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<SEC-DOCUMENT>0000912057-02-013048.txt : 20020415
<SEC-HEADER>0000912057-02-013048.hdr.sgml : 20020415
ACCESSION NUMBER:		0000912057-02-013048
CONFORMED SUBMISSION TYPE:	6-K
PUBLIC DOCUMENT COUNT:		7
CONFORMED PERIOD OF REPORT:	20011231
FILED AS OF DATE:		20020401

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			SUNCOR ENERGY INC
		CENTRAL INDEX KEY:			0000311337
		STANDARD INDUSTRIAL CLASSIFICATION:	PETROLEUM REFINING [2911]
		IRS NUMBER:				000000000
		STATE OF INCORPORATION:			A0
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		6-K
		SEC ACT:		1934 Act
		SEC FILE NUMBER:	001-12384
		FILM NUMBER:		02597778

	BUSINESS ADDRESS:	
		STREET 1:		112 4TH AVENUE SW PO BOX 38
		STREET 2:		CALGARY
		CITY:			ALBERTA CANADA
		STATE:			A0
		ZIP:			T2P 2V5
		BUSINESS PHONE:		4032698100

	MAIL ADDRESS:	
		STREET 1:		112 FOURTH AVE SW BOX 38
		STREET 2:		CALGARY
		CITY:			ALBERTA CANADA
		ZIP:			T2P 2V5

	FORMER COMPANY:	
		FORMER CONFORMED NAME:	SUNCOR INC
		DATE OF NAME CHANGE:	19970430

	FORMER COMPANY:	
		FORMER CONFORMED NAME:	GREAT CANADIAN OIL SANDS & SUN OIL CO LTD
		DATE OF NAME CHANGE:	19791129
</SEC-HEADER>
<DOCUMENT>
<TYPE>6-K
<SEQUENCE>1
<FILENAME>a2075015z6-k.txt
<DESCRIPTION>FORM 6-K COVER, AIF (49 PP), SIGNATURES, EXH.INDEX
<TEXT>

<PAGE>




                                    FORM 6-K


                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                        Report of Foreign Private Issuer
                    Pursuant to Rule 13a - 16 or 15d - 16 of
                       the Securities Exchange Act of 1934



For the month of:  March 2002                   Commission File Number:  1-12384



                               SUNCOR ENERGY INC.
                              (Name of registrant)


                             112 FOURTH AVENUE S.W.
                                   P.O. BOX 38
                        CALGARY, ALBERTA, CANADA, T2P 2V5



Indicate by check mark whether the registrant  files or will file annual reports
under cover of Form 20-F or Form 40-F:

        Form 20-F                         Form 40-F      X
                  ---------                           ---------


Indicate by check mark whether the  registrant  by  furnishing  the  information
contained in this Form is also thereby  furnishing  the  information  to the SEC
pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:

        Yes                               No              X
                 ---------                            ---------


If "Yes" is marked, indicate the number assigned to the registrant in connection
with Rule 12g3-2(b):

         N/A



<PAGE>



                   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM




                                FEBRUARY 28, 2002





<PAGE>



                             ANNUAL INFORMATION FORM

                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
<S>                                                                                  <C>
ANNUAL INFORMATION FORM..................................................................ii
GLOSSARY OF TERMS.......................................................................iii
CONVERSION TABLE........................................................................vii
CURRENCY................................................................................vii
FORWARD-LOOKING STATEMENTS..............................................................vii
CORPORATE STRUCTURE.......................................................................1
     Incorporation of the Issuer..........................................................1
     Subsidiaries of Suncor...............................................................1
GENERAL DEVELOPMENT OF THE BUSINESS.......................................................1
     Three-Year Highlights................................................................2
NARRATIVE DESCRIPTION OF THE BUSINESS.....................................................5
   OIL SANDS..............................................................................5
     Operations...........................................................................5
     Leasehold Interests and Royalties....................................................7
     Estimated Reserves...................................................................8
     Reserves Reconciliation.............................................................10
     Revenues from Synthetic Crude Oil and Diesel........................................10
     Capital Expenditures................................................................11
     Environmental Compliance............................................................12
   NATURAL GAS...........................................................................12
     Reserves and Reserves Reconciliation................................................12
     Conventional Crude Oil..............................................................14
     Before Royalties at.................................................................15
     Natural Gas.........................................................................17
     Land Holdings.......................................................................17
     Drilling............................................................................18
     Wells...............................................................................19
     Sales and Sales Revenues............................................................19
     Production Costs....................................................................20
     Quarterly Volumes and Netback Analysis..............................................21
     Marketing, Pipeline and Other Operations............................................22
     Capital and Exploration Expenditures................................................22
     Environmental Compliance............................................................23
SUNOCO...................................................................................23
     Procurement of Feedstocks...........................................................23
     Refining Operations.................................................................24
     Principal Products..................................................................24
     Transportation and Distribution.....................................................26
     Capital Expenditures................................................................26
SUNCOR EMPLOYEES.........................................................................27
RISK/SUCCESS FACTORS.....................................................................27
SELECTED CONSOLIDATED FINANCIAL INFORMATION..............................................34
     Selected Consolidated Financial Information.........................................34
     Dividend Policy and Record..........................................................34
     Future Commitments to Buy, Sell, Exchange or Transport Crude Oil And Natural Gas....35
MANAGEMENT'S DISCUSSION AND ANALYSIS.....................................................36
MARKET FOR THE SECURITIES OF THE ISSUER..................................................36
DIRECTORS AND OFFICERS...................................................................37
ADDITIONAL INFORMATION...................................................................40
</TABLE>


                                                                             ii
<PAGE>


                                GLOSSARY OF TERMS


BITUMEN/HEAVY OIL

A naturally occurring viscous tar-like mixture,  mainly containing  hydrocarbons
heavier  than  pentane,  that is not  recoverable  at a  commercial  rate in its
naturally occurring viscous state through a well without using enhanced recovery
methods.  When  extracted  bitumen/heavy  oil can be upgraded into crude oil and
other petroleum products.

CAPACITY

Maximum  output  that  can  be  achieved  from a  facility  in  ideal  operating
conditions in accordance with current design specifications.

COALBED METHANE

Natural gas produced from wells drilled into a coal formation.  Also called coal
seam methane.

CONVENTIONAL CRUDE OIL

Crude oil produced through wells by standard  industry  recovery methods for the
production of crude oil.

CONVENTIONAL NATURAL GAS

Natural gas produced from all geological strata, excluding coalbed methane.

CRUDE OIL

Unrefined liquid hydrocarbons, excluding natural gas liquids.

DOWNSTREAM

This business  segment  manufactures,  distributes and markets refined  products
from crude oil.

DRY HOLE/WELL

An exploration or  development  well  determined,  on an economic  basis,  to be
incapable  of  producing  hydrocarbons  that  will  be  plugged,  abandoned  and
reclaimed.

GROSS PRODUCTION/RESERVES

Suncor's undivided percentage interest in  production/reserves  before deducting
Crown royalties, freehold and overriding royalty interests.

GROSS WELLS/LAND HOLDINGS

Total  number of wells or  acres,  as the case may be,  in which  Suncor  has an
interest.

HEAVY FUEL OIL

Residue  from  refining of  conventional  crude oil that remains  after  lighter
products such as gasoline, petrochemicals and heating oils have been extracted.


                                                                           iii

<PAGE>

IN-SITU OIL

In-situ or "in place" refers to methods of extracting  heavy crude oil from deep
deposits of oil sands with minimal disturbance of the ground cover.

NATURAL GAS

Hydrocarbons that at atmospheric conditions of temperature and pressure are in a
gaseous state.

NATURAL GAS LIQUIDS

Hydrocarbon  products  recovered as liquids  from raw natural gas by  processing
through extraction plants or recovered from field separators, scrubbers or other
gathering facilities.  These liquids include the hydrocarbon  components ethane,
propane, butane and pentane plus, or a combination thereof.

NET PRODUCTION/RESERVES

Suncor's undivided percentage interest in total production or total reserves, as
the case may be, after  deducting  Crown  royalties and freehold and  overriding
royalty interests.

NET WELLS/LAND HOLDINGS

Suncor's  undivided  percentage  interest in the gross  number of wells or gross
number of acres, as the case may be, after deducting interests of third parties.

OVERBURDEN

Material  overlying oil sands that must be removed  before  mining.  Consists of
muskeg, glacial deposits and sand.

PROBABLE RESERVES

Those  reserves  which  analysis  of  drilling,   geological,   geophysical  and
engineering data does not demonstrate to be proved under current  technology and
existing economic conditions, but where such analysis suggests the likelihood of
their existence and future recovery. Probable additional reserves to be obtained
by the application of enhanced recovery processes will be the increased recovery
over and above proved estimates that can be realistically estimated for the pool
on the basis of enhanced recovery processes which can be reasonably  expected to
be instituted in the future.

PROVED RESERVES

Those reserves  estimated as recoverable  with a high degree of certainty  under
current  technology  and existing  economic  conditions,  from that portion of a
reservoir which can be reasonably  evaluated as  economically  productive on the
basis of analysis of drilling,  geological,  geophysical and  engineering  data,
including   the  reserves  to  be  obtained  by  enhanced   recovery   processes
demonstrated to be economic and technically successful in the subject reservoir.

RESOURCES

Resources,  with respect to Suncor's oil sands leases, 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 and are of a higher risk than, and are generally  believed to
be less likely to be  recovered  than  proved and  probable  reserves,  and also
include proved and probable  reserves.  Total  resources  include both synthetic
crude oil estimates  for mining  leases,  and bitumen  estimates for in-situ oil
sands leases.


                                                                             iv
<PAGE>

RESERVOIR

Body of porous rock containing an  accumulation  of water,  crude oil or natural
gas.

SOUR SYNTHETIC CRUDE OIL

Crude oil  produced  from oil sands that  requires  only partial  upgrading  and
contains a higher sulphur content than sweet synthetic crude oil.

SWEET SYNTHETIC CRUDE OIL

Crude  oil  produced  from  oil  sands  consisting  of a blend  of  hydrocarbons
resulting from thermal cracking and purifying of bitumen.

SYNTHETIC CRUDE OIL

Upgraded or partially  upgraded  crude oil  recovered  from oil sands  including
surface mineable oil sands leases and in-situ heavy oil leases.

UNDEVELOPED OIL AND NATURAL GAS LANDS

Suncor's  undivided   percentage   interest  in  lands  where  no  producing  or
commercially producible well has been drilled.

UPSTREAM

This business segment includes acquisition, exploration, development, production
and marketing of crude oil, natural gas and natural gas liquids; and for greater
clarity  includes the production of synthetic  crude oil,  butimen and other oil
products from oil sands.

UTILIZATION

The average use of capacity  taking  into  consideration  planned and  unplanned
outages and maintenance.

WELLS

Development Well

A crude  oil or  natural  gas well in a  reservoir  known to be  productive  and
expected to produce in future.

DRILLED WELL

A well that has been  drilled and has a defined  status e.g.  gas well,  shut-in
well,  producing  oil  well,  producing  gas  well,  suspended  well  or dry and
abandoned well.

EXPLORATORY WELL

A well  drilled in unproved  or  semi-proved  territory  with the  intention  to
discover commercial reservoirs or deposits of crude oil and/or natural gas.



                                                                            v


<PAGE>

ACCOUNTING TERMS

BARREL OF OIL EQUIVALENT (BOE)

Suncor converts natural gas to crude oil on the approximate  long-term  economic
equivalent basis that 6,000 cubic feet of natural gas equals one barrel of crude
oil.

DEVELOPMENT COSTS

Includes all costs  associated  with moving  reserves from other classes such as
"proved undeveloped" and "probable" to the "proved developed" class.

FINDING COSTS

Includes  the  cost  of and  investment  in  undeveloped  land,  geological  and
geophysical  activities,  exploratory  drilling and direct  administrative costs
necessary to discover crude oil and natural gas reserves.

INTEREST COVERAGE -- CASH FLOW BASIS

Cash provided from operating  activities  before interest expense and income tax
payments, divided by the aggregate of interest expense and interest capitalized.

LIFTING COSTS

Includes all expenses  related to the operation and  maintenance of producing or
producible  wells and  related  facilities,  natural  gas plants  and  gathering
systems.

MMCF/E (MILLION CUBIC FEET EQUIVALENT)

Converts  crude oil  to  natural  gas  on  the  approximate  long-term  economic
equivalent  basis that one barrel of crude oil equals  6,000 cubic feet  natural
gas.

NET DEBT

Long-term borrowings (including the current portion) plus short-term borrowings,
less cash and cash equivalents.

OPERATING WORKING CAPITAL

Current assets (excluding cash and cash equivalents),  less current  liabilities
(excluding borrowings).

RETURN ON AVERAGE CAPITAL EMPLOYED

Earnings before  long-term  interest  expense as a percentage of average capital
employed. Average capital employed is the total of shareholders' equity and debt
(short-term   borrowings  and  current  and  long-term   portions  of  long-term
borrowings,  less the  capitalized  cost  related to major  growth  projects  in
progress), at the beginning and end of the year, divided by two.

RETURN ON AVERAGE SHAREHOLDERS' EQUITY

Earnings as a percentage of average shareholders' equity.  Average shareholders'
equity is the aggregate of total  shareholders'  equity at the beginning and end
of the year, divided by two.


                                                                            vi

<PAGE>


                                CONVERSION TABLE

<TABLE>
<CAPTION>
<S>                                                              <C>
 1 cubic metre m(3) = 6.29 barrels                               1 tonne = 0.984 tons (long)
 1 cubic metre m(3) (natural gas) = 35.49 cubic feet             1 tonne = 1.102 tons (short)
 1 cubic metre m(3) (overburden) = 1.31 cubic yards              1 kilometre = 0.62 miles
                                                                 1 hectare = 2.5 acres
</TABLE>

NOTES:

(1)      Conversion using the above factors on rounded numbers appearing in this
         Annual  Information  Form may produce small  differences  from reported
         amounts.

(2)      Some information in this Annual Information Form is set forth in metric
         units and some in imperial units.


                                    CURRENCY

All references in this Annual Information Form to dollar amounts are in Canadian
dollars unless otherwise indicated.


                           FORWARD-LOOKING STATEMENTS

This Annual  Information Form 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 and future expenditures,
commodity prices, costs, schedules,  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", "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.

You are  cautioned  not to place  undue  reliance on  Suncor's  forward  looking
statements.  The risks,  uncertainties  and other  factors that could  influence
actual results include but are not limited to: 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 and timely 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
reserve estimates, 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  tax
increases and changes in 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; the occurrence of
unexpected events such as fires,  blowouts,  freeze-ups,  equipment failures and
other


                                                                             vii

<PAGE>



similar  events  affecting  Suncor or other parties  whose  operations or assets
directly or  indirectly  affect  Suncor;  and other  factors,  many of which are
beyond Suncor's control.


Suncor cautions that the foregoing list of important  factors is not exhaustive.
Many of these risk  factors are  discussed  in further  detail  throughout  this
Annual Information Form and in Management's Discussion and Analysis for the year
ended  December  31, 2001 and dated  February 28, 2002  ("MD&A"),  which MD&A is
incorporated by reference herein.  Readers are also referred to the risk factors
described  in other  documents  Suncor  files from time to time with  securities
regulatory  authorities.  Copies of these documents are available without charge
from the Company at 112 - 4th Avenue S.W., Calgary, Alberta, T2P 2V5, by calling
1-800-558-9071, or by email request to info@suncor.com.




                                                                           viii


<PAGE>


                               CORPORATE STRUCTURE

INCORPORATION OF THE ISSUER

Suncor  Energy  Inc.  (formerly  Suncor  Inc.)  was  originally  formed  by  the
amalgamation  under the CANADA BUSINESS  CORPORATIONS  ACT on August 22, 1979 of
Sun Oil  Company  Limited,  incorporated  in 1923 and Great  Canadian  Oil Sands
Limited,  incorporated in 1953. On January 1, 1989,  Suncor  amalgamated  with a
wholly-owned  subsidiary under the CANADA BUSINESS  CORPORATIONS  ACT.  Suncor's
articles  were  amended  in 1995 to move its  registered  office  from  Toronto,
Ontario,  to Calgary,  Alberta,  and amended  again in April 1997,  to adopt its
current  name,  "Suncor  Energy  Inc.".  In April  1997 and May  2000,  Suncor's
articles  were  amended  to  divide  its  issued  and  outstanding  shares  on a
two-for-one  basis.  In January 2002,  Suncor's Board of Directors  authorized a
further  two-for-one  common share  division  with a May 15, 2002,  record date,
subject to shareholder  approval at the Company's  annual meeting  scheduled for
April 26, 2002.

Suncor's  registered and principal  office is located at 112 - 4th Avenue,  S.W.
Calgary, Alberta, T2P 2V5.

In this Annual Information Form, references to "Suncor" or the "Company" include
Suncor Energy Inc., its  subsidiaries and joint venture  investments  unless the
context otherwise requires.

SUBSIDIARIES OF SUNCOR

Suncor Energy Inc. has two principal subsidiaries.

Sunoco Inc. ("Sunoco") is an Ontario corporation that is wholly-owned by Suncor.
Sunoco refines and markets petroleum  products and  petrochemicals  directly and
indirectly through  subsidiaries and joint ventures.  In this Annual Information
Form,  references  to "Sunoco"  mean Sunoco  Inc.,  its  subsidiaries  and joint
venture investments,  unless the context otherwise requires. Sunoco is unrelated
to Sunoco,  Inc. (formerly known as Sun Company,  Inc.) that is headquartered in
Philadelphia, Pennsylvania.

Suncor Energy Marketing Inc.,  wholly-owned by Sunoco, is incorporated under the
laws of Alberta.  Suncor Energy Marketing Inc. manages Company and certain third
party  Alberta-based  pipeline  operations  and markets,  mainly to customers in
Canada and the United  States,  certain  crude oil,  diesel fuel  products,  and
byproducts such as petroleum  coke,  sulphur and gypsum produced by Suncor's Oil
Sands and Natural Gas (NG)  business  units as well as certain other third party
products.  Commencing in 2002, Suncor Energy Marketing Inc. will also market the
Company's  natural gas  production  to customers in Canada and the United States
and supply  natural gas to Oil Sands and Sunoco.  Suncor Energy  Marketing  Inc.
also  has a  petrochemical  marketing  division  that  principally  manages  its
participation  in Sun  Petrochemicals  Company,  a  petrochemical  product joint
venture partnership.


                       GENERAL DEVELOPMENT OF THE BUSINESS

OVERVIEW

Suncor  is a  Canada-based  integrated  energy  company.  Suncor  explores  for,
acquires,  develops,  produces,  and markets crude oil and natural gas,  refines
crude oil and markets petroleum and petrochemical products.

Suncor has three principal  operating business units. Oil Sands, based near Fort
McMurray,  Alberta,  produces  sweet and sour crude oil,  diesel fuel and custom
blended  feedstocks.  Natural Gas ("NG") (formerly  Exploration and Production),
based in Calgary, Alberta, explores for, acquires, develops and produces natural
gas.  Sunoco,  headquartered in Toronto,  Ontario,  refines crude oil, markets a
broad range of  petroleum  products,  mostly in Ontario,  markets  petrochemical
products in the United States and Europe, and markets natural gas to residential
and commercial customers in Ontario.

                                                                              1

<PAGE>


While it provides hydrocarbon-based  resources for the immediate energy needs of
consumers,  Suncor also pursues the development of low-emission  and no-emission
energy sources that have a reduced  environmental impact. Suncor announced plans
to place its renewable  energy  projects under the management of NG beginning in
2002.  While NG will manage these  projects,  segmented  financial  data will be
reported  under the results for the  "Corporate"  segment in Suncor's  financial
reporting.

In 2001,  Suncor produced  approximately  127,100 barrels per day (bpd) of crude
oil and natural gas liquids  (approximately 6% of Canada's crude oil production)
and 177  million  cubic feet per day of natural  gas.  In 2000,  the most recent
period  with  published  results,  Suncor  was the third  largest  crude oil and
natural gas  liquids  producer  and the 26th  largest  natural  gas  producer in
Canada.

In 2001,  Suncor  sold  approximately  93,400 bpd (14,800 m3 per day) of refined
products,  mainly in Ontario but also in the United States and Europe.  Suncor's
refined  product  sales in Ontario  represented  approximately  18% of Ontario's
total refined product sales in 2001.

THREE-YEAR HIGHLIGHTS

OIL SANDS

In  April  1999,  following  approval  from  Suncor's  Board  of  Directors  and
regulatory authorities,  Suncor commenced construction of Project Millennium, an
expansion of its Oil Sands plant near Ft. McMurray, Alberta. Through an expanded
mine,  additional  mining  equipment,  increased  energy  services  support  and
twinning of the bitumen extraction and upgrading process, Project Millennium was
ultimately  designed to increase production capacity of the plant to 225,000 bpd
by 2002.

Project  Millennium  was  completed  in  2001 at a  final  capital  cost of $3.4
billion,  up from the original  estimate of $2 billion.  The increase in project
costs over both the original,  and subsequent interim  estimates,  was primarily
attributable to rising labour, fabrication and material costs and a $150 million
change in the project's  scope.  The  additional  capital costs were financed by
internally generated cash flow and additional borrowing.

In October 1999,  pursuant to an agreement  entered into with  TransAlta  Energy
Corporation  ("TransAlta"),  TransAlta  assumed the role of operator of Suncor's
existing Oil Sands energy  services  plant.  Also in 1999,  TransAlta  commenced
construction  of a $315  million  co-generation  facility at Suncor's  Oil Sands
plant  site.  Fully  operational  in 2001,  this  TransAlta  owned and  operated
facility is meeting a portion of Oil Sands'  electricity and steam  requirements
as well as supplying electricity to the Alberta power grid.

In  early  2000,  Suncor  announced  a plan to  further  expand  its  Oil  Sands
operations  beyond  Project  Millennium and in 2001 Suncor  received  regulatory
approval to proceed with  development of the Firebag  In-situ Oil Sands Project.
Combined with the construction of an associated  vacuum tower at the site of its
plant,  the first stage of Firebag is designed to add 35,000  barrels per day of
bitumen production at an estimated cost of $1 billion. The current cost estimate
is up from the original estimate of $750 million.  Firebag  construction,  which
commenced  in 2001,  is  expected  to  continue  through to 2005 when  Suncor is
targeting to achieve a total Oil Sands production capacity of 260,000 bpd. Three
additional  stages of  development  of the Firebag  leases,  which have received
regulatory approval, have the potential to increase production from these leases
to a total of  140,000  barrels  of  bitumen  per day by the end of the  decade.
Approval from Suncor's Board of Directors is required before construction beyond
the first stage can begin.

In 2001,  Suncor also announced  plans for Voyageur,  a phased  expansion of the
Company's oil sands mining and in-situ  operations  and related  extraction  and
upgrading facilities. Management believes Voyageur has the potential to increase
production capacity at Oil Sands to 500,000 to 550,000 bpd in 2010 to 2012.

Suncor plans to develop  Voyageur in phases with  engineering,  construction and
production  plans  for  each  phase  to be  aligned  with  long  term  marketing
strategies.  In 2002,  Suncor  plans to  undertake a


                                                                              2

<PAGE>


comprehensive stakeholder consultation program and integrate recommendations, as
appropriate,  into  engineering,  design and project  development  for Voyageur.
Preliminary  cost  estimates  for  Voyageur are expected to be available in late
2002. Development of Voyageur requires approval of regulators and Suncor's Board
of Directors,  as well as favourable fiscal and market  conditions,  among other
things.

In 2001, Suncor commenced a crude oil brokerage business to generate  additional
income by buying  and  selling  crude oil  production  of other  companies.  The
activity  conducted by this  business did not have a  significant  impact on the
Company's earnings or cash flow in 2001.

NATURAL GAS (NG)

In April 2000,  Suncor's  Board of  Directors  approved a  repositioning  of the
Exploration and Production business and renamed it Natural Gas ("NG") to reflect
the  sharpened  focus on natural gas  production  to meet growing  demand,  both
internally and externally.


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.

NG's goal is to achieve a return on average  capital  employed (see Glossary) of
at least 12% in 2002 and at least 15% in 2004 at  mid-cycle  natural  gas prices
(U.S. $3.00 to $3.50/mcf price range).  Management will work toward this goal by
building  existing  operating  areas and  developing  new production and revenue
streams.  Achievement  of this goal  cannot  be  assured.  See  "Forward-looking
statements" at the beginning of this AIF.

SUNOCO

In 2001,  Sunoco entered into an energy supply  agreement with TransAlta.  Under
the agreement, steam from the TransAlta Sarnia Regional Co-generation Project, a
multi-user cogeneration project in Sarnia, Ontario, will be supplied to Sunoco's
Sarnia Refinery. The agreement is expected to help mitigate Sunoco's exposure to
increases  in  energy  costs  and  supply  steam  to the  Sarnia  Refinery  at a
competitive  cost, while  eliminating the need for Sunoco to build its own steam
generating  boilers.  According  to  TransAlta,  the new facility is expected to
commence  operation in the fourth  quarter of 2002.  Under this  agreement  with
TransAlta, Sunoco has the right to take a portion of the electricity output from
the TransAlta Sarnia Regional  Co-generation  Project.  If Sunoco exercised this
right prior to startup of the new facility, the electricity  requirements of the
Sarnia  Refinery  would also be supplied  under the  agreement  with  TransAlta.
Sunoco had entered into a conditional  fixed-rate  electricity  supply  contract
with a third  party in 2000 to  lock-in  costs on a portion  of its  electricity
requirements for three years following  deregulation of the Ontario  electricity
market.  However,  due to the delay in  deregulation,  this contract  terminated
automatically  in  accordance  with its  terms.  Sunoco  continues  to  evaluate
available options with respect to long-term  electricity  supply and no decision
has been  taken by Sunoco to date with  respect  to the  exercise  of its option
under the TransAlta contract.

Federal  legislation  passed in 1999 mandates  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.  Sunoco  finalized an investment plan in 2001 to meet
the sulphur content limits.  Capital required to achieve  compliance is expected
to  be   approximately   $40   million,   which   includes  the  addition  of  a
desulphurization unit. Construction of the unit is planned for 2002 and 2003.

In 2001,  Sunoco  completed a  strategic  assessment  of its retail  natural gas
marketing business.  Sunoco is currently exploring  alternatives with respect to
the  business,  including  a  possible  disposition,   joint  venture  or  other
transaction involving such business.


                                                                              3

<PAGE>

OTHER

FINANCING ACTIVITIES

During 1999, the Company  completed a Canadian offering of $276 million of 9.05%
preferred  securities  and a U.S.  offering  of  U.S.$162.5  million  of  9.125%
preferred securities,  the proceeds of which totaled Canadian $507 million after
issue costs of $17 million ($10 million after income tax credits of $7 million).
The preferred  securities are unsecured junior subordinated debt of the Company,
due in 2048 and  redeemable at the Company's  option on or after March 15, 2004.
See "Dividend Policy and Record."

During 2000, the Company put in place a borrowing facility for $500 million that
is fully  revolving  for 364 days and was  scheduled to expire in 2001.  In 2001
this facility was extended to June 2002 and increased to $550 million.

In 2001 Suncor issued $500 million of Series 2 Medium Term Notes with a ten year
maturity. The notes have a coupon of 6.7% and will yield 6.74%.

In January  2002,  Suncor  issued U.S.  $500 million  principal  amount of 7.15%
unsecured  notes due February 1, 2032,  to  investors in the United  States (the
"U.S.").  The notes were sold at a price of 99.595% per note to yield  7.183% to
maturity.  The sale of the notes  was  under  Suncor's  shelf  prospectus  dated
January 10, 2002,  which allows for the issuance of debt  securities  and common
shares in an  aggregate  principal  amount  of up to U.S.  $1  billion.  Also in
January 2002,  Suncor filed a base 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.  To date,  no notes have been issued
under this prospectus.

SALE OF STUART OIL SHALE PROJECT

In April 2001,  Sunoco sold its interest in the Stuart Oil Shale  Project to its
Australian joint venture  co-owners,  Southern Pacific  Petroleum NL ("SPP") and
Central Pacific Minerals NL ("CPM")  (together,  "SPP/CPM").  The first stage of
the Queensland, Australia project, originally announced by Suncor and SPP/CPM in
1997,  was  designed as a 4,500 barrel per day  demonstration  plant to test the
commercial viability of producing crude oil from oil shale.  Construction of the
demonstration   plant  was  completed  and  commissioning   commenced  in  1999.
Operational  issues were  experienced  during  commissioning,  including  issues
relating to plant reliability,  noise, odours and the discovery of low levels of
dioxin and other  emissions.  In the third quarter of 2000,  Suncor  recorded an
after-tax write-down of $80 million,  reflecting increased costs and delayed oil
production,  and  thereafter,  all  future  expenditures  on  the  Project  were
expensed.  Suncor's investment in the Project up to the date of sale,  excluding
$4  million  invested  by Suncor in  partially  paid  SPP/CPM  shares  that were
cancelled as part of the sale transaction,  and $5 million in shares acquired in
2001, as discussed below, was approximately $275 million.

Under the terms of the sale,  Suncor retained a 5% royalty interest in the first
stage of the project,  and SPP/CPM and Suncor retained  worldwide  rights to the
project technology. Suncor made total payments as part of the transaction in the
amount of Aus$7 million  (approximately Cdn$5 million) for which Sunoco received
2.5 million SPP shares and 0.926 million CPM shares. In addition, SPP/CPM issued
to Suncor 12.5 million SPP share options and 4.6 million CPM share options,  and
Suncor  surrendered  the partly  paid  SPP/CPM  restricted  class  shares it had
originally acquired in 1997.

As a result  of the sale an  after-tax  charge to  earnings  of $3  million  was
recorded in the second quarter of 2001. At the end of 2001 Suncor also partially
wrote-down the carrying value of the shares acquired by $3 million.

OTHER HIGHLIGHTS

In  September  1999,   Suncor  was  included  in  the  newly  formed  Dow  Jones
Sustainability  Index,  the world's  first  global  equity  index  tracking  the
performance of 200 leading sustainability-driven companies in 68 industry groups
in 22 countries. Suncor continued to be part of the Sustainability Index in 2000
and 2001.

Suncor  announced  in 2000 plans to invest at least $100 million over five years
to pursue  renewable  energy  opportunities.  As of December  31,  2001,  Suncor
hadexpended  approximately $16 million with the

                                                                              4


<PAGE>

majority of these funds  expended on the  SunBridge  Wind Power  Project in Gull
Lake,  Saskatchewan.  This project is a 50-50  partnership  with  Enbridge  Inc.
("Enbridge"). In 2001, the first electricity was generated from this project.

For  further  information  on the  status of the  ongoing  projects  and  issues
referred to above and other  highlights  of 2001,  refer to "Outlook"  and other
sections of Suncor's MD&A.

                      NARRATIVE DESCRIPTION OF THE BUSINESS

                                    OIL SANDS

Suncor  produces a variety of refinery  feedstocks and diesel fuel by mining the
Athabasca oil sands in northeastern  Alberta and upgrading the bitumen extracted
at its plant near Fort McMurray,  Alberta. The Oil Sands operations,  accounting
for over 99% of Suncor's  conventional  and  synthetic  crude oil  production in
2001,  represents a significant  portion of Suncor's  asset base,  cash flow and
earnings.

OPERATIONS

Suncor's  integrated  Oil Sands  business  involves  four  operations:  a mining
operation  using  trucks  and  shovels  to mine  the oil  sand  ore;  extraction
facilities  to recover the bitumen from the oil sand ore; a heavy oil  upgrading
process,  where  bitumen is  converted  into crude oil  products;  and an energy
services  plant  (operated  by  TransAlta),   which  together  with  TransAlta's
natural-gas fired co-generation plant that commenced operations at the Oil Sands
plant site in 2001,  provides the site with steam and electric  power.  Suncor's
energy  services plant primarily uses petroleum coke, a by-product of the coking
process, as fuel. It also consumes natural gas.

The first step of the open pit mining operation is to remove the overburden with
trucks  and  shovels  to  access  the oil sands - a  mixture  of sand,  clay and
bitumen.  The oil sands ore is  transported  to one of four  sizing  plants by a
fleet of trucks.  The ore is dumped  into  sizers  where it is crushed  and then
transported to the extraction  plant.  On the west bank of the Athabasca  River,
the ore is transported by a conveyor  system that stretches  approximately  five
kilometers.  On the east bank, a slurry of partially processed ore from the mine
is transported by a  hydrotransport  system to the extraction  plant on the west
side of the  river.  Bitumen  is  extracted  from the oil sands with a hot water
process. After the final removal of impurities and minerals, naphtha is added as
diluent  to  facilitate  transportation  to the  upgrading  plant.  Periodically
bitumen is sold rather than being upgraded.  In 2001 approximately  8,500 bpd of
bitumen were sold, representing approximately seven percent of 2001 production.

After  transfer to the upgrading  plant,  the diluted  bitumen is separated into
naphtha and bitumen. The naphtha is recycled to be used again as diluent and the
bitumen is upgraded  through a coking and  distillation  process.  The  upgraded
product,  referred to as sour crude oil, is either sold directly to customers or
is further  upgraded  into sweet crude oil by removing  the sulphur and nitrogen
using a hydrogen treating  process.  Three separate streams of refined crude oil
are  blended  together  according  to  customer  specifications.  Suncor  Energy
Marketing Inc. purchases and ships these product blends by pipeline for sale and
distribution to Suncor's Sarnia, Ontario refinery, as well as other customers in
Canada and the United States.  Oil Sands entered into a  transportation  service
agreement  with a subsidiary  of Enbridge for a term that  commenced in 1999 and
extends to 2028, for pipeline  capacity that allows for the initial  shipment of
60,000 and  increasing to 170,000  barrels per day of sour crude oil and bitumen
from Fort McMurray, Alberta to Hardisty,  Alberta. As the initial shipper on the
pipeline,  Suncor's  tolls  payable  under the  agreement  are subject to annual
adjustments.  The  pipeline is operated by Suncor  Energy  Marketing  Inc.  This
pipeline,  together with Suncor's proprietary oil sands pipeline, is expected to
meet Suncor's  anticipated  crude oil shipping  requirements for expected future
production levels up to 2008.

Suncor  has an  agreement  TransCanada  Pipeline  Ventures  Limited  Partnership
("TCPV"),  to provide  Suncor with firm  capacity on a new natural gas  pipeline
constructed by TCPV. This pipeline came into service in 1999.

                                                                              5


<PAGE>

The  oil  sands  plant  is   susceptible  to  loss  of  production  due  to  the
interdependence of its component  systems.  In 1999 two unplanned outages of the
5C9  fractionator  lasted a total of 16 days and resulted in  approximately  1.8
million  barrels  of lost  production.  Parts of the 5C9 unit that  failed  were
redesigned  during the second  outage in September  1999,  with the objective of
improving  reliability and helping to achieve targeted  production rates. Suncor
shut down the same unit for  maintenance  twice in 2001,  also for a total of 16
days.  It is  estimated  that the lost  production  from these 2001  outages was
approximately  1.8  million  barrels.  Management  will  continue to monitor the
performance of this unit and evaluate  whether further repairs or other remedial
actions are required to address the operational issues.

Through expansion projects like Millennium,  Suncor expects improved operational
flexibility by reducing the cash flow impact of complete  plant-wide  shutdowns.
For example,  Millennium adds a second complete processing operation. This "dual
train" approach  increases  production  capacity and provides the flexibility to
schedule  periodic plant  maintenance on one train while  continuing to generate
production  and cash flow from the other.  Oil Sands base plant (which  excludes
Millennium  facilities) is currently scheduled to undergo a maintenance shutdown
in 2002.  Suncor  plans  to  continue  producing  from  the  Project  Millennium
facilities  during this  scheduled  maintenance.  During these partial  shutdown
maintenance  periods,  work can be done while the rest of the plant continues to
operate.  This  reduces  both the cost and scope of  shutdowns  and  allows  for
continued production of sour crude oil during the shutdown period.

Suncor has also undertaken other work to improve operational  performance.  Over
the past several years,  backup  components and systems have been  introduced in
critical  areas to  improve  reliability.  In  addition  to  ongoing  preventive
maintenance   programs,   full  plant   maintenance   shutdowns   are  completed
approximately  every four years.  In addition  to  complete  shutdowns,  partial
shutdowns in the upgrader are undertaken periodically.

Severe climatic conditions at Oil Sands can cause reduced production and in some
situations result in higher costs.


                                                                              6

<PAGE>


LEASEHOLD INTERESTS AND ROYALTIES

Set out in the table below is a summary of Suncor's oil sands mining and in-situ
leasehold interests as of December 31, 2001.


<TABLE>
<CAPTION>
                                                                                                   Percentage of
                                                                                                  Proved Reserves
                                                                           Number of Gross      (bbl of synthetic
                                                                                Acres          crude oil for mining
                                                          Referred           (Net Acres if      leases / bbl bitumen
      Description              Legal Description            to as             applicable)        for in-situ leases)
- ------------------------     ----------------------     ------------     --------------------- ----------------------
<S>                          <C>                        <C>              <C>                   <C>
MINING LEASES:
- --------------
Mine Expansion:
Leases                            7280100T25                25                   17,644
                                  7279080T19                19                   18,760        Mine Expansion
                                  7597030T11                97                    2,483        Leases and Fee Lots
                                  7280060T23                                     36,954        represent 99%
                                  7498050014                                        243

Fee Lots(1)                            1                    N/A                   1,894        (1)
                                       3                    N/A                   1,967        (1)
                                       4                    N/A                   1,886        (1)

Original Mine                     7387060T04                86                    4,522        Original Mine
Leases                            7279120092                17                    1,619        Leases represent 1%

TOTAL MINING LEASES                                                              87,972

FIREBAG LEASES:
- -------------------
Firebag(2)                        7285100T85                85                   39,594        (1)
                                  7097110062                N/A                   7,040        (1)
                                  7097110063                N/A                   5,760        (1)
                                  7097110064                N/A                   4,800        (1)
                                  7097120065                N/A                  13,440        (1)
                                  7097120066                N/A                  18,560        (1)
                                  7097120067                N/A                  19,200        (1)
                                  7099120072                N/A                  23,040        (1)
                                  7099120073                N/A                  23,040        (1)
                                  7099120074                N/A                  16,640        (1)
                                  7099120075                N/A                  23,040        (1)
                                  7001100001                N/A                  22,400        (1)
                                  7401100027                N/A                  23,040        (1)
                                  7401100029                N/A                  10,240        (1)
                                  7401100013                N/A                   7,360        (1)

Firebag(2)                        Various(3)              Various                84,480        (1)

TOTAL FIREBAG LEASES                                                            341,674

TOTAL LEASES
                                                                                429,646
</TABLE>


                                                                             7

<PAGE>


Notes:
(1)      No proved reserves are attributable to these leases.

