hanlan Robb natural gas
plant in the Foothills region of Alberta.      The Wildcat Hills natural gas
plant.  North American Natural Gas  BUSINESS SUMMARY AND STRATEGY  North
American Natural Gas has a long history of exploring for and producing natural
gas, crude oil and natural gas liquids in Western Canada. This business also
markets natural gas in North America, has established resources in the
Mackenzie Delta/Corridor and has landholdings in Alaska. In 2004, the business
expanded into unconventional production and signed an agreement to develop a
proposed LNG re-gasification facility in Quebec.  The
North American Natural Gas strategy is to be a significant and sustainable
market participant by accessing new and diverse natural gas supply sources in
North America. Key features of the strategy include:  continuing exploration and
development in existing Western Canada conventional areas; increasing focus on unconventional production in the
U.S. Rockies and Western Canada; developing LNG import
capacity in North America; and building the northern resource base for long-term
growth.  18


North
American Natural Gas Financial Results  (millions of dollars)
  
  2004
  
  2003
  
  2002Net
  earnings
  
  $
  500
  
  $
  492
  
  $
  168Gain (loss)
  on sale of assets
  
  
  
  33
  
  (1
  )Earnings
  from operations
  
  $
  500
  
  $
  459
  
  $
  169Income tax
  adjustment
  
  7
  
  10
  
  Earnings
  from operations excluding adjustments for one-time and unusual items
  
  $
  493
  
  $
  449
  
  $
  169Cash flow
  from operating activities before changes in non-cash working capital
  
  $
  940
  
  $
  985
  
  $
  534Expenditures
  on property, plant and equipment and exploration
  
  $
  724
  
  $
  560
  
  $
  530Total assets
  
  $
  3,477
  
  $
  2,341
  
  $
  2,285  2004
COMPARED WITH 2003  North American Natural Gas
contributed earnings from operations adjusted for one-time and unusual items of
$493 million in 2004, up 10% from $449 million in 2003. The increase was
largely driven by strong realized natural gas prices and acquired volumes from
the U.S. Rockies. These factors were partially offset by lower Western Canada
volumes and higher costs.  Net earnings from North
American Natural Gas were $500 million in 2004, up from $492 million in 2003.
Net earnings in 2004 included a $7 million positive adjustment to reflect a
reduction in provincial income tax rates. Net earnings in 2003 included a $33
million after-tax gain on the sale of assets and a $10 million positive
adjustment to reflect the changes in federal and provincial tax rates.  Natural
gas commodity prices and volumes remained strong in 2004. The realized natural
gas price averaged $6.72/Mcf, up 3% from $6.50/Mcf in 2003. Natural gas
production averaged 695 MMcf/d in 2004, up from 693 MMcf/d in 2003, as acquired
volumes from the U.S. Rockies offset lower volumes in Western Canada.
Conventional crude oil and natural gas liquids production averaged 15,300 b/d,
down from 16,900 b/d in 2003 due to the disposition of properties in 2003.  2004
Operating Review and Strategic Initiatives  North American Natural Gas
recorded solid operating results in 2004 from core areas in Western Canada and
the U.S. Rockies. In addition, Petro-Canada announced a proposal to jointly
develop an LNG re-gasification facility in Quebec and continued building its
resource position in the Far North.  Western
Canada continued to exploit conventional gas opportunities in four core areas 
the Alberta Foothills, Northeastern British Columbia, Southeastern Alberta and
West-Central Alberta. Western Canada natural gas production averaged 676
MMcf/d, down 2% from 693 MMcf/d in 2003. Exploration and development drilling
activity in Western Canada resulted in 564 gross successful wells, for a
success rate of 96% in 2004. Western Canada operating and overhead costs were
$0.85 per thousand cubic feet of natural gas equivalent (Mcfe) in 2004, up from
$0.71/Mcfe in the previous year. This increase reflected industry-wide cost
increases and higher turnaround costs.  During
2004, the North American Natural Gas business grew to include unconventional
gas operations and skills. In mid-2004, its footprint was extended into the
U.S. Rockies by acquiring Prima Energy Corporation (U.S. Rockies) for $644
million, net of acquired cash. This acquisition added 55 MMcfe/d primarily from
coal bed methane in the Powder River Basin and from tight gas in the
Denver-Julesburg basin and significant expertise in unconventional production.
The integration of this acquisition went smoothly in 2004.  In
Western Canada, the business unit also began pursuing unconventional
production. A dedicated team began developing tight gas opportunities east of
the Foothills of Alberta and in Northeast British Columbia. During 2004, 20
gross wells were drilled and approximately 70,000 gross acres of land were
acquired.  Western
Canada Operating and Overhead Costs  Western Canada
operating and overhead costs were largely driven by industry-wide cost
increases, lower volumes and higher turnaround costs.        Includes
Western Canada natural gas, conventional oil and natural gas liquids.   The U.S.
Rockies acquisition in 2004 provided expertise and growth opportunities in
unconventional gas.  19


North
American Natural Gas Annual Production    Crude Oil
and Natural Gas Liquids Annual Production    Petro-Canada
will continue to access new supply from three sources: unconventional gas; Far
North gas; and LNG projects.  Petro-Canada is seeking to
participate in the global LNG business with the objective to add long-life
producing assets to its portfolio. In September 2004, a Memorandum of
Understanding (MOU) was signed with TransCanada PipeLines Limited to develop
and share (50/50) ownership of a $660 million LNG facility at Gros-Cacouna,
Quebec. The proposed facility, targeted to be in service by late 2009, will
receive, store and re-gasify imported LNG. Petro-Canada will have 100% of the
send-out capacity of approximately 500 MMcf of natural gas per day.  Petro-Canada
also continued to position itself for long-term North American supply by accessing
Far North supply regions in advance of proposed northern pipeline projects. In
the Mackenzie Delta/Corridor region, plans for development of existing
discoveries of Tuk in the Mackenzie Delta and Tweed Lake and Bele in the
Colville area were advanced. The business also purchased an exploration licence
to add to its land base in the Corridor. In addition, a large land position was
acquired in the National Petroleum Reserve-Alaska, an area with significant
potential for large oil prospects.  Capital
expenditures in 2004 totaled $724 million, with $625 million for exploration
and development of natural gas in Western Canada, $26 million for U.S. Rockies
development and $73 million for other natural gas opportunities in North
America.  OUTLOOK  Production expectations in 2005: Western Canada production to average 630
MMcf/d of natural gas and 12,000 b/d of crude oil and natural gas liquids; U.S. Rockies production to average about 55
MMcfe/d.  Action plans: drill approximately 650 gross wells in Western
Canada in 2005; advance long-term opportunities in Northern
Canada and Alaska; file regulatory application for LNG facility
at Gros-Cacouna by mid-2005; double U.S. Rockies gas production by 2007.  Capital spending plans in 2005: $485 million to replace reserves in the
Western Canada core areas; $230 million for new unconventional growth
opportunities in Western Canada and the U.S. Rockies; $45 million to develop long-term supply opportunities in Alaska and the Mackenzie Delta/Corridor,
and to further the proposed Gros-Cacouna LNG re-gasification terminal.  The 2005 capital program of
approximately $760 million reflects a focus on replacing reserves in core areas
and continuing to develop tight gas and coal bed methane production capability.
Additional volumes from the U.S. Rockies are expected to largely offset, in the
medium term, the natural declines of Western Canada conventional natural gas
production. In the long term, supply from the Mackenzie Delta/Corridor, Alaska
and LNG projects is expected to play a growing role to meet North American
demand.  Western
Canada will continue to exploit core conventional areas. In the Foothills, the
business will capitalize on a strong technical and operating competency in deep
sour gas and is well positioned with its producing infrastructure.  In
the shallow gas region of Southeastern Alberta, production has steadily
increased over the last few years to 78 MMcf/d at 2004 year end. This success
is expected to continue as a result of a multi-year drilling program aimed at
doubling well space density from four to eight wells per section. In
Northeastern British Columbia, the business will continue to optimize and
selectively explore existing assets. In the West Central region, declines will
be managed through asset optimization and cost discipline.  In
2005, Western Canada intends to continue to pursue tight gas structures, with
plans to drill approximately 35 additional wells. The full value from the U.S.
Rockies acquisition will come from developing the large inventory of probable
reserves. Petro-Canada plans to double unconventional gas equivalent production
to 100 MMcfe/d by 2007.  20


