Petro-canada 40F 2007 Annual report | SEC Filing

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Exhibit 99.2

Management's Discussion and Analysis

This Management's Discussion and Analysis (MD&A), dated effective as of February 14, 2008, should be read in conjunction with the audited Consolidated Financial Statements and Notes for the year ended December 31, 2007, included within this 2007 annual report and the 2007 Annual Information Form (AIF). Financial data have been prepared in accordance with Canadian generally accepted accounting principles (GAAP), unless otherwise specified. All dollar values are Canadian (Cdn) 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 portray performance of the Company within its "value drivers," which are the key measures of performance in each segment of Petro-Canada's business. A glossary of financial terms and ratios can be found on page 112 of this report.

BUSINESS ENVIRONMENT

The major economic factors influencing Petro-Canada's upstream financial performance include crude oil and natural gas prices and foreign exchange, particularly the Cdn dollar/U.S. dollar rates. Crude oil and natural gas prices are affected by a number of factors, including supply and demand balance, weather and political events. Factors influencing Downstream financial performance include the level and volatility of crude oil prices, industry refining margins, levels of crude oil price differentials, demand for refined petroleum products, the degree of market competition and foreign exchange, particularly the Cdn dollar/U.S. dollar rates.

Business Environment in 2007

The year 2007 saw the highest oil price on record, with a near doubling of prices. The price of North Sea Brent (Dated Brent) opened the year at lows near $51 US/bbl and closed at a record $96 US/bbl. North American natural gas prices at the Henry Hub were much less volatile, averaging around $7 US/million British thermal units (MMBtu) for most of the year.

On an annual average basis, the price of Dated Brent reached $72.52 US/bbl, the highest annual average ever and almost 11% above the 2006 average. Strong oil prices in 2007 were driven by continued demand growth in China, geopolitical tensions and speculation. In 2007, the international light/heavy crude (Dated Brent/Mexican Maya) price differentials averaged $12.67 US/bbl, narrower than the $13.94 US/bbl posted in 2006. Canadian light/heavy crude (Edmonton Light/Western Canada Select (WCS)) spreads widened in 2007 to $24.07 Cdn/bbl from $22.40 Cdn/bbl in 2006. Canadian heavy crudes sold at a larger discount to light crude prices, compared with international heavy crudes, due to Canadian heavy crude oil production growing at a faster rate than North American investment to convert refineries to process heavy feedstock.

The appreciation of the Cdn dollar during 2007 reduced the impact of international prices on Canadian crude oil and natural gas prices. The Cdn dollar averaged 93 cents US in 2007, compared with 88 cents US in 2006.

6 PETRO-CANADA Management's Discussion and Analysis

North American natural gas prices were lower in 2007, compared with 2006 due to continuing high levels of natural gas in storage and lower weather-related demand. Henry Hub prices averaged $6.92 US/MMBtu in 2007, 5% lower than in 2006. In 2007, the Canadian natural gas price at the AECO-C hub fell in line with U.S. prices and averaged 5% below its 2006 level.

In the downstream sector, in 2007, refined petroleum product sales in Canada increased by about 3%, compared with declines of 1% in the past two years. The positive impact of improved product sales on industry margins during 2007 was partially offset by a stronger Cdn dollar and its impact on cracking margins and crude differentials and narrower international light/heavy crude price differentials. The New York Harbor 3-2-1 crack spread, an indicator of overall refining margins, averaged $14.15 US/bbl in 2007, compared with $9.80 US/bbl in 2006. Logistical bottlenecks associated with the replacement of Methyl Tertiary Butyl Ether (MTBE) with ethanol in gasoline blending in the U.S. and a busy schedule of refinery turnarounds helped to improve gasoline margins in early 2007, compared with 2006. Distillate margins continued to be strong, largely reflecting the penetration of ultra-low sulphur on-road diesel in the market since June 2006.

Commodity Price Indicators and Exchange Rates

(averages for the years indicated)			2007		2006	2005

Crude oil price indicators(per bbl)
	Dated Brent at Sullom Voe	US$	72.52		65.14	54.38
	West Texas Intermediate (WTI) at Cushing	US$	72.31		66.22	56.56
	WTI/Dated Brent price differential	US$	(0.21	)	1.08	2.18
	Dated Brent/Mexican Maya price differential	US$	12.67		13.94	13.52
	Edmonton Light	Cdn$	76.84		73.23	69.22
	Edmonton Light/WCS (heavy) price differential	Cdn$	24.07		22.40	25.27
Natural gas price indicators
	Henry Hub(per MMBtu)	US$	6.92		7.26	8.55
	AECO-C spot(per Mcf)	Cdn$	6.89		7.28	8.84
	Henry Hub/AECO basis differential(per MMBtu)	US$	0.80		1.09	1.53
New York Harbor 3-2-1 refinery crack spread(per bbl)¹		US$	14.15		9.80	9.47
US$/Cdn$ exchange rate		US$	0.93		0.88	0.83

1: On January 1, 2007, the New York Harbor 3-2-1 crack spread calculation changed. It is now based on Reformulated Gasoline Blendstock for Oxygenate Blending (RBOB) gasoline (the base for blending gasoline with 10% denatured ethanol) as opposed to conventional gasoline. Due to this change in specification, the 2007 crack spread values are not directly comparable to 2005 or 2006 values.

Competitive Conditions

It is increasingly challenging for the energy sector to find new sources of oil and natural gas. Petro-Canada is well positioned to successfully increase production of oil and natural gas and compete for new opportunities that could complement existing upstream resources. The Company has an estimated 15 billion boe of resources from which to develop new production, with approximately 71% of the resources located in Alberta's oil sands. With upstream business operations in Canada and internationally, the Company has the flexibility to pursue a wide range of opportunities. While the Company has significant operational scope, as measured by production levels, it remains a mid-sized global company. This means Petro-Canada has the operational capability and balance

Management's Discussion and Analysis PETRO-CANADA 7

sheet strength to invest in large projects, but smaller investments can also have a meaningful impact on the Company's production levels and financial returns.

Petro-Canada is well positioned to compete in the petroleum product refining and marketing business in Canada. The Company accounts for 13% of the total refining capacity and has a 16% share of the petroleum products market in Canada. With a network of more than 1,300 retail service stations, Petro-Canada has the highest gasoline sales per site in Canada among national integrated oil companies. The Company also has Canada's largest commercial road transport network, with 229 locations, as well as a robust bulk fuel sales channel.

The Company's strong financial position, track record of successfully executing large capital projects and depth of management experience should enable it to continue to compete effectively in the current business environment.

Outlook for Business Environment in 2008

Prices for energy commodities are expected to remain volatile in 2008, reflecting the unpredictable nature of weather, the level of industry inventories, and political, fiscal and natural developments. 2008 is expected to be a challenging year for the petroleum industry worldwide. Concern about the risk of a U.S. recession spreading to other regions of the world has put a lid on potential further increases in international oil prices. For the first time in several years, questions are being raised about the ability of China to maintain both the extraordinary economic and oil demand growth rates, which have been sustaining the oil price increases of recent years, should its key export markets go into economic decline. Also clouding the 2008 outlook is the continuing rise of nationalism in key resource-rich countries, aggravated by the tightening of fiscal and royalty regimes in countries both inside and outside of the Organization of the Petroleum Exporting Countries (OPEC).

Demand for natural gas would remain challenged in 2008 should a recession take hold in North America. Notwithstanding the fact that, with the exception of coal, natural gas during 2007 was the cheapest of all fuels available for industrial and power generation applications. The 2007-08 heating season demand for the fuel is anticipated to improve relative to the 2006-07 heating season due to colder temperatures. Concern about faltering production growth in North America, especially in Canada, and the lack of competitive prices to attract liquefied natural gas (LNG) supplies will temper any downward price pressures arising from softer demand.

Barring refinery mishaps or accidents of nature, 2008 refining margins in the downstream are expected to be weaker than in 2007. A North American recession would also serve to dampen refined product demand growth. Lower anticipated light crude oil price levels in 2008 are also likely to compress current light/heavy crude price differentials and negatively affect refining margins in 2008.

Finally, we expect a continuation of Cdn dollar strength during 2008. A strong dollar will continue to erode gains as a result of any strength in commodity prices.

8 PETRO-CANADA Management's Discussion and Analysis

Economic Sensitivities

The following table illustrates the estimated after-tax effects that changes in certain factors would have had on Petro-Canada's 2007 net earnings from continuing operations had these changes occurred.

Sensitivities Affecting Net Earnings

Factor^1,²		Change (+)		Annual Net Earnings Impact			Annual Net Earnings Impact

		(millions of Canadian dollars			)		($/share) ³
Upstream
Price received for crude oil and liquids⁴	$	1.00/bbl	$	52		$	0.11
Price received for natural gas	$	0.25/Mcf		30			0.06
Exchange rate: US$/Cdn$ refers to impact on upstream earnings from continuing operations⁵	$	0.01		(40	)		(0.08	)
Crude oil and liquids production(barrels/day – b/d)		1,000 b/d		10			0.02
Natural gas production(million cubic feet/day – MMcf/d)		10 MMcf/d		7			0.01

Downstream
New York Harbor 3-2-1 crack spread⁶	$	1.00 US/bbl		22			0.05
Chicago 3-2-1 crack spread	$	1.00 US/bbl		24			0.05
Seattle 3-2-1 crack spread	$	1.00 US/bbl		7			0.01
Dated Brent/Maya FOB price differential	$	1.00 US/bbl		6			0.01
Edmonton Light/Synthetic price differential	$	1.00 Cdn/bbl		13			0.03
Exchange rate: US$/Cdn$ refers to impact on downstream cracking margins and crude price differentials⁷	$	0.01		(11	)		(0.02	)

Corporate
Exchange rate: US$/Cdn$ refers to impact of the revaluation of U.S. dollar-denominated, long-term debt⁸	$	0.01	$	10		$	0.02

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: Per share amounts are based on the number of shares outstanding at December 31, 2007.
4: This sensitivity is based upon an equivalent change in the price of WTI and Dated Brent, excluding the derivative contracts associated with the Buzzard acquisition that were closed out in the fourth quarter of 2007.
5: A strengthening Cdn dollar compared with the U.S. dollar has a negative effect on upstream earnings from continuing operations.
6: On January 1, 2007, the New York Harbor 3-2-1 crack spread calculation changed. It is now based on RBOB gasoline (the base for blending gasoline with 10% denatured ethanol) as opposed to conventional gasoline. Due to this change in specification, the 2007 crack spread values are not directly comparable to 2006 values.
7: A strengthening Cdn dollar compared with the U.S. dollar has a negative effect on downstream cracking margins and crude price differentials.
8: A strengthening Cdn dollar versus the U.S. dollar has a positive effect on corporate earnings because the Company holds U.S. dollar denominated debt. The impact refers to gains or losses on $1.4 billion US of the Company's U.S. dollar denominated long-term debt and interest costs on U.S. dollar denominated debt. Gains or losses on $1.1 billion US of the Company's U.S. dollar 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.

Management's Discussion and Analysis PETRO-CANADA 9

BUSINESS STRATEGY

Value Proposition and Strategy

The value proposition Petro-Canada offers to its investors can best be summarized as "Integrated Value from a Diversified Resource Base." The Company's business strategy continues to be:

•

taking a disciplined approach to profitable growth

.: leveraging existing assets
.: accessing new opportunities with a focus on long-life assets
.: building a balanced exploration program

•

improving the profitability of the base business

.: meeting annual production guidance
.: selecting the right assets to develop and then driving for first quartile performance¹

The Company believes its structure and scope strategically position Petro-Canada to deliver long-term shareholder value. With a base in Canada, Petro-Canada is situated in a stable, resource-rich and demand-driven market. An ever-increasing international presence and integration across businesses provide the Company access to more value-adding growth opportunities and an ability to better manage risk through having a diversified portfolio. As a mid-sized global company, even smaller sized investments can have a material impact. The Company remains committed to developing energy resources responsibly and providing growth opportunities for employees.

Execution of the Strategy in 2007

Improving Base Business Profitability

For 2007, Petro-Canada focused on two areas to deliver improved base business profitability – increasing upstream production by 15% compared with 2006, and continuing to improve our safety and reliability performance while prudently managing costs. Safety, reliability and cost management are measures that are constantly tracked, reported and improved upon.

Through a focus on execution, the Company achieved a 21% increase in upstream production from continuing operations in 2007. This strong production growth was largely due to the successful startup of the partner-operated Buzzard facility, full-year production from Syncrude Stage III and White Rose and improved reliability at key operated facilities.

Western Canada natural gas processing facilities operated at reliability rates of 99%. The two Downstream refineries and lubricants plant had a combined reliability index of 92. Terra Nova significantly improved its facility reliability, operating at 86% in 2007. The facility that did not meet expectations was the Oil Sands' MacKay Riverin situ operation with reliability of 87%. The Company has a continued focus to improve facility reliability in 2008.

Corporate-wide, Petro-Canada views safety as an indicator of operational excellence. The Company has a Zero-Harm philosophy. This means that the Company believes that work-related injuries and illnesses are foreseeable and preventable. The Company is committed to maintaining a first quartile safety record. In 2007, Petro-Canada achieved a Total Recordable Injury Frequency of 0.86, a slight increase over the previous year, but still one of the best safety records in the sector.

Managing costs is another key to improving base business profitability. Efforts are constantly made across the Company to responsibly manage expenses and improve efficiencies.

1: References to first quartile operations in this report do not refer to industry-wide benchmarks or externally known measures. The Company has a variety of internal metrics that define and track first quartile operational performance.

10 PETRO-CANADA Management's Discussion and Analysis

Maintaining Financial Discipline and Flexibility

PRIORITY	2007 GOALS	2007 RESULTS	2008 GOALS

Fund Capital Expenditures with Cash Flow and Debt As Required	• fund $4.1 billion capital expenditure program from expected cash flow, cash on hand and accessing balance sheet strength, as needed • manage operating and capital costs within budgets • maintain investment grade credit ratings	• funded 2007 expenditure program out of a combination of cash flow and cash on hand • 2007 operating and capital costs were in line with budget • maintained investment grade credit ratings of Baa2 from Moody's Investors Service, BBB from Standard & Poor's (S&P) and A (low) from Dominion Bond Rating Service	• fund $5.3 billion capital expenditure program through a combination of cash flow and access capital markets, as needed • prioritize execution of projects • maintain investment grade credit ratings

Fund Profitable Growth	• invest in additional growth opportunities when there is a strong business case	• extended Libya concessions and increased Fort Hills ownership by 5% • finished 2007 strong, with debt levels at 22.5% of total capital and a ratio of debt-to-cash flow from continuing operating activities of 1.0 times • settled Buzzard derivative contracts for $1,145 million after-tax	• identify and invest in long-life assets

Return Cash to Shareholders	• buy back shares when appropriate, although likely at lower levels than 2006 • regularly review the dividend strategy to align with financial and growth objectives, and shareholder expectations	• renewed NCIB program in June 2007, entitling the Company to purchase up to 5% of the outstanding common shares, subject to certain conditions • purchased 16 million common shares at an average price of $52.42/share for a total cost of $839 million • increased quarterly dividend by 30% to $0.13/share, effective April 1, 2007	• regularly review the dividend strategy to align with financial and growth objectives, and shareholder expectations • buy back shares when appropriate, with priority to first fund profitable growth

Long-Term Profitable Growth

Adding new material opportunities is fundamental to long-term growth. In 2007, one of Petro-Canada's priorities was to advance its five major growth projects. Highlights included completing 61% of the Edmonton refinery conversion and advancing the Montreal coker project toward a final investment decision. The Company also moved to front-end engineering and design (FEED) on the Fort Hills mining and upgrading project, and received a recommendation of approval from the Energy Resources Conservation Board and Alberta Environment for its regulatory permit for expansion of the MacKay River facility. Internationally, Petro-Canada advanced plans on the Syria Ebla gas project with FEED expected to be completed in early 2008. In addition to advancing these projects, in 2007, the Company added two more growth projects: the Libya Concession Development and partner-operated White Rose Extensions.