(2)      Leases are principally in-situ.

(3)      Suncor holds a beneficial  interest in 13 leases  totaling 84,480 gross
         and net acres.

The  Government of Alberta is entitled to royalties  under Leases 17, 19, 25, 86
and 97 and the Fee Lots at rates which the Government  establishes  from time to
time.

Under the Alberta Suncor Crown Royalty Agreement, Crown royalties are 25% of net
revenues less allowable costs  (including  capital  expenditures),  subject to a
minimum  payment of 5% of gross  revenues.  In 2001,  the minimum  royalty  rate
changed to 1% of gross revenues. Suncor currently expects to pay Crown royalties
at the minimum 1% rate until 2009, based on assumptions relating to future crude
oil prices,  production  levels,  operating costs and capital  expenditures.  In
2000,  Suncor made Crown  royalty  payments  based upon the 5% minimum  royalty.
Suncor  transitioned  to a generic Oil Sands royalty  agreement with the Alberta
government  in  1999  that  provides  Suncor  with  additional   allowable  cost
deductions  to a maximum  of $158  million  per year for ten years  (related  to
Suncor's original investment in the Oil Sands facility).

Anadarko  Inc. (a  successor  to Norcen  Energy  Resources  Limited) has a gross
overriding royalty on Lease 86 pursuant to an agreement dated March 1, 1989 (the
"Anadarko  Royalty").  The  Anadarko  Royalty  is  based  on a  graduated  scale
dependent on the  synthetic  crude oil price  expressed as a percentage of gross
revenue  from  production  of the lease.  As of  December  31,  2001,  under the
Anadarko  Royalty,  no payment is required if  synthetic  crude prices are below
$20.15 per barrel. Payment of 1.5% of gross revenue is required if the synthetic
crude price ranges from $20.15 to $21.14 per barrel.  For every $1.00 per barrel
increase  in the price of  synthetic  crude in the range of $21.15 to $26.14 per
barrel,  the percentage  rate of the royalty  increases by 0.5%. For every $1.00
per barrel  increase in the price of  synthetic  crude in the range of $26.15 to
$37.14 per barrel,  the  percentage  rate of the royalty  increases by a further
0.25 % until a maximum royalty of 7% is reached.  All synthetic crude prices are
calculated  on a monthly  average  basis and the crude  price  break  points are
adjusted  annually  on  March  1 of  each  year  by a  contractually  determined
inflation component. Suncor currently expects to complete mining on the Anadarko
lease in 2002.

Petro-Canada has a royalty on Lease 19 pursuant to an agreement dated October 6,
1992. The royalty is calculated as 1.5% of net sale proceeds.  Net sale proceeds
are  calculated  based upon a formula by which the sale  proceeds for the period
exceeds the sum of allowed deductions for the period.

The Crown royalty  regime  applicable to the Firebag  in-situ leases will be the
same regime as described for Suncor's oil sands mining  leases  above.  To date,
Suncor  has had no  commercial  production  from this area and none is  expected
until 2004-2005.

ESTIMATED RESERVES

Suncor  estimates its mining leases,  on a combined  basis,  contain proved plus
probable  reserves of synthetic crude oil totaling 2.405 billion  barrels,  with
376 million  barrels  classified as proved.  Its in-situ  leases,  on a combined
basis,  contain  probable  reserves of 2.029 billion barrels of bitumen.  In the
case of Firebag in-situ bitumen reserves,  Suncor has the option of selling this
bitumen production and/or upgrading the bitumen to synthetic crude oil. Suncor's
current  upgrading  operations  have a synthetic  crude oil yield of 80%.  These
estimates are before deduction of Crown and applicable  royalties on the leases.
Under the Crown  Royalty  Agreement the Crown royalty is dependent on deemed net
revenues (Revenue-Cost, or R-C); therefore the calculation of net reserves would
vary depending upon production rates, prices and operating and capital costs.

The mining  reserve  estimates are based upon a detailed  geological  assessment
including  drilling  density


                                                                             8


<PAGE>

and laboratory tests and also consider current production capacity and upgrading
yields, current mine plans, operating life and regulatory constraints.  Based on
these factors,  additional  proved  reserves are anticipated to be recognized as
the mine is further developed. The current proved plus probable reserve estimate
is based on an additional 30 years of operations without further expansion.

Suncor  engaged  Gilbert  Laustsen Jung  Associates  Ltd.  ("GLJ"),  independent
petroleum  engineering  consultants,  to audit  Suncor's  estimate of proved and
probable  reserves of synthetic  crude oil on its mining leases,  as of December
31,  2001.  A  synthetic  crude  oil  yield  of 80%  has  been  utilized  in the
determination of the proved and probable  reserves.  The proved reserves exclude
areas within the current pit designed not drilled up to a density of at least 10
holes per square  kilometer.  The proved plus probable reserves are based upon a
production  forecast  recognizing  30  additional  years  of  mining  operations
(210,000  bpd in 2002 and 220,000 bpd  thereafter).  Suncor is  considering  pit
design changes to the Millennium  mine  associated  with higher  stripping ratio
areas,  permitted  under  operating  criteria  issued by the Alberta  Energy and
Utilities  Board in 2001.  The current  proved plus probable  volumes are now 58
million  barrels higher than current model  estimates which reflect the proposed
changes.  This  difference  in  estimates  corresponds  to  about  9  months  of
anticipated production, and is considered to be within the accuracy of the model
estimates.  The pit designs  will  continue  to be  impacted by both  additional
drilling data and operating experience,  as well as technology  developments and
economic  considerations.  Furthermore,  the  potential  exists to expand mining
operations  north  across the  Steepbank  River,  to develop an ore body not yet
classified as a reserve. In their opinion dated January 16, 2002, GLJ state they
believe  there is at least a 90% and 50%  confidence  the proved and proved plus
probable mining reserves estimates will be exceeded, respectively. Their opinion
is  qualified  to the  extent  that it  assumes  Suncor  will  comply  with  any
amendments that may be made to regulatory approvals.

At  Suncor's  request GLJ has  prepared an  independent  resource  and  economic
analysis of Suncor's Firebag in-situ oil sands project leases. Suncor's geologic
interpretation  of the  leases  was  provided  to  GLJ,  who  reviewed  Suncor's
methodology and  interpretation and then prepared  independent  interpretations.
GLJ's interpretation was based on an analysis of individual well data and 3D and
2D seismic  data  supplied by Suncor.  GLJ based its  interpretation  on current
pricing and  royalty  assumptions.  In  addition,  GLJ  utilized  estimates  and
assumptions for factors such as recovery efficiencies and operating costs, based
on GLJ's  experience  with  similar  projects.  Cost and  construction  schedule
estimates were supplied by Suncor.

Based upon the work  conducted by GLJ as described  above,  GLJ  estimates  that
there are 9.6 billion barrels of bitumen resources on the Firebag leases,  which
includes a total 2.029 billion  barrels that are probable  nonproducing  bitumen
working interest reserves within the project approved area.

Suncor continues to conduct its evaluation  program in the Firebag area in 2002,
utilizing  a  combination  of seismic and  corehole  drilling.  This  process is
expected to be ongoing over a number of years. The program is intended to assist
Suncor in evaluating the potential  bitumen resources in order satisfy oil sands
lease tenure  regulations,  obtain  sufficient  geological  data to quantify the
resources on the leases, and gain a more detailed  understanding of the resource
to facilitate future design and layout of production wells.

To  date  Suncor  has  drilled   approximately   300   coreholes   and  acquired
approximately  400 miles of  seismic  data in the  Firebag  area.  Programs  are
conducted annually to gain the information needed to guide resource development.


                                                                             9


<PAGE>

RESERVES RECONCILIATION

The following  table sets out a  reconciliation  of Suncor's proved and probable
reserves of synthetic  crude oil and bitumen from  December 31, 2000 to December
31, 2001,  based on reports issued by GLJ as described above (the "GLJ Oil Sands
Reports").

<TABLE>
<CAPTION>
                                                            Mining Reserves(2)                  Insitu Firebag(3)
                                                            ------------------                  -----------------      Total Mining
                                                 (millions of barrels of synthetic crude     (millions of barrels of    and In-Situ
                                                                   oil)                              bitumen)
                                                                                                                         Proved and
                                                    Proved           Probable       Total            Probable              Probable
                                                  --------           --------       -----            --------            -----------
                   <S>                            <C>                <C>            <C>              <C>                 <C>

                   December 31, 2000..........        422             2,034         2,456               -                   2,456
                   Revisions(1)...............        (1)              (5)           (6)                -                    (6)
                   Additions..................         -                -             -               2,029                 2,029
                   Production.................       (45)               -           (45)                -                    (45)
                                                     ----               -           ----                -                    ----
                   December 31, 2001..........        376             2,029         2,405             2,029                 4,434

</TABLE>

Note:

(1)      Revisions  relate to  drilling  activity,  revisions  to the pit design
         based upon both  geotechnical  and  economic  data  related to the Mine
         Expansion leases (see the table under the heading "Leasehold  Interests
         and Royalties") and operational issues.
(2)      Synthetic crude oil reserves based upon a net coker, or synthetic crude
         oil yield of 80%.
(3)      Suncor has the option of selling the bitumen production from these
         leases and/or upgrading the bitumen to synthetic crude oil.

REVENUES FROM SYNTHETIC CRUDE OIL AND DIESEL

Although  revenues after royalties per barrel are higher for synthetic crude oil
than for conventional  crude oil, operating costs to produce synthetic crude oil
are higher than lifting and administrative  costs to produce  conventional crude
oil from the Western Canada  Sedimentary  Basin.  While there is no finding cost
associated  with  synthetic  crude  oil,  mine   development  and  expansion  of
production can entail  significant  outlays of funds.  The costs associated with
synthetic  crude oil  production are largely fixed for the same reason and, as a
result, operating costs per unit are largely dependent on levels of production.

Aside from onsite fuel use, all of Oil Sands production is sold to Suncor Energy
Marketing  Inc., a wholly  owned  subsidiary  of Sunoco,  which then markets the
production.

In 1997, Suncor and Shell Canada ("Shell") renewed a purchase  agreement whereby
Shell  agreed  to  purchase  and  receive   approximately  95,000  cubic  metres
(approximately  600,000  barrels) of sweet  synthetic  crude oil per month.  The
original term of the agreement was to December 31, 1997,  with 60-day  evergreen
terms thereafter.  The price received is based on a formula  involving  postings
for sweet  crude oil.  With  Millennium  start-up,  Suncor also  entered  into a
one-year agreement  effective January 1, 2002 to sell an additional 28,600 cubic
meters (180,000 barrels) per month to Shell under the same pricing terms.

In 1997  Suncor  entered  into a  long-term  agreement  with  Koch Oil Co.  Ltd.
("Koch") to supply Koch with up to 30,000 barrels per day  (approximately 26% of
Suncor's  average 2001 total  production)  of sour crude from Suncor's Oil Sands
operation. Suncor began shipping the crude to Koch's refinery in Minnesota under
this  long-term  agreement  effective  January 1, 1999.  The initial term of the
agreement  extends  to January 1,  2009,  with  month to month  evergreen  terms
thereafter, subject to termination after January 1, 2004, on twenty-four months'
notice.  In 2000,  Suncor  announced a long term sales  agreement with Consumers
Co-operative  Refineries  Limited  ("CCRL")  under which Suncor expects to begin
supplying CCRL with 20,000 barrels per day of sour crude oil production from its
Project Millennium  expansion facilities by late 2002. Prices for sour crude oil
under these agreements are set at agreed differentials to market benchmarks.  In
2001,  Suncor announced a long-term  agreement with Petro-


                                                                             10
<PAGE>


Canada to  supply up to 30,000  barrels  per day of  diluent  to dilute  bitumen
produced by Petro-Canada.  The contract is expected to commence in 2002 and is a
four year agreement that will be extended unless terminated by either party.

In 2001,  Koch was the only  customer that  represented  10% or more of Suncor's
consolidated  revenues,  while there were two such  customers in 2000,  Koch and
Shell.

A portion of Oil Sands  production  is used in connection  with Suncor's  Sarnia
refining  operations.  During 2001, the Sarnia refinery processed  approximately
14% (2000 -- 25%) of Oil Sands crude oil production.

The following  table sets forth the average  sales price  received per barrel of
synthetic  crude oil from Oil Sands on a quarterly  basis for the years 2001 and
2000, after the impact of hedging activities.

<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
                                       2001                                               2000
                 ------------------------------------------------  -------------------------------------------------


- --------------------------------------------------------------------------------------------------------------------
     $/bbl          4Q          3Q           2Q           1Q           4Q           3Q           2Q           1Q
     -----          --          --           --           --           --           --           --           --
 <S>               <C>         <C>          <C>          <C>          <C>          <C>          <C>          <C>
 Average sales     24.43       31.43        31.40        30.85        31.33        32.39        31.12        31.84
     price
- --------------------------------------------------------------------------------------------------------------------
</TABLE>


CAPITAL EXPENDITURES

Capital spending at Oil Sands is expected to total approximately $600 million in
2002,  $420  million  with  respect to the in-situ  phase of Suncor's  Oil Sands
development  and  expansion  of the  upgrading  facilities  and $180  million in
capital investments for the current facility.  Capital expenditures in 2001 were
approximately $1.5 billion.

Suncor's in-situ spending of $420 million in 2002 is part of $1 billion in total
spending on in-situ projects planned for the period 2002 to 2005.

The following table sets out, for the quarters indicated,  capital  expenditures
by Suncor's Oil Sands business unit:

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
                                                        2001                                     2000
- -----------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES BY QUARTER           4Q        3Q        2Q        1Q         4Q        3Q        2Q        1Q
                                          --        --        --        --         --        --        --        --
<S>                                      <C>       <C>       <C>        <C>       <C>       <C>       <C>       <C>
- -----------------------------------------------------------------------------------------------------------------------
Property acquisitions                     4         -         -          9         13        4         -         -
- -----------------------------------------------------------------------------------------------------------------------
Drilling activity                         4         -         4         14         1         -         -         -
- -----------------------------------------------------------------------------------------------------------------------
Capital Additions to Facilities (1)      305       384       392        363       466       363       552       409
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>


Note:

(1)     Includes capital spending on Project Millennium, Firebag Oil Sands
        Projects, acquisition of mining equipment, and other capital spending


                                                                             11

<PAGE>

ENVIRONMENTAL COMPLIANCE

For a description of the impact of environmental  protection requirements on Oil
Sands,  refer  to  "Environmental  Risks"  and  "Government  Regulation"  in the
"Risk/Success Factors" section of this AIF.


                                   NATURAL GAS

Suncor's Natural Gas business, based in Calgary, Alberta, explores for, develops
and produces conventional natural gas in western Canada, supplying it to markets
throughout North America.  The sale of NG production  provides an internal hedge
for natural gas  consumption  at Suncor's  Oil Sands and Sunoco  businesses.  In
addition, Suncor's U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., is
acquiring land and exploring for coal bed methane in the United States.

In April 2000,  Suncor's  Board of  Directors  approved a  repositioning  of the
Exploration  and  Production  business  and  renamed it Natural Gas to reflect a
sharpened  focus on natural  gas  production.  The  repositioning  entailed  the
consolidation of production in three core natural gas areas, and a restructuring
of business processes to support the new focus.

During  2000,   NG  targeted  its  natural  gas  focus  in  Western   Canada  by
concentrating  on natural gas  prospects  and selling  most of its  conventional
crude  oil  properties.  Exiting  2001,  natural  gas and  natural  gas  liquids
accounted for approximately 94% of the NG business unit's production.

Suncor's  exploration  program is focused on multiple  geological zones in three
core asset areas:  Northern  (northeast British Columbia and northwest Alberta),
Foothills  (western  Alberta and portions of  northeast  British  Columbia)  and
Central  Alberta.  Suncor drills primarily medium to high-risk wells focusing on
prospects that can be connected to existing infrastructure.

An in-house natural gas marketing group sells Suncor's  proprietary  natural gas
and natural gas acquired from other producers.  During 1997, Suncor entered into
a five-year  agreement  with Enron  Capital  and Trade  Resources  Canada  Corp.
("ECT") for ECT to provide  operational  and  administrative  services to Suncor
related to its natural gas portfolio. This agreement was terminated without cost
to Suncor in  December  2001.  ECT  continues  to provide  natural  gas  related
operational and administrative services to Suncor under a short-term agreement.

RESERVES AND RESERVES RECONCILIATION

GLJ  reported  January 29,  2002,  on  Suncor's  estimated  proved and  probable
reserves of natural gas,  natural gas liquids and crude oil (other than reserves
from Suncor's  mining leases and the Firebag in-situ  reserves),  as of December
31, 2001.  Information  with respect to these  reserves is set out in the tables
below and in the tables under the  headings  "Crude Oil and Natural Gas Liquids"
and "Natural  Gas" (the  "Reserves  Tables").  GLJ's  determination  of Suncor's
estimated  proved and probable  recoverable  reserves are based on constant year
end prices and costs  determined  as of the dates  indicated  with no escalation
into the  future.  The  accuracy  of any  reserve  estimate is a function of the
quality and quantity of available  data and of  engineering  interpretation  and
judgment.  While  reserve and  production  estimates  presented  are  considered
reasonable, the estimates should be viewed with the understanding that reservoir
performance subsequent to the date of the estimate may justify revision,  either
upward or downward.

IN THE RESERVES TABLES:

(1)      Proved  reserves  and  probable  reserves  have the  meanings  set out
         in the  Glossary  of Terms at the front of this  Annual Information
         Form.  All proved and probable reserves are in Canada.

(2)      Proved  developed  reserves are on production,  or reserves that could
         be recovered from existing wells or facilities,  if the Company placed
         them on production.


                                                                             12

<PAGE>


(3)      Gross reserves represent the aggregate of Suncor's undivided percentage
         interest in reserves  including the royalty interest of governments and
         others in such  reserves and Suncor's  royalty  interest in reserves of
         others.  Net reserves  are gross  reserves  less that royalty  interest
         share of others  including  governments.  Royalties can vary  depending
         upon  selling  prices,   production  volumes,  and  timing  of  initial
         production  and  changes  in   legislation.   Net  reserves  have  been
         calculated  following  generally accepted  guidelines,  on the basis of
         prices and the royalty  structure in effect at year-end and anticipated
         production  rates.  Such estimates by their very nature are inexact and
         subject to constant revision.

The following tables set out a reconciliation  of NG's estimated proved reserves
from December 31, 2000 to December 31, 2001.


                   ESTIMATED PROVED RESERVES RECONCILIATION(1)

<TABLE>
<CAPTION>
                                                             GROSS                                          NET
                                                             -----                                          ---
                                             CRUDE OIL AND                                 CRUDE OIL AND
                                          NATURAL GAS LIQUIDS         NATURAL GAS        NATURAL GAS LIQUIDS         NATURAL GAS
                                         --------------------     -------------------   --------------------    -------------------
       <S>                               <C>                      <C>                   <C>                     <C>
                                         (MILLIONS OF BARRELS)    (BILLIONS OF CUBIC    (MILLIONS OF BARRELS)   (BILLIONS OF CUBIC
                                                                         FEET)                                         FEET)

       December 31, 2000...............          16(1)                    797                     11                     567
       Revisions of previous estimates.            (1)                     (3)                     -                       4
       Extension and discoveries.......             -                      27                      -                      20
       Production......................            (1)                    (65)                    (1)                    (45)
       Sales of minerals in place......             -                      (1)                     -                      (1)
                                                 -------                 ------                 ------                 -------
       December 31, 2001...............          14(1)                    755                     10                     545
                                                 =======                 ======                 ======                 =======
</TABLE>

Note:

(1)      Includes 8.6 million barrels of natural gas liquids as at December 31,
         2001 (9.2 million barrels as at December 31, 2000).

Estimated  proved reserves are comprised of developed and undeveloped  reserves.
The following tables show the breakdown between these categories.


               ESTIMATED PROVED DEVELOPED RESERVES RECONCILIATION

<TABLE>
<CAPTION>
                                                             GROSS                                          NET
                                                             -----                                          ---
                                             CRUDE OIL AND                                 CRUDE OIL AND
                                          NATURAL GAS LIQUIDS         NATURAL GAS        NATURAL GAS LIQUIDS         NATURAL GAS
                                         --------------------     -------------------   --------------------    -------------------
       <S>                               <C>                      <C>                   <C>                     <C>
                                         (MILLIONS OF BARRELS)    (BILLIONS OF CUBIC    (MILLIONS OF BARRELS)   (BILLIONS OF CUBIC
                                                                         FEET)                                         FEET)

         December 31, 2000...............           13                     573                     9                    409
         Revisions of previous estimates.           (1)                     31                     -                     27
         Extension and discoveries.......            -                      34                     -                     25
         Production......................           (1)                    (65)                   (1)                   (45)
         Sales of minerals in place......            -                       -                     -                      -
                                                  -------                --------               -------                ------
         December 31, 2001...............           11                     573                     8                    416
                                                  =======                ========               =======                ======
</TABLE>


                                                                             13

<PAGE>


              ESTIMATED PROVED UNDEVELOPED RESERVES RECONCILIATION

<TABLE>
<CAPTION>
                                                             GROSS                                          NET
                                                             -----                                          ---
                                             CRUDE OIL AND                                 CRUDE OIL AND
                                          NATURAL GAS LIQUIDS         NATURAL GAS        NATURAL GAS LIQUIDS         NATURAL GAS
                                         --------------------     -------------------   --------------------    -------------------
       <S>                               <C>                      <C>                   <C>                     <C>
                                         (MILLIONS OF BARRELS)    (BILLIONS OF CUBIC    (MILLIONS OF BARRELS)   (BILLIONS OF CUBIC
                                                                         FEET)                                         FEET)

       December 31, 2000................            3                     224                     2                    158
       Revisions of previous estimates..            -                    (34)                     -                    (23)
       Extension and discoveries........            -                     (7)                     -                    (5)
       Sales of minerals in place.......            -                     (1)                     -                    (1)
                                                  -----                 -----                   -----                 -----
       December 31, 2001................            3                    182                      2                    129
                                                  =====                 =====                   =====                 =====
</TABLE>

The  following  table  sets  out a  reconciliation  of NG's  estimated  probable
reserves from December 31, 2000 to December 31, 2001.


                   ESTIMATED PROBABLE RESERVES RECONCILIATION

<TABLE>
<CAPTION>
                                                             GROSS                                          NET
                                                             -----                                          ---
                                             CRUDE OIL AND                                 CRUDE OIL AND
                                          NATURAL GAS LIQUIDS         NATURAL GAS        NATURAL GAS LIQUIDS         NATURAL GAS
                                         --------------------     -------------------   --------------------    -------------------
       <S>                               <C>                      <C>                   <C>                     <C>
                                         (MILLIONS OF BARRELS)    (BILLIONS OF CUBIC    (MILLIONS OF BARRELS)   (BILLIONS OF CUBIC
                                                                         FEET)                                         FEET)

       December 31, 2000................            7                      304                   5                      217
       Revisions of previous estimates..           (1)                     (80)                  -                      (57)
       Purchases of minerals in place...            -                        -                   -                        -
       Extension and discoveries........            -                       16                   -                       11
       Sales of minerals in place.......            -                       (3)                  -                       (2)
       December 31, 2001................            6                      237                   5                      169
                                                  =====                   ======               =====                  =======
</TABLE>

CONVENTIONAL CRUDE OIL

The  following  table shows  estimates of NG's proved crude oil reserves  before
royalties as prepared by GLJ (see  "Reserves and Reserves  Reconciliation")  and
Suncor's average daily production of crude oil before royalties,  in Alberta and
British  Columbia,  represented by the  conventional  fields  identified in this
table.

                                                                             14

<PAGE>

<TABLE>
<CAPTION>

                                                                         PROVED RESERVES                     2001 AVERAGE
                                                                       BEFORE ROYALTIES AT                 DAILY PRODUCTION
                                                                       DECEMBER 31, 2001(1)               BEFORE ROYALTIES(3)
                                                                       --------------------               -------------------

                                                                  (MILLIONS OF                       (BARRELS OF
                            FIELDS                                  BARRELS)             %           OIL PER DAY)           %
                 ---------------------------
                 <S>                                              <C>                  <C>           <C>                 <C>
                 Simonette..............................               2.3              47               647               44
                 Blueberry..............................               1.8              37               374               25
                 McKinley...............................               0.2               4               120                8
                 Bonanza................................               0.2               4                61                4
                 Rosevear...............................               0.1               2               133                9
                 Boundary Lake..........................               0.1               2                25                2
                 Other(2)...............................               0.3               4               110                8
                                                                       ---             ---            ------              ---
                 Total-- gross..........................                 5             100             1,470              100
                                                                       ===             ===            ======              ===
</TABLE>


Notes:

(1) The  reserves  and  production  in this  table do not  include  natural  gas
    liquids.

(2) Includes fields in which Suncor holds overriding royalty interests.

(3) Production in 2001 was materially different from 2000 due to strategic
    divestments.

Most of the large  conventional oil fields in the western provinces have been in
production  for a number of years and the rate of  production in these fields is
subject to natural decline.  In some cases,  additional amounts of crude oil can
be recovered by using various  methods of enhanced  crude oil  recovery,  infill
drilling  and  production   optimization   techniques.   At  the  end  of  2001,
approximately  90% of  Suncor's  proved  conventional  oil  reserves  were under
enhanced oil recovery programs.


                                                                             15


<PAGE>

NATURAL GAS LIQUIDS

The following table shows estimates of NG's proved natural gas liquids  reserves
before royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation")
and Suncor's average daily  production of natural gas liquids before  royalties,
in  Alberta  and  British  Columbia,  represented  by  the  conventional  fields
identified in this table.


<TABLE>
<CAPTION>

                                                                         PROVED RESERVES                     2001 AVERAGE
                                                                       BEFORE ROYALTIES AT                 DAILY PRODUCTION
                                                                        DECEMBER 31, 2001                   BEFORE ROYALTIES
                                                                       --------------------               -------------------

                                                                  (MILLIONS OF                       (BARRELS OF
                            FIELDS                                  BARRELS)             %           OIL PER DAY)           %
                 ---------------------------
                 <S>                                              <C>                  <C>           <C>                 <C>
                 Simonette...............................              2.0               23              502               21
                 Grande Prairie..........................              1.4               16              183                8
                 Knopcik.................................              1.2               14              389               16
                 Pine Creek..............................              0.8                9              247               10
                 Glacier.................................              0.5                6               94                4
                 Stolberg................................              0.5                6               49                2
                 Blueberry...............................              0.5                6              164                7
                 Rosevear................................              0.4                5              227               10
                 Blackstone..............................              0.3                4               68                3
                 Phoenix.................................              0.2                2               36                2
                 George..................................              0.1                1              175                7
                 Hinton..................................              0.1                1               53                2
                 Mountain Park...........................              0.1                1               18                1
                 Boundary Lake...........................              0.1                1               23                1
                 Other(1)................................              0.8                5              141                6
                                                                       ---              ---            ------             ---

                 Total-- gross...........................                9              100            2,369              100
                                                                       ===              ===            ======             ===
</TABLE>


Note:

(1) Includes fields in which Suncor holds overriding royalty interests.



                                                                             16

<PAGE>


NATURAL GAS

The following table shows estimates of NG's proved natural gas reserves,  before
royalties,  as prepared by GLJ (see "Reserves and Reserves  Reconciliation") and
Suncor's  average daily production of natural gas before  royalties,  in Alberta
and British Columbia,  represented by the major natural gas fields identified in
the table.

<TABLE>
<CAPTION>
                                                                         PROVED RESERVES                     2001 AVERAGE
                                                                       BEFORE ROYALTIES AT                 DAILY PRODUCTION
                                                                        DECEMBER 31, 2001                   BEFORE ROYALTIES
                                                                       --------------------               -------------------

                                                                  (MILLIONS OF                       (BARRELS OF
                            FIELDS                                  BARRELS)             %           OIL PER DAY)          %
                 ---------------------------
                 <S>                                              <C>                  <C>           <C>                 <C>
                 Stolberg...............................              216               29                22               12
                 Blackstone/Brown Creek.................               79               11                21               12
                 Grande Prairie area....................               59                8                 7                4
                 Mountain Park..........................               52                7                11                6
                 Knopcik area...........................               50                7                16                9
                 Glacier................................               49                6                 8                5
                 Simonette..............................               40                5                 9                5
                 Rosevear...............................               39                5                21               12
                 Blueberry..............................               38                5                11                6
                 Sinclair...............................               20                3                 7                4
                 Pine Creek.............................               18                2                 6                3
                 Cutbank................................               16                2                12                7
                 Other(1)...............................               79               10                26               15
                                                                      ---              ---               ---              ---
                 Total-- Gross..........................              755              100               177              100
                                                                      ===              ===               ===              ===
</TABLE>


Note:

(1) Includes fields in which Suncor holds overriding royalty interests.

LAND HOLDINGS

The following table sets out the undeveloped and developed lands in which the NG
business  unit held  crude oil and  natural  gas  interests  at the end of 2001.
Undeveloped  lands are lands  within  their  primary term upon which no well has
been drilled.  Developed lands are lands past their primary term or upon which a
well has been drilled.

The petroleum and natural gas interests  include Suncor's  undivided  percentage
interest in leases,  licenses,  reservations,  permits or exploration agreements
(collectively,  the "Agreements"). In general, Agreements confer upon the lessee
the right to explore  for and remove  crude oil and  natural gas from the lands,
with the lessee paying  exploration  and  development  costs,  operating  costs,
abandonment costs and reclamation  costs,  subject to paying rentals,  taxes and
royalties.  Interests in Agreements (excluding freehold agreements) are acquired
from the federal or provincial  governments  through  competitive  bidding or by
undertaking  work  commitments,  or by joint  venture  agreements  with industry
companies.


                                                                             17

<PAGE>

<TABLE>
<CAPTION>
                                                        UNDEVELOPED ACRES
                                                        -----------------
                                                 GROSS ACRES(1)       NET ACRES(1)
                                                 --------------       ------------
<S>                                              <C>                  <C>
                                                           (THOUSANDS)
CANADA
      Western provinces                                627                508

INTERNATIONAL                                         1,685              1,227
                                                      =====              =====

Total Undeveloped Landholdings                        2,312              1,735
                                                      =====              =====

Note:

(1)      "Gross  Acres"  means all of the acres in which  Suncor  has  either an
         entire or undivided  percentage interest in. "Net Acres" represents the
         acres remaining after deducting the undivided  percentage  interests of
         others from the gross acres.

DRILLING

The following  table sets forth the gross and net  exploratory  and  development
wells, in Western Canada, the United States and Australia, which were completed,
capped or abandoned in which Suncor participated during the years indicated.


                                                                                            YEAR ENDED DECEMBER 31,
                                                                                            -----------------------
                                                                                      2001                         2000
                                                                                      ----                         ----
                                                                              GROSS          NET           GROSS            NET
                                                                              -----          ---           -----            ---
                <S>                                                           <C>            <C>           <C>             <C>

                Exploratory Wells
                     Crude oil............................                       -             -              -              -
                     Gas..................................                       5             4              3              1
                     Dry (1)..............................                      22            16             17             15
                Total Exploratory Wells...................                      27            20             20             16
                                                                               ----          ----           ----           ----
                Development Wells
                     Crude oil............................                       1             -              5              2
                     Gas..................................                      24            16             23             14
                     Dry..................................                       4             2              4              3
                                                                                 -             -              -              -
                Total Development Wells ..................                      29            18             32             19
                                                                               ----          ----           ----           ----
                Total.....................................                      56            38             52             35
                                                                               ====          ====           ====           ====
</TABLE>


NOTE:

(1) Includes 18 gross (14 net) coal bed methane wells in 2001.

Not  included  are earning  wells  completed by other  companies  under  farmout
agreements  relating  to lands  in  which  Suncor  has an  undivided  percentage
interest,  since Suncor did not incur cash  expenditures in connection with such
wells. In addition to the above wells, Suncor had interests in 27 gross (14 net)
exploratory  wells in progress  and 12 gross  (seven net)  development  wells in
progress at the end of 2001.

Suncor continues to hold interests in frontier  properties (Arctic and Northwest
Territories) including 28 long-term "significant discovery licences".


                                                                             18

<PAGE>




WELLS

The  following  table  summarizes  the wells in which the NG business unit has a
working interest or a royalty interest as at December 31, 2001.

<TABLE>
<CAPTION>

                                                                                   Producing                   Non-Producing
                                                                                  Wells(1)(2)                   Wells(1)(3)
                                                                                  -----------                  -------------
                                                                              Gross          Net           Gross            Net
                                                                              -----         ----           -----           ----
<S>                                                                           <C>           <C>            <C>             <C>
CONVENTIONAL CRUDE OIL WELLS
     Alberta..............................................................      47            32             20             17
     British Columbia.....................................................      24            11             6               3
Total Conventional Crude Oil Wells........................................      71            43             26             20
                                                                                --            --             --             --
CONVENTIONAL NATURAL GAS WELLS
     Alberta..............................................................     269           148             48             25
     British Columbia.....................................................      49            24             17             12
TOTAL CONVENTIONAL NATURAL GAS WELLS......................................     318           172             65             37
                                                                               ---           ---             --             --
TOTAL WELLS                                                                    389           215             91             57
                                                                               ===           ===             ==             ==
</TABLE>


Notes:

(1)      Gross wells  represent the number of wells in which NG has an undivided
         percentage  interest and net wells  represent NG's aggregate  undivided
         percentage interest share in such wells.

(2)      Producing  wells  are  wells  producing   hydrocarbons  or  having  the
         potential to produce,  excluding shut-in wells. As at December 31, 2001
         Suncor has interests in four oil fields and 29 gas fields.

(3)      Non-Producing  Wells represent  management's  estimate of shut-in wells
         that could be capable of economic production but were not on production
         as at December 31, 2001.

SALES AND SALES REVENUES

The following table shows the breakdown of NG's sources of revenues.

<TABLE>
<CAPTION>
                                                                                                                  YEAR ENDED
                                                   GROSS REVENUES(1)                                             DECEMBER 31,
                                                                                                              ------------------
                                                                                                              2001          2000
                                                                                                              ----          ----
              <S>                                                                                             <C>           <C>

                                                                                                                 ($ MILLIONS)

              Crude oil and natural gas liquids.........................................................        45           77
              Natural gas...............................................................................       394          344
              Pipeline..................................................................................         5            6
              Other.....................................................................................         5            1
                                                                                                               ---          ---
              Total.....................................................................................       449          428
                                                                                                               ===          ===
</TABLE>


Note:

(1)      Includes intersegment revenues.



                                                                            19
<PAGE>


PRODUCTION COSTS

The following shows production (lifting) costs in connection with NG's crude oil
and natural gas operations  for the years  indicated.  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 prior to 2001 have been restated on a 6:1 basis.

<TABLE>
<CAPTION>
                                                                                                                  YEAR ENDED
PRODUCTION    (LIFTING) COSTS                                                                                    DECEMBER 31,
                                                                                                              ------------------
                                                                                                              2001          2000
                                                                                                              ----          ----
<S>                                                                                                           <C>           <C>
                                                                                                                 ($ PER BOE OF
                                                                                                               GROSS PRODUCTION)

Average production (lifting) cost of conventional crude oil and gas(1)................................        2.96          3.11
</TABLE>


Note:
(1)      Production   (lifting)  costs  include  all  expenses  related  to  the
         operation and maintenance of producing or producible  wells and related
         facilities,  natural  gas plants  and  gathering  systems.  It does not
         include an estimate for future reclamation costs.


                                                                            20

<PAGE>


QUARTERLY VOLUMES AND NETBACK ANALYSIS

The  following  table  shows  Suncor's  average  production  volumes,   pricing,
royalties,  operating expenses and netbacks for natural gas,  conventional crude
oil and natural gas liquids, for the periods indicated.

<TABLE>
<CAPTION>

                                             2001                                                      2000
                     ------------------------------------------------------    -----------------------------------------------------
                       4Q          3Q          2Q         1Q          2001       4Q           3Q         2Q         1Q         2000
                     --------    --------    -------    -------    --------    --------    ---------   -------    -------    -------
<S>                  <C>         <C>         <C>        <C>        <C>         <C>         <C>         <C>        <C>
NATURAL GAS
Production Volume
(mmcf/day)              180         176        177        177         177         183          200       195        222        200
                     --------    --------    -------    -------    --------    --------    ---------   -------    -------    -------

Price ($/mcf)          3.10        3.90       6.78      10.73        6.09        8.02         4.63      3.70       2.96       4.72
Royalties ($/mcf)     (0.54)      (0.85)     (1.58)     (2.91)      (1.46)      (2.14)       (1.09)    (0.85)     (0.61)     (1.17)
Operating Expenses
($/mcf) (1)           (0.97)      (0.79)     (0.95)     (0.73)      (0.86)      (0.95)       (0.68)    (0.77)     (0.66)     (0.76)
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
Netback ($/mcf)        1.59        2.26       4.25       7.09        3.77        4.93         2.86      2.08       1.69       2.79
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------

CONVENTIONAL CRUDE
OIL
Production Volume
(kbbls/d) (2)           1.3         1.5        1.5        1.7         1.5         1.6          3.6        3.5        8.1       4.2
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------

Price ($/bbl)         27.17       33.17      36.75      37.35       34.35       36.01        33.09     30.04      26.30      29.50
Royalties ($/ bbl)    (1.84)      (2.46)     (2.60)     (2.89)      (2.45)     (11.52)       (9.70)    (8.29)     (8.31)     (9.46)
Operating Expenses
($/ bbl) (1)          (7.25)      (4.76)     (5.69)     (3.85)      (5.17)      (9.47)       (6.79)    (7.65)     (6.62)     (7.63)
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
Netback ($/bbl)       18.08       25.95      28.46      30.61       26.73       15.02        16.60     14.10      11.37      12.41
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------

NATURAL GAS LIQUIDS
Production Volume
(kbbls/d) (2)           2.4         2.4        2.3        2.3         2.4         2.5          2.8       3.1        3.5        3.0
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
Price ($/bbl)         23.47       30.26      39.32      45.07       34.38       43.00        39.56     32.80      33.16      36.66
Royalties ($/ bbl)    (5.96)     (10.26)    (10.77)    (12.86)      (9.93)     (12.62)      (11.50)    (9.55)     (9.25)    (10.73)
Operating Expenses
($/ bbl) (1)          (5.83)      (4.75)     (5.72)     (4.40)      (5.17)      (9.47)       (6.79)    (7.65)     (6.62)     (7.63)
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
Netback ($/bbl)       11.68       15.25      22.83      27.81       19.28       20.91        21.27     15.60      17.29      18.30
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
                    ---------    --------    -------    -------    --------    --------    ---------   --------   --------   -------
</TABLE>


Note:

(1)   Operating expenses includes production (lifting) costs and administrative
      expenses.
(2)   Thousands of barrels per day



                                                                             21

<PAGE>


MARKETING, PIPELINE AND OTHER OPERATIONS

Suncor operates gas processing  plants at South Rosevear,  Pine Creek,  Boundary
Lake South, Progress and Simonette with a total design capacity of approximately
206 million cubic feet per day (mmcf/day).  Suncor's  capacity interest in these
gas processing  plants is  approximately  128 mmcf/day.  Suncor also has varying
undivided  percentage  interests in natural gas  processing  plants  operated by
other companies.

