-----BEGIN PRIVACY-ENHANCED MESSAGE-----
Proc-Type: 2001,MIC-CLEAR
Originator-Name: webmaster@www.sec.gov
Originator-Key-Asymmetric:
 MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen
 TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB
MIC-Info: RSA-MD5,RSA,
 VRgzGGEZV3tZ0qEmvQKseXmFKvOGI9qRj9wJ8kslXPq6FvEwqhkxdhqVbNbELaZu
 Y3HFTwVcZsMxmQnroBgCIw==

<SEC-DOCUMENT>0000912057-01-506966.txt : 20010410
<SEC-HEADER>0000912057-01-506966.hdr.sgml : 20010410
ACCESSION NUMBER:		0000912057-01-506966
CONFORMED SUBMISSION TYPE:	6-K
PUBLIC DOCUMENT COUNT:		7
CONFORMED PERIOD OF REPORT:	20010319
FILED AS OF DATE:		20010404

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:		
		SEC FILE NUMBER:	001-12384
		FILM NUMBER:		1595523

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

	MAIL ADDRESS:	
		STREET 1:		112 FOURTH AVE SW BOX 38
		STREET 2:		CALGARY ALBERTA
		CITY:			CANADA T2P 2V5
</SEC-HEADER>
<DOCUMENT>
<TYPE>6-K
<SEQUENCE>1
<FILENAME>a2042188z6-k.txt
<DESCRIPTION>FORM 6-K (40F)
<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 2001                    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>

                                  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, 2000

EXHIBIT 3               Management's Discussion and Analysis for the fiscal year
                        ended December 31, 2000, dated February 28, 2001

EXHIBIT 4               Excerpt from page 78 of Suncor Energy Inc.'s 2000 Annual
                        Report to Shareholders

EXHIBIT 5               Consent of PricewaterhouseCoopers LLP

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

<PAGE>

                   SUNCOR ENERGY INC. ANNUAL INFORMATION FORM

                                FEBRUARY 28, 2001


<PAGE>

                             ANNUAL INFORMATION FORM

                                TABLE OF CONTENTS

<TABLE>
<S>                                                                                       <C>
GLOSSARY OF TERMS..........................................................................iii
CONVERSION TABLE...........................................................................vii
CURRENCY...................................................................................vii
FORWARD LOOKING STATEMENTS................................................................viii
CORPORATE STRUCTURE..........................................................................9
     Incorporation of the Issuer.............................................................9
     Subsidiaries of Suncor..................................................................9
GENERAL DEVELOPMENT OF THE BUSINESS..........................................................9
     Three-Year Highlights..................................................................10
NARRATIVE DESCRIPTION OF THE BUSINESS.......................................................13
   OIL SANDS................................................................................13
     Operations.............................................................................13
     Leasehold Interests and Royalties......................................................14
     Estimated Synthetic Crude Oil Reserves.................................................16
     Reserves Reconciliation................................................................17
     Revenues from Synthetic Crude Oil and Diesel...........................................17
     Capital Expenditures...................................................................18
     Environmental Compliance...............................................................18
   NATURAL GAS..............................................................................18
     Reserves and Reserves Reconciliation...................................................19
     Conventional Crude Oil.................................................................21
     Before Royalties at....................................................................22
     Natural Gas............................................................................24
     Land Holdings..........................................................................24
     Drilling...............................................................................25
     Wells..................................................................................26
     Sales and Sales Revenues...............................................................26
     Production Costs.......................................................................27
     Quarterly Volumes and Netback Analysis.................................................27
     Marketing, Pipeline and Other Operations...............................................28
     Capital and Exploration Expenditures...................................................28
     Environmental Compliance...............................................................29
   SUNOCO...................................................................................29
     Refining...............................................................................29
     Environmental Compliance...............................................................33
SUNCOR EMPLOYEES............................................................................33
RISK/SUCCESS FACTORS........................................................................34
SELECTED CONSOLIDATED FINANCIAL INFORMATION.................................................39
     Selected Consolidated Financial Information............................................39
     Dividend Policy and Record.............................................................39
     Future Commitments to Buy, Sell, Exchange or Transport Crude Oil And Natural Gas.......40
MANAGEMENT'S DISCUSSION AND ANALYSIS........................................................41
MARKET FOR THE SECURITIES OF THE ISSUER.....................................................41
DIRECTORS AND OFFICERS......................................................................41
ADDITIONAL INFORMATION......................................................................45
</TABLE>


                                                                              ii
<PAGE>

                                GLOSSARY OF TERMS

INDUSTRY TERMS

BITUMEN/HEAVY OIL

     A naturally occurring viscous tar-like mixture, mainly of hydrocarbons
heavier than pentane, that may contain sulphur compounds and that in its
naturally occurring viscous state is not recoverable at a commercial rate
through a well, without using enhanced recovery methods; and that when extracted
can be upgraded into crude oil and other petroleum products.

CAPACITY

     Maximum output that can be achieved from a facility in ideal operating
conditions.

COAL BED 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 coal bed
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 interest 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 which at atmospheric conditions of temperature and pressure
are in a gaseous phase.

NATURAL GAS LIQUIDS

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

NET PRODUCTION/RESERVES

     Suncor's 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 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

     With reference to conventional crude oil and natural gas, 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 that estimated in the proved category which 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

     With reference to conventional crude oil and natural gas, those reserves
estimated as recoverable 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.


                                                                              iv

<PAGE>

PROVED AND PROBABLE OIL SANDS RESERVES

     Annual estimates made by Suncor of recoverable synthetic crude oil
associated with Suncor's surface mineable oil sands leases. The estimates are
allocated between proven and probable categories based upon criteria agreed to
by management and reviewed by independent consultants. The proved reserves are
considered to be conservative estimates in which there are a high degree of
confidence. Probable reserves incorporate portions of the mine that have a lower
drilling density. There is least a 50% chance the proved plus probable reserve
estimates will be exceeded. The bitumen estimates are converted to synthetic
crude estimates on the basis of yields currently being obtained.

RESERVOIR

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

SOUR CRUDE OIL

     Crude oil produced by Oil Sands that requires only partial upgrading and
contains a higher sulphur content than sweet crude oil.

SWEET SYNTHETIC CRUDE OIL

     Crude oil produced by 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 on which 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 and other oil
products from oil sands.

UTILIZATION

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

WELLS

DEVELOPMENT WELL

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


                                                                               v
<PAGE>

DRILLED WELL

     A well which 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.

ACCOUNTING TERMS

BARREL OF OIL EQUIVALENT (BOE)

     Converts natural gas to crude oil on the approximate long-term economic
equivalent basis that 10,000 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, natural gas plants and gathering systems.

MMCF/E

     Converts crude oil to natural gas on the approximate long-term economic
equivalent basis that one barrel of crude oil equals 10,000 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).


                                                                              vi
<PAGE>

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 borrowings), less the
book value of significant capital projects in process 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.

                                CONVERSION TABLE

<TABLE>
<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.


                                                                             vii
<PAGE>

                           FORWARD LOOKING STATEMENTS

     This Annual Information Form contains certain forward-looking statements,
which are based on Suncor's current expectations, estimates, projections and
assumptions and were made by Suncor 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 expenditures, commodity prices, costs, schedules and production
volumes, operating or 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
of which are similar to other oil and gas companies and some of which 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 and timely
implementation of its growth projects including Project Millennium; 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 which 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, 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 Annual Information Form
and in Management's Discussion and Analysis for the year ended December 31, 2000
and dated February 28, 2001, 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 by contacting the Secretary at
403-269-8709.


                                                                            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. In September
1995, Suncor's articles were amended to change the location of its registered
office from Toronto, Ontario, to Calgary, Alberta. In April 1997, Suncor's
articles were amended to divide its issued and outstanding shares on a
two-for-one basis, and to change the Company's name to Suncor Energy Inc. In May
2000, Suncor's articles were again amended to divide its issued and outstanding
shares on a two-for-one basis.

     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. is an
Ontario corporation that is wholly-owned by Suncor and is incorporated under the
laws of Ontario. 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 has offices in Pennsylvania.

     Suncor Energy Marketing Inc., wholly-owned by Sunoco, is incorporated under
the laws of Alberta. Suncor Energy Marketing Inc. manages Company and third
party Alberta-based pipeline operations, and markets, mainly to customers in
Canada and the United States, certain crude oil and 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 other third party products.
Suncor Energy Marketing Inc. also has a petrochemicals marketing division that
principally manages its participation in a petrochemical products joint venture
partnership.