Q:How is Petro-Canada going
  to sustain reliable and profitable East Coast production from these
  capital-intensive investments into the next decade?A:We have plans in place
  to achieve first quartile performance at existing platforms, add production
  through development of reservoir extensions, participate in White Rose and
  pursue new projects.The Petro-Canada operated
  Terra Nova FPSO produces oil on the Grand Banks offshore Newfoundland and
  Labrador.Workers on a support vessel
  prepare to tow an iceberg offshore Newfoundland and Labrador as part of the active
  ice management program.  East Coast Oil  BUSINESS SUMMARY AND STRATEGY  Petro-Canada is positioned
in every major oil development off Canadas East Coast. The Company is the
operator and holds the largest interest in Terra Nova (34%), and has a 20% interest
in Hibernia, the first Grand Banks development. Petro-Canada also holds a 27.5%
interest in the White Rose project, scheduled to be on-stream in 2006.  The East Coast Oil strategy
is to improve reliability and sustain profitable production well into the next
decade. Key features of the strategy include:  delivering top quartile safety
and operating performance; sustaining profitable production
through reservoir extensions and add-ons; and pursuing high potential
development projects.   21


East Coast Oil Operating and Overhead Costs  Operating and
overhead costs are effectively unchanged in 2004.    White Rose
will add approximately 25,000 b/d of production at plateau.  Petro-Canadas
Share of Hibernia and Terra Nova Production    East Coast
Oil Financial Results  (millions of dollars)
  
  2004
  
  2003
  
  2002Net
  earnings and earnings from operations
  
  $
  711
  
  $
  597
  
  $
  428Income tax
  adjustment
  
  3
  
  7
  
  Terra Nova
  insurance proceeds
  
  31
  
  17
  
  Earnings
  from operations excluding adjustments for one-time and unusual items
  
  $
  677
  
  $
  573
  
  $
  428Cash flow
  from operating activities before changes in non-cash working capital
  
  $
  996
  
  $
  869
  
  $
  687Expenditures
  on property, plant and equipment and exploration
  
  $
  278
  
  $
  344
  
  $
  289Total assets
  
  $
  2,265
  
  $
  2,288
  
  $
  2,249  2004
COMPARED WITH 2003  East Coast Oil contributed
earnings from operations adjusted for one-time and unusual items of $677
million in 2004, up 18% from $573 million in 2003. The earnings increase
reflected higher realized prices, partially offset by lower production.  Net earnings from East Coast
Oil were $711 million in 2004, up from $597 million in 2003. Net earnings in
2004 included a $3 million positive adjustment to reflect a reduction in
provincial income tax rates and $31 million of insurance proceeds related to
the delayed start-up of Terra Nova. Net earnings in 2003 included a $7 million
positive adjustment to reflect the changes in federal and provincial tax rates
and $17 million of insurance proceeds related to the delayed start-up of Terra
Nova.  East
Coast Oil realized crude prices averaged $48.39/bbl, up from $39.91/bbl in
2003.  Petro-Canadas share of East Coast Oil
production averaged 78,200 b/d, down from 86,100 b/d in 2003. The decrease was
largely due to lower production at Terra Nova.  East Coast Oil operating and overhead costs
averaged $2.89/bbl in 2004, effectively unchanged from $2.88/bbl in 2003.  2004
Operating Review and Strategic Initiatives  Petro-Canadas share of
Hibernias production averaged 40,800 b/d in 2004, up from 40,600 b/d in 2003.
The Hibernia platform continued to deliver first quartile operating
performance. As a result of better-than-expected reservoir performance, the
life of field reserves estimate increased from 835 MMbbls at year-end 2003 to
940 MMbbls at year-end 2004 at Hibernia, with Petro-Canadas share being 20%.  At Terra Nova, the Companys share of production averaged
37,400 b/d, down from 45,500 b/d in 2003. Both production and reliability
measures were significantly below target due to extended maintenance activities
and operating difficulties in the third and fourth quarters of 2004. During the
third quarter, volumes were impacted by a longer-than-expected turnaround for
repairs to the gas compression facilities. Further downtime occurred in the
fourth quarter for investigation and repairs following a discharge of oily
water. Following successful maintenance activities, production rates were
returned to normal levels during the last half of December. Terra Nova reached
simple royalty payout in 2004. Meeting this milestone in two-and-a-half years
is a good indication of the value created by this asset.  The next East Coast development to come on-stream
will be White Rose in early 2006, which will add approximately 25,000 b/d of
production. The project remained on budget and on schedule in 2004, and
key project milestones included: arrival of the Sea Rose Floating Production,
Storage and Offloading (FPSO) hull in Newfoundland and Labrador; fabrication
and lifting of the topsides modules onto the hull of the FPSO; initiation of
the marine construction program offshore; and drilling of the first five
development wells with pre-commissioning activities under way.  In 2004, capital expenditures for exploration and
development of crude oil offshore Canadas East Coast were $278 million,
including $155 million related to the development of the White Rose oilfield.  22


OUTLOOK  Production
expectations in 2005: East Coast
Oil production is expected to average 77,000 b/d, reflecting planned
turnarounds.  Growth
plans: achieve first
quartile operating performance at Terra Nova; begin
development drilling of Terra Novas Far East block; submit
development plans for Hibernias Ben Nevis Avalon formation; complete
White Rose development for early 2006; continue
discussions on a Joint Operating Agreement with the partners of the potential
Hebron project.  Capital
spending plans in 2005: Approximately
$125 million will be spent on drilling to replace reserves at Hibernia and
Terra Nova, and developing Terra Novas Far East block and the Ben Nevis Avalon
reservoir at Hibernia. Approximately
$190 million will be spent to bring the White Rose project on-stream in early
2006, adding 25,000 b/d net to Petro-Canada at peak production.  From a reliability
perspective, Petro-Canada plans to achieve first quartile reliability and operating
costs at Terra Nova during 2006. In 2005, a four-week planned turnaround will
perform regulatory inspections on equipment and do work to improve the
reliability of the gas compression and injection systems. These areas were the
main cause of downtime over the past couple of years. The Hibernia platform
will also have a one-week turnaround in 2005.  While
royalty rates at Hibernia remained relatively constant in 2004, Terra Nova
royalty rates increased to 5% in mid-2004 due to the simple royalty payout
achieved. Further increases in royalty rates will occur in line with the
projects profitability-sensitive royalty regime. Terra Nova royalties are
forecast to average about 12% in 2005.  The
business will continue development drilling in the main fields, with plans to
bring on the Far East block at Terra Nova and to expand production from the Ben
Nevis Avalon reservoir at Hibernia. East Coast Oil volumes are expected to
increase in the second quarter of 2006, as production from the White Rose
development comes on-stream. This production will help offset declines in the
main reservoirs at Hibernia and Terra Nova.  Petro-Canada
is also continuing to have discussions with partners on the potential Hebron
project.  In East
Coast Oil, the priorities are to improve reliability at Terra Nova and sustain
profitable production while progressing the White Rose project.  23