Approximately  69% of Suncor's  natural gas  production is marketed under direct
sales  arrangements  to customers  in Alberta,  eastern  Canada,  and the United
States.  Contracts for these direct sales arrangements are of varied terms, with
a majority  having terms of one year or less, and  incorporate  pricing which is
either fixed over the term of the contract or  determined  on a monthly basis in
relation to a specified  market reference  price.  Under these contracts,  NG is
responsible for  transportation  arrangements to the point of sale. Sales to the
United  States  are  made  under  a  variety  of  arrangements   with  different
transportation and pricing terms. NG's direct sales arrangements include some of
the natural gas consumed in Suncor's Oil Sands plant at Fort McMurray and in its
downstream operations.

Approximately  31% of Suncor's  natural gas  production  is sold under  existing
contracts to aggregators ("system sales").  Proceeds received by producers under
these  sales  arrangements  are  determined  on a netback  basis,  whereby  each
producer  receives  revenue  equal to its  proportionate  share  of  sales  less
regulated  transportation charges and a marketing fee. Most of NG's system sales
volumes are  contracted to  TransCanada  Gas Services and  Pan-Alberta  Gas Ltd.
These  companies  resell this  natural gas  primarily  to eastern  Canadian  and
midwest and eastern United States markets.

To ensure ongoing  direct sales access to markets in the United  States,  NG has
entered into long-term gas pipeline transportation  contracts.  Suncor currently
has 14  million  cubic  feet per day of firm  capacity  on the  Northern  Border
Pipeline to the U.S. midwest that expires October 31, 2003. Suncor also has firm
capacity of 40 mmcf/day on the Pacific Gas Transmission  ("PGT") pipeline to the
California border extending to the year 2023.

Suncor's  conventional crude oil production is used in its refining  operations,
exchanged  for  other  crude  oil with  Canadian  or U.S.  refiners,  or sold to
Canadian and U.S.  purchasers.  Sales are generally made under spot contracts or
under  contracts  that are  terminable  on  relatively  short  notice.  Suncor's
conventional   crude  oil  production  is  shipped  on  pipelines   operated  by
independent pipeline companies. NG currently has no pipeline commitments related
to the shipment of crude oil.

The Suncor-owned  Albersun  pipeline,  operated by Suncor Energy Marketing Inc.,
was  constructed  in 1968 to transport  natural gas to the Oil Sands  plant.  It
extends  approximately  300 kilometres  south of the plant and connects with the
TCPL Alberta  intra-provincial  pipeline system.  The Albersun  pipeline has the
capacity to move in excess of 100 mmcf/day of natural gas.  Suncor  arranges for
natural gas supply and  controls  most of the  natural  gas on the system  under
delivery  based  contracts.  The pipeline moves natural gas both north and south
for Suncor and other shippers.  In 2001,  throughput on Albersun pipeline was 66
mmcf/day and revenues were approximately $5 million.

CAPITAL AND EXPLORATION EXPENDITURES

The following table sets out, for the quarters indicated,  capital  expenditures
by Suncor's NG business unit:

<TABLE>
<CAPTION>

- --------------------------------------------------------------------------------------------------------------------
                                              2001                                          2000
- --------------------------------------------------------------------------------------------------------------------
($ millions)                 4Q          3Q          2Q         1Q          4Q          3Q          2Q         1Q
- --------------------------------------------------------------------------------------------------------------------
<S>                          <C>         <C>         <C>       <C>          <C>        <C>         <C>        <C>
Property Acquisition          -           -           -          -           8           -           2          1
- --------------------------------------------------------------------------------------------------------------------
Exploration                  29           4          14          3          17           9           6         18
- --------------------------------------------------------------------------------------------------------------------
Development                  19          20          17         26           8          13           3         42
- --------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                                             22

<PAGE>


NG expects  to spend $140  million  in 2002 to  support  the  Company's  goal of
increasing natural gas production.

ENVIRONMENTAL COMPLIANCE

For a description of the impact of environmental  protection requirements on NG,
refer to "Environmental Risks" and "Government  Regulation" in the "Risk/Success
Factors" section of this AIF.


                                     SUNOCO

Suncor  refines and markets  petroleum  products in central  Canada  through its
wholly owned subsidiary,  Sunoco Inc.. Its refinery in Sarnia, Ontario,  refines
petroleum feedstocks from Oil Sands and other sources into gasoline, distillates
and petrochemicals.

Sunoco's  controlled  distribution  channels enhance its position in the Ontario
market.  Approximately  59% of Sunoco's  sales  volume in 2001 was sold  through
controlled  distribution  networks in Ontario  that sell  gasoline and diesel to
retail  customers.   Approximately  38%  was  sold  to  industrial,  commercial,
wholesale  and refining  customers in Ontario and Quebec,  primarily  jet fuels,
diesel and gasolines.  The remaining 3% represents  petrochemical  sales through
Sun  Petrochemicals  Company,  a 50% joint  venture  between  Sunoco  and a U.S.
refinery.

Sunoco  also  markets  natural  gas  to  approximately  125,000  commercial  and
residential  customer accounts in Ontario. In 2001, Sunoco completed a strategic
assessment of this business, and is currently exploring alternatives including a
possible  disposition,  joint  venture,  or  other  transaction  involving  such
business.

Sunoco's  financial  reporting  in 2001 is based on its Rack Back / Rack Forward
organizational  structure. The Rack-Back division procures and refines crude oil
and  feedstocks,  and sells and  distributes  to the Sarnia  refinery's  largest
industrial and reseller  customers.  The  Rack-Forward  division is comprised of
retail  operations,  retail  natural gas  marketing,  cardlock and  industrial /
commercial  sales, and the UPI Inc.  ("UPI") and Pioneer Group Inc.  ("Pioneer")
joint venture businesses. UPI is a 50% joint venture company owned by Sunoco and
GROWMARK  Inc.,  a  U.S.  Midwest   agricultural   supply  and  grain  marketing
cooperative.  Pioneer is an  independent  retailer  with which  Sunoco has a 50%
joint venture partnership.

PROCUREMENT OF FEEDSTOCKS

Sunoco's  refining  operation  uses both synthetic and  conventional  crude oil.
Sunoco  procured  approximately  47% of its synthetic  crude oil feedstock  from
Suncor's Oil Sands  production in 2001,  compared with 56% in 2000. In 2001, 55%
of the crude oil  refined  at the  Sarnia  Refinery  was  synthetic  crude  oil,
compared with 64% in 2000. The balance of the refinery's synthetic crude oil, as
well as its conventional and condensate  feedstocks,  were purchased from others
under month to month contracts.  In the event of a significant disruption in the
supply of synthetic  crude oil, the refinery has the  flexibility  to substitute
other sources of sweet or sour conventional crude oil.

Sunoco  procures its  conventional  crude oil feedstock  primarily  from western
Canada, supplemented from time to time with crude oil from the United States and
other countries.  Foreign crude oil is delivered to Sarnia via pipeline from the
United  States Gulf Coast or via the  Interprovincial  Pipeline  from  Montreal.
Sunoco has made no firm  commitments  for  capacity on these  pipeline  systems.
Crude  oil is  procured  from the  market  on a spot  basis  or under  contracts
terminable on short notice.

In  1998,  Sunoco  signed  a  10-year  synergistic  feedstock  agreement  with a
Sarnia-based  petrochemical  refinery,  Nova Chemicals  (Canada) Ltd. Under this
buy/sell  agreement,   Sunoco  obtains  feedstock  that  is  more  suitable  for
production of  transportation  fuels in exchange for feedstock more suitable for
petrochemical cracking.  Sunoco also enters into reciprocal buy/sell or exchange
arrangements  with  other  refining  companies  from  time to time as a means to
minimize transportation costs, balance product


                                                                            23

<PAGE>


availability and enhance  refinery  utilization.  Sunoco also purchases  refined
products in order to meet customer requirements.

REFINING OPERATIONS

Sunoco's  Sarnia  Refinery  produces  transportation  fuels  (gasoline,  diesel,
propane and jet fuel), heating fuels,  liquefied petroleum gases,  residual fuel
oil, asphalt feedstock, benzene, toluene, mixed xylenes and orthoxylene, as well
as the petrochemicals  A-100 and A-150 that are used in the manufacture of paint
and chemicals.

The  refinery has the  capacity to refine  70,000  barrels of crude oil per day.
Refining sales in 2001 averaged approximately 93,400 barrels per day. The Sarnia
Refinery is  configured  to allow for  operational  flexibility.  In addition to
conventional  sweet and sour crudes, the refinery is capable of processing sweet
synthetic  crude oil, which yields a more valuable  product mix. A hydrocracker,
jet fuel tower and  low-sulphur  diesel tower  further  increase the  refinery's
ability to produce premium-value  transportation fuels, distillates and naphtha,
and its flexibility to vary the gasoline/distillate  ratio. The hydrocracker has
a  capacity  to  process   approximately  23,300  barrels  per  day.  Additional
flexibility in gasoline,  octane and petrochemical production is provided by the
complementary  operations of an alkylation unit with a capacity of 5,400 barrels
per day. The petrochemical  facilities,  which have a capacity of 13,100 barrels
per day, produce benzene,  toluene,  and mixed xylenes,  and recover orthoxylene
from mixed xylenes, as well as petrochemicals A-100 and A-150.

The  refinery  has a cracking  capacity of 40,200  barrels per day from a Houdry
Catalytic Cracker  ("catcracker")  and a hydrocracker.  Approximately 40% of the
cracking  capacity is attributable to the catcracker,  which uses older cracking
technology.  In 2001, The refinery  completed planned  maintenance on Plant One,
which consists of a crude unit,  catalytic  cracker,  alkylation unit, and other
treating  units.  However,  the  refinery  also  experienced  unplanned  outages
involving the catcracker,  the BTX unit and the vacuum unit. As a result,  crude
utilization declined 6% to 92% in 2001. The following chart sets out daily crude
input,  average refinery utilization rates, and cracking capacity utilization of
the Sarnia refinery over the last two years.

<TABLE>
<CAPTION>

Sarnia Refinery Capacity                             2001              2000
- ------------------------------------                 ----              ----
<S>                                                 <C>              <C>


Average daily crude input   (barrels per day)        64,200            68,900
Average utilization rate (%)(1)                      92                98
Average cracking capacity utilization (%)(2)         88                91
</TABLE>


Notes:

(1) Based on crude unit capacity and input to crude units.
(2) Based on cracking capacity and input to the hydrocracker and catalytic
    cracker.

In 2001 Sunoco  entered into an energy supply  agreement with  TransAlta,  under
which steam will be supplied to Sunoco's Sarnia Refinery.  For more details, see
the "Sunoco"  section under "Three Year  Highlights" in this Annual  Information
Form.

PRINCIPAL PRODUCTS

Sales of gasolines and other  transportation  fuels  represented 80% of Sunoco's
consolidated  revenues and other  operating  revenues in 2001 compared to 83% in
2000.  Set forth below is  information  on daily sales volumes and percentage of
Sunoco's  consolidated  revenues  contributed  by product group for the last two
years.


                                                                             24

<PAGE>

<TABLE>
<CAPTION>


              DAILY SALES VOLUMES                             2001                                   2000
              -------------------                             ----                                   ----
                                            (THOUSANDS OF CUBIC     % OF SUNOCO'S      (THOUSANDS OF     % OF SUNOCO'S
                                              METRES PER DAY)        CONSOLIDATED      CUBIC METRES      CONSOLIDATED
                                                                       REVENUES          PER DAY)          REVENUES
     <S>                                    <C>                     <C>                <C>               <C>
                Transportation fuels
       Gasoline                                     5.6                   42                5.5               44
             Retail (1)..................
             Other (2)...................           3.1                   17                2.8               16
     Jet fuel............................           0.7                    4                1.1                5
     Other...............................           3.1                   17                3.1               18
                                                   -----                 ----              -----             ----
                                                   12.5                   80               12.5               83
                                                   -----                 ----              -----             ----
     Petrochemicals......................           0.5                    4                0.5                4
     Heating fuels.......................           0.4                    2                0.4                2
     Heavy fuel oils.....................           0.8                    2                0.6                2
     Other...............................           0.6                    2                0.6                2
                                                   -----                 ----              -----             ----

     Total Refined Products..............          14.8                   90               14.6               93
                                                   -----                 ----              -----             ----

     Other Non Refined Products..........             -                   10                  -                7
                                                   -----                 ----              -----             ----
     Total %.............................                                100                                 100
                                                   -----                 ----              -----             ----
                                                   -----                 ----              -----             ----
</TABLE>

Notes:
(1)      Excludes joint ventures.
(2)      Joint ventures


PRINCIPAL MARKETS

Approximately   59%  of  Sunoco's  total  sales  volumes  are  marketed  through
controlled retail networks,  including the Sunoco retail network,  joint-venture
operated retail stations,  and cardlock  operations.  This controlled network is
comprised of:

- - 302 Sunoco retail service stations
- - 154 Pioneer-operated retail service stations
- - 47 UPI-operated service stations and a network of bulk distribution facilities
  for rural and farm fuels
- - 18 Sunoco branded Fleet Fuel Cardlock sites

Refined petroleum products (excluding  petrochemicals),  and natural gas sold to
commercial and residential accounts are marketed under several brands, including
the Company's Canadian "Sunoco" trademark.  Sunoco's other principal  trademarks
include  "Ultra 94" in respect of its premium  high octane  gasoline,  and "Gold
Diesel" used in respect of its premium low sulphur diesel product.

Approximately  38% of  Sunoco's  total  sales  volumes  are sold to  industrial,
commercial, wholesale, and refining customers, primarily in Ontario. Sunoco also
supplies  industrial  and  commercial  customers  in  Quebec  through  long-term
arrangements  with other regional  refiners,  or through Group Petrolier  Norcan
Inc., a 25% Sunoco-owned fuels terminal and product supply business in Montreal.

Sunoco markets toluene, mixed xylenes, orthoxylene and petrochemicals, primarily
in Canada  and the U.S.,  through  Sun  Petrochemicals  Company.  Suncor  Energy
Marketing Inc. has a 50% interest in Sun Petrochemicals Company, a petrochemical
marketing  joint  venture  company,  to market  products  from  Sunoco's  Sarnia
Refinery and a Toledo,  Ohio,  refinery owned by the joint venture partner.  Sun
Petrochemicals  Company  markets  petrochemicals  used to manufacture  plastics,
rubber, synthetic fibres,  industrial solvents and agricultural products, and as
gasoline octane enhancers.  All of Sunoco's benzene  production is sold directly
to other petrochemical manufacturers in Sarnia.


                                                                             25

<PAGE>


Sunoco's  share of total refined  product sales in its primary market of Ontario
is  approximately  18%  in  2001  compared  with   approximately  17%  in  2000.
Transportation  fuels  accounted for over 84% of Sunoco's total sales volumes in
2001;  petrochemicals  accounted for 3%. The remaining  volumes  included  other
refined  products  such as heating  fuels,  heavy oils and  liquefied  petroleum
gases, and were sold to industrial users and resellers.

Sunoco supplies refined petroleum products to the Pioneer and UPI joint ventures
under exclusive  supply  agreements.  The UPI joint venture expires in 2002, and
thereafter will be automatically  renewed unless  terminated upon 120 days prior
written notice.  The shareholder  agreement between UPI and Sunoco provides that
Sunoco has the exclusive right to supply petroleum products to the joint venture
as long as Sunoco remains as a shareholder of UPI. No notice of termination  has
been received or given to date.


In  addition  to refined  product  sales,  Sunoco  also  markets  natural gas to
approximately  125,000 commercial and residential  customer accounts in Ontario.
Margins  improved in the natural gas business in 2001 due to a restructuring  of
customer contracts that locked in fixed price sales to fixed price supply.

TRANSPORTATION AND DISTRIBUTION

Sunoco  uses a variety of  transportation  modes to deliver  products to market,
including  pipeline,  water, rail and road.  Sunoco owns and operates  petroleum
transportation,  terminal and dock facilities,  including storage facilities and
bulk distribution  plants in Ontario.  The major mode of transporting  gasoline,
diesel,  jet fuel and heating fuels from the Sarnia  Refinery to core markets in
Ontario  is the  Sun-Canadian  Pipe  Line,  which is 55% owned by Sunoco and 45%
owned by another  refiner.  The pipeline  operates as a private facility for its
owners. It serves terminal facilities in Toronto, Hamilton and London, and has a
capacity of 126,000  barrels per day (20,000 cubic metres).  Sunoco utilized 85%
of this capacity in 2001 compared with 84% in 2000.

Sunoco also has direct pipeline  access to petroleum  markets in the Great Lakes
region of the United States by way of connection to a pipeline  system in Sarnia
operated by a U.S.-based  refiner.  This link to the U.S.  allows Sunoco to move
products  to market or obtain  feedstocks/products  when market  conditions  are
favourable in the Michigan and Ohio markets.

Sunoco  believes  that its own storage  facilities,  and those  under  long-term
contractual  arrangements with other parties, are sufficient to meet its current
and foreseeable needs.

CAPITAL EXPENDITURES

Sunoco  plans to spend  approximately  $96  million  in 2002  compared  with $54
million in 2001. Expenditures in 2002 will include funds associated with meeting
sulphur-in-gasoline  limit regulations at its Sarnia refinery.  In 2002 and 2003
Sunoco  plans  to spend  $40  million  to meet the new 2005  sulphur-in-gasoline
regulated  limits.  See "Risk / Success  Factors  Affecting  Performance" in the
Sunoco section of MD&A and "Risks Specifically Respecting Sunoco" in the "Risk /
Success Factors" section of this AIF.

ENVIRONMENTAL COMPLIANCE

For a description  of the impact of  environmental  protection  requirements  on
Sunoco,  please  refer to the  sections  entitled  "Outlook"  and  "Risk/Success
Factors Affecting Performance" in the Sunoco section of Management's  Discussion
and Analysis in Suncor's 2001 Annual Report. Also refer to "Environmental Risks"
and "Government Regulation" in the "Risk/Success Factors" section of this AIF.


                                                                             26

<PAGE>


                                SUNCOR EMPLOYEES

The following  table shows the  distribution  of employees  among Suncor's three
business  units,  its corporate  office and the Stuart Oil Shale Project for the
past two years.

<TABLE>
<CAPTION>
                                                                          YEAR ENDED
                                                                         DECEMBER 31,
                                                                      -----------------
                                                                      2001         2000
                                                                      -----------------
<S>                                                                  <C>           <C>
           Oil Sands............................................      2,367        2,057
           Natural Gas..........................................        190          182
           Sunoco(1)............................................        561          590
           Stuart Project.......................................          -           77
           Corporate(2).........................................        189          137
                                                                      -----        -----
           Total......................................................3,307        3,043
                                                                      =====        =====
</TABLE>


Notes:

(1)      Excludes joint venture employees.

(2)      Reflects  inclusion  of  Calgary-based  employees  providing  technical
         support to the Firebag  In-Situ  Project,  as well as some  information
         technology  employees who were previously counted within the individual
         business units.

(3)      In addition to Suncor employees, independent contractors supply a range
         of services to the Company.

The   Communications,   Energy  and  Paperworkers  Union  Local  707  represents
approximately  1,423 Oil  Sands  employees.  Suncor  entered  into a  three-year
collective  agreement with the union effective May 1, 2001.  Management believes
Suncor's positive working relationship with the union will continue.

Employee  associations  represent  approximately  170 Sunoco Sarnia refinery and
Sun-Canadian Pipe Line Company  employees.  In March 2001, Sunoco and the Sarnia
employee  association  signed a one-year  agreement that will be renegotiated in
2002.  Sunoco management  believes  Sunoco's positive working  relationship with
this  association  will  continue  and a new  agreement  should be reached.  The
agreement with the employee  association of  Sun-Canadian  Pipe Line Company was
signed in 1993, and it is renewed  automatically  each year unless terminated by
written notice by either party at least 60 days prior to the anniversary date of
the  agreement.  No notice under such  agreement  has been  received or given to
date.  Sunoco management  believes  Sunoco's positive working  relationship with
this association  will continue and the agreement will be automatically  renewed
on its anniversary.



                              RISK/SUCCESS FACTORS

VOLATILITY  OF CRUDE OIL AND  NATURAL  GAS  PRICES.  Suncor's  future  financial
performance is closely linked to oil prices,  and to a lesser extent natural gas
prices.  The price of these commodities can be influenced by global and regional
supply and demand factors.  Worldwide economic growth,  political  developments,
compliance  or   non-compliance   with  quotas   imposed  upon  members  of  the
Organization of Petroleum Exporting  Countries and weather,  among other things,
can affect  world oil supply and demand.  Natural gas prices  realized by Suncor
are  affected  primarily  by North  American  supply and demand and by prices of
alternate  sources of energy.  All of these factors are beyond Suncor's  control
and can result in a high  degree of price  volatility  not only in crude oil and
natural gas prices, but also fluctuating price  differentials  between heavy and
light grades of crude oil, which can impact prices for sour crude.  In 2001, the
heavy-light  differential widened and reduced earnings.  Management believes the
differential  will trend toward more historical levels in 2002 if the demand for
heavy oil increases as  anticipated.  Oil and natural gas


                                                                             27
<PAGE>


prices  have  fluctuated  widely in recent  years and Suncor  expects  continued
volatility  and  uncertainty  in crude oil and natural  gas prices.  A prolonged
period of low crude oil prices could affect the value of Suncor's  crude oil and
gas  properties  and the level of spending on  development  projects,  and could
result in curtailment of production at some  properties,  and accordingly  could
have an adverse impact on Suncor's financial condition and liquidity and results
of  operations.  Suncor  cannot  control the factors that  influence  supply and
demand or the prices of crude oil or natural gas.

Suncor  cannot  control  the prices of crude oil or  natural  gas,  or  currency
exchange rates.  However, the Company has a hedging program that fixes the price
of crude oil, and periodically,  natural gas, and the associated  exchange for a
percentage of Suncor's total production volume. Suncor's objective is to lock-in
prices on a portion of its future  production today to reduce exposure to market
volatility and ensure the Company's ability to finance growth. If an operational
upset  occurred  that  reduced  or  eliminated  crude  oil  and/or  natural  gas
production  for a period of time,  Suncor  would be required to continue to make
payments under its hedging program if the actual price was higher than the price
hedged.  For particulars of Suncor's  hedging  position as of year-end 2001, see
Note 17 of Suncor's consolidated financial statements.

Suncor  conducts an assessment of the carrying value of its assets to the extent
required by Canadian general accepted accounting  principles ("GAAP").  If crude
oil and natural gas prices decline,  the carrying value of Suncor's assets could
be subject to downward  revisions,  and  Suncor's  earnings  could be  adversely
affected.

RISK FACTORS RELATED TO FIREBAG AND VOYAGEUR  PROJECTS.  There are certain risks
associated with the execution of the proposed  Firebag In-Situ Oil Sands Project
and Voyageur,  including:  regulatory approvals,  schedule, resources and costs,
including  the  availability  and cost of  materials,  equipment  and  qualified
labour;  the impact of general  economic,  business and market  conditions;  the
impact of weather  conditions;  Suncor's  ability to finance Oil Sands growth if
commodity prices were to stay at low levels for an extended  period;  the impact
of new  entrants  to the  oil  sands  business  which  could  take  the  form of
competition for skilled people, increased demands on the Fort McMurray,  Alberta
infrastructure (for example,  housing,  roads and schools), or price competition
for products sold into the marketplace;  the potential ceiling on the demand for
synthetic  crude  oil;  and the  effect  of  changing  standards  of  government
regulation  and  public  expectations  in  relation  to the  impact of oil sands
development  on  the  environment.  The  commissioning  and  integration  of new
facilities with the existing asset base could cause delays in achieving targeted
production  capacity.  Suncor  management  believes the planned increases in Oil
Sands production through these projects present issues that require prudent risk
management.

RISKS  ASSOCIATED  WITH  INTEGRATION  OF  PROJECT  MILLENNIUM  WITH  BASE  PLANT
OPERATIONS. With Project Millennium commissioning complete by year-end 2001, the
main risks to final Project Millennium execution are associated with integration
of the new  facilities  with the existing  asset base,  particularly  during the
winter months where risks  associated  with weather are  increased.  These risks
could  cause  unforeseen  outages  and  costs,  and  delays  in  achieving  full
utilization of the combined production capacity of 225,000 barrels per day.

INCREASED  DEPENDENCE ON OIL SANDS BUSINESS.  The Company's  significant capital
commitment  to further its growth  projects at Oil Sands,  including the Firebag
In-Situ Oil Sands  Project,  and  Voyageur if  approved,  may require  Suncor to
forego  investment  opportunities  in  other  segments  of its  operations.  The
completion  of Project  Millennium,  and the other  future  projects to increase
production at Oil Sands, will substantially increase the Company's dependence on
the Oil Sands segment of its business. For example,  assuming achievement of Oil
Sands' 2002 production target of 210,000 barrels per day, the Oil Sands business
will  account for  approximately  86% of Suncor's  upstream  production  in 2002
compared to 79% in 2001 and 74% in 2000.

RISKS  ASSOCIATED  WITH  IN-SITU  EXTRACTION.   Current  steam-assisted  gravity
drainage (SAGD)  technologies  for in-situ recovery of heavy oil and bitumen are
energy  intensive,  requiring  significant  consumption of natural gas and other
fuels to produce  steam.  Although  there have been a number of SAGD  technology


                                                                            28

<PAGE>



pilot projects and several  commercial scale projects are under  development and
are scheduled to be on production by the end of 2002, commercial  application of
this technology is not yet commonplace.

COMPETITION.  The  petroleum  industry  is highly  competitive  in all  aspects,
including the  exploration  for, and the  development of, new sources of supply,
the acquisition of crude oil and gas interests,  and the refining,  distribution
and marketing of petroleum products and chemicals.  Suncor competes in virtually
every aspect of its business with other energy companies. The petroleum industry
also  competes  with other  industries  in  supplying  energy,  fuel and related
products to consumers.  Suncor  offers  custom blends of synthetic  crude oil to
meet specific  customer  demands.  Suncor  believes that the competition for its
custom  blended  synthetic  crude oil  production is Canadian  conventional  and
synthetic sweet and sour crude oil.

A number of other  companies have entered or have indicated they are planning to
enter the oil sands business and begin production of bitumen and synthetic crude
oil, or expand existing operations.  If all announced competing projects were to
be built,  they could  quadruple  Canada's  production  of bitumen and  upgraded
synthetic  crude oil to more than two and half million  barrels  (400,000  cubic
metres)  per day by the end of the  decade.  The recent  trend  toward  industry
consolidation has created more competitors with financial capacity who may enter
into  similar  and  competing  oil  sands  businesses.   Expansion  of  existing
operations and development of new projects could materially  increase the supply
of bitumen and synthetic crude oil and other competing crude oil products in the
marketplace.  Depending on the levels of future demand, increased supplies could
have a negative impact on prices.

In the western Canadian diesel market demand and supply can fluctuate. Currently
there is excess  supply of diesel fuel and Suncor  expects  the market  could be
impacted by this excess  supply and have a negative  impact on margins.  Margins
for diesel are typically  higher than the margins for synthetic and conventional
crude oil. The above noted  expansion plans of Suncor's  competitors  could also
result in an increase in the supply of diesel and further weakening of margins.

Historically, the industry-wide oversupply of refined petroleum products and the
overabundance  of retail  outlets  have kept  pressure  on  downstream  margins.
Management  expects that  fluctuations  in demand for refined  products,  margin
volatility and overall marketplace  competitiveness will continue.  In addition,
as  Suncor's  downstream  business  unit,  Sunoco,  participates  in new product
markets,  such as natural gas, it could be exposed to margin risk and volatility
from either cost and/or selling price fluctuations.

NEED TO REPLACE  CONVENTIONAL  NATURAL  GAS  RESERVES.  The future  natural  gas
reserves and production of the Company's NG business unit and,  therefore,  both
NG's cash flow from such production and Suncor's ability to maintain an internal
hedge  against  growing  consumption  of natural gas in its Oil Sands and Sunoco
operations,  are highly  dependent  on its success in  discovering  or acquiring
additional reserves and exploiting its current reserve base. Without natural gas
reserve additions through exploration and development or acquisition activities,
NG's conventional  natural gas reserves and production will decline over time as
reserves  are  depleted.  For  example,  in 2001,  Suncor's  natural gas average
reservoir  decline  rates  were  in the  28%  range,  consistent  with  industry
experience. Decline rates will vary with the nature of the reservoir, life-cycle
of the well, and other factors. Therefore past decline rates are not necessarily
indicative  of future  performance.  Exploring  for,  developing  and  acquiring
reserves is highly capital intensive. To the extent cash flow from operations is
insufficient  to generate  sufficient  capital and  external  sources of capital
become  limited  or  unavailable,  NG's  ability to make the  necessary  capital
investments to maintain and expand its  conventional  natural gas reserves could
be impaired. In addition, NG's long term performance is dependent on its ability
to  consistently  and  competitively  find and  develop  low cost,  high-quality
reserves that can be economically brought on stream.  Market demand for land and
services can also increase or decrease finding and development  costs. There can
be no  assurance  that  Suncor  will  be able to find  and  develop  or  acquire
additional reserves to replace production at acceptable costs.

RISKS RELATED TO COALBED  METHANE.  Coalbed  Methane (CBM)  exploration is being
undertaken by Suncor in Canada and the U.S.  through a wholly owned  subsidiary,
Suncor Energy (Natural Gas) America Inc. The  identification  of gas in coals is
necessary but not  sufficient for  establishing  commercial  success.


                                                                             29

<PAGE>


Effective production technology, water handling, well productivity,  requirement
for large land blocks, and a pilot production period are risk elements unique to
CBM. In Canada,  CBM as a gas resource has not yet been proven  commercial,  and
bears the additional risk that significant commercial production may require new
technology  or only be  available  in limited  areas or at higher  long term gas
prices than currently exist.

CBM is a commercial  gas  resource in the U.S..  The risks  associated  with CBM
activities in the U.S. vary by geographic region but can include: constraints on
land access from federal, state and individual land holders; local opposition to
well drilling and CBM  development;  high costs of treating  water produced with
CBM gas; limited  regional  pipeline exit capacity;  and strong  competition for
mineral  leases  and  services.   The  regulatory   framework  and   stakeholder
environment  varies by region. The physical operation of drilling and ultimately
producing gas in a location distant from Suncor's key management  presents risks
of  inadequate  oversight  of  operations.  Business  activity  in the U.S.  has
different  political  risk than in Canada,  and is conducted  in an  environment
where litigation and legal risk are more prevalent and substantial.

OPERATING  HAZARDS AND OTHER  UNCERTAINTIES.  Each of Suncor's  three  principal
business units, Oil Sands, NG and Sunoco,  require high levels of investment and
have particular economic risks and opportunities. Generally, Suncor's operations
are  subject to  hazards  and risks such as fires,  explosions,  gaseous  leaks,
migration of harmful substances, blowouts and oil spills, any of which can cause
personal injury, damage to property,  equipment and the environment,  as well as
interrupt operations. In addition, all of Suncor's operations are subject to all
of the risks normally incident to the transportation,  processing and storing of
crude oil, natural gas and other related products.

At Oil  Sands,  mining  oil sand,  extracting  bitumen  from the oil  sand,  and
upgrading  bitumen  into  synthetic  crude  oil  and  other  products,   involve
particular  risks  and  uncertainties.  Oil  Sands  is  susceptible  to  loss of
production,  slowdowns,  or  restrictions on its ability to produce higher value
products due to the  interdependence of its component  systems.  Severe climatic
conditions  at Oil Sands can cause  reduced  production  and in some  situations
result in higher costs. While there is no finding cost associated with oil sands
resources, the costs associated with production,  including mine development and
drilling of wells for SAGD  operations,  and the costs associated with upgrading
bitumen into synthetic crude oil, can entail  significant  capital outlays.  The
costs  associated  with synthetic  crude oil production at Oil Sands are largely
fixed and, as a result, operating costs per unit are largely dependent on levels
of production.

Aboriginal  peoples have claimed  aboriginal  title and rights to a  substantial
portion of western Canada. Certain aboriginal peoples have filed a claim against
the  government  of  Canada,  certain  governmental  entities  and the  Regional
Municipality  of Wood  Buffalo  (which  includes  the  city  of  Fort  McMurray,
Alberta),  claiming,  among other things, a declaration that the plaintiffs have
aboriginal title to large areas of lands  surrounding  Fort McMurray,  including
the lands on which Oil  Sands  and most of the  other  oil sands  operations  in
Alberta are situated.  To Suncor's knowledge the aboriginal peoples have made no
claims  against  Suncor and Suncor is unable to assess the effect,  if any,  the
claim would have on its Oil Sands operations.

In Suncor's NG business unit, the risks and  uncertainties  associated  with the
exploration for, and the development, production,  transportation and storage of
crude oil, natural gas and natural gas liquids should not be  underestimated  or
viewed as predictable.  NG's operations are subject to all of the risks normally
incident to drilling for natural gas wells,  the  operation and  development  of
such  properties,  including  encountering  unexpected  formations or pressures,
premature  declines  of  reservoirs,  blow-outs,  equipment  failures  and other
accidents, sour gas releases,  uncontrollable flows of crude oil, natural gas or
well fluids,  adverse weather  conditions,  pollution,  and other  environmental
risks.

Suncor's  downstream  business  unit,  Sunoco,  is  subject  to all of the risks
normally  incident  to  the  operation  of  a  refinery,   terminals  and  other
distribution facilities, as well as service stations,  including loss of product
or slowdowns due to equipment failures or other accidents.

Although  Suncor  maintains a risk  management  program,  including an insurance
component,   such   insurance   may  not  provide   adequate   coverage  in  all
circumstances,  nor are all such  risks  insurable.


                                                                             30

<PAGE>


Losses  resulting  from the  occurrence  of these  risks  could  have a material
adverse impact on Suncor.  Under the Company's business  interruption  insurance
coverage,  the Company would bear the first $U.S.260 million of any loss arising
from a future insured incident at its Oil Sands operations.

In addition,  there are risks  associated with growth projects that rely largely
or partly on new technologies and the  incorporation of such  technologies  into
new  or  existing  operations.   The  success  of  projects   incorporating  new
technologies, such as the Firebag In-Situ Oil Sands Project, cannot be assured.

There are also inherent risks, including political and foreign exchange risk, in
investing in business  ventures  internationally.  To date, Suncor does not have
material   international   investments  but  is  investigating  coalbed  methane
opportunities  in the United States.  However,  export sales in 2001 represented
15% of Suncor's 2001 consolidated revenue (2000 - 14%).

INTEREST RATE RISK.  Suncor is exposed to  fluctuations  in short-term  Canadian
interest rates as a result of the use of floating rate debt.  Suncor maintains a
substantial  portion  of its debt  capacity  in  revolving,  floating  rate bank
facilities  and  commercial  paper,  with the  remainder  issued  in fixed  rate
borrowings.  To minimize  its  exposure to interest  rate  fluctuations,  Suncor
occasionally enters into interest rate swap agreements and exchange contracts to
either  effectively  fix the interest rate on floating rate debt or to float the
interest  rate on fixed rate debt.  For more  details,  see the  "Liquidity  and
Capital Resources" section of MD&A.

EXCHANGE RATE  FLUCTUATIONS.  Suncor's  consolidated  financial  statements  are
presented  in  Canadian  dollars.  Results of  operations  are  affected  by the
exchange rates between the Canadian dollar and the U.S.  dollar.  These exchange
rates have varied substantially in the last five years. A substantial portion of
Suncor's revenue is received by reference to U.S. dollar denominated prices. Oil
prices  are  generally  set in U.S.  dollars,  while  Suncor's  sales of refined
products  are  primarily in Canadian  dollars.  Fluctuations  in exchange  rates
between the U.S. and Canadian dollar may therefore give rise to foreign currency
exposure,   either  favorable  or  unfavorable,   creating  another  element  of
uncertainty.  In the future,  the  strength of the Canadian  dollar  relative to
foreign  currencies  could  create  additional  uncertainties  for  Suncor as it
pursues its international growth plans.