In pursuing these growth projects, Petro-Canada is seeking to increase the relative proportion of long-life resources in the portfolio as a means to deliver sustainable cash flow and earnings. In the upstream, we define long-life assets as those projects that have more than 10 years of sustainable production and cash flow. In the Downstream, refineries and gasoline stations share the same characteristic of having a long contributing life. These kinds of assets provide sustainable cash flow and make the Company less dependent on exploration success for growth. It is also efficient to expand long-life assets from existing infrastructure.

Management's Discussion and Analysis PETRO-CANADA 11

Long-Life Production (%)

In 2007, about 30% of Petro-Canada's production came from assets considered long-life. Successful execution of our business strategy will mean a higher proportion of long-life resources in the future.

Along with long-life assets, the Company pursues profitable growth through a balanced exploration program that provides a balanced risk/reward profile and that collectively adds to reserves over time. In 2007, Petro-Canada and its partners executed one of the Company's most significant exploration programs, drilling 15 wells.

Seven of these wells were completed as discoveries. Three wells were shut-in and are awaiting evaluation. Five wells were abandoned as dry holes or non-commercial discoveries and were written off.

At year-end 2007, operations continued on four additional wells.

This table represents exploration in International, East Coast Canada, Alaska and the Northwest Territories (NWT) (does not include Western Canada and U.S. Rockies).

	2007 Results				2008 Outlook

(number of wells)	Discoveries – Oil	Discoveries – Natural Gas	Still Being Evaluated	Dry and Abandoned

North Sea	2	2	–	2	6
Syria	–	–	1	1	–
Libya	1	–	–	–	3
Trinidad and Tobago	–	2	–	1	5
Alaska, NWT	–	–	2	1	3

Total	3	4	3	5	17

12 PETRO-CANADA Management's Discussion and Analysis

Cash and In-Kind Contributions of Nearly $15 Million in 2007
Years ended December 31 (unaudited)

(millions of Canadian dollars)

1: The total includes community partnership funding, as well as other community support in the form of equipment, property and cash donations from various operating budgets.

Following our Principles for Responsible Investment and Operations

Our principles guide our actions and track our performance in the areas of business conduct, community support, environment, working conditions and human rights.

There is a growing concern about the impact the energy sector has on the environment. The Company shares this concern and actively seeks to minimize the impact of Petro-Canada's operations on land, water and air. The Company's areas of focus are use of water, greenhouse gas (GHG) emissions and air emissions management.

The Company has more than 5,600 employees and many contractors working on Petro-Canada's behalf. These people deserve respectful and meaningful employment. In 2007, Petro-Canada recruited more than 860 new employees. The Company is committed to providing them with a safe and attractive place to work where they can learn and make a difference.

Management's Discussion and Analysis PETRO-CANADA 13

Following our Principles for Responsible Investment and Operations

PRIORITY	PRINCIPLES	2007 GOALS	2007 RESULTS	2008 GOALS

Business Conduct	• comply with applicable laws and regulations • apply our Code of Business Conduct wherever we operate • seek contractors, suppliers and agents whose practices are consistent with our principles	• improve training for Code of Business Conduct and Privacy Policies • strengthen leaders' understanding of their roles in sustaining a culture of integrity • improve pre-selection and communication of Code of Conduct expectations with contractors	• 5,522, or 98% of employees, and 906 contractors completed an interactive Code of Conduct refresher • developed interactive, web-based privacy training and deployed it to 3,885 employees • conducted workshops on how to deal with bribery and corruption in most International offices • developed safety pre-selection criteria for contractors • strengthened our Total Loss Management (TLM) framework by introducing a consistent and robust method to assess environment and social risks	• update our Code of Conduct and introduce interactive web-based training on the new Code of Conduct • continue to strengthen our communication of Code of Conduct expectations with an increasing contractor workforce • improve new employee orientation process across the Company to emphasize Zero-Harm and TLM culture and principles • implement online TLM training to strengthen employee understanding

Community	• strive within our sphere of influence to ensure a fair share of benefits to stakeholders impacted by our activities • conduct meaningful and transparent consultation with all stakeholders • endeavour to integrate our activities with, and participate in, local communities as good corporate citizens	• develop Stakeholder Engagement Policy and improve training and capability development • increase Aboriginal community participation in business opportunities to provide goods and services • better measure the socio-economic impact on the communities in which we operate • assess the effectiveness of key community partnership initiatives	• developed a Stakeholder and Community Engagement Policy, training program and appointed a senior manager to support its delivery and integration • developed and implemented Aboriginal procurement guidelines • piloted a World Business Council for Sustainable Development tool to improve social investment decisions in the context of our impact on a community • implemented the London Benchmarking Group framework for measuring the impacts of community partnership investments	• improve the consistency and capability relative to engaging with stakeholders • solicit feedback from external stakeholders regarding the effectiveness of the Company's interactions • initiate and implement a social investment program that is integral to the Libya Concession Development • introduce a number of new key community partnerships in our education, environment and local community support areas • advance Olympic initiatives in anticipation of the 2010 Winter Olympics

14 PETRO-CANADA Management's Discussion and Analysis

Following our Principles for Responsible Investment and Operations (continued)

PRIORITY	PRINCIPLES	2007 GOALS	2007 RESULTS	2008 GOALS

Environment	• conduct our activities with sound environmental management and conservation practices • strive to minimize the environmental impact of our operations • work diligently to prevent any risk to community health and safety from our operations or our products • seek opportunities to transfer expertise in environmental protection to host communities	• strengthen environmental stewardship by developing specific commitments and indicators for air, land and water management • complete first phase of the environmental management system to steward performance against principles and indicators • improve method to capture and report environmental expenditures • submit environmental impact assessment in support of drilling programs offshore Trinidad and Tobago	• developed a set of Water Principles to guide operations in managing this key risk • signed Memorandum of Agreement (MOA) to use treated waste water as the industrial process water at the Fort Hills Sturgeon Upgrader • environmental expenditure reporting methodology still in progress • incorporated cost of carbon into business plan • completed first emissions offset trade on surplus credits from North Sea operations • participated in Alberta's first emissions credit auction • completed first phase of environmental information management system for air and GHG emissions • lowered environmental exceedances from 24¹ in 2006 to 16 in 2007, partially due to change in asset mix • submitted environmental impact assessment supporting drilling programs offshore Trinidad and Tobago	• integrate Water Principles into the environmental stewardship process • pilot carbon intensity performance measures • continue to review internal and external GHG mitigation opportunities • meet 2008 auditable emissions reporting requirements • commence development of second phase of environmental information management system for water and waste management • advance major water-related community partnership projects

1: 2006 environmental exceedances included the Brazeau and West Pembina assets, which were sold in the first quarter of 2007.

Management's Discussion and Analysis PETRO-CANADA 15

Following our Principles for Responsible Investment and Operations (continued)

PRIORITY	PRINCIPLES	2007 GOALS	2007 RESULTS	2008 GOALS

Working Conditions and Human Rights	• provide a healthy, safe and secure work environment • honour internationally accepted labour standards prohibiting child labour, forced labour and discrimination in employment • respect freedom of association and expression in the workplace • not be complicit in human rights abuses • support and respect the protection of human rights within our sphere of influence	• sustain and further improve safety • develop health performance metrics to address and mitigate the impact of employee illness • enhance the social risk impact assessment process in the project management model	• achieved total recordable injury frequency (TRIF) of 0.86 in 2007, compared with 0.85 in 2006 • experienced two contractor fatalities in 2007 • continued to evolve Company's internal health metrics • developed guidelines for an early phase social risk assessment in our international operations • conducted a corporate-wide process safety review to assess opportunities to strengthen TLM framework • hired 862 new employees and delivered a low voluntary turnover rate of 4.3% • finalized pandemic planning based on emergency response exercises	• establish enterprise wide contractor engagement process for selection, performance monitoring and management • attract 925 new employees • develop capability in managing the social issues of a temporary foreign workforce • pilot a social risk assessment that will apply to new operations • enhance management, systems and work processes related to process safety • strengthen process for communicating and learning from internal high potential and serious events

Business Strategy Looking Forward

Striving to ensure that existing facilities run safely, reliably and efficiently through excellent execution will continue to be a key focus for Petro-Canada. This same focus on execution will apply to the advancement of seven major projects over the next several years. Capital expenditures are expected to increase to between $6 billion and $7 billion per year for the next several years, reflecting spending on these major projects. In 2008, growth highlights are expected to include the Edmonton refinery conversion project coming on-stream and final investment decisions on the Montreal coker, the Fort Hills mining and upgrading project, and the Syria gas project. The Company also plans on drilling up to 17 exploration wells in the North Sea, offshore Trinidad and Tobago, Libya, the NWT and the Alaska Foothills.

Major Project	Target On-Stream Date

Edmonton Refinery Conversion	2008
Libya Concession Development	2008
White Rose Extensions	2009
Syria Ebla Gas Development	2010
Montreal Refinery Coker	2010
MacKay River Expansion	2011
Fort Hills – Phase I	2011 / 2012

16 PETRO-CANADA Management's Discussion and Analysis

RISK MANAGEMENT

Risks Relating to Petro-Canada's Business

Petro-Canada's results are impacted by several risks and management's strategies for handling these risks. Management believes each major risk requires a unique response based on Petro-Canada's business strategy and financial tolerance. Some risks can be effectively managed through internal controls, business processes, insurance and hedging. Hedging is used in limited circumstances, mainly to mitigate Downstream risks associated with refinery feedstock costs. Petro-Canada's business risks include, but are not limited to, the following items. These risks could have a material adverse effect on the Company's business, financial conditions, and results of operations.

A substantial or extended decline in crude oil or natural gas prices could have a material adverse effect on Petro-Canada.

The Company's financial condition depends substantially on the market prices of crude oil and natural gas. Fluctuations in crude oil or natural gas prices could have a material adverse effect on Petro-Canada's financial condition, as well as the value and amount of the Company's reserves. Prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of other factors beyond Petro-Canada's control. These factors include, but are not limited to, the actions of OPEC, world economic conditions, government regulation, political developments, the foreign supply of oil, the price of foreign imports, the availability of alternate fuel sources and weather conditions. Canadian natural gas prices are primarily affected by North American supply and demand, weather conditions, the level of industry inventories, political events, and, to a lesser extent, the price of alternate sources of energy.

Any substantial or extended decline in the prices of crude oil or natural gas could result in a delay or cancellation of existing or future drilling, development or construction programs, curtailment in production at some properties and unused long-term transportation commitments.

The margins realized for Petro-Canada's refined products are also affected by factors such as crude oil price fluctuations due to the impact on refinery feedstock costs, third-party refined product purchases and the demand for refined petroleum products. The Company's ability to maintain product margins in an environment of higher feedstock costs depends upon its ability to pass higher costs on to customers.

Factors that affect Petro-Canada's ability to execute projects could adversely affect business results.

Petro-Canada manages a variety of projects to support continuing operations and future growth. Significant project cost over-runs could make certain projects uneconomic. The Company's ability to execute projects depends upon numerous factors, some of which extend beyond Petro-Canada's control. These factors include, but are not limited to: changes in project scope, labour availability and productivity, staff resourcing, availability and cost of material and services, design and/or construction errors, delays in regulatory approvals and access to capital funding.

As a result, Petro-Canada may not be able to execute projects on time, on budget or at all.

A failure to acquire or find additional reserves would cause a decline in Petro-Canada's reserves and production levels.

The Company's future oil and natural gas reserves and production and, therefore, cash flows are highly dependent upon success in exploiting Petro-Canada's current reserves base and acquiring or discovering additional reserves. Without reserves additions through exploration, acquisition or development activities, Petro-Canada's reserves and production will decline over time. Exploring for, developing or acquiring reserves is capital intensive. To the extent cash flows from operations are insufficient to fund the Company's capital expenditures and external sources of capital become limited or unavailable, Petro-Canada's ability to make the necessary capital investments to maintain oil and natural gas reserves will be impaired. Costs to find and develop or acquire additional reserves also depend on success rates, which vary over time.

Management's Discussion and Analysis PETRO-CANADA 17

Petro-Canada's oil and natural gas reserves data and future net revenue estimates are subject to variability.

There are many uncertainties inherent in estimating quantities of oil and natural gas reserves, including many factors beyond the Company's control. Estimates of economically recoverable oil and natural gas reserves are based upon a number of variables and assumptions. These include geoscientific interpretation, commodity prices, operating and capital costs and historical production from properties. These estimates have some degree of uncertainty and reserves classifications are best estimates. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributed to properties and classification of reserves based on recovery risk may vary substantially. Petro-Canada's actual production, revenues, taxes and development and operating expenditures related to reserves may vary materially from estimates.

Petro-Canada's operations are subject to physical damage, business interruption and casualty losses.

Petro-Canada is subject to the operating risks associated with exploring for and producing oil and natural gas, as well as operating midstream and downstream facilities. These risks include blowouts, explosions, fires, gaseous leaks, equipment failures, migration of harmful substances, adverse weather conditions and oil spills. These risks could cause personal injury, could result in damage or destruction to oil and natural gas wells, formations, production facilities, other property and equipment, and the environment, and could interrupt operations. In addition, Petro-Canada's operations are subject to the risks related to transporting, processing and storing of oil, natural gas and other related products, drilling of oil and natural gas wells, and operating and developing oil and natural gas properties.

Changes in governmental regulation affecting the oil and natural gas industry could have a material adverse impact on Petro-Canada.

The petroleum industry is subject to regulation and intervention by governments, including the awarding of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, regulation of the development and abandonment of fields (including restrictions on production) and, possibly, expropriation or cancellation of contract rights. As well, governments may regulate or intervene on prices, taxes, royalties and the exportation of oil and natural gas. Regulations may be changed in response to economic or political conditions. New regulations or changes to existing regulations that affect the oil and natural gas industry could reduce demand for natural gas or crude oil, and increase Petro-Canada's costs.

Fluctuations in exchange rates create foreign currency exposure.

Due to the fact that energy commodity prices are primarily in U.S. dollars, Petro-Canada's revenue stream is affected by the Cdn/U.S. dollar exchange rate. The Company's net earnings are negatively affected by a strengthening Cdn dollar. Petro-Canada is also exposed to fluctuations in other foreign currencies, such as the euro and British pounds sterling.

Petro-Canada's foreign operations may expose the Company to risks, which could negatively affect results of operations.

The Company has operations in a number of countries with different political, economic and social systems. As a result, Petro-Canada's operations and related assets are subject to a number of risks, which may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks, increases in taxes and governmental royalties, renegotiation of contracts with governmental entities and quasi-governmental agencies, changes in laws and policies governing operations of foreign-based companies, economic and legal sanctions (such as restrictions against countries that the U.S. government may deem to sponsor terrorism) and other uncertainties arising from foreign government sovereignty over Petro-Canada's international operations. If a dispute arises in Petro-Canada's foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be able to subject foreign persons to the jurisdiction of a court in the U.S. or Canada.

18 PETRO-CANADA Management's Discussion and Analysis

The Company has operations in Libya, which is a member of OPEC. Petro-Canada may operate in other OPEC-member countries in the future. Production in those countries may be constrained by OPEC quotas.

Petro-Canada is subject to environmental legislation in all jurisdictions where it operates. Changes in this legislation could negatively affect the Company's results of operations.

Petro-Canada is subject to environmental regulation under a variety of Canadian, U.S. and other foreign, federal, provincial, territorial, state and municipal laws and regulations. This is collectively referred to below as environmental legislation.