                       GENERAL DEVELOPMENT OF THE BUSINESS

OVERVIEW

     Suncor is a Canada-based integrated energy company. Suncor explores for,
acquires, 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
various custom blends and markets these products in Canada and the United
States. NATURAL GAS (formerly Exploration and Production), based in Calgary,
Alberta, explores for, acquires, develops, produces and markets natural gas
throughout North America. Since November 1, 1998, Suncor Energy Marketing Inc.
has marketed the crude oil, diesel products and other byproducts produced by
Suncor's Oil Sands and Natural Gas business units. Since January 1, 2000, it has
also managed the Company's, and certain third party, Alberta-based pipeline
operations. Sunoco, headquartered in Toronto, Ontario, refines crude oil,
markets a broad range of petroleum products, mostly in Ontario, and markets
petrochemical products in the United States and Europe. In 1997, Sunoco started
an energy marketing business and began marketing natural gas to residential and


                                                                               9
<PAGE>

commercial customers in Ontario. Suncor is currently commissioning an oil shale
demonstration project known as the Stuart Oil Shale Project, in Gladstone,
Queensland, Australia.

     In 2000, Suncor produced approximately 121,100 barrels per day of crude oil
and natural gas liquids (approximately 6% of Canada's crude oil production) and
200 million cubic feet per day of natural gas. In 1999, the most recent period
with published results, Suncor was the second largest crude oil and natural gas
liquids producer and in the top quartile of natural gas producers in Canada.

     In 2000, Suncor sold approximately 92,000 barrels (14,600 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 17% of
Ontario's total refined product sales in 2000.

THREE-YEAR HIGHLIGHTS

OIL SANDS

     In July 1997, Suncor announced plans to expand the production capacity of
its Oil Sands plant, near Ft. McMurray, Alberta, including plans for a project
("Project Millennium") designed to double Oil Sands' production capacity from
1997 levels. Project Millennium involves an expanded mine, additional mining
equipment, increased energy services support and twinning of the bitumen
extraction and upgrading processes. Detailed engineering studies that followed
the original announcement in 1997 resulted in a Project Millennium plan designed
to increase total production capacity at Oil Sands to 225,000 barrels per day by
2002. Project Millennium was approved in 1999 by both Suncor's Board of
Directors and the Alberta Energy & Utilities Board. In February 1999, Suncor
announced the integrated project team of Canada-based companies, including
Suncor, that would undertake the engineering, procurement, construction,
commissioning and start-up of Project Millennium. Project Millennium
construction began in April 1999.

     In the first quarter of 2000, Suncor announced Project Millennium costs
could be as high as $2.45 billion, up from the original estimate of $2 billion.
In October of 2000, a thorough analysis was completed on Suncor's Project
Millennium that resulted in a revised capital cost estimate of $2.8 billion. The
current capital cost estimate of $2.8 billion is attributed to rising labour,
fabrication and material costs, and a $150 million change in the project's
scope. The additional capital costs are expected to be financed by internally
generated cash flow and additional borrowing.

     At the end of 2000 all Project Millennium engineering was completed and in
aggregate the project was 70% complete.

     In March 1999, Suncor and TransAlta Energy Corporation ("TransAlta")
announced TransAlta's plans to build, own and operate a $315 million
co-generation facility at Suncor's Oil Sands site. This facility is expected to
meet a portion of Oil Sands' electricity and steam requirements and to supply
electricity to the Alberta power grid. The new TransAlta facility is being built
in phases and is expected to generate 360 megawatts of electricity when fully
operational in 2001. The first phase, consisting of two gas turbines producing
220 megawatts of electricity, became operational in 2000. Commissioning of other
co-generation equipment continued throughout 2000 and the entire complex is
expected to be fully commissioned in 2001. In October 1999, TransAlta also
assumed the role of operator of Suncor's existing energy services plant.

     In early 2000, Suncor announced a plan to further expand its oil sands
facilities beyond the Project Millennium expansion currently in process, with a
proposed investment of $750 million in the first stage of an in-situ project and
further expansion of the Oil Sands plant. Under current planning assumptions,
the commercial scale in-situ portion of the project (referred to as the "Firebag
In-situ Oil Sands Project") is targeted to add approximately 35,000 barrels of
bitumen per day in 2005. The Firebag In-situ Oil Sands Project is intended to be
integrated with Suncor's open pit mining operation. To process the additional
bitumen, Suncor plans to add a vacuum tower complex designed to increase the Oil
Sands plant upgrading capacity to a targeted 260,000 barrels per day in 2005.
Work to finalize cost estimates is


                                                                              10
<PAGE>

underway. These plans are subject to Board of Directors and provincial
regulatory approvals. Suncor submitted regulatory approval applications for the
Firebag In-situ Oil Sands Project in 2000, and expects a regulatory decision in
2001. Subject to these approvals, construction of the Firebag In-Situ Oil Sands
Project and the vacuum tower complex addition is scheduled to begin in late
2001, with start-up in late 2003 and commissioning in 2004 - 2005.

     The Company's long-term vision is to produce 140,000 barrels of bitumen per
day from the Firebag project by the end of this decade, and to increase total
production at its Oil Sands facilities, by a combination of oil sands mining and
in-situ development, to approximately 400,000 to 450,000 barrels of crude oil a
day in 2008. Any plans toward realizing this long-term vision would be subject
to Board of Directors and regulatory approvals.

NATURAL GAS

     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.

     The repositioning plans called for a reduction in annual expenses in the NG
business by $18 to $20 million by the end of 2001. During 2000, NG reduced
annualized costs by approximately $15 million, approximately 80% of its target.
Consolidation of the asset base, organizational restructuring and a reduction in
the NG workforce of about 70 positions contributed to the reduced operating
costs. The NG business has established a goal of achieving a sustainable 10%
return on capital employed by 2004 at natural gas prices in the range of $3.00
to $3.50 per thousand cubic feet (mid-cycle prices).

SUNOCO

     In 1997, Sunoco entered the natural gas marketing business in Ontario. In
1999, as part of its goal to broaden its energy offerings, Sunoco expanded the
number of dealer members in the Home Energy Dealer Network to 29 dealers. In
2000 it was decided to exit the heating, ventilation and air conditioning market
and shut down its Home Energy Dealer Network. This decision does not affect
Sunoco's interests in the natural gas marketing business. Costs associated with
the shut down were not significant.

     During 1998, TransAlta announced plans to build a co-generation facility in
Sarnia, Ontario. Sunoco continues to evaluate its participation in this project.
Any such participation would be subject to enabling rules and regulations
arising from the Ontario government's electricity deregulation process. These
include acceptable tariff structures currently under a rate hearing by the
Ontario Energy Board. Due to the length of the deregulation process, start-up of
the project is now estimated for mid-2002, as opposed to the 1998 estimate of
completion in 2001. If the project proceeds, it is expected to supply some of
Sarnia's power-consuming industries, including Sunoco's Sarnia refinery, with
lower-cost power and steam. Negotiations continue with TransAlta to purchase
steam and electricity from the project.

     In 2000, to reduce exposure to energy cost increases expected when the
electricity market deregulates, Sunoco's Sarnia refinery negotiated a fixed-rate
supply contract to lock-in costs on a portion of its electricity requirements
for three years. The contract commences on the date when electricity
deregulation begins and provides that, if this does not occur prior to a
specific outside date, the contract would terminate unless renegotiated. Under
this contract Sunoco is not prevented from reselling the purchased electricity
and as such Sunoco would have the ability to sell into the marketplace any
electricity surplus to its needs.


                                                                              11
<PAGE>

OTHER

     In the first quarter of 1998, Suncor arranged syndicated credit facilities
totaling $1.296 billion to be used for general corporate purposes. These
borrowings were arranged in anticipation of the Company's planned multi-billion
dollar capital expenditure program during the 1999 - 2001 period, primarily
relating to Project Millennium. The facilities are unsecured and rank equally
with other unsecured and unsubordinated indebtedness of Suncor. 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 expires in
2001.

     In June 1997, Sunoco Inc. and Australian joint venture participants,
Southern Pacific Petroleum NL (SPP) and Central Pacific Minerals NL (CPM)
announced the first stage of the Stuart Oil Shale Project in Gladstone,
Queensland, Australia where the Company and the two Australian co-owners are
currently testing the commercial viability of producing crude oil from oil
shale. The first phase is designed as a 4,500-barrel per day demonstration
plant. Suncor Energy (Management) Pty Ltd., a subsidiary of Sunoco, is the
operator of the demonstration plant. Construction is now complete and
commissioning of the first stage of the Stuart Oil Shale Project commenced in
1999.