ENVIRONMENTAL  RISKS.  Environmental  legislation  affects nearly all aspects of
Suncor's  operations.  These regulatory regimes are laws of general  application
that  apply to Suncor in the same  manner as they apply to other  companies  and
enterprises in the energy  industry.  The regulatory  regimes  require Suncor to
obtain  operating  licenses and permits in order to operate,  and impose 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.  Environmental  assessments
and regulatory  approvals are required before initiating most new major projects
or undertaking significant changes to existing operations.  In addition to these
specific,  known  requirements,  Suncor expects future 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;  storage,  treatment,  and
disposal of  hazardous  or  industrial  waste,  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;
Great Lakes water quality;  and  reformulated  gasoline to support lower vehicle
emissions. Changes in environmental legislation could have a potentially adverse
effect on Suncor from the standpoint of product  demand,  product  reformulation
and quality,  methods of production  and  distribution  and costs.  For example,
requirements  for  cleaner-burning  fuels  could  cause  additional  costs to be
incurred, which may or may not be recoverable in the marketplace. The complexity
and breadth of these issues make it extremely  difficult to predict their future
impact on Suncor.  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.   Compliance  with
environmental  legislation can require  significant  expenditures and failure to
comply with environmental  legislation may result in the imposition of fines and
penalties,  liability  for clean up costs and damages and the loss of  important
permits.


                                                                             31

<PAGE>


Suncor is  required  to and has posted  annually  with  Alberta  Environment  an
irrevocable  letter of credit equal to $0.03 per bbl of crude oil produced  ($15
million as at December  31,  2001) as  security  for the  estimated  cost of its
reclamation  activity on Leases 86 and 17, and the Steepbank  Mine.  For Project
Millennium,  Suncor  has  posted  an  irrevocable  letter  of  credit  equal  to
approximately  $26  million,  representing  security for the  estimated  cost of
reclamation  activities relating to Project Millennium up to the end of January,
2002.

UNCERTAINTY  OF RESERVE AND  RESOURCE  ESTIMATES.  The reserve data and resource
estimates  for  Suncor's Oil Sands and NG business  units,  included in Suncor's
Annual   Information  Form,   represent   estimates  only.  There  are  numerous
uncertainties  inherent in estimating quantities and quality of these proved and
probable reserves and other resources, including many factors beyond the control
of Suncor.

In general,  estimates  of  economically  recoverable  reserves are based upon a
number of variable factors and assumptions,  such as historical  production from
the properties,  the assumed effect of regulation by  governmental  agencies and
future operating costs, all of which may vary  considerably from actual results.
The accuracy of any reserve  estimate is a matter of engineering  interpretation
and judgment  and is a function of the quality and  quantity of available  data,
which may have been gathered over time. In the Oil Sands business unit,  reserve
estimates  are  based  upon a  geological  assessment,  including  drilling  and
laboratory  tests, and also consider current  production  capacity and upgrading
yields,  current mine plans,  operating  life and  regulatory  constraints.  The
Firebag reserves and resource  estimates are based upon a geological  assessment
based upon the data  gathered  from  evaluation  drilling,  the  testing of core
samples and seismic operations.  In the NG business unit, reservoir  performance
subsequent  to the date of the estimate may justify  revision,  either upward or
downward. For these reasons,  estimates of the economically recoverable reserves
attributable to any particular group of properties, and in NG the classification
of such reserves based on risk of recovery prepared by different engineers or by
the same engineers at different times, may vary substantially. At Oil Sands, the
independent  audit does not take into  account  the  economic  aspects of future
reserves.  Suncor's  actual  production,  revenues,  taxes and  development  and
operating  expenditures  with  respect  to its  reserves  will  vary  from  such
estimates, and such variances could be material.

Certain  information  included  in this  annual  information  form  to  describe
Suncor's reserves and resources, such as "probable reserves" and "resources", is
prohibited in filings with the United States Securities and Exchange  Commission
by U.S.  companies.  The  differences  between  Canadian  and U.S.  standards of
reporting  reserves and  resources  may make it  difficult  to compare  Suncor's
reserve and  resource  information  with the reserve  information  of  companies
subject to the U.S. standards of reporting.

RISKS  SPECIFICALLY  RESPECTING  SUNOCO.  Sunoco's  operations  are sensitive to
wholesale  and retail  margins for its  refined  products,  including  gasoline.
Margin volatility is influenced by overall marketplace competitiveness, weather,
the cost of crude oil (See  "Volatility  of Crude Oil and Natural Gas  Prices.")
and fluctuations in supply and demand for refined products.  Sunoco expects that
margin  and  price  volatility  and  overall  marketplace  competitiveness  will
continue.

In 1999, the Canadian  government passed 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. The Canadian  refining  industry faces
significant  capital  spending to construct  sulphur removal  facilities to meet
these  requirements.  In 2001 Sunoco  finalized an investment plan to meet those
limits.  Capital spending to achieve  compliance is expected to be approximately
$40  million,  and will  involve the  addition of a new  desulphurization  unit.
Construction of the unit is planned for 2002 and 2003.

The  federal   government   has  proposed  a   regulation   under  the  CANADIAN
ENVIRONMENTAL PROTECTION ACT that will limit the level of sulphur in diesel fuel
used in on-road  vehicles to a maximum of 15 ppm.  The  proposed  regulation  is
expected to come into effect in June 2006 for  producers and  importers,  and in
September  2006 for sellers.  Regulations  with  respect to off-road  diesel and
light fuel oil are also expected.  Sunoco continues to examine strategic options
to comply with the pending regulations.  Actual capital required to meet the new
standards is subject to further  development of such  regulations  and


                                                                             32

<PAGE>


strategic  assessment by Sunoco.  The cost to comply with the  sulphur-in-diesel
limits could be significant  but is not currently  expected to place the Company
at a competitive disadvantage.

LABOUR RELATIONS.  Suncor's hourly employees at its Oil Sands facility near Fort
McMurray  and its  Sarnia  refinery  are  represented  by a labour  union and an
employee  association,  respectively.  Suncor's  collective  agreement  with the
Communications,  Energy  and  Paperworkers  Union  Local  707 at Oil  Sands  was
renegotiated in May 2001 for a three-year term. Any work interruptions involving
Suncor's  employees,  or contract trades utilized in its growth projects,  could
materially and adversely affect Suncor's business and financial position.

GOVERNMENTAL  REGULATION.  The oil and gas industry in Canada, including the oil
sands  industry  and the  downstream  segment  of the  Company,  operates  under
federal, provincial and municipal legislation.  This industry is also subject to
regulation  and  intervention  by  governments  in such  matters as land tenure,
royalties, government fees, production rates, environmental protection controls,
the  export of crude  oil,  natural  gas and other  products,  the  awarding  or
acquisition of exploration and  production,  oil sands or other  interests,  the
imposition of specific drilling obligations,  environmental protection controls,
control over the development and abandonment of fields and mine sites (including
restrictions  on  production)  and possibly  expropriation  or  cancellation  of
contract  rights.   Before  proceeding  with  most  major  projects,   including
significant  changes to  existing  operations,  Suncor  must  obtain  regulatory
approvals. The regulatory approval process can involve stakeholder consultation,
environmental  impact  assessments and public hearings,  among other things.  In
addition,  regulatory  approvals may be subject to conditions including security
deposit  obligations  and  other  commitments.   Failure  to  obtain  regulatory
approvals,  or failure to obtain them on a timely basis, could result in delays,
abandonment or restructuring of projects and increased costs, all of which could
negatively affect future earnings and cash flow. Such regulations may be changed
from  time to  time  in  response  to  economic  or  political  conditions.  The
implementation  of new regulations or the  modification of existing  regulations
affecting  the crude oil and natural gas industry  could reduce demand for crude
oil and natural gas,  increase Suncor's costs and have a material adverse affect
on its financial condition.


                                                                             33

<PAGE>


                   SELECTED CONSOLIDATED FINANCIAL INFORMATION

SELECTED CONSOLIDATED FINANCIAL INFORMATION

The following selected consolidated  financial information for each of the years
in the  three-year  period  ended  December  31, 2001 is derived  from  Suncor's
consolidated  financial  statements.  The consolidated  financial statements for
each of the years in the  three-year  period  ended  December 31, 2001 have been
audited by  PricewaterhouseCoopers  LLP,  Chartered  Accountants.  Suncor's 2001
audited  consolidated  financial  statements  accompanied by the audit report of
PricewaterhouseCoopers  LLP for each of the years in the three-year period ended
December 31, 2001. The information set forth below should be read in conjunction
with the MD&A and Suncor's  consolidated  comparative  financial  statements and
related notes.


<TABLE>
<CAPTION>

                                                                               YEAR ENDED DECEMBER 31,(1)
                                                                              ----------------------------
                                                                               2001        2000       1999
                                                                               ----        ----       ----
                <S>                                                           <C>        <C>        <C>
                                                                              ($ MILLIONS EXCEPT PER SHARE
                                                                                        AMOUNTS)

                Revenues.................................................      3,995       3,388     2,387
                Net earnings.............................................        388         377       186
                Per common share(1) (undiluted)..........................       1.63        1.58      0.74
                Per common share(1) (diluted)............................       1.61        1.57      0.73
                Cash flow provided from operations.......................        831         958       591
                Per common share(1)......................................       3.52        4.11      2.51
                Capital and exploration expenditures.....................      1,678       1,998     1,350
</TABLE>

<TABLE>
<CAPTION>
                                                                                   AS AT DECEMBER 31,
                                                                               ---------------------------
                                                                               2001        2000       1999
                                                                               ----        ----       ----
                                                                                       ($ MILLION)
                <S>                                                           <C>         <C>         <C>
                Total assets..............................................    8,094       6,833      5,176
                Long-term borrowings(2)...................................    3,113       2,193      1,307
                Accrued liabilities and other(3)                                251         252        236
                Common shareholders' equity(4)............................    2,263       1,958      1,594
</TABLE>


Notes:

(1) Per share amounts for all years reflect a two-for-one share split in 2000
    and payments on the preferred  securities issued in 1999.

(2) Includes current portion.

(3) See Notes 12 and 13 to Suncor's 2001 Consolidated Financial Statements,
    which Notes are incorporated by reference herein.

(4) Excludes Preferred Securities issued in 1999. See Dividend Policy and
    Record.

DIVIDEND POLICY AND RECORD

Suncor's  Board of Directors has  established a policy of paying  dividends on a
quarterly basis.  This policy is reviewed from time to time in light of Suncor's
financial  position,  its financing  requirements for growth,  its cash flow and
other factors considered relevant by Suncor's Board of Directors.  A dividend of
$0.085 per common share for the first quarter of 2002 has been declared, payable
on March 25, 2002 to shareholders of record on March 15, 2002.


                                                                             34

<PAGE>



During 1999, the Company  completed a Canadian offering of $276 million of 9.05%
preferred  securities  and a U.S.  offering  of  U.S.$162.5  million  of  9.125%
preferred securities, the proceeds of which totalled Canadian $507 million after
issue costs of $17 million ($10 million after income tax credits of $7 million).
The preferred  securities are unsecured junior subordinated debt of the Company,
due in 2048 and  redeemable at the Company's  option on or after March 15, 2004.
Subject to certain  conditions,  the Company  has the right to defer  payment of
interest on the securities for up to 20 consecutive quarterly periods.  Deferred
interest  and  principal  amounts are payable in cash,  or, at the option of the
Company,  from the  proceeds  on the sale of equity  securities  of the  Company
delivered to the trustee of the preferred  securities.  For accounting purposes,
the preferred  securities  are  classified as share capital in the  consolidated
balance sheet and the interest  distributions  thereon, net of income taxes, are
classified as dividends.

The following  table sets forth the per share amount of dividends paid by Suncor
during the last three years.

<TABLE>
<CAPTION>
                                                                        YEAR ENDED DECEMBER 31,
                                                                        -----------------------
                                                                     2001        2000        1999
                                                                     ----        ----        ----
             <S>                                                    <C>         <C>         <C>

             Common Shares
             Cash dividends(1)..................................    $0.34       $0.34       $0.34
             Preferred Securities
             Cash interest distributions........................    $0.21       $0.21       $0.17
             Dividends paid in common shares....................      --           --        --
</TABLE>



Note:

(1)      Per share amounts for 2000 and 1999 have been adjusted to reflect a
         two-for-one share split in 2000.

FUTURE COMMITMENTS TO BUY, SELL, EXCHANGE OR TRANSPORT CRUDE OIL AND NATURAL GAS

In order to ensure  continued  availability  of, and  access to,  transportation
facilities  for the  crude oil and  natural  gas  products  of its Oil Sands and
Natural Gas business units, the Company has entered into long-term contracts for
pipeline capacity on various third party systems.

The  Company's Oil Sands  business unit has entered into a long-term  commitment
with Enbridge for the transportation of sour crude oil and bitumen from Suncor's
oil sands plant near Ft. McMurray, Alberta, to Hardisty, Alberta. Particulars of
that commitment are described under the heading  "Operations" in the "Oil Sands"
section of this Annual Information Form.

Natural gas product pipeline commitments are described in the following table:


                                                                             35


<PAGE>


<TABLE>
<CAPTION>

- --------------------------------------------------------------------------------------------------------------
                                                                             AGGREGATE
- --------------------------------------------------------------------------------------------------------------
        NATURE OF COMMITMENTS                 TERM           VOLUME         PRICE/COST    PRICE PER THOUSAND
                                                           (MMCF/DAY)                         CUBIC FEET
- --------------------------------------------------------------------------------------------------------------
<S>                                      <C>               <C>             <C>            <C>

                                                                           ($ MILLIONS)
- --------------------------------------------------------------------------------------------------------------
Natural gas pipeline commitments:
- --------------------------------------------------------------------------------------------------------------
     Nova                                1998-2008             **               30               $0.17
- --------------------------------------------------------------------------------------------------------------
     Westcoast Energy                    2001-2006             27                9               $0.23
- --------------------------------------------------------------------------------------------------------------
     Foothills                           1997-2003             16                1               $0.08
- --------------------------------------------------------------------------------------------------------------
     Northern Border                     1997-2003             14                5               $0.52
- --------------------------------------------------------------------------------------------------------------
     Alberta Natural Gas                 1991-2008             41                8               $0.07
- --------------------------------------------------------------------------------------------------------------
     Pacific Gas Transmission            1995-2023             40               164              $0.49
- --------------------------------------------------------------------------------------------------------------
</TABLE>

** volume varies on an annual basis

The  Company's  Natural Gas  business  has  entered  into  numerous  natural gas
purchase  and  sale  commitments,  aggregating  90  mmcf/day  and 180  mmcf/day,
respectively. Purchase commitment terms vary from one to three years and pricing
varies,  representing  a combination  of fixed and  index-based  pricing.  Sales
commitments  consist of both short- and long- term contracts ranging from one to
eight years in duration,  with varying pricing  generally based on a combination
of fixed and index-based terms.

Oil Sands has also entered into  long-term  contracts to sell crude oil products
to customers,  some of which are  described  under the heading,  "Revenues  from
Synthetic  Crude Oil and  Diesel",  in the "Oil  Sands"  section of this  Annual
Information  Form.  In addition,  the Company  enters into crude oil and foreign
currency swap and option contract to protect its future Canadian dollar earnings
and cash flows from the potential  adverse impact of low petroleum prices and an
unfavourable  U.S./Canadian  dollar exchange rates.  For further  particulars of
these hedging  arrangements,  see the information  under the heading  "Hedging",
under "Risk/Success Factors Affecting Performance" in the "Corporate" section of
the Company's MD&A,  incorporated by reference  herein,  and Note 17 to Suncor's
2001 Consolidated Financial Statements,  which note is incorporated by reference
herein.

Also see Note 14 to Suncor's 2001 Consolidated Financial Statements,  which note
is incorporated by reference herein, for a further  description of the Company's
operating commitments for 2002 and subsequent years.


                      MANAGEMENT'S DISCUSSION AND ANALYSIS

Suncor's MD&A is  incorporated  by reference  into and forms an integral part of
this  Annual  Information  Form,  and  should  be read in  conjunction  with the
consolidated comparative financial statements and the notes thereto.


                     MARKET FOR THE SECURITIES OF THE ISSUER

The common shares of Suncor are listed on The Toronto Stock  Exchange in Canada,
and on the  New  York  Stock  Exchange  in the  United  States.  To the  best of
management's  knowledge,   approximately  50%  of  Suncor's  common  shares  are
beneficially  held by residents of the United States.  Suncor's 9.05%  preferred
securities  are listed on The Toronto  Stock  Exchange in Canada,  and  Suncor's
9.125%  preferred  securities  are listed on the New York Stock  Exchange in the
United States.


                                                                            36

<PAGE>


                             DIRECTORS AND OFFICERS

As of the date  hereof,  Suncor's  Board of  Directors  is  comprised  of eleven
directors.  The term of office of each  director is from the date of the meeting
at which he or she is  elected or  appointed  until the next  annual  meeting of
shareholders  or  until a  successor  is  elected  or  appointed.  The  Board of
Directors  is  required  to have,  and has,  an Audit  Committee.  The  Board of
Directors also has a Board Policy,  Strategy Review and Governance Committee,  a
Human  Resources and  Compensation  Committee,  and an  Environment,  Health and
Safety Committee.

The  following  table sets out  certain  information  with  respect to  Suncor's
directors.

<TABLE>
<CAPTION>



                                                                                         VOTING SECURITIES OF
                                                            PRINCIPAL OCCUPATION         SUNCOR BENEFICIALLY
                                                             OR EMPLOYMENT, AND           OWNED OR OVER WHICH
                                                            MAJOR POSITIONS AND          CONTROL OR DIRECTION
 NAME AND MUNICIPALITY OF        PERIODS OF SERVICE         OFFICES IN THE LAST           IS EXERCISED AS AT
         RESIDENCE                  AS A DIRECTOR                FIVE YEARS              FEBRUARY 28, 2002(1)
- ----------------------------     --------------------      -----------------------      ----------------------
<S>                              <C>                       <C>                          <C>

Mel Benson(2) (5)                April 19, 2000 to         Management Services           2,565 Common Shares
Calgary, Alberta                 Present                   Consultant
                                                                                          367 Deferred Share
                                                                                               Units(3)

Brian A. Canfield(2)(4)          November 10, 1995         Chairman                      6,000 Common Shares
Point Roberts, Washington        to Present                TELUS Corporation (a
                                                           telecommunications            3,770 Deferred Share
                                                           company)                            Units(3)

Bryan P. Davies(2)(5)            January 28, 1991          Senior Vice                   6,200 Common Shares
Etobicoke, Ontario               to April 23, 1996         President, Regulatory
                                                           Affairs, Royal Bank           1,644 Deferred Share
                                 April 19, 2000 to         of Canada (a                        Units(3)
                                 Present                   chartered banking
                                                           institution)

John T. Ferguson(5)(6)           November 10, 1995         Chairman, Princeton           8,374 Common Shares
Edmonton, Alberta                to Present                Developments Ltd. (a
                                                           real estate                   1,955 Deferred Share
                                                           development company),               Units(3)
                                                           Chair of the Board,
                                                           TransAlta Corporation
                                                           (an electric utility
                                                           company)



</TABLE>

                                                                             37


<PAGE>


<TABLE>
<CAPTION>



                                                                                         VOTING SECURITIES OF
                                                            PRINCIPAL OCCUPATION         SUNCOR BENEFICIALLY
                                                             OR EMPLOYMENT, AND           OWNED OR OVER WHICH
                                                            MAJOR POSITIONS AND          CONTROL OR DIRECTION
 NAME AND MUNICIPALITY OF        PERIODS OF SERVICE         OFFICES IN THE LAST           IS EXERCISED AS AT
         RESIDENCE                  AS A DIRECTOR                FIVE YEARS              FEBRUARY 28, 2002(1)
- ----------------------------     --------------------      -----------------------      ----------------------
<S>                              <C>                       <C>                          <C>
Richard L. George(6)             February 1, 1991          President and Chief           99,277 Common Shares
Calgary, Alberta                 to Present                Executive Officer,
                                                           Suncor Energy Inc.(7)

Poul Hansen(2)(5)(9)             April 23, 1996 to         Chairman and General          7,291 Common Shares
Vancouver, British Columbia      Present                   Manager, Sperling
                                                           Hansen Associates
                                                           Inc. (an
                                                           environmental
                                                           engineering
                                                           consulting company)

John R. Huff(4)(6)               January 30, 1998          Chairman and Chief            10,354 Common Shares
Houston, Texas                   to Present                Executive Officer,
                                                           Oceaneering                   4,047 Deferred Share
                                                           International, Inc.                 Units(3)
                                                           (an oilfield services
                                                           company)

Robert W. Korthals(5)(6)(8)      April 23, 1996 to         Corporate Director            8,000 Common Shares
Toronto, Ontario                 Present
                                                                                         3,343 Deferred Share
                                                                                              Units (3)

M. Ann McCaig(2)(4)              October 1, 1995 to        President, VPI                5,144 Common Shares
Calgary, Alberta                 Present                   Investments Ltd. (a
                                                           private investment            4,227 Deferred Share
                                                           holding company)                    Units(3)

JR Shaw(4)(6)                    January 30, 1998          Executive Chair, Shaw         41,600 Common Shares
Calgary, Alberta                 to Present                Communications Inc.
                                                           (a diversified                6,234 Deferred Share
                                                           communications                      Units(3)
                                                           company); Chairman
                                                           of the Board of
                                                           Directors of Suncor
                                                           Energy Inc.

</TABLE>


                                                                            38

<PAGE>

<TABLE>
<CAPTION>



                                                                                         VOTING SECURITIES OF
                                                            PRINCIPAL OCCUPATION         SUNCOR BENEFICIALLY
                                                             OR EMPLOYMENT, AND           OWNED OR OVER WHICH
                                                            MAJOR POSITIONS AND          CONTROL OR DIRECTION
 NAME AND MUNICIPALITY OF        PERIODS OF SERVICE         OFFICES IN THE LAST           IS EXERCISED AS AT
         RESIDENCE                  AS A DIRECTOR                FIVE YEARS              FEBRUARY 28, 2002(1)
- ----------------------------     --------------------      -----------------------      ----------------------
<S>                              <C>                       <C>                          <C>

W. Robert Wyman(4)(6)(9)         November 25, 1987         Retired Chairman of           32,400 Common Shares
West Vancouver, British          to Present                the Board of
Columbia                                                   Directors of Suncor           4,138 Deferred Share
                                                           Energy Inc.                         Units(3)

</TABLE>


Notes:

(1)      The information relating to holdings of Common Shares, not being within
         the knowledge of Suncor, has been furnished by the respective  nominees
         individually.  Fractional  Common  Shares have been  excluded  from the
         numbers  shown.  Certain of the Common Shares held by Mr.  George,  Mr.
         Hansen and Mr. Shaw are held jointly with their respective spouses. The
         number of Common  Shares  held by Mr.  George  includes  82,486  Common
         Shares  over  which he  exercises  control or  direction  but which are
         beneficially owned by members of his family. Certain Common Shares held
         by Mr.  Benson  (400) and Mr. Shaw  (1,000) are  beneficially  owned by
         their respective  spouses,  but they  respectively  exercise control or
         direction over such shares.

(2)      Member of the Environment, Health and Safety Committee.

(3)      Deferred Share Units (DSU's) are not voting securities but are included
         for informational purposes as they are Common Share equivalents.

(4)      Member of the Human Resources and Compensation Committee.

(5)      Member of the Audit Committee.

(6)      Member of the Board Policy, Strategy Review and Governance Committee.

(7)      Mr. George also serves as director and/or officer of certain
         subsidiaries of Suncor.

(8)      In 1998, Mr. Korthals was a director of Anvil Range Mining Corporation,
         which sought protection under the COMPANIES  CREDITORS  ARRANGEMENT ACT
         (Canada).

(9)      Retiring from the Board in April 2002.

Each of the nominees has been engaged in the principal  occupation  (or in other
executive capacities for the same, affiliated or predecessor entities) indicated
above for the past five years,  except for Mr. Benson, who from 1996 to 2000 was
the Senior Operations Advisor, African Development, Exxon Co. International, Mr.
Shaw, who became the Chairman of the Board of Suncor in 2001 and Mr. Wyman,  who
in 1999 and  prior  thereto  was Vice  Chairman  of the  Board of  Directors  of
Fletcher Challenge Canada Limited.

The following are officers of the Corporation. Except where otherwise indicated,
the persons  named in the table below held the  offices set out  opposite  their
respective names as at December 31, 2001 and as of the date hereof.


                                                                           39

<PAGE>



<TABLE>
<CAPTION>

         NAME AND MUNICIPALITY OF RESIDENCE                                      OFFICE(1)
         ----------------------------------                                      ---------
         <S>                                                  <C>
         JR SHAW..............................................Chairman of the Board
         Calgary, Alberta

         RICHARD L. GEORGE....................................President and Chief Executive Officer
         Calgary, Alberta

         M.M. (MIKE) ASHAR....................................Executive Vice President, Oil Sands
         Fort McMurray, Alberta

         DAVID W. BYLER.......................................Executive Vice President, Natural Gas and Renewable
         M.D. of Rockyview, Alberta                           Energy

         MICHAEL W. O'BRIEN...................................Executive Vice President, Corporate Development and
         Canmore, Alberta                                     Chief Financial Officer

         THOMAS L. RYLEY......................................Executive Vice President, Sunoco
         Toronto, Ontario

         TERRENCE J. HOPWOOD..................................Senior Vice President and General Counsel
         Calgary, Alberta

         SUE LEE..............................................Senior Vice President, Human Resources and
         Calgary, Alberta                                     Communications

         KEVIN NABHOLZ                                        Senior Vice President, Major Projects
         Fort McMurray, Alberta

         J. KENNETH ALLEY.....................................Vice.President, Finance
         Calgary, Alberta

         JANICE B. ODEGAARD...................................Vice.President, Associate General Counsel and
         Calgary, Alberta                                     Corporate Secretary
</TABLE>


Note:

(1)      The principal  occupation of each officer is the specified  office with
         Suncor except Mr. Shaw, who is also Executive Chair of Shaw
         Communications Inc.

All of the foregoing officers of the Company have, for the past five years, been
actively engaged as executives or employees of Suncor or its affiliates,  except
Mr. Shaw, as described in Note (1) to the above table.

The  percentage  of Common  Shares of Suncor  owned  beneficially,  directly  or
indirectly,  or over  which  control  or  direction  is  exercised  by  Suncor's
directors and senior officers, as a group, is less than 1%.


                             ADDITIONAL INFORMATION

Copies of the  documents  set out below may be  obtained  without  charge by any
person upon request to the Company at 112 - 4 Avenue S.W., Calgary, Alberta, T2P
2V5, by calling 1-800-558-9071, by e-mail request to info@suncor.com.
                                                     ----------------

(i)      The current Suncor Annual Information Form together with any pertinent
         information incorporated by reference therein;

(ii)     The  current  Suncor  comparative  financial  statements  for the  most
         recently  completed  financial


                                                                            40

<PAGE>


         year and the report of the auditors relating thereto, together with any
         subsequent interim financial statements;

(iii)    Suncor's management proxy circular in respect of its most recent annual
         meeting of shareholders that involved the election of directors; and

(iv)     Any other documents incorporated by reference into Suncor's most recent
         preliminary   short  form   prospectus  or  short  form  prospectus  if
         securities of Suncor are in the course of distribution pursuant to such
         documents.

Additional  information,  including  directors' and officers'  remuneration  and
indebtedness,  principal  holders of  Suncor's  securities,  options to purchase
securities and interests of insiders in material transactions, where applicable,
is  contained in Suncor's  most recent  management  proxy  circular for its most
recent  annual  meeting  of its  shareholders  that  involved  the  election  of
directors.  Additional financial information is provided in Suncor's comparative
financial statements for its most recently completed financial year.


<PAGE>

                  UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.   UNDERTAKING

     Suncor Energy Inc. (the "Registrant") undertakes to make available, in
person or by telephone, representatives to respond to inquiries made by the
staff of the Securities and Exchange Commission ("SEC"), and to furnish
promptly, when requested to do so by the SEC staff, information relating to the
securities in relation to which the obligation to file an annual report on Form
40-F arises or transactions in said securities.

B.   CONSENT TO SERVICE OF PROCESS

     The Registrant has filed previously with the SEC a Form F-X in connection
with the Common Shares.


<PAGE>



                                   SIGNATURES


Pursuant  to the  requirements  of the  Securities  Exchange  Act of  1934,  the
registrant  has duly  caused  this  report  to be  signed  on its  behalf by the
undersigned, thereunto duly authorized.




                                    SUNCOR ENERGY INC.


Date:  March 28, 2002               BY:     "DAVID W. BYLER"
                                        -----------------------------------
                                        DAVID W. BYLER
                                        Executive Vice President, Natural
                                        Gas and Renewable Energy





<PAGE>


                                  EXHIBIT INDEX

<TABLE>
<CAPTION>
   EXHIBIT                                     DESCRIPTION OF EXHIBIT
- -------------                                  ----------------------
<S>                     <C>
EXHIBIT 1               Reconciliation to U.S. GAAP

EXHIBIT 2               Audited  Consolidated  Financial  Statements  of Suncor  Energy Inc. for the
                        fiscal year ended December 31, 2001

EXHIBIT 3               Management's  Discussion and Analysis for the fiscal year ended December 31,
                        2001, dated February 28, 2002

EXHIBIT 4               Excerpt from pages 69 and 70 of Suncor  Energy  Inc.'s 2001 Annual Report to
                        Shareholders

EXHIBIT 5               Consent of PricewaterhouseCoopers LLP

EXHIBIT 6               Consent of Gilbert Laustsen Jung Associates Ltd.
</TABLE>








</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-1
<SEQUENCE>3
<FILENAME>a2075015zex-1.txt
<DESCRIPTION>EXHIBIT 1
<TEXT>
<PAGE>








                               SUNCOR ENERGY INC.

                         2001 RECONCILIATION OF RESULTS
                         FROM CANADIAN GAAP TO U.S. GAAP
                      (ALL FIGURES ARE IN CANADIAN DOLLARS)



<PAGE>


CANADIAN AND UNITED STATES ACCOUNTING PRINCIPLES

The consolidated financial statements of Suncor Energy Inc. have been prepared
in accordance with Canadian generally accepted accounting principles (GAAP). The
measurement adjustments under U.S. GAAP result in changes to the Consolidated
Statements of Earnings and Consolidated Balance Sheets of the company as
follows:

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
                                                                2001                    2000                      1999
- -------------------------------------------------------------------------------------------------------------------------------
($ millions)                                               CDN        US            CDN         US           CDN        US
- -------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>           <C>          <C>          <C>         <C>        <C>
REVENUES
  Sales & other operating revenues  (1) (8)                3,990        4,077        3,385        3,481       2,383      2,448
  Interest                                                     5            5            3            3           4          4
  Other income (8)                                             -           20            -            -           -          -
- -------------------------------------------------------------------------------------------------------------------------------
                                                           3,995        4,102        3,388        3,484       2,387      2,387
- -------------------------------------------------------------------------------------------------------------------------------
EXPENSES
  Purchases of crude oil and products                      1,391        1,391          807          807         519        519
  Operating, selling and general  (1) (2) (8)              1,010        1,148          918        1,036         774        791
  Exploration                                                 22           22           53           53          40         40
  Royalties                                                  134          134          199          199          99         99
  Taxes other than income taxes                              367          367          361          361         334        334
  Depreciation, depletion & amortization  (3)                360          365          365          372         318        318
  Gain on disposal of assets                                  (7)          (7)        (148)        (148)        (34)       (34)
  Write down of oil shale assets  (4)                         48          (71)         125          244           -          -
  Restructuring                                              (2)          (2)           65           65           -          -
  Start-up expenses- Project Millennium                      141          141           15           14           -          1
                                - Other  (5)                   -          (17)           -          (13)          -         31
  Interest (3)                                                18           62            8           40          26         59
- -------------------------------------------------------------------------------------------------------------------------------
                                                           3,482        3,533        2,768        3,030       2,076      2,158
- -------------------------------------------------------------------------------------------------------------------------------
                                                             513          569          620          454         311        294
EARNINGS BEFORE INCOME TAXES
- -------------------------------------------------------------------------------------------------------------------------------
PROVISION FOR (RECOVERY OF) INCOME TAXES
  Current (8)                                                  4           (7)           45          45          29         29
  Future (3) (4) (5) (6) (8)                                  121         157           198         138          96         87
- -------------------------------------------------------------------------------------------------------------------------------
                                                              125         150           243         183         125        116
- -------------------------------------------------------------------------------------------------------------------------------
                                                              388         419           377         271         186        178
NET EARNINGS
  Dividends on preferred securities (3)                       (26)          -          (26)           -         (22)          -
- -------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS              362         419           351         271         164        178
PER COMMON SHARE

NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
  Basic                                                      1.63        1.88          1.58        1.22        0.74       0.81
  Diluted                                                    1.61        1.86          1.57        1.21        0.73       0.80
- -------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME, NET OF TAX
  Minimum pension liability (7)                               N/A         (28)         N/A           (2)        N/A          6
  Hedging activities  (8)                                     N/A          29          N/A            -         N/A          -
- -------------------------------------------------------------------------------------------------------------------------------

OTHER COMPREHENSIVE INCOME                                    N/A           1           N/A         (2)         N/A          6
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>

* Per share calculations, for both current and prior years, reflect a
two-for-one split of the company' common shares during 2000.


<PAGE>

<TABLE>
<CAPTION>
                                                            AS AT                              as at
                                                      DECEMBER 31, 2001                  December 31, 2000

                                                        ($ MILLIONS)                       ($ millions)

                                                    AS               U.S.              As               U.S.
                                                 REPORTED            GAAP           reported            GAAP
                                                ------------      ------------     ------------      ------------
<S>                                                 <C>               <C>              <C>               <C>
Current assets (8)                                    622               694              665               666
Capital assets, net (3)                             7,141             7,174            5,883             5,768
Deferred charges and
other (3) (7)                                         199               210              166               173
Future income taxes (3) (7)                           132               159              119               125
                                                ------------      ------------     ------------      ------------
Total assets                                        8,094             8,237            6,833             6,732
                                                ============      ============     ============      ============
Current liabilities (8)                               773               806              837               837
Long-term borrowings (3)                            3,113             3,649            2,192             2,716
Accrued liabilities and  other (2) (7)                251               336              252               277

Future income taxes (3)                             1,180             1,220            1,080             1,042

Equity:
 Share capital and retained earnings (3)            2,777             2,225            2,472             1,862
 Accumulated other comprehensive
 Income (7) (8)                                       N/A                 1              N/A                (2)
                                                ------------      ------------     ------------      ------------
                                                    2,777             2,226            2,472             1,860
                                                ------------      ------------     ------------      ------------
Total liabilities and
  shareholders' equity                              8,094             8,237            6,833             6,732
                                                ============      ============     ============      ============
</TABLE>


(1)  Under U.S. GAAP (EITF 00 - 10, "Accounting for Shipping and Handling Fees
     and Costs"), amounts billed to customers for shipping and handling costs
     should be classified as revenues, and shipping and handling costs incurred
     that relate to amounts billed to customers should be classified as expenses
     in the earnings statement.

     The company's accounting policy is to classify shipping and handling costs
     incurred that relate to amounts billed to customers as follows:
     o    As "Operating, selling and general" for downstream refining and
          marketing operations; and
     o    Deducted from "Sales and other operating revenues" for upstream
          operations.
     The company's accounting policy is acceptable under Canadian GAAP, which
     does not specifically address accounting for shipping and handling costs.
     The impact of EITF 00 - 10, which is one of reclassification only and does
     not affect net earnings, is to increase 2001 "Sales and other operating
     revenues" and "Operating, selling and general" expenses by $95 million
     (2000 - $96 million; 1999 - $65 million).

(2)  Under Canadian GAAP, no compensation cost has been recognized in the
     consolidated statements of earnings for common share options granted to
     executives, certain employees and non-employee directors under the
     company's share option programs. Had compensation cost been determined on
     the basis of fair values in accordance with SFAS No. 123, "Accounting for
     Stock-Based Compensation", 2001 net earnings would have been lower by $9
     million (2000 - $7 million; 1999 - $5 million) and 2001 earnings per share
     would have been lower by $0.04 (2000 - $0.03; 1999 - $0.02).

     Under U.S. GAAP (Accounting Principles Board Opinion No. 25, "Accounting
     for Stock Issued to Employees"), compensation expense is also recorded,
     over the same vesting period, for the portion of awards payable in common
     shares to employees under the company's long-term employee incentive plans.

<PAGE>

     The impact of this GAAP difference is to decrease 2001 net earnings by $14
     million (2000 - $22 million; 1999 - nil). Since the common shares awarded
     under these plans are to be issued from treasury, the income tax impact on
     the company is nil.

(3)  Under Canadian GAAP, the preferred securities issued in 1999 are classified
     as share capital in the consolidated balance sheets and the interest
     distributions thereon, net of income taxes, are accounted for as dividends
     in the consolidated statements of changes in shareholders' equity. Under US
     GAAP, the preferred securities are classified as long-term borrowings in
     the consolidated balance sheets and the interest distributions thereon and
     the related income tax impact are accounted for in the consolidated
     statements of earnings. Under US GAAP, the portion of the preferred
     securities that is denominated in US dollars, U.S. $163 million, is valued
     at the exchange rate in effect at the year end.

     Under Canadian GAAP, issue costs of the preferred securities, net of the
     related income tax credits, are charged against share capital. Under US
     GAAP, issue costs are deferred on the consolidated balance sheets and
     amortized to earnings over the term of the related long-term borrowings.

     This difference in classification decreased 2001 net earnings by $28
     million after income tax recoveries of $23 million (2000 decreased net
     earnings by $31 million after income tax recoveries of $23 million; 1999 -
     decreased net earnings by $20 million after income tax recoveries of $17
     million). However, the interest distributions on the preferred securities
     above are eligible for interest capitalization under U.S. GAAP, resulting
     in an increase in 2001 net earnings of $9 million after future income taxes
     of $5 million (2000 - increased net earnings by $9 million after future
     income taxes of $6 million; 1999 - increased net earnings by $2 million
     after future income taxes of $2 million).

     The net effect of all of the above differences decreased 2001 net earnings
     by $27 million (2000 - $22 million; 1999 - $18 million).

     These preferred securities, which are publicly traded, had a fair value,
     based on quoted market prices, of $575 million at December 31, 2001 (2000 -
     $544 million; 1999 - $492 million).