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous and non-hazardous substances, including natural resources and waste, and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation requires that wells, facility sites and other properties associated with Petro-Canada's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Certain types of operations, including exploration and development projects, and changes to certain existing projects, may require submitting and seeking the approval of environmental impact assessments or permit applications. Complying with environmental legislation can require significant expenditures, including costs for cleanup and damages due to contaminated properties. Failure to comply with environmental legislation may result in fines and penalties. Petro-Canada is also exposed to civil liability for environmental matters, including private parties commencing actions, new theories of liability and new heads of damages. Although it is not expected that the costs of complying with environmental legislation or dealing with environmental civil liabilities, as they are known today, will have a material adverse effect on Petro-Canada's financial condition or results of operations, no assurance can be made that the costs of complying with future environmental legislation will not have a material effect.

The Kyoto Protocol, effective in Canada since 2005, requires signatory nations to reduce their emissions of carbon dioxide and other greenhouse gases (collectively, GHG). The details of the implementation of a federal GHG emissions reduction program in Canada have not been finalized. Depending on the specifics of the regulations, compliance options currently being considered include reduction of GHG emissions from operations, the purchase of emission-trading credits, or the purchase of other types of offsets. As of December 31, 2007, the only financial GHG obligations in Canada impacting Petro-Canada's operations were the Specified Gas Emitters Regulation in Alberta and the Green Tax in Quebec. It is premature to predict what impact changes to federal or provincial regulations will have on the Canadian oil and natural gas industry, but Petro-Canada will most likely face increased capital and operating costs in order to comply with GHG emissions targets and/or reductions which costs may be material.

Petro-Canada's oil and natural gas production and refining operations impact communities and surrounding environments.

Those impacted by Petro-Canada's operations can become concerned over the use of resources, such as land and water, the perceived or real threat to human health, the potential impact on biodiversity, and/or possible societal changes to surrounding communities. The Company must secure and maintain formal regulatory approvals and licences in order to conduct operations. In addition, broader societal acceptance of Petro-Canada's activities is necessary for resource development. An inability for the Company to secure local community support, necessary regulatory approvals and licences, and broader societal acceptance can result in projects being delayed or stopped, resulting in higher project costs. Lack of local community and stakeholder support can lead to pressure to limit or shut down operations.

Counterparties exposure.

Petro-Canada is exposed to credit risk, and operational risk associated with counterparties' abilities to fulfil their obligations to the Company.

Management's Discussion and Analysis PETRO-CANADA 19

Petro-Canada does not operate all of its properties and assets.

Other companies operate some of the assets in which Petro-Canada has interests. As a result, the Company has limited ability to exercise influence over operations of these assets or their associated costs. The risks associated with assets operated by others depend upon a number of factors that may be outside of Petro-Canada's control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices applied to the assets.

Marketing of production could adversely affect Petro-Canada's business.

The Company's ability to market its oil and natural gas depends on numerous factors. These include, but are not limited to, availability of processing capacity, availability and proximity of pipeline capacity, supply of and demand for oil and natural gas, availability of alternative fuel sources, effects of weather, availability of drilling and related equipment and accidental events. These factors could cause Petro-Canada to be unable to market all of the oil and natural gas that the Company produces.

20 PETRO-CANADA Management's Discussion and Analysis

CONSOLIDATED FINANCIAL RESULTS

Analysis of Consolidated Earnings and Cash Flow

Consolidated Financial Results

On January 31, 2006, Petro-Canada closed the sale of the Company's producing assets in Syria. These assets and associated results are reported as discontinued operations and are excluded from continuing operations.

(millions of Canadian dollars, unless otherwise indicated)			2007		2006		2005

Net earnings		$	2,733	$	1,740	$	1,791
Net earnings from discontinued operations			–		152		98

Net earnings from continuing operations		$	2,733	$	1,588	$	1,693

Earnings per share from continuing operations(dollars)	– basic	$	5.59	$	3.15	$	3.27
	– diluted		5.53		3.11		3.22
Earnings per share(dollars)	– basic	$	5.59	$	3.45	$	3.45
	– diluted		5.53		3.41		3.41
Cash flow from continuing operating activities¹			3,339		3,608		3,783
Cash flow from continuing operating activities per share(dollars)			6.83		7.16		7.30
Debt			3,450		2,894		2,913
Cash and cash equivalents ²			231		499		789
Average capital employed ²		$	14,328	$	12,868	$	11,860
Return on capital employed(%) ²			19.8		14.3		16.0
Return on equity(%) ²			24.5		17.5		19.7

1: Cash flow from continuing operating activities in 2007 was reduced by the payment of $1,145 million after-tax to settle the Buzzard derivative contracts.
2: Includes discontinued operations.

2007 Compared with 2006

Net earnings from continuing operations increased 72% to $2,733 million in 2007, compared with $1,588 million in 2006. Higher upstream production and realized crude oil prices, strong Down-stream refining margins, foreign currency translation gains, tax adjustments and lower other expenses contributed to the increase. These factors were partially offset by declining realized natural gas prices, higher exploration and depreciation, depletion and amortization (DD&A) expenses and increased operating and general and administrative (G&A) expenses.

1: Other mainly includes interest expense, changes in effective tax rates, gain on sale of assets, insurance proceeds, amounts related to the derivative contracts associated with Buzzard and upstream inventory levels.

Management's Discussion and Analysis PETRO-CANADA 21

In 2007, net earnings from continuing operations included a number of unusual items: net losses on the Buzzard derivative contracts of $331 million, a foreign currency translation gain on long-term debt of $208 million, a $191 million income tax recovery, a $97 million charge for asset impairment, a gain on sale of assets of $58 million, a $54 million charge related to the mark-to-market of stock-based compensation, $30 million in insurance proceeds and a $7 million insurance premium recovery.

In 2006, net earnings from continuing operations included a number of unusual items: a $240 million loss on the Buzzard derivative contracts, a $185 million income tax charge, $37 million in insurance proceeds, a $31 million charge related to the mark-to-market of stock-based compensation, a $29 million insurance premium surcharge, a $25 million gain on the sale of assets and a $1 million gain in foreign currency translation.

Quarterly Information

Consolidated Quarterly Financial Results

			2007									2006

(millions of Canadian dollars, unless otherwise indicated)			Quarter 1		Quarter 2		Quarter 3		Quarter 4			Quarter 1		Quarter 2		Quarter 3		Quarter 4

Total revenue from continuing operations		$	4,841	$	5,478	$	5,497	$	5,434		$	4,188	$	4,730	$	5,201	$	4,550
Net earnings from continuing operations			590		845		776		522			54		472		678		384
Cash flow from (used in) continuing operating activities¹			1,166		1,435		1,340		(602	)		886		799		959		964
Earnings per share from continuing operations(dollars)
	– basic	$	1.19	$	1.71	$	1.59	$	1.08		$	0.11	$	0.93	$	1.36	$	0.77
	– diluted	$	1.18	$	1.70	$	1.58	$	1.07		$	0.10	$	0.92	$	1.34	$	0.76
Earnings per share(dollars)
	– basic	$	1.19	$	1.71	$	1.59	$	1.08		$	0.40	$	0.93	$	1.36	$	0.77
	– diluted	$	1.18	$	1.70	$	1.58	$	1.07		$	0.40	$	0.92	$	1.34	$	0.76

1: Cash flow from (used in) continuing operating activities in the fourth quarter of 2007 was significantly reduced due to the payment of $1,145 million after-tax to settle the Buzzard derivative contracts.

Revenue and net earnings variances from quarter to quarter 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 website at www.petro-canada.ca.

22 PETRO-CANADA Management's Discussion and Analysis

LIQUIDITY AND CAPITAL RESOURCES

Summary of Cash Flows

(millions of Canadian dollars)			2007			2006			2005

Cash flow from continuing operating activities		$	3,339		$	3,608		$	3,783
Cash flow from discontinued operating activities			–			15			204
Net cash inflows (outflows) from:
	– investing activities		(3,647	)		(2,738	)		(3,358	)
	– financing activities		40			(1,175	)		(10	)

Increase (decrease) in cash and cash equivalents		$	(268	)	$	(290	)	$	619

Cash and cash equivalents at end of year		$	231		$	499		$	789

Cash and cash equivalents – discontinued operations		$	–		$	–		$	68

In 2007, cash flow from continuing operating activities was $3,339 million ($6.83/share), compared with $3,608 million ($7.16/share) in 2006. The decrease in cash flow was primarily due to the $1,145 million after-tax payment to settle the Buzzard derivative contracts, partially offset by higher net earnings from continuing operations.

Financial Ratios

		2007	2006	2005

Interest coverage from continuing operations(times)¹
	Net earnings basis	26.0	19.2	17.9
	EBITDAX basis	39.2	27.0	25.4
	Cash flow basis	27.2	27.1	29.9
Debt-to-cash flow from continuing operating activities(times)		1.0	0.8	0.8
Debt-to-debt plus equity(%)		22.5	21.7	23.5

1: Refer to the Glossary of Terms and Ratios on page 112 for methods of calculation.

Petro-Canada's financing strategy is designed to maintain financial strength and flexibility to support profitable growth in all business environments. Two key measures that Petro-Canada uses to measure the Company's overall financial strength are debt-to-cash flow from continuing operating activities and debt-to-debt plus equity. Petro-Canada's debt-to-cash flow from continuing operating activities ratio, the key short-term measure, was 1.0 times at December 31, 2007 and 0.8 times at year-end 2006. This was well within the Company's target range of no more than 2.0 times. Debt-to-debt plus equity, the long-term measure

for capital structure, was 22.5% at year-end 2007, up from 21.7% at year-end 2006. This was below the target range of 25% to 35% for both years, providing the financial flexibility to fund the Company's capital program and profitable growth opportunities. In the future, from time to time, Petro-Canada may exceed target ranges for short periods of time, but always with the goal to return back within the target ranges. Financial covenants associated with the Company's various debt arrangements are reviewed regularly and controls are in place to maintain compliance with these covenants.

Management's Discussion and Analysis PETRO-CANADA 23

Operating Activities

Excluding cash and cash equivalents, short-term notes payable and the current portion of long-term debt, the operating working capital deficiency, including discontinued operations, was $565 million at December 31, 2007, compared with an operating working capital deficiency, including discontinued operations, of $1,014 million at December 31, 2006. The working capital deficiency was lower primarily due to an increase in accounts receivable and income taxes receivable, partially offset by an increase in accounts payable.

Investing Activities

Capital and Exploration Expenditures

(millions of Canadian dollars)		2008 Outlook		2007		2006		2005

Upstream
North American Natural Gas	$	675	$	866	$	788	$	713
Oil Sands		1,520		779		377		772
International & Offshore
East Coast Canada		295		159		256		314
International¹		1,635		762		760		696

	$	4,125	$	2,566	$	2,181	$	2,495

Downstream
Refining and Supply	$	950	$	1,214	$	1,038	$	883
Sales and Marketing		150		155		142		108
Lubricants		25		27		49		62

	$	1,125	$	1,396	$	1,229	$	1,053

Shared Services	$	35	$	26	$	24	$	12

Total property, plant and equipment and exploration	$	5,285	$	3,988	$	3,434	$	3,560
Other assets		–		121		50		70

Total continuing operations	$	5,285	$	4,109	$	3,484	$	3,630

Discontinued operations	$	–	$	–	$	1	$	46

Total	$	5,285	$	4,109	$	3,485	$	3,676

1: International excludes capital expenditures related to the Syrian producing assets, which were sold in 2006 and are reflected as discontinued operations.

Capital and exploration expenditures were $4,109 million in 2007, up 18% compared with $3,485 million in 2006, mainly reflecting higher investment in Oil Sands and the Edmonton refinery conversion project.

In 2008, spending on new growth projects is expected to increase substantially. Two-thirds of planned capital expenditures support delivering profitable new growth and funding exploration and new ventures. This is up by more than $1 billion, compared with the same categories in 2007. The remaining one-third of 2008 planned capital expenditures is directed toward replacing reserves in core areas, enhancing existing assets, improving base business profitability and complying with new regulations.

2008 Capital Program from Continuing Operations

24 PETRO-CANADA Management's Discussion and Analysis

Financing Activities and Dividends

Sources of Capital Employed

(millions of Canadian dollars)		2007		2006		2005

Short-term notes payable	$	109	$	–	$	–
Long-term debt, including current portion		3,341		2,894		2,913
Shareholders' equity		11,870		10,441		9,488

Total	$	15,320	$	13,335	$	12,401

Total debt increased to $3,450 million at December 31, 2007, compared with $2,894 million at the previous year end. The increase in debt occurred to fund operations after available cash balances were used to settle the Buzzard derivative contracts. The increase was partially offset by the impact of a strengthening Cdn dollar.

2007 Financing Activities

At December 31, 2007, Petro-Canada's syndicated committed credit facilities totalled $2,200 million and the Company's bilateral demand credit facilities totalled $1,500 million. A total of $1,372 million of the credit facilities was used for Bankers' Acceptances, letters of credit and overdraft coverage. As at December 31, 2007, there was $1,104 million in Bankers' Acceptances outstanding.

As at December 31, 2007, the Company's unsecured long-term debt securities are rated Baa2 by Moody's Investors Service, BBB by S&P and A (low) by Dominion Bond Rating Service. The Company's long-term debt ratings remained unchanged from year-end 2006. Petro-Canada's short-term debt securities are rated R-1 (low) by Dominion Bond Rating Service. This rating remains unchanged from year-end 2006.

As the Company moves into 2008 and beyond, spending on future large projects will likely result in annual capital expenditures exceeding operating cash flow. The Company anticipates that additional funding requirements will be met by external financing. As financial leverage is expected to increase over time, it will be managed in the context of Petro-Canada's target ranges.

Returning Cash to Shareholders

Petro-Canada's priority uses of cash are to fund the capital program and profitable growth opportunities, and then to return cash to shareholders through dividends and a share buyback program.

Petro-Canada regularly reviews its dividend strategy to ensure the alignment of the dividend policy with shareholder expectations, and financial and growth objectives. Total dividends paid in 2007 were $255 million ($0.52 per share), compared with $201 million ($0.40 per share) in 2006.

Petro-Canada renewed its NCIB program for the repurchase of its common shares from June 22, 2007 to June 21, 2008, entitling the Company to purchase up to 5% of its outstanding common shares, subject to certain conditions. Due to an increasing capital program, share buybacks are expected to be lower in future years, compared with 2006 and 2007.

	Shares Repurchased		Average Price				Total Cost

Period	2007	2006		2007		2006		2007		2006

Full year	15,998,000	19,778,400	$	52.42	$	51.10	$	839 million	$	1,011 million

Management's Discussion and Analysis PETRO-CANADA 25

Off Balance Sheet

The Company has certain retail licensee and wholesale marketing agreements that would constitute variable interest entities as described in Note 25 to the Consolidated Financial Statements. These entities are not consolidated because Petro-Canada is not the primary beneficiary and, therefore, consolidation is not required. The Company's maximum exposure to losses from these arrangements would not be material. Other off balance sheet activities are limited to the accounts receivable securitization program, which does not meet the criteria for consolidation.

Pension Plans

At year-end 2007, Petro-Canada's defined benefit pension plans were under funded by $282 million, compared with an under funded position of $300 million at year-end 2006. For both the defined benefit and defined contribution pension plans, the Company made cash contributions of $121 million and recorded a pension expense of $81 million before-tax in 2007. This compares with $114 million of cash contributions and $91 million before-tax of pension expense in 2006. The Company expects to make pension contributions of approximately $58 million in 2008.

Contractual Obligations – Summary

	Payments due by period

(millions of Canadian dollars)		Total		2008		2009-2010		2011-2012		2013 and thereafter

Unsecured debentures and senior notes¹	$	6,269	$	1,257	$	298	$	298	$	4,416
Capital lease obligations¹		114		9		20		19		66
Operating leases		1,250		427		441		251		131
Transportation agreements		1,557		227		303		235		792
Product purchase/delivery obligations		15,119		3,967		4,165		1,967		5,020
Exploration work commitments²		103		82		20		1		–
Asset retirement obligations		4,136		50		79		66		3,941
Other long-term obligations^3,⁴		3,191		295		1,256		417		1,223

Total contractual obligations	$	31,739	$	6,314	$	6,582	$	3,254	$	15,589

1: Obligations include related interest. Amounts due in 2008 include $1 billion due under a revolving committed credit facility maturing in 2012. For further details, see Note 17 to the 2007 Consolidated Financial Statements.
2: 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 of the 2007 MD&A.
3: 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.
4: 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.

