<DOCUMENT>
<TYPE>EX-3
<SEQUENCE>5
<FILENAME>a2075015zex-3.txt
<DESCRIPTION>EXHIBIT 3
<TEXT>
<PAGE>

       M A N A G E M E N T 'S  D I S C U S S I O N  A N D  A N A L Y S I S

This Management's Discussion and Analysis contains forward-looking statements
based on current expectations, but which involve certain risks, uncertainties
and assumptions. Actual results may differ materially. See page 44 for
additional information. All financial information is reported in Canadian
dollars unless noted otherwise. In 2001, Suncor began to convert natural gas to
crude oil equivalent at a ratio of six thousand cubic feet to one barrel.
Figures for past years have been restated to reflect this change.

  S U N C O R  O V E R V I E W  A N D  S T R A T E G I C  P R I O R I T I E S

Suncor Energy Inc. is an integrated Canadian energy company with its corporate
office located in Calgary, Alberta. Suncor's cornerstone business, Oil Sands,
mines and upgrades oil sands near Fort McMurray, Alberta, to produce
custom-blended refinery feedstocks and diesel fuel. Suncor's conventional
Natural Gas production in Western Canada is sold in North American markets,
creating an internal hedge against the company's natural gas consumption. The
company refines crude oil and markets finished petroleum products through its
subsidiary, Sunoco Inc., headquartered in Toronto, Ontario.

Suncor's strategy is based on:

 o Expanding Oil Sands facilities to increase oil production and provide greater
   operational flexibility.

 o Developing Suncor's large resource base through oil sands mining and in-situ
   technology.

 o Controlling costs through a strong operational focus, economies of scale and
   improved management of engineering, procurement and construction on major
   projects.

 o Supporting integration and growth through natural gas production that offsets
   internal demand and by expanding the downstream marketing of Oil Sands
   products.

 o Actively managing environmental and social issues associated with operations
   to help build support for Suncor's growth plans among community, government
   and other stakeholders.

[GRAPHIC DESCRIPTION]
NET EARNINGS
(per cent)

                              2001      2000   1999

Oil Sands                     59         64     71
Natural Gas                   24         20     17
Sunoco                        17         16     12


[GRAPHIC DESCRIPTION]
CASH FLOW PROVIDED
FROM OPERATIONS
(per cent)

                              2001      2000   1999

Oil Sands                     52         62     60
Natural Gas                   30         22     25
Sunoco                        18         16     15


[GRAPHIC DESCRIPTION]
CAPITAL EMPLOYED
(per cent)

                              2001      2000   1999

Oil Sands                     64         64     55
Natural Gas                   14         19     29
Sunoco                        22         17     16

<PAGE>

NET EARNINGS COMPONENTS

<TABLE>
<CAPTION>
($ millions after income taxes)                             2001      2000*    1999
<S>                                                          <C>       <C>      <C>
Operational earnings**                                       433       414      167
NATURAL GAS
  Asset divestments                                            4        69       19
  Restructuring                                                1       (30)      --
STUART OIL SHALE PROJECT
  Partial asset write-down                                    (3)      (80)      --
OIL SANDS
  Start-up expenses - Project Millennium                     (90)       (9)      --
Impact of provincial income tax rate reductions
  on opening future income tax balances***                    43        13       --
-----------------------------------------------------------------------------------
Net earnings                                                 388       377      186
===================================================================================
</TABLE>

CASH FLOW FROM OPERATIONS COMPONENTS
<TABLE>
<CAPTION>
($ millions)                                                2001       2000     1999
<S>                                                          <C>       <C>      <C>
Operational cash flow**                                    1 061      1,009      591
NATURAL GAS
  Restructuring costs                                         (1)        (9)      --
OIL SANDS
  Start-up expenses & overburden removal
   - Project Millennium                                     (229)       (42)      --
-----------------------------------------------------------------------------------
Cash flow provided from operations                           831        958      591
===================================================================================
</TABLE>

INCOME TAX RATE CHANGES

IMPACT OF PROVINCIAL INCOME TAX RATE REDUCTIONS
ON OPENING FUTURE INCOME TAX BALANCES*

<TABLE>
<CAPTION>
                                                                               TOTAL
($ millions)                   Oil Sands    Natural Gas    Sunoco   Corporate   2001   2000
<S>                                   <C>             <C>      <C>        <C>     <C>    <C>
                                      31              9        10         (7)     43     13
===================================================================================
</TABLE>

*    The determination of operational earnings for 2000 has been restated to be
     consistent with the treatment and presentation in 2001 of the impact of
     income tax rate reductions.

**   Suncor's presentation of operational earnings and operational cash flow are
     provided to enhance readers' understanding of the factors impacting
     Suncor's operational and financial performance and should not be used to
     compare Suncor's financial results with those of other companies. For
     comparability purposes readers should rely on the reported net earnings and
     cash flow provided from operations and the related per share information,
     which are prepared and presented in accordance with Canadian generally
     accepted accounting principles in the Consolidated Financial Statements.

***  See Note 5 to the Consolidated Financial Statements.

For information related to quarterly sales, net income and net income per share
for the years 2001 and 2000 refer to the information under the heading Quarterly
Summary on pages 69 and 70 of this 2001 Annual Report, which information is
incorporated by reference into this Management's Discussion and Analysis.

EARNINGS ANALYSIS

NET EARNINGS UP 3% IN 2001

Net earnings for the year increased to $388 million, up from $377 million in
2000. Cash flow provided from operations was $831 million, compared with $958
million in 2000.

During 2001 and 2000, several transactions impacted net earnings and cash flow
provided from operations that were not viewed as ongoing. These transactions in
2001 included start-up expenses of Suncor's major oil sands expansion, Project
Millennium, restructuring cost adjustments and a divestment gain in Natural Gas,
adjustments related to the revaluation of opening future provincial income tax
balances due to a reduction in income tax rates and Suncor's sale of the Stuart
Oil Shale Project. Non-operational transactions are explained in the Notes to
the Consolidated Financial Statements.

Operational earnings in 2001 increased to $433 million from $414 million in
2000. The $19 million increase was primarily the result of increased Oil Sands
sales, lower crude oil hedging losses, higher natural gas prices, the benefit of
a royalty rate reduction for Oil Sands production and higher downstream retail
gasoline margins and volumes. These factors were partially offset by lower crude
oil prices, the widening of light/heavy crude oil differentials, the impact of
two maintenance shutdowns that halted Oil Sands production for a total of 16
days and higher operating expenses and interest charges.

                                                           2001 ANNUAL REPORT 23

<PAGE>

Operational cash flow in 2001 increased over 2000 primarily due to the same
factors that increased earnings. Operational cash flow also increased as a
result of the favourable income tax impact from the sale of the company's
interest in the Stuart Oil Shale Project.

These favourable factors were partially reduced by recognition at December 31,
2001 of the $32 million estimated payment to be made in 2002 under Suncor's
long-term employee compensation programs. Subsequent to year-end it was
determined that 2001 performance targets were achieved and the final payout will
be based upon the average weekly closing common share price in the first quarter
of 2002. Based on current share prices it is estimated the total cash cost of
these programs will be approximately $108 million. The payment with respect to
these programs in the second quarter of 2002 will be $72 million. This payment
is approximately $30 million higher as a result of elections subsequent to the
year-end with respect to the form of payment under one component of these
programs. This $30 million change will decrease cash flow provided from
operations in the first quarter of 2002. Up to the end of 2001 the after-tax
cumulative cost since the programs' inception in 1997 that had been charged
against Suncor's earnings was $67 million.

CONSOLIDATED EARNINGS ANALYSIS
Sales and other operating revenues were $3,990 million in 2001, up from $3,385
million in 2000. The increase was primarily the result of the items discussed
below:

o    During the first quarter of 2001, Suncor changed the methodology of
     accounting for sales from its upstream to downstream operations, as
     explained in Note 18 to the Consolidated Financial Statements. This change
     increased revenue.

o    Higher natural gas prices were more than offset by a decrease in crude oil
     prices due to weakening demand. Also impacting crude oil operating revenues
     were lower revenues from sour crude oil sales due to widening of the
     light/heavy crude oil differential and a higher proportion of lower value
     sour crude oil sales in 2001 (35% of total sales volumes versus 31% in
     2000). The increase in sour crude oil production was primarily due to
     initial production from Project Millennium that could not be upgraded from
     sour to sweet crude oil until the hydrotreating units were commissioned
     late in 2001. Revenues were favourably impacted by a one-time $18 million
     pricing adjustment related to a large supply contract calculated
     retroactively to 1999.

o    Sales volumes for the year were unfavourably impacted by two maintenance
     shutdowns (one planned and one unplanned) at the Oil Sands operations that
     totalled 16 days.

o    Increased revenues of $99 million were associated with a crude oil business
     that commenced in 2001 to generate additional income by buying and selling
     production of other companies. The purchase of the crude oil for resale is
     shown in purchases of crude oil and products in the Consolidated Financial
     Statements. This activity did not have a significant impact on earnings or
     cash flow in 2001.

The purchases of crude oil and products increased year-over-year by $584
million. This increase includes the impact, as noted above, of the change in
accounting methodology for sales of $473 million between upstream and downstream
operations. Costs for crude oil and other product purchases also increased due
to a number of factors:

o    As noted above, Suncor initiated a business which purchased third party
     crude oil for resale.

o    Two maintenance shutdowns at the Sarnia refinery resulted in higher product
     purchases being incurred to meet customer commitments.

o    Two maintenance shutdowns at Oil Sands, which halted production for a total
     of 16 days, also resulted in more third party purchases of crude oil by the
     Sarnia refinery.

o    Higher natural gas costs and volume increases were associated with the
     retail marketing of natural gas in Ontario.

These cost increases were partially offset by a reduction in the cost of crude
oil and refinery feedstocks purchased from third parties due to a 14% decline in
the benchmark WTI crude oil price in 2001 from 2000.

Operating, selling and general expenses increased to $1,010 million in 2001,
up from $918 million in 2000. The increase was primarily due to:

o    Higher refining costs reflecting increased energy costs and higher
     maintenance costs associated with two maintenance shutdowns at the Sarnia
     refinery.

o    Lower foreign exchange gains in 2001 with respect to the Stuart Oil Shale
     Project.