     Under Canadian GAAP, the 2001 interest distributions of $48 million (2000 -
     $47 million; 1999 - $37 million) on the preferred securities are classified
     as financing activities in the consolidated statements of cash flows. Under
     U.S. GAAP (SFAS No.95, "Statement of Cash Flows"), the interest
     distributions and the 2001 amortization of issue costs of $3 million (2000
     - $7 million) are classified as operating activities.

(4)  Effective April 5, 2001, the company sold its interest in the Stuart oil
     shale project and, as a result, the company wrote off the carrying value of
     the interest.

     Under Canadian GAAP, the carrying value of the interest in the Stuart oil
     shale project is calculated as the estimated future cash flow from use
     together with its residual value, calculated on an undiscounted basis.

     Under U.S. GAAP (SFAS 121, "Accounting for the Impairment of Long-Lived
     Assets and for Long-Lived Assets to be Disposed of"), the carrying value of
     the interest in the Stuart oil shale project is calculated as the estimated
     net cash flows, but calculated on a discounted basis.

     As a result of this GAAP difference in the calculation of the carrying
     value of the interest in the Stuart oil shale project, the write down in
     2000 and the subsequent write off in 2001 of the carrying value of the
     interest is different under US GAAP. The impact of this GAAP difference is
     to increase 2001 net earnings by $64 million, after income taxes of $55
     million (2000 decrease net earnings by $64 million, after income tax
     recoveries of $55 million).

(5)  Under U.S. GAAP (AICPA Statement of Position 98-5, "Reporting the Costs of
     Start-Up Activities"), all costs relating to start-up activities are
     expensed as incurred. Under Canadian GAAP, certain costs relating to the
     company's start-up activities are initially capitalized and then amortized
     over the estimated useful lives of the related assets.

     Under Canadian GAAP, in 2001, the remaining costs associated with the
     Stuart oil shale project that were previously capitalized were written
     down. Under U.S. GAAP, these start-up costs were expensed in 1999.

<PAGE>

     These differences increased 2001 net earnings by $10 million after related
     income taxes of $7 million (2000 - increased net earnings by $8 million
     after related income taxes of $6 million; 1999 - decreased net earnings by
     $12 million after related income tax credits of $8 million).

(6)  In December 2000, the Canadian Federal Department of Finance released draft
     legislation that merged federal budget proposals announced earlier in the
     year. The draft legislation was enacted into law in June, 2001. Under
     Canadian GAAP, the budget proposals were considered to be substantially
     enacted at December 31, 2000. Accordingly, future income tax assets and
     liabilities at December 31, 2000 were measured taking into account the
     reduction in tax rates presented in the draft legislation.

     Under US GAAP, in accordance with SFAS 109 "Accounting for Income Taxes",
     changes in tax rates and tax laws are considered only after they have been
     enacted into law.

     The impact of this GAAP difference was to increase 2001 net earnings by $6
     million (2000 - decrease net earnings by $6 million; 1999 - nil).

(7)  Under U.S. GAAP (SFAS No.87, "Employers' Accounting for Pensions"),
     recognition of an additional minimum pension liability is required when the
     accumulated benefit obligation exceeds the fair value of plan assets to the
     extent that such excess is greater than accrued pension costs otherwise
     recorded. No such adjustment is required under Canadian GAAP.

     Recording the additional minimum liability affects the consolidated balance
     sheet only and has no impact on net earnings or cash flows. An intangible
     asset equal to the amount of any unamortized liabilities arising from plan
     amendments is recognized. Any excess of the additional minimum liability
     over the amount recognized as an intangible asset is recorded as a separate
     component of equity (net of any related income tax recoveries), and is
     included as a component of comprehensive income under SFAS No. 130,
     "Reporting Comprehensive Income".

     At December 31, 2001, an additional minimum pension liability of $52
     million (2000 - $3 million), an intangible asset of $12 million (2000 -
     nil) and other comprehensive income of $28 million (2000 - $2 million), net
     of income tax recoveries of $12 million (2000 - $1 million), was recognized
     under U.S. GAAP. The impact of this GAAP difference is to decrease 2001
     other comprehensive income by $28 million (2000 - decrease of $2 million;
     1999 - increase of $6 million).

(8)  Derivative Financial Instruments

     Effective January 1, 2001, the company adopted SFAS 133 "Accounting for
     Derivative Instruments and Hedging Activities", as amended by SFAS 138,
     (the Standards), which establishes accounting and reporting standards for
     derivative instruments, including certain derivative instruments embedded
     in other contracts, and for hedging activities. Generally, all derivatives,
     whether designated in hedging relationships or not, and excluding normal
     purchase and sales, are required to be recorded on the balance sheet at
     fair value. If the derivative is designated as a fair value hedge, the
     effective portions of the changes in the fair value of the derivative, and
     changes in the fair value of the hedged item attributable to the hedged
     risk, are recognized in the income statement. If the derivative is
     designated as a cash flow hedge, the effective portions of the changes in
     fair value of the derivative are recorded in other comprehensive income
     (OCI) and are recognized in the income statement when the hedged item is
     recognized. Accordingly, ineffective portions of changes in the fair value
     of hedging instruments are recognized in earnings immediately. Gains or
     losses arising from hedging activities, including the ineffective portion,
     are reported in the same earnings statement caption as the hedged item.
     Gains or losses from derivative instruments for which hedge accounting is
     not applied are reported in other income.

     In accordance with the transition provisions of the Standards, the company
     recorded the following after-tax cumulative adjustments on January 1, 2001:

      A decrease in OCI of $173 million, net of future income tax recoveries of
     $87 million and an increase in 2001 US GAAP earnings of $47 million net of
     future income taxes of $28 million. Assets increased by $89 million and
     liabilities increased by $274 million as a result of recording all
     derivative instruments on the consolidated Balance Sheet at fair value.



<PAGE>

     Commodity Price Risk
     The company periodically enters into derivative financial instrument
     contracts such as forwards, futures, swaps and options to hedge against the
     potential adverse impact of market prices for its petroleum and natural gas
     products. The company manages its Canadian dollar crude price exposure by
     entering into US dollar WTI derivative transactions and in some instances
     combines US dollar WTI derivative transactions and Canadian/US foreign
     exchange derivative contracts. The company has hedged future cash flows
     subject to commodity price risk for up to four years.

     Interest Rate Risk
     The company also periodically enters into derivative financial instrument
     contracts such as interest rate swaps as part of its risk management
     strategy to minimize exposure to changes in cash flows of interest bearing
     debt. The company has interest rate derivatives outstanding for up to two
     years classified as cash flow hedges.

     During 1996, the company entered into a cross currency swap transaction to
     convert its 7.4% Debentures to a 6.2% fixed interest rate U.S. dollar
     obligation of approximately $91 million. Later in 1996, the company entered
     into another cross currency interest rate swap transaction to convert the
     U.S. $91 million obligation back to a fixed rate Canadian $125 million
     obligation. The net effect of the two swap transactions was to reduce the
     effective interest rate on the debentures from 7.3% (7.4% coupon rate) to
     5.5%. The transactions did not qualify for hedge accounting. In 2001, the
     company monetized the two swap transactions and realized a gain of $5.7
     million of which, $4.9 million was deferred for Canadian purposes. The
     entire gain was recognized in current period earnings for US purposes.

     Inventory Monetization
     In 1999, the company sold inventory and subsequently entered into a
     derivative contract with an option to repurchase the inventory at the end
     of five years. The company realized an economic benefit as a result of
     liquidating a portion of its inventory. The derivative did not qualify for
     hedge accounting because the company did not have purchase price risk
     associated with the repurchase of the inventory. This derivative does not
     represent a US GAAP difference as the company records this derivative at
     fair value for Canadian purposes.

     During the year, the company settled early a long-term contract that was
     designated as a hedge under Canadian GAAP. Under US GAAP, the long-term
     contract was designated as a normal purchase and sale. Accordingly, the
     payment of $29 million was deferred for Canadian purposes and for US
     purposes, was recognized in current period earnings. For Canadian GAAP, the
     $29 million will be recognized in income as the hedged item is settled.

<PAGE>

     A reconciliation of changes in OCI attributable to derivatives and hedging
     activities is as follows:

<TABLE>
<CAPTION>
     ------------------------------------------------------------------------------------------------------
                                                                                         OCI
     ---------------------------------------------------------------------- -------------------------------
                                                                                     (millions $)
     ------------------------------------------------------------------------------------------------------
     <S>                                                                                             <C>
     Net derivative losses, net of $87 million future tax recoveries,
     arising from implementation of the Standards                                                    (173)
     ------------------------------------------------------------------------------------------------------
     Current period net hedging gains arising from cash flow hedges, net
     of $50 million future tax expense                                                                 79
     ------------------------------------------------------------------------------------------------------
     Net hedging losses at beginning of the period reclassified to earnings
     during the period, net of $62 million future tax recoveries
                                                                                                      123
     ------------------------------------------------------------------------------------------------------
     Total net hedging gain net of future tax of $13 million                                           29
     ------------------------------------------------------------------------------------------------------
</TABLE>

     During the year, assets increased by $93 million and liabilities increased
     by $44 million as a result of recording all derivative instruments on the
     consolidated Balance Sheet at fair value.

     The loss associated with hedge ineffectiveness on derivative contracts
     designated as cash flow hedges during the period was $25 million net of $12
     million tax. The company estimates that $3 million of hedging losses net of
     future tax recoveries of $2 million will be reclassified from OCI to
     current period earnings within the next 12 months as a result of forecasted
     sales occurring. There were no derivative instruments designated as fair
     value hedges.

     Implementation of the standards did not affect the company's cash flows or
     liquidity. The Standards are complex and subject to a potentially wide
     range of interpretations in their application. The FASB continues to
     consider several issues, and the potential exists for additional issues to
     be brought under its review. Therefore, if subsequent FASB interpretations
     of the Standards are different than the company's initial application, it
     is possible that the impact of the company's application of the Standards,
     as described above, will be modified.

RECENTLY ISSUED ACCOUNTING STANDARDS

ASSET RETIREMENT OBLIGATIONS

     In August 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations"
     was issued. This statement changes the method and timing of accruing for
     costs arising from legal obligations associated with the retirement of
     tangible capital assets and the associated asset retirement costs. The
     company will evaluate the impact and timing of implementing SFAS 143, which
     must be adopted no later than January 1, 2003.

IMPAIRMENT OF LONG-LIVED ASSETS

     In August 2001, SFAS No. 144, "Accounting for the Impairment and Disposal
     of Long-Lived Assets" was issued. SFAS 144 supersedes SFAS No. 121,
     "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
     Assets to Be Disposed Of" but retains its fundamental provisions for
     recognition and measurement of impairment of long-lived assets to be held
     and used, and measurement of long-lived assets to be disposed of by sale.

     SFAS 144 also supersedes the accounting and reporting provisions of
     Accounting Principles Board Opinion No. 30, "Reporting the Results of
     Operations - Reporting the Effects of Disposal of a Segment of a Business,
     and Extraordinary, Unusual and Infrequently Occurring Events and
     Transactions" for segments of a business to be disposed of, but retains APB
     30's requirement to report discontinued operations separately from
     continuing operations and extends that reporting to a component of an
     entity that either has been disposed of or is classified as held for sale.
     The company will evaluate the impact of implementing SFAS 144, which must
     be adopted on January 1, 2002.

HEDGING RELATIONSHIPS

     In 2001, the Accounting Standards Board of the CICA approved a new
     Accounting Guideline, "Hedging Relationships", which deals with the
     identification, documentation and effectiveness of hedging

<PAGE>

     relationships for the purpose of applying hedge accounting. The Guideline
     is meant to codify certain best practices and, wherever possible, harmonize
     with certain requirements of U.S. GAAP, in particular SFAS No. 133,
     "Accounting for Derivative Instruments and Hedging Activities", as amended
     by SFAS No. 138. The company will evaluate the impact of implementing the
     new standard, which must be adopted no later than January 1, 2003.

FOREIGN CURRENCY TRANSLATION

     In 2001, the Accounting Standards Board of the Canadian Institute of
     Chartered Accountants approved amendments to CICA Handbook Section 1650,
     Foreign Currency Translation. The amendments to Section 1650, applicable
     for the company in fiscal 2002 with retroactive application, eliminate the
     deferral and amortization method for unrealized translation gains and
     losses on non current monetary assets and liabilities and require the
     disclosure of exchange gains and losses included in net income.

STOCK-BASED COMPENSATION

     In 2001, the Accounting Standards Board of the Canadian Institute of
     Chartered Accountants approved amendments to CICA Handbook Section 3870,
     Stock-Based Compensation and Other Stock-Based Payments. Under the
     amendments to Section 3870, stock-based payments to non-employees and
     direct awards of stock to employees and non-employees will be accounted for
     using a fair value method of accounting. The standard provides for the
     recognition of compensation expense based on fair values or a disclosure
     only basis of accounting. The standard is effective for years beginning on
     or after January 1, 2002. The company will apply this standard in fiscal
     2002 and has not yet determined the impact.

Implementation of the above noted accounting standards will not affect the
company's cash flows or liquidity.

OIL AND GAS DATA

     The following data supplements oil and gas disclosure in the company's
     Annual Report, and is provided in accordance with the provision of the
     United States Financial Accounting Standards Board's Statement No. 69. This
     statement requires disclosure about conventional oil and gas activities
     only, and therefore the company's oil sands activities are excluded.

     COSTS INCURRED

<TABLE>
<CAPTION>
                                                                        COSTS INCURRED
                                                               FOR THE YEARS ENDED DECEMBER 31,
                                                                                   ------------
                                                            2001             2000             1999
                                                            ----             ----             ----
                                                                         ($ MILLIONS)
<S>                                                          <C>              <C>              <C>
     Property acquisition costs
       Proved properties..................................     -                5                -
       Unproved properties................................    11               10               48
     Exploration costs....................................    35               40               64
     Development costs....................................    84               69               70
                                                             ---              ---              ---
                                                             130              124              182
                                                             ===              ===              ===
</TABLE>


      RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION

<TABLE>
<CAPTION>
                                                                   RESULTS OF OPERATIONS FOR
                                                                     OIL AND GAS PRODUCTION
                                                                FOR THE YEARS ENDED DECEMBER 31,
                                                                                    ------------
                                                             2001             2000             1999
                                                             ----             ----             ----
                                                                          ($ MILLIONS)
<S>                                                          <C>              <C>              <C>
      Revenues
        Sales to unaffiliated customers...................   128              139               97
        Transfers to other operations.....................   207              183              153
                                                             ---              ---              ---
                                                             335              322              250
                                                             ---              ---              ---
      Expenses
        Production costs..................................    36               47               63
        Depreciation, depletion and amortization..........    61               68               76
</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                                                   RESULTS OF OPERATIONS FOR
                                                                     OIL AND GAS PRODUCTION
                                                                FOR THE YEARS ENDED DECEMBER 31,
                                                                                    ------------
                                                             2001             2000             1999
                                                             ----             ----             ----
                                                                          ($ MILLIONS)
<S>                                                          <C>              <C>              <C>

        Exploration.......................................    31               63               52
        Gain on disposal of assets........................    (8)            (147)             (36)
        Restructuring costs...............................    (2)              65                -
        Other related costs...............................    21               25               21
                                                             ---              ---              ---
                                                             139              121              176
                                                             ---              ---              ---
     Operating profit before income taxes.................   196              201               74
     Related income taxes.................................   (79)            (103)             (33)
                                                            ----              ---             ----
     Results of operations from Natural Gas................  117               98               41
                                                             ===              ===              ===
</TABLE>

     The information noted above does not totally agree to the segmented
     information on page 51 of the company's annual report due to different
     classification of revenues and expenses,





<PAGE>


STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED
PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES

     In computing the standardized measure of discounted future net cash flows
     from estimated production of proved oil and gas reserves after income
     taxes, assumptions other than those mandated by SFAS No. 69 could produce
     substantially different results. The Company cautions against viewing this
     information as a forecast of future economic conditions or revenues, and
     does not consider it to represent the fair market value of gas properties.
     Figures are based on year-end commodity prices, and are as follows:

<TABLE>
<CAPTION>
                                                                     2001         2000          1999
<S>                                                                  <C>          <C>           <C>
     Year end natural gas price assumptions (AECO - $/mcf)           3.55         13.52         2.90
</TABLE>

     Actual future net cash flows may differ from those estimated due to, but
     not limited to, the following:

     o    Production rates could differ from those estimated both in terms of
          timing and amount;

     o    Future prices and economic conditions will likely differ from those at
          yearend;

     o    Future production and development costs will be determined by future
          events and may differ from those at year end; and

     o    Estimated income taxes may differ in terms of amounts and timing due
          to the above factors as well as changes in enacted rates and the
          impact of future expenditures on unproved properties.

     The standardized measure of discounted future net cash flows is determined
     by using estimated quantities of proved reserves and taking into account
     the future periods in which they are expected to be developed and produced
     based on year-end economic conditions. The estimated future production is
     priced at year-end prices, except that future gas prices are increased,
     where applicable, for fixed and determinable price escalations provided by
     contract. At December 31, 2001, no such contractual arrangements existed.
     The resulting estimated future cash inflows are reduced by estimated future
     costs to develop and produce the proved reserves based on year-end cost
     levels. In addition, the Company has also deducted certain other estimated
     costs deemed necessary to derive the estimated pretax future net cash flows
     from the proved reserves including direct general and administrative costs
     of exploration and production operations and reclamation and environmental
     remediation costs. Deducting future income tax expenses then reduces the
     estimated pretax future net cash flows further. Such income taxes are
     determined by applying the appropriate year-end statutory tax rates, with
     consideration of future tax rates already legislated, to the future pretax
     cash flows relating to the Company's proved oil and gas reserves less the
     tax basis of the properties involved. At December 31, 2001, there were no
     legislated future tax rate changes. The future income tax expenses give
     effect to permanent differences and tax credits and allowances relating to
     the company's proved oil and gas reserves. The resultant future net cash
     flows are reduced to present value amounts by applying the SFAS No. 69
     mandated 10% discount factor. The result is referred to as "Standardized
     Measure of Discounted Future Net Cash Flows from Estimated Production of
     Proved Oil and Gas Reserves after Income Taxes".



<PAGE>

<TABLE>
<CAPTION>
                                                                    2001           2000          1999
                                                                    ----           ----          ----
                                                                               ($ MILLIONS)
<S>                                                                 <C>           <C>           <C>
     Future cash inflows..........................................  2,266          8,176         3,272
     Future production and development costs......................  (652)           (633)       (1,053)
     Other related future costs...................................  (283)           (175)         (133)
     Future income tax expenses...................................  (521)         (3,426)         (789)
                                                                    ----           -----         -----
     Future net cash flows.........................................  810            3,942        1,297
     Discount at 10 %.............................................. (370)          (2,009)        (548)
                                                                    ----            -----        -----
     Standardized measure of discounted future net cash
     flows  from estimated production of proved oil and gas
     reserves after income taxes...................................  440            1,933          749
                                                                     ===            =====        =====
</TABLE>

SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME
TAXES

<TABLE>
<CAPTION>
                                                                              2001           2000          1999
                                                                              ----           ----          ----
                                                                                        ($ MILLIONS)
<S>                                                                          <C>             <C>           <C>
     Balance, beginning of year.............................................. 1,933           749           797
     Increase (decrease) in discounted future net cash flows:
       Sales and transfers of oil and gas net of related costs............... (297)          (275)         (192)
       Revisions to estimates of proved reserves:
          Prices.............................................................(3,055)         3,886          458
          Development costs................................................... (50)           (3)          (68)
          Production costs....................................................  (9)           55           (25)
          Quantities..........................................................  (2)          (363)         (175)
          Other............................................................... (16)          (237)         (81)
       Extensions, discoveries, and improved recovery less related costs......  23            177           46
       Development costs incurred during the period...........................  81            69            70
       Purchases of reserves in place.........................................  -             41            -
       Sales of reserves in place............................................. (1)           (989)         (130)
       Accretion of discount.................................................. 361            115           113
       Income taxes.......................................................... 1,472         (1,292)        (64)
                                                                              -----         -------        ----
     Balance, end of year..................................................... 440           1,933          749
                                                                               ===           =====          ===
</TABLE>


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-2
<SEQUENCE>4
<FILENAME>a2075015zex-2.txt
<DESCRIPTION>EXHIBIT 2
<TEXT>
<Page>

MANAGEMENT'S STATEMENT ON FINANCIAL REPORTING

The financial statements on pages 46 to 68, which consolidate the financial
results of Suncor Energy Inc., its subsidiaries and joint ventures, and all
information in this annual report, are the responsibility of management.

The financial statements have been prepared in accordance with Canadian
generally accepted accounting principles. They include some amounts that are
based on estimates and judgments relating to matters not concluded by
year-end. Financial information presented elsewhere in this annual report is
consistent with that in the financial statements.

In management's opinion the financial statements have been properly prepared
within reasonable limits of materiality and within the framework of the
accounting policies summarized on pages 46 to 48. In meeting its
responsibilities for the integrity of the financial statements, management
maintains a system of internal controls and an internal audit program.
Management also administers a program of proper business conduct compliance.

PricewaterhouseCoopers LLP, the company's independent auditors, have audited
the accompanying financial statements. Their report accompanies this
statement.

The Audit Committee of the Board of Directors, composed of five independent
directors, meets regularly with management, the internal auditors and
PricewaterhouseCoopers LLP to review their activities and to discuss
auditing, management information systems, internal control, accounting policy
and financial reporting matters. The Audit Committee also meets quarterly to
review and approve interim financial statements prior to release. The
internal auditors and PricewaterhouseCoopers LLP have unrestricted access to
the company, the Audit Committee and the Board of Directors. The Audit
Committee reviews the financial statements and Management's Discussion and
Analysis and recommends approval to the Board of Directors.

/s/ Rick George                               /s/ Mike O'Brien
RICK GEORGE                                   MIKE O'BRIEN
President and                                 Executive Vice President,
Chief Executive Officer                       Corporate Development
                                              and Chief Financial Officer

January 16, 2002

AUDITORS' REPORT

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have audited the consolidated balance sheets of Suncor Energy Inc. as at
December 31, 2001, 2000 and 1999 and the consolidated statements of earnings,
cash flows and changes in shareholders' equity for each of the years then
ended. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in Canada. Those standards require that we plan and perform an audit
to obtain reasonable assurance that the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.

In our opinion, these consolidated financial statements present fairly, in
all material respects, the financial position of the company as at December
31, 2001, 2000 and 1999 and the results of its operations and cash flows for
each of the years then ended in accordance with accounting principles
generally accepted in Canada.

/s/ PricewaterhouseCoopers
PRICEWATERHOUSECOOPERS LLP
Chartered Accountants
Calgary, Alberta

January 16, 2002


                                                        2001 ANNUAL REPORT    45
<Page>

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Suncor Energy Inc. is an integrated Canadian energy company, comprised of
three operating segments: Oil Sands, Natural Gas and Sunoco.

Oil Sands includes the production of light sweet and light sour crude oil,
diesel fuel and various custom blends from oil sands mined in the Athabasca
region of northeastern Alberta, and the marketing of these products in Canada
and the United States.

Natural Gas includes the exploration, acquisition, development, production,
transportation and marketing of natural gas and crude oil in Canada and the
United States.

Sunoco includes the manufacture, transportation and marketing of petroleum
and petrochemical products, primarily in Ontario and Quebec, and the
marketing of natural gas in Ontario. Petrochemical products are also sold in
the United States and Europe.

The significant accounting policies of the company are summarized below:

(a)  PRINCIPLES OF CONSOLIDATION AND THE PREPARATION OF FINANCIAL STATEMENTS

These consolidated financial statements are prepared and reported in Canadian
dollars in accordance with Canadian generally accepted accounting principles
(GAAP), which differ in some respects from GAAP in the United States. The
significant differences in GAAP, as applicable to these consolidated
financial statements and notes, are described in the company's annual report
on Form 40-F, which is filed with the United States Securities and Exchange
Commission and is available on request.

The consolidated financial statements include the accounts of Suncor Energy
Inc. and its subsidiaries and the company's proportionate share of the
assets, liabilities, revenues, expenses and cash flows of its joint ventures.

The timely preparation of financial statements requires that management make
estimates and assumptions, and use judgment, regarding assets, liabilities,
revenues and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial statements.
Accordingly, actual results may differ from estimated amounts as future
confirming events occur.

(b)  CASH EQUIVALENTS AND INVESTMENTS

The company considers all highly liquid investments with a maturity of three
months or less at the time of purchase to be cash equivalents. Cash
equivalents consist primarily of term deposits and certificates of deposit.
Investments with maturities from greater than three months to one year are
classified as short-term investments, while those with maturities in excess
of one year are classified as long-term investments. Cash equivalents and
short-term investments are stated at cost, which approximates market value.

(c)  REVENUES

Crude oil sales from upstream operations (Oil Sands and Natural Gas) to
downstream operations (Sunoco) are based upon actual product shipments. On
consolidation, revenues from these sales are eliminated from sales and other
operating revenues and purchases of crude oil and products.

The company also uses a portion of its natural gas production for internal
consumption at its oil sands plant and refinery. On consolidation, revenues
from these sales are eliminated from sales and other operating revenues and
operating, selling and general expenses.

Revenues associated with sales of crude oil, natural gas, petroleum and
petrochemical products and all other items not eliminated on consolidation
are recorded when title passes to the customer. Revenues from natural gas
production from properties in which the company has an interest with other
producers are recognized on the basis of the company's net working interest.

(d)  PROPERTY, PLANT AND EQUIPMENT

COST

Property, plant and equipment are recorded at cost.

The company follows the successful efforts method of accounting for its crude
oil and natural gas operations. Under the successful efforts method,
acquisition costs of proved and unproved properties are capitalized. Costs of
unproved properties are transferred to proved properties when proved reserves
are confirmed. Exploration costs, including geological and geophysical costs,
are expensed as incurred. Exploratory drilling costs are capitalized
initially. If it is determined that the well does not contain proved
reserves, the capitalized exploratory drilling costs are charged to expense,
as dry hole costs, at that time. The related land costs are expensed through
the amortization of unproved properties as covered under the Natural Gas
section of the depreciation, depletion and amortization policy below.

Development costs, which include the costs of wellhead equipment, development
drilling costs, gas plants and handling facilities, applicable geological and
geophysical costs and the costs of acquiring or constructing support
facilities and equipment are capitalized. Costs incurred to operate and
maintain wells and equipment and to lift oil and gas to the surface are
expensed as operating costs.

INTEREST CAPITALIZATION

Interest costs relating to major capital projects and to the portion of
non-producing oil and gas properties expected to become producing are
capitalized as part of the cost of such property, plant and equipment.
Capitalization of interest ceases when the capital asset is substantially
complete and ready for its intended productive use.


46    SUNCOR ENERGY INC.
<Page>

LEASES

Leases entered into by the company as lessee that transfer substantially all
the benefits and risks of ownership to the lessee are recorded as capital
leases and classified as property, plant and equipment with offsetting
long-term borrowings. All other leases are classified as operating leases
under which leasing costs are expenses in the period in which they are
incurred.

Gains and losses on the sale and leaseback of assets recorded as capital
leases are deferred and amortized to earnings in proportion to the
amortization of leased assets.

DEPRECIATION, DEPLETION AND AMORTIZATION

OIL SANDS:

Property, plant and equipment are depreciated over their useful lives on a
straight line basis, except for original lease acquisition costs and related
mine assets, which are depreciated over the life of proved reserves on a unit
of production basis.

The company is depreciating property, plant and equipment as follows:

       i)  mobile equipment over three to 20 years;

      ii)  mine equipment and acquisition costs of original lease over
           approximately four million barrels of proved reserves;

     iii)  plant and other property and equipment, including new leases,
           primarily over four to 40 years.

NATURAL GAS:

Unproved properties of which acquisition costs are individually significant
are evaluated for impairment by management. Impairment of unproved properties
of which acquisition costs are not individually significant is provided for
through amortization of the portion not expected to become producing, based
on historical experience, over the average projected holding period.

Acquisition costs of proved properties are depleted using the unit of
production method based on proved reserves. Capitalized exploratory drilling
costs and development costs are depleted on the basis of proved developed
reserves. For purposes of the depletion calculation, production and reserves
volumes for oil and natural gas are converted to a common unit of measure on
the basis of their approximate relative energy content. Gas plants, support
facilities and equipment are depreciated on a straight line basis over their
useful lives, which average 12 years.

SUNOCO:

Depreciation of property, plant and equipment is on a straight line basis
over their useful lives. The refinery and additions thereto are depreciated
over an average of 30 years, service stations and related equipment over an
average of 20 years and other facilities and equipment over three to 25 years.

RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS

Reclamation and environmental remediation costs for identified sites are
estimated and charged against earnings when there exists a regulatory or
statutory requirement or contractual agreement, or when management has made a
decision to decommission or restore a site, providing that assessments
indicate that such costs are probable and reasonably estimable.

Estimated reclamation costs in the company's upstream operations are accrued
on the unit of production basis. Estimated environmental remediation costs,
which are predominantly in the company's downstream operations, are accrued
for those sites where assessments indicate that such work is required.

Costs are accrued based upon currently known information, estimated timing of
remedial actions, and existing regulatory requirements and technology.
Changes in these factors may result in material changes to estimated costs,
which will be recognized prospectively when known.

IMPAIRMENT

Property, plant and equipment are reviewed for impairment whenever events or
conditions indicate that their net carrying amount, less related provisions
for reclamation and environmental remediation costs and future income taxes,
may not be recoverable from estimated undiscounted future cash flows. If it
is determined that the estimated net recoverable amount is less than the net
carrying amount, then a write-down to the estimated net recoverable amount is
made, with a charge to earnings.

DISPOSALS

Gains or losses on disposals of property, plant and equipment are generally
recognized in earnings. For oil and gas property, plant and equipment, gains
or losses are recognized in earnings for significant disposals or disposal of
an entire property. However, the acquisition cost of an unproved property
surrendered or abandoned that is not individually significant or a partial
abandonment of a proved property is charged to accumulated depreciation,
depletion or amortization, as appropriate.

(e)  DEFERRED CHARGES

Overburden removal costs incurred to expose oil sands for mining, including
depreciation on overburden removal equipment where applicable, are deferred.
These costs are amortized based on the amount of oil sands mined in the year,
the ratio of total overburden to be removed to total reserves of oil sands to
be mined and the removal cost, determined on a last-in, first-out (LIFO)
basis, per unit of overburden.

The cost of major maintenance shutdowns is deferred and amortized on a
straight line basis over the period to the next shutdown that varies from
three to seven years. Normal maintenance and repair costs are charged to
expense as incurred.

Goodwill is reviewed on an ongoing basis by management to determine if the
unamortized goodwill balance can be recovered through undiscounted projected
future operating cash flows. If it cannot be recovered, the goodwill is
considered permanently impaired and the net book value of goodwill would be
written down.

Oil Sands preproduction costs incurred at the inception of operation are
amortized on a unit of production basis over the life of proved producing
reserves.


                                                        2001 ANNUAL REPORT    47
<Page>

(f)  EMPLOYEE FUTURE BENEFITS

The company has employee future benefit programs as follows:

o    Defined benefit pension plans and a defined contribution pension plan
     providing retirement benefits for its eligible employees, and supplementary
     defined benefit pension plans providing additional retirement benefits for
     its executives;

o    Other post-retirement benefits, including certain health care and life
     insurance benefits, for its retired employees and eligible surviving
     dependants;

o    Post-employment benefits providing certain benefits to former or inactive
     employees and eligible surviving dependants, after employment but before
     retirement under specified circumstances.

The estimated future cost of providing defined benefit pension and other
post-retirement benefits is actuarially determined using management's best
estimates of demographic and financial assumptions, and such cost is accrued
rateably from the date of hire of the employee to the date the employee
becomes fully eligible to receive the benefits. The discount rate used to
determine accrued benefit obligations is based upon a year-end market rate of
interest. Company contributions to the defined contribution plan are expensed
as incurred.

(g)  INVENTORIES

Inventories of crude oil and refined products are valued at the lower of cost
using the last-in, first-out (LIFO) method and net realizable value.

Materials and supplies are valued at the lower of average cost and net
realizable value.

(h)  DERIVATIVE FINANCIAL INSTRUMENTS

The company periodically enters into derivative financial instrument
contracts such as forwards, futures, swaps and options to hedge against the
potential adverse impact of market prices for its petroleum and natural gas
products and to protect its Canadian dollar income and cash flows against
adverse foreign currency exchange movements. The company also periodically
enters into derivative financial instrument contracts such as interest rate
swaps as part of its risk management strategy to minimize exposure to
interest rate fluctuations. The company does not use derivative financial
instruments involving multipliers or leverage.

These derivative contracts are initiated within the guidelines of the
company's risk management policies, which require stringent authorities for
approval and commitment of contracts, designation of the contracts by
management as hedges of the related transactions, and monitoring of the
effectiveness of such contracts in reducing the related risks. Contract
maturities are consistent with the settlement dates of the related hedged
transactions.

Derivative contracts accounted for as hedges are not recognized in the
consolidated balance sheets. Gains or losses on these contracts, including
realized gains and losses on hedging derivative contracts settled prior to
maturity, are recognized in earnings and cash flows when the related sales
revenues, costs, interest expense and cash flows are recognized.

Gains or losses resulting from changes in the fair value of derivative
contracts that do not qualify for hedge accounting are recognized in earnings
and cash flows when those changes occur.

(i)  FOREIGN CURRENCY TRANSLATION

Monetary assets and liabilities in foreign currencies are translated to
Canadian dollars at rates of exchange in effect at the end of the period.
Other assets and related depreciation, depletion and amortization, other
liabilities, revenues and expenses are translated at rates of exchange in
effect at the respective transaction dates. The resulting exchange gains and
losses are included in earnings, except for unrealized exchange gains and
losses arising on translation of long-term liabilities with fixed or
ascertainable lives. These gains and losses are deferred and amortized over
the remaining terms of the liabilities.

The company's former Stuart Oil Shale Project in Australia was integrated
with the company's other activities and was translated in the manner
described above.

(j)  STOCK-BASED COMPENSATION PLANS

Under the company's share option programs, common share options are granted
to executives, certain employees and non-employee directors. The company does
not recognize compensation expense on the issuance of common share options
under these programs because the exercise price of the share options is equal
to the market value of the common shares at the date of grant.

The company also has long-term employee incentive plans that provide awards
to certain executives based on the market price of the company's common
shares and to all other employees based on the market price of the company's
common shares and the achievement of certain performance measurement criteria
relating to the company's business segments. These awards vest on April 1,
2002, and are payable at that time, generally in equal amounts of cash and
common shares of the company. The estimated costs of the cash portion of
these awards, based on share price and expected performance achievement, are
recorded as compensation expense over the vesting period.

Under the company's directors' compensation plan, non-employee directors of
the company may elect to receive half or all of their annual remuneration as
directors in common share equivalents. The estimated costs of directors'
compensation in the form of these common share equivalents, based on share
price, are recorded as compensation expense annually.


48    SUNCOR ENERGY INC.
<Page>

CONSOLIDATED STATEMENTS OF EARNINGS
for the years ended December 31

<TABLE>
<CAPTION>
($ millions)                                                      2001              2000             1999
<S>                                                              <C>               <C>              <C>
REVENUES
   Sales and other operating revenues (notes 4, 6 and 18)        3 990             3 385            2 383
   Interest                                                          5                 3                4
- ---------------------------------------------------------------------------------------------------------
                                                                 3 995             3 388            2 387
- ---------------------------------------------------------------------------------------------------------
EXPENSES
   Purchases of crude oil and products (note 18)                 1 391               807              519
   Operating, selling and general (note 12)                      1 010               918              774
   Exploration (note 4)                                             22                53               40
   Royalties (note 3)                                              134               199               99
   Taxes other than income taxes (note 4)                          367               361              334
   Depreciation, depletion and amortization                        360               365              318
   Gain on disposal of assets                                       (7)             (148)             (34)
   Start-up expenses - Project Millennium (note 8)                 141                15               --
   Write-off of oil shale assets (note 1)                           48               125               --
   Restructuring (note 2)                                           (2)               65               --
   Interest (note 4)                                                18                 8               26
- ---------------------------------------------------------------------------------------------------------
                                                                 3 482             2 768            2 076
- ---------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES                                       513               620              311
- ---------------------------------------------------------------------------------------------------------
Provision for income taxes (note 5)
   Current                                                           4                45               29
   Future                                                          121               198               96
- ---------------------------------------------------------------------------------------------------------
                                                                   125               243              125
- ---------------------------------------------------------------------------------------------------------
NET EARNINGS                                                       388               377              186
Dividends on preferred securities (note 15)                        (26)              (26)             (22)
- ---------------------------------------------------------------------------------------------------------
Net earnings attributable to common shareholders                   362               351              164
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
PER COMMON SHARE (dollars) (note 16)
Net earnings attributable to common shareholders
   basic                                                          1.63              1.58             0.74
   diluted                                                        1.61              1.57             0.73
- ---------------------------------------------------------------------------------------------------------
Cash dividends                                                    0.34              0.34             0.34
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
</TABLE>

See accompanying Summary of Significant Accounting Policies and notes.


                                                        2001 ANNUAL REPORT    49
<Page>

CONSOLIDATED BALANCE SHEETS
as at December 31

<TABLE>
<CAPTION>
($ millions)                                                            2001              2000             1999
<S>                                                                    <C>               <C>              <C>
ASSETS
   CURRENT ASSETS
      Cash and cash equivalents                                            1                21                5
      Accounts receivable (notes 4 and 6)                                306               407              277
      Income taxes recoverable                                            28                --               --
      Future income taxes (note 5)                                        29                45               14
      Inventories (note 7)                                               258               192              161
- ---------------------------------------------------------------------------------------------------------------
   Total current assets                                                  622               665              457
   Property, plant and equipment, net (note 8)                         7 141             5 883            4 528
   Deferred charges and other (note 9)                                   199               166              191
   Future income taxes (note 5)                                          132               119              --
- ---------------------------------------------------------------------------------------------------------------
   Total assets                                                        8 094             6 833            5 176
- ---------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
   CURRENT LIABILITIES
      Short-term borrowings                                               31                64               32
      Accounts payable and accrued liabilities (notes 12 and 13)         672               709              616
      Income taxes payable                                                --                15               15
      Future income taxes (note 5)                                        28                 9               --
      Taxes other than income taxes                                       42                39               46
      Current portion of long-term borrowings (note 10)                   --                 1                1
- ---------------------------------------------------------------------------------------------------------------
   Total current liabilities                                             773               837              710
- ---------------------------------------------------------------------------------------------------------------
   Long-term borrowings (notes 10 and 11)                              3 113             2 192            1 306
   Accrued liabilities and other (notes 12 and 13)                       251               252              236
   Future income taxes (note 5)                                        1 180             1 080              816

   Commitments and contingencies (note 14)

   SHAREHOLDERS' EQUITY
      Preferred securities (note 15)                                     514               514              514
      Share capital (note 16)                                            555               537              524
      Retained earnings                                                1 708             1 421            1 070
- ---------------------------------------------------------------------------------------------------------------
   Total shareholders' equity                                          2 777             2 472            2 108
- ---------------------------------------------------------------------------------------------------------------
   Total liabilities and shareholders' equity                          8 094             6 833            5 176
- ---------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------
</TABLE>

See accompanying Summary of Significant Accounting Policies and notes.