Total contractual obligations of $29.6 billion at December 31, 2006 included $11.4 billion of supply purchase agreements contracted at market prices where the product could reasonably be re-sold into the market¹. During 2007, Petro-Canada's total contractual obligations increased by $2.1 billion, mainly due to additional product purchase obligations, issuances of Bankers' Acceptances and an increase in the estimate of asset retirement obligations, partially offset by gains on the translation of foreign currency denominated unsecured debentures and senior notes.

1: As disclosed in footnote 2 to the table on page 17 of the 2006 annual MD&A.

26 PETRO-CANADA Management's Discussion and Analysis

UPSTREAM

Petro-Canada's upstream operations consisted of three business units in 2007: North American Natural Gas, with current production in Western Canada and the U.S. Rockies; Oil Sands with operations in northeast Alberta; and International & Offshore. International & Offshore has two segments: East Coast Canada, with three major developments offshore Newfoundland and Labrador; and International, where the Company is active in two core areas: North Sea and Other International. The diverse asset base provides a balanced portfolio and a platform for long-term growth.

North American Natural Gas

Business Summary and Strategy

North American Natural Gas explores for and produces natural gas, crude oil and natural gas liquids (NGL) in Western Canada and the U.S. Rockies. This business also markets natural gas in North America and has established resources in the NWT and Alaska.

The North American Natural Gas strategy is to be a significant market participant by accessing new and diverse natural gas supply sources in North America. Key features of the strategy include:

•: optimizing core properties in Western Canada and developing coal bed methane (CBM) and tight gas in the U.S. Rockies
•: targeting 50% to 60% reserves replacement
•: focused exploration activity in Western Canada, with increasing emphasis in the U.S.
•: building the northern resource base for long-term growth

North American Natural Gas Financial Results

(millions of Canadian dollars)		2007		2006		2005

Net earnings	$	191	$	405	$	674

Cash flow from continuing operating activities	$	725	$	651	$	1,219
Expenditures on property, plant and equipment and exploration	$	866	$	788	$	713
Total assets	$	4,119	$	4,151	$	3,763

2007 Compared with 2006

North American Natural Gas contributed $191 million of net earnings, down considerably from $405 million in 2006. Weak natural gas prices, lower Western Canada production, increased operating costs, higher exploration expenses and increased DD&A expenses were partially offset by higher U.S. Rockies production.

Net earnings in 2007 included a $97 million charge related to the impairment of CBM assets in the U.S. Rockies, a $41 million gain on sale of assets and an $8 million income tax recovery. Net earnings in 2006 included a $6 million income tax recovery.

Oil and natural gas production averaged 674 million cubic feet of oil equivalent/day (MMcfe/d) in 2007, down from 701 MMcfe/d in 2006, as natural declines in Western Canada were partially offset by U.S. Rockies production growth. Natural gas commodity prices declined over the course of 2007. The North American realized natural gas price averaged $6.30/Mcf in 2007, down 8% from $6.85/Mcf in 2006.

Management's Discussion and Analysis PETRO-CANADA 27

2007 Operating Review and Strategic Initiatives

The North American Natural Gas business is selectively investing to optimize the existing core assets in Western Canada and the U.S. Rockies, with focused exploration in these basins, and building the northern resource base for the longer term.

2007 Operating Review

			2007		2006		2005

Production net(MMcfe/d)
	Western Canada		590		646		704
	U.S. Rockies		84		55		52

Total North American Natural Gas production net			674		701		756

Western Canada realized natural gas price($/Mcf)		$	6.48	$	6.88	$	8.55
U.S. Rockies realized natural gas price($/Mcf)		$	4.88	$	6.36	$	7.17

Western Canada operating and overhead costs (dollars/thousand cubic feet of oil equivalent – $/Mcfe)		$	1.50	$	1.31	$	1.10
U.S. Rockies operating and overhead costs ($/Mcfe)		$	2.21	$	2.29	$	1.84

Western Canada

Western Canada natural gas production averaged 590 MMcfe/d in 2007, down 9% from 646 MMcfe/d in 2006. Exploration and development drilling activity in Western Canada resulted in 395 successful wells (gross), for an overall success rate of 93% in 2007. Western Canada realized natural gas price was $6.48/Mcf in 2007, compared with $6.88/Mcf in 2006. Western Canada operating and overhead costs were $1.50/Mcfe in 2007, up from $1.31/Mcfe in the previous year. The operating and overhead cost increase in Western Canada reflected general industry-wide cost pressures for materials, fuel and labour, combined with lower production.

U.S. Rockies

U.S. Rockies natural gas production averaged 84 MMcfe/d in 2007, up 53% from 55 MMcfe/d in 2006. Exit volumes for the year exceeded 100 MMcfe/d, a doubling of production from 2004 acquisition levels. The increase reflected the ramp up of production from the Wild Turkey and other CBM fields in the Powder River Basin and increased drilling activity in the Denver-Julesburg Basin. Exploration and development drilling activity in the U.S. Rockies during 2007 resulted in 150 gross wells, down from 280 wells in 2006. U.S. Rockies realized natural gas price was $4.88/Mcf in 2007, down from $6.36/Mcf in 2006 due to pipeline constraints. Late in 2007, the initial expansion of the Fort Union gas gathering system was completed, helping to reduce curtailments in the Powder River Basin. The completion of the Rockies Express pipeline expansion is expected to alleviate additional U.S. Rockies pipeline

28 PETRO-CANADA Management's Discussion and Analysis

constraints when it comes on-stream in 2008. U.S. Rockies operating and overhead costs were $2.21/Mcfe in 2007, down compared with $2.29/Mcfe in 2006 due to higher production.

2007 Strategic Initiatives

In Western Canada, the Company continued its planned shallow tight gas drilling program in the Medicine Hat area, drilling more than 300 wells in 2007. The business expects to drill another 360 wells in 2008. In the other core areas of British Columbia (BC) and Alberta, the Company continued to optimize existing fields with the drilling of more than 100 exploration and development wells in 2007. As part of the Company's ongoing optimization of its portfolio of assets, Petro-Canada completed the sale of its 31% working interest in the Brazeau plant and 7% of its 10% working interest in the West Pembina plant in early 2007.

During 2007, the Company advanced its exploration activities in Alaska by participating with FEX L.P. in three exploration wells on jointly held acreage in the National Petroleum Reserve – Alaska (NPR-A). The Company is positioning for 2008 exploratory drilling in the Alaska Foothills and the NWT.

One NPR-A well was abandoned, having failed to encounter reservoir quality sands in the primary target. Two wells have been suspended, with plans for future testing, having encountered several hydrocarbon bearing zones.

In the Alaska Foothills, the Company and its joint venture partners implemented pre-drill operations in 2007 for a two-well program in 2008, both wells targeting natural gas. In the Canadian North, the Company completed preparations to drill one well, also targeting natural gas, in the NWT.

In June 2007, the Quebec government granted a decree approving the proposal to construct the Gros-Cacouna LNG re-gasification terminal. The National Energy Board (NEB) approved an application by TransCanada PipeLines Limited for a natural gas pipeline receipt point at Gros-Cacouna, Quebec, as well as a rolled-in toll methodology for the proposed project.

In February 2008, Gazprom (the potential anchor supply for the proposed project) decided not to pursue a Baltic LNG project with Petro-Canada. As a result, the Company and its partner are reviewing the long-term outlook for the Gros-Cacouna project.

The Company sees long-term potential for the development of Arctic island natural resources discovered in the 1970s and 1980s. In January 2008, a small team was formed to look at the feasibility of developing the Company's assets in this region. The two largest assets Petro-Canada holds in the region are the Drake and Hecla fields on Melville Island.

Capital expenditures in 2007 totalled $866 million, with $533 million for exploration and development of natural gas in Western Canada, $210 million for other natural gas opportunities in North America and $123 million for U.S. Rockies exploration and development.

Outlook

Production expectations in 2008

•: production is expected to average about 630 MMcfe/d net of natural gas, crude oil and NGL

Action plans in 2008

•: drill approximately 400 gross wells in Western Canada and approximately 300 gross wells in the U.S. Rockies
•: advance long-term opportunities in Northern Canada and Alaska

Capital spending plans in 2008

•: approximately $415 million for replacing reserves in Western Canada core areas
•: approximately $190 million for growth opportunities in the U.S. Rockies
•: approximately $70 million directed to exploration in the Far North

The Company plans to continue selectively investing in core assets in Western Canada to optimize existing fields, with about 360 wells planned to continue the drilling program in the Medicine Hat area and more than 50 exploration and development wells in other BC and Alberta areas. As part of this activity, the Company is seeking regulatory approval in 2008 to proceed with a multi-well development program in the Sullivan field. The development of CBM and tight gas in the U.S. Rockies will continue, with the drilling of about 300 development wells, along with an increasing focus on exploration. The reduced spending and natural production declines in Western Canada are expected to result in approximately a 7% drop in production in 2008, compared with 2007.

The Company will also continue to advance long-term supply opportunities. In the Alaska Foothills and NWT, the Company plans to start testing its exploration lands by drilling up to three wells in early 2008.

Management's Discussion and Analysis PETRO-CANADA 29

Link to Petro-Canada's Corporate and Strategic Priorities

The North American Natural Gas business is aligned with Petro-Canada's strategic priorities as outlined by its progress in 2007 and goals for 2008.

PRIORITY	2007 GOALS	2007 RESULTS	2008 GOALS

Delivering Profitable Growth with a Focus on Operated, Long-Life Assets	• transition further into unconventional gas plays • optimize opportunities around core assets • double U.S. Rockies production to 100 MMcfe/d net by year-end 2007 • shift focus from developing around existing production to exploring in new areas • receive regulatory decision for the LNG facility at Gros-Cacouna • advance exploration prospects in the Mackenzie Delta/Corridor¹ and Alaska	• 26% of 2007 production was unconventional, compared with 22% in 2006 • drilled 427 gross wells in Western Canada focused on the Company's core assets, including 312 wells in the Medicine Hat region • exited 2007 having achieved 100 MMcfe/d net production from the U.S. Rockies • drilled 150 gross wells and continued to increase CBM well de-watering in the U.S. Rockies • exploration activity in 2007 continued exploration shift to the U.S. • received provincial regulatory approval to construct the proposed LNG re-gasification terminal at Gros-Cacouna • NEB approved application for new pipeline receipt point at Gros-Cacouna and reaffirmed rolled-in tolling methodology for the proposed pipeline expansion • participated in three Alaska NPR-A wells, with plans to test two of the wells that encountered hydrocarbons	• continue to selectively optimize Western Canada core assets • continue U.S. Rockies CBM and tight natural gas development • target 50% to 60% reserves replacement from these core assets • focus exploration activity in Western Canada, with increasing emphasis on the U.S. • advance exploration prospects in the NWT and Alaska • initiate an Arctic LNG feasibility study

Driving for First Quartile Operation of Our Assets	• sustain reliability performance • continue to leverage costs through strategic alliances and preferred suppliers	• maintained reliability of 99% at Western Canada natural gas processing facilities • delivered value to the organization through preferred supplier relationships, while continuing to ensure competitive supply costs through selective bidding	• continue to focus on safety and reliability performance • continue to leverage costs through strategic alliances and preferred suppliers

Continuing to Work at Being a Responsible Company	• continue to focus on TRIF and maintain low regulatory exceedances • complete the roll out of behaviour-based safety for employees and contractors • drive for continuous improvement in contractor safety performance • proactively remediate and reclaim old sites	• TRIF increased to 1.54, compared with 1.42 in 2006 due mostly to the addition of select U.S. contractors to the TRIF calculation • completed the roll out of behaviour-based safety for employees and contractors • improved Western Canada contractor injury frequency • recorded three regulatory compliance exceedances in 2007, compared with nine in 2006 • established a program for risk assessment and managing the reclamation of old sites	• continue to focus on TRIF and maintain low regulatory exceedances • conduct internal stakeholder engagement training for project managers and other key business roles • strengthen approach to investigating and learning from events

1: Mackenzie Delta/Corridor is also referred to as Northwest Territories (NWT) in this document.

30 PETRO-CANADA Management's Discussion and Analysis

Oil Sands

Business Summary and Strategy

Petro-Canada has approximately 1.2¹ billion barrels of Oil Sands proved plus probable reserves and more than 10.4² billion barrels of Contingent and Prospective Resources. The Company'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 Riverin situ bitumen development (a steam-assisted gravity drainage (SAGD) operation), a 60% ownership in and operatorship of the proposed Fort Hills oil sands mining and upgrading project, and extensive oil sands acreage considered prospective forin situ development of bitumen resources.

1: These reserves numbers represent the sum of oil sands mining and oil and gas activities, including probable reserves, and are presented before royalties. Reporting reserves in this manner does not conform to SEC standards and is for general supplemental information only.
2: 45% of total Oil Sands resources are risked Prospective Resources and 55% are Contingent Resources.

The Oil Sands strategy for profitable growth includes:

•: integrated development of reserves to maximize financial returns
•: disciplined capital investment to optimize the value created by long-life projects
•: a staged approach to development of capital-intensive oil sands projects to allow rigorous cost management and the opportunity to benefit from evolving technology

The Company has chosen to participate in the full oil sands value chain due to its resource potential and strong position with bitumen upgrading capacity. Petro-Canada has processing capacity through Syncrude and Suncor Energy Inc. (starting in 2008). The Company is also converting the conventional crude oil train at its Edmonton refinery to refine oil sands-based feedstock from northern Alberta, which is expected to start up at the end of 2008. This conversion, along with the existing synthetic crude supply, will result in the refinery running on an exclusive diet of oil sands-based feedstock. This connection between resource and upgrading capacity should provide more economic certainty in a business where volatile light/heavy differentials affect bitumen pricing.

Oil Sands Financial Results

(millions of Canadian dollars)		2007		2006		2005

Net earnings	$	316	$	245	$	115

Cash flow from continuing operating activities	$	512	$	499	$	340
Expenditures on property, plant and equipment and exploration	$	779	$	377	$	772
Total assets	$	3,659	$	2,885	$	2,623

2007 Compared with 2006

Oil Sands contributed a record $316 million of net earnings, up 29% from $245 million in 2006. Higher realized prices and production at Syncrude were partially offset by lower production and increased operating costs at MacKay River.

Net earnings in 2007 included a $62 million income tax recovery. Net earnings in 2006 included a $44 million income tax recovery and $12 million of Syncrude insurance proceeds related to the 2005 hydrogen plant fire.

Management's Discussion and Analysis PETRO-CANADA 31

Record prices and production at Syncrude were highlights of 2007 performance. Syncrude realized price for synthetic crude oil averaged $79.20/bbl in 2007, up from $72.13/bbl in 2006. MacKay River realized price for bitumen averaged $28.23/bbl in 2007, compared with $28.93/bbl in 2006. Oil Sands production averaged 56,900 b/d net in 2007, compared with 52,200 b/d net in 2006.

2007 Operating Review and Strategic Initiatives

In 2007, Oil Sands delivered a record $316 million in net earnings. Oil Sands' strategic progress included completing the Fort Hills design basis and preliminary capital cost estimate, finalizing an agreement to earn an additional 5% of the Fort Hills project, continuing to ramp up the Syncrude Stage III expansion and beginning steaming the fourth well pad at MacKay River.