24 SUNCOR ENERGY INC.

<PAGE>

o    Higher compensation, including a $10 million cost associated with the
     long-term compensation program (as described in Note 12(b) to the
     Consolidated Financial Statements).

o    Higher mining costs due to increased production and ore variability.

o    Higher research and development costs with respect to new technology
     assessments.

The above factors were partially offset by lower production costs in Suncor's
Natural Gas business due to the 18% production decline in 2001 compared to 2000,
and lower costs associated with the Stuart Oil Shale Project in 2001, compared
to 2000 due to divestment of this project in April 2001.

In 2002 insurance costs are expected to increase by an estimated $14 million
(175%). The increase primarily reflects higher premiums on property and business
interruption insurance due to the tightening of insurance market capacity. As
noted in Note 14(b) to the Consolidated Financial Statements, the deductible
limit for the business interruption policy will be increased to $415 million
(US$260 million) for 2002 from $70 million (US$45 million) in 2001.

Exploration expenses decreased by $31 million in 2001, primarily as a result of
lower dry hole costs. Royalty expenses decreased by $65 million in 2001 to $134
million. The decrease was primarily due to a lower Crown royalty rate for Oil
Sands production, which was reduced to 1% of gross revenue compared to 5% in
2000 and lower Natural Gas sales levels. These favourable factors were partially
offset by higher royalties due to higher natural gas prices and increased
production from Oil Sands.

Depreciation, depletion and amortization (DD&A) decreased by $5 million to $360
million in 2001 from $365 million in 2000. The decrease was primarily due to an
$8 million decrease in DD&A in the Natural Gas business as a result of the 2000
asset divestment program. Most of the Project Millennium assets at Oil Sands
will be depreciated over 40 years. Over the life of the assets, depreciation
will average $90 million per year, with higher depreciation in the initial years
and lower depreciation in the later years. In 2002 depreciation will be
approximately $115 million. Overburden amortization is expected to increase in
2002 to approximately $160 million (pre-tax).

Interest costs (before capitalization of interest on projects) increased in 2001
to $143 million, from $112 million in 2000, primarily reflecting higher debt
levels, partially offset by lower variable interest rate costs. Long-term
borrowings at the end of 2001 were $3.1 billion, up from $2.2 billion at the end
of 2000, reflecting expenditures of approximately $1 billion on Project
Millennium in 2001. With Project Millennium commencing commercial operations in

CONSOLIDATED FINANCIAL RESULTS

<TABLE>
<CAPTION>
($ millions)                                2001    2000    1999
<S>                                        <C>     <C>     <C>
Net earnings                                 388     377     186
Cash flow provided from operations           831     958     591
Investing activities                       1 680   1 607   1 290
Dividends - common shares                     75      75      75
          - preferred securities              48      47      37
Long-term borrowings                       3 113   2 192   1 306
----------------------------------------------------------------
</TABLE>

INDUSTRY INDICATORS

<TABLE>
<CAPTION>
(average for the year unless otherwise noted)                                            2001       2000      1999
<S>                                       <C>                                           <C>        <C>       <C>
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing                           25.90      30.25     19.30
Canadian 0.3% par crude Cdn$/barrel at Edmonton                                         39.34      44.56     27.50
Light/heavy crude oil differential US$/barrel -
  WTI @ Cushing/Bow River @ Hardisty                                                     9.51       6.84      3.42
Natural gas US$/thousand cubic feet at Henry Hub                                         4.38       3.90      2.27
Natural gas (Alberta spot) Cdn$/thousand cubic feet at Empress                           6.31       5.08      3.00
Canadian natural gas exports to the U.S., trillions of cubic feet                        3.8*       3.60      3.40
New York Harbour 3-2-1 crack US$/barrel**                                                4.42       5.45      2.47
Refined product demand (Ontario) percentage change over prior year                     (1.6)*        2.6       3.8
Exchange rate: Cdn$:US$                                                                  0.64       0.67      0.67
------------------------------------------------------------------------------------------------------------------
</TABLE>

* Estimate
** New York Harbour 3-2-1 crack is an industry indicator measuring the margin on
a barrel of oil for gasoline and distillate. It is calculated by taking 2 times
the New York Harbour gasoline margin plus 1 times the New York Harbour
distillate margin and dividing by 3.

                                                           2001 ANNUAL REPORT 25

<PAGE>

2002, interest charges that were capitalized in 2001 will now be expensed in
2002, thereby reducing 2002 earnings. Interest capitalized on Project Millennium
in 2001 was approximately $120 million.

Net interest costs increased from $8 million in 2000 to $18 million in 2001
primarily due to the costs associated with the Stuart Oil Shale Project.

Subsequent to year-end, Suncor issued US$500 million of 7.15% unsecured notes
due 2032 from a US$1 billion unallocated shelf prospectus. The net proceeds from
the sale were used to repay commercial paper and bank borrowings. Following this
transaction, Suncor had approximately $2,050 million of fixed rate borrowing at
an average cost of 6.7%. The balance of Suncor borrowings are at floating
interest rates. Short-term floating interest rates are at historical lows and
total interest expense will be influenced by changes in short-term rates.

Financing costs in 2002 could also be higher or lower due to foreign exchange
gains or losses as the January 2002 debt issued will be restated
("marked-to-market") at the prevailing exchange rate between the Canadian and
U.S. dollar. This could create volatility in earnings. It is anticipated that a
$0.01 change in the exchange rate would have an estimated $5 million pre-tax
impact on earnings with respect to the U.S. dollar denominated debt.

Interest expense will be influenced by the company's anticipated change in its
debt portfolio. For the past few years a high percentage of Suncor's debt was at
floating interest rates. With the completion of Project Millennium, Suncor
intends to replace bank debt with longer-term fixed rate public market debt.
During 2001 Suncor issued $500 million medium-term notes as well as the above
noted U.S. debt issue in early 2002. Subsequent to year-end, Suncor has also
filed a shelf prospectus with Canadian securities regulatory authorities,
enabling it to issue up to a further $500 million in medium-term notes in Canada
if required. Suncor plans to manage the fixed versus floating rate exposure with
the use of interest rate swaps.

Taxes, other than income taxes, increased by $6 million to $367 million
primarily due to higher sales volumes of taxable products (mainly
transportation fuels) in Sunoco.

Suncor's effective income tax rate in 2001 was 24%. This includes
favourable adjustments of $43 million (9%) for provincial tax rate reductions
and $9 million (1%) for federal tax rate reductions related to revaluation of
opening future income tax balances. In 2000 the effective income tax rate was
39%, including $13 million (2%) in favourable provincial tax rate adjustments
related to revaluation of opening future income tax balances. Also, in 2001
there was the recognition of lower provincial taxes of $6 million due to
provincial deductibility of Crown royalties in excess of the federal resource
allowance deduction. This deduction reduced the 2001 effective rate by 1%. In
2000 there was a similar provincial reduction of $13 million, which reduced the
effective tax rate by 2%.

Suncor believes its effective tax rate in 2002 will be approximately 38%. Based
upon the prior year's capital investment levels and planned future investment
levels, Suncor does not expect its upstream operations to be cash taxable until
the latter half of the current decade. This assessment can change depending upon
such factors as profitability and capital investments.

DIVIDENDS
During 2001, Suncor's quarterly common share dividend was $0.085 per share,
unchanged from 2000. Dividend levels are reviewed quarterly in light of Suncor's
growth-related initiatives, financial position, financing requirements, cash
flow and other factors considered relevant by the Board of Directors.

CORPORATE OFFICE EXPENSES
Corporate office after-tax expenses decreased to $92 million in 2001 from $117
million in 2000. Operational expenses in 2001 exclude the $3 million write-down
of the investment in the Stuart Oil Shale Project and a $7 million unfavourable
provincial income tax rate adjustment. Operational expenses in 2000 exclude an
$80 million write-down of the Stuart Oil Shale Project.

Excluding these factors, the increase in operational expenses in 2001 to $82
million from $37 million in 2000 was primarily due to lower foreign exchange
gains, higher research and development costs with respect to new technology
assessments, higher compensation costs including the costs associated with the
company's long-term compensation program and higher interest costs.

The corporate centre had a net cash deficiency of $165 million in 2001 compared
to a net cash deficiency of $76 million in 2000. The increase was primarily due
to settlement in 2001 of outstanding 2000 obligations and income tax refunds
expected to be received in 2002.

26 SUNCOR ENERGY INC

<PAGE>

O U T L O O K
Suncor recognizes that operational excellence is important to achieving improved
financial returns. Safe and efficient operations reduce the risk of production
loss, environmental liability and the higher costs incurred in conducting
unscheduled maintenance. In 2002, all of Suncor's businesses plan to continue to
focus on base business excellence to improve operational reliability. Plans to
apply technological advancements that are intended to increase the efficiency of
each business, reduce costs and improve environmental and safety performance
will be a key focus.

PRODUCTION GROWTH AT OIL SANDS
Suncor plans to leverage its existing facilities and operational experience with
the intention of increasing Oil Sands production in phases over the next decade.
(See Oil Sands Overview page 30.)

PROJECT MANAGEMENT
Engineering, procurement and construction (EPC) of Suncor's planned major
expansions will be managed directly by the company's newly created Major
Projects group. Management believes direct control of EPC can assist Suncor to
reduce costs and improve the efficiency of the transition between construction
and operation.

INTEGRATION
Natural gas production and downstream marketing strategies will continue
to be an important part of Suncor's corporate strategy. (See Natural Gas
Overview page 36 and Sunoco Overview page 40.)

SUSTAINABILITY
As the company expands its hydrocarbon-based businesses, management believes
Suncor must also work toward the development of renewable energy. Renewable
energy has the potential to reduce environmental impacts and create additional
business investment opportunities.

As part of the company's plans to invest $100 million in renewable energy
projects by 2005, the SunBridge Wind Power Project was constructed in 2001.
SunBridge is a $20 million partnership (50:50) between Suncor and Enbridge Inc.

Suncor's effort to reduce greenhouse gas emissions is reflected in its pursuit
of greater internal energy efficiency - with the dual objective of cost savings
and improved environmental performance. Suncor also plans to invest in emissions
offsets and carbon capture research and development. The company's goal is to
align operations with relevant national and international commitments to limit
greenhouse gas emissions.