     Operational issues have been experienced during commissioning of the Stuart
Oil Shale Project, 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 announced plans to spend up to $22 million to address
these issues. Suncor recorded an after-tax write-down of $80 million on the
project in 2000, reflecting increased costs and delayed oil production. All
future expenditures on the Stuart Oil Shale Project are being expensed until
operational issues and concerns about environmental and social impacts are
addressed. Suncor intends to resolve operating issues at the plant before making
any decisions regarding the project's next stage of development. To the end of
December 2000, Suncor's investment in the first stage of the project, excluding
$4 million invested by Suncor in partially paid SPP/CPM shares (See Note 2 to
Suncor's consolidated financial statements for information about these shares),
has been approximately $270 million, higher than the original estimate of $210
million due to the issues and delays experienced to date. A portion of the
financing for the project, $73 million at the end of 2000, has been funded
through project financing from SPP and CPM.

     The success of the Stuart Oil Shale Project is subject to uncertainty
because of the developmental nature of the project and the inherent risks
associated with the use of new technology. If the project does not proceed, the
remaining associated costs and obligations on the balance sheet would be
eliminated. The impact on future earnings, should this occur, is currently
estimated not to be significant. If the first stage of the project proves
successful, the next stages have the potential to increase production to 85,000
barrels per day within 10 years. Sunoco and SPP/CPM would ultimately have a
50/50 interest in the project.

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

     Suncor announced in 2000 plans to invest at least $100 million over the
next five years to pursue alternative and renewable energy opportunities.

     For further information on the status of the ongoing projects referred to
above, including Project Millennium, and other highlights of 2000, reference is
made to "Outlook" and other sections of Suncor's Management's Discussion and
Analysis for the year ended December 31, 2000 and dated February 28,


                                                                              12
<PAGE>

2001 ("MD&A"), which MD&A is incorporated by reference herein.

                      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 95% of Suncor's conventional and synthetic crude oil
production in 2000, 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; extraction which
involves extracting the bitumen from the oil sands; a heavy oil upgrading
process, where bitumen is converted into crude products; and an energy services
plant (operated by TransAlta), which provides the site with steam and electric
power.

     The first step of the open pit mining operation is the removal of
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 which stretches approximately three
miles. On the east bank, a slurry of partially processed ore from the Mine
Expansion 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.

     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. 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 Inc. ("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 annual tolls payable under the
agreement are subject to annual adjustments. The pipeline is operated by Suncor
Energy Marketing Inc. The pipeline is expected to meet Suncor's anticipated
crude oil shipping requirements for the foreseeable future.

     The Oil Sands operation meets most of its current energy needs from an
existing energy services plant which uses primarily petroleum coke, a by-product
of the coking process, as fuel. The operation also consumes natural gas. The
natural gas used includes volumes produced by Suncor, as well as natural gas
purchased from others. TransAlta commenced operation of this facility in October
1999. The Project Millennium expansion energy requirements are to be met by the
existing energy services plant, and Suncor's portion of the output from a new
TransAlta owned and operated onsite cogeneration facility.

     In 1998, Suncor entered into an agreement with Nova Pipeline Ventures
Limited Partnership, now known as TransCanada Pipeline Ventures Limited
Partnership ("TCPV"), to provide Suncor with firm capacity on a new natural gas
pipeline to be constructed by TCPV. This pipeline came into service in 1999.


                                                                              13
<PAGE>

     In 1998, Suncor's Mine Expansion on the east side of the Athabasca River
began operations. The project included a mine site facilities complex, a 250
tonne capacity bridge over the Athabasca River, and a new ore preparation
process. The new ore preparation process utilizes crushers, slurry preparation
equipment, and hydrotransport pumps to deliver an oil sand slurry across the
Athabasca River through hydro-transport pipelines to the existing extraction
plant.

     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 diluent recovery unit lasted a total of 16 days and resulted in
approximately 1.8 million barrels of lost production. These outages were
precipitated by a change in feedstock resulting from the operation of a new
vacuum tower. Parts of the 5C9 unit that failed were redesigned during the
second outage in September, with the objective of improving reliability and
helping to achieve targeted production rates. Suncor plans to shut down the same
unit for routine maintenance before mid-year, 2001, for approximately eight
days. There will be no production from the oil sands plant while this
maintenance work takes place. Suncor's 130,000 barrels per day average
production target for 2001 includes the estimated impact of this maintenance
work on production.

     Project Millennium will involve the duplication of some facilities, thereby
reducing the potential for a total loss of production.

     Severe climatic conditions at Oil Sands can cause reduced production and in
some situations result in higher costs. In December 2000, three weeks of
prolonged cold weather reduced production. 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. The next
complete shutdown is scheduled for 2002 when the original facilities (excluding
the assets associated with Project Millennium) will undergo scheduled
maintenance shutdown work. In addition to complete shutdowns, partial shutdowns
in the upgrader are undertaken periodically. 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.

LEASEHOLD INTERESTS AND ROYALTIES

     In 1997, regulatory approval was obtained to allow Suncor to mine
additional leases on its existing mine site (the "Mine Expansion"). Mining
activity on the Mine Expansion, located east of the Athabasca River and south
of the Steepbank River, commenced during the third quarter of 1998.


                                                                              14
<PAGE>

     Set out in the table below is a summary of Suncor's oil sands leasehold
interests as of December 31, 2000.

<TABLE>
<CAPTION>
                                                                              NUMBER OF
                                                                             GROSS ACRES             PERCENTAGE OF
                                                         REFERRED           (NET ACRES IF           SYNTHETIC CRUDE
      DESCRIPTION              LEGAL DESCRIPTION          TO AS              APPLICABLE)          OIL PROVED RESERVES
- ------------------------     ----------------------     ------------       ---------------        --------------------
<S>                          <C>                        <C>                <C>                    <C>
Mine Expansion:
Leases                            7280100T25                25                   17,664           Mine Expansion
                                  7279080T19                19                   18,760           Leases and Fee
                                  7597030T11                97                    2,483           Lots represent 95%
                                  7280060T23                                     36,900
                                  7498050014                                        240

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                    4,500           Original Mine
Leases                            7279120092                17                    1,600           Leases represent
                                                                                                  5.1%

Firebag(2)                        7285100T85                85                   39,500           (1)

Firebag(2)                        Various(3)              Various               266,440           (1)

Cheecham(2)                       7280100T27                27                   49,900           (1)
                                                                                (24,450)
</TABLE>

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 266,440 gross and
     net acres.


     The Government of Alberta is entitled to royalties under Leases 17, 19,
25, 86 and 97 and fee lots one, three and four at rates which the Government
establishes from time to time.

      Under the Alberta Suncor Crown Royalty Agreement, Crown royalties are
25% of revenues less allowable costs (including capital expenditures),
subject to a minimum payment of 5% of gross revenues. 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 10 years (related to Suncor's original
investment in the Oil Sands facility). In 2001, the minimum royalty rate will
change to 1% of gross revenues. Suncor currently expects to pay Crown
royalties at the minimum 1% rate until 2008, based on assumptions relating to
future crude oil prices, production levels, operating costs and capital
expenditures.


                                                                              15
<PAGE>

      Union Pacific Resources 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 "Union Pacific Royalty"). The Union Pacific 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, 2000, under the Union Pacific Royalty, no payment is required if synthetic
crude prices are below $19.70 per barrel. Payment of 1.5% of gross revenue is
required if the synthetic crude price ranges from $19.70 to $20.69 per barrel.
For every $1.00 per barrel increase in the price of synthetic crude in the range
of $20.70 to $25.69 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 $25.70 to $36.69 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. Mining is currently expected to be
completed on the Union Pacific lease in the 2001/2002 time period.

      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 is 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 that will be applicable to the Firebag and
Cheecham in-situ leases has not been determined at this time.

ESTIMATED SYNTHETIC CRUDE OIL RESERVES

     Suncor estimates that Leases 86 and 17 (the original leases), and the Mine
Expansion leases, on a combined basis, contain proved plus probable reserves of
synthetic crude oil totaling 2.5 billion barrels, with 422 million barrels
classified as proved. 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 reserve estimates are based upon a detailed geological assessment
including drilling density 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 reserves may be
identified when more work on the mine is completed. The current proved plus
probable reserve estimate is based on the mine plan approved by the Alberta
Energy and Utilities Board.