Approved on behalf of the Board of Directors:

/s/ Rick George                                /s/ Robert Korthals
RICK GEORGE                                    ROBERT KORTHALS
Director                                       Director


50    SUNCOR ENERGY INC.
<Page>

CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31

<TABLE>
<CAPTION>
($ millions)                                                            2001              2000             1999
<S>                                                                   <C>               <C>              <C>
OPERATING ACTIVITIES
Cash flow provided from operations (1), (2)                              831               958              591
Decrease (increase) in operating working capital
   Accounts receivable (note 4)                                          101              (130)            (101)
   Inventories                                                           (66)              (31)              14
   Accounts payable and accrued liabilities                              (37)               93              322
   Taxes payable                                                         (17)               18               12
- ---------------------------------------------------------------------------------------------------------------
Cash provided from operating activities                                  812               908              838
- ---------------------------------------------------------------------------------------------------------------
CASH USED IN INVESTING ACTIVITIES (2)                                 (1 680)           (1 607)          (1 290)
- ---------------------------------------------------------------------------------------------------------------
NET CASH DEFICIENCY BEFORE FINANCING ACTIVITIES                         (868)             (699)            (452)
- ---------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Increase (decrease) in short-term borrowings                             (33)               32               16
Proceeds from issuance of long-term borrowings (note 10)                 500                --               --
Issuance of preferred securities (note 15)                                --                --              507
Stuart Oil Shale Project borrowings                                       --                --               11
Repayment of commercial paper borrowings (note 15)                        --                --             (507)
Net increase in other long-term borrowings                               486               792              510
Issuance of common shares under stock option plan (note 16)               15                 9                6
Dividends paid on preferred securities (3) (note 15)                     (48)              (47)             (37)
Dividends paid on common shares                                          (72)              (71)             (75)
- ---------------------------------------------------------------------------------------------------------------
Cash provided from financing activities                                  848               715              431
- ---------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                         (20)               16              (21)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR                            21                 5               26
- ---------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR                                   1                21                5
- ---------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------
PER COMMON SHARE (dollars) (note 16)
(1) Cash flow provided from operations                                  3.73              4.32             2.68
(3) Dividends paid on preferred securities (pre-tax)                    0.21              0.21             0.17
- ---------------------------------------------------------------------------------------------------------------
    Cash flow provided from operations after deducting
      dividends paid on preferred securities                            3.52              4.11             2.51
- ---------------------------------------------------------------------------------------------------------------
(2) See Schedules of Segmented Data on pages 54 and 55
- ---------------------------------------------------------------------------------------------------------------
</TABLE>

See accompanying Summary of Significant Accounting Policies and notes.


CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                                Preferred             Share         Retained
($ millions)                                                   Securities           Capital         Earnings
<S>                                                            <C>                  <C>             <C>
AT DECEMBER 31, 1998                                                   --               518              981
Net earnings                                                           --                --              186
Dividends paid on preferred securities                                 --                --              (22)
Dividends paid on common shares                                        --                --              (75)
Issuance of preferred securities (note 15)                            514                --               --
Issued for cash under stock option plan                                --                 6               --
- ------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1999                                                  514               524            1 070
Net earnings                                                           --                --              377
Dividends paid on preferred securities                                 --                --              (26)
Dividends paid on common shares                                        --                --              (71)
Issued for cash under stock option plan                                --                 9               --
Issued under dividend reinvestment plan                                --                 4               (4)
Income taxes - impact of new standard                                  --                --               75
- ------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 2000                                                  514               537            1 421
Net earnings                                                           --                --              388
Dividends paid on preferred securities                                 --                --              (26)
Dividends paid on common shares                                        --                --              (72)
Issued for cash under stock option plan                                --                15               --
Issued under dividend reinvestment plan                                --                 3               (3)
- ------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 2001                                                  514               555            1 708
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
</TABLE>

See accompanying Summary of Significant Accounting Policies and notes.


                                                        2001 ANNUAL REPORT    51
<PAGE>

SCHEDULES OF SEGMENTED DATA*
for the years ended December 31

<TABLE>
<CAPTION>
                                                 Oil Sands                    Natural Gas                       Sunoco
($ millions)                             2001      2000      1999      2001      2000      1999       2001       2000       1999
<S>                                     <C>       <C>        <C>       <C>       <C>       <C>       <C>        <C>        <C>
EARNINGS
REVENUES**
Sales and other
   operating revenues                   1 227       544       461       178       237       143      2 585      2 604      1 779
Intersegment revenues (note 18) ***       158       792       428       271       191       163          3         --         --
Interest                                   --        --        --        --        --        --         --         --         --
- --------------------------------------------------------------------------------------------------------------------------------
                                        1 385     1 336       889       449       428       306      2 588      2 604      1 779
- --------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Purchases of crude oil
   and products (note 18)                  99         3         6        --        --        --      1 721      1 783      1 090
Operating, selling and general            481       467       369        64        74        88        350        310        270
Exploration                                --        --        --        22        53        40         --         --         --
Royalties                                  30        98        51       104       101        48         --         --         --
Taxes other than income taxes              12        12         9         3         3         5        351        345        320
Depreciation, depletion
   and amortization                       233       232       177        70        78        87         56         54         53
(Gain) loss on disposal of assets           1        --         2        (8)     (147)      (36)        --         (1)        --
Start-up expenses --
Project Millennium                        141        15        --        --        --        --         --         --         --
Write-off of oil shale assets              --        --        --        --        --        --         --         --         --
Restructuring                              --        --        --        (2)       65        --         --         --         --
Interest                                   --        --        --        --        --        --         --         --         --
- --------------------------------------------------------------------------------------------------------------------------------
                                          997       827       614       253       227       232      2 478      2 491      1 733
- --------------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE
   INCOME TAXES                           388       509       275       196       201        74        110        113         46
Provision for income taxes               (105)     (194)     (108)      (79)     (103)      (33)       (30)       (32)       (19)
- --------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)                       283       315       167       117        98        41         80         81         27
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------

As at December 31

TOTAL ASSETS                            6 409     5 079     3 178       722       762       962        934        911        849
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
CAPITAL EMPLOYED****                    1 398     1 412     1 352       317       412       727        483        386        405
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
   CAPITAL EMPLOYED (%)****              20.1      22.8      12.9      32.1      17.2       5.5       18.4       20.5        6.0
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
   CAPITAL EMPLOYED (%)*****              6.4      10.6       9.2      32.1      17.2       5.5       18.4       20.5        6.0
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>

*     The company currently has no foreign geographic segments. See note 4 for
      information on export sales. Accounting policies for segments are the
      same as those described in the Summary of Significant Accounting Policies.

**    One customer, in the Oil Sands segment, in 2001 represented 10% or more
      ($450 million) of the company's 2001 consolidated revenues.
      (2000 - two customers represented 10% or more ($493 million and
      $355 million); 1999 - one customer represented 10% or more
      ($281 million)).

***   Intersegment revenues are recorded at prevailing fair market prices and
      accounted for as if the sales were to third parties.

****  Capital Employed - the total of shareholders' equity and debt (short-term
      borrowings and current and long-term portions of long-term borrowings),
      less capitalized costs related to major projects in progress.

***** If capital employed were to include capitalized costs related to major
      projects in progress, the return on average capital employed would be as
      stated on this line.

See accompanying Summary of Significant Accounting Policies and notes.


52    SUNCOR ENERGY INC.
<Page>

SCHEDULES OF SEGMENTED DATA* (CONTINUED)
for the years ended December 31

<TABLE>
<CAPTION>
                                                   Corporate and Eliminations                             Total
($ millions)                                   2001           2000           1999           2001           2000           1999
<S>                                            <C>            <C>            <C>           <C>            <C>            <C>
EARNINGS
REVENUES**
Sales and other
   operating revenues                            --             --             --          3 990          3 385          2 383
Intersegment revenues (note 18) ***            (432)          (983)          (591)            --             --             --
Interest                                          5              3              4              5              3              4
- ------------------------------------------------------------------------------------------------------------------------------
                                               (427)          (980)          (587)         3 995          3 388          2 387
- ------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Purchases of crude oil
   and products (note 18)                      (429)          (979)          (577)         1 391            807            519
Operating, selling and general                  115             67             47          1 010            918            774
Exploration                                      --             --             --             22             53             40
Royalties                                        --             --             --            134            199             99
Taxes other than income taxes                     1              1             --            367            361            334
Depreciation, depletion
   and amortization                               1              1              1            360            365            318
(Gain) loss on disposal of assets                --             --             --             (7)          (148)           (34)
Start-up expenses --
   Project Millennium                            --             --             --            141             15             --
Write-off of oil shale assets                    48            125             --             48            125             --
Restructuring                                    --             --             --             (2)            65             --
Interest                                         18              8             26             18              8             26
- ------------------------------------------------------------------------------------------------------------------------------
                                               (246)          (777)          (503)         3 482          2 768          2 076
- ------------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE
   INCOME TAXES                                (181)          (203)           (84)           513            620            311
Provision for income taxes                       89             86             35           (125)          (243)          (125)
- ------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)                             (92)          (117)           (49)           388            377            186
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------

As at December 31

TOTAL ASSETS                                     29             81            187          8 094          6 833          5 176
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
CAPITAL EMPLOYED****                             32             22           (121)         2 230          2 232          2 363
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
   CAPITAL EMPLOYED (%)****                                                                 17.9           16.6            8.3
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
   CAPITAL EMPLOYED (%)*****                                                                 7.5            9.3            6.4
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                        2001 ANNUAL REPORT    53
<Page>

SCHEDULES OF SEGMENTED DATA* (CONTINUED)
for the years ended December 31

<TABLE>
<CAPTION>
                                                 Oil Sands                    Natural Gas                       Sunoco
($ millions)                             2001      2000      1999      2001      2000      1999       2001       2000       1999
<S>                                    <C>       <C>       <C>         <C>       <C>       <C>        <C>        <C>        <C>
CASH FLOW BEFORE
   FINANCING ACTIVITIES
CASH PROVIDED FROM (USED IN)
   OPERATING ACTIVITIES:
Cash flow provided from
   (used in) operations
   Net earnings (loss)                    283       315       167       117        98        41         80         81         27
   Exploration expenses
      Cash                                 --        --        --        12        12        12         --         --         --
      Dry hole costs                       --        --        --        10        41        28         --         --         --
   Non-cash items included
      in earnings
      Depreciation, depletion
         and amortization                 233       232       177        70        78        87         56         54         53
      Future income taxes                  89       189       102        76       101        31         18        (16)       (33)
      Current income tax provision
         allocated to Corporate            16         5         6         3         2         2         12         48         52
      (Gain) loss on disposal of assets     1        --         2        (8)     (147)      (36)        --         (1)        --
      Write-off of oil shale assets        --        --        --        --        --        --         --         --         --
      Restructuring                        --        --        --        (3)       56        --         --         --         --
      Other                                (4)      (12)       --         3        (4)        6          2          6          3
   Overburden removal outlays             (31)      (48)      (53)       --        --        --         --         --         --
   Overburden removal outlays --
      Project Millennium                  (88)      (27)       --        --        --        --         --         --         --
   Increase (decrease) in deferred
      credits and other                   (13)        1         4        --         1         1         (3)         2          1
- --------------------------------------------------------------------------------------------------------------------------------
Total cash flow provided from
   (used in) operations                   486       655       405       280       238       172        165        174        103
Decrease (increase) in operating
   working capital                        (35)     (169)       83        44        27        27         17         40         69
- --------------------------------------------------------------------------------------------------------------------------------
Total cash provided from (used in)
   operating activities                   451       486       488       324       265       199        182        214        172
- --------------------------------------------------------------------------------------------------------------------------------
CASH PROVIDED FROM (USED IN)
   INVESTING ACTIVITIES:
Capital and exploration
   expenditures                        (1 479)   (1 808)   (1 057)     (132)     (127)     (200)       (54)       (45)       (42)
Deferred maintenance
   shutdown expenditures                   (5)       (3)      (22)       (2)       (1)       --         (9)        (9)        --
Deferred outlays and
   other investments                       (2)       (5)       (7)       (1)       --        --         (9)        (7)        (2)
Proceeds from disposals                    10       101         1        22       314        90          1          2          1
- --------------------------------------------------------------------------------------------------------------------------------
Total cash provided from (used in)
   investing activities                (1 476)   (1 715)   (1 085)     (113)      186      (110)       (71)       (59)       (43)
- --------------------------------------------------------------------------------------------------------------------------------
NET CASH SURPLUS (DEFICIENCY)
   BEFORE FINANCING ACTIVITIES         (1 025)   (1 229)     (597)      211       451        89        111        155        129
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>


*  The company currently has no foreign geographic segments. See note 4 for
   information on export sales. Accounting policies for segments are the same
   as those described in the Summary of Significant Accounting Policies.

See accompanying Summary of Significant Accounting Policies and notes.


54    SUNCOR ENERGY INC.
<Page>

SCHEDULES OF SEGMENTED DATA* (CONTINUED)
for the years ended December 31

<TABLE>
<CAPTION>
                                                   Corporate and Eliminations                             Total
($ millions)                                   2001           2000           1999           2001           2000           1999
<S>                                            <C>            <C>            <C>          <C>            <C>            <C>
CASH FLOW BEFORE
   FINANCING ACTIVITIES
CASH PROVIDED FROM (USED IN)
   OPERATING ACTIVITIES:
Cash flow provided from
   (used in) operations
   Net earnings (loss)                          (92)          (117)           (49)           388            377            186
   Exploration expenses
      Cash                                       --             --             --             12             12             12
      Dry hole costs                             --             --             --             10             41             28
   Non-cash items included
      in earnings
      Depreciation, depletion
         and amortization                         1              1              1            360            365            318
      Future income taxes                       (62)           (76)            (4)           121            198             96
      Current income tax provision
         allocated to Corporate                 (31)           (55)           (60)            --             --             --
      (Gain) loss on disposal of assets          --             --             --             (7)          (148)           (34)
      Write-off of oil shale assets              48            125             --             48            125             --
      Restructuring                              --             --             --             (3)            56             --
      Other                                       7             (7)             4              8            (17)            13
   Overburden removal outlays                    --             --             --            (31)           (48)           (53)
   Overburden removal outlays --
      Project Millennium                         --             --             --            (88)           (27)            --
   Increase (decrease) in deferred
      credits and other                          29             20             19             13             24             25
- ------------------------------------------------------------------------------------------------------------------------------
Total cash flow provided from
   (used in) operations                        (100)          (109)           (89)           831            958            591
Decrease (increase) in operating
   working capital                              (45)            52             68            (19)           (50)           247
- ------------------------------------------------------------------------------------------------------------------------------
Total cash provided from (used in)
   operating activities                        (145)           (57)           (21)           812            908            838
- ------------------------------------------------------------------------------------------------------------------------------
CASH PROVIDED FROM (USED IN)
   INVESTING ACTIVITIES:
Capital and exploration
   expenditures                                 (13)           (18)           (51)        (1 678)        (1 998)        (1 350)
Deferred maintenance
   shutdown expenditures                         --             --             --            (16)           (13)           (22)
Deferred outlays and
   other investments                             (7)            (1)            (1)           (19)           (13)           (10)
Proceeds from disposals                          --             --             --             33            417             92
- ------------------------------------------------------------------------------------------------------------------------------
Total cash provided from (used in)
   investing activities                         (20)           (19)           (52)        (1 680)        (1 607)        (1 290)
- ------------------------------------------------------------------------------------------------------------------------------
NET CASH SURPLUS (DEFICIENCY)
   BEFORE FINANCING ACTIVITIES                 (165)           (76)           (73)          (868)          (699)          (452)
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                        2001 ANNUAL REPORT    55
<Page>

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.   OIL SHALE PROJECT

Effective April 5, 2001, the company sold its interest in the Stuart Oil
Shale Project to joint venture co-owners Southern Pacific Petroleum NL and
Central Pacific Minerals NL (SPP/CPM). Under the terms of the sale, the
company retains a 5% royalty interest in Stage 1 of the project and SPP/CPM
and the company retain worldwide rights to the Alberta Taciuk Processor
technology. The company made total payments as part of the transaction in the
amount of $5 million (AUD$7 million), which SPP/CPM will use to fund Stage 1
operating, capital and transition costs. The company received 2.5 million SPP
shares and 0.926 million CPM shares in consideration. SPP/CPM issued the
company 12.5 million SPP share options and 4.6 million CPM share options,
exercisable over five years at a strike price of AUD$1.25 per SPP share and
AUD$3.38 per CPM share. The company surrendered its partly paid Restricted
Class shares (SPP 57 million and CPM 18.85 million) that were acquired in
1997.

In the second quarter of 2001, as a result of the sale of this interest, the
company wrote off the carrying value of the property, plant and equipment and
the partly paid shares, and extinguished the long-term borrowings and accrued
interest. The earnings impact of the sale of Suncor's remaining interest in
the project was $48 million pre-tax, $3 million after-tax.

At December 31, 2001, the company holds 2.5 million SPP shares and 0.926
million CPM shares, and 12.5 million SPP share options and 4.6 million CPM
share options. The SPP and CPM shares have declined in value and have been
written down from $5 million to $2 million. The impact of the write-down was
to decrease net earnings by $2 million.

2.   RESTRUCTURING CHARGE

In 2000, the carrying values of certain assets of the company's Natural Gas
business were written down to their net estimated recoverable amount and a
provision for estimated restructuring costs was recorded.

In the third quarter of 2001, some of these properties that were previously
written down were sold and provisions for estimated restructuring costs were
revised to reflect increased employee termination costs as follows:

<TABLE>
<CAPTION>
($ millions)                                    2001                   2000
<S>                                             <C>                    <C>
Non-cash charges:
   Impairment of non-core
      proved properties                           --                     21
   Impairment of non-core
      unproved properties                         (3)                    18
   Write-down of capitalized
      development costs
      on proved properties                        --                     17
Cash charges:
   Employee terminations                           1                      6
   Consultants and other                          --                      3
- ---------------------------------------------------------------------------
                                                  (2)                    65
- ---------------------------------------------------------------------------
- ---------------------------------------------------------------------------
</TABLE>

The impact of these adjustments is to increase net earnings by $1 million
(2000 - decreased net earnings by $30 million).

3.   ROYALTIES

Oil Sands Crown royalty payments in 2001 were based on a minimum royalty rate
of 1% of gross revenues (2000 and 1999 - 5% of gross revenues).

<TABLE>
<CAPTION>
                                 2001                          2000                          1999
($ millions)           Crown     Other     Total     Crown     Other     Total     Crown     Other     Total
<S>                    <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>
Oil Sands                 15        15        30        87        11        98        48         3        51
Natural Gas               93        11       104        90        11       101        40         8        48
Total                    108        26       134       177        22       199        88        11        99
</TABLE>


56    SUNCOR ENERGY INC.
<PAGE>

4.   SUPPLEMENTAL INFORMATION

<TABLE>
<CAPTION>
($ millions)                                    2001           2000           1999
<S>                                             <C>            <C>            <C>
Export sales (1)                                 590            478            233
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
Exploration expenses
   Geological and geophysical                     11             10             10
   Other                                           1              2              2
- ----------------------------------------------------------------------------------
   Cash costs                                     12             12             12
   Dry hole costs                                 10             41             28
- ----------------------------------------------------------------------------------
   Cash and dry hole costs (2)                    22             53             40
   Leasehold impairment (3)                        9             10             12
- ----------------------------------------------------------------------------------
                                                  31             63             52
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
Taxes other than income taxes
   Excise taxes (4)                              343            336            311
   Production, property and other taxes           24             25             23
- ----------------------------------------------------------------------------------
                                                 367            361            334
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
Interest expense
   Long-term interest cost                       143            112             71
   Less interest capitalized                    (125)          (104)           (45)
- ----------------------------------------------------------------------------------
                                                  18              8             26
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
Cash interest payments                           130            104             63
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
Allowance for doubtful accounts                    3              3              3
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
</TABLE>

In 2001, the company had in place a securitization program to sell, on a
revolving, fully serviced and limited recourse basis, up to $170 million of
accounts receivable having a maturity of 45 days or less to a third party. As
at December 31, 2001, $166 million in accounts receivable had been sold under
the program. Under the recourse provisions, the company would provide
indemnification against credit losses to a maximum of $54 million. The
company believes it has no significant exposure to credit losses. Proceeds
received from new securitizations and proceeds from collections reinvested in
previous securitizations for the year-ended December 31, 2001 were
approximately $44 and $1,804 million, respectively. The company recorded a
loss of approximately $3 million on the securitization program in 2001.

(1)  Sales of crude oil, natural gas and refined products to customers in the
     United States and petrochemicals in Europe.

(2)  Exploration expenses in the Consolidated Statements of Earnings.

(3)  Included in depreciation, depletion and amortization in the Consolidated
     Statements of Earnings.

(4)  Excise taxes are also included in sales and other operating revenues in the
     Consolidated Statements of Earnings.

5.   INCOME TAXES

THE ASSETS AND LIABILITIES SHOWN ON SUNCOR'S BALANCE SHEETS ARE CALCULATED
USING ACCOUNTING RULES KNOWN AS GENERALLY ACCEPTED ACCOUNTING PRINCIPLES.
SUNCOR'S INCOME TAXES ARE CALCULATED ACCORDING TO GOVERNMENT TAX LAWS AND
REGULATIONS, WHICHCOULD RESULT IN DIFFERENT VALUES FOR SOME ASSETS AND
LIABILITIES FOR INCOME TAX PURPOSES. THESE DIFFERENCES ARE KNOWN AS TEMPORARY
DIFFERENCES, BECAUSE EVENTUALLY THESE DIFFERENCES WILL REVERSE.

THE AMOUNTS SHOWN ON THE BALANCE SHEETS AS FUTURE INCOME TAXES REPRESENT
INCOME TAXES THAT WILL EVENTUALLY BE PAYABLE OR RECOVERABLE IN FUTURE YEARS
WHEN THESE TEMPORARY DIFFERENCES DO REVERSE.

SEE BELOW FOR MORE TECHNICAL DETAILS AND NUMBERS.

The provision for income taxes reflects an effective tax rate that differs
from the statutory tax rate. A reconciliation of the two rates and the dollar
effect is as follows:

<TABLE>
<CAPTION>
                                                        2001                       2000                       1999
($ millions)                                     Amount          %          Amount          %          Amount          %
<S>                                              <C>           <C>          <C>           <C>          <C>           <C>
Federal tax rate                                    195         38             236         38             118         38
Provincial abatement                                (51)       (10)            (62)       (10)            (31)       (10)
Federal surtax                                        6          1               7          1               3          1
Provincial tax rates                                 69         14              96         16              48         16
- ------------------------------------------------------------------------------------------------------------------------
STATUTORY TAX AND RATE                              219         43             277         45             138         45
Add (deduct) the tax effect of:
Crown royalties (see note 3)                         48          9              83         13              44         13
Resource allowance                                  (77)       (15)           (101)       (17)            (56)       (17)
Large corporations tax                               16          3              10          2              10          3
Tax rate changes on future income taxes*            (52)       (11)            (13)        (2)             --         --
Attributed Canadian royalty income                   (6)        (1)            (13)        (2)             --         --
Assessments and adjustments                         (11)        (2)             (3)        --              --         --
Other                                               (12)        (2)              3         --             (11)        (4)
- ------------------------------------------------------------------------------------------------------------------------
INCOME TAXES AND EFFECTIVE RATE                     125         24             243         39             125         40
- ------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>

* Includes $(43) million, (9)% related to revaluation of future income tax
  balances (2000 - $(13) million, (2)%; 1999 - nil). 2001 income tax payments
  totalled $23 million (2000 - $22 million; 1999 - $5 million).


                                                        2001 ANNUAL REPORT    57
<Page>

At December 31, future income taxes are comprised of the following:

<TABLE>
<CAPTION>
                                                                     2001                                    2000
($ millions)                                               Current           Non-current           Current           Non-current
<S>                                                        <C>               <C>                   <C>               <C>
Future income tax assets:
   Employee future benefits                                      4                    30                 2                    39
   Reclamation and environmental remediation costs               8                    19                 9                    23
   Royalties                                                    --                    44                --                    43
   Employee incentive plans                                     --                    29                --                    10
   Inventories                                                  11                    --                20                    --
   Other                                                         6                    10                14                     4
- --------------------------------------------------------------------------------------------------------------------------------
                                                                29                   132                45                   119
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
Future income tax liabilities:
   Depreciation                                                 --                 1 105                --                 1 038
   Overburden removal costs                                     --                    30                --                    23
   Maintenance shutdown costs                                   --                    10                --                    12
   Inventories                                                  10                    --                --                    --
   Other                                                        18                    35                 9                     7
- --------------------------------------------------------------------------------------------------------------------------------
                                                                28                 1 180                 9                 1 080
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>

6.   RELATED PARTY TRANSACTIONS

The following table summarizes the company's related party transactions for
the year and balances at the end of the year. These transactions are in the
normal course of operations and have been carried out on the same terms as
would apply with unrelated parties.

<TABLE>
<CAPTION>
($ millions)                             2001           2000           1999
<S>                                      <C>            <C>            <C>
Revenues
   Sales to Sunoco
      joint ventures:
      Refined products                    602            600            395
      Petrochemicals                      131            128            108
- ---------------------------------------------------------------------------
At the end of the year,
   amounts due from related
   parties are as follows:
Sunoco joint ventures                      33             58             45
- ---------------------------------------------------------------------------
</TABLE>

Sales to and balances with Sunoco joint ventures are exchange amounts
established and agreed to by the related parties.

The company has exclusive supply agreements with two Sunoco joint ventures
for the sale of refined products. The company plans to maintain its
relationship with these joint ventures.

The company also has a non-exclusive supply agreement with a Sunoco joint
venture for the sale of petrochemicals.

7.   INVENTORIES

<TABLE>
<CAPTION>
($ millions)                       2001           2000          1999
<S>                                <C>            <C>           <C>
Crude Oil                           115             83            47
Refined Products                     71             55            67
Materials and Supplies               72             54            47
Total                               258            192           161
</TABLE>

The replacement cost at December 31, 2001, of all inventories valued at LIFO
exceeded their carrying value by $5 million (2000 - $61 million; 1999 - $37
million).

In 2000, the company sold inventories produced in prior years whose LIFO
costs were lower than current crude oil and operating costs. The impact of
this reduction in inventory was to decrease expenses by $8 million and
increase net earnings by $5 million.


58    SUNCOR ENERGY INC.
<Page>

8.   PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                         2001                       2000                      1999
                                                               Accum.                     Accum.                      Accum.
($ millions)                                      Cost      Provision        Cost      Provision        Cost       Provision
<S>                                              <C>        <C>             <C>        <C>             <C>         <C>
Oil Sands
   Plant                                         1 744            557       1 632            476       1 690             470
   Mine and mobile equipment                     1 008            337         918            313         850             243
   Pipeline costs                                   81             23          81             20          80              17
   Capitalized energy services asset lease         101              6         101              2          --              --
   Capitalized aircraft lease                        8             --           8             --          --              --
   Project Millennium*                           3 618              8       2 536              6         905              --
   Project Firebag - in progress                   275             --         101             --          --              --
- ----------------------------------------------------------------------------------------------------------------------------
                                                 6 835            931       5 377            817       3 525             730
- ----------------------------------------------------------------------------------------------------------------------------
Natural Gas
   Proved properties (note 3)                      965            423         877            366       1 190             487
   Unproved properties (note 3)                    114             48         125             56         344             171
   Pipeline                                         20             17          20             17          22              18
   Other support facilities and equipment           14              8          13              6          19              12
- ----------------------------------------------------------------------------------------------------------------------------
                                                 1 113            496       1 035            445       1 575             688
- ----------------------------------------------------------------------------------------------------------------------------
Sunoco
   Refinery                                        771            391         745            367         740             350
   Marketing and transportation                    434            209         405            187         380             165
- ----------------------------------------------------------------------------------------------------------------------------
                                                 1 205            600       1 150            554       1 120             515
- ----------------------------------------------------------------------------------------------------------------------------
Corporate
   Stuart Oil Shale Project (note 2)                --             --         134             --         237              --
   Other                                            19              4           6              3           7               3
- ----------------------------------------------------------------------------------------------------------------------------
                                                    19              4         140              3         244               3
- ----------------------------------------------------------------------------------------------------------------------------
                                                 9 172          2 031       7 702          1 819       6 464           1 936
- ----------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment                               7 141                      5 883                       4 528
- ----------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>

Interest capitalized during 2001 totalled $125 million (2000 - $104 million;
1999 - $45 million).

Capitalized costs related to the in-progress phase of projects are not being
depreciated until the facilities are substantially complete and ready for
commercial production to commence. Effective January 1, 2002, Project
Millennium commenced commercial production, therefore depreciation will begin
in January 2002.

* Project Millennium costs include capitalized interest of $229 million (2000 -
  $111 million; 1999 - $21 million). Start-up costs related to Project
  Millennium have been expensed.

9.   DEFERRED CHARGES AND OTHER

<TABLE>
<CAPTION>
($ millions)                                          2001              2000             1999
<S>                                                   <C>               <C>              <C>
Oil sands overburden removal costs (see below)         101                76               85
Deferred maintenance shutdown costs                     34                35               45
Investments                                              7                 8                8
Goodwill                                                14                14               13
Other                                                   43                33               40
- ---------------------------------------------------------------------------------------------
                                                       199               166              191
- ---------------------------------------------------------------------------------------------
Oil Sands overburden removal costs
   Balance - beginning of year                          76                85               95
   Outlays during year                                 119                75               53
   Depreciation on equipment during year                 9                 8                6
- ---------------------------------------------------------------------------------------------
                                                       204               168              154
   Amortization during year                           (103)              (92)             (69)
- ---------------------------------------------------------------------------------------------
   Balance - end of year                               101                76               85
- ---------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------
</TABLE>

                                                        2001 ANNUAL REPORT    59

<Page>

10.  LONG-TERM BORROWINGS

<TABLE>
<CAPTION>
($ millions)                                                         2001            2000             1999
<S>                                                                 <C>             <C>              <C>
FIXED RATE BORROWINGS
Medium-term Notes, maturing in 2011
   Interest payable semi-annually*                                    500              --               --
Medium-term Notes, maturing in 2007
   Interest payable semi-annually                                     400             400              400
7.4% Debentures, Series C, maturing in 2004
   Interest payable semi-annually**                                   125             125              125
Borrowings under or with support of lines of credit
   converted to fixed rate obligations by interest rate
   swap transactions, maturing in 2003. Interest payable
   quarterly at rates averaging 5.6%***                               110             110              110
Stuart Oil Shale Project borrowings (note 1)                           --              73               82
Sunoco joint venture borrowings with interest at rates
   averaging 7.1% at December 31, 2001
   (2000 - 7.7%; 1999 - 7.6%)                                           6               4                5
- ----------------------------------------------------------------------------------------------------------
                                                                    1 141             712              722
Capital leases****                                                    109             109               --
Less current portion of fixed rate long-term borrowings                --               1                1
- ----------------------------------------------------------------------------------------------------------
                                                                    1 250             820              721
- ----------------------------------------------------------------------------------------------------------
VARIABLE RATE BORROWINGS*****
Borrowings with interest at variable rates averaging
   2.7% at December 31, 2001 (2000 - 6.0%; 1999 - 5.2%)
   under or with support of lines of credit                         1 863           1 372              585
- ----------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM BORROWINGS                                          3 113           2 192            1 306
- ----------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------
</TABLE>

*    During 2001, the company issued $500 million of Series 2 Medium-term Notes
     at an interest rate of 6.7%. The net proceeds received were used to repay
     commercial paper and bank borrowings.

**   During 1996, the company entered into a cross-currency interest rate swap
     transaction to convert its 7.4% debentures to a 6.2% fixed interest rate
     U.S. dollar obligation of approximately $91 million. Later in 1996, the
     company entered into another cross-currency interest rate swap transaction
     to convert the US$91 million obligation back to a fixed rate Cdn$125
     million obligation. The net effect of the two swap transactions was to
     reduce the effective interest rate on the debentures from 7.3% (7.4% coupon
     rate) to 5.5%. In 2001, the two swap transactions were terminated,
     resulting in a deferred gain on settlement of $5 million, which is
     classified as accrued liabilities in the consolidated balance sheets and
     which is being recognized in earnings as a reduction of interest expense
     over the period to maturity of the debentures.

***  During 1998, the company entered into interest rate swap transactions to
     convert $50 million and $60 million of variable rate borrowings to fixed
     interest rate obligations at 5.5% and 5.7%, respectively.

**** Obligations under capital leases are as follows:

<TABLE>
<CAPTION>
($ millions)                                       2001           2000
<S>                                                <C>            <C>
Energy services assets lease with
   interest at 6.82% maturing in 2004               101            101
Aircraft lease with interest at prime
   plus 0.5% maturing in 2008                         8              8
- ----------------------------------------------------------------------
                                                    109            109
- ----------------------------------------------------------------------
- ----------------------------------------------------------------------
</TABLE>

Future minimum amounts payable under these capital leases are as follows:

<TABLE>
<CAPTION>
                                                               ($ millions)
<C>                                                            <C>
2002                                                                      8
2003                                                                      8
2004                                                                    108
2005                                                                      1
2006                                                                     --
Later years                                                               6
- ---------------------------------------------------------------------------
Total minimum lease payments                                            131
- ---------------------------------------------------------------------------
Less amount representing imputed interest                               (22)
- ---------------------------------------------------------------------------
Present value of obligation under capital leases                        109
- ---------------------------------------------------------------------------
- ---------------------------------------------------------------------------
</TABLE>

***** During 1999, the company entered into a cross-currency interest rate swap
      transaction to convert US$183 million of variable rate borrowings with
      interest based on 90-day LIBOR to Cdn$278 million with interest based on
      90-day bankers acceptances. In 2001, swap transactions for US$71 million
      (Cdn$109 million) of these borrowings were settled. There was no gain or
      loss on settlement.

LONG-TERM BORROWINGS

<TABLE>
<CAPTION>
(per cent)                      2001                2000                 1999
<S>                             <C>                 <C>                  <C>
Variable rate                     60                  63                   45
Fixed rate                        40                  37                   55
</TABLE>


60    SUNCOR ENERGY INC.

<PAGE>

Principal repayments of long-term borrowings other than obligations under
capital leases in each of the next five years are as follows:

<TABLE>
<CAPTION>
                                                    ($ millions)
<C>                                                 <C>
2002                                                         --
2003                                                          3
2004                                                      2 099
2005                                                         --
2006                                                         --
- ---------------------------------------------------------------
</TABLE>

11.  LINES OF CREDIT

At December 31, 2001, the company had available $2,337 million in credit and
term loan facilities, of which $1,112 million had been drawn, as follows:

o    A facility for $600 million that is fully revolving for 364 days, has a
     term period of three years and expires in 2004.

o    A facility for $550 million that is fully revolving for 364 days and
     expires in 2002.

o    A facility for US$112 million (Cdn$169 million) that is non-revolving, has
     been fully drawn and expires in 2004.

o    A facility for $1,003 million that is fully revolving for six years and
     expires in 2004.

o    Uncommitted facilities totalling $15 million, which can be terminated at
     any time at the option of the lenders.

The company is also authorized, supported by unutilized credit and term loan
facilities, to issue commercial paper to a maximum of $900 million, having a
term not to exceed 364 days. At December 31, 2001, the company had $861
million in commercial paper outstanding.

These credit facilities are subject to commitment fees, the amounts of which
are not significant.

12.  ACCRUED LIABILITIES AND OTHER

<TABLE>
<CAPTION>
($ millions)                           2001         2000         1999
<S>                                    <C>          <C>          <C>
Reclamation and Environmental
   Remediation Costs (a)                 61           70           86
Pension Costs (see note 13)             110           95           96
Other (b)                                80           87           54
Total                                   251          252          236
</TABLE>

(a)  RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS

Total accrued reclamation and environmental remediation costs also include
$23 million in current liabilities (2000 - $27 million; 1999 - $13 million).
Payments during 2001 totalled $28 million (2000 - $15 million; 1999 - $13
million).

(b)  EMPLOYEE AND DIRECTOR INCENTIVE PLANS

Compensation expense recorded under the company's long-term employee
incentive plans was $42 million (2000 - $32 million; 1999 - $26 million).
Compensation expense is an estimated amount, based on the market price of the
company's common shares and expected performance achievement, and is
therefore subject to measurement uncertainty and volatility. Vesting of these
plans will occur on April 1, 2002. At December 31, 2001, the estimated
portion of these awards expected to be paid in cash of $32 million is
included in accrued liabilities, with the remaining $72 million included in
accrued liabilities and other.

Compensation expense in the form of common share equivalents under the
directors' compensation plan is not significant.

13.  EMPLOYEE FUTURE BENEFITS

WHEN EMPLOYEES WORK FOR SUNCOR, THEY ARE ELIGIBLE TO RECEIVE PENSION, HEALTH
CARE AND INSURANCE BENEFITS WHEN THEY RETIRE. THIS BENEFIT OBLIGATION OR
COMMITMENT THAT SUNCOR HAS TO EMPLOYEES AND RETIREES AT DECEMBER 31, 2001,
WAS $554 MILLION.