Workplace health and safety will remain a priority at
all Suncor businesses and work sites.

RISK/SUCCESS FACTORS
AFFECTING PERFORMANCE

The issues Suncor must manage include, but are not limited to commodity prices,
environmental regulations and regional labour issues including those specific
issues discussed under Risk/Success Factors Affecting Performance for each
Suncor business.

Suncor believes that while the planned increases in Oil Sands production will
provide strategic advantages, they also present issues that will require prudent
risk management.

COMMODITY PRICES
Suncor's future financial performance remains closely linked to hydrocarbon
commodity prices, which can be influenced by global and regional supply and
demand, worldwide political events and the weather. These factors, among others,
can result in a high degree of price volatility. In the last three years for
example, the industry has seen the monthly average price for benchmark WTI crude
oil range from a low of US$12 per barrel to a high in 2000 of US$34.25 per
barrel. During the same period, the natural gas Henry Hub benchmark monthly
average price ranged from a low of US$1.69 per thousand cubic feet (mcf) to a
high of US$9.79 per mcf.

Crude oil and natural gas prices are based on a U.S. dollar benchmark that
results in Suncor's earned prices being influenced by the Canadian/U.S. currency
exchange rate, thereby creating another element of uncertainty for the company.
The continued weakness in the Canadian dollar versus the U.S. dollar in 2001
increased Suncor's revenues and earnings, as measured in Canadian dollars. In
the future, Suncor's revenues will continue to be influenced by the value of the
Canadian dollar relative to foreign currencies.

                                                           2001 ANNUAL REPORT 27

<PAGE>


HEDGING
Suncor cannot control or accurately predict the prices of crude oil or natural
gas, or currency exchange rates. For this reason, the company has a hedging
program that fixes the prices of crude oil and natural gas for a percentage of
Suncor's total production. Suncor has entered into a foreign exchange contract
for 2002, but currently has no plans to enter into foreign exchange contracts
beyond 2002. Suncor's risk management objective with its hedging program is to
lock in prices on a portion of the company's future production to reduce its
exposure to market volatility and support the company's ability to finance
growth. Refer to Note 17(b) to the Consolidated Financial Statements for details
of revenue hedges.

The Audit Committee and the Board of Directors meet with management regularly to
assess Suncor's hedging thresholds in light of its price forecast and cash
requirements. To add more certainty to Suncor's ability to finance future
capital programs and repay debt, the Board authorized hedging up to 30% of the
company's crude oil volumes between 2003 and 2006. In 2001, hedging decreased
Suncor's earnings by $148 million. In 2000, hedging decreased earnings by $259
million.

ENVIRONMENTAL REGULATION RISK/SUCCESS FACTORS
Environmental legislation affects nearly all aspects of Suncor's operations.
Environmental legislation imposes certain standards and controls on
activities relating to mining, oil and gas exploration, development and
production and the refining, distribution and marketing of petroleum products
and petrochemicals and requires companies engaged in those activities to
obtain necessary permits to operate. Also, environmental assessments and
approvals are required before initiating most new projects or undertaking
significant changes to existing operations.

In addition to these specific known requirements, Suncor expects changes to
environmental legislation will likely impose further requirements on companies
operating in the energy industry. Some of the issues include the possible
cumulative impacts of oil sands development in the Athabasca region; the need to
reduce or stabilize various emissions; issues relating to global climate change,
including the potential impacts of government regulation; land reclamation and
restoration; water quality; and reformulated gasoline to support lower vehicle
emissions. Changes in regulation could have an adverse effect on Suncor in terms
of product demand, product formulation and quality, methods of production and
distribution and operating costs. The complexity of these issues makes it
difficult to predict their future impact on the company. Management anticipates
capital expenditures and operating expenses could increase in the future as a
result of the implementation of new and increasingly stringent environmental
regulations.

[GRAPHIC DESCRIPTION]
                            2002   2003   2004   2005  2006

CRUDE OIL HEDGING
PROGRAM
(at December 31, 2001)

Thousands of barrels per day  84     44     11     15    --
(kbpd) of Annual Crude
Oil Hedged
Current Annual Limits (kbpd) 105     66     68     68    68
Percentage of Annual          40     20      5      7     0
Crude Oil Hedged
Hedged Price - Cdn$ per    31.99  33.44  33.44  34.37    --
barrel

OTHER FACTORS
Other critical factors affecting Suncor's financial results include volumes and
margins of refined product sales, success of the natural gas exploration and
development program, interest rates and the company's ability to manage both
day-to-day operating costs as well as project costs. For further discussions of
possible risk factors and uncertainties which may affect the company, refer to
page 44 at the end of the MD&A and to the company's Annual Information Form, on
file with securities regulators or available from the company.

SENSITIVITY ANALYSIS
The following sensitivity analysis shows the main factors affecting Suncor's
annual pre-tax cash flow from operations and after-tax earnings based on actual
2001 operations. The table illustrates the potential financial impact of these
factors applied to Suncor's 2001 results. With Project Millennium commissioning
complete, Oil Sands production is expected to increase over 2001 levels and thus
the sensitivity analysis on a 1,000 barrel per day change in production may not
be indicative of future results. A change in any one factor could compound or
offset other factors.

LIQUIDITY AND CAPITAL RESOURCES
Suncor's growth has been funded by a combination of internally generated funds
and increased debt. Net debt increased to $3.1 billion at the end of 2001,
approximately $900 million higher than at the end of 2000.

28 SUNCOR ENERGY INC.

<PAGE>

SENSITIVITY ANALYSIS
<TABLE>
<CAPTION>
                                                                                  APPROXIMATE CHANGE IN
                                                                                 PRE-TAX CASH
                                                                                  FLOW FROM     AFTER-TAX
                                                  2001 AVERAGE        CHANGE      OPERATIONS    EARNINGS
                                                                                 ($ millions)
<S>                                               <C>                 <C>           <C>          <C>
Oil Sands
  Price of crude oil ($/barrel)                     29.17             US$1.00         35           25
  Sweet/sour differential ($/barrel)                 8.29             US$1.00         19           13
  Sales (barrels/day)                             121 500               1 000         10            7
Natural gas
  Price of natural gas ($/thousand cubic feet)       6.09                0.10          5            3
  Production of natural gas (millions of cubic        177                  10         15            6
    feet/day)
Sunoco
  Retail gasoline margin (cents/litre)                6.6                 0.1          2            1
  Refining/wholesale margin (cents/litre)             5.7                 0.1          3            2
Consolidated
  Exchange rate: Cdn$:US$                            0.64                0.01         14           10
  Interest rate                                     2.7%*                  1%          2            1
-----------------------------------------------------------------------------------------------------------
</TABLE>
 * Borrowings with interest at variable rates averaging 2.7% at December 31.

<TABLE>
<CAPTION>
PLANNING ASSUMPTIONS                                  2001 ACTUAL        Current Plan   Last Year's Plan
                                                      AVERAGE FOR        Average next     Average next
                                                       THE YEAR          3-year range     3-year range
<S>                                                      <C>            <C>     <C>      <C>     <C>
Crude oil - WTI US$ per barrel                           25.90          19.00 - 21.00    18.00 - 19.00
Natural gas - US$/thousand cubic feet @ Henry Hub         4.38            3.00 - 3.45      3.00 - 3.50
Exchange rate: Cdn$:US$                                   0.64            0.65 - 0.69      0.69 - 0.71
-----------------------------------------------------------------------------------------------------------
</TABLE>

The above are planning assumptions and are not estimates or predictions of
actual future events or circumstances. Because this table does not incorporate
potential cross-relationships, it would not necessarily accurately predict
future results.

With the completion of Project Millennium, capital and exploration investment
activity is planned to decrease to $900 million in 2002, down from $1.7 billion
in 2001 and $2 billion in 2000.

Suncor plans to make debt reduction one of its priorities as it prepares for
the next stages of growth. Management believes a phased approach to future
growth projects should improve the ability to manage project costs, providing
further opportunities for debt reduction. This approach, along with
anticipated higher Oil Sands sales levels and the hedging of approximately
50% of crude oil production in 2002, should allow for the reduction in both
the absolute debt level and the net debt/cash flow provided from operations
ratio. Suncor's target for this ratio is in the range of 1.5 to 2.0 times at
mid-cycle pricing. At the end of 2001 this ratio was 3.8 times, higher than
the expected 2001 short-term peak of 3.5 times Suncor targeted last year. The
increase was due to the higher than estimated Project Millennium spending.

Other key factors that can contribute to a reduction in this ratio are
operational performance and crude oil prices, and to a lesser degree natural gas
prices and downstream margins. Management does not expect crude oil prices will
be sustained at the average level achieved in 2001. Suncor's business plans are
based upon assumptions, including a crude oil price assumption lower than the
2001 WTI average price per barrel of $25.90. Based on current planning and
operational assumptions, Suncor believes net debt could be reduced by $200 to
$400 million in 2002, reducing the net debt to cash flow provided from
operations ratio to the two times range in 2002.

[GRAPHIC DESCRIPTION]

                            1997     1998     1999    2000    2001

RATIO OF NET DEBT/
CASH FLOW PROVIDED
FROM OPERATIONS


Number of Times              1.4      2.2     2.3      2.3     3.8

Ratio could decline over the next two years depending upon such factors as
commodity price assumptions and the integration of Project Millennium.

                                                           2001 ANNUAL REPORT 29

<PAGE>

                         O I L  S A N D S  O V E R V I E W

Suncor's Oil Sands business, located near Fort McMurray, Alberta, is the
cornerstone of the company's growth plans. The business mines oil sands,
extracts the bitumen and upgrades it into a variety of refinery feedstocks and
diesel fuel.

Relative to conventional oil exploration and production, oil sands reserves and
recovery rates are generally better defined and more predictable, providing
Suncor with what management believes is a more stable foundation for production
growth.

Oil Sands strategy for profitable growth is based on:

o    Applying proven as well as new technologies to increase oil production.

o    Reducing costs through application of technologies, economies of scale,
     direct management of growth projects and more efficient operations.

o    Building strategic business relationships to mitigate risk and capture
     value from the production of energy, steam and by-products.

o    Implementing growth in a manner that supports Suncor's vision of becoming a
     sustainable energy company.