2007 Operating Review

			2007		2006		2005

Production net(b/d)
	Syncrude		36,600		31,000		25,700
	MacKay River		20,300		21,200		21,300

Total Oil Sands production net			56,900		52,200		47,000

Syncrude realized crude price($/bbl)		$	79.20	$	72.13	$	70.41
MacKay River realized bitumen price($/bbl)		$	28.23	$	28.93	$	18.53

Syncrude operating and overhead costs($/bbl)		$	26.94	$	30.00	$	31.90
MacKay River operating and overhead costs($/bbl)		$	20.97	$	17.83	$	17.06

Syncrude's production and unit operating costs were positively affected by the full-year impact of the Stage III expansion, which started up in 2006. Syncrude's production averaged 305,000 b/d gross (36,600 b/d net) in 2007, compared with 258,300 b/d gross (31,000 b/d net) in 2006. Ramp up of Stage III was hampered by Coker 8-3 related incidents in the fourth quarter of 2007. Average unit operating and overhead costs in 2007 decreased compared with 2006. Lower unit operating costs were mainly due to higher production and lower natural gas costs. Syncrude reached royalty payout in the second quarter of 2006 and shifted to a royalty rate of 25% of net operating revenues from 1% of gross revenues. The total royalty paid in 2007 equated to a rate of 15% of gross revenues. Petro-Canada and its partners in Syncrude remain in negotiations with the Government of Alberta regarding the province's desire for Syncrude to move to the New Alberta Royalty Framework recommendations in advance of the expiry of its existing royalty agreement in 2016.

MacKay River's production decreased slightly and unit operating costs increased considerably in 2007. Production averaged 20,300 b/d in 2007, down 4% compared with 21,200 b/d in 2006. Lower production reflected unplanned outages and reduced throughputs resulting from damage to a steam header. MacKay River reliability averaged 87% in 2007, down from 92% in 2006,

32 PETRO-CANADA Management's Discussion and Analysis

reflecting water treatment issues and several unplanned outages in the year. Unit operating and overhead costs increased by 18% in 2007, averaging $20.97/bbl, compared with $17.83/bbl in 2006. Higher unit operating costs were due to higher maintenance and repair costs and decreased production for the year, partially offset by lower natural gas costs.

2007 Strategic Initiatives

In April 2007, Syncrude joint venture owners initiated implementation of the Management Services Agreement with Imperial Oil Resources.

At MacKay River, the Company completed the MacKay River plant capacity upgrade and began steaming the fourth well pad. Production from the new well pad commenced in January 2008 and will ramp up throughout 2008.

The time frame for completion of FEED for the MacKay River expansion project was extended by one year due to cost pressures, including increased royalties. The economics forin situ oil sands projects are challenging, so the Company is proceeding at a measured pace. Currently, Petro-Canada is evaluating opportunities for integration with the Fort Hills project and pursuing cost-saving opportunities associated with using foreign engineering, procurement and construction (EPC) contractors. A final investment decision is now expected in the first quarter of 2009.

Based on the progress of the MacKay River expansion project in 2007, proved plus probable reserves increased from 310¹ million barrels (MMbbls) to 598¹ MMbbls. In addition, assessment of the newly acquired lands in the MacKay River area and the results of the 2006-07 delineation drilling and seismic programs resulted in overallin situ Contingent and risked Prospective Resources estimates before royalties, increasing from approximately 6.9 billion barrels to approximately 8.2 billion barrels.

1: The reporting of before royalty reserves information does not conform to SEC standards and is for general supplemental information only.

In June 2007, Petro-Canada and its partners in the Fort Hills integrated mine and upgrader project completed and announced the design basis and preliminary cost estimate for the project. The first phase of the project is planned to produce 140,000 b/d gross of synthetic crude oil (84,000 b/d net). Associated bitumen production is expected to be about 160,000 b/d gross (96,000 b/d net). First bitumen production is expected to begin in the fourth quarter of 2011, with first synthetic crude oil production from the Sturgeon Upgrader anticipated in the second quarter of 2012. The preliminary capital cost estimate for the mine and upgrading components of the first phase of the Fort Hills Project is $14.1 billion gross ($8.5 billion net).

In November 2007, Petro-Canada and its partners in the Fort Hills project finalized the agreement for the Company to earn an additional 5% working interest in the project in return for funding $375 million of partnership expenditures. This brings Petro-Canada's total stake in the Fort Hills project to 60%. The partnership also entered into a MOA with Sturgeon County and the Alberta Capital Region Wastewater Commission (ACRWC) to use treated waste water from the ACRWC as industrial process water at the Fort Hills Sturgeon Upgrader. Also in November 2007, Petro-Canada entered into an agreement, subject to the final investment decision, with Enbridge Inc., to develop pipeline and terminalling facilities to meet the requirements of Phase 1 and subsequent phases of the project.

Oil Sands capital expenditures of $779 million in 2007 included $531 million for the Fort Hills integrated mining and upgrading project, $95 million for the MacKay River expansion, $87 million for MacKay River, $58 million at the Syncrude operations and $8 million for other Oil Sands projects.

Management's Discussion and Analysis PETRO-CANADA 33

Outlook

Production expectations in 2008

•: Petro-Canada's share of Syncrude production is expected to average 35,000 b/d net
•: MacKay River bitumen production is expected to average 25,000 b/d net, which includes a major 10- to 15-day planned maintenance turnaround

Growth plans

•: work to improve reliability at Syncrude and MacKay River
•: advance MacKay River expansion project to enable a final investment decision in the first quarter of 2009
•: advance the Fort Hills oil sands mining and upgrading project to final investment decision
•: progress SAGD technology through research and development

Capital spending plans in 2008

•: approximately $1,311 million for new growth opportunities, the majority of which is to advance the Fort Hills project and the MacKay River expansion
•: approximately $147 million to enhance existing operations, comply with regulations and improve the base business profitability at Syncrude and MacKay River
•: approximately $62 million to replace reserves through ongoing pad development at MacKay River

Oil Sands production is expected to increase to 60,000 b/d net in 2008, compared with actual production of 56,900 b/d net in 2007. Higher expected production in 2008 is due to higher volumes anticipated at both Syncrude and MacKay River, partially offset by a major 10- to 15-day planned turnaround scheduled for May 2008 at MacKay River. The total Syncrude royalty payable in 2008 is expected to equate to a rate of between 14% and 17% of gross revenue, depending on crude oil prices. The total MacKay River royalty payable in 2008 is expected to be 1% of gross revenue.

In 2008, the Company expects to complete the Fort Hills mine, extraction and upgrading FEED, which establishes detailed cost estimates and a more detailed project schedule and workforce plan. Petro-Canada expects to receive a regulatory decision on the filed commercial application for the Sturgeon Upgrader by mid-2008. The Company also expects to make a final investment decision on the Fort Hills project in the third quarter of 2008.

The Oil Sands business has a capital program of about $1,520 million in 2008. Capital for new growth opportunities of $1,311 million includes funding the preliminary engineering and design for the Fort Hills project (forecast to be $1,165 million) and the FEED for the MacKay River expansion (forecast to be $90 million). With the initial phase of the Fort Hills project and the MacKay River expansion, Petro-Canada's production is expected to grow to more than 190,000 b/d net. Beyond that, the Company has the potential to grow the Oil Sands business to approximately 300,000 b/d net over the next decade. Petro-Canada is focused on resolving the challenges associated with the implementation of its Oil Sands strategy, including capital cost pressures, skilled labour shortages, and environmental and stakeholder issues. As an experienced and responsible operator, Petro-Canada is well positioned to meet these challenges.

34 PETRO-CANADA Management's Discussion and Analysis

Link to Petro-Canada's Corporate and Strategic Priorities

The Oil Sands business is aligned with Petro-Canada's strategic priorities as outlined by its progress in 2007 and goals for 2008.

PRIORITY	2007 GOALS	2007 RESULTS	2008 GOALS

Delivering Profitable Growth with a Focus on Operated, Long-Life Assets	• complete Fort Hills design basis and initial cost estimate, and start FEED • receive regulatory decision on MacKay River expansion project • continue ramp up of Syncrude Stage III expansion • complete MacKay River water handling capacity upgrade and tie-in a fourth well pad so that production can increase in 2008	• completed Fort Hills design basis, with Phase 1 estimated to cost $14.1 billion gross ($8.5 billion net) • signed MOA for an additional 5% interest in the Fort Hills project • Energy Resources Conservation Board and Alberta Environment recommended approval of MacKay River expansion to cabinet • Syncrude achieved record production of 305,000 b/d gross (36,600 b/d net) • completed MacKay River capacity upgrade and started steaming the fourth well pad	• complete Fort Hills FEED and make final investment decision in the third quarter of 2008 • order long-lead items for Fort Hills project • continue to ramp up Syncrude Stage III expansion • receive regulatory decision on MacKay River expansion project • continue to advance MacKay River expansion project in preparation for the final investment decision in the first quarter of 2009 • receive regulatory decision on the Sturgeon County Upgrader

Driving for First Quartile Operation of Our Assets	• decrease MacKay River non-fuel unit operating costs by 10%, compared with 2006 • decrease Syncrude non-fuel unit operating costs by 10%, compared with 2006 • sustain MacKay River reliability at greater than 90%	• saw MacKay River non-fuel unit operating costs increase by 26%, compared with 2006, as a result of higher maintenance costs and lower production • saw Syncrude non-fuel unit operating costs decrease by 8%, compared with 2006 • achieved 87% reliability at MacKay River	• ramp up MacKay River production to hit 30,000 b/d and increase reliability to greater than 90% • commence shipping MacKay River bitumen to the Edmonton refinery after it has been upgraded into synthetic crude oil at Suncor • decrease Syncrude non-fuel unit operating costs by 10%, compared with 2007

Continuing to Work at Being a Responsible Company	• maintain focus on TLM and Zero-Harm • ensure regulators, First Nations and other key stakeholders affected by major projects are properly consulted and engaged	• TRIF increased to 0.75, compared with 0.58 in 2006 due to more complex work, increased drilling activities and a larger number of new workers • followed through with effective stakeholder interactions, expediting the commercial application process for the MacKay River expansion • recorded one compliance exceedance for 2007, compared with five in 2006 • signed MOA to use treated waste water as the industrial process water at the Fort Hills Sturgeon Upgrader	• drive for continuous improvement in safety • continue relevant and transparent engagement with key stakeholders to obtain approval for the Sturgeon Upgrader and Fort Hills mine expansion • develop capability in managing the social issues of a temporary foreign workforce • pursue research on practical solutions for tailings management

Management's Discussion and Analysis PETRO-CANADA 35

International & Offshore

In the first quarter of 2007, the Company combined its East Coast Canada and International businesses under one management structure. The change leverages and grows the capabilities of similar operations. The combined East Coast Canada and International operations are now referred to as International & Offshore.

East Coast Canada

Business Summary and Strategy

Petro-Canada is positioned in every major producing oil development off Canada's east coast. The Company holds a 20% interest in Hibernia, a 27.5% interest in White Rose¹ and a 23.9% interest in Hebron, and is the operator with a 34% interest in Terra Nova.

The East Coast Canada strategy is to improve reliability and sustain profitable production well into the next decade leveraging the existing infrastructure. Key features of the strategy include:

•: delivering top quartile operating performance
•: sustaining profitable production through reservoir extensions and add-ons
•: pursuing high potential development projects

1: Petro-Canada's working interest in the White Rose Extensions will be 26.125% after the Provincial Energy Corporation acquires its 5% working interest effective with the signing of the final project agreements. There is no change to the White Rose 27.5% working interest for the original field development as the Provincial Energy Corporation is not a partner.

East Coast Canada Financial Results

(millions of Canadian dollars)		2007		2006		2005

Net earnings	$	1,229	$	934	$	775

Cash flow from continuing operating activities	$	1,491	$	1,129	$	1,002
Expenditures on property, plant and equipment and exploration	$	159	$	256	$	314
Total assets	$	2,345	$	2,465	$	2,442

2007 Compared with 2006

East Coast Canada contributed a record $1,229 million of net earnings, up 32% from $934 million in 2006. Strong realized prices and higher production were partially offset by increased DD&A expenses.

Net earnings in 2007 included a $52 million income tax recovery and $27 million of insurance proceeds related to mechanical failures on the Terra Nova Floating Production Storage and Offloading (FPSO) vessel. Net earnings in 2006 included a $37 million income tax recovery, $22 million of insurance proceeds related to mechanical failures on the Terra Nova FPSO vessel and a $9 million insurance premium surcharge.

36 PETRO-CANADA Management's Discussion and Analysis

In 2007, realized crude oil prices remained strong, while production increased. East Coast Canada realized crude prices averaged $75.87/bbl in 2007, up from $71.12/bbl in 2006. East Coast oil production averaged 98,700 b/d in 2007, up from 72,700 b/d in 2006. Higher Terra Nova and White Rose production was partially offset by natural declines at Hibernia.

2007 Operating Review and Strategic Initiatives

In 2007, East Coast Canada delivered record net earnings of $1,229 million. Terra Nova delivered solid production with facility reliability averaging 86%; White Rose ramped up production, averaging 117,500 b/d gross (32,300 b/d net), while natural reservoir declines reduced Hibernia production.

2007 Operating Review

			2007		2006		2005

Production net(b/d)
	Hibernia		26,900		35,700		39,800
	Terra Nova		39,500		12,800		33,700
	White Rose		32,300		24,200		1,800

Total East Coast Canada production net			98,700		72,700		75,300

Average realized crude price($/bbl)		$	75.87	$	71.12	$	63.15

Operating and overhead costs($/bbl)		$	4.86	$	7.71	$	4.52

Hibernia production averaged 134,500 b/d gross (26,900 b/d net) in 2007, down from 178,500 b/d gross (35,700 b/d net) in 2006, reflecting natural reservoir declines. Early in 2007, Hibernia experienced a mechanical failure on one of the platform's main power generators, thereby reducing production. The main power generator was repaired as part of a planned Hibernia 30-day turnaround completed in the first quarter of 2007. The total royalty paid at Hibernia in 2007 equated to a rate of 5% of gross revenues.

At Terra Nova, production averaged 116,200 b/d gross (39,500 b/d net), up considerably from 37,600 b/d gross (12,800 b/d net) in 2006. Terra Nova production was lower in 2006 due to a planned maintenance turnaround. The Terra Nova FPSO operated at 86% facility reliability in 2007 and achieved a cumulative production milestone of 200 MMbbls by mid-year. In December 2006, the Terra Nova FPSO experienced a mechanical issue in a swivel connection on the turret system that supports water injection to the reservoir. A repair was completed in December 2006 and production returned to normal rates in excess of 100,000 b/d gross (34,000 b/d net). Performance of the water injection swivel was unchanged throughout 2007. Plans have been developed and parts have been sourced for the repair or replacement of the swivel in the event that performance deteriorates. The total royalty paid at Terra Nova in 2007 equated to a rate of 25% of gross revenues.

Management's Discussion and Analysis PETRO-CANADA 37

White Rose operated reliably in 2007, ramping up production to average 117,500 b/d gross (32,300 b/d net), compared with 88,000 b/d gross (24,200 b/d net) in 2006. A scheduled 16-day turnaround was completed at White Rose in the third quarter of 2007. In 2007, White Rose achieved simple and tier one payout, thereby increasing royalties to 20% of net revenues. The total royalty paid in 2007 equated to a rate of 10% of gross revenues.

East Coast Canada operating and overhead costs averaged $4.86/bbl in 2007, compared with $7.71/bbl in 2006. Unit operating costs for East Coast Canada decreased as a result of higher production in the year. Unit operating costs in 2006 reflected costs for the Terra Nova dry dock turnaround.

2007 Strategic Initiatives

In January 2007, the Government of Newfoundland and Labrador rejected the decision report of the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) to approve the development of the Hibernia Southern Extension. During 2007, the operator continued to address requests for additional information by the Government of Newfoundland and Labrador regarding the Hibernia Southern Extension development plan amendment (DPA) application.

In August 2007, the Hebron partners signed a non-binding memorandum of understanding (MOU) with the Government of Newfoundland and Labrador related to the fiscal and other terms for the future development of the Hebron/Ben Nevis offshore field.