Q:Is Petro-Canadas phased
  and integrated strategy in the Oil Sands yielding results?A:We have made great
  strides to improve reliability. We see greater potential from these long-life
  assets as we integrate with our Edmonton refinery and bring on the next phase
  of oil sands development.This production well at
  MacKay River collects heated bitumen, which is then piped to the sites
  central processing facility.      The steam from these four
  generators is used to reduce the viscosity of the tar-like bitumen so it can
  be brought to the surface.  Oil SandsBUSINESS
  SUMMARY AND STRATEGYPetro-Canadas major Oil
  Sands interests include a 12% ownership in the Syncrude joint venture (an oil
  sands mining operation and upgrading facility), 100% ownership of the MacKay
  River in situbitumen
  development (a steam-assisted gravity drainage (SAGD) operation), a 60%
  ownership in and operator of the Fort Hills oil sands mining project and
  extensive oil sands acreage considered prospective for in situdevelopment of bitumen
  resources.The Oil Sands strategy for
  profitable growth includes:phased and integrated
  development of reserves to incorporate knowledge gained;
  disciplined capital
  investment to ensure long-life projects are value creating; and
  a staged approach to
  development of capital-intensive Oil Sands projects to allow rigorous cost
  management and the opportunity to benefit from evolving technology.  24


Oil Sands Financial Results  (millions of dollars)
  
  2004
  
  2003
  
  2002Net earnings and earnings (loss) from
  operations
  
  $
  120
  
  $
  (52
  )
  $
  78Income tax adjustment
  
  2
  
  5
  
  Edmonton refinery conversion program
  
  
  
  (82
  )
  Earnings from operations excluding
  adjustments for one-time and unusual items
  
  $
  118
  
  $
  25
  
  $
  78Cash flow from operating activities before
  changes in non-cash working capital
  
  $
  334
  
  $
  127
  
  $
  196Expenditures on property, plant and
  equipment and exploration
  
  $
  399
  
  $
  448
  
  $
  462Total assets
  
  $
  1,883
  
  $
  1,770
  
  $
  1,498  2004
COMPARED WITH 2003  Oil Sands contributed
earnings from operations adjusted for one-time and unusual items of $118
million in 2004, up 372% from $25 million in 2003. The earnings increase
reflected higher realized prices and production at Syncrude and MacKay River in
2004.  Net earnings from Oil Sands
were $120 million in 2004, up from a net loss of $52 million in 2003. Net
earnings in 2004 included a $2 million positive adjustment to reflect a
reduction in provincial income tax rates. Net earnings in 2003 included a $5
million positive adjustment to reflect changes in federal and provincial tax
rates and an after-tax charge of $82 million for the write-off of costs related
to the original Edmonton refinery conversion plan.  At Syncrude, the average
price realized for synthetic crude oil production in 2004 was $52.40/bbl, up
from $42.67/bbl in 2003.  MacKay River realized prices
for bitumen averaged $18.37/bbl for 2004, up from $16.69/bbl in 2003. Bitumen
prices sank to extremely low levels in late 2004. This was due to the widening
of light/heavy crude price differentials, to unprecedented levels, which
hindered Oil Sands earnings. Operating costs averaged $20.98/bbl in 2004,
compared to $22.11/bbl in 2003. Contributing factors to high operating costs
were lower-than-expected volumes, increased water treatment costs and fixed
contractual obligations.  Oil Sands production in 2004
averaged 45,200 b/d, up from 36,100 b/d in 2003, reflecting higher production
at both Syncrude and MacKay River.  2004
Operating Review and Strategic Initiatives  A key focus for Oil Sands
during 2004 was reliability.  At Syncrude, efforts to
improve reliability and lower unit operating costs resulted in record gross
production of 238,000 b/d. Syncrude also lowered unit operating costs by
$2.51/bbl. Average unit operating costs decreased to $21.13/bbl in 2004,
compared to $23.64/bbl in 2003 due to improved reliability and higher volumes.
Petro-Canadas share of Syncrudes production averaged 28,600 b/d, up from
25,400 b/d in 2003.  Capital expenditures for
Syncrude in 2004 were $314 million, mainly for the Stage III expansion. This
project includes a second Aurora mine and an upgrading expansion. Construction
progress and costs remain in line with the revised plan announced in March
2004, with completion scheduled for mid-2006.  MacKay River improved
reliability of operations and production during 2004, but fell short of full
year expectations of 25,000 b/d. In 2004, MacKay River production averaged
16,600 b/d, compared to 10,700 b/d in 2003. Continual improvements resulted in
fourth quarter production averaging 19,800 b/d, compared to 16,300 b/d in the
same period in 2003. Production was impacted by a one-week outage and
subsequent ramp up resulting from a mechanical problem with the plant. There
were also steam limitations when the third-party co-generation facility was not
operational due to water treatment reliability. Reliability improved with
steady operations from the 165-megawatt co-generation facility for the second
half of 2004. Equipment to improve water treatment and plant reliability was
successfully tied-in during the planned turnaround in the third quarter.  In 2004, capital expenditures
were $45 million for MacKay River and $40 million for other in situprojects.  The SAGD in situdevelopment uses horizontal drilling
technology to inject steam into the deposit to heat the oil sands, lowering the
viscosity of the bitumen.  Syncrude and MacKay River Operating and Overhead Costs    MacKay River operating costs are expected to
decline going forward as reliability improves and volumes grow.  Syncrude
reached record net production of 28,600 b/d in 2004.  25