Oil Sands progressed this strategy in 2001 by commissioning Project Millennium,
a $3.4 billion expansion that nearly doubled Oil Sands production capacity to
225,000 barrels per day (bpd) and improved operational flexibility by adding a
second upgrader. This expansion is expected to reduce operating costs through
process improvements and economies of scale.

In 2001 Suncor received regulatory approval for the Firebag IN-SITU Oil Sands
Project, a commercial scale in-situ project planned to supply an additional
140,000 barrels of bitumen per day by the end of the decade.

Also in 2001, Suncor announced plans for Project Voyageur, which call for a
staged expansion of Suncor's oil sands and in-situ facilities. Suncor has
initiated the consultation process for the project and plans to apply for
regulatory approval in late 2002.

Voyageur requires approval of regulators and Suncor's Board of Directors, as
well as development of engineering, construction and production plans for each
phase and favourable fiscal and market conditions. Any expansion decisions will
be aligned with the company's long-term marketing strategies.

To support increased production, Suncor is working with other companies at
the Oil Sands plant site. In 2001, TransAlta Energy Corporation commenced
operation of its COGENERATION facility at the plant. A portion of the energy
from the facility will help meet current energy needs of the Oil Sands
operation while mitigating fluctuating energy costs and lowering carbon
dioxide emissions per unit of production.

RESULTS OF OPERATIONS
AND INVESTING ACTIVITIES

2001 VS 2000

<TABLE>
<CAPTION>
Oil Sands - Summary of Results
($ millions unless otherwise noted)  2001     2000    1999
<S>                                 <C>      <C>     <C>
Revenue                             1 385    1 336     889
Production
  (thousands of bpd)                123.2    113.9   105.6
Average sales price
  ($/barrel)                        29.17    31.67   23.84
Operational earnings                  342      324     167
Net earnings                          283      315     167
Cash flow provided
  from operations                     486      655     405
Total assets                        6 409    5 079   3 178
Investing activities                1 476    1 715   1 085
ROCE(%)                              20.1     22.8    12.9
ROCE (%)*                             6.4     10.6     9.2
----------------------------------------------------------
</TABLE>

*    ROCE- Return on average capital employed. Includes capitalized costs
     related to major projects in progress.

IN-SITU
In-situ refers to methods of extracting heavy oil from deep deposits of oil
sands through horizontal drilling with minimal disturbance of the ground cover.

COGENERATION
The simultaneous production of electricity and steam from one
energy source.

30 SUNCOR ENERGY INC.

<PAGE>

REVISED COST ESTIMATES FOR GROWTH PROJECTS
The capital cost of Suncor's Project Millennium was approximately $3.4 billion,
a $1.4 billion increase over the original 1997 estimate of $2 billion. The
capital cost increased primarily as a result of higher labour, fabrication and
material costs and changes in project scope. The additional capital costs were
financed through internally generated cash flow and additional borrowing.

When combined with an associated expansion of Suncor's upgrader, the first phase
of the Firebag In-situ Oil Sands Project is expected to cost about $1 billion.
This estimate is $250 million higher than Suncor estimated in 1999 when planning
on the project was first initiated. The revised estimate reflects construction
of additional common infrastructure to support subsequent stages of Firebag,
future capacity improvements of the company's upgrader and other costs
reflecting Suncor's experience with construction on Project Millennium.

NET EARNINGS ANALYSIS

OIL SANDS EARNINGS DECREASE 10%
Oil Sands net earnings were $283 million in 2001, compared with $315 million in
2000. Operational earnings of $342 million in 2001 exclude a $31 million
favourable income tax rate reduction and $90 million in Project Millennium
start-up expenses. Operational earnings in 2000 were $324 million. The increase
in operational earnings of $18 million in 2001 was primarily due to higher
volumes and lower Crown royalty payments, offset by higher costs and an 8%
decrease in crude oil prices from 2000. If the incremental start-up volumes had
been excluded from the determination of 2001 operational earnings, it is
estimated that operational earnings in 2001 would have been lower than in 2000.

During 2001, Suncor initiated a new business to generate additional income by
buying and selling the crude oil production of other companies. The purchase of
crude oil for resale, $96 million in 2001, is shown in the purchases of crude
oil and products line in the Consolidated Financial Statements. These activities
did not have asignificant impact on earnings or cash flow.

OIL SANDS CRUDE OIL PRICES DECREASE 8%
Oil Sands crude oil prices in 2001 averaged $29.17 per barrel, compared with
$31.67 per barrel in 2000. WTI benchmark prices decreased 14% to an average of
US$25.90 per barrel in 2001 from an average of US$30.20 per barrel in 2000.
Price was further negatively impacted by wider sweet and sour differentials
combined with a proportionately higher volume of lower value sour crude sales.
The effect of a lower crude price was partially offset by decreased hedging
losses of $224 million in 2001, compared with $407 million in 2000. The combined
impact of the above pricing factors reduced earnings in 2001 by $65 million
after-tax from 2000 levels.

OIL SANDS PRODUCTION INCREASES 8%
Oil Sands increased production in 2001 for the ninth consecutive year to an
average of 123,200 bpd, up from 113,900 bpd in 2000, mostly due to the startup
of Project Millennium in the fourth quarter. With the Millennium upgrading
facilities in operation, production averaged a record-breaking 180,000 bpd in
December 2001.

[GRAPHIC DESCRIPTION]
BRIDGE ANALYSIS
OF NET
EARNINGS
(Cdn$millions)

Total                 315                                     2000
Volume                 40
Oil Price             (65)
Royalties              44
Cash Expenses         (10)
Tax Adjustment          9
- Other
Earnings Before
  the Following       333
Millennium
  Start-up            (81)
Tax Adjustments*       31
Total                 283                                     2001

Lower crude price and increased costs associated with start-up of Project
Millennium, partially offset by record sales volume and decreased royalties and
income taxes, resulted in a 10% decrease in earnings.

*    Provincial income tax rate adjustment on opening future tax balances.

[GRAPHIC DESCRIPTION]
                               1997    1998    1999    2000    2001

PRODUCTION
(thousands of bpd)

Actual                         79.4    93.6   105.6   113.9   123.2

Oil Sands achieved record production of 123,200 bpd in 2001. As the new
Millennium facilities are fully integrated with base operations, Oil Sands
expects production to average 210,000 bpd in 2002.

                                                           2001 ANNUAL REPORT 31

<PAGE>

Production in 2001 was impacted by a planned MAINTENANCE SHUTDOWN of the
fractionating tower in the second quarter that halted production for a total of
nine days and an unscheduled seven-day maintenance shutdown of the same facility
in the fourth quarter.

Higher sales levels in 2001 resulted in a year-over-year earnings improvement of
$40 million.

Because production commenced from Millennium upgrading facilities before the
hydrotreating units were fully commissioned, sour crude inventories increased in
late 2001. The sour crude inventory is expected to be reduced in the first half
of 2002. Since the majority of the anticipated future incremental production
from Project Millennium is expected to be upgraded sweet crude, an improved
crude sales mix is expected in 2002. Oil Sands is targeting production of
approximately 55% light sweet crude, 12% diesel and 33% light sour crude in 2002
compared to the 2001 mix of 46% light sweet crude, 12% diesel and 42% light sour
crude.

ROYALTIES
Crown royalties in effect for Suncor's existing Oil Sands operations require
payments to the Government of Alberta of 25% of net revenues less allowable
costs (including capital expenditures), subject to a minimum payment of 1% of
gross revenues, a rate that Suncor expects to pay until 2009. This expectation
is based on assumptions relating to future oil prices, production levels,
operating costs and capital expenditures. In 2001 Oil Sands made royalty
payments of 1% of gross revenues, compared to 5% in 2000.

Crown royalties payable by Suncor to the Government of Alberta decreased to $15
million in 2001 from $87 million in 2000 as a result of the 1% royalty rate and
lower commodity prices that were only partially offset by higher sales levels.
The lower Crown royalties were partially offset by a $4 million increase in
royalties paid to Anadarko Petroleum Corporation (Anadarko) due to more tonnes
mined in 2001 from the lease on which Anadarko has a royalty interest. Mining on
the lease is expected to be completed in 2002.

The decrease in total royalties expensed increased earnings by $44 million
after-tax.

EXPENSES INCREASED
Cash expenses of $493 million in 2001 increased by 3% over 2000 levels, reducing
Oil Sands earnings by approximately $10 million after-tax. The increase in
expenses was a result of higher energy costs driven by higher natural gas
prices, higher sales volumes and higher mining costs, including the costs
associated with minimizing the impact of ore variability.

Non-cash charges (depreciation, depletion and amortization) remained flat
year-over-year due to offsetting factors.

PER BARREL OPERATING COSTS
Cash operating costs, excluding $5.10 per barrel Project Millennium start-up and
OVERBURDEN removal expenditures, decreased to $11.90 per barrel in 2001. This
compares to $12.55 in 2000 (excluding $1.00 per barrel in Project Millennium
start-up and overburden removal costs in 2000). The decrease of $0.65 per barrel
is due to higher volumes, partially offset by higher energy costs.

Not all the expenses associated with the additional volumes from Project
Millennium are included in the $11.90 per barrel cash operating cost. As a
result, the $11.90 per barrel cash operating cost is not indicative of cash
operating costs in the future.

Total cash and non-cash operating costs per barrel in 2001 were $14.50 ($19.60
including Project Millennium start-up and overburden removal expenses), compared
with $16.25 per barrel ($17.25 per barrel including Project Millennium

[GRAPHIC DESCRIPTION]
                               1997    1998      1999    2000    2001
CASH AND TOTAL
OPERATING COSTS
(Cdn$ per barrel)

Cash Operating Cost           13.25   11.75     11.70   12.55   11.90
Start-up Expenditures           --      --         --    1.00    5.10
Project Millennium
Total Cash Cost               13.25   11.75     11.70   13.55   17.00
Non-cash Cost                  2.55    2.25      3.35    3.70    2.60
Total                         15.80   14.00     15.05   17.25   19.60

Total cash costs increased due to higher energy costs and Project Millennium
start-up expenditures. Non-cash expenses decreased due to reduced maintenance
shutdown amortization costs resulting from deferral of a maintenance shutdown to
2002.

MAINTENANCE SHUTDOWN
Preventative maintenance activities that involve shutting down major parts
of a facility or an entire facility.