     Suncor engaged Gilbert Laustsen Jung Associates Ltd. ("GLJ"), independent
petroleum consultants, to audit Suncor's estimate of proved and probable
reserves of synthetic crude oil as of December 31, 2000. In their opinion dated
January 15, 2001, GLJ state that they believe that there is at least a 90%
confidence that the current proved, and 50% confidence that the current proved
plus probable, reserve estimates will be exceeded. Their opinion is qualified to
the extent that it assumes Suncor will comply with any amendments that may be
made to regulatory approvals. Planned future improvements in the extraction
(bitumen production) and upgrading processes have not been considered in their
report. On-site fuel consumption has been deducted. The independent GLJ audit
does not take into account the economic aspects of future reserves.


                                                                              16
<PAGE>

RESERVES RECONCILIATION

     The following table sets out a reconciliation of Suncor's proved and
probable reserves of synthetic crude oil from December 31, 1999 to December 31,
2000.

<TABLE>
<CAPTION>
                                          PROVED RESERVES            PROBABLE RESERVES                 TOTAL
                                          ---------------          ---------------------               -----
                                                                   (MILLIONS OF BARRELS)
<S>                                       <C>                      <C>                                 <C>
December 31, 1999..................             476                        2,028                       2,504
Revisions(1).......................             (13)                           6                          (7)
Additions..........................               0                            0                           0
Production.........................             (41)                           -                         (41)
                                                ---                        -----                       -----
December 31, 2000..................             422                        2,034                       2,456
</TABLE>

Note:

(1)  Substantially all of the proved reserve revisions relate to proved bitumen
     drilling activity and revisions to the pit design based upon both
     geotechnical and economic data related to the Mine Expansion leases.

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. Since the early 1990's, cost reduction efforts, and higher
production levels, have been successful in reducing unit costs.

     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.

     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 2000 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.

     There were two customers in 2000, Koch and Shell, that each represented 10%
or more of Suncor's consolidated revenues in 2000. Shell was the only such
customer in 1999.

     A portion of Oil Sands production is used in connection with Suncor's
Sarnia refining operations. During 2000, the Sarnia refinery processed
approximately 25% (1999 -- 26%) of Oil Sands crude oil


                                                                              17
<PAGE>

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 2000
and 1999, after the impact of hedging activities.

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
                                       2000                                               1999
- ----------------------------------------------------------------------------------------------------------------------
     $/bbl           4Q         3Q           2Q           1Q           4Q           3Q           2Q           1Q
     -----         -----       -----        -----        -----        -----        -----        -----        -----
<S>                <C>         <C>          <C>          <C>          <C>          <C>          <C>          <C>
Average sales
   price           31.33       32.39        31.12        31.84        28.77        24.24        21.57        20.00
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>

CAPITAL EXPENDITURES

     Capital spending information for Oil Sands is set out in the table under
the caption "Capital and Exploration Investing Expenditures" in the Corporate
section of the MD&A.

ENVIRONMENTAL COMPLIANCE

     For a description of the impact of environmental protection requirements on
Oil Sands, refer to the "Government Regulation" section of this Annual
Information Form.

                                   NATURAL GAS

     Suncor's Natural Gas business, based in Calgary, Alberta, explores for,
develops, produces and markets natural gas and natural gas liquids from the
Western Canada Sedimentary Basin.

     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 a
workforce reduction of 70 positions, the consolidation of production in three
core natural gas areas, and a restructuring of business processes to support the
new focus.

     During 2000, NG sharpened its natural gas focus in Western Canada by
concentrating on natural gas prospects and selling most of its conventional
crude oil properties. Exiting 2000, natural gas and natural gas liquids
accounted for approximately 92% of the NG business unit's production. NG also
sold its Burnt Lake property, a project to evaluate steam assisted gravity
drainage technology in the production of heavy oil, which had commenced
production in 1997 (see the "Conventional Crude Oil" section of this Annual
Information Form).

     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.


                                                                              18
<PAGE>

RESERVES AND RESERVES RECONCILIATION

     GLJ reported January 26, 2001, on Suncor's estimated proved and probable
reserves of natural gas, natural gas liquids and crude oil (other than synthetic
crude oil), as of December 31, 2000. Information with respect to these reserves
is set out in the tables below and in the tables under the headings
"Conventional Crude Oil" 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 are considered recoverable under current technology and
     existing economic conditions, from reservoirs that are evaluated on known
     drilling, geological, geophysical and engineering data.

(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.

(3)  Probable reserves are those reserves which the analysis of drilling,
     geological, geophysical and engineering data does not demonstrate to be
     proved under current technology and existing economic conditions, but where
     analysis suggest the likelihood of their existence and future recovery.
     Probable reserves to be obtained by the application of enhanced recovery
     processes will be the increased recovery, over and above that estimated in
     the proved category, 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. A 50% risk factor has been utilized in
     arriving at probable reserves.

(4)  Gross reserves represent the aggregate of Suncor's working 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.


                                                                              19
<PAGE>

     The following tables set out a reconciliation of NG's estimated proved
reserves from December 31, 1999 to December 31, 2000.

                   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
                                                   -------------------  ------------     -------------------   ------------
                                                      (MILLIONS OF      (BILLIONS OF         (MILLIONS OF      (BILLIONS OF
                                                        BARRELS)         CUBIC FEET)           BARRELS)         CUBIC FEET)

<S>                                                <C>                   <C>             <C>                   <C>
December 31, 1999...............................          51(2)            1,013                  41                764
Revisions of previous estimates.................          (3)                (52)                 (6)               (81)
Purchases of minerals in place..................           -                   9                   -                  7
Extension and discoveries.......................           1                  39                   1                 28
Production......................................          (3)                (73)                 (2)               (52)
Sales of minerals in place......................         (30)               (139)                (23)               (99)
                                                         ----               -----                ----               ----
December 31, 2000...............................          16(2)              797                  11                567
                                                         ====               =====                ====               ====
</TABLE>

Notes:

(1)  Sales of minerals in place includes 3.5 million barrels related to Suncor's
     Burnt Lake heavy oil extraction pilot project.

(2)  Includes 9.2 million barrels of natural gas liquids as at December 31, 2000
     (15.8 million barrels as at December 31, 1999).

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

             ESTIMATED PROVED DEVELOPED RESERVES RECONCILIATION (1)

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

<S>                                                <C>                   <C>             <C>                   <C>
December 31, 1999...............................          38                 627                  30                471
Revisions of previous estimates.................          (3)                (10)                 (5)               (31)
Purchases of minerals in place..................           -                   6                   -                  5
Extension and discoveries.......................           1                  69                   1                 49
Production......................................          (3)                (73)                 (2)               (52)
Sales of minerals in place......................         (20)                (46)                (15)               (33)
                                                         ----               -----                ----               ----
December 31, 2000...............................          13                 573                   9                409
                                                         ====               =====                ====               ====
</TABLE>

Note:

(1)  Sales of minerals in place includes 2.5 million barrels of crude oil
     related to Suncor's Burnt Lake heavy oil extraction pilot project


                                                                              20
<PAGE>

            ESTIMATED PROVED UNDEVELOPED RESERVES RECONCILIATION (1)

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

<S>                                                <C>                   <C>             <C>                   <C>
December 31, 1999...............................          13                 386                  11                293
Revisions of previous estimates.................           -                 (42)                 (1)               (50)
Purchases of minerals in place..................           -                   3                   -                  2
Extension and discoveries.......................           -                 (30)                  -                (21)
Sales of minerals in place......................         (10)                (93)                 (8)               (66)
                                                         ----               -----                ----               ----
December 31, 2000...............................           3                 224                   2                158
                                                         ====               =====                ====               ====
</TABLE>

Note:

(1)  Sales of minerals in place includes 1.1 million barrels of crude oil
     related to Suncor's Burnt Lake heavy oil extraction pilot project.

     The following tables set out a reconciliation of NG's estimated probable
reserves from December 31, 1999 to December 31, 2000.

                 ESTIMATED PROBABLE RESERVES RECONCILIATION (1)

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

<S>                                                <C>                   <C>             <C>                   <C>
December 31, 1999...............................          20                 428                  15                322
Revisions of previous estimates.................          (2)                (69)                 (2)               (63)
Purchases of minerals in place..................           -                   5                   -                  4
Extension and discoveries.......................           -                   2                   -                  1
Sales of minerals in place......................         (11)                (62)                 (8)               (47)
                                                         ----               -----                ----               ----
December 31, 2000...............................           7                 304                   5                217
                                                         ====               =====                ====               ====
</TABLE>

Note:

(1)  Sales of minerals in place includes 0.5 million barrels related to Suncor's
     Burnt Lake heavy oil extraction pilot project.