In September 2007, the Government of Newfoundland and Labrador approved the C-NLOPB recommendation to permit development of the South White Rose Extension. Shortly thereafter, the White Rose partners reached an agreement in principle with the province on fiscal and other terms for the White Rose Extensions development, incorporating the South White Rose Extension, North Amethyst and West White Rose satellite fields. In December 2007, Petro-Canada and its partners signed a formal agreement with the Province of Newfoundland and Labrador for the development of these oilfields. The Company anticipates North Amethyst will be developed initially, with first oil targeted for late 2009. The development of the West White Rose satellite is expected to follow. FEED for the North Amethyst portion of the project is complete and detailed design is underway, with necessary long-lead equipment and drilling commitments in place. The partners' objective is to achieve a timely regulatory decision and to facilitate making the final investment decision for North Amethyst in the first half of 2008.

Capital expenditures for exploration and development of crude oil offshore Canada's East Coast were $159 million in 2007, including $89 million related to the development of the White Rose oilfield, $48 million for Hibernia development drilling and $22 million for Terra Nova and other development drilling.

Outlook

Production expectations in 2008

•: East Coast production is expected to average 85,000 b/d net, reflecting 16-day planned turnarounds at both Terra Nova and White Rose

Growth plans

•: achieve greater than 90% reliability at Terra Nova
•: begin development drilling in the North Amethyst satellite field of White Rose
•: advance Hibernia Southern Extension development plan discussions with the Government of Newfoundland and Labrador to facilitate project planning and approvals

•: achieve binding formal agreements and re-establish the Hebron project team with the goal of submitting the project for regulatory approval in the 2010 time frame
•: advance White Rose Extensions development toward final investment decision in 2008

Capital spending plans in 2008

•: approximately $295 million is expected to be spent primarily on advancing the White Rose Extensions developments and drilling to replace reserves at Hibernia and White Rose

38 PETRO-CANADA Management's Discussion and Analysis

East Coast Canada production is expected to be 85,000 b/d in 2008, compared with actual production of 98,700 b/d in 2007. The 2008 production estimate reflects natural declines at Hibernia and Terra Nova, while White Rose volumes are expected to come off plateau. Terra Nova and White Rose have planned maintenance turnarounds of 16 days each. White Rose has advanced its planned 2008 turnaround from the summer of 2008 to January 2008 to facilitate required cleaning and inspection of the low pressure separator. The Terra Nova turnaround is planned in the summer of 2008. There is no major turnaround planned for Hibernia in 2008.

Beyond 2008, the East Coast Canada business intends to offset natural declines in the main reservoirs and sustain profitable production by adding production from reservoir extensions and satellite tie-ins. The Hebron project remains a significant resource the Company would like to see developed, subject to the conclusion of definitive project agreements with the provincial government.

Management's Discussion and Analysis PETRO-CANADA 39

Link to Petro-Canada's Corporate and Strategic Priorities

The East Coast Canada business is aligned with Petro-Canada's strategic priorities as outlined by its progress in 2007 and goals for 2008.

PRIORITY	2007 GOALS	2007 RESULTS	2008 GOALS

Delivering Profitable Growth with a Focus on Operated, Long-Life Assets	• advance in-field Hibernia growth prospects • delineate West White Rose • progress development plans for South White Rose Extension, North Amethyst and West White Rose prospects	• continued to address questions raised by the Government of Newfoundland and Labrador relative to the DPA application for the Hibernia Southern Extension • drilled two delineation wells at West White Rose • White Rose received regulatory approval for the development of the Southern Extension and completed a formal binding agreement for the overall White Rose Extensions development • signed MOU with the Government of Newfoundland and Labrador for the development of Hebron	• advance White Rose Extensions development toward regulatory approval and final investment decision in 2008, with first oil targeted for late 2009 • commence development drilling for the White Rose Extensions project • achieve binding formal agreements and re-establish the Hebron project team, with the goal of submitting the project for regulatory approval in the 2010 time frame • advance in-field Hibernia Southern Extension growth project

Driving for First Quartile Operation of Our Assets	• work toward improving Terra Nova reliability to the 90% range • conduct 30-day turnaround scheduled at Hibernia for regulatory compliance • complete 16-day turnaround at White Rose • receive regulatory approval to increase annual production from SeaRose FPSO at White Rose	• achieved 86% reliability at Terra Nova • completed Terra Nova Phase 1 drilling • Hibernia and White Rose successfully completed their planned turnarounds • White Rose granted regulatory approval to increase the daily oil production rate to 140,000 b/d gross (38,500 b/d net) and to increase the annual oil production rate to 50 MMbbls • decreased overall operating and overhead costs, compared with 2006	• achieve and maintain greater than 90% reliability at Terra Nova • finalize Terra Nova swivel repair plans • complete 16-day turnarounds at Terra Nova and partner-operated White Rose

Continuing to Work at Being a Responsible Company	• further reduce TRIF • apply lessons learned from oily water discharge to prevent future incidents • maintain zero regulatory exceedances	• TRIF decreased to 0.51, compared with 1.38 in 2006 • achieved zero regulatory compliance exceedances for a second year in a row • completed loss containment analysis and action plan • increased process safety focus	• continue to reduce injuries and illnesses through implementation of Exposure Based Safety program and First Aid reduction initiatives • enhance focus on process safety management • continue to implement loss containment improvement plan • continue to enhance produced water management • integrate stakeholder management process and tools and streamline with regulatory processes and requirements

40 PETRO-CANADA Management's Discussion and Analysis

International

For reporting purposes, Petro-Canada has consolidated its International activities into two core areas: the North Sea (the United Kingdom (U.K.), the Netherlands and Norway sectors) and Other International areas (Libya, Syria, offshore Trinidad and Tobago and Venezuela¹). This change better reflects existing production and exploration interests.

1: The Company completed the sale of its Venezuelan assets and closed the local office in 2007.

Business Summary and Strategy

International production and exploration interests are currently focused in two core areas. In the North Sea, production comes from the U.K. and the Netherlands sectors, with exploration activities extending into Denmark and Norway. The Other International region provides crude oil production from assets in Libya, natural gas production from operations offshore Trinidad and Tobago, and exploration and development activity in Syria.

The International strategy is to access a sizable resource base using a three-fold approach:

•: optimize and leverage existing assets
•: seek out new, long-life opportunities
•: execute a substantial and balanced exploration program

In 2005, Petro-Canada reached an agreement to sell the Company's mature producing assets in Syria. The sale was closed on January 31, 2006. These assets and associated results are reported as discontinued operations and excluded from continuing operations. Sale proceeds were used to buy back shares under the NCIB program.

International Financial Results

(millions of Canadian dollars)		2007		2006			2005

Net earnings (loss) from continuing operations	$	374	$	(206	)	$	(109	)

Cash flow from continuing operating activities ¹	$	220	$	840		$	722
Expenditures on property, plant and equipment and exploration from continuing operations	$	762	$	760		$	696
Total assets from continuing operations	$	5,180	$	6,031		$	4,856

1: International cash flow from continuing operating activities in 2007 was reduced by the payment of $1,145 million after-tax to settle the Buzzard derivative contracts.

2007 Compared with 2006

International contributed a record $374 million of net earnings, up 282% from a net loss of $206 million in 2006. Higher realized prices and production were partially offset by higher exploration, DD&A expenses and increased losses on the derivative contracts associated with the Buzzard acquisition.

Net earnings from continuing operations in 2007 included net losses on the derivative contracts associated with the Buzzard acquisition of $331 million, a $30 million income tax recovery, a $9 million gain on the sale of non-core assets and $5 million in insurance proceeds from the Scott platform fire. Net loss from continuing operations in 2006 included a $242 million charge for the

Management's Discussion and Analysis PETRO-CANADA 41

U.K. supplemental corporate tax rate adjustment, a $240 million net loss on the Buzzard derivative contracts, a $12 million gain on the sale of non-core assets, an $8 million insurance premium surcharge and $3 million in insurance proceeds from the Scott platform fire.

Late in 2007, the Company entered into derivative contracts to close out the hedged portion of its Buzzard production from January 1, 2008 to December 31, 2010. Under the terms of the contracts, the Company repurchased 30,688,000 bbls of Dated Brent crude oil at an average price of approximately $85.79 US/bbl, resulting in a reduction in cash flow of $1,145 million after-tax.

International production from continuing operations averaged 150,500 boe/d net in 2007, compared with 103,600 boe/d net in 2006. The significant increase was primarily due to additional North Sea production. International crude oil and liquids realized prices from continuing operations averaged $75.90/bbl and natural gas realized prices averaged $6.46/Mcf in 2007, compared with $72.69/bbl and $7.64/Mcf, respectively, in 2006. Operating and overhead costs from continuing operations averaged $9.12/boe in 2007, up 20% compared with $7.61/boe in 2006, due to higher operating costs in Libya.

International capital expenditures from continuing operations in 2007 were $762 million, with $395 million directed to the North Sea region, primarily for the Saxon development, and $367 million invested in Other International and other capital projects.

2007 Operating Review and Strategic Initiatives

In 2007, the International business strengthened its production profile by delivering first production from Buzzard and Saxon in the North Sea.

2007 Operating Review

			2007		2006		2005

Production from continuing operations net(boe/d)
	North Sea		91,000		43,700		44,600
	Other International		59,500		59,900		61,700

Total International production net			150,500		103,600		106,300

Average realized crude oil and NGL price from continuing
	operations($/bbl)	$	75.90	$	72.69	$	65.93
Average realized natural gas price from continuing operations($/Mcf)		$	6.46	$	7.64	$	7.13
Operating and overhead costs from continuing operations($/boe)		$	9.12	$	7.61	$	7.60

42 PETRO-CANADA Management's Discussion and Analysis

North Sea

Petro-Canada's North Sea production averaged 91,000 boe/d net in 2007, compared with 43,700 boe/d net in 2006. The addition of production from Buzzard and Saxon and a full year of production from De Ruyter and L5b-C were partially offset by natural declines. North Sea crude oil and liquids realized prices averaged $75.12/bbl and natural gas averaged $7.94/Mcf in 2007, compared with $72.67/bbl and $8.91/Mcf, respectively, in 2006.

During 2007, Petro-Canada continued to leverage its existing infrastructure through concentric development near core areas and through new discoveries.

In the U.K. sector of the North Sea, the Buzzard development, in which the Company has a 29.9% interest, achieved first oil in January 2007. The field ramped up to peak production of 220,000 boe/d gross (65,700 boe/d net) in July 2007. In 2006, a rig was secured to complete a 12-month program of development, infill and exploration drilling, which began in early 2007. This program included completing the Saxon project, 100% owned and operated by Petro-Canada. The Saxon development was tied back to the Triton area infrastructure and came on-stream in November 2007.

Following the discovery in 2005 on the Petro-Canada operated 13/27a Block (90% working interest), the Company farmed into adjacent Blocks 13/26a and 13/26b in September 2006, obtaining a 27.5% non-operated working interest. An appraisal well was drilled during 2007 on Block 13/26a, which encountered hydrocarbons. This well did not confirm the commerciality of the original Block 13/27a discovery.

On Block 13/21b, Petro-Canada, as operator with a 50% working interest in the Block, drilled a successful exploration well late in 2007. The Company and its partners will complete further appraisal work before considering development options. In late 2006, the Golden Eagle discovery was made on the non-operated Block 20/1 North located near the Buzzard field. The Company has a 25% working interest in this licence and work is ongoing to assess the possible development of the discovery. In early 2007, Petro-Canada was awarded Block 13/24d in the U.K. 24th licensing round. The Company is operator with a 90% working interest.

In the Netherlands sector of the North Sea, the Company drilled two successful exploration wells in 2007, van Nes and van Brakel, near De Ruyter, in which Petro-Canada is operator with a 50% and 60% working interest, respectively. Both van Nes and van Brakel have been suspended as gas discoveries and the Company is assessing its development options. The De Ruyter and L5b-C developments achieved first production in 2006. De Ruyter, a Petro-Canada operated oil development, delivered 25,200 boe/d gross (13,600 boe/d net) in 2007. The Company has a 54.07% working interest in De Ruyter.

In 2007, the Company was awarded nine additional production licences in the 2006 Awards in Predefined Areas (APA) round in Norway. Petro-Canada is operator of five of the 14 licences in Norway.

Other International

Libya

In 2007, Petro-Canada's production from continuing operations in Libya averaged 47,700 boe/d net, down 3% from 49,400 boe/d net in 2006. Libyan crude oil and liquids realized prices from continuing operations averaged $77.26/bbl in 2007, compared with $72.70/bbl in 2006.

In the first quarter of 2007, the National Oil Corporation (NOC) of Libya renamed all of the joint ventures operating in Libya. Petro-Canada's joint venture name has been changed from Veba Oil Operations (VOO) to Harouge Oil Operation (HOO).

In late 2007, Petro-Canada signed binding heads of agreement with the NOC to convert its old Exploration and Production Sharing Agreements (EPSA), except for its exploration licence on Block 137, into six EPSA IV agreements. Once ratified, the EPSAs will run for 30 years and enable the Company and NOC to jointly design and implement the redevelopment of more than 20 major fields and continue exploration in the Sirte Basin. Under the terms of the agreements, Petro-Canada is required to pay a signature bonus of $1 billion. Petro-Canada and NOC will each pay one-half of development expenditures, which are expected to total up to

Management's Discussion and Analysis PETRO-CANADA 43

$7 billion US gross. As operator, the Company has also committed to fully fund an exploration program at an estimated cost of $460 million US over a five- to seven-year period.

In 2007, preparations continued for exploration activities on Block 137 in the Sirte Basin, where Petro-Canada is the operator with a 50% working interest. In the third quarter of 2007, the Company completed an environmental impact assessment and Petro-Canada expects to begin 2D and 3D seismic acquisition early in 2008.

In 2007, 14 wells were drilled in the producing fields in Libya (six development wells, six water supply wells and two injector wells). Twelve of the wells were completed. A further two exploration wells were drilled, one of which was a discovery.

Syria

In 2007, the Company commenced the FEED and undertook 2D and 3D seismic operations for the Ebla gas project. When completed, the Ebla gas project is expected to produce an estimated 80 MMcf/d of natural gas from the Ash Shaer and Cherrife natural gas fields, with first gas anticipated in 2010. In December 2007, the Company exercised its option to purchase the remaining 10% interest in the Ebla gas Production Sharing Contracts (PSC).

On Block II, the Company drilled two exploration wells in 2007. The Al Houlou well was plugged and abandoned as a dry hole, while the Al Dahramat well has been suspended and is pending further testing.

Trinidad and Tobago

In 2007, Petro-Canada's share of Trinidad and Tobago offshore production averaged 71 MMcf/d net, up from 63 MMcf/d net in 2006. Increased production reflected the ability to take advantage of short-term opportunities to supply additional volumes to the Atlantic LNG trains. Trinidad and Tobago realized prices for natural gas averaged $4.34/Mcf in 2007, compared with $5.13/Mcf in 2006.

In 2007, Petro-Canada completed and received approval of its environmental impact assessments for the drilling programs on Blocks 1a, 1b and 22 in advance of the arrival of the contracted drilling rigs. In the third quarter of 2007, the Company drilled and completed the successful Zandolie West exploration well on Block 1a. The Anole well on Block 1b was abandoned as a dry hole and a second well on Block 1a, Zandolie East, was spud in December 2007. On Block 22 offshore Trinidad and Tobago, Petro-Canada, as operator with a 90% working interest in the Block, drilled the Cassra-1 well in 430 metres of water and reached a depth of 1,712 metres below sea level. The well was completed as a discovery and the Company and its partners expect to complete further appraisal work before considering development options. The Company continues to develop its 17.3% working interest in the North Coast Marine Area (NCMA-1) asset.

Other

In Algeria, Petro-Canada was the operator and had a 100% working interest in the Zotti Block. The Zotti exploration well in Algeria was abandoned as a dry hole in the first quarter of 2007. At the end of 2007, the Company closed its operations in Algeria.