Syncrude
and MacKay River Production    When
completed, the third well pad at MacKay River will increase production and
maximize utilization of surface facilities.  OUTLOOK  2005 production expectations: Petro-Canadas share of Syncrude production to
average 28,000 b/d; MacKay River bitumen production to average
24,000 b/d.  Growth plans: Syncrude Stage III expansion comes on-stream
in 2006, adding 13,000 b/d over the ensuing two- to three-year ramp up period; application for next (second) SAGD project in
2005; increase production capacity at MacKay River
by adding a third well pad; develop Fort Hills oil sands mining and
upgrading project; advance SAGD technology through research and
development.  2005 capital spending plans: $35 million to enhance existing operations and
comply with regulations at Syncrude; $135 million to add a third well pad at MacKay
River and replace the southwest quadrant mine at Syncrude; $150 million to fund the Syncrude Stage III
expansion; $80 million to advance development of in situoil sands leases.  Oil Sands production is
expected to increase to about 52,000 b/d in 2005, compared to 45,200 b/d in
2004. The higher outlook reflects improved reliability and operating
performance at MacKay River. The Syncrude Stage III expansion, scheduled for
completion in mid-2006, will increase Petro-Canadas share of Syncrudes production
capacity to approximately 42,000 b/d. Production will reach this level
following a ramp up period of two to three years.  The Oil Sands 2005 capital
expenditures of $400 million are focused on providing additional production
from existing projects. A third well pad will be added at MacKay River to
increase reservoir production and maximize plant throughput. As a result,
operating costs at MacKay River are expected to decline going forward as
reliability improves and volumes grow. A further $80 million will advance the
future development of the Companys in situoil
sands leases at MacKay River and other leases. The Companys next in situis expected to be developed on one
of the existing leases with potential production of 30,000 to 40,000 b/d.  At the Edmonton refinery,
Petro-Canada is investing to convert the facility to exclusively oil sands
feedstocks and to produce low-sulphur products. By mid-2008, capital investment
of $1.2 billion will expand coker capacity and utilities, and add a new crude unit,
a vacuum unit and new sulphur plants. This will enable the Company to directly
upgrade 26,000 b/d of bitumen and process 48,000 b/d of sour synthetic crude
oil, replacing the conventional light crude feedstock refined today. The
refinery conversion program supports the long-term strategy and builds on the
$1.4 billion investment in gasoline and diesel desulphurization.  In early 2005, Petro-Canada
became a 60% interest holder and operator of the Fort Hills oil sands mining
project. The Company plans to develop this estimated 2.8 billion barrels of
bitumen resource (1.7 billion barrels net to Petro-Canada) over a 30- to
40-year period.  26


Q:How does Petro-Canada see
  its International business adding value over the long term?A:Petro-Canada is well positioned
  to access reserves to supply growing market demand from three focused
  international areas.The Hibiscus platform
  offshore Trinidad is the production facility for the NCMA-1 development.    Operations on the Hanze production
platform offshore in The Netherlands.  International  BUSINESS
SUMMARY AND STRATEGY  International production and
exploration interests are currently focused in three regions. In Northwest
Europe, production comes from the U.K. and The Netherlands sectors of the North
Sea. The North Africa/Near East region provides the major portion of
International crude oil production from interests principally in Syria and
Libya. In Northern Latin America, operations are focused in Trinidad and
Venezuela.  The International business is
the platform for Petro-Canadas global growth. The strategy is to access a
sizeable international resource base using a three-fold approach to:  expand and exploit
the existing portfolio of assets; target new
opportunities and acquisitions with a focus on long-life assets; and build a balanced
exploration program to replace reserves over time.  27


International
Operating and Overhead Costs    Acquisition
of the Buzzard project has strengthened Petro-Canadas portfolio by adding
higher netback barrels.  International Financial Results  (millions of dollars)
  
  2004
  
  2003
  
  2002Net earnings
  
  $
  175
  
  $
  307
  
  $
  225Unrealized loss on Buzzard derivative
  contracts
  
  (205
  )
  
  
  Gain on sale of assets
  
  8
  
  10
  
  Earnings from operations
  
  $
  372
  
  $
  297
  
  $
  225Kazakhstan impairment
  
  
  
  (46
  )
  International provisions
  
  
  
  45
  
  Earnings from operations excluding adjustments
  for one-time and unusual items
  
  $
  372
  
  $
  298
  
  $
  225Cash flow from operating activities before
  changes in non-cash working capital
  
  $
  1,027
  
  $
  890
  
  $
  583Expenditures on property, plant and
  equipment and exploration
  
  $
  1,824
  
  $
  525
  
  $
  221Total assets
  
  $
  5,954
  
  $
  3,973
  
  $
  3,544  2004
COMPARED WITH 2003  International contributed
earnings from operations adjusted for one-time and unusual items of $372
million in 2004, up 25% from $298 million in 2003. The earnings increase
reflected higher realized commodity prices, partially offset by lower volumes
and higher exploration and depreciation, depletion and amortization expenses.  Net earnings from
International were $175 million in 2004, down from $307 million in 2003. Net earnings
in 2004 included an after-tax unrealized loss on Buzzard derivative contracts
of $205 million and an $8 million after-tax gain on the sale of non-core
assets. Net earnings in 2003 included a $10 million after-tax gain on the sale
of non-core assets, a $46 million provision related to the impairment of assets
in Kazakhstan and a $45 million positive adjustment related to the
clarification of production rights and a tax provision of a former operation.  International oil and liquids
realized prices averaged $48.06/bbl in 2004, compared with $39.10/bbl in 2003.
International realized prices for natural gas averaged $5.21/Mcf in 2004,
compared with $4.80/Mcf in 2003.  International production of
crude oil and natural gas averaged 196,700 boe/d in 2004, compared with 210,000
boe/d in 2003. Higher production in Trinidad and Northwest Europe was offset by
lower production in Syria due to natural declines in the existing mature
fields.  International operating and
overhead costs averaged $5.94/boe in 2004, up from $5.21/boe in 2003,
reflecting lower production and rising industry costs.  2004
Operating Review and Strategic Initiatives  Northwest Europe  In 2004, Northwest Europe
continued to provide high netback production. Although a maturing basin, small-
to mid-size reserves can be produced economically, especially if tied back to
the extensive existing infrastructure. Petro-Canadas production averaged
40,400 b/d of crude oil and natural gas liquids and 85 MMcf/d of natural gas in
2004, compared with 37,700 b/d and 80 MMcf/d, respectively, in 2003. The
increase in production mainly reflected the new Clapham field, which came
on-stream at the end of 2003.  The focus in Northwest Europe
has been to expand and exploit the current portfolio. During 2004, Petro-Canada
acquired a 29.9% interest in the Buzzard project in the U.K. sector of the
North Sea. The Buzzard field has an estimated recovery of 550 MMbbls of oil,
plus 18 MMboe of associated natural gas and natural gas liquids. Progress on
the Buzzard field development was on schedule and on budget during 2004, with
first oil expected by 2006. Other North Sea oil developments also progressed
during the year. Both Pict and De Ruyter are expected to produce 10,000 b/d net
to Petro-Canada, with on-stream dates in mid-2005 and late 2006, respectively.  28