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,
British Columbia and Saskatchewan, represented by the conventional fields
identified in this table.


                                                                              21
<PAGE>

<TABLE>
<CAPTION>
                                                        PROVED RESERVES                   2000 AVERAGE
                                                      BEFORE ROYALTIES AT               DAILY PRODUCTION
                                                      DECEMBER 31, 2000(1)             BEFORE ROYALTIES(3)
                                                     ---------------------           ----------------------
                                                     (MILLIONS OF                    (BARRELS OF
           FIELDS                                      BARRELS)          %           OIL PER DAY)         %
- ------------------------------                       ------------       ---          ------------        ---
<S>                                                  <C>                <C>          <C>                 <C>
Simonette.......................................          3.3            53                910            22
Blueberry.......................................          2.0            31                390             9
McKinley........................................          0.3             5                100             2
Bonanza.........................................          0.2             3                 80             2
Rosevear........................................          0.1             2                 45             1
Divested Properties.............................            0             0              2,650            63
Other(2)........................................          0.3             6                 40             1
                                                          ---           ---              -----           ---
Total -- gross...................................          6.2           100              4,215           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 will be 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 2000,
approximately 75% of Suncor's proved conventional oil reserves were under
enhanced oil recovery programs.

     Suncor's NG business unit had a 79% working interest in a heavy oil
extraction pilot project at Burnt Lake, Alberta. This interest was sold in 2000.


                                                                              22
<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, British Columbia and Saskatchewan, represented by
the conventional fields identified in this table.

<TABLE>
<CAPTION>
                                                        PROVED RESERVES                   2000 AVERAGE
                                                      BEFORE ROYALTIES AT               DAILY PRODUCTION
                                                       DECEMBER 31, 2000                BEFORE ROYALTIES
                                                     ---------------------           ----------------------
                                                     (MILLIONS OF                    (BARRELS OF
           FIELDS                                      BARRELS)          %           OIL PER DAY)         %
- ------------------------------                       ------------       ---          ------------        ---
<S>                                                  <C>                <C>          <C>                 <C>
Simonette.......................................          2.4            26                592            20
Grande Prairie                                            1.5            15                206             7
Knopcik.........................................          1.4            14                448            15
Pine Creek......................................          0.7             8                235             8
Glacier.........................................          0.7             7                 96             3
Stolberg                                                  0.5             6                 40             1
Blueberry                                                 0.5             6                131             4
Rosevear                                                  0.4             4                147             5
George                                                    0.2             2                309            10
Blackstone                                                0.1             1                 48             2
Hinton                                                    0.1             1                 95             3
Mountain Park                                             0.1             1                 19             1
Divested Properties.............................            0             0                125             4
Other(1)........................................          0.8             9                501            17
                                                          ---           ---              -----           ---
Total -- gross..................................          9.4           100              2,992           100
                                                          ===           ===              =====           ===
</TABLE>

Note:

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


                                                                              23
<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                   2000 AVERAGE
                                                      BEFORE ROYALTIES AT               DAILY PRODUCTION
                                                       DECEMBER 31, 2000                BEFORE ROYALTIES
                                                     ---------------------           ----------------------
                                                                                     (MILLIONS OF
                                                     (BILLIONS OF                     CUBIC FEET
           FIELDS                                     CUBIC FEET)        %             PER DAY)           %
- ------------------------------                       ------------       ---          ------------        ---
<S>                                                  <C>                <C>          <C>                 <C>
Stolberg........................................          207            26                 17             8
Blackstone/Brown Creek..........................           92            12                 15             8
Grande Prairie area.............................           61             8                  9             5
Mountain Park...................................           54             7                 11             5
Glacier.........................................           51             6                 10             5
Knopcik area....................................           50             6                 18             9
Rosevear........................................           49             6                 27            13
Simonette.......................................           48             6                 11             5
Blueberry.......................................           43             5                 11             5
Sinclair........................................           22             3                  7             4
Pine Creek......................................           17             2                  6             3
Cutbank.........................................           15             2                  9             5
Divested Properties.............................            0             0                 12             6
Other(1)........................................           88            11                 37            19
                                                          ---           ---                ---           ---
Total -- Gross..................................          797           100                200           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
2000. 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, development costs, operating
costs, abandonment 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.


                                                                              24
<PAGE>

<TABLE>
<CAPTION>
                                     DEVELOPED ACRES                 UNDEVELOPED ACRES                   TOTAL ACRES
                             -----------------------------     ------------------------------    -----------------------------
                             GROSS ACRES(1)   NET ACRES(1)     GROSS ACRES(1)   NET ACRES(1)     GROSS ACRES(1)   NET ACRES(1)
                             --------------   ------------     --------------   ------------     --------------   ------------
                                                                           (THOUSANDS)
<S>                          <C>              <C>              <C>              <C>               <C>             <C>
CANADA
CONVENTIONAL
Alberta....................       318             204                 738            547              1,056             751
British Columbia...........       111              47                 329            247                440             294
Saskatchewan...............         0               0                   -              -                  0               0
                                  ---             ---               -----          -----              -----           -----
Total Conventional.........       429             251               1,067            794              1,496           1,045
                                  ---             ---               -----          -----              -----           -----
NON-CONVENTIONAL
Alberta....................        15               4                 294            257                309             261
Frontier...................         7               3                 535             70                542              73
Total Non-Conventional.....        22               7                 829            327                851             334
                                  ---             ---               -----          -----              -----           -----
UNITED STATES
Coal Bed Methane...........         -               -                  18             18                 18              18
                                  ---             ---               -----          -----              -----           -----
AUSTRALIA
Coal Bed Methane...........         -               -               1,280          1,100              1,280           1,100
                                  ===             ===               =====          =====              =====           =====
Total Landholdings                451             258               3,194          2,239              3,645           2,497
                                  ===             ===               =====          =====              =====           =====
</TABLE>

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, all in Western Canada, which were completed, capped or
abandoned in which Suncor participated during the years indicated.

<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31,
                                                      -------------------------------------------------
                                                              2000                         1999
                                                      ------------------           --------------------
                                                      GROSS          NET           GROSS            NET
                                                      -----          ---           -----            ---
<S>                                                   <C>            <C>           <C>              <C>
Exploratory Wells
  Crude oil.....................................         0             0              1               1
  Gas...........................................         3             1              6               5
  Dry...........................................        17            15             17              13
                                                        --            --             --              --
Total Exploratory Wells.........................        20            16             24              19
                                                        --            --             --              --
Development Wells
  Crude oil.....................................         5             2             14               2
  Gas...........................................        23            14              9               4
  Dry...........................................         4             3              3               1
                                                        --            --             --              --
Total Development Wells ........................        32            19             26               7
                                                        --            --             --              --
Total...........................................        52            35             50              26
                                                        ==            ==             ==              ==
</TABLE>

     Not included are 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 four gross (two
net) exploratory wells in progress at the end of 2000. Also, Suncor had an
interest in one gross (one net) coal bed methane well in Alberta.

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


                                                                              25
<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, 2000.

<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.....................................................          48            32             22              18
  British Columbia............................................          23            11              6               3
  NWT.........................................................           -             -              -               -
                                                                       ---           ---            ---              --
Total Conventional Crude Oil Wells............................          71            43             28              21
                                                                       ---           ---            ---              --
CONVENTIONAL NATURAL GAS WELLS
  Alberta.....................................................          45           135             51              27
  British Columbia............................................          45            22             20              13
  NWT                                                                    -             0              2               2
                                                                       ---           ---            ---              --
TOTAL CONVENTIONAL NATURAL GAS WELLS..........................         290           157             73              42
                                                                       ---           ---            ---              --
NON-CONVENTIONAL HEAVY CRUDE OIL
  Alberta.....................................................           0             0             10               8
                                                                       ---           ---            ---              --
COAL BED METHANE
  Alberta.....................................................           0             0              1               1
                                                                       ---           ---            ---              --
TOTAL WELLS...................................................         361           200            112              72
                                                                       ===           ===            ===              ==
</TABLE>

Notes:

(1)  Gross wells represent the number of wells in which NG has a working
     interest and net wells represent NG's aggregate working 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, 2000 Suncor has
     interests in four oil fields and 28 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, 2000.