OVERBURDEN
Surface material that must be removed before mining. Consists of muskeg, glacial
deposits and sand.

32 SUNCOR ENERGY INC.

<PAGE>

expenses) in 2000. The $1.75 per barrel decrease in total operating costs
(excluding Project Millennium expenses) was due to the same factors affecting
cash operating costs.

Oil Sands cash operating margin was $11.50 per barrel in 2001, compared with
$15.80 per barrel in 2000. The following factors influenced cash margins during
the year:

o    Lower crude prices (before hedging) had an unfavourable impact of $7.10 per
     barrel.

o    Lower hedging losses had a favourable net impact of $4.60 per barrel.

o    Cash operating costs had a favourable impact of $0.65 per barrel.

o    Project Millennium start-up and overburden removal expenditures had an
     unfavourable impact of $4.10 per barrel.


o    Lower royalties had a favourable impact of approximately $1.65 per barrel.

NET CASH DEFICIENCY ANALYSIS
Cash flow provided from operations was $486 million in 2001, compared with $655
million in 2000. The decrease of $169 million was primarily due to lower
earnings resulting from Project Millennium's $141 million start-up expenses in
2001, $126 million higher than 2000 spending. Higher overburden removal
expenditures (mostly related to Project Millennium) of $119 million, compared to
2000 expenditures of $75 million, a $10 million increase in reclamation spending
to $22 million, and recognition of the estimated employee long-term compensation
program payment in the amount of $16 million were other factors that reduced
cash flow provided from operations compared to 2000 by $43 million.

Oil Sands working capital increase in 2001 was $35 million, compared to $169
million increase in 2000. This reduction is primarily due to lower trade
receivables in 2001, reflecting lower crude oil prices. The reduction was partly
offset by higher inventory levels and lower accounts payable and accruals,
reflecting completion of Project Millennium, offset partially by an increase in
current liabilities resulting from recognition of the estimated employee
long-term compensation program payment.

Capital investment at Oil Sands decreased to approximately $1.5 billion in 2001
from approximately $1.7 billion in 2000. The $239 million decrease was primarily
due to lowerspending on Project Millennium.

These combined factors resulted in a decrease in net cash deficiency from $1.2
billion in 2000 to approximately $1 billion in 2001.

[GRAPHIC DESCRIPTION]
                          1997    1998    1999    2000    2001

OPERATING MARGINS
(Cdn$ per barrel)

Selling Price             26.36   22.18   23.84  31.67   29.17
Cash Margin               12.05    9.25   10.75  15.80   11.50-
                                                 16.80   16.60
SELLING PRICE - The average price from the sale of crude oil, including the
impact of hedging activities.

CASH MARGIN - The difference between the selling price received for products
sold and cash operating cost per barrel plus royalties per barrel.

[GRAPHIC DESCRIPTON]
                             2000                       2001

BRIDGE ANALYSIS
OF NET CASH                 0
DEFICIENCY
(Cdn$ millions)

Total                            (1 229)
Operations                          (43)
Working Capital                     134
Investing Activities                239
Cash Flow Before the Following     (229)
Project Millennium                 (126)
Total                            (1 025)


Lower capital spending on Project Millennium and a decrease in working capital
mainly due to lower trade receivables were partially offset by decreased cash
flow from operations and expenses associated with start-up of Project
Millennium.

                                                           2001 ANNUAL REPORT 33

<PAGE>

O U T L O O K
The foundation of Oil Sands growth plans is the large resource base estimated to
be in place on Suncor leases.

Independent estimates place total Oil Sands resources at 12 billion barrels,
including PROVED AND PROBABLE RESERVES that are estimated at 4.4 billion
barrels.

Suncor's future plans for Oil Sands are a continuation of the company's current
plans and strategic drivers. The company's focus remains on activities expected
to increase production, decrease operating costs and improve environment, health
and safety performance.

INCREASE PRODUCTION
Oil Sands expects production to average approximately 210,000 bpd in 2002 as the
new Millennium facilities are fully integrated with base operations. This
production goal assumes a 28-day maintenance shutdown will take place during the
year. Management will look at the potential to defer the shutdown to 2003.

Construction on the first phase of the Firebag In-situ Oil Sands Project,
including approved upgrader expansions, is scheduled to continue in 2002. Twenty
steam assisted gravity drainage (SAGD) well pairs for Stage 1 are scheduled for
drilling during the year. Production facility modules are under construction and
installation is scheduled to begin at the site in the second quarter of 2002.
Spending in 2002 for this work is currently estimated at $420 million. In-situ
production from the first phase of Firebag and upgrader expansions is expected
to bring Oil Sands production capacity from 225,000 bpd to a daily average of
260,000 bpd in 2005.

In 2002 Suncor will consult with stakeholders in creating detailed plans for
engineering, design and project development for Project Voyageur. Voyageur is
planned to further expand Suncor's oil sands and in-situ developments, building
on the benefits of both types of operations to increase production.

Assuming production of 260,000 bpd has been reached by 2005, Voyageur phase one
is being planned to increase production capacity to the range of 400,000 to
450,000 bpd in 2008. Current phase two plans call for additional processing
units to reach a target production capacity of 500,000 to 550,000 bpd in 2010 to
2012.

Preliminary cost estimates for Voyageur will be made late in 2002. Development
requires regulatory approval, and is subject to other conditions mentioned on
page 30.

A Sustainability Legacy program will be integrated into planning for Voyageur
with an objective of mitigating increases in air emissions, reducing water use
and discharge, accelerating reclamation and limiting land disturbance. The
Sustainability Legacy program also plans to examine ways Suncor can support
training and apprenticeship programs and help neighbouring communities benefit
from the growth of the oil sands industry. Currently, there are no cost
estimates for this program.

REDUCE OPERATING COSTS
Management believes that debottlenecking and efficiency and reliability
improvements provide an opportunity to further reduce the cash operating cost
per barrel. Management will work towards its objective of achieving cash
operating costs of $8.50 to $9.50 (approximately US$6) per barrel, though

--------------------------------------------------------------------------------

PROVED AND PROBABLE RESERVES
Annual estimates are made by Suncor of recoverable bitumen reserves associated
with company in-situ leases and of synthetic crude oil reserves associated with
its mineable oil sands leases. The estimates are then allocated between proved
and probable categories based upon criteria determined by management and
reviewed by independent consultants. With proved reserves there is at least a
90% confidence the estimate will be exceeded.

Probable reserves incorporate portions of both mining and in-situ (Firebag)
Suncor leases that have a lower drilling density and are expected to be
recovered under current approvals within a period of 30 years. There is at least
a 50% chance the proved plus probable reserve estimates will be exceeded. The
bitumen estimates are converted to crude oil estimates on the basis of yields
currently being obtained.

Resources include proved and probable reserves. These resources include
quantities of oil and gas that are estimated, on a given date, to be potentially
recoverable from known accumulations and undiscovered accumulations that are not
proved or probable reserves. Resources are a higher risk and are generally
believed to be less likely to be recovered than proved and probable reserves.
Total resources include both synthetic crude oil estimates for mining leases,
and bitumen estimates for in-situ oil sands leases.

34 SUNCOR ENERGY INC.

<PAGE>

attaining this objective will require achieving some of the improvements noted
above and will depend on factors and assumptions such as natural gas costs at
mid-cycle prices and higher production levels. In 2002 management believes cash
operating costs could be in the $10 to $10.50 (US$6.50 to US$6.80) per barrel
range.

These targets and estimates are subject to certain risk factors and
uncertainties discussed on page 44 under "Forward-looking Statement" and their
achievement cannot be assured.

RISK/SUCCESS FACTORS
AFFECTING PERFORMANCE
The strategic advantages of Oil Sands growth include:

o    Economies of scale associated with higher levels of production from the
     existing Oil Sands infrastructure.

o    Parallel processing in the extraction and upgrading processes provide
     flexibility to schedule periodic plant maintenance while continuing to
     generate production from the remaining units.

o    The ability to leverage demonstrated operational experience and
     technologies.

o    Production growth without the level of exploration risk associated with
     conventional oil and gas operations.

The issues Suncor must manage include, but are not limited to:

o    Suncor's ability to finance Oil Sands growth in a volatile commodity
     pricing environment. (Also refer to the section on Liquidity and Capital
     Resources on page 28.)


o    The ability to complete future oil sands projects both on time and on
     budget could be impacted by competition from other oil sands projects for
     skilled people, increased demands on the Fort McMurray, Alberta
     infrastructure (housing, roads, schools, etc.), or higher prices for the
     products and services required to operate and maintain the Oil Sands plant.
     Suncor continues to address these issues through a comprehensive
     recruitment and retention strategy, working with the community to determine
     infrastructure needs, designing Oil Sands expansion to reduce unit costs,
     seeking strategic alliances with service providers and tightening controls
     on engineering, procurement and project management.

o    Potential changes in the demand for refinery feedstocks and diesel fuel.
     Suncor believes it can reduce the impact of this issue by entering into
     long-term supply agreements with major customers, expanding its customer
     base and offering customized blends of refinery feedstocks to meet customer
     specifications.

The profitability of Suncor's Oil Sands business is influenced by world crude
oil price levels. These prices are difficult to predict and impossible to
control. In addition, the light/heavy oil differential can have an impact on
earnings. In 2001, this differential widened and reduced earnings. Management
believes the differential will trend toward more historical ranges in 2002 if
the demand for heavy oil increases as anticipated.

Unplanned production or operational outages and slowdowns, particularly those
that are weather-related, can be expected.

Suncor's relationship with employees and trade unions is important to the
company's future success because work disruptions have the potential to
adversely affect Oil Sands operations and growth projects. Suncor entered into a
new three-year collective agreement with the Communications, Energy and
Paperworkers Union, Local 707 effective May 1, 2001.

Also refer to Risk/Success Factors Affecting Performance on page 27.

                                                           2001 ANNUAL REPORT 35

<PAGE>

                      N A T U R A L  G A S  O V E R V I E W

Suncor's Natural Gas business (NG) produces conventional natural gas in Western
Canada, supplying it to markets throughout North America. The sale of NG
production provides an internal hedge for Suncor's natural gas consumption.