North Africa/Near East  The North Africa/Near East
region provides large resource potential with long-life, platform assets and is
Internationals largest producing region. In 2004, Petro-Canadas production of
crude oil and natural gas liquids averaged 126,600 b/d and 21 MMcf/d for
natural gas, compared with averages of 143,100 b/d and 32 MMcf/d, respectively,
in 2003. Lower volumes reflected declining production in the mature Syrian
assets, partially offset by strong production in Libya.  In 2004, Petro-Canada
continued to work on its expanded portfolio of operated exploration assets in
Tunisia, Syria and Algeria. In Syria, the Company undertook extensive data
gathering on Block II in preparation for shooting of both 2D and 3D seismic in
2005. In Tunisia, on the Melitta Block, Petro-Canada is currently preparing to
drill the first of two exploration wells scheduled for 2005. The first well,
which is onshore, should commence operations during the second quarter of 2005.
The final timing of the second well, which is offshore, is dependent on
securing a suitable drilling unit for the planned operations. In Algeria, the
Company received final government approval for the Zotti Block. Preparations
are ongoing for shooting of 2D seismic and drilling one well during 2005. These
assets further business plans to build a balanced International exploration
program for long-term growth.  Northern Latin America  Northern Latin America contains
large potential in both offshore natural gas and conventional and heavy oil.
Petro-Canada holds a 17% working interest in the North Coast Marine Area-1 gas
development in Trinidad and a 50% interest in the La Ceiba block in Venezuela.
In 2004, Petro-Canadas share of Trinidad production averaged 72 MMcf/d, up
from 63 MMcf/d in 2003. The increase was a result of supplying full year
production to Train 3 at the Atlantic LNG facility. Train 3 started operations
in the second quarter of 2003.  Petro-Canada continued its
negotiations with the Government of the Republic of Trinidad and Tobago for
production-sharing contracts for Blocks 1a and 1b in the Gulf of Paria. Further
discussions and clarification of the bid for Block 22 progressed. In Venezuela,
the extended production test to evaluate commercial viability of the La Ceiba
development began during 2004.  International capital
expenditures in 2004 were $606 million, with $395 million directed to Northwest
Europe primarily for North Sea developments, $162 million invested in the North
Africa/Near East region and $49 million going toward the Northern Latin America
region and other capital projects.  Business
Development Opportunities  To deliver Internationals
strategy of adding sizeable, long-life assets to the portfolio, the business
has an experienced business development team. In 2004, this team pursued a
number of significant opportunities such as participating in LNG projects,
acquiring and developing established reserves in the Middle East and furthering
exploration opportunities.  Complementing the proposed
Gros-Cacouna LNG re-gasification terminal (page 20, North American Natural Gas,
MD&A), Petro-Canada signed a Memorandum of Understanding (MOU) with OAO
«Gazprom» (Gazprom) to investigate a joint project to ship Russian LNG to North
American markets by 2009. The MOU covers options for Petro-Canada and Gazprom
to jointly develop a liquefaction plant in the St. Petersburg region. Also
included is the investigation of options for natural gas supplies to that LNG
plant, and the re-gasification and marketing of natural gas in North America.
With an international presence and extensive marketing experience, Petro-Canada
is well positioned throughout the LNG value chain.  Negotiations to develop the
Syria Middle Area Gas project ended early in 2005. The Government of the Syrian
Arab Republic decided to develop the project rather than award it to a foreign
consortium.  International
Production    
 (1)Production for North Africa/Near East and
Northwest Europe in 2002 is based on the average daily rate, post acquisition.
Northern Latin America production in 2002 is based on production from start-up
in August 2002.  In 2004,
Petro-Canada signed an MOU with Gazprom to investigate upstream LNG supply
options and marketing in North America.  29


OUTLOOK  Production expectations in 2005: North Africa/Near East oil and gas production
to average 114,000 boe/d; Northwest Europe oil and gas production to
average 43,000 boe/d; Northern Latin America natural gas production
to average 66 MMcf/d.  Growth plans: advance Pict and De Ruyter developments for
2005 and 2006 start-up, respectively; progress Buzzard project in 2005, for first
oil in 2006; expand exploration program to include activity
in Northwest Europe and North Africa/Near East; continue to pursue new business opportunities
in LNG and established reserves in the Middle East.  Capital spending plans in 2005: $195 million for reserves replacement spending
in core areas; $470 million for new North Sea growth
projects; $120 million for exploration and new ventures; $40 million for other expenditures, including
a provision for the potential development of La Ceiba.  International production is
expected to be 168,000 boe/d in 2005, compared with production of 196,700 boe/d
in 2004. Lower production reflects declines in Syria and Northwest Europe.  International 2005 capital
expenditures of approximately $825 million are primarily focused on significant
near-term production growth, such as Buzzard, Pict and De Ruyter. These
projects are well under way with an allocation of approximately $470 million of
capital in 2005. Production from these projects is on track to come on-stream
in 2005 and 2006.  Reserves
replacement spending in core areas is expected to be about $195 million in
2005. The $120 million allocated to exploration and new ventures will initiate
programs on new acreage in the North Sea, Tunisia, Syria and Algeria. This
capital will also develop prospects around existing operations in North Africa
and the North Sea.  Other expenditures, including
a provision for the potential development of La Ceiba, will total $40 million.
Should Petro-Canada receive a positive evaluation of the production test at La
Ceiba, development of the project could proceed and come on-stream as early as
2008, building to peak production of 13,000 b/d (net).  In 2005, Petro-Canada expects
to receive a decision from the Government of the Republic of Trinidad and
Tobago for production-sharing contracts for Blocks 1a and 1b in the Gulf of
Paria. A successful bid on Block 22 would also provide Petro-Canada with
another quality exploration opportunity.  During 2005, International
will also continue its investigation of potential LNG supply and marketing
options with Gazprom.  30


Q:What volume of production does
  Petro-Canada expect from the upstream businesses in 2005?A:Our 2005
  upstream production outlook is expected to fall in the range of 415,000 to
  440,000 boe/d, with significant production growth over the next three years
  as new projects come on-stream.  Upstream Production  2004
COMPARED WITH 2003  In 2004, production of crude
oil, natural gas liquids and natural gas averaged 451,100 boe/d, compared with
464,500 boe/d in 2003. Production gains from the Oil Sands, the U.K. and the
addition of the U.S. Rockies were more than offset by declines in Syria and
Western Canada, and production outages at Terra Nova.  2004 Average Daily
  Production Volumes
  
  North American
  Natural Gas
  
  East
  Coast Oil
  
  Oil Sands
  
  International
  
  TotalCrude oil, natural gas liquids and bitumen
  (b/d)net before royalties
  
  15,300
  
  78,200
  
  16,600
  
  167,000
  
  277,100net after royalties
  
  11,400
  
  75,100
  
  16,500
  
  107,800
  
  210,800Synthetic crude oil
  (b/d)net before royalties
  
  
  
  
  
  28,600
  
  
  
  28,600net after royalties
  
  
  
  
  
  28,300
  
  
  
  28,300Natural gas  (MMcf/d)net before royalties
  
  695
  
  
  
  
  
  178
  
  873net after royalties
  
  530
  
  
  
  
  
  139
  
  669Total volumes  (boe/d)net before royalties
  
  131,100
  
  78,200
  
  45,200
  
  196,600
  
  451,100net after royalties
  
  99,700
  
  75,100
  
  44,800
  
  131,000
  
  350,600  2003 Average Daily
  Production Volumes
  
  North American
  Natural Gas
  
  East
  Coast Oil
  
  Oil Sands
  
  International
  
  TotalCrude oil, natural gas liquids 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  31


2005
Production Outlook  In 2005, production from
Petro-Canadas upstream businesses is expected to decrease slightly compared to
2004 levels. This is mainly due to declines in Syria and Northwest Europe.
Factors that may impact production during 2005 include reservoir performance,
drilling results, facility reliability and the execution of planned turnarounds
at certain gas plants, Terra Nova, Hibernia, and Syncrude, and other factors.
Investments in existing growth projects will provide additional production in
2006 and 2007. Exploration and new venture investments will also add
longer-term production to the Companys portfolio of assets.  Consolidated Production(boe/d)
  