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,
                                                                     ------------------
                                                                     2000          1999
                                                                     ----          ----
                                                                        ($ MILLIONS)
<S>                                                                  <C>           <C>
Crude oil and natural gas liquids.............................         77           100
Natural gas...................................................        344           198
Pipeline......................................................          6             5
Other.........................................................          1             3
                                                                      ---           ---
Total.........................................................        428           306
                                                                      ===           ===
</TABLE>

Note:

(1)  Includes intersegment revenues.


                                                                              26
<PAGE>

PRODUCTION COSTS

     The following shows production (lifting) costs in connection with NG's
crude oil and natural gas operations for the years indicated.

<TABLE>
<CAPTION>
                                                                                                YEAR ENDED
PRODUCTION    (LIFTING) COSTS                                                                  DECEMBER 31,
                                                                                            ------------------
                                                                                            2000          1999
                                                                                            ----          ----
                                                                                               ($ PER BOE OF
                                                                                             GROSS PRODUCTION)

<S>                                                                                         <C>           <C>
Average production (lifting) cost of conventional crude oil and gas(1)..................    4.62          4.40
</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.

QUARTERLY VOLUMES AND NETBACK ANALYSIS

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

<TABLE>
<CAPTION>
                                                2000                                                    1999
                         ----------------------------------------------------    ---------------------------------------------------
                           4Q         3Q          2Q        1Q        TOTAL        4Q        3Q         2Q         1Q       TOTAL
                         --------   --------    -------   -------    --------    -------    ------    -------    -------   ---------
<S>                      <C>        <C>         <C>       <C>        <C>         <C>        <C>       <C>        <C>       <C>
NATURAL GAS
Production Volume
(mmcf/day)                   183        200        195       222         200        219       231        225        229         226
                         --------   --------    -------   -------    --------    -------    ------    -------    -------   ---------

Price / mcf                 8.02       4.63       3.70      2.96        4.72       2.96      2.48       2.15       2.18        2.44
Royalties / mcf            (2.14)     (1.09)     (0.85)    (0.61)      (1.17)     (0.72)    (0.37)     (0.23)     (0.28)      (0.40)
Operating
Expenses / mcf             (0.95)     (0.68)     (0.77)    (0.66)      (0.76)     (0.68)    (0.77)     (0.58)     (0.61)      (0.66)
                         --------   --------    -------   -------    --------    -------    ------    -------    -------   ---------
Netback / mcf               4.93       2.86       2.08      1.69        2.79       1.56      1.34       1.34       1.29        1.38
                         ========   ========    =======   =======    ========    =======    ======    =======    =======   =========

CONVENTIONAL CRUDE OIL
Production Volume
(kbbls/day)                  1.6        3.6        3.5       8.1         4.2        7.9       8.4        9.7       10.8         9.2
                         --------   --------    -------   -------    --------    -------    ------    -------    -------   ---------

Price / bbl                36.01      33.09      30.04     26.30       29.50      25.21     20.55      20.48      18.48       20.94
Royalties / bbl           (11.52)     (9.70)     (8.29)    (8.31)      (9.46)     (7.00)    (5.54)     (3.81)     (2.29)      (4.66)
Operating
Expenses / bbl             (9.47)     (6.79)     (7.65)    (6.62)      (7.63)     (6.76)    (7.69)     (5.83)     (6.07)      (6.59)
                         --------   --------    -------   -------    --------    -------    ------    -------    -------   ---------
Netback / bbl              15.02      16.60      14.10     11.37       12.41      11.45      7.32      10.84      10.12        9.69
                         ========   ========    =======   =======    ========    =======    ======    =======    =======   =========

NATURAL GAS LIQUIDS
Production Volume
(kbbls/day)                  2.5        2.8        3.1       3.5         3.0        4.0       4.1        4.1        4.7         4.2
                         --------   --------    -------   -------    --------    -------    ------    -------    -------   ---------

Price / bbl                43.00      39.56      32.80     33.16       36.66      27.12     22.81      16.70      11.88       19.32
Royalties / bbl           (12.62)    (11.50)     (9.55)    (9.25)     (10.73)     (7.44)    (5.89)     (4.96)     (3.40)      (5.42)
Operating
Expenses / bbl             (9.47)     (6.79)     (7.65)    (6.62)      (7.63)     (6.76)    (7.69)     (5.83)     (6.07)      (6.59)
                         --------   --------    -------   -------    --------    -------    ------    -------    -------   ---------
Netback / bbl              20.91      21.27      15.60     17.29       18.30      12.92      9.23       5.91       2.41        7.31
                         ========   ========    =======   =======    ========    =======    ======    =======    =======   =========
</TABLE>


                                                                              27
<PAGE>

MARKETING, PIPELINE AND OTHER OPERATIONS

     Suncor operates gas processing plants at South and North Rosevear, Pine
Creek, Boundary Lake South, Progress, and Simonette with a total design capacity
of approximately 243 million cubic feet per day. Suncor's interest in these gas
processing plants is approximately 166 million cubic feet per day. Suncor also
has varying working interests in natural gas processing plants operated by other
companies.

     Approximately 70% of Suncor's natural gas production is marketed under
direct sales arrangements to customers in Alberta, eastern Canada, and the U.S.
midwest and west coast. This includes a significant volume of natural gas
consumed in Suncor's Oil Sands plant at Fort McMurray and in its Sarnia
refinery. NG contracts for the supply of natural gas to each of these
facilities. Natural gas consumption at the Oil Sands plant in 2000 was 24
million cubic feet per day and is anticipated to range from 50 - 100 million
cubic feet per day during Project Millennium commissioning in 2001. Natural gas
consumption at the Sarnia refinery in 2000 was 21 million cubic feet per day.
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
U.S. are made under a variety of arrangements with differing transportation and
pricing terms.

     Approximately 30% 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 U.S. markets.

     To ensure ongoing direct sales access to U.S. markets, 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
million cubic feet per day on the Pacific Gas Transmission ("PGT") pipeline to
the California border extending to the year 2023.

     Suncor's 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 180 miles south of the plant and connects with the TCPL
Alberta intraprovincial pipeline system. The Albersun pipeline has the capacity
to move in excess of 100 million cubic feet per 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 2000, throughput on Albersun
pipeline was 68 million cubic feet per day and revenues were approximately $6
million.

CAPITAL AND EXPLORATION EXPENDITURES

     Capital and exploration spending information for Suncor's NG business unit
is set out in the table under the caption "Capital and Exploration Investing
Expenditures" in the Corporate section of MD&A.


                                                                              28
<PAGE>

ENVIRONMENTAL COMPLIANCE

     For a description of the impact of environmental protection requirements on
NG, refer to the information under the headings, "Risk/Success Factors Affecting
Performance" in the Natural Gas Section of the MD&A, and also to the "Government
Regulation" section of this Annual Information Form.

                                     SUNOCO

     Suncor conducts its refining and retail marketing of petroleum products and
petrochemicals through its principal subsidiary, Sunoco Inc., and its
subsidiaries and joint ventures. Sunoco's operations are carried out by three
divisions: Refining (including wholesale), Retail Marketing, and Integrated
Energy Solutions.

REFINING

     SARNIA REFINERY.  Located in Sarnia, Ontario, the Sunoco refinery has an
economic refining capacity of 70,000 barrels of crude oil per day and average
2000 refining sales of approximately 92,200 barrels per day. This complex
refinery has the flexibility to produce a high proportion of transportation
fuels and value-added petrochemicals. The configuration of the refinery
permits the processing of a high percentage of sweet synthetic crude oil, in
addition to conventional sweet and sour crudes. The competitive advantage of
processing sweet synthetic crude oil is that it is low in sulphur and heavy
petroleum products (less valuable products) yielding a more valuable product
mix.

     The refinery has cracking capacity of 40,200 barrels per day from a Houdry
catalytic cracker and a hydrocracker. Approximately 40% of the cracking capacity
at the refinery is attributable to the Houdry catalytic cracker, which was built
in the early 1950s and uses an older cracking technology. In 2000, some
additional maintenance costs were incurred as the result of unplanned outages.
The next major maintenance on the Houdry catalytic cracker is expected in 2001.

     The hydrocracker, which is capable of processing approximately 23,300
barrels per day, adds flexibility by producing premium distillate and napthas.
An alkylation unit, capable of processing 5,400 barrels per day, complements a
petrochemical plant for flexibility in gasoline, octane and petrochemical
production. The addition of a jet fuel tower in 1993 and a low sulphur diesel
tower in 1995 further added to the refinery's ability and flexibility to produce
premium-valued transportation fuels. As a result of this configuration, the
refinery has flexibility to vary its gasoline/distillate ratio.