AS REQUIRED BY GOVERNMENT REGULATIONS AND PLAN PERFORMANCE, SUNCOR SETS ASIDE
FUNDS, WHICH ARE IN THE CUSTODY OF AN INDEPENDENT TRUSTEE, TO MEET THESE
OBLIGATIONS. AT THE END OF DECEMBER, 2001, PLAN ASSETS TO MEET THE BENEFIT
OBLIGATION WERE $301 MILLION.

THE EXCESS OF THE BENEFIT OBLIGATION OVER PLAN ASSETS OF $253 MILLION
REPRESENTS THE NET UNFUNDED OBLIGATION.

SEE BELOW FOR MORE TECHNICAL DETAILS AND NUMBERS.

DEFINED BENEFIT PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS

The company's defined benefit pension plans provide a pension benefit at
retirement based upon years of service and final average earnings. The
defined benefit pension plans consist of a funded plan that covers most
employees, and unfunded supplementary benefit plans that provide supplemental
retirement benefits to executives. Under the funded plan, the company makes
contributions to an independent trustee to cover pension payment obligations
to retired employees. The trustee acts as the depository for contributions,
the disbursing agent and custodian of the pension plan's assets. These assets
are managed by a pension fund investment committee, on behalf of the
beneficiaries, which retains independent managers and advisers.

The company's other post-retirement benefits program, which is unfunded,
includes certain health care and life insurance benefits provided to retired
employees and eligible surviving dependants. Retirees share in the cost of
providing these benefits.


                                                        2001 ANNUAL REPORT    61
<PAGE>

Company contributions to the funded pension plan, the present value of
pension and other post-retirement benefit obligations and periodic benefit
costs are determined by an independent actuary in accordance with regulatory
requirements, based on management's best estimate of actuarial assumptions.

ASSUMPTIONS AND ESTIMATES

<TABLE>
<CAPTION>
                                                                   Other Post-
                             Pension Benefits                  retirement Benefits
(per cent)             2001        2000        1999        2001        2000        1999
<S>                    <C>         <C>         <C>         <C>         <C>         <C>
Discount Rate          6.50        7.00        7.25        6.50        7.00        7.25
Expected Return
   on Plan Assets      7.25        7.25        7.25          --          --          --
Rate of Compen-
   sation Increase     4.25        4.25        4.25        4.25        4.25        4.25
</TABLE>

The following table presents information about the funded status of the plans
and obligations recognized in the consolidated balance sheets at December 31:

<TABLE>
<CAPTION>
                                                           Pension Benefits             Other Post-retirement Benefits
                                                     2001        2000        1999        2001        2000        1999
<S>                                                  <C>         <C>         <C>         <C>         <C>         <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year               404         364         403          79          69          72
Service costs                                          14          12          15           3           3           4
Interest costs                                         28          26          24           6           5           4
Plan participants' contribution                         3           3           2          --          --          --
Amendments                                             --          --          --          --          --          (8)
Actuarial (gain) loss                                  34          23         (61)          7           4          (1)
Benefits paid                                         (22)        (24)        (19)         (2)         (2)         (2)
- ---------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year                     461         404         364          93          79          69
- ---------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS*
Fair value of plan assets at beginning of year        322         316         278          --          --          --
Actual return on plan assets                          (14)         15          39          --          --          --
Employer contribution                                  12          12          16          --          --          --
Plan participants' contribution                         3           3           2          --          --          --
Benefits paid                                         (22)        (24)        (19)         --          --          --
- ---------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year              301         322         316          --          --          --
- ---------------------------------------------------------------------------------------------------------------------
Net unfunded obligation                              (160)        (82)        (48)        (93)        (79)        (69)
Items not yet recognized in earnings:
Unamortized transitional asset                         --          (8)        (16)         --          --          --
Unamortized net actuarial loss                        109          45          18          19          13          11
- ---------------------------------------------------------------------------------------------------------------------
Accrued benefit liability                             (51)        (45)        (46)        (74)        (66)        (58)
- ---------------------------------------------------------------------------------------------------------------------
   Current portion                                    (15)        (15)         (8)         (2)         (2)         (2)
   Long-term portion                                  (36)        (30)        (38)        (72)        (64)        (56)
- ---------------------------------------------------------------------------------------------------------------------
                                                      (51)        (45)        (46)        (74)        (66)        (58)
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>

* Assets in the employees' pension plan consist of marketable equity securities,
  government and corporate bonds and short-term notes. Pension plan assets are
  not the company's assets and therefore are not included in the consolidated
  balance sheets.

The above benefit obligation at year-end includes funded and unfunded plans, as
follows:

<TABLE>
<CAPTION>
                                                           Pension Benefits             Other Post-retirement Benefits
                                                     2001        2000        1999        2001        2000        1999
<S>                                                  <C>         <C>         <C>         <C>         <C>         <C>
Funded plan                                           377         334         309          --          --          --
Unfunded plans                                         84          70          55          93          79          69
- ---------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year                     461         404         364          93          79          69
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>


62    SUNCOR ENERGY INC.

<PAGE>

The components of net periodic benefit cost are as follows:

<TABLE>
<CAPTION>
                                                           Pension Benefits             Other Post-retirement Benefits
                                                     2001        2000        1999        2001        2000        1999
<S>                                                  <C>         <C>         <C>         <C>         <C>         <C>
Service costs                                          14          12          15           3           3           4
Interest costs                                         28          26          24           6           5           4
Expected return on plan assets                        (23)        (22)        (22)         --          --          --
Amortization of transitional asset                     (8)         (8)         (8)         --          --          --
Amortization of net actuarial loss                      9           6          12           1           1           1
- ---------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost                              20          14          21          10           9           9
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>

The unamortized net actuarial loss represents annually calculated differences
between actual and projected plan performance. These amounts are amortized as
part of the net periodic benefit cost over the expected average remaining
service life of employees of 13 years for pension benefits (2000 and 1999 -
13 years), and over the expected average future service life to full
eligibility age of 11 years for post-retirement benefits.

In order to measure the expected cost of other post-retirement benefits, a
9.5% annual rate of increase in the per capita cost of covered health care
benefits was assumed for 2001. The rate was assumed to decrease gradually
each year to a rate of 5% for 2010 and remain at that level thereafter.

Assumed health care cost trend rates have a significant effect on the amounts
reported for other post-retirement benefit obligations. A 1% change in
assumed health care cost trend rates would have the following effects:

<TABLE>
<CAPTION>
                                                     1%              1%
($ millions)                                   Increase        Decrease
<S>                                            <C>             <C>
Effect on total of service
   and interest cost components
   of net periodic post-retirement
   health care benefit cost                           2              (1)
- -----------------------------------------------------------------------

Effect on the health care
   component of the accumulated
   post-retirement benefit obligation                17             (13)
- -----------------------------------------------------------------------
</TABLE>

DEFINED CONTRIBUTION PENSION PLAN

The company has a defined contribution plan, under which both the company and
employees make contributions. Company contributions, which totalled $4
million (2000 - $4 million; 1999 - $4 million), are based on employees'
earnings and contributions.

14.  COMMITMENTS AND CONTINGENCIES

(a)  OPERATING COMMITMENTS

In order to ensure continued availability of, and access to, facilities and
services to meet its operational requirements, the company enters into
non-cancellable operating leases for service stations, office space and other
property and equipment, as well as transportation service agreements for
pipeline capacity and an energy services agreement. Under contracts existing
at December 31, 2001, future minimum amounts payable under these leases and
agreements are as follows:

<TABLE>
<CAPTION>
                         Pipeline Capacity               Operating
($ millions)           and Energy Services *                Leases
<C>                    <C>                               <C>
2002                                   131                      45
2003                                   134                      42
2004                                   133                      36
2005                                   141                      32
2006                                   148                      29
Later years                          3 826                      89
- ------------------------------------------------------------------
                                     4 513                     273
- ------------------------------------------------------------------
- ------------------------------------------------------------------
</TABLE>

* Includes annual tolls payable under a transportation service agreement with a
  major pipeline company to use a portion of its pipeline capacity and tankage
  for the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The
  agreement commenced in 1999 and extends to 2028. As the initial shipper on the
  pipeline, Suncor's annual tolls payable under the agreement could be subject
  to annual adjustments.

  To meet the energy needs of its oil sands operation, Suncor has a commitment
  under long-term energy agreements to obtain a portion of the power and all of
  the steam generated by a cogeneration facility owned by a major energy
  company. Effective October 1999, this company also commenced managing the
  operations of Suncor's existing energy services facility.

(b)  CONTINGENCIES

The company is subject to various regulatory and statutory requirements
relating to the protection of the environment. These requirements, in
addition to contractual agreements and management decisions, result in the
accrual of estimated reclamation and environmental remediation costs. These
costs are accrued at the company's natural gas and oil sands operations on
the unit of production basis. Estimated environmental remediation costs at
service stations are also accrued upon completion of site investigations.
These costs are reduced by any estimated gains likely to be realized on a
sale of these sites. Any changes in these estimates will affect future
earnings.


                                                        2001 ANNUAL REPORT    63

<Page>

Under the company's business interruption insurance coverage, the company
would bear the first $415 million of any loss arising from a future insured
incident at its Oil Sands operations.

The company is defendant and plaintiff in a number of legal actions that
arise in the normal course of business.

Costs attributable to these commitments and contingencies are expected to be
incurred over an extended period of time and to be funded mainly from the
company's cash provided from operating activities. Although the ultimate
impact of these matters on net earnings cannot be determined at this time, it
could be material for any one quarter or year. The company believes that any
liabilities which might arise pertaining to such matters would not be
expected to have a material effect on the company's consolidated financial
position.

15.  PREFERRED SECURITIES

During 1999, the company completed a Canadian offering of $276 million of
9.05% preferred securities and a U.S. offering of US$162.5 million of 9.125%
preferred securities, the proceeds of which totalled Cdn$507 million after
issue costs of $17 million ($10 million after income tax credits of $7
million). The preferred securities are unsecured junior subordinated
debentures, due in 2048 and redeemable at the company's option on or after
March 15, 2004. Subject to certain conditions, the company has the right to
defer payment of interest on the securities for up to 20 consecutive
quarterly periods. Deferred interest and principal amounts are payable in
cash, or, at the option of the company, from the proceeds on the sale of
equity securities of the company delivered to the trustee of the preferred
securities. Accordingly, the preferred securities are classified as share
capital in the consolidated balance sheet and the interest distributions
thereon, net of income taxes, are classified as dividends. Proceeds from the
offerings were used to repay commercial paper borrowings.

16.  SHARE CAPITAL

(a)  AUTHORIZED:

COMMON SHARES

The company is authorized to issue an unlimited number of common shares
without nominal or par value.

PREFERRED SHARES

The company is authorized to issue an unlimited number of preferred shares
without nominal or par value in series.

(b)  ISSUED:

The number of common shares and common share options outstanding, common
share prices and per share calculations, for both current and prior periods,
reflect a two-for-one split of the company's common shares during 2000.

<TABLE>
<CAPTION>
                                                Common Shares
($ millions)                              Number                 Amount
<S>                                 <C>                          <C>
Balance as at
   December 31, 1998                220 433 656                     518
Issued for cash under
   stock option plan                    587 850                       6
Issued under dividend
   reinvestment plan                     10 732                      --
- -----------------------------------------------------------------------
Balance as at
   December 31, 1999                221 032 238                     524
Issued for cash under
   stock option plan                    738 176                       9
Issued under dividend
   reinvestment plan                    130 165                       4
- -----------------------------------------------------------------------
Balance as at
   December 31, 2000                221 900 579                     537
Issued for cash under
   stock option plan                  1 048 069                      15
Issued under dividend
   reinvestment plan                     29 597                       3
- -----------------------------------------------------------------------
BALANCE AS AT
   DECEMBER 31, 2001                222 978 245                     555
- -----------------------------------------------------------------------
</TABLE>

COMMON SHARE OPTIONS

i)   EXECUTIVE STOCK PLAN

Under this plan, the company has granted common share options to non-employee
directors and certain executives of the company and its subsidiaries. The
exercise price of an option is equal to the market value of the common shares
at the date of grant. Options granted to non-employee directors are
exercisable immediately. Options granted to employees are exercisable as
follows: one-third after one year, the second third after two years and the
final third after three years from the grant date. No option may be
exercisable more than 10 years after the grant date.

ii)  EMPLOYEE STOCK OPTION PROGRAM

Under this program, the company granted 1,063,000 share options to certain
senior employees. The exercise price for these grants was equal to or greater
than the market value of the common shares at the grant date. Options vest
and are exercisable on April 1, 2002, one-half at that time and the other
half based on achievement of certain performance measurement criteria.


64    SUNCOR ENERGY INC.
<Page>

The following tables cover all common share options granted by the company:

<TABLE>
<CAPTION>
                                                                                         Weighted
Exercise price per share (dollars)             Number                    Range            Average
<S>                                        <C>                   <C>                     <C>
Outstanding, December 31, 1998              5 397 238             4.75 - 26.38              16.64
   Granted                                  1 090 456            20.25 - 30.18              20.70
   Exercised                                 (583 040)            4.75 - 24.55               9.76
   Cancelled                                  (46 668)           15.54 - 26.08              25.73
- -------------------------------------------------------------------------------------------------
Outstanding, December 31, 1999              5 857 986             4.75 - 30.18              18.01
   Granted                                    950 016            26.08 - 38.55              31.29
   Exercised                                 (737 202)            4.75 - 24.55              12.57
   Cancelled                                 (209 925)           20.25 - 33.03              26.03
- -------------------------------------------------------------------------------------------------
Outstanding, December 31, 2000              5 860 875             4.75 - 38.55              20.55
   Granted                                  1 090 360            31.88 - 42.70              35.26
   Exercised                               (1 014 334)            4.75 - 32.95              14.60
   Cancelled                                  (52 866)           20.25 - 40.40              28.42
- -------------------------------------------------------------------------------------------------
OUTSTANDING, DECEMBER 31, 2001              5 884 035             4.75 - 42.70              24.24
- -------------------------------------------------------------------------------------------------
Exercisable, December 31
   1999                                     2 609 816             4.75 - 26.98              12.89
- -------------------------------------------------------------------------------------------------
   2000                                     3 067 594             4.75 - 31.98              15.42
- -------------------------------------------------------------------------------------------------
   2001                                     3 067 806             4.75 - 42.70              19.34
- -------------------------------------------------------------------------------------------------
</TABLE>

Common shares authorized for issuance by the Board of Directors, that remain
available for the granting of future options, at December 31:

<TABLE>
<CAPTION>
(number of common shares)               2001              2000              1999
<S>                                <C>               <C>               <C>
                                   5 298 883         6 336 377         7 076 468
</TABLE>

The following table is an analysis of outstanding and exercisable common
share options as at December 31, 2001:

<TABLE>
<CAPTION>
                                           Outstanding                                             Exercisable
                      ----------------------------------------------------------        ---------------------------------
                                                Weighted                Weighted                                 Weighted
                                       Average Remaining        Average Exercise                         Average Exercise
Exercise Price           Number         Contractual Life         Price Per Share           Number         Price Per Share
<S>                   <C>              <C>                      <C>                     <C>              <C>
 4.75 - 12.80           795 460                        3                    9.94          795 460                    9.94
15.54 - 20.25         1 475 746                        6                   18.18        1 187 641                   17.67
24.55 - 28.12         1 670 761                        6                   25.56          648 584                   24.73
28.40 - 33.73           862 436                        8                   31.44          335 906                   31.49
34.90 - 42.70         1 079 632                        9                   35.26          100 215                   38.03
- -------------------------------------------------------------------------------------------------------------------------
Total                 5 884 035                        6                   24.24        3 067 806                   19.34
- -------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                        2001 ANNUAL REPORT    65
<Page>

iii) EARNINGS PER COMMON SHARE

The following table provides a reconciliation between basic and diluted
earnings per share:

<TABLE>
<CAPTION>
($ millions)                                                        2001            2000            1999
<S>                                                                 <C>             <C>             <C>
Net earnings attributable to common shareholders                     362             351             163
Dividends on preferred securities                                     -- **           26 ***          -- ****
- -------------------------------------------------------------------------------------------------------------
Net earnings before deducting dividends on preferred securities      362 **          377 ***         163 ****
- -------------------------------------------------------------------------------------------------------------
(millions of common shares)
Weighted-average number of common shares                             222             221             221
Dilutive securities:
   Options/shares issued under long-term incentive plan                3               2               2
   Preferred securities converted                                     -- **           17 ***          -- ****
- -------------------------------------------------------------------------------------------------------------
Weighted-average number of diluted common shares                     225             240             223
- -------------------------------------------------------------------------------------------------------------
(dollars per common share)
Basic earnings per share                                            1.63 *          1.58 *          0.74 *
Diluted earnings per share                                          1.61 **         1.57 ***        0.73 ****
- -------------------------------------------------------------------------------------------------------------
</TABLE>

*    Basic earnings per share is the net earnings attributable to common
     shareholders divided by the weighted-average number of common shares.

**   For the year-ended December 31, 2001, diluted earnings per share is the
     net earnings attributable to common shareholders divided by the weighted-
     average number of diluted common shares. Dividends on preferred securities
     of $26 million and preferred securities converted of 13 million shares
     have an anti-dilutive impact, therefore they are not included in the
     calculation of diluted earnings per share.

***  For the year-ended December 31, 2000, diluted earnings per share is the
     net earnings before deducting dividends on preferred securities divided by
     the weighted-average number of diluted common shares.

**** For the year-ended December 31, 1999, diluted earnings per share is the
     net earnings attributable to common shareholders divided by the weighted-
     average number of diluted common shares. Dividends on preferred securities
     of $22 million and preferred securities converted of 22 million shares
     have an anti-dilutive impact, therefore they are not included in the
     calculation of diluted earnings per share.

iv) FAIR VALUE OF OPTIONS GRANTED

The weighted average fair value of common share options granted in 2001 is
$6.41 per share (2000 - $7.12 per share; 1999- $7.01 per share). The fair
value of common share options granted is estimated as at the grant date using
the Black-Scholes option-pricing model, using the following assumptions:

<TABLE>
<CAPTION>
                                             2001              2000                1999
<S>                                        <C>               <C>                 <C>
Dividend                                   $0.34/            $0.34/              $0.34/
                                           share             share               share
Risk-free interest rate                    5.07%             6.45%               4.89%
Expected life                              5 years           7 years             7 years
Expected volatility                        35%               37%                 32%
- ----------------------------------------------------------------------------------------
</TABLE>

The company does not recognize compensation cost in the consolidated
statement of earnings when common share options are granted to non-employee
directors and employees. Had compensation cost been determined on the basis
of fair values using the Black-Scholes option-pricing model, 2001 net
earnings would have been lower by $9 million (2000 - $7 million; 1999 - $5
million), and 2001 earnings per share would have been lower by $0.04 (2000 -
$0.03; 1999 - $0.02).

17. FINANCIAL INSTRUMENTS

(a) BALANCE SHEET FINANCIAL INSTRUMENTS

The company's financial instruments recognized in the consolidated balance
sheets consist of cash and cash equivalents, accounts receivable, derivative
contracts not accounted for as hedges, investments in SPP and CPM,
substantially all current liabilities, except for income taxes payable and
future income taxes, and long-term borrowings.

The estimated fair values of recognized financial instruments have been
determined based on the company's assessment of available market information
and appropriate valuation methodologies; however, these estimates may not
necessarily be indicative of the amounts that could be realized or settled in
a current market transaction.

The fair values of cash and cash equivalents, accounts receivable and current
liabilities approximate their carrying amounts due to the short-term maturity
of these instruments.

At December 31, 2001, the company had outstanding crude oil and U.S. dollar
swap contracts maturing in 2004, fixing the purchase price of 2 130 000
barrels of crude oil at Cdn$49 million. These derivative contracts, which
have not been accounted for as hedges, had a fair value and carrying value of
$13 million at December 31, 2001 (2000 - $10 million; 1999 - $(2) million).

The fair value of the company's investment in the shares of SPP and CPM is
determined based on quoted market prices.


66    SUNCOR ENERGY INC.
<Page>

The following table summarizes estimated fair value information about the
company's long-term borrowings at December 31:

<TABLE>
<CAPTION>
                                              2001                             2000                             1999
($ millions)                   Carrying Amount    Fair Value    Carrying Amount    Fair Value    Carrying Amount    Fair Value
<S>                            <C>                <C>           <C>                <C>           <C>                <C>
Long-term borrowings
   -- fixed rate                         1 025         1 047                525           528                525           516
   -- variable rate                      1 974         1 974              1 482         1 482                695           695
   -- Sunoco joint ventures                  6             6                  3             3                  4             4
   -- Stuart Oil Shale Project              --            --                 73            73                 82            82
   -- capital leases                       109           109                109           109                 --            --
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>

The fair value of the company's fixed rate long-term borrowings, which are
publicly traded, is based on quoted market prices. The fair value of the
company's variable rate long-term borrowings, capital leases, and
proportionate share of the long-term borrowings of its Sunoco joint ventures
approximatesthe carrying amount.

(b) UNRECOGNIZED DERIVATIVE FINANCIAL INSTRUMENTS

The company is also a party to certain derivative financial instruments which
are not recognized in the consolidated balance sheets, as follows:

REVENUE AND MARGIN HEDGES

The company enters into crude oil and foreign currency swap and option
contracts to protect its future Canadian dollar earnings and cash flows from
the potential adverse impact of low petroleum prices and an unfavourable
U.S./Canadian dollar exchange rate. These contracts reduce fluctuations in
sales revenues by locking in fixed prices, or a range of fixed prices, and
exchange rates on the portion of its crude oil sales covered by the
contracts. The company also enters into crude oil and heating oil swap
contracts to lock in fixed margins on the portion of refined product sales
covered by the contracts. While these contracts reduce the risk of exposure
to adverse changes in commodity prices and exchange rates, they also reduce
the potential benefit of favourable changes in commodity prices and exchange
rates.

The contracts do not require the payment of premiums or cash margin deposits
prior to settlement. On settlement, these contracts result in cash receipts
or payments by the company for the difference between the contract and market
rates for the applicable dollars and volumes hedged during the contract term.
Such cash receipts or payments offset corresponding decreases or increases
in the company's sales revenues or crude oil purchase costs. For accounting
purposes, amounts received or paid on settlement are recorded as part of the
related hedged sales or purchase transactions.

Contracts outstanding at December 31 were as follows:

<TABLE>
<CAPTION>
($ millions except for average price)           Quantity           Average Price*           Revenue Hedged           Hedge Period
<S>                                       <C>                      <C>                      <C>                      <C>
REVENUE HEDGES
AS AT DECEMBER 31, 2001
Crude oil swaps and options*              40 576 bbl/day                      30                       444                   2002
                                             424 bbl/day                      21 (a)                     3 (a)               2002
                                          43 000 bbl/day                 22 - 27 (a)             345 - 424 (a)               2002
                                          44 000 bbl/day                 21 - 26 (a)             337 - 418 (a)               2003
                                          11 000 bbl/day                 21 - 24 (a)               84 - 96 (a)               2004
                                          15 000 bbl/day                      22 (a)                   120 (a)               2005
- ---------------------------------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 2000
Crude oil swaps and options*              42 710 bbl/day                      28                       436                   2001
                                           4 790 bbl/day                      20 (a)                    35 (a)               2001
                                          10 000 bbl/day                 26 - 32 (a)              95 - 117 (a)               2001
                                          41 000 bbl/day                      28                       426                   2002
                                           7 000 bbl/day                 22 - 26 (a)               56 - 66 (a)               2002
- ---------------------------------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 1999
Crude oil swaps*                          52 655 bbl/day                      26                       503                   2000
                                           9 845 bbl/day                      19 (a)                    67 (a)               2000
                                          35 000 bbl/day                      26                       327                   2001
                                           4 000 bbl/day                      26                        38                   2002
U.S. dollar swaps                                  US$81                    1.41                       114                   2001
                                                  US$289                    1.41                       408                   2002
- ---------------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

*   Average price for crude oil swaps is WTI per barrel at Cushing, Oklahoma.

(a) Average price and revenue hedged is in U.S. dollars, with no foreign
    exchange component.


                                                        2001 ANNUAL REPORT    67
<Page>

<TABLE>
<CAPTION>
($ millions except for average margin)        Quantity        Average Margin        Margin Hedged        Hedge Period
                                               bbl/day               US$/bbl                  US$
<S>                                           <C>             <C>                   <C>                  <C>
MARGIN HEDGES
Refined product sales and
   crude purchase swaps
As at December 31, 2001                             --                    --                   --                  --
As at December 31, 2000                          6 575                     5                   12                2001
As at December 31, 1999                             --                    --                   --                  --
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>

INTEREST RATE HEDGES

The company enters into interest rate and cross-currency interest rate swap
contracts as part of its risk management strategy to minimize exposure to
interest rate fluctuations. The interest rate swap contracts involve an
exchange of floating rate and fixed rate interest payments between the
company and a financial institution. The cross-currency swap contracts
involve an exchange of Canadian dollar interest payments and U.S. dollar
interest payments between the company and a financial institution, and an
exchange of Canadian and U.S. dollar principal amounts at the maturity date
of the underlying borrowing to which the swaps relate. The swap transactions
are completely independent from and have no direct effect on the relationship
between the company and its lenders. The differentials on the exchange of
periodic interest payments are recognized in the accounts as an adjustment to
interest expense.

The notional amounts of interest rate and cross-currency interest rate swap
contracts outstanding at December 31, 2001 are detailed in note 10, Long-Term
Borrowings.

FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS

The fair value of these hedging derivative financial instruments is the
estimated amount, based on brokers' quotes, that the company would receive
(pay) to terminate the contracts. Such amounts, which also represent the
unrecognized and unrecorded gain (loss) on the contracts, were as follows at
December 31:

<TABLE>
<CAPTION>
($ million)                           2001             2000             1999
<S>                                   <C>              <C>              <C>
Revenue hedge
   swaps and options                    54             (247)            (136)
Margin hedge swaps                      (2)             (11)              --
U.S. dollar swaps                       --               --               (1)
Interest rate and cross-
   currency interest
   rate swaps                            4                5               --
- ----------------------------------------------------------------------------
                                        56             (253)            (137)
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
</TABLE>

COUNTERPARTY CREDIT RISK

The company may be exposed to certain losses in the event that counterparties
to the derivative financial instruments are unable to meet the terms of the
contracts. The company's exposure is generally limited to those
counterparties holding derivative contracts with positive fair values at the
reporting date. The company minimizes this risk by entering into agreements
only with highly rated financial institutions, and through regular management
review of potential exposure to, and credit ratings of, such financial
institutions. At December 31, the company had exposure to credit risk with
counterparties as follows:

<TABLE>
<CAPTION>
($ millions)                                          2001        2000
<S>                                                   <C>         <C>
Derivative contracts not accounted for as hedges        12           8
Unrecognized derivative contracts                       93          --
- ----------------------------------------------------------------------
                                                       105           8
- ----------------------------------------------------------------------
- ----------------------------------------------------------------------

</TABLE>

18. ACCOUNTING FOR INTERSEGMENT REVENUES

During the first quarter of 2001, the company changed the methodology of
accounting for sales from its upstream operations to its downstream
operations from a deeming concept to one based on actual product shipments.
Under the deeming concept, upstream sales, except for sales to third parties
under long-term contracts, were deemed to be sold to downstream operations
and, therefore, eliminated on consolidation whether or not product was
actually shipped. The company's current operational activities are such that
product shipped from its upstream operations to its downstream operations is
considerably less than previous years and therefore, this change better
reflects the company's current operational activities and enhances
comparability within the industry.

The impact of this change in methodology in accounting for intersegment
sales, which has been applied prospectively, is to increase both sales and
other operating revenues and purchases of crude oil and products by $473
million. There is no impact on consolidated and segmented net earnings.


68    SUNCOR ENERGY INC.
<Page>

QUARTERLY SUMMARY
(unaudited)

<TABLE>
<CAPTION>
FINANCIAL DATA                                    Total                              Total                              Total
                         For the Quarter Ended    Year      For the Quarter Ended    Year       For the Quarter Ended   Year
                        Mar   June   Sept    Dec           Mar   June   Sept    Dec           Mar   June   Sept   Dec
($ millions except       31     30     30     31            31     30     30     31            31     30     30     31
per share amounts)     2001   2001   2001   2001   2001   2000   2000   2000   2000   2000   1999   1999   1999   1999   1999
<S>                   <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
REVENUES              1 001  1 098  1 013    883  3 995    779    820    862    927  3 388    469    564    639    715  2 387
- -----------------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)
Oil Sands                69    108     69     37    283     90     81     76     68    315     17     34     43     73    167
Natural Gas              53     39     13     12    117      8     16     43     31     98      3     13     20      5     41
Sunoco                   23     45     12     --     80     19     20     19     23     81      5      3     12      7     27
Corporate and
  eliminations          (20)   (28)   (21)   (23)   (92)   (12)    (6)   (88)   (11)  (117)   (14)   (17)    (5)   (13)   (49)
- -----------------------------------------------------------------------------------------------------------------------------
                        125    164     73     26    388    105    111     50    111    377     11     33     70     72    186
- -----------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
PER COMMON SHARE
  -- net earnings
     attributable
     to common
     shareholders
  -- basic             0.53   0.71   0.30   0.09   1.63   0.45   0.47   0.19   0.47   1.58   0.04   0.12   0.29   0.29   0.74
  -- diluted           0.52   0.70   0.30   0.09   1.61   0.44   0.46   0.20   0.47   1.57   0.04   0.12   0.29   0.28   0.73
- -----------------------------------------------------------------------------------------------------------------------------
  -- cash dividends   0.085  0.085  0.085  0.085   0.34  0.085  0.085  0.085  0.085   0.34  0.085  0.085  0.085  0.085   0.34
- -----------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
CASH FLOW PROVIDED
  FROM (USED IN)
  OPERATIONS
Oil Sands               140    117    139     90    486    199    181    156    119    655     53     90    104    158    405
Natural Gas             127     76     42     35    280     48     42     64     84    238     42     43     39     48    172
Sunoco                   50     67     30     18    165     46     38     49     41    174     23     17     37     26    103
Corporate and
  eliminations          (42)   (14)   (34)   (10)  (100)   (24)   (17)   (40)   (28)  (109)   (25)   (21)   (33)   (10)   (89)
- -----------------------------------------------------------------------------------------------------------------------------
                        275    246    177    133    831    269    244    229    216    958     93    129    147    222    591
- -----------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
OPERATING DATA                                    Total                              Total                              Total
                         For the Quarter Ended    Year      For the Quarter Ended    Year       For the Quarter Ended   Year
                        Mar   June   Sept    Dec           Mar   June   Sept    Dec           Mar   June   Sept   Dec
($ millions except       31     30     30     31            31     30     30     31            31     30     30     31
per share amounts)     2001   2001   2001   2001   2001   2000   2000   2000   2000   2000   1999   1999   1999   1999   1999
<S>                   <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
OIL SANDS
PRODUCTION (a)        113.4  109.7  116.5  153.0  123.2  114.8  116.7  114.2  110.0  113.9   95.5  112.0  101.5  113.2  105.6
SALES (a)
  -- light sweet
     crude oil         53.0   55.0   54.2   62.4   56.2   67.7   64.3   61.4   64.0   64.3   54.6   41.3   52.1   62.8   52.7
  -- diesel            13.5   15.2   15.0   15.3   14.8    8.7    8.6    8.9   11.0    9.3    7.9    6.8    8.4    9.5    8.2
  -- light sour
     crude oil         31.4   31.5   40.6   64.3   42.0   39.1   41.7   35.6   27.5   35.8   27.3   47.9   40.6   35.1   37.5
  -- bitumen            8.6   13.0    8.0    4.3    8.5    2.4    3.5    7.0   11.0    6.2    1.5    6.9    6.9     --    3.8
- -----------------------------------------------------------------------------------------------------------------------------
                      106.5  114.7  117.8  146.3  121.5  117.9  118.1  112.9  113.5  115.6   91.3  102.9  108.0  107.4  102.2
- -----------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
AVERAGE SALES
  PRICE (b)
  -- light sweet
     crude oil        36.09  36.05  35.20  30.22  34.17  34.35  33.54  36.21  37.22  35.31  20.55  24.47  27.23  30.81  26.06
  -- other (diesel,
     light sour
     crude oil
     and bitumen)     25.66  27.12  28.21  20.12  24.86  28.46  28.22  27.84  23.71  27.09  19.18  19.60  21.45  25.91  21.48
  -- total            30.84  31.40  31.43  24.43  29.17  31.84  31.12  32.39  31.33  31.67  20.00  21.57  24.24  28.77  23.84
  -- total*           38.17  38.35  37.37  25.65  34.21  39.19  39.40  43.41  43.27  41.29  18.52  22.29  27.56  33.72  25.89
Cash operating
  costs (1) (c)       15.40  17.00  18.25  17.45  17.00  11.10  12.20  14.50  16.40  13.55  12.55  10.90  12.35  11.15  11.70
Total operating
  costs (2) (c)       18.60  19.65  20.95  19.40  19.60  15.50  16.60  18.55  19.50  17.25  15.60  14.30  15.30  15.10  15.05
- -----------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                        2001 ANNUAL REPORT    69
<Page>
<TABLE>
<CAPTION>
OPERATING DATA
(continued)                                       Total                              Total                              Total
                         For the Quarter Ended    Year      For the Quarter Ended    Year       For the Quarter Ended   Year
                        Mar   June   Sept    Dec           Mar   June   Sept    Dec           Mar   June   Sept   Dec
($ millions except       31     30     30     31            31     30     30     31            31     30     30     31
per share amounts)     2001   2001   2001   2001   2001   2000   2000   2000   2000   2000   1999   1999   1999   1999   1999
<S>                   <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
NATURAL GAS
GROSS PRODUCTION**
Conventional
  -- natural
    gas (d)             177    177    176    180    177    222    195    200    183    200    229    225    231    219    226
  -- natural gas
    liquids (a)         2.3    2.3    2.4    2.4    2.4    3.5    3.1    2.8    2.5    3.0    4.7    4.1    4.1    4.0    4.2
  -- crude oil
    (a)***              1.7    1.5    1.5    1.3    1.5    8.1    3.5    3.6    1.6    4.2   10.8    9.7    8.4    7.9    9.2
  -- total (e)         33.5   33.3   33.2   33.7   33.4   48.6   39.1   39.7   34.6   40.5   53.7   51.3   51.0   48.4   51.1
AVERAGE SALES PRICE
  -- natural gas (f)  10.73   6.78   3.90   3.10   6.09   2.96   3.70   4.63   8.02   4.72   2.18   2.15   2.48   2.96   2.44
  -- natural gas (f)* 10.81   6.82   3.90   3.09   6.12   2.97   3.70   4.62   8.05   4.73   2.10   2.17   2.58   3.11   2.48
  -- natural gas
    liquids (b)       45.07  39.62  30.26  23.47  34.38  33.16  32.80  39.56  43.00  36.66  11.88  16.70  22.81  27.12  19.32
  -- crude oil --
    conventional (b)  37.35  36.75  33.17  27.17  33.92  26.30  30.04  33.09  36.01  29.50  18.48  20.48  20.55  25.21  20.94
  -- crude oil --
    conventional (b)* 42.12  42.30  37.86  28.60  38.14  38.23  38.65  42.31  44.35  39.80  16.28  21.89  28.01  32.72  24.01
SUNOCO
Refined product
  sales (g)****        14.9   15.3   15.1   14.0   14.8   14.3   15.1   14.0   15.2   14.6   13.1   14.1   13.9   14.2   13.8
Natural gas sales (d)    92    102     95     92     95     84     78     74     95     83     93     86     87     90     89
Margins --
  refining (3) (h)      6.2    8.1    4.3    3.7    5.7    5.4    6.3    6.1    5.8    5.9    3.4    3.3    4.8    4.3    4.0
  -- retail (4) (h)     6.1    7.6    5.9    6.9    6.6    6.8    6.4    6.4    7.0    6.6    7.9    7.6    6.9    7.2    7.4
Utilization of
  refining
  capacity (%)           88     98     99     83     92    102     99     96     95     98     97     93    100     92     95
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>

*    Excludes the impact of hedging activities.

**   Currently all Natural Gas production is located in the Western Canada
     Sedimentary Basin.

***  Before deducting 2001 Alberta Crown royalty of 0.2 thousand barrels per day
     (2000 - 0.5 thousand barrels per day; 1999 - 0.9 thousand barrels per day).

**** Excludes sales through joint venture interests.

Definitions

(1) Cash operating costs  - operating, selling and general expenses, taxes
                            other than income taxes, and overburden cash
                            expenditures for the period.

(2) Total operating costs - cash and non-cash operating costs (total Oil
                            Sands expenses less purchases of crude oil and
                            products and royalties in Schedules of Segmented
                            Data on page 52 and 53).

(3) Refining margin       - average wholesale unit price from all products
                            minus average unit cost of crude oil.

(4) Retail margin         - average street price of Sunoco-branded retail
                            gasoline minus refining gasoline price.