  2005 Outlook (+/-)North American Natural GasNatural gas
  
  113,000Liquids
  
  14,000East Coast Oil
  
  77,000Oil SandsSyncrude
  
  28,000MacKay River
  
  24,000InternationalNorth Africa/Near East
  
  114,000Northwest Europe
  
  43,000Northern Latin America
  
  11,000Total
  
  415,000  440,000  PRODUCTION
OVERVIEW    
 (1)As per the Companys forecast.  32


Reserves  At year-end 2004, proved
reserves before royalties totaled 1,214 million barrels of oil equivalent
(MMboe), including 331 MMbbls of synthetic crude oil from oil sands mining.  This amount was down slightly
from 1,220 MMboe at year-end 2003. Exploration, development and acquisition
activities all contributed to the Companys overall replacement of its
reserves. As a result of better than forecast reservoir performance at
Hibernia, Petro-Canada revised its life of field reserves estimate upward from
835 MMbbls to 940 MMbbls (from 167 MMbbls to 188 MMbbls, net Petro-Canada).
This revision added more than 15 MMbbls to year-end 2004 proved reserves at
Hibernia. However, in complying with U.S. Securities Exchange Commission (SEC)
requirements to use prices and costs as of the date of the reserves estimate,
the Company reclassified 22 MMbbls of proved bitumen reserves at its MacKay
River development as probable reserves. This reflects abnormally high
light/heavy crude oil differentials and high costs for synthetic crude oil
(used as a blending material for transporting the bitumen to market) at
year-end 2004. This reclassification did not have any financial impact on the
Company and Petro-Canada continues to view its bitumen reserves and resources
as an integral part of its overall growth portfolio. Absent this
reclassification, the Company would have replaced 110% of its 2004 production.  As part of Petro-Canadas
long-term reserves replacement strategy, the Company added exploration
capability and funding  especially internationally  to develop a balanced
exploration program aimed at increasing the reserves base over time. In
particular, Petro-Canada will target long-life reserves and aim for greater
operatorship. The Companys goal is a growth portfolio that provides a balanced
range of risk/reward opportunities. The new exploration lands 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. In Western Canada, the
Company plans to gradually increase the exploration program 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 SEC and Financial Accounting Standards Board (FASB) standards when
reporting reserves.  Petro-Canada strongly
believes that the 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 assessment 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 that which would be
provided if the work was done solely by a third party.  Petro-Canadas staff of
qualified reserves evaluators determines the Companys reserves data and
quantities based on corporate-wide policies, procedures and practices. These
reserves policies, procedures and practices conform to the requirements of
Canadian, as well as the 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 qualified
engineering evaluators/auditors. For 2004, independent petroleum reservoir
engineering consultants Sproule Associates Limited (Sproule) and Gaffney, Cline
& Associates Ltd. (GCA) conducted assessments of Petro-Canadas hydrocarbon
reserves. GCA completed an independent audit of 78% of the Companys proved
crude oil, natural gas and natural gas liquids reserves outside of North
America. Similarly, Sproule audited 77% of Petro-Canadas Canadian proved
conventional reserves and reviewed Syncrude. Sproule also conducted an
evaluation of Petro-Canadas proved, probable and possible reserves in the U.
S. Rockies. The independent auditors/evaluators reports concluded that the
Companys year-end 2004 proved reserves are reasonable.  Sproule and GCA also audited
Petro-Canadas reserves policies, procedures and practices. They concluded that
Petro-Canadas reserves booking standards meet applicable disclosure
regulations, that management is complying with those standards, and that the
reserves process is carried out 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 proved reserves of crude oil, natural gas liquids, natural gas,
bitumen and synthetic crude oil before and after royalties is available on
pages 70 to 73 of this Annual Report.  Reserves
Inventory    Petro-Canada
reserves processes and estimates are assessed by independent consultants.  33


Q:What progress has
  Petro-Canada made to improve the Downstream base business profitability?A:Progress during 2004 included
  successfully progressing consolidation of Eastern Canada refining operations,
  the sale of high-margin lubricants rising to 67% and convenience store sales
  increasing 11% year-over-year.Yasir Suliman operates one
  of Petro-Canadas award-winning retail stores.At Petro-Canadas
  Mississauga lubricants plant, employees, like Tony Pollock, produce the purest
  lubricating oil base stocks in Canada.  Downstream  BUSINESS
  SUMMARY AND STRATEGY  The Downstream operations
  include three refineries with a total rated capacity of 49,000 cubic metres
  (308,000 barrels) per day.(1) The stand alone
  lubricants plant is the largest producer of lubricant base stocks in Canada.
  In 2004, Petro-Canada accounted for about 15% of the Canadian industrys
  total refining capacity. Product sales represented about 17% of total petroleum
  products sold in Canada.Downstream strategies are
  focused on strengthening the foundations for improved profitability through
  effective capital investment and discipline over controllable factors. The
  goal is superior returns and growth, including a 12% return on capital
  employed, based on a mid-cycle business environment. Key features of the
  strategy include:      achieving and maintaining
  first quartile operating performance;      advancing Petro-Canada as
  the brand of choice for Canadian gasoline consumers; and      building on market
  strengths and increasing sales of high-margin specialty lubricants.  
 (1)Capacity revised, on a pro rata basis, from
49,800 cubic metres (313,000 barrels) per day in 2003 to reflect partial
closure of Oakville refinery operations, effective November 12, 2004.  34


Downstream Financial Results  (millions of dollars)
  
  2004
  
  2003
  
  2002Net earnings
  
  $
  314
  
  $
  248
  
  $
  252Gain (loss) on sale of assets
  
  4
  
  (15
  )
  3Earnings from operations
  
  $
  310
  
  $
  263
  
  $
  249Income tax adjustment
  
  2
  
  34
  
  Oakville closure costs
  
  (46
  )
  (151
  )
  Earnings from operations excluding
  adjustments for one-time and unusual items
  
  $
  354
  
  $
  380
  
  $
  249Cash flow from operating activities before
  changes in non-cash working capital
  
  $
  556
  
  $
  601
  
  $
  380Expenditures on property, plant and
  equipment
  
  $
  839
  
  $
  424
  
  $
  344Total assets
  
  $
  4,462
  
  $
  3,827
  
  $
  3,836  2004
COMPARED WITH 2003  Downstream contributed
earnings from operations, adjusted for one-time and unusual items of $354
million in 2004, down 7% from $380 million in 2003. The impact of rising crude
prices on margins for retail and heavy products and a stronger Canadian dollar
more than offset the benefits of favourable U.S. refining margins and a wider
light/heavy crude price differential in 2004.  Net earnings from Downstream
were $314 million in 2004, up from $248 million in 2003. Net earnings in 2004
included a $4 million after-tax gain on the sale of assets, a $2 million
positive adjustment to reflect a reduction in provincial income tax rates and a
$46 million after-tax charge for additional depreciation and other charges
related to the previously announced consolidation of the Eastern Canada
refinery operations. Net earnings in 2003 included a $15 million after-tax loss
on asset sales related to the selective rationalization of marketing networks in
Eastern Canada, a $34 million positive adjustment to reflect the changes in
federal and provincial tax rates and a $151 million charge related to the
closure of the Oakville refinery.  Excluding the impacts of
one-time and unusual items, Refining and Supply contributed 2004 operating
earnings of $288 million, which was unchanged from 2003. Earnings in 2004 were
increased by favourable U.S. refining margins, wider light/heavy crude price
differentials and a positive last-in, first-out (LIFO) inventory valuation
adjustment associated with the Oakville closure. This was offset by the effects
of a 2% decline in overall crude capacity utilization at Downstreams three
refineries and lower asphalt and heavy fuel oil margins, as prices failed to
keep pace with rising crude oil costs in the second half of 2004. Petro-Canada,
as the leading player in asphalt and heavy fuel oil in Eastern Canada, was
particularly impacted by the low-margin environment.  Marketing contributed
earnings from operations excluding one-time and unusual items of $66 million,
down from $92 million in 2003. The decrease in earnings was primarily
attributable to increased retail price competition in 2004.  2004
Operating Review and Strategic Initiatives  Total crude oil processed in
2004 averaged 48,200 cubic metres per day (m(3)/d), down from 49,900 m(3)/d in
2003. The overall utilization rate at the three refineries, adjusted for the
partial closure of the Oakville refinery on November 12, 2004, averaged 98% in
2004, down slightly from 100% in 2003. The decline reflected a 35-day
turnaround related to the Eastern Canada consolidation and a major turnaround
at the Edmonton refinery for maintenance and to facilitate tieing in
low-sulphur gasoline equipment.  Total Downstream sales
decreased slightly, to an average 56,600 m(3)/d from 56,800 m(3)/d in 2003.
Lower gasoline and distillate sales were mostly offset by stronger sales of
lubricants and unfinished refinery stock. Non-petroleum product sales continued
to demonstrate strong growth with convenience store sales rising 11% from the
previous year.  Total Downstream operating,
marketing and general and administration unit costs of 6.4 cents/litre were up
slightly from 6.2 cents/litre in 2003. The increase mainly reflected higher
maintenance and shutdown costs.  Downstream
Operating, Marketing and General Costs  Per litre costs reflected
higher maintenance and shutdown costs.    Petro-Canada
is successfully consolidating Eastern Canada refineries.  35