     In 2000 a solvents unit was added. With a capacity of 3,100 barrels per
day, the unit produces two streams of chemical products, A-100 and A-150, which
were not previously produced at the Sarnia refinery. These chemical products are
of a higher value than the streams they replaced, broadening Sunoco's chemical
product slate and expanding the Company's customer base to include paint and
chemical manufacturers. The total chemicals output of the Sarnia refinery
increased in 2000 as a result of the addition of the new unit.


                                                                              29
<PAGE>

     The following chart sets out the average daily crude input, average
refinery utilization rate, and cracking capacity utilization of the Sarnia
refinery over the last two years:

<TABLE>
<CAPTION>
                                                                           2000        1999
                                                                          ------      ------
<S>                                                                       <C>         <C>
Crude input -- barrels per day......................................      68,900      66,500
Average utilization rate (%)(1).....................................          98          95
Average cracking capacity utilization (%)(2)........................          91          96
</TABLE>

Notes:

(1)  Based upon crude unit processing capacity and input to crude units.

(2)  Based upon rated throughput capacity and input to units.

     During 2000, the Sarnia refinery completed a planned 32-day turnaround on
the hydrocracker. The work was completed on time and on budget. Several
unplanned outages were also experienced during 2000. In the next regular
turnaround in 2001, specific maintenance work to address the operational issues
will be integrated into the plan.

     SOURCES OF FEEDSTOCK.  Sunoco's refining operation uses both synthetic
and conventional crude oil. In 2000, 64% of the crude oil refined at the
Sarnia refinery was synthetic crude oil, compared with 65% in 1999, the
remainder being conventional crude oil and condensate. Of the synthetic crude
oil refined, approximately 56% in 2000 was from Suncor's Oil Sands plant
production compared to 63% in 1999, with the balance purchased from others
under month to month contracts. In the event of a significant disruption in
the supply of synthetic crude oil from either Suncor's Oil Sands business
unit or the other suppliers of synthetic crude oil, additional sweet or sour
conventional crude oil would be processed. Conventional crude oil refined by
Sunoco comes mainly from western Canada, supplemented from time to time with
crude oil from the United States and other foreign sources purchased or
obtained in exchange for Canadian crude. Crude oil from other countries can
be delivered to Sarnia via pipeline from the United States Gulf Coast and
from the east coast, via the Interprovincial Pipeline from Sarnia to Montreal
(Line 9), which began shipping in an east-west direction in October 1999.
Sunoco has not committed to firm pipeline capacity on either of these lines.

     The market for crude oil generally is conducted on a spot basis or under
contracts terminable by short notice.

     Production of transportation fuels is enhanced through a buy/sell agreement
with Nova Chemicals (Canada) Ltd., a petrochemical refinery in which feedstocks
more suitable for gasoline blending are taken by Sunoco in exchange for
feedstocks more suitable for petrochemical cracking. Reciprocal product buy/sell
and exchange agreements are also used with other refiners to minimize
transportation costs, balance product availability in particular locations, and
enhance refinery utilization. These agreements are entered into from time to
time, and renewed as necessary. On occasion, Sunoco purchases refined products
to supplement its own refinery production.

     Since late 1997, Sunoco has been marketing ethanol-enhanced gasolines
through all of its Sunoco branded service stations. In order to secure supply,
Sunoco signed an exclusive 10-year ethanol fuel supply agreement with Commercial
Alcohols Inc., which constructed a 150 million litre per year capacity ethanol
plant near Chatham, Ontario. The agreement with Commercial Alcohols Inc.
terminates in 2007. By the end of 2000, Sunoco's ethanol enhanced gasolines were
also being sold through most of the joint-venture operated retail service
stations.

     PRINCIPAL PRODUCTS.  The refinery produces transportation fuels, heating
fuels, heavy fuel oils, and petrochemicals and liquefied petroleum gases.
Sunoco's petrochemical facilities, with a design capacity of 13,100 barrels
per day (approximately 2,090 cubic metres), produce benzene, toluene and
mixed xylenes and recover orthoxylene from mixed xylenes, as well as
petrochemicals A-100 and A-150.


                                                                              30
<PAGE>

     Noted below is information on Sunoco's daily sales volumes for the last two
years.

<TABLE>
<CAPTION>
        DAILY SALES VOLUMES                                               2000          1999
        -------------------                                              ------        ------
                                                                             (THOUSANDS OF
                                                                         CUBIC METRES PER DAY)
<S>                                                                      <C>         <C>
Transportation fuels
Gasoline -- retail (1).............................................        4.2           4.1
         -- other..................................................        4.0           3.7
Jet fuel...........................................................        1.1           1.1
Other..............................................................        3.1           2.7
                                                                          ----          ----
                                                                          12.4          11.6
                                                                          ----          ----
Petrochemicals.....................................................        0.6           0.7
Heating fuels......................................................        0.4           0.4
Heavy fuel oils....................................................        0.6           0.5
Other..............................................................        0.6           0.6
                                                                          ----          ----
Total..............................................................       14.6          13.8
                                                                          ====          ====
</TABLE>

Note:

(1)  Excludes sales through joint ventures.

     Sales of gasolines and other transportation fuels represented 69% of
Sunoco's consolidated sales and other operating revenues in 2000 compared to 62%
in 1999.

     TRANSPORTATION AND DISTRIBUTION.  A variety of transportation modes are
used to deliver products to markets, including pipeline, water, rail and
road. Sunoco owns and operates petroleum transportation, terminal and dock
facilities in support of its refining and marketing activities. Such assets
include storage facilities and bulk distribution plants in Ontario and a 55%
interest in the Sun-Canadian Pipe Line, a refined products pipeline between
Sarnia and Toronto.

     The major mode of transportation for gasolines, diesel, jet fuel and
heating fuels from the Sarnia refinery to its core markets in Ontario is the
refined products pipeline owned and operated by Sun-Canadian Pipe Line
Company Limited. The pipeline serves terminal facilities in London, Hamilton
and Toronto, and has a capacity of 126,000 (20,000 m(3)) barrels per day of
which 84% was utilized in 2000 and 83% was utilized in 1999. Ownership of the
pipeline company is divided between Suncor with a 55% interest, and another
integrated refiner with a 45% interest. The pipeline operates as a private
facility for its owners.

     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 at
Sarnia operated by a U.S. based refiner. This link to the United States allows
Sunoco to quickly move products to market or obtain feedstocks or products when
market conditions are favourable in the Michigan and Ohio markets.

     Sunoco believes that its own facilities and those under long-term
contractual arrangements with other parties will provide a sufficient level of
storage for its current and foreseeable needs.

     PRINCIPAL MARKETS.  Sunoco markets transportation fuels (gasoline,
diesel, propane and jet fuel), heating fuels, liquefied petroleum gases,
residual fuel oil and asphalt feedstock to its retail marketing business and
industrial, commercial and wholesale customers and refiners, primarily in
Ontario. In Quebec, Sunoco supplies its industrial and commercial customers
through long-term arrangements with other regional refiners or through Group
Petrolier Norcan Inc., a 25% Suncor-owned fuels terminal and product supply
business in Montreal, Quebec. In addition, at the end of 2000, Sunoco markets
diesel through eleven branded Fleet Fuel Cardlock sites.

     Sunoco also markets toluene, mixed xylenes, orthoxylene and petrochemicals,
primarily in Canada and the United States, through Sun Petrochemicals Company.
Suncor Energy Marketing Inc.



                                                                              31
<PAGE>

has a 50% interest in Sun Petrochemicals Company, a petrochemical marketing
joint venture established in 1992 with a subsidiary of a U.S. refiner, to
market products from a Toledo, Ohio refinery owned by the joint venture
partner, and Sunoco's Sarnia refinery. Under this arrangement, petrochemicals
used to manufacture plastics, rubber, synthetic fibres, industrial solvents
and agricultural products, and as gasoline octane enhancers, are marketed.
All Sunoco's benzene production is sold directly to other petrochemical
manufacturers in Sarnia, and sales of other petrochemical products are made
mostly in North America.

     Approximately 84% of Sunoco's total gasoline volumes are sold through the
retail marketing channels referred to under the heading "Retail Distribution
Channels" below. The remainder is sold through wholesale, commercial and
industrial accounts in Ontario and Quebec which sell transportation fuels
(including gasoline, diesel and jet fuels) and heating oil. Sunoco's share of
total refined product sales in its primary market of Ontario is approximately
17% (1999 - approximately 16%). Sales of transportation fuels accounted for over
85% of Sunoco's total volumes in 2000. Petrochemicals sales represented over 3%
of total volumes, and the remaining volumes were comprised of other refined
products such as heating fuels, heavy oils, and liquefied petroleum gases which
were sold to various industrial users and resellers.