(a) thousands of barrels per day

(b) dollars per barrel

(c) dollars per barrel sold rounded to the nearest $0.05

(d) millions of cubic feet per day

(e) BOE (6:1 basis) per day

(f) dollars per thousand cubic feet

(g) thousands of cubic metres per day

(h) cents per litre

Metric conversion
Crude oil, refined products, etc.   1m3 (cubic metre) = approx. 6.29 barrels
Natural gas                         1m3 (cubic metre) = approx. 35.49 cubic feet


70    SUNCOR ENERGY INC.
<Page>

FIVE-YEAR FINANCIAL SUMMARY
(unaudited)

<TABLE>
<CAPTION>
($ millions except for ratios)                                     2001       2000       1999       1998       1997
<S>                                                               <C>        <C>        <C>        <C>         <C>
REVENUES
Oil Sands                                                         1 385      1 336        889        768        751
Natural Gas                                                         449        428        306        290        302
Sunoco                                                            2 588      2 604      1 779      1 533      1 673
Corporate and eliminations                                         (427)      (980)      (587)      (521)      (572)
- -------------------------------------------------------------------------------------------------------------------
                                                                  3 995      3 388      2 387      2 070      2 154
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)
Oil Sands                                                           283        315        167        145        175
Natural Gas                                                         117         98         41         24         23
Sunoco                                                               80         81         27         37         36
Corporate and eliminations                                          (92)      (117)       (49)       (28)       (20)
- -------------------------------------------------------------------------------------------------------------------
                                                                    388        377        186        178        214
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
CASH FLOW PROVIDED FROM (USED IN) OPERATIONS
Oil Sands                                                           486        655        405        320        331
Natural Gas                                                         280        238        172        167        162
Sunoco                                                              165        174        103        112        121
Corporate and eliminations                                         (100)      (109)       (89)       (19)       (39)
- -------------------------------------------------------------------------------------------------------------------
                                                                    831        958        591        580        575
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
CAPITAL AND EXPLORATION EXPENDITURES
Oil Sands                                                         1 479      1 808      1 057        507        491
Natural Gas                                                         132        127        200        242        240
Sunoco                                                               54         45         42         60         54
Corporate                                                            13         18         51        127         62
- -------------------------------------------------------------------------------------------------------------------
                                                                  1 678      1 998      1 350        936        847
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS                                                      8 094      6 833      5 176      4 104      3 457
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
CAPITAL EMPLOYED*
Debt
   Short-term borrowings                                             31         64         32         16         36
   Current portion of long-term borrowings                           --          1          1          1          6
   Long-term borrowings                                           3 113      2 192      1 306      1 298        767
Shareholders' equity                                              2 777      2 472      2 108      1 499      1 391
- -------------------------------------------------------------------------------------------------------------------
                                                                  5 921      4 729      3 447      2 814      2 200
Less capitalized costs related to major projects in progress     (3 691)    (2 497)    (1 084)      (373)      (599)
- -------------------------------------------------------------------------------------------------------------------
                                                                  2 230      2 232      2 363      2 441      1 601
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
RATIOS
Per common share (dollars)
   -- net earnings attributable to common shareholders             1.63       1.58       0.74       0.81       0.98
   -- cash dividends                                               0.34       0.34       0.34       0.34       0.34
   -- cash flow provided from operations                           3.73       4.32       2.68       2.64       2.62
   -- cash flow provided from operations
      attributable to common shareholders                          3.52       4.11       2.51       2.64       2.62
Return on capital employed (%)*                                    17.9       16.6        8.3        9.5       14.3
Return on shareholders' equity (%)*                                14.8       16.5       10.3       12.3       16.2
Debt to debt plus shareholders' equity (%)                         53.1       47.7       38.9       46.7       36.8
Debt to cash flow provided from operations (times)                  3.8        2.3        2.3        2.2        1.4
Interest coverage - cash flow basis*                                5.9        9.0        9.1        8.7       15.4
Interest coverage - net earnings basis*                             3.7        5.6        5.1        4.8        9.2
- -------------------------------------------------------------------------------------------------------------------
</TABLE>

* Definitions

  Capital employed - see page 52.

  Return on shareholders' equity - earnings as a percentage of average
  shareholders' equity. Average shareholders' equity is the aggregate of total
  shareholders' equity at the beginning and end of the year divided by two.

  Interest coverage - cash flow basis - cash provided from operations before
  interest expense and current income tax provision, divided by interest expense
  plus interest capitalized.

  Interest coverage - net earnings basis - net earnings before interest
  expense and income tax payments, divided by interest expense plus interest
  capitalized.


                                                        2001 ANNUAL REPORT    71
<Page>

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION
(unaudited)

<TABLE>
<CAPTION>
                                                                   2001       2000       1999       1998       1997
<S>                                                               <C>        <C>        <C>        <C>         <C>
OIL SANDS
PRODUCTION (thousands of barrels per day)                         123.2      113.9      105.6       93.6        79.4
SALES (thousands of barrels per day)
Light sweet crude oil                                              56.2       64.3       52.7       58.8        53.5
Diesel                                                             14.8        9.3        8.2        9.7        10.0
Light sour crude oil                                               42.0       35.8       37.5       26.6        14.6
Bitumen                                                             8.5        6.2        3.8         --          --
- --------------------------------------------------------------------------------------------------------------------
                                                                  121.5      115.6      102.2       95.1        78.1
- --------------------------------------------------------------------------------------------------------------------
AVERAGE SALES PRICE (dollars per barrel)
Light sweet crude oil                                             34.17      35.31      26.06      22.80       26.65
Other (diesel, light sour crude oil and bitumen)                  24.86      27.09      21.48      21.16       25.74
Total                                                             29.17      31.67      23.84      22.18       26.36
Total*                                                            34.21      41.29      25.89      20.37       27.98
Cash operating costs
   (dollars per barrel rounded to the nearest $0.05)**            17.00      13.55      11.70      11.75       13.25
Total operating costs
   (dollars per barrel rounded to the nearest $0.05)**            19.60      17.25      15.05      14.00       15.80
OTHER OIL SANDS STATISTICS
Overburden removed (millions of cubic metres)                      50.9       30.7       22.5       22.2        17.5
Oil sands mined (millions of tonnes)                               97.9       84.9       72.9       62.4        54.1
Average bitumen content of oil
   sands mined (per cent by weight)                                10.4       11.1       11.6       11.6        12.7
Average crude yield of oil
   sands mined (barrels per tonne)                                 .459       .491       .529       .547        .535
- --------------------------------------------------------------------------------------------------------------------
</TABLE>

* Excludes the impact of hedging activities.

**See definitions on page 70.


SYNTHETIC CRUDE OIL AND BITUMEN GROSS RESERVES*

<TABLE>
<CAPTION>

                                                                   Firebag
                                        Mining Reserves            In-situ         Total
                                      Synthetic Crude Oil          Bitumen    Proved and
(millions of barrels)          Proved     Probable       Total    Probable      Probable
<S>                            <C>        <C>            <C>      <C>         <C>
December 31, 1997                 338          463         801          --           801
- -------------------------------------------------------------------------------------------
December 31, 1998                 302          464         766          --           766
   Revisions                      (10)         (13)        (23)         --           (23)
   Additions                      222        1 577       1 799          --         1 799
   Production                     (38)          --         (38)         --           (38)
- -------------------------------------------------------------------------------------------
December 31, 1999                 476        2 028       2 504          --         2 504
   Revisions                      (13)           6          (7)         --            (7)
   Production                     (41)          --         (41)         --           (41)
- -------------------------------------------------------------------------------------------
December 31, 2000                 422        2 034       2 456          --         2 456
   Revisions                       (1)          (5)         (6)         --            (6)
   Additions                       --           --          --       2 029         2 029
   Production                     (45)          --         (45)         --           (45)
- -------------------------------------------------------------------------------------------
DECEMBER 31, 2001                 376        2 029       2 405       2 029         4 434
- -------------------------------------------------------------------------------------------
</TABLE>

Gross proved reserves do not reflect deductions in respect of Crown and
applicable sublease royalties. Under the Crown Royalty Agreement, the Crown
royalty rate is dependent on deemed net revenues; therefore, calculations of the
net reserves would vary depending upon assumed production rates, prices and
operating and capital costs.

*  Reserve estimates are based upon a detailed geological assessment, including
   drilling and laboratory analysis. Estimates also reflect the integrated
   nature of the operation and therefore reflect demonstrated productive
   capacity, upgrading yield, plans for increased output, operating life and
   regulatory constraints.

72    SUNCOR ENERGY INC.

<PAGE>

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (CONTINUED)
(unaudited)

<TABLE>
<CAPTION>
                                                          2001       2000       1999       1998       1997
<S>                                                      <C>        <C>        <C>        <C>        <C>
NATURAL GAS
PRODUCTION
Conventional
Natural gas (millions of cubic feet per day)
   - gross                                                 177        200        226        247        240
   - net                                                   124        142        170        195        199
Natural gas liquids (thousands of barrels per day)
   - gross                                                 2.4        3.0        4.2        4.9        5.0
   - net                                                   1.7        2.1        3.0        3.7        3.5
Crude oil (thousands of barrels per day)
   - gross                                                 1.5        4.2        9.2       11.4       10.7
   - net                                                   1.1        3.3        7.5        9.4        8.6
Total (thousands of boe* per day)
   - gross                                                33.4       40.5       51.1       57.5       55.7
   - net                                                  23.5       29.1       38.8       45.6       45.3

AVERAGE SALES PRICE
Natural gas (dollars per thousand cubic feet)             6.09       4.72       2.44       1.95       1.93
Natural gas (dollars per thousand cubic feet)**           6.12       4.73       2.48       1.95       1.94
Natural gas liquids (dollars per barrel)                 34.38      36.66      19.32      15.13      22.45
Crude oil
   - conventional (dollars per barrel)                   33.92      29.50      20.94      20.14      22.75
   - conventional (dollars per barrel)**                 38.14      39.80      24.01      17.37      24.80

UNDEVELOPED LANDHOLDINGS***
Oil and gas (millions of acres)
   - western provinces
      - gross                                              0.6        1.4        1.5        1.7        1.7
      - net                                                0.5        1.1        1.2        1.3        1.3
   - international
      - gross                                              1.7        1.3         --         --         --
      - net                                                1.3        1.1         --         --         --

NET WELLS DRILLED****
Conventional
   Exploratory   - oil                                      --         --          1          2          7
                 - gas                                       4          1          5         10         10
                 - dry                                      16         15         13         18         25
   Development   - oil                                      --          2          2         15         26
                 - gas                                      16         14          4         16         10
                 - dry                                       2          3          1          8          4
- ----------------------------------------------------------------------------------------------------------
                                                            38         35         26         69         82
- ----------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------
</TABLE>

*    Barrel of oil equivalent (boe) converts gas to oil on the approximate
     long-term economic equivalent basis that 6,000 cubic feet equals one
     barrel of oil.

**   Excludes the impact of hedging activities.

***  Metric conversion: Landholdings - 1 hectare = approximately 2.5 acres.

**** Excludes interests in 14 net exploratory wells and seven net development
     wells in progress at the end of 2001.

OIL AND GAS DATA

The following supplemental oil and gas disclosure is provided in accordance with
the provisions of the United States Statement of Financial Accounting Standards
(SFAS) No. 69. This statement requires disclosure about conventional oil and gas
activities only, and therefore the company's oil sands activities are excluded.
Additional information required by SFAS No. 69 is included in the company's Form
40-F report, which is filed in the Electronic Data Gathering, Analysis and
Retrieval (EDGAR) system of the United States Securities and Exchange Commission
(SEC). This information can be accessed on the internet at www.freeedgar.com.

                                                        2001 ANNUAL REPORT    73

<PAGE>

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (CONTINUED)
(unaudited)

<TABLE>
<CAPTION>
RESERVES                                                   Gross                                         Net
                                              Crude Oil and            Natural              Crude Oil and            Natural
                                        Natural Gas Liquids                Gas        Natural Gas Liquids                Gas
                                               (millions of       (billions of               (millions of       (billions of
                                                    barrels)        cubic feet)                   barrels)        cubic feet)
<S>                                     <C>                        <C>                 <C>                       <C>
PROVED
December 31, 1997                                        70              1 088                         56                850
- -----------------------------------------------------------------------------------------------------------------------------
December 31, 1998                                        69              1 197                         56                915
   Revisions of previous estimates                       (2)              (103)                        (2)               (80)
   Purchases of minerals in place                        --                  1                         --                  1
   Extensions and discoveries                            --                 53                         --                 41
   Production                                            (5)               (82)                        (4)               (68)
   Sales of minerals in place                           (11)               (53)                        (9)               (45)
- -----------------------------------------------------------------------------------------------------------------------------
December 31, 1999                                        51              1 013                         41                764
   Revisions of previous estimates                       (3)               (52)                        (6)               (81)
   Purchases of minerals in place                        --                  9                         --                  7
   Extensions and discoveries                             1                 39                          1                 28
   Production                                            (3)               (73)                        (2)               (52)
   Sales of minerals in place                           (30)              (139)                       (23)               (99)
- -----------------------------------------------------------------------------------------------------------------------------
December 31, 2000                                        16                797                         11                567
   Revisions of previous estimates                       (1)                (3)                        --                  4
   Extensions and discoveries                            --                 27                         --                 20
   Production                                            (1)               (65)                        (1)               (45)
   Sales of minerals in place                            --                 (1)                        --                 (1)
- -----------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2001                                        14                755                         10                545
- -----------------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED
   December 31, 1997                                     55                727                         44                568
   December 31, 1998                                     53                730                         43                557
   December 31, 1999                                     38                627                         30                471
   December 31, 2000                                     13                573                         10                414
   DECEMBER 31, 2001                                     11                573                          8                416
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>

Proved reserves are considered recoverable under current technology and
existing economic conditions, from reservoirs that are evaluated on known
drilling, geological, geophysical and engineering data.

Proved developed reserves are on production, or reserves that could be recovered
from existing wells or facilities, if the company placed them on production.

Gross reserves are before deducting royalties. Net reserves are after deducting
royalties. Royalties can vary depending upon factors such as prices, production
volumes, timing of initial production and changes in legislation.

All reserves are located in Canada. There has been no major discovery or other
favourable or adverse event which caused a significant change in estimated
proved reserves since December 31, 2001. The company has no long-term supply
agreements or contracts with governments or authorities in which it acts as
producer nor does it have any interest in oil and gas operations accounted for
by the equity method.


<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS FROM ESTIMATED PRODUCTION OF
PROVED OIL AND GAS RESERVES AFTER INCOME TAXES

($ millions)                       2001         2000       1999
<S>                                <C>        <C>          <C>
At December 31                      440        1 933        749
</TABLE>

74    SUNCOR ENERGY INC.

<PAGE>

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (CONTINUED)
(unaudited)

<TABLE>
<CAPTION>
                                                                 2001        2000        1999        1998        1997
<S>                                                             <C>         <C>         <C>         <C>         <C>
SUNOCO
REFINED PRODUCT SALES (thousands of cubic metres per day)
Transportation fuels
Gasoline - retail*                                                4.3         4.2         4.1         4.1         3.8
         - other                                                  4.4         4.0         3.7         3.5         3.3
Jet fuel                                                          0.7         1.1         1.1         1.0         1.2
Diesel                                                            3.1         3.1         2.7         2.5         2.6
- ---------------------------------------------------------------------------------------------------------------------
                                                                 12.5        12.4        11.6        11.1        10.9
Petrochemicals                                                    0.5         0.6         0.7         0.7         0.7
Heating oils                                                      0.4         0.4         0.4         0.6         1.0
Heavy fuel oils                                                   0.8         0.6         0.5         0.7         0.7
Other                                                             0.6         0.6         0.6         0.7         0.9
- ---------------------------------------------------------------------------------------------------------------------
                                                                 14.8        14.6        13.8        13.8        14.2
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
NATURAL GAS SALES (millions of cubic feet per day)                 95          83          89          88          14

MARGINS (cents per litre)
Refining                                                          5.7         5.9         4.0         4.1         4.6
Retail                                                            6.6         6.6         7.4         7.0         6.8

CRUDE OIL SUPPLY AND REFINING
Processed at Suncor Energy refinery
   (thousands of cubic metres per day)                           10.2        10.9        10.6        11.0        10.8
Utilization of refining capacity (%)                               92          98          95          99          97

RETAIL OUTLETS** (number at year-end)                             400         402         415         423         441

* Excludes sales through joint venture interests.

**Sunoco-branded service stations, other private brands
  managed by Sunoco and Sunoco's interest in service
  stations managed through joint ventures. Outlets are
  located mainly in Ontario.
- ---------------------------------------------------------------------------------------------------------------------

TOTAL SUNCOR EMPLOYEES (number at year-end)                     3 307       3 043       2 796       2 659       2 439
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>

                                                        2001 ANNUAL REPORT    75

<PAGE>

SHARE TRADING INFORMATION
(unaudited)
(Stock trading symbol SU)

The following share trading information reflects a two-for-one split of the
company's common shares during 2000.

<TABLE>
<CAPTION>
                                                For the Quarter Ended                       For the Quarter Ended
                                       Mar 31    June 30    Sept 30     Dec 31       Mar 31    June 30    Sept 30     Dec 31
                                         2001       2001       2001       2001         2000       2000       2000       2000
<S>                                   <C>        <C>        <C>        <C>          <C>        <C>        <C>        <C>
SHARE OWNERSHIP
Average number outstanding,
   weighted monthly
   (thousands) (1)                    222 115    222 463    222 631    222 910      221 064    221 265    221 562    221 773
SHARE PRICE (dollars) (2)
Toronto Stock Exchange
   High                                 44.40      44.25      48.20      53.70        34.95      36.90      39.80      38.80
   Low                                  31.70      37.05      38.05      41.50        27.25      31.20      30.50      29.40
   Close                                40.55      38.60      44.00      52.40        31.45      34.20      33.20      38.30
New York Stock Exchange - US$
   High                                 28.60      30.00      30.25      33.60        22.00      24.95      26.75      26.40
   Low                                  21.00      24.35      25.00      26.10        18.50      20.80      20.50      19.40
   Close                                25.90      25.70      27.90      32.90        21.25      23.25      22.15      25.70
SHARES TRADED (thousands)
Toronto Stock Exchange                 45 160     50 115     38 514     50 206       42 976     32 903     37 181     43 177
New York Stock Exchange                 3 539      6 379      6 669      6 943        3 014      3 268      2 371      2 851
PER COMMON SHARE
   INFORMATION (dollars)
Net earnings attributable to
   common shareholders                   0.53       0.71       0.30       0.09         0.45       0.47       0.19       0.47
Cash dividends                          0.085      0.085      0.085      0.085        0.085      0.085      0.085      0.085
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) The company had approximately 1,225 holders of record of common shares as at
    January 31, 2002.

(2) The company's common shares are traded on the Toronto and New York stock
    exchanges.

INFORMATION FOR SECURITY HOLDERS OUTSIDE CANADA

Cash dividends paid to shareholders resident in countries with which Canada has
an income tax convention are usually subject to Canadian non-resident
withholding tax of 15%.

The withholding tax rate is reduced to 5% on dividends paid to a corporation if
it is a resident of the United States that owns at least 10% of the voting
shares of the company.

76    SUNCOR ENERGY INC.

<PAGE>

INVESTOR INFORMATION

STOCK TRADING SYMBOLS AND EXCHANGE LISTING

Common shares (SU) are listed on the Toronto and New York stock exchanges.
Suncor's 9.05% preferred securities (SU.PR.A-T) are listed on the Toronto Stock
Exchange. Suncor's 9.125% preferred securities (SU.PR.A-N) are listed on the New
York Stock Exchange.

DIVIDENDS

Suncor's Board of Directors reviews its dividend policy from time to time. In
2001, an aggregate dividend of $0.34 per share was paid.

DIVIDEND REINVESTMENT AND COMMON SHARE PURCHASE PLAN

Suncor's Dividend Reinvestment and Common Share Purchase plan provides an
efficient and cost-effective way for shareholders to increase their
investment in the company. The plan enables resident Canadian and U.S.
shareholders to invest cash dividends in common shares or acquire additional
shares through optional cash payments without payment of brokerage
commissions, service charges or other costs associated with administration of
the plan. To obtain additional information, please call Computershare Trust
Company of Canada at 1-888-267-6555.

STOCK TRANSFER AGENT AND REGISTRAR

In Canada, Suncor's agent is Computershare Trust Company of Canada with
locations in Calgary, Edmonton, Toronto, Montreal and Vancouver. In the United
States, Computershare Trust Company, Inc. is located in Denver, Colorado.

ACCOUNT MANAGEMENT

Sometimes shareholders receive more than one copy of Suncor's Annual Report
because their shares are registered under different names or addresses. If you
receive but do not require more than one mailing, call Computershare Trust
Company of Canada at 1-888-267-6555 to make arrangements to combine your
accounts.

ANNUAL MEETING

Suncor's annual and special meeting of shareholders will be held at 10 a.m. MST
on April 26, 2002, at the Keyano College Theatre in Fort McMurray, Alberta.
Presentations from the meeting will be web cast at www.suncor.com.

CORPORATE OFFICE

Box 38, 112 - 4th Avenue SW
Calgary, Alberta, T2P 2V5
tel: (403) 269-8100
toll free: 1-866-SUNCOR-1
fax: (403) 269-6217
info@suncor.com

ANALYST AND INVESTOR INQUIRIES

John Rogers
Vice President, Investor Relations
tel: (403) 269-8670
fax: (403) 269-6217
info@suncor.com

ADDITIONAL INFORMATION

In addition to annual and quarterly reports, Suncor publishes a bi-annual Report
on Sustainability. To order copies of Suncor's print materials call
1-800-558-9071. More information about Suncor and print materials that can be
downloaded are available from www.suncor.com.



LA VERSION FRANCAISE DU RAPPORT ANNUEL DE SUNCOR ET DE SON RAPPORT DE
DURABILITE PEUT ETRE TELECHARGEE A L'ADRESSE SUIVANTE : www.suncor.com

                                                        2001 ANNUAL REPORT    77

<PAGE>

CORPORATE DIRECTORS AND OFFICERS

OFFICERS

J. KENNETH ALLEY
Vice President, Finance

M. (MIKE) ASHAR
Executive Vice President, Oil Sands

DAVID W. BYLER
Executive Vice President, Natural Gas and Renewable Energy

RICHARD L. GEORGE
President and Chief Executive Officer

TERRENCE J. HOPWOOD
Senior Vice President and General Counsel

SUE LEE
Senior Vice President, Human Resources and Communications

KEVIN D. NABHOLZ
Senior Vice President, Major Projects

MICHAEL W. O'BRIEN
Executive Vice President, Corporate Development and Chief Financial Officer

JANICE B. ODEGAARD
Vice President, Associate General Counsel and Corporate Secretary

THOMAS L. RYLEY
Executive Vice President, Energy Marketing and Refining

JR SHAW
Chairman of the Board


DIRECTORS

MEL E. BENSON 1, 4
Calgary, Alberta
Management Consultant
Director since 2000

BRIAN A. CANFIELD 3, 4
Point Roberts, Washington
Chairman, TELUS Corporation
Director since 1995
Chair, Human Resources
and Compensation Committee

BRYAN P. DAVIES 1, 4
Toronto, Ontario
Senior Vice President, Regulatory Affairs
Royal Bank of Canada
Director since 2000

JOHN T. FERGUSON 1, 2
Edmonton, Alberta
Chairman, Princeton Development Ltd.
Chairman, TransAlta Corporation
Director since 1995

RICHARD L. GEORGE 2
Calgary, Alberta
President and Chief Executive Officer
Suncor Energy Inc.
Director since 1991

POUL HANSEN 1, 4, 5
Vancouver, British Columbia
Chairman and General Manager
Sperling Hansen Associates Inc.
Director since 1996

JOHN R. HUFF 2, 3
Houston, Texas
Chairman and Chief Executive Officer
Oceaneering International, Inc.
Director since 1998

ROBERT W. KORTHALS 1, 2
Toronto, Ontario
Director since 1996
Chair, Audit Committee

M. ANN McCAIG 3, 4
Calgary, Alberta
President, VPI Investments Ltd.
Director since 1995
Chair, Environment, Health and Safety Committee

JR SHAW 2, 3
Calgary, Alberta
Executive Chair, Shaw Communications Inc.
Chairman of the Board, Suncor Energy Inc.
Director since 1998
Chair, Board Policy, Strategy Review
and Governance Committee

W. ROBERT WYMAN 2, 3, 5
Vancouver, British Columbia
Director since 1987

1   Audit Committee

2   Board Policy, Strategy Review and Governance Committee

3   Human Resources and Compensation Committee

4   Environment, Health and Safety Committee

5   Retiring in April 2002

78    SUNCOR ENERGY INC.

</TEXT>
</DOCUMENT>
<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>
<DOCUMENT>
<TYPE>EX-4
<SEQUENCE>6
<FILENAME>a2075015zex-4.txt
<DESCRIPTION>EXHIBIT 4
<TEXT>
<PAGE>

QUARTERLY SUMMARY
 (unaudited)

<TABLE>
<CAPTION>
FINANCIAL DATA                                         TOTAL                               Total                             Total
                              FOR THE QUARTER ENDED     YEAR     For the Quarter Ended      Year    For the Quarter Ended     Year
                              MAR   JUNE   SEPT   DEC           Mar   June   Sept    Dec           Mar   June   Sept   Dec
($ millions except             31     30     30    31            31     30     30     31            31     30     30     31
per share amounts)           2001   2001   2001  2001   2001   2000   2000   2000   2000    2000  1999   1999   1999   1999   1999
<S>                        <C>    <C>    <C>    <C>     <C>   <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>     <C>
REVENUES                    1 001  1 098  1 013   883   3 995   779    820    862    927   3 388   469    564    639    715  2 387
- -----------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)
Oil Sands                     69    108     69     37    283     90     81     76     68    315     17     34     43     73    167
Natural Gas                   53     39     13     12    117      8     16     43     31     98      3     13     20      5     41
Sunoco                        23     45     12     --     80     19     20     19     23     81      5      3     12      7     27
Corporate and eliminations   (20)   (28)   (21)   (23)   (92)   (12)    (6)   (88)   (11)  (117)   (14)   (17)    (5)   (13)   (49)
- -----------------------------------------------------------------------------------------------------------------------------------
                             125    164     73     26    388    105    111     50    111    377     11     33     70     72    186
===================================================================================================================================
PER COMMON SHARE
 - net earnings
   attributable to
   common shareholders
 - basic                    0.53   0.71   0.30   0.09   1.63   0.45   0.47   0.19   0.47   1.58   0.04   0.12   0.29   0.29   0.74
 - diluted                  0.52   0.70   0.30   0.09   1.61   0.44   0.46   0.20   0.47   1.57   0.04   0.12   0.29   0.28   0.73
- -----------------------------------------------------------------------------------------------------------------------------------
 - cash dividends          0.085  0.085  0.085  0.085   0.34  0.085  0.085  0.085   0.085 00.34  0.085  0.085  0.085  0.085   0.34
===================================================================================================================================
CASH FLOW PROVIDED FROM
 (USED IN) OPERATIONS
Oil Sands                    140    117    139     90    486    199    181    156    119    655     53     90    104    158    405
Natural Gas                  127     76     42     35    280     48     42     64     84    238     42     43     39     48    172
Sunoco                        50     67     30     18    165     46     38     49     41    174     23     17     37     26    103
Corporate and eliminations   (42)   (14)   (34)   (10)  (100)   (24)   (17)   (40)   (28)  (109)   (25)   (21)   (33)   (10)   (89)
- -----------------------------------------------------------------------------------------------------------------------------------
                             275    246    177    133    831    269    244    229    216    958     93    129    147    222    591
===================================================================================================================================
</TABLE>

<TABLE>
<CAPTION>
OPERATING DATA                                           TOTAL                              Total                              Total
                               FOR THE QUARTER ENDED      YEAR     For the Quarter Ended     Year     For the Quarter Ended     Year
                               MAR   JUNE   SEPT    DEC           Mar   June   Sept    Dec           Mar   June   Sept    Dec
($ millions except              31     30     30     31            31     30     30     31            31     30     30     31
per share amounts)            2001   2001   2001   2001   2001   2000   2000   2000   2000   2000   1999   1999   1999   1999   1999
<S>                          <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>

OIL SANDS
PRODUCTION (a)               113.4  109.7  116.5  153.0  123.2  114.8  116.7  114.2  110.0  113.9   95.5  112.0  101.5  113.2  105.6
SALES (a)
- - light sweet crude oil       53.0   55.0   54.2   62.4   56.2   67.7   64.3   61.4   64.0   64.3   54.6   41.3   52.1   62.8   52.7
- - diesel                      13.5   15.2   15.0   15.3   14.8    8.7    8.6    8.9   11.0    9.3    7.9    6.8    8.4    9.5    8.2
- - light sour crude oil        31.4   31.5   40.6   64.3   42.0   39.1   41.7   35.6   27.5   35.8   27.3   47.9   40.6   35.1   37.5
- - bitumen                      8.6   13.0    8.0    4.3    8.5    2.4    3.5    7.0   11.0    6.2    1.5    6.9    6.9    --     3.8
- ------------------------------------------------------------------------------------------------------------------------------------
                             106.5  114.7  117.8  146.3  121.5  117.9  118.1  112.9  113.5  115.6   91.3  102.9  108.0  107.4  102.2
- ------------------------------------------------------------------------------------------------------------------------------------
AVERAGE SALES PRICE (b)
- - light sweet crude oil      36.09  36.05  35.20  30.22  34.17  34.35  33.54  36.21  37.22  35.31  20.55  24.47  27.23  30.81  26.06
- - other (diesel, light
  sour crude oil and         25.66  27.12  28.21  20.12  24.86  28.46  28.22  27.84  23.71  27.09  19.18  19.60  21.45  25.91  21.48
  bitumen)
- - total                      30.84  31.40  31.43  24.43  29.17  31.84  31.12  32.39  31.33  31.67  20.00  21.57  24.24  28.77  23.84
- - total*                     38.17  38.35  37.37  25.65  34.21  39.19  39.40  43.41  43.27  41.29  18.52  22.29  27.56  33.72  25.89
Cash operating costs (1)(c)  15.40  17.00  18.25  17.45  17.00  11.10  12.20  14.50  16.40  13.55  12.55  10.90  12.35  11.15  11.70
Total operating costs (2)(c) 18.60  19.65  20.95  19.40  19.60  15.50  16.60  18.55  19.50  17.25  15.60  14.30  15.30  15.10  15.05
====================================================================================================================================
</TABLE>



<PAGE>

<TABLE>
<CAPTION>
OPERATING DATA (CONTINUED)                               TOTAL                              Total                              Total
                                FOR THE QUARTER ENDED     YEAR     For the Quarter Ended     Year      For the Quarter Ended    Year
                               MAR   JUNE   SEPT    DEC          Mar    June   Sept    Dec           Mar   June   Sept    Dec
($ millions except              31     30     30     31           31      30     30     31            31     30     30     31
per share amounts)            2001   2001   2001   2001   2001  2000    2000   2000   2000   2000   1999   1999   1999   1999   1999
<S>                          <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
NATURAL GAS
GROSS PRODUCTION**
Conventional
 - natural gas (d)             177    177    176    180    177    222    195    200    183    200    229    225    231    219    226
 - natural gas liquids (a)     2.3    2.3    2.4    2.4    2.4    3.5    3.1    2.8    2.5    3.0    4.7    4.1    4.1    4.0    4.2
 - crude oil (a)***            1.7    1.5    1.5    1.3    1.5    8.1    3.5    3.6    1.6    4.2   10.8    9.7    8.4    7.9    9.2
 - total (e)                  33.5   33.3   33.2   33.7   33.4   48.6   39.1   39.7   34.6   40.5   53.7   51.3   51.0   48.4   51.1
AVERAGE SALES PRICE
 - natural gas (f)           10.73   6.78   3.90   3.10   6.09   2.96   3.70   4.63   8.02   4.72   2.18   2.15   2.48   2.96   2.44
 - natural gas (f)*          10.81   6.82   3.90   3.09   6.12   2.97   3.70   4.62   8.05   4.73   2.10   2.17   2.58   3.11   2.48
 - natural gas liquids (b)   45.07  39.62  30.26  23.47  34.38  33.16  32.80  39.56  43.00  36.66  11.88  16.70  22.81  27.12  19.32
 - crude oil -
   conventional (b)          37.35  36.75  33.17  27.17  33.92  26.30  30.04  33.09  36.01  29.50  18.48  20.48  20.55  25.21  20.94
 - crude oil -
   conventional (b)*         42.12  42.30  37.86  28.60  38.14  38.23  38.65  42.31  44.35  39.80  16.28  21.89  28.01  32.72  24.01
SUNOCO
Refined product
 sales (g)****                14.9   15.3   15.1   14.0   14.8   14.3   15.1   14.0   15.2   14.6   13.1   14.1   13.9   14.2   13.8
Natural gas sales (d)           92    102     95     92     95     84     78     74     95     83     93     86     87     90     89
Margins - refining (3) (h)     6.2    8.1    4.3    3.7    5.7    5.4    6.3    6.1    5.8    5.9    3.4    3.3    4.8    4.3    4.0
 - retail (4) (h)              6.1    7.6    5.9    6.9    6.6    6.8    6.4    6.4    7.0    6.6    7.9    7.6    6.9    7.2    7.4
Utilization of refining
 capacity (%)                   88     98     99     83     92    102     99     96     95     98     97     93    100     92     95
====================================================================================================================================
</TABLE>

*    Excludes the impact of hedging activities.

**   Currently all Natural Gas production is located in the Western Canada
     Sedimentary Basin.

***  Before deducting 2001 Alberta Crown royalty of 0.2 thousand barrels per day
     (2000 - 0.5 thousand barrels per day; 1999 - 0.9 thousand barrels per day).

**** Excludes sales through joint venture interests.

Definitions
(1) Cash operating costs  - operating, selling and general expenses, taxes other
                            than income taxes, and overburden cash expenditures
                            for the period.
(2) Total operating costs - cash and non-cash operating costs (total Oil Sands
                            expenses less purchases of crude oil and products
                            and royalties in Schedules of Segmented Data on
                            page 52 and 53).
(3) Refining margin       - average wholesale unit price from all products minus
                            average unit cost of crude oil.
(4) Retail margin         - average street price of Sunoco-branded retail
                            gasoline minus refining gasoline price.

<TABLE>
<S>                               <C>                                 <C>
(a) thousands of barrels per day  (d) millions of cubic feet per day  (g) thousands of cubic metres per day
(b) dollars per barrel            (e) BOE (6:1 basis) per day         (h) cents per litre
(c) dollars per barrel sold       (f) dollars per thousand cubic feet
    rounded to the nearest $0.05
</TABLE>

<TABLE>
<S>                                 <C>
Metric conversion
Crude oil, refined products, etc.   1m(3) (cubic metre) = approx. 6.29 barrels
Natural gas                         1m(3) (cubic metre) = approx. 35.49 cubic feet
</TABLE>

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-5
<SEQUENCE>7
<FILENAME>a2075015zex-5.txt
<DESCRIPTION>EXHIBIT 5
<TEXT>
<PAGE>

[PRICEWATERHOUSECOOPERS LOGO]

                                                     PRICEWATERHOUSECOOPERS LLP
                                                     CHARTERED ACCOUNTANTS
                                                     425 1st Street SW
                                                     Suite 1200
                                                     Calgary Alberta
                                                     Canada T2P 3V7
                                                     Telephone +1 (403) 509 7500
                                                     Facsimile +1 (403) 781 1825


REPORT OF INDEPENDENT ACCOUNTANTS ON THE RECONCILIATION TO US GAAP

TO THE BOARD OF DIRECTORS
OF SUNCOR ENERGY INC.

Our audits of the consolidated financial statements referred to in our report
dated January 16, 2002 appearing in the Annual Report to Shareholders of Suncor
Energy Inc., which report and financial statements are incorporated by reference
into this Form 40-F also included audits of the Reconciliation to US GAAP
presented on pages 56 to 64 of this form 40-F. In our opinion, this
Reconciliation to US GAAP is presented fairly, in all material respects, when
read in conjunction with the related consolidated financial statements.


CHARTERED ACCOUNTANTS
CALGARY, ALBERTA
JANUARY 16, 2002





CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS

We hereby consent to the incorporation by reference in this Annual Report on
Form 40-F of Suncor Energy Inc. for the year ended December 31, 2001 of our
reports dated January 16, 2002 relating to the consolidated financial statements
for the three years ended December 31, 2001 and relating to the Reconciliation
to US GAAP for the three years ended December 31, 2001 (as set out on page 56 to
64 of the Form 40-F).

We also hereby consent to the incorporation by reference in the Registration
Statement on Form F-10 (file No. 333-14242) of Suncor Energy Inc. of our reports
dated January 16, 2002 relating to the consolidated financial statements for the
three years ended December 31, 2001 and relating to the 2001 Reconciliation to
US GAAP for the three years ended December 31, 2001 (as set out on pages 56 to
64 of the Form 40-F) which are incorporated by reference and appears,
respectively, in this Form 40-F.


CHARTERED ACCOUNTANTS
CALGARY, ALBERTA
MARCH 28, 2002

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-6
<SEQUENCE>8
<FILENAME>a2075015zex-6.txt
<DESCRIPTION>EXHIBIT 6
<TEXT>
<PAGE>

[LOGO]  GILBERT LAUSTSEN JUNG
        ASSOCIATES LTD.   Petroleum Consultants
        4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada T2P 4H2
                                            (403) 266-9500    Fax (403) 262-1855


                                LETTER OF CONSENT



TO: Suncor Energy Inc.
    The Securities and Exchange Commission
    The Securities Regulatory Authorities of each Province of Canada


                             RE: SUNCOR ENERGY INC.

We refer to the following reports prepared by Gilbert Laustsen Jung Associates
Ltd.:

- -    the letter reports dated January 16, 2002, as to the synthetic crude oil
     reserves effective December 31, 2001 associated with the Suncor Energy Inc.
     oil sands mining operations located near Fort McMurray, Alberta;

- -    the Reserve Determination and Evaluation of the Canadian Oil and Gas
     Properties of Suncor Energy Inc. Natural Gas effective December 31, 2001,
     dated January 28, 2002;

- -    the Suncor Energy Inc. Natural Gas Constant Price Analysis effective
     December 31, 2001, dated January 29, 2002;

- -    the letter report dated January 22, 2002, as to the Firebag SAGD Project
     Approval Area Probable Nonproducing Reserves and Economic Analysis,
     effective December 31, 2001.

We hereby consent to the use of our name, reference to and excerpts from the
said reports by Suncor Energy Inc. in its Annual Information Form for the 2001
fiscal year (AIF), and to the incorporation by reference of the AIF in the
annual report of Suncor Energy Inc. on Form 40-F and the registration statement
on Form F-10 No. 333-14242.

We have read the AIF and have no reason to believe that there are any
misrepresentations in the information contained in it that is derived from our
Reports or that are within our knowledge as a result of the services which we
performed in connection with the preparation of the Reports.

                                         Yours very truly,

                                         GILBERT LAUSTSEN JUNG
                                         ASSOCIATES LTD.

                                         ORIGINALLY SIGNED BY

                                         Wayne W. Chow, P. Eng.
                                         Vice-President

Calgary, Alberta
Date: March 12, 2002



</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
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