In 2001, NG continued to advance its strategy for profitable growth in order to
maintain an INTERNAL HEDGE for Suncor's growing gas consumption. This strategy
is built on four key platforms:

o    Focusing on natural gas.

o    Building competitive operating areas.

o    Improving base business efficiency.

o    Creating new low capital service offerings to the resource sector.

NG's first service offering, Prospect Generation Services (PGS), was launched
and generated net cash flow of $6 million in 2001 primarily through land sales.
PGS develops prospects on new and existing non-core Suncor lands and markets
those business opportunities to the resource sector. PGS earnings did not have a
material impact on earnings in 2001.

NET EARNINGS ANALYSIS

NET EARNINGS INCREASE BY 19%
Net earnings were $117 million in 2001, up 19% over the 2000 level of $98
million, primarily due to stronger natural gas prices and cost reductions.
Operational earnings, which in 2001 exclude the impact of the adjustment related
to revaluation of opening future provincial income tax balances ($9 million),
asset divestments ($4 million) and restructuring charges ($1 million), increased
by 75% from $59 million in 2000 to $103 million in 2001. This was primarily due
to higher commodity prices and lower exploration and operating costs, partially
offset by lower production volumes resulting from property divestments in 2000
and higher royalty expenses. Cash flow from operations rose to $280 million from
$238 million in 2000, also a reflection of higher natural gas prices and lower
costs.

RESULTS OF OPERATIONS,
INVESTING AND EXPLORATION
ACTIVITIES

2001 VS. 2000

NATURAL GAS - SUMMARY OF RESULTS
<TABLE>
<CAPTION>
($ millions unless otherwise noted)   2001     2000    1999
<S>                                  <C>      <C>     <C>
Revenue                                449      428     306
Production (thousands boe/d)          33.4     40.5    51.1
Average sales price
  Natural gas
  ($/thousand cubic feet)             6.09     4.72    2.44
  Natural gas liquids
  ($/barrel)                         34.38    36.66   19.32
  Crude oil ($/barrel)               33.92    29.50   20.94
Operational earnings                   103       59      22
Net earnings                           117       98      41
Cash flow provided
  from operations                      280      238     172
Total assets                           722      762     962
Capital and exploration
  expenditures                         132      127     200
ROCE (%)                              32.1     17.2     5.5
-----------------------------------------------------------
</TABLE>

In 2001, Suncor began to convert natural gas to barrels of oil equivalent (boe)
at a 6:1 ratio (thousand cubic feet of natural gas:barrel of oil); previously,
conversion was on a 10:1 basis. Figures for 1999 and 2000 have been restated on
a 6:1 basis.

--------------------------------------------------------------------------------
INTERNAL HEDGE
An internal hedge occurs when Suncor's natural gas production equals or is
greater than internal consumption, providing the company protection from
volatile natural gas prices in the North American market.

36 SUNCOR ENERGY INC.

<PAGE>

NATURAL GAS PRICES INCREASE 29%
In 2001, NG's natural gas price averaged $6.09 per thousand cubic feet (mcf) of
natural gas, compared with $4.72 per mcf in 2000. Increased prices in 2001 were
a result of increased demand coupled with a relatively flat natural gas supply
in North American markets. NG also benefited from higher than industry average
exposure to the high value California market in 2001. While crude oil made up
only 7% of NG's production in 2001, crude prices were also higher than 2000,
averaging $33.92 per barrel (after hedging losses), compared to $29.50 per
barrel (after hedging losses) in 2000. The price for natural gas liquids
averaged $34.38 per barrel in 2001, compared to $36.66 per barrel in 2000. The
combined impact of the above pricing factors increased earnings by $49 million.

PRODUCTION DECLINES 17% FROM 2000 LEVELS NG's natural gas and liquids volumes
declined to an average of 33,400 barrels of oil equivalent per day (boe/d), or
200 million cubic feet equivalent/day (mmcfe/d) in 2001, from an average of
40,500 boe/d or 243 mmcfe/d in 2000. The main reason for production declines was
asset divestments associated with portfolio optimization during 2000. Production
divestments of 10,600 boe/d at the time of sale were only partially offset by
volume growth related to the 2001 capital spending program. The decrease in
volumes resulted in a reduction in earnings of $28 million compared to 2000.

ROYALTIES INCREASE
Royalties increased to $8.56 per boe in 2001, from $6.81 per boe in 2000 due
mainly to the increase in commodity prices. The increase in royalties resulted
in a reduction in earnings of $2 million.

[GRAPHIC DESCRIPTON]
                             2000                       2001

BRIDGE ANALYSIS
OF NET EARNINGS
DEFICIENCY
(Cdn$ millions)

Total                               98
Price                              (28)
Volume Royalties                    (2)
Expenses                            25
Earnings Before the Following      142
Divestment Gains                   (65)
Tax Adjustment*                      9
Restructuring Costs                 31
Total                              117

Higher natural gas prices and lower expenses offset the decline in production
from 2000 divestments.
*    Provincial income tax rate adjustment on opening future tax balances.

[GRAPHIC DESCRIPTON]
                                1997    1998    1999    2000    2001

SUNCOR NG PRICING
VS. INDUSTRY AVERAGE
(Cdn$/thousand cubic feet)

Suncor NG Average Annual Price  1.93    1.95    2.44    4.72    6.09
Industry Average Reference      1.98    1.95    2.47    4.53    5.39
  Price

2001 Industry Average Reference Price is an estimate.

[GRAPHIC DESCRIPTON]
                             2000                       2001

BRIDGE ANALYSIS
NET CASH SURPLUS
(Cdn$ millions)

Total                               451
Operations                           59
Capital and Exploration
  Expenditures                       (7)
Divestment Proceeds                (292)
Total                               211

Year-over-year decline of $240 million in NG's net cash flow reflected lower
proceeds from property dispositions and slightly higher capital and exploration
spending, partially offset by higher operating cash flows resulting from higher
natural gas prices and lower expenses.

[GRAPHIC DESCRIPTON]
                                1997    1998    1999    2000    2001

PRODUCTION
(thousands of boe per day)


Natural Gas                     40.0    41.2    37.7     33.3    29.5
Liquids (natural gas liquids    15.7    16.3    13.4      7.2     3.9
and crude oil)
Total                           55.7    57.5    51.1     40.5    33.4

Although 2001 production was lower than 2000 due to property divestments,
production exceeded 2001 goals by 1,000 boe/d, as NG continued bringing
non-producing reserves to the producing stage.

                                                           2001 ANNUAL REPORT 37

<PAGE>

TOTAL EXPENSES REDUCED FROM 2000 LEVELS
Total expenses, excluding royalties and restructuring charges, were reduced by
$49 million in 2001 from 2000 levels. Exploration expenses were down $31 million
in 2001 due to a decrease in dry hole costs. Operating expenses decreased by $10
million compared to 2000 levels due to asset divestments and improved base
business efficiency. Non-cash expenses (depreciation, depletion and
amortization) decreased by $8 million as a result of divestments in 2000.
Combined, the above factors increased earnings by $25 million year-over-year.

In 2000, NG set a target to decrease annualized operating costs by a total of
$18 million to $20 million by year-end 2001. Approximately $15 million of this
target was reached in 2000. Annualized operating costs decreased an additional
$5 million in 2001 through a focus on administrative cost controls and reduced
lifting costs.

ASSET DIVESTMENT GAINS
In 2001, NG divested a non-core heavy oil property, recording a $4 million
after-tax gain, compared to a $69 million gain in 2000 when the majority of NG's
announced strategic divestments occurred. This resulted in a $65 million change
year-over-year.

RESTRUCTURING CHARGES
In 2001, NG recorded a positive adjustment on restructuring charges that
increased after-tax earnings by $1 million. In 2000, NG recorded restructuring
charges that reduced after-tax earnings by $30 million for a year-over-year
change of $31 million.

TAX ADJUSTMENTS
In 2001, earnings benefited from positive tax adjustments of $9 million. This
reflects the impact of adjustments related to revaluation of opening future
income tax balances.

NET CASH SURPLUS ANALYSIS
NG had a net cash surplus of $211 million in 2001, a decline of $240 million
when compared to the net cash surplus of $451 million in 2000. This reduction
was primarily due to a decrease in divestment proceeds of $292 million,
partially offset by an improvement in cash from operating activities of $59
million.

CAPITAL AND EXPLORATION INVESTING ANALYSIS
During 2001, NG continued to focus on bringing proved undeveloped reserves into
production. Capital expenditures were $132 million, higher than $127 million in
2000, due to increased expenditures on coalbed methane land acquisition and
exploration. Divestment proceeds decreased $292 million as a result of
completing the strategic divestment program in 2000.

[GRAPHIC DESCRIPTION]
2001 DIRECT PROPRIETARY GAS SALES
(69% of sales)

                                      (mmcf/d) (%)
British Columbia                      13       11
Midwest U.S.                          15       12
Eastern Canada                        21       17
California                            40       33
Alberta                               33       27
Total                                122      100

[GRAPHIC DESCRIPTION]
2001 SYSTEM PROPRIETARY GAS
(31% of sales)

                                   (mmcf/d)    (%)
TransCanada Gas Services           29          53
Pan Alberta                        19          35
Canwest                             2           3
Other                               5           9
Total                              55         100

[GRAPHIC DESCRIPTION]
                             1997     1998     1999     2000     2001

LIFTING AND
ADMINISTRATION COSTS

Administration                 28       29       28       29       24
(Cdn$ millions)
Lifting ($ per boe)          2.81     2.79     3.10     3.11     2.96

Total operating costs decreased from the prior year as Natural Gas maintained
focus on controlling administrative costs and reducing lifting costs.

[GRAPHIC DESCRIPTION]
                            1997   1998   1999   2000   2001
TOTAL PROVED RESERVES
(millions of barrels
of oil equivalent)

Natural Gas                  182    200    168    133    125
Liquids                       70     69     51     16     14
Total                        252    269    219    149    139

Over the last two years, Natural Gas activities have been directed towards
bringing non-producing reserves to the producing stage.

38 SUNCOR ENERGY INC.

<PAGE>

O U T L O O K

PROFITABLE GROWTH
NG has a goal of achieving a return on capital employed (after-tax earnings
divided by average capital employed) of at least 12% in 2002 and 15% in 2004 at
mid-cycle natural gas prices (US$3.00 to US$3.50/mcf price range) while
producing volumes in excess of internal demand. Management will work toward this
goal by building existing operating areas and developing new production and
revenue streams.