Refinery
Utilization  Lower refinery utilization
was due to the Eastern Canada consolidation and a major turnaround at the
Edmonton refinery allowing tie-in of low-sulphur gasoline equipment.    New image
sites combine highly visible and attractive design elements with improved
traffic flow and convenience for customers.  Gasoline
Throughput per Retail Site  Total Downstream sales per
retail site continued to grow in 2004.    Excludes Petro-Canada branded sites operated
by independent dealers.  In 2004, Downstream completed
its most aggressive capital plan ever. The Downstream business continued to
focus on improving refining assets and operations, becoming the brand of
choice in sales and marketing, and realizing the full potential of the
lubricants business.  In Refining and Supply, key
initiatives were the consolidation of Eastern Canada refining and supply
operations to Montreal and the ongoing work to convert the Edmonton refinery to
process oil sands feed-stock. The Eastern Canada consolidation is on schedule,
including the successful reversal and expansion of the Trans-Northern Pipelines
Inc. pipeline and completion of logistics tie-ins at the Montreal refinery to
supply the Ontario market. The consolidation work also included a successful 35-day
crude unit turnaround at the Montreal refinery to expand the plants crude
capacity. Excellent safety and reliability were maintained at the Oakville
refinery during the transition. The refinery will operate at a reduced level
into early 2005 to increase short-term supply flexibility through the
transition period.  The largest maintenance
shutdown ever at the Edmonton refinery was completed on time and on budget in
2004, with an outstanding safety record. The turnaround also included work to
successfully tie-in low-sulphur gasoline equipment. Both the Edmonton and
Montreal refineries were producing gasoline in compliance with new federal
ultra-low sulphur gasoline regulations well in advance of the January 1, 2005
deadline.  Overall plant reliability, a
critical component of success in the refining business, improved in 2004.
However, outstanding performance at Edmonton, Oakville and the lubricants plant
was offset by lower reliability at the Montreal refinery. Work undertaken to
address this issue through an increased focus on operations and maintenance
procedures, as well as selective equipment upgrades, should improve reliability
in 2005.  Downstream capital
expenditures for plant, property and equipment were $839 million for 2004. A
substantial portion of the 2004 spending was directed to produce
cleaner-burning diesel fuels. The Downstream business remained focused on
positioning Petro-Canada for improved profitability, accelerating growth
oriented projects primarily in the retail and wholesale networks.  The focus in Marketing was on
profitable growth through initiatives directed at the retail and PETRO-PASS
truck stop networks. Petro-Canada led the industry in key urban market metrics
and continued to improve the fundamentals of the retail business with more than
85% of the re-imaging program complete. Fast-tracking this re-imaging program
allowed realization of industry-leading throughputs, with annual gasoline sales
from re-imaged sites within the Companys network now averaging in excess of
6.8 million litres per site. Based on this success, the Company extended this
new image program to independent retailers. More than 35% of these retailers
elected to invest their capital in the new image standard.  Petro-Canada continued to
leverage its position as Canadas Gas Station, with innovative product
developments and a continuing track record of new product firsts in the
industry. In September 2004, the Downstream business introduced the Citi
Petro-Points MasterCard, the first general-purpose credit card in North America
to offer cardholders an instant discount on gasoline. The Company also
accelerated the roll out of the Cash Point program, the industrys first
privately owned automated bank machine network. Petro-Canada also continued to
focus on expanding non-petroleum revenue base, as evidenced by the 11%
year-over-year sales growth of the convenience store business, and the 7%
increase in same-store sales in 2004 compared to 2003.  In the Wholesale business,
the focus was on improving the sales mix and leveraging the best-in-class
position in the commercial road transport and bulk fuels channels. The
PETRO-PASS network of 213 truck stop facilities is the leading national
marketer of fuel in the commercial road transport segment in Canada. In 2004, the
network was further expanded and upgraded, increasing sales volume in this
high-value channel. In bulk fuels, Petro-Canada concentrated on the successful
integration of acquisitions in the home heat business.  In 2004, the Lubricants
business focused on growing volume in high-margin sales and improving plant
reliability. Petro-Canada made great strides in improving reliability by
intensifying efforts to optimize operations and maintenance procedures based on
industry best practices. Despite continued soft demand in the key U.S. export
market, Lubricants sales totaled 833 million litres in 2004, an increase of 8%
compared to sales volume of 768 million litres in 2003. Over the last five
years, growth in high-margin sales has averaged more than 11% per year. In
2004, high-margin sales rose 11%, resulting in 67% of production going into
high-margin markets. Lubricants continues to be well positioned for profitable
future growth as tougher performance and environmental standards increase
global demand for higher quality base oils and finished products.  36


OUTLOOK  Growth plans:     complete the closure of Oakville refinery;     drive for first quartile refinery reliability;     increase service station network effectiveness
with a focus on increasing non-petroleum revenue;     increase sales of high-margin, value-added
lubricants;     invest in Montreal and Edmonton refineries to
produce low-sulphur diesel;     advance Edmonton refinery conversion program
to process oil sands based feedstocks by 2008.  2005 capital spending plans: $625 million primarily focused on diesel
desulphurization at Montreal and Edmonton refineries; $90 million for Edmonton refinery conversion
program; $205 million for sustaining investments and new
growth opportunities.  While the largest component
of the Downstreams approximate $920 million capital investment will be for
regulatory compliance, business spending for 2005 also supports the strategy to
improve base business profitability and pursue profitable growth.  Approximately $625 million
will go to modify the Montreal and Edmonton refineries to produce low-sulphur
distillates in line with regulations, which come into effect June 1, 2006. This
includes the pre-investment for the Edmonton refinery to process oil sands
feedstocks in the future. An additional $85 million will be invested to sustain
existing operations with the main focus on improving plant reliability at the
Montreal refinery and the Mississauga lubricants plant.  The Downstream business also
plans to spend about $120 million to improve the profitability of the base
business. This will include investments to advance the development of the
retail network and to increase non-petroleum revenue. In keeping with the
strategy to pursue profitable growth, Downstream will invest approximately $90
million to begin the detailed engineering work to convert the Edmonton refinery
to run 100% oil sands crude feedstock. Petro-Canada will also begin work to
debottleneck the Mississauga plant as the high-margin, specialty lubricants
business grows.  Shared
Services  Shared Services includes investment income, interest expense, foreign
currency translation and general corporate revenue and expenses.  Shared
Services Financial Results  (millions of dollars)
  