In Tunisia during 2007, the Company focused on exploration of the offshore, non-operated Cap Serrat and Bechateur permits (33% working interest).

In Morocco, Petro-Canada extended its reconnaissance licence on the Bas Draa Block. A gravity magnetic survey was completed in July 2007.

In Western Venezuela, Petro-Canada held a 50% working interest in the La Ceiba Block that straddles the eastern shores of Lake Maracaibo. In 2007, the Company disposed of its interest in the La Ceiba project, completing a settlement with the Venezuelan Ministry for Energy and Petroleum to compensate Petro-Canada for its working interest in La Ceiba. At the end of 2007, Petro-Canada closed its office in Venezuela.

44 PETRO-CANADA Management's Discussion and Analysis

Outlook

Production expectations in 2008

•: North Sea oil and gas production to average 93,000 boe/d net
•: Other International oil and gas production to average 57,000 boe/d net

Growth plans

•: execute the exploration program offshore Trinidad and Tobago, North Sea and Libya
•: advance natural gas development in Syria
•: continue to pursue new business opportunities in LNG

Capital spending plans in 2008

•: approximately $986 million, primarily for new growth projects in Syria and Libya
•: approximately $366 million for reserves replacement spending in core areas, primarily at Buzzard, Guillemot West and on the producing fields offshore Trinidad and Tobago
•: approximately $283 million for exploration

International production from continuing operations is expected to be 150,000 boe/d net in 2008, similar to production levels of 150,500 boe/d net in 2007. Production in 2008 reflects the full-year contributions from Buzzard and Saxon. These projects are expected to offset the 15% to 20% natural declines in the North Sea.

The Company continued its discussions on importing gas from Russia to North America through a joint LNG project with OAO «Gazprom» (Gazprom). In February 2008, Petro-Canada was informed that Gazprom had decided not to pursue this project and instead wanted to focus on other projects.

Management's Discussion and Analysis PETRO-CANADA 45

Link to Petro-Canada's Corporate and Strategic Priorities

The International business is aligned with Petro-Canada's strategic priorities as outlined by its progress in 2007 and goals for 2008.

PRIORITY	2007 GOALS	2007 RESULTS	2008 GOALS

Delivering Profitable Growth with a Focus on Operated, Long-Life Assets	• ramp up Buzzard and L5b-C to full production • achieve first production at Saxon in the U.K. sector of the North Sea by year end • participate in up to a 17-well exploration drilling program, (depending on rig arrival dates) with balanced risk profile over the next 18 months • commence field appraisal and project design activities on the Syria Ebla gas project • establish a Libyan exploration program on the newly acquired Sirte exploration block • actively pursue LNG supply opportunities	• Buzzard achieved first production early in 2007 and reached plateau production of 200,000 boe/d gross (59,800 boe/d net) in August 2007 • compressor problems and export line repairs prevented L5b-C from ramping up to full production in 2007 • achieved first oil at Saxon in November 2007 • drilled 15 exploration wells, with seven wells suspended as discoveries, five wells abandoned as dry holes and three wells being evaluated • commenced FEED and undertook 2D and 3D seismic on the Syria Ebla gas project • signed binding heads of agreement for a long-term redevelopment of the Libya concessions and a seven-year exploration program in the Sirte Basin • continued negotiations with Gazprom for base load supply to proposed Gros-Cacouna re-gasification facility¹	• evaluate 2007 exploration results and deliver 2008 exploration program • award EPC contract for Syria Ebla gas project and finalize commercial agreements • develop a transition plan for the Libya Concession Development project • develop a detailed exploration program in Libya • spud first well for the Syria Ebla gas project • evaluate opportunities to commercialize Trinidad and Tobago gas discoveries, subject to exploration results

Driving for First Quartile Operation of Our Assets	• maintain excellent reliability at De Ruyter platform • optimize production capacity on Triton area assets by implementing recommendations from de-bottlenecking study	• delivered 87% production efficiency at De Ruyter • reviewed options for the purchase of Triton de-bottlenecking equipment prior to making the investment decision	• maintain excellent production efficiency at the operated De Ruyter and Hanze platforms • deliver plateau level production at Buzzard while the enhancement program is implemented

Continuing to Work at Being a Responsible Company	• maintain focus on TRIF, and increase leadership visibility of Zero-Harm effort • reduce oil in produced water at Triton • collaborate with local stakeholders in Trinidad and Tobago to minimize impact of offshore drilling	• TRIF increased to 1.42, compared with 0.80 in 2006 due to the impact of new contractor seismic and drilling operations • achieved zero regulatory compliance exceedances for a second year in a row • implemented new technology that reduced oil in produced water at Triton by 26% in 2007 to 18.8 milligrams (mg)/litre from 25.3 mg/litre in 2006 • completed environmental impact assessments on Block 137 in Libya, Block 2 and the Ebla gas project in Syria and on Blocks 1a, 1b and 22 offshore Trinidad and Tobago • proactively managed environmental and fisheries issues in Trinidad and Tobago and endangered species issues in Syria	• continue to work with contractors to reduce injuries and illnesses • continue to improve TLM systems and processes in Libya • complete the environmental impact assessment for the Ebla gas project in Syria • continue to develop stakeholder management processes to maintain positive outcomes with key stakeholders

1: In February 2008, Petro-Canada was informed that Gazprom had decided not to pursue this project and instead wanted to focus on other projects.

46 PETRO-CANADA Management's Discussion and Analysis

Discontinued Operations

On January 31, 2006, Petro-Canada completed the sale of the Company's producing assets in Syria to a joint venture of companies owned by India's Oil and Natural Gas Corporation Limited and the China National Petroleum Corporation for net proceeds of $640 million. The sale resulted in a gain on disposal of $134 million recorded in the first quarter of 2006. This sale aligned with Petro-Canada's strategy to increase the proportion of long-life and operated assets within its portfolio. Petro-Canada's activities in Syria remain part of the Other International producing region, with an active exploration program in Block II and the addition of the Ebla gas project in Syria during 2006.

Producing assets in Syria are presented as discontinued operations in the Consolidated Financial Statements. Petro-Canada's net earnings from discontinued operations in 2006 were $152 million and included a gain on disposal of $134 million. Summary information is presented below. Additional information concerning Petro-Canada's discontinued operations can be found in Note 4 to the Consolidated Financial Statements.

Discontinued Financial Results

(millions of Canadian dollars, unless otherwise noted)			2007		2006		2005

Net earnings from discontinued operations		$	–	$	152	$	98

Cash flow from discontinued operating activities		$	–	$	15	$	204
Expenditures on property, plant and equipment and exploration		$	–	$	1	$	46
Total assets		$	–	$	–	$	648

Total volumes(boe/d)
	– net before royalties		–		5,500		70,100
	– net after royalties		–		1,400		21,000

Average realized crude oil and NGL price($/bbl)		$	–	$	71.84	$	61.82

Average realized natural gas price($/Mcf)		$	–	$	7.94	$	6.43

Management's Discussion and Analysis PETRO-CANADA 47

Upstream Production

2007 Compared with 2006

In 2007, Petro-Canada's production from continuing operations of crude oil, NGL and natural gas averaged 418,400 boe/d net, up 21% from 345,400 boe/d net in 2006.

				*International & Offshore*

2007 Average Daily Production Volumes Net		North American Natural Gas	Oil Sands	East Coast Canada	International	Total

Crude oil, NGL and bitumen(b/d)
	– net before royalties	12,500	20,300	98,700	129,000	260,500
	– net after royalties	9,500	20,100	84,400	124,700	238,700
Synthetic crude oil(b/d)
	– net before royalties	–	36,600	–	–	36,600
	– net after royalties	–	31,100	–	–	31,100
Natural gas(MMcf/d)
	– net before royalties	599	–	–	129	728
	– net after royalties	471	–	–	123	594

Continuing operations(boe/d)
	– net before royalties	112,300	56,900	98,700	150,500	418,400
	– net after royalties	88,000	51,200	84,400	145,200	368,800

Discontinued operations(boe/d)
	– net before royalties	–	–	–	–	–
	– net after royalties	–	–	–	–	–

Total volumes(boe/d)
	– net before royalties	112,300	56,900	98,700	150,500	418,400
	– net after royalties	88,000	51,200	84,400	145,200	368,800

				*International & Offshore*

2006 Average Daily Production Volumes Net		North American Natural Gas	Oil Sands	East Coast Canada	International	Total

Crude oil, NGL and bitumen(b/d)
	– net before royalties	14,200	21,200	72,700	82,600	190,700
	– net after royalties	10,800	20,800	68,500	77,900	178,000
Synthetic crude oil(b/d)
	– net before royalties	–	31,000	–	–	31,000
	– net after royalties	–	28,000	–	–	28,000
Natural gas(MMcf/d)
	– net before royalties	616	–	–	126	742
	– net after royalties	489	–	–	95	584

Continuing operations(boe/d)
	– net before royalties	116,900	52,200	72,700	103,600	345,400
	– net after royalties	92,300	48,800	68,500	93,700	303,300

Discontinued operations(boe/d)
	– net before royalties	–	–	–	5,500	5,500
	– net after royalties	–	–	–	1,400	1,400

Total volumes(boe/d)
	– net before royalties	116,900	52,200	72,700	109,100	350,900
	– net after royalties	92,300	48,800	68,500	95,100	304,700

48 PETRO-CANADA Management's Discussion and Analysis

2008 Production Outlook

Upstream production is expected to decrease slightly in 2008, primarily due to natural declines in East Coast Canada and Western Canada. Offsetting these decreases is the expectation of additional volumes from the full-year impact of Buzzard and Saxon in the North Sea and higher planned Oil Sands production. Production is expected to average in the range of 390,000 boe/d to 420,000 boe/d in 2008.

Factors that may impact production during 2008 include reservoir performance, drilling results, facility reliability and the successful execution of planned turnarounds.

Production from Continuing Operations
2007 upstream production increased 21%, compared with 2006 due to the addition of North Sea projects (Buzzard and Saxon). In 2008, upstream production is expected to decrease slightly, primarily due to natural declines in East Coast Canada and Western Canada.

(thousands of bbls of oil equivalent/day –
Mboe/d, net before royalties)

Consolidated Production from Continuing Operations Net

		2007 Outlook (+/-)	2007 Actual	2008 Outlook (+/-)
(thousands of boe/d)		As at July 26, 2007

North American Natural Gas
	Natural gas	97	100	93
	Liquids	13	12	12

Oil Sands
	Syncrude	34	37	35
	MacKay River	24	20	25

*International & Offshore*
East Coast Canada		95	99	85

International
	North Sea	90	91	93
	Other International	57	59	57

Total continuing operations		400 – 420	418	390 – 420

Management's Discussion and Analysis PETRO-CANADA 49

Reserves Summary

The Company's reserves data and reserves quantities are determined by Petro-Canada's staff of qualified reserves evaluators using corporate-wide policies, procedures and practices. These reserves policies, procedures and practices conform with the SEC standards, as well as with the requirements in Canada, and the Association of Professional Engineers, Geologists and Geophysicists of Alberta's Standard of Practice for the Evaluation of Oil and Gas Reserves for Public Disclosure. Petro-Canada also employs independent third parties to evaluate, audit and/or review its reserves processes and estimates. In 2007, 33% of North American (excluding Oil Sands) and 42% of International proved reserves were assessed by independent reserves evaluators. The independent reserves evaluators concluded that the Company's year-end reserves estimates were reasonable.

Petro-Canada's proved reserves table that conforms to SEC standards for Oil and Gas activities can be found on page 101.

The following table and the accompanying narrative do not conform to SEC standards and are for supplemental general information. The reporting of working interest reserves before royalties and MMboe do not conform to SEC standards.

December 31, 2007 Consolidated Reserves – for Oil and Gas Activities (working interest before royalties)	Proved liquids (MMbbls)	Proved gas (Billion cubic feet – Bcf)	2007 Proved reserves additions liquids¹ (MMbbls)	2007 Proved reserves additions gas¹ (Bcf)	Proved² (MMboe)	2007 Proved reserves additions¹ (MMboe)

North American Natural Gas	45	1,479	3	53	291	11
Oil Sands³	276	–	127	–	276	127
International & Offshore
East Coast Canada	100	–	13	–	100	13
International	251	280	20	27	298	25

Total	672	1,759	163	80	965	176

Production net	96	266			140

1: Proved reserves additions are the sum of revisions of previous estimates, net purchases/sales, and discoveries, extensions and improved recovery.
2: At year-end 2007, 57% of proved reserves were classified as proved developed reserves. Of the total proved undeveloped reserves, 95% were associated with large projects currently producing or under active development, including Buzzard, Syncrude, MacKay River, Hibernia, Terra Nova, White Rose and Trinidad and Tobago natural gas.
3: Oil Sands proved reserves excluded reserves from Syncrude, which is considered a mining activity by the SEC.

At year-end 2007, the Company had 965 MMboe of proved reserves from oil and gas activities, compared with 929 MMboe at the end of 2006.

December 31, 2007 Reserves – for Syncrude Mining Operation	Proved Liquids	2007 Proved reserves additions liquids¹
(working interest before royalties)	(MMbbls)	(MMbbls)

Reserves of synthetic crude oil	350	18
Production net	13

1: Proved reserves additions are the sum of revisions of previous estimates, net purchases/sales, and discoveries, extensions and improved recovery.

At year-end 2007, the Company had 350 MMbbls of proved reserves from oil sands mining operations, compared with 345 MMbbls at year-end 2006.

50 PETRO-CANADA Management's Discussion and Analysis

The following table and the accompanying narrative do not conform to SEC standards and are for supplemental general information.¹

December 31, 2007 Consolidated Reserves – for Oil and Gas and Oil Sands Mining Activities	Proved liquids	Proved gas	2007 Proved reserves additions liquids¹	2007 Proved reserves additions gas¹	Proved²	2007 Proved reserves additions¹
(working interest before royalties)	(MMbbls)	(Bcf)	(MMbbls)	(Bcf)	(MMboe)	(MMboe)

North American Natural Gas	45	1,479	3	53	291	11
Oil Sands³	626	–	145	–	626	145
International & Offshore
East Coast Canada	100	–	13	–	100	13
International	251	280	20	27	298	25

Total	1,022	1,759	181	80	1,315	194

Production net	109	266			153

1: Proved reserves additions are the sum of revisions of previous estimates, net purchases/sales, and discoveries, extensions and improved recovery.
2: At year-end 2007, 57% of proved reserves were classified as proved developed reserves. Of the total proved undeveloped reserves, 95% were associated with large projects currently producing or under active development, including Buzzard, Syncrude, MacKay River, Hibernia, Terra Nova, White Rose and Trinidad and Tobago natural gas.
3: Oil Sands proved reserves included reserves from Syncrude and MacKay River.

Petro-Canada's objective is to replace reserves over time through exploration, development and acquisition. The Company believes that, due to the specific nature of its upstream portfolio and attributes of its probable reserves, the combination of proved plus probable reserves provides the best perspective of Petro-Canada's reserves.

In 2007, total consolidated proved reserves for oil and gas and oil sands mining activities was 1,315 MMboe, compared with 1,274 MMboe in 2006.

The North American Natural Gas business added 11 MMboe of proved reserves additions in 2007. Reserves additions were due to exploration and development activity, partially offset by technical revisions related to reservoir performance of some Western Canada pools.

In 2007, 145 MMbbls of proved reserves were added in Oil Sands². At MacKay River, demonstrated performance, delineation drilling and progress with regulatory approval for an expanded development area resulted in the addition of 127 MMbbls of proved reserves. At Syncrude, 18 MMbbls were added to proved reserves as a result of optimizing the Aurora North mine plan.

In East Coast Canada, a total of 13 MMbbls were added to proved reserves during 2007. This was due to ongoing development well drilling and production performance at White Rose, Terra Nova and Hibernia.

International proved reserves increased by 25 MMboe in 2007, due primarily to development drilling at Buzzard and the startup of Saxon in the U.K. North Sea.