NG's production outlook for 2002 targets 180 mmcf/d to 190 mmcf/d of natural gas
plus 1,800 bpd of natural gas liquids and 1,200 bpd of oil.

Leveraging Suncor's expertise and assets in three core areas in western Alberta
and northeastern British Columbia will continue to be the foundation for
production and revenue in 2002.

SUSTAINABILITY AND RENEWABLE ENERGY
Suncor announced plans to place investments in renewable energy under the
management of NG beginning in 2002. NG will manage and operate Suncor's
renewable energy projects, but segmented financial data will be reported under
Corporate results. This realignment is part of Suncor's strategy to provide
hydrocarbon-based resources that meet the immediate energy needs of consumers
while also pursuing the development of low-emission and no-emission energy
sources that have a reduced environmental impact.

In 2002, Suncor plans to continue to investigate wind power as an economically
viable source of renewable energy. Incentives announced in Canada's federal
budget late in 2001 should increase the attractiveness of wind power
investments.

Coalbed methane development may contribute to both increased volumes and reduced
carbon dioxide (CO2) emissions. NG is participating in research and development
initiatives to evaluate the potential of coalbeds to SEQUESTER CO2, a waste
greenhouse gas emission. CO2 pumped into the coalbed may provide an economic
means of increasing production of natural gas from the coalbed while reducing
the company's net overall greenhouse gas emissions.

RISK/SUCCESS FACTORS
AFFECTING PERFORMANCE

Management continues to believe the single most important factor influencing
NG's long-term performance is its ability to consistently and competitively find
and develop reserves that can be brought on stream economically. Market demand
for land and services can also increase or decrease operating costs.

Management believes there are risks and uncertainties associated with obtaining
regulatory approval for exploration and development activities. Working in other
countries could increase these risks and add to costs or cause delays to these
projects.

These factors and estimates are subject to certain of the risks, assumptions and
uncertainties discussed on page 44 under "Forward-looking Statement" and their
achievement cannot be assured.

Also refer to Risk/Success Factors Affecting Performance on page 27.

--------------------------------------------------------------------------------
SEQUESTER
Sequester refers to the capture and storage of carbon dioxide, preventing its
release to the atmosphere.

                                                           2001 ANNUAL REPORT 39

<PAGE>

                          S U N O C O   O V E R V I E W

Suncor's wholly owned subsidiary Sunoco Inc. operates a refining and marketing
business in central Canada. Its Sarnia, Ontario refinery has the capacity to
refine 70,000 barrels per day of crude oil into gasoline, distillates and
petrochemical products. Products are sold to wholesale, commercial and
industrial markets and through a controlled retail network in Ontario.

Sunoco's refining and marketing strategy is focused on:

o    Improving gross profit of refining assets.

o    Enhancing retail customer offering.

o    Creating long-term growth opportunities.

o    Supporting sustainable development.

For the third consecutive year, Sunoco continued to show volume growth in
refined product sales. In 2001, total sales averaged 93,400 barrels per day
(bpd), representing an improvement of 1% from 2000. Sunoco's share of the total
refined product sales in its primary market of Ontario was approximately 18%,
compared to 17% in 2000.

Approximately 59% of Sunoco's total sales volumes are marketed in Ontario
through controlled retail networks. These include 302 Sunoco retail service
stations, 18 Sunoco-branded Fleet Fuel Cardlock sites and two joint venture
businesses comprised of 154 Pioneer-operated service stations, 47 UPI-operated
retail service stations and bulk distribution facilities for rural and farm
fuels. (Pioneer Group Inc. is an independent retailer with which Sunoco has a
50% joint venture partnership and UPI Inc. is a 50% joint venture company with
GROWMARK Inc.)

Approximately 38% of Sunoco's refined products were sold to wholesale and
industrial accounts in Ontario and Quebec in 2001, primarily consisting of jet
fuels, diesel and gasolines. The remaining 3% of Sunoco's refined products were
petrochemicals sold through Sun Petrochemicals Company, a 50% joint venture
between a subsidiary of Sunoco and a U.S. refinery. Sunoco also markets natural
gas to approximately 125,000 commercial and residential customer accounts in
Ontario.

RESULTS OF OPERATIONS AND
INVESTING ACTIVITIES

2001 VS. 2000

SUNOCO - SUMMARY OF RESULTS
<TABLE>
<CAPTION>
($ millions unless otherwise noted)      2001    2000    1999
<S>                                     <C>     <C>     <C>
Revenue                                 2 588   2 604   1 779
Refined product sales
(thousands of cubic metres)
  Sunoco retail gasoline                1 575   1 539   1 500
  Total                                 5 419   5 360   5 080
Operational earnings                       70      68      27
Net earnings (loss) breakdown:
  Rack Back                                47      69      14
  Rack Forward                             23      (1)     13
  Others (tax adjustments)                 10      13      --
  Total                                    80      81      27
Cash flow provided
  from operations                         165     174     103
Investing activities                       71      59      43
Net cash surplus                          111     155     129
ROCE (%)                                 18.4    20.5     6.0
</TABLE>

IN JANUARY 2002, SUNCOR'S DOWNSTREAM OPERATIONS WERE REORGANIZED AS ENERGY
MARKETING AND REFINING. SEGMENTED RESULTS FOR 2001 ARE REPORTED UNDER THE SUNOCO
NAME.

40 SUNCOR ENERGY INC.

<PAGE>

NET EARNINGS ANALYSIS

NET EARNINGS REMAIN STEADY
Sunoco's 2001 net earnings were $80 million, compared with $81 million in 2000.
Operational earnings were $70 million, up from $68 million in 2000. Operational
earnings in 2001 and 2000 exclude favourable income tax adjustments of $10
million and $13 million, respectively, related to revaluation of opening future
provincial income tax balances. The higher operational earnings were due
primarily to improved margins in the commercial and reseller channels, stronger
profit from retail operations and retail natural gas business, and a 1% growth
in sales volumes. Partially offsetting the favourable factors were lower
refining margins, lower refinery production and higher expenses. Return on
capital employed was 18.4%, compared to 20.5% in 2000. The reduction resulted
from lower net earnings combined with a higher capital employed.

LOWER REFINING MARGINS IMPACT RACK BACK
RACK BACK operational earnings declined
to $47 million in 2001, compared with $69 million in 2000, due primarily to
lower refining margins, lower refinery production and higher expenses. Refining
margins decreased to 5.7 cents per litre (cpl) in 2001, compared with 5.9 cpl in
2000. The lower margins were attributable to a decline in product demand
resulting from a weakening economy. Net earnings decreased by $14 million due to
lower refining margins and higher costs driven by increased product purchases.

The refinery encountered a number of unplanned outages involving the catalytic
cracker (in the first quarter, 2001) and the petrochemical and vacuum units (in
the fourth quarter, 2001). As a result, the crudeutilization rate dropped to
92%, down 6% from 2000. Additional product purchases were made to satisfy
customer demand due to the lower production.

Sales volumes were 1% higher compared to 2000, averaging 14,800 cubic metres per
day (93,400 bpd) from 14,600 cubic metres per day (92,200 bpd) in 2000. The
higher sales volumes were comprised of the refinery's production, which was 4%
lower than 2000, and purchases of finished products to meet customer demand.

In the fourth quarter of 2001, the Sarnia refinery completed a planned
maintenance shutdown. While a majority of the work was completed on schedule,
there was a two-week extension to resolve catalyst problems.

Rack Back's expenses were $22 million higher in 2001 compared with 2000,
primarily as a result of higher natural gas prices and a 20% increase in natural
gas consumption due to reduced fuel oil burning. The increase in expenses was
partially offset by a gain of $9 million in 2001 from sales of excess supplies
of natural gas initially bought for the retail natural gas marketing business.
Due to changes in customer demand forecasting methodology, excess gas supply was
identified and liquidated.

Also impacting Rack Back's earnings was a $2 million earnings reduction from Sun
Petrochemicals Company.

RACK FORWARD EARNINGS UP $24 MILLION
RACK FORWARD operational earnings increased
to $23 million in 2001, compared to a loss of $1 million in 2000. The increase
was attributable to stronger earnings from retail operations, commercial and
reseller channels and improved retail natural gas margins.

[GRAPHIC DESCRIPTION]
                              1997    1998    1999    2000    2001

CRUDE UTILIZATION/
HIGH VALUE COMPONENTS
(percentage)

Crude Utilization               97      99      95      98      92
High Value Components           90      91      92      91      89

Sunoco's crude utilization rate declined 6% to 92% in 2001 due primarily to
unplanned outages during the year. A planned maintenance shutdown was also
completed in the fourth quarter.

--------------------------------------------------------------------------------
RACK BACK AND RACK FORWARD
Sunoco's financial reporting in 2001 is based on its Rack Back/Rack Forward
organizational structure and prior year results have been reclassified
accordingly. The Rack Back division includes the procurement and refining of
crude oil and feedstocks and sales and distribution to the Sarnia refinery's
largest industrial and reseller customers. Rack Forward includes retail
operations, retail natural gas marketing, cardlock and industrial/commercial
sales, and the UPI and Pioneer joint venture businesses.

                                                           2001 ANNUAL REPORT 41

<PAGE>

For the fourth consecutive year, gasoline sales at Sunoco's retail network
increased. Retail gasoline volume improved by more than 2%, contributing to an
earnings improvement of $2 million over 2000. While the retail gasoline margin
remained unchanged from 2000 at 6.6 cpl in 2001, total fuel margins from the
retail business improved by $4 million due to a more favourable product mix.
ANCILLARY and royalty income was $4 million higher than 2000, reflecting
continued expansion of non-fuel products and services in the retail network.
These positive earnings impacts were partially offset by increased expenses of
$7 million resulting from higher operating costs.

In 2001, retail natural gas margins improved $10 million from 2000. The
restructuring of customer contracts enabled Sunoco to match fixed price sales
contracts with fixed price supply. In addition, commercial and reseller sales
channels further improved Rack Forward earnings by $8 million due to margin
improvement and $1 million related to volume growth.

Net earnings from Sunoco's retail joint ventures with UPI and Pioneer were $2
million higher in 2001, reflecting stronger volumes and margins.