  2004
  
  2003
  
  2002Net earnings (loss)
  
  $
  (63
  )
  $
  58
  
  $
  (196
  )Gain (loss) on sale of assets
  
  (1
  )
  1
  
  Foreign currency translation
  
  63
  
  239
  
  (52
  )Net loss from operations
  
  $
  (125
  )
  $
  (182
  )
  $
  (144
  )Income tax adjustment
  
  (1
  )
  (11
  )
  Net loss from operations excluding
  adjustments for one-time and unusual items
  
  $
  (124
  )
  $
  (171
  )
  $
  (144
  )Cash flow from operating activities before
  changes in non-cash working capital
  
  $
  (106
  )
  $
  (100
  )
  $
  (104
  )  Lubricants
High-Margin Sales  High-margin lubricants sales
increased 2% compared to 2003.    The
Lubricants strategy remained focused on growing volume in high-margin sales and
improving plant reliability.  37


2004 COMPARED
WITH 2003  Shared Services net loss from
operations adjusted for one-time and unusual items was $124 million in 2004,
compared to $171 million in 2003. This decrease primarily reflected lower
interest expense and general expenses.  Shared Services net loss was
$63 million in 2004, compared to net earnings of $58 million in 2003. Net
expenses in 2004 included a $1 million after-tax loss on the sale of assets, a
$63 million foreign currency translation gain on U.S. dollar-denominated
long-term debt and a $1 million charge to reflect a change in the provincial
income tax rate. Net earnings in 2003 included a $1 million after-tax gain on
the sale of assets, a $239 million foreign currency translation gain on U.S.
dollar-denominated long-term debt and an $11 million charge to reflect changes
in federal and provincial income tax rates. The 2004 and 2003 foreign currency
translation gain on U.S. dollar-denominated long-term debt reflected the
strengthening of the Canadian dollar versus the U.S. dollar.  Q:What is Petro-Canadas approach
  to disclosure?A:Petro-Canada
  is committed to open and fair disclosure in compliance with securities
  regulations and generally accepted accounting standards.  Financial Reporting  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 of the Board of Directors
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 2004 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  38


production method based upon
estimated reserves (see Estimated Oil and Gas Reserves discussion on page 40).
Reserves 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 reserves
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 write-down
of oil and gas producing properties as part of the impairment assessment (see
Asset Impairment discussion below).  Asset
Retirement Obligations  The Company currently records
the obligation for estimated asset retirement costs at fair value when
incurred. Factors that can affect the fair values of the obligations include
the expected costs and the useful lives of the assets. Cost estimates are
influenced by factors such as the number and type of assets subject to asset
retirement obligations, the extent of work required and changes in
environmental legislation. A revision to the estimated costs or useful lives of
the assets could result in an increase or decrease in the total obligation
which would change the amount of amortization and accretion expense recognized
in net earnings over time.  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 on page 40), 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 judgment, and include estimates of reserves
acquired (see Estimated Oil and Gas Reserves discussion on page 40), 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 on page 40), 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.  39


Estimated
Oil and Gas Reserves  Reserves estimates, although
not reported as part of the Companys Consolidated Financial Statements, can
have a significant effect on net earnings as a result of their impact on
depreciation and depletion rates, asset impairments and goodwill impairment
(see discussion of these items on pages 38 and 39). 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 qualified petroleum reservoir engineering consultants
also conduct annual evaluations, technical audits and/or reviews of a
significant portion of the Companys reserves and audit the Companys reserves
policies, procedures and practices. In addition, the Companys contract
internal auditors test 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.  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 pro rated 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 in the normal course of operations. Management is of the
opinion that any resulting settlements would not materially affect the
financial position of the Company as at December 31, 2004. 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  Asset
Retirement Obligations  Effective January 1, 2004,
the Company retroactively adopted the new standard of the Canadian Institute of
Chartered Accountants (CICA) on accounting for asset retirement obligations.
The new standard requires the fair values of asset retirement obligations to be
recorded as liabilities when incurred and the related assets be 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. Asset retirement
obligations are not recorded for those assets which have an indeterminate
useful life. The impact of this change has been disclosed in Note 2 of the
Consolidated Financial Statements.  40


Reclassification
of Costs  Pursuant to the new CICA
section 1100 Generally Accepted Accounting Principles, which provides
guidance on the sources to consult when selecting accounting policies, the
Company began accounting, effective January 1, 2004, for certain transportation
costs, third-party gas purchases and diluent purchases as expenses in the
Consolidated Statement of Earnings. Previously, these costs were netted against
revenue. Prior years comparatives have been restated.  Hedging
Relationships  Effective January 1, 2004,
the Company adopted Accounting Guideline 13 (AcG 13), Hedging Relationships,
which resulted in changes to the conditions as to when hedge accounting may be
obtained. As a result, certain of the Companys risk management derivative
instruments no longer qualify as accounting hedges and are accounted for as
required under Emerging Issues Committee (EIC) 128, Accounting for Trading,
Speculative or Non-Hedging Derivative Financial Instruments. EIC 128 requires
that all derivative instruments that do not qualify, or are not designated as a
hedge under AcG 13, be recorded on the Consolidated Balance Sheet at fair value
as either an asset or liability with changes in fair value recognized in
earnings.  RECENT PRONOUNCEMENTS  Pursuant to recent guidance
on the classification of cash flows relating to asset securitization
transactions, the Company has included the proceeds from its 2004 sale of
accounts receivable as part of cash flows from operating activities. The
Company had previously reported these proceeds as part of investing activities
when reporting its quarterly results in 2004 and will reclassify the
comparative amounts when quarterly results are reported in 2005.  RELATED-PARTY TRANSACTIONS  On September 29, 2004, the
Government of Canada completed its offering to the public of its entire
remaining interest in Petro-Canada. Transactions with the Government of Canada
and its agencies prior to the sale were in the normal course of business and on
the same terms as those accorded to 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 March 3, 2005, there
were 260,358,471 common shares outstanding and no preferred shares outstanding.
For details of the Companys share capital and stock options outstanding, refer
to Notes 20 and 21 to the 2004 Consolidated Financial Statements.  ADDITIONAL INFORMATION  Copies of this MD&A and
the following Consolidated Financial Statements, as well as the Companys
latest Annual Information Form and Management Proxy Circular may be obtained
from the Companys Web site at www.petro-canada.ca or by mail upon request from
the corporate secretary, 150  6th Avenue S.W., Calgary, Alberta, T2P 3E3.
Other disclosure documents, and any reports, statements or other information
filed by Petro-Canada with the Canadian provincial securities commissions or
other similar regulatory authorities is accessible through the internet on the
Canadian System for Electronic Document Analysis and Retrieval, which is
commonly known by the acronym SEDAR and is located at www.sedar.com. SEDAR is
the Canadian equivalent of the U.S. SECs Electronic and Document Gathering and
Retrieval System, which is commonly known by the acronym EDGAR and is located
at www.sec.gov.  41