Further detail on Petro-Canada's reserves is provided in the reserves table at the end of this report (see pages 100 to 104).

1: The reporting of working interest reserves before royalties, MMboe and combining oil and gas and oil sands mining activities together do not conform to SEC standards.
2: Oil Sands proved reserves include reserves from Syncrude and MacKay River. Syncrude is an oil sands mining operation. Oil sands mining is not an oil and gas activity as defined by the SEC. The oil sands mining proved reserves are estimated in accordance with the SEC Industry Guide 7.

Management's Discussion and Analysis PETRO-CANADA 51

Downstream

Business Summary and Strategy

Petro-Canada has the second largest Downstream business and is the "brand of choice" in Canada. In 2007, Petro-Canada accounted for approximately 13% of the total refining capacity in Canada and about 16% of total petroleum products sold in Canada.

Downstream operations include two refineries – one in Edmonton and one in Montreal - with a total daily rated capacity of 40,500 cubic metres/day (m³/d) (255,000 b/d), a lubricants plant that is the largest producer of lubricant base stocks in Canada, a network of more than 1,300 retail service stations, Canada's largest national commercial road transport network of 229 locations and a robust bulk fuel sales channel.

The strategy in the Downstream business is to increase the profitability of the base business through effective capital investment and disciplined management of controllable factors. In 2008, planned Downstream capital investment focuses

on growth projects. The Downstream business goal is to deliver superior returns and growth, including a 12% return on capital employed (ROCE) based on a mid-cycle business environment. Key features of the strategy include:

•: achieving and maintaining first quartile operating performance in all areas
•: managing and reducing costs, with a specific focus on reducing feedstock costs
•: growing revenue

The trend toward increased heavy crude production globally has resulted in an increased need for refining capacity that can process this feedstock. In addition, the present excess supply of domestic heavy crudes has led to a widening in light/heavy crude price differentials. As a result, Petro-Canada is converting the conventional crude oil train at its Edmonton refinery to refine oil sands-based feedstock and the Company is considering construction of a 25,000 b/d coker at its Montreal refinery.

Downstream Financial Results

(millions of Canadian dollars)		2007		2006		2005

Net earnings	$	629	$	473	$	415

Cash flow from continuing operating activities	$	994	$	835	$	663
Expenditures on property, plant and equipment	$	1,396	$	1,229	$	1,053
Total assets	$	7,989	$	6,649	$	5,609

52 PETRO-CANADA Management's Discussion and Analysis

2007 Compared with 2006

Downstream contributed a record $629 million of net earnings, up 33% from $473 million in 2006. Solid reliability at the Edmonton and Montreal refineries allowed Petro-Canada to maximize the benefits of unprecedented light oil refining margins.

Net earnings in 2007 included a $34 million income tax recovery and a $7 million gain on the sale of assets. Net earnings in 2006 included a $41 million income tax recovery, a $10 million gain on the sale of assets and an $8 million insurance premium surcharge.

Refining and Supply contributed 2007 net earnings of $446 million, compared with $338 million in 2006. Higher 2007 net earnings reflected favourable realized refining margins.

Total sales of refined products increased by 1%, compared with 2006. The increased volumes were mainly due to an increase in higher value retail and wholesale volume, partially offset by lower refining and supply sales.

In 2007, marketing contributed net earnings of $183 million, compared with $135 million in 2006. Improved margins were partially offset by increased costs related to higher fuel prices.

Total Downstream operating, marketing, and G&A unit costs of 7.8 cents/litre in 2007 were flat, compared with 2006.

2007 Operating Review and Strategic Initiatives

In 2007, the Downstream delivered record net earnings for the fourth year in a row of $629 million due to solid execution of its strategies and management of controllables. These factors provided the opportunity to capture the unprecedented light oil business environment experienced earlier in the year. Petro-Canada is well positioned with the supply capability to optimize profitability within a range of future business environment scenarios.

Refining and Supply

In 2007, the business processed an average of 40,100 m³/d of crude oil, up from 37,800 m³/d in 2006. The overall utilization rate at Petro-Canada's two refineries averaged 99% in 2007, up from 93% in 2006. The increase reflected fewer planned maintenance turnarounds at the Edmonton and Montreal refineries, compared with the turnaround activity in 2006 related to completion of the ultra-low sulphur diesel projects.

Overall plant reliability is a critical component of success in the refining business. For the third year in a row, solid operational performance at both refineries resulted in an overall reliability index of more than 90. In 2007, the overall refinery reliability index was 92. This is down slightly from 2006 due to unplanned outages at the Edmonton refinery.

Looking forward, Petro-Canada is well positioned to take advantage of the trend toward increased production of cheaper, heavier crudes. At the Edmonton refinery in 2007, the Company continued construction of new crude and vacuum units, and expanded coker and sulphur capacity. This is part of the refinery conversion project to upgrade and refine oil sands-based feedstock. This project is estimated to cost $2.2 billion and come on-stream in 2008. At its Montreal refinery, the Company furthered work to evaluate the feasibility of adding a 25,000 b/d coker to the refinery. An investment decision on a new coker at the Montreal refinery is expected to be made in the second quarter of 2008.

Management's Discussion and Analysis PETRO-CANADA 53

Marketing

Total Downstream sales increased to an average 53,300 m³/d in 2007, compared with 52,500 m³/d in 2006. Higher volumes were mainly due to an increase in higher value retail and wholesale volume, partially offset by lower refinery and supply sales.

In the retail business, Petro-Canada completed the core of its re-imaging program, contributing to industry-leading throughputs. Within the Company's network, annual gasoline sales from re-imaged sites averaged just under seven million litres per site. The Company has extended the re-imaging program to independent retailers and, to date, nearly 60% of these retailers have chosen to participate.

Petro-Canada continued to leverage its position as a market innovator with the advancement of new offerings such as Neighbours and Glide Autowash. Neighbours is a new retail concept that combines fresh food and coffee, with convenience products and services and fuel at a single location. Glide Autowash is a completely re-engineered, high quality car wash offer that allows consumers to choose between the touchless or cloth wash at the same facility. In 2007, the Company continued to focus on expanding its non-petroleum revenue base, as evidenced by the 9% year-over-year sales growth of its convenience store business and 7% increase in same-store sales, compared with 2006.

In 2007, the wholesale PETRO-PASS network, which includes 229 truck stop facilities, continued to be the leading national marketer of fuel in the commercial road transport segment in Canada. The distribution network was upgraded during the year.

Lubricants

Overall sales of lubricants totalled 778 million litres in 2007, an increase of 8% compared with sales volumes of 722 million litres in 2006. The increase in sales volumes was primarily due to higher base oil, white oil and commercial and industrial product sales, partially offset by lower process fluid sales.

Sales into high margin product segments grew to 562 million litres, a 3% increase compared with 2006. High margin product segments now represent 72% of total sales. Over the past five years, sales of high margin products have grown by approximately 18%.

Lubricants is positioned for profitable future growth as tougher product performance and environmental standards increase global demand for higher quality base oils and finished products like those produced at the Mississauga lubricants plant. In 2007, Petro-Canada received international recognition for its new food grade lubricant, PURITY™ with MICROL™¹ by winning the International Stevie Award® for Best New Product. This prestigious award recognizes outstanding performance in the workplace worldwide.

1: MICROL is an antimicrobial product protection agent.

Downstream capital expenditure of $1,396 million in 2007 included $1,214 million in Refining and Supply, predominantly associated with the Edmonton refinery conversion project of $959 million and $97 million for the advancing of the potential 25,000 b/d Montreal coker, $155 million in Sales and Marketing and $27 million in Lubricants.

54 PETRO-CANADA Management's Discussion and Analysis

Outlook

Growth plans

•: drive for first quartile refinery safety and reliability
•: complete Edmonton refinery conversion project to process oil sands-based feedstock and startup in the fourth quarter of 2008
•: make investment decision for a coker at the Montreal refinery
•: increase service station network effectiveness, with a focus on increasing non-petroleum revenue
•: build wholesale volumes primarily through the commercial road transport and bulk fuels sales channels
•: increase sales of high quality, higher margin lubricants through expansion into new markets and introduction of new products

Capital spending plans in 2008

•: approximately $767 million focused on new growth projects, such as the Edmonton refinery conversion and the possible Montreal coker
•: approximately $138 million to improve profitability in the base business
•: approximately $136 million to enhance existing operations
•: approximately $84 million for regulatory compliance projects

Downstream investment is focused on growth and improving base business profitability. The Edmonton refinery conversion project is expected to add earnings and cash flow starting in late 2008.

The Downstream business will have a capital program of approximately $1,125 million in 2008. The majority of capital spending is forecasted for new growth project funding of $767 million. This capital will be directed toward completing the Edmonton refinery conversion project and advancing the potential 25,000 b/d Montreal coker.

Approximately $138 million is planned to be invested to improve the profitability of the Downstream's base business. This includes a number of high return refining projects and the continued development of the retail and wholesale network. A further $136 million is forecast to be directed to the enhancement of existing operations. This includes reliability and safety improvements at Downstream facilities, as well as site enhancement within the wholesale and retail networks.

Approximately $84 million is expected to be invested in regulatory compliance, relatively flat compared with the estimated $70 million invested in 2007.

Based on the current mid-cycle business environment, the Downstream business delivered a mid-cycle ROCE of just under 11% in 2007. Over time, it is anticipated that improvement in the base business and the refinery conversion projects will help drive the mid-cycle ROCE to the target of 12%.

Management's Discussion and Analysis PETRO-CANADA 55

Link to Petro-Canada's Corporate and Strategic Priorities

The Downstream business is aligned with Petro-Canada's strategic priorities as outlined by its progress in 2007 and goals for 2008.

PRIORITY	2007 GOALS	2007 RESULTS	2008 GOALS

Delivering Profitable Growth with a Focus on Operated, Long-Life Assets	• continue the Edmonton refinery conversion project to enable the planned startup in 2008 • complete Montreal coker feasibility study for investment decision in 2007 • continue to invest in smaller scale refinery yield and reliability improvement projects • continue to integrate the Montreal refinery and the ParaChem Chemicals L.P. plant	• advanced construction of the Edmonton refinery conversion project, which was 61% complete at year-end 2007 and on track for planned startup in 2008 • completed FEED for proposed 25,000 b/d Montreal coker • invested $41 million in smaller scale refinery yield and reliability improvement projects in 2007 • completed tunnel and pipelines and captured synergies between ParaChem plant and the Montreal refinery	• advance Montreal coker, with final investment decision expected in the second quarter of 2008 • complete Edmonton refinery conversion project for startup in the fourth quarter of 2008 • continue to invest in smaller scale refinery yield and reliability improvement projects • selectively invest in retail and wholesale assets

Driving for First Quartile Operation of Our Assets	• continue to focus on safety and refinery reliability • increase retail non-petroleum revenue • grow high margin lubricants sales volume	• achieved a combined reliability index of 92 at the Company's two refineries • grew convenience store sales by 9% and same-store sales by 7%, compared with 2006 • increased high margin lubricants sales volume by 3% in 2007	• continue to focus on safety and refinery reliability, with increased focus on process safety • reduce feedstock costs • increase retail non-petroleum revenue • grow high margin lubricants sales volume

Continuing to Work at Being a Responsible Company	• maintain focus on TRIF and regulatory compliance exceedances • meet provincial ethanol regulations • continue to focus on community relations, including establishment of Community Liaison Committee in Montreal • continue to look for partnerships with Aboriginal communities on retail opportunities	• TRIF decreased to 0.64, compared with 0.80 in 2006 • recorded 12 regulatory compliance exceedances in 2007, compared with 10 in 2006 • complied with provincial ethanol regulations in Ontario and Saskatchewan • established Montreal Liaison Committee and held an open house for the community • grew retail business with Aboriginal communities in 2007	• maintain focus on TRIF and regulatory compliance exceedances • assess highest risk retail sites for safety and security enhancements • assess water use at retail and wholesale facilities and review our current management activities in high risk areas

56 PETRO-CANADA Management's Discussion and Analysis

Shared Services

Shared Services includes investment income, interest expense, foreign currency translation and general corporate revenue and expenses.

Shared Services Financial Results

(millions of Canadian dollars)		2007			2006			2005

Net loss	$	(6	)	$	(263	)	$	(177	)

Cash flow used in continuing operating activities	$	(603	)	$	(346	)	$	(163	)

2007 Compared with 2006

Shared Services recorded a net loss of $6 million in 2007, compared with a loss of $263 million in 2006.

The 2007 net loss included a $208 million foreign currency translation gain on long-term debt, a $54 million charge related to the mark-to-market valuation of stock-based compensation and a $5 million income tax recovery. The 2006 net loss included a $71 million charge for income tax adjustments, a $31 million charge related to the mark-to-market valuation of stock-based compensation and a $1 million foreign currency translation gain on long-term debt.

Fourth Quarter 2007

For a discussion and analysis of the Company's Fourth Quarter 2007 performance and results, see Petro-Canada's MD&A for that period, which is incorporated herein, by reference.

Management's Discussion and Analysis PETRO-CANADA 57

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 2007 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, includingin situ oil sands 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; and 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. Acquisition, exploration and development of oil sands mining activities are capitalized when costs are recoverable and directly result in an identifiable future benefit. Capitalized costs of oil and gas producing properties, includingin situ oil sands properties and oil sands mining properties, are depreciated and depleted using the unit of production method based upon estimated reserves (see Estimated Oil and Gas Reserves discussion on page 59). Reserves estimates can have a significant impact on net earnings, because 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 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 to be incurred, the useful lives of the assets and discount rates applied. 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 to be incurred, useful lives of the assets or discount rates applied 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 net 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 59), 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.

58 PETRO-CANADA Management's Discussion and Analysis

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 below), future commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill in the purchase price allocation. Future net earnings can be affected as a result of changes in future depreciation and depletion, asset impairment or goodwill impairment.

Goodwill Impairment

Goodwill is subject to impairment tests annually, or as economic events dictate, by comparing the fair value of the reporting unit to its carrying value, including goodwill. If the fair value of the reporting unit is less than its carrying value, a goodwill impairment loss is recognized as the excess of the carrying value of the goodwill over the fair value of the goodwill. The determination of fair value requires management to make assumptions and estimates about recoverable reserves (see Estimated Oil and Gas Reserves discussion below), future commodity prices, operating costs, production profiles and discount rates. Changes in any of these assumptions, such as a downward revision in reserves, a decrease in future commodity prices, an increase in operating costs or an increase in discount rates, could result in an impairment of all or a portion of the goodwill carrying value in future periods.

Estimated Oil and Gas Reserves

Reserves estimates, although not reported as part of the Company's 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 impairments (see discussion of these items above and on page 58). 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, economic conditions, 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. 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 and discount rates. 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.

Management's Discussion and Analysis PETRO-CANADA 59

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, 2007. However, the determination of contingent liabilities relating to 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.

Share Data

The authorized share capital of Petro-Canada consists of an unlimited number of common shares and an unlimited number of preferred shares issuable in series designated as either senior preferred shares or junior preferred shares. As at February 29, 2008, there were 483,637,000 common shares outstanding and no preferred shares outstanding. For details of the Company's share capital and stock options outstanding at December 31, 2007, refer to Notes 20 and 21 of the 2007 Consolidated Financial Statements.

Additional Information

Copies of this MD&A and the following Consolidated Financial Statements, as well as the Company's latest AIF and Management Proxy Circular, may be obtained from the Company's website at www.petro-canada.ca or by mail upon request from the Corporate Secretary, 150 - 6 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, are accessible through the Internet on the Canadian System for Electronic Document Analysis and Retrieval, which is commonly known by the acronym SEDAR, and located at www.sedar.com. SEDAR is the Canadian equivalent of the U.S. SEC's Electronic Data Gathering, Analysis, and Retrieval System, which is commonly known by the acronym EDGAR, and located at www.sec.gov.

60 PETRO-CANADA Management's Discussion and Analysis

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