NET CASH SURPLUS ANALYSIS
Net cash surplus decreased to $111 million in 2001, compared with $155 million
in 2000. This decrease reflects the higher investment spending of $12 million, a
lower working capital decline of $23 million compared to 2000 and a decrease in
cash flow provided from operations of $9 million. This decrease includes the
recognition of estimated payments in 2002 with respect to Suncor's employee
long-term compensation programs.

[GRAPHIC DESCRIPTION]          1997   1998   1999   2000   2001
REFINED PRODUCT
SALES VOLUMES
(thousands of cubic metres)

                              5 182  5 037  5 080  5 360  5 419

Total sales volumes increased by more than 1% over 2000, reflecting higher
commercial/industrial sales volume and continued volume growth in the retail
gasoline business.

--------------------------------------------------------------------------------
ANCILLARY INCOME
Income earned from non-fuel products and services such as car washes, sale of
fast foods and confectionery items.

Working capital decreased by $17 million in 2001, compared with a reduction of
$40 million in 2000, contributing $23 million to the net cash surplus decline.
Key contributing factors were higher ending inventory and lower product prices
impacting payables. Investing activities totalled $71 million in 2001, including
$9 million for the planned maintenance shutdown at the Sarnia refinery, compared
with $59 million in 2000.

O U T L O O K
Sunoco will continue to focus on improving gross profit of refining assets,
enhancing its retail customer offerings, creating long-term growth opportunities
and focusing on sustainable development.

IMPROVE GROSS PROFIT OF REFINING ASSETS
Sunoco continues to pursue its goal to position the Sarnia refinery in the top
one-third of North American refineries of similar size and complexity by the end
of 2002. To achieve this, Sunoco will continue to focus on increasing the
operational flexibility of the Sarnia refinery to run different feedstocks,
improving energy cost management and optimizing existing assets to improve
reliability and flexibility.

To reduce exposure to energy cost increases, an energy supply agreement was
signed with TransAlta Energy Corporation (TransAlta) in 2001. Under the
contract, the TransAlta Sarnia Regional Cogeneration Project will provide a
portion of its steam supply to the Sarnia refinery at a competitive cost,
eliminating the need for Sunoco to build boilers for steam generation. According
to TransAlta, the new facility is expected to commence operation in late 2002.

[GRAPHIC DESCRIPTION]          1997   1998   1999   2000   2001

MARGIN
(Cdn cents per litre)

Sunoco-branded Retail
  Gasoline Margin               6.8    7.0    7.4    6.6    6.6
Refining Margin                 4.6    4.1    4.0    5.9    5.7

Refining margins declined from last year due mainly to the higher industry
inventory levels and lower demand in North America. Sunoco retail gasoline
margins remained unchanged from last year.

42 SUNCOR ENERGY INC.

<PAGE>

ENHANCE RETAIL CUSTOMER OFFERINGS
Sunoco plans to implement initiatives to improve its retail customer offerings
by expanding premium food and beverage service. Sunoco also continues to expand
its premium fuel products to retail customers. Marketing initiatives are in
place to increase sales of premium fuel products such as Ultra 94 gasoline and
Gold Diesel.

CREATE LONG-TERM GROWTH OPPORTUNITIES
Sunoco continues to evaluate strategic opportunities associated with the
industry's need to reformulate fuels to comply with new sulphur regulations on
gasoline and diesel.
Integration enhancement with Oil Sands and the economic
attractiveness of processing sour streams continue to be a strategic focus. To
capture a greater share of long-term value from increasing Oil Sands production,
Sunoco will continue to assess new marketing and refining investment
opportunities to further integrate Suncor's upstream and downstream businesses.

Sunoco completed a strategic assessment in 2001 of its retail natural gas
marketing business and is exploring possible disposition, joint venture or other
transactions.

FOCUS ON SUSTAINABLE DEVELOPMENT
Sunoco completed a detailed emission reduction plan in 2001. The plan targets to
reduce emissions of carbon dioxide, sulphur dioxide, nitrogen oxide and volatile
organic compounds at the Sarnia refinery by 25% from the 1995 levels by 2005.

While targeting improved margins and market growth, Sunoco also continues to
focus on environmental issues facing Ontario and Canada and developing more
environmentally responsible products. For example, to reduce emissions of carbon
monoxide and greenhouse gas, Sunoco's retail network introduced ethanol-enhanced
gasoline in 1997, which is now blended in all Sunoco gasoline and marketed
through the Sunoco, UPI and Pioneer retail networks.

Sunoco will continue to enforce management control programs to improve health
and safety performance.

RISK/SUCCESS FACTORS
AFFECTING PERFORMANCE
While Suncor's downstream business achieved higher operational earnings in 2001,
financial performance in the second half of the year was negatively affected by
margin and crude oil price volatility, lower demand for energy products and
overall market competitiveness. Management expects fluctuation in demand for
refined products, margin and price volatility and market competitiveness will
continue to impact the business environment.

The Canadian refining industry faces significant capital spending to construct
sulphur removal facilities. The spending is required to comply with legislation
limiting sulphur levels in gasoline to an average of 150 parts per million (ppm)
from mid-2002 to the end of 2004 and a maximum of 30 ppm by 2005. In 2001,
Sunoco finalized an investment plan to meet the sulphur content limits. Capital
spending

[GRAPHIC DESCRIPTION]
BRIDGE              2000                         2001
ANALYSIS OF
NET EARNINGS
(Cdn$ millions)

Total                           81
Fuel Margin                     (2)
Fuel Volume                     10
Retail Natural Gas Margin       10
Ancillary Income                 4
Expenses                       (20)
Earnings Before the Following   83
Tax Adjustment*                 (3)
Total                           80

Improvement in fuel volume, natural gas margin and ancillary income helped
offset increased expenses and lower margins. Tax adjustments related to opening
future income tax balances were $3 million lower than in 2000.
*    Provincial income tax rate adjustment on opening future tax balances.

[GRAPHIC DESCRIPTION]
BRIDGE              2000                         2001
ANALYSIS OF
NET CASH SURPLUS
(Cdn$ millions)

Total                      155
Operations                  (9)
Working Capital            (23)
Investing Activities       (12)
Total                      111

Net cash surplus declined $44 million to $111 million in 2001 due to a
combination of higher capital spending and lower reduction in working capital
driven by higher inventory and lower accounts payable.

                                                           2001 ANNUAL REPORT 43

<PAGE>

to achieve compliance is expected to be approximately $40 million and will
involve the addition of a new desulphurization unit. Construction is expected to
be completed in 2003. In 2001 Sunoco's sulphur level in gasoline averaged about
180 ppm, compared with the 2000 Ontario industry average of 450 ppm.

Environment Canada is expected to finalize new on-road diesel sulphur
regulations by mid-2002, with an implementation date of mid-2006. Regulations
reducing sulphur in off-road diesel and light fuel oil are also expected. Sunoco
continues to examine strategic options to comply with the pending regulations.
Actual capital spending required to meet the new standard is subject to the
development of such regulations and strategic assessment. Capital spending could
be significant, but is not expected to place the company at a competitive
disadvantage.

These factors and estimates are subject to certain of the risks, assumptions and
uncertainties discussed below under "Forward-looking Statement" and their
achievement cannot be assured.

Also refer to Risk/Success Factors Affecting Performance on page 27.

--------------------------------------------------------------------------------
FORWARD-LOOKING STATEMENT
This Management's Discussion and Analysis contains certain forward-looking
statements that are based on Suncor's current expectations, estimates,
projections and assumptions and were made by the company in light of its
experience and its perception of historical trends.

All statements that address expectations or projections about the future,
including statements about Suncor's strategy for growth, expected and future
expenditures, commodity prices, costs, schedules and production volumes,
operating and financial results, are forward-looking statements. Some of the
forward-looking statements may be identified by words like `expects,'
`anticipates,' `plans,' `intends,' `believes,' `projects,' `indicates,' `could,'
`vision,' `goal,' `target,' `objective' and similar expressions. These
statements are not guarantees of future performance and involve a number of
risks, uncertainties and assumptions. Suncor's business is subject to risks and
uncertainties, some that are similar to other oil and gas companies and some
that are unique to Suncor. Suncor's actual results may differ materially from
those expressed or implied by its forward-looking statements as a result of
known and unknown risks, uncertainties and other factors.

The risks, uncertainties and other factors that could influence actual results
include: changes in the general economic, market and business conditions;
fluctuations in supply and demand for Suncor's products; fluctuations in
commodity prices; fluctuations in currency exchange rates; Suncor's ability to
respond to changing markets; the ability of Suncor to receive timely regulatory
approvals; the successful implementation of its growth projects including the
Firebag In-situ Oil Sands Project and Project Voyageur; the integrity and
reliability of Suncor's capital assets; the cumulative impact of other resource
development projects; Suncor's ability to comply with current and future
environmental laws; the accuracy of Suncor's production estimates and production
levels and its success at exploration and development drilling and related
activities; the maintenance of satisfactory relationships with unions, employee
associations and joint venturers; competitive actions of other companies,
including increased competition from other oil and gas companies or from
companies that provide alternative sources of energy; the uncertainties
resulting from potential delays or changes in plans with respect to exploration
or development projects or capital expenditures; actions by governmental
authorities including increasing taxes, government fees, changes in
environmental and other regulations; the ability and willingness of parties with
whom Suncor has material relationships to perform their obligations to Suncor;
and the occurrence of unexpected events such as fires, blowouts, freeze-ups,
equipment failures and other similar events affecting Suncor or other parties
whose operations or assets directly or indirectly affect Suncor. Many of these
risk factors are discussed in further detail throughout this Management's
Discussion and Analysis and in the company's Annual Information Form on file
with the Alberta Securities Commission and certain other securities regulatory
authorities. Readers are also referred to the risk factors described in other
documents that Suncor files from time to time with securities regulatory
authorities. Copies of these documents are available without charge from the
company.

The tables and charts in this document form an integral part of Management's
Discussion and Analysis and should be referred to when reading the narrative.
References to Suncor or the company include Suncor Energy Inc. and its
subsidiaries and investment in joint ventures, unless otherwise stated.

44 SUNCOR ENERGY INC.

</TEXT>
</DOCUMENT>