RETAIL MARKETING

     RETAIL DISTRIBUTION CHANNELS.  Sunoco's retail marketing division
consists of three distinct distribution channels

     o    301 Sunoco retail service stations,

     o    154 Pioneer-operated retail service stations (Pioneer Group Inc. is an
          independent retailer with which Sunoco has a 50% joint venture
          partnership), and

     o    54 UPI-operated service stations and a network of bulk distribution
          facilities for rural and farm fuels (UPI Inc. is a 50% joint venture
          company owned by Sunoco and GROWMARK Inc., a U.S. midwest agricultural
          supply and grain marketing cooperative).

     Volumes to the Pioneer and UPI joint ventures are supplied under exclusive
supply agreements. The agreement with UPI expires in 2002, after which Sunoco
will continue to be the exclusive supplier of refined products as long as it
remains a shareholder. Sunoco plans to maintain its relationship with this joint
venture. The Pioneer agreement expires in 2003 and it will be automatically
renewed thereafter for one-year terms until terminated upon twelve months prior
written notice. No notice has been given.

INTEGRATED ENERGY SOLUTIONS

     In 1997, Sunoco entered the residential and commercial natural gas
marketing business in Ontario. This initiative was considered to be the first
step to broaden Sunoco's energy offering. Sunoco now serves more than 130,000
residential and commercial customer accounts in Ontario. Despite a small
percentage of the customer contracts still tied to utility-regulated rates,
which have lagged behind the rising market prices, over 95% of Sunoco's customer
contracts have been converted to fixed-price sales contracts. These are matched
with fixed-price supply arrangements to mitigate risk exposure to market
volatility and to yield a positive margin in 2001.

CAPITAL EXPENDITURES

     Capital spending information for Sunoco is set out in the table under the
caption, "Capital and Exploration Investing Expenditures" in the Corporate
section of the MD&A.


                                                                              32
<PAGE>

ENVIRONMENTAL COMPLIANCE

     For a description of the impact of environmental protection requirements on
Sunoco, refer to "Environmental Performance" and "Risk/Success Factors
Affecting Performance" in the Sunoco section of MD&A, and also to the
"Government Regulation" section of this Annual Information Form.

                                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,
                                                                             -------------------
                                                                              2000          1999
                                                                             -----         -----
<S>                                                                          <C>           <C>
Oil Sands...........................................................         2,057         1,741
Natural Gas.........................................................           182           314
Sunoco(1)...........................................................           590           591
Stuart Project......................................................            77            68
Corporate(2)........................................................           137            82
                                                                             -----         -----
Total...............................................................         3,043         2,796
                                                                             =====         =====
</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.

     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 1,250 Oil Sands employees. The current collective
agreement expires on May 1, 2001. Management believes Suncor's positive working
relationship will continue and that a new agreement should be reached without
work interruptions.

     Employee associations represent approximately 170 Sunoco Sarnia refinery
and Sun-Canadian Pipe Line Company employees. In September 1999, Sunoco signed a
new two-year agreement with the employee associations, which will be
renegotiated in 2001. Sunoco management believes Sunoco's positive working
relationship will continue and a new agreement should be reached. Relations with
these associations have been constructive for many years.


                                                                              33
<PAGE>

                              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 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. Oil and natural gas 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 in 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 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 2000, see note 18 of Suncor's consolidated financial statements.

     Suncor conducts an assessment of the carrying value of its assets to the
extent required by Canadian 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. In 2000, Suncor
wrote down the carrying value of its investment in the Stuart Oil Shale
Project. In addition, as result of a decision to dispose of properties that
were no longer viewed as core or strategic to ongoing plans of Suncor's
Natural Gas business, the carrying values of these properties were written
down to their net estimated recoverable amount and a provision for estimated
restructuring costs was recorded.

     RISK FACTORS RELATED TO PROJECT MILLENNIUM.  The present capital cost
estimate for completion of Project Millennium is $2.8 billion, up from
original estimates. There are certain risks associated with the Project
Millennium schedule, resources (including securing materials, skilled labour
and equipment) and cost, including the risk that current cost estimates will
be exceeded. At this stage of the project, the main risks to Project
Millennium execution include the potential for reduced productivity and
increased costs that can be associated with weather, or unforeseen
disruptions in the supply of labour. While Project Millennium design mainly
utilizes established technologies, the commissioning of all the new units and
the integration of the new facilities with the existing asset base could
cause delays in achieving the expected production capacity of 225,000 barrels
per day by 2002.

     Suncor believes that the planned increases in Oil Sands production
present issues that require prudent risk management, including, but not
limited to: 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 impact of changing standards for
government regulation and public expectations in relation to the impact of
oil sands development on the environment.


                                                                              34
<PAGE>

     INCREASED DEPENDENCE ON OIL SANDS BUSINESS.  The Company's significant
capital commitment to complete Project Millennium may require it to forego
investment opportunities in other segments of its operations. Equally
significant capital commitments may be required and made in future toward
achievement of Suncor's long term vision for its Oil Sands operations. In
addition, completion of Project Millennium, and any such future projects to
increase production capacity at Oil Sands, will substantially increase the
Company's dependence on the Oil Sands segment of its business. When Project
Millennium is completed, for example, the Oil Sands business could account
for 90% of Suncor's upstream production in 2002 compared to 70% in 1998. To
mitigate this, twinning of the extraction and upgrading processes after
completion of Project Millennium will reduce the impact of disruption in
operations.

     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 indicated they are planning to enter
the oil sands business and begin production of synthetic crude oil, or expand
existing operations. Expansion of existing operations and development of new
projects could materially increase the supply of 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. If all announced competing projects were to be built, they could
quadruple production of bitumen and upgraded synthetic crude oil to more than
two million barrels (320,000 cubic metres) per day.

     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.

     Over the past five years 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 and potentially
electricity, 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,
NG's cash flow from such production 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 2000, 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.


                                                                              35
<PAGE>

     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. The Oil Sands plant located near Fort
McMurray in northern Alberta 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. During December 2000, for example, three weeks of prolonged cold
weather conditions impacted productivity and costs. While there is no finding
cost associated with synthetic crude oil, mine development and expansion of
production 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
sand 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. 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 $70 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 Stuart Oil Shale Project, cannot
be assured.

     There are also inherent risks, including political and foreign exchange
risk, in investing in business ventures internationally. To date, other than
the Stuart Oil Shale Project, Suncor has not made material international
investments. However, export sales in 2000 represented 14% of Suncor's 2000
consolidated revenue (1999 - 10%).


                                                                              36
<PAGE>

     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 effectively fix the interest rate on floating rate debt.

     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 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 productions and petrochemicals. Environmental assessments are
required before initiating most new major projects or undertaking significant
changes to existing operations. In addition to these specific, known
requirements, Suncor expects further changes will likely be required to
preserve and protect the environment and quality of life. Some of the issues
under discussion include: possible cumulative impacts of oil sands
development in the Athabasca region; reducing or stabilizing various
emissions, including greenhouse gases; 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, and methods of production and distribution. For
example, requirements for cleaner-burning fuels could cause additional costs,
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 will 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.

     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
($13 million as at December 31, 2000) 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 2001.

     UNCERTAINTY OF RESERVE ESTIMATES.  The reserve data 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 of these proved reserves, 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
function of the quality and quantity of available data and of engineering
interpretation and judgment. 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


                                                                              37
<PAGE>

regulatory constraints. 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.

     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 volatility and overall marketplace competitiveness will
continue.

     In 1998, 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. No regulations have been tabled at
this time with respect to sulphur levels in diesel, although Suncor expects
limits that will be less than its current capabilities. Actual capital
spending required for Sunoco to meet the announced and anticipated new
standards for both gasoline and diesel is subject to the findings of a
strategic assessment underway at Sunoco. Decisions relative to gasoline will
be finalized and a detailed implementation plan will be completed in 2001.
The cost to comply with the anticipated sulphur in diesel limits could be
significant but are not 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 labor union
and an employee association, respectively. Suncor's collective agreement with
the Communications, Energy and Paperworkers Union Local 707 at Oil Sands
expires on May 1, 2001. Suncor believes that the current positive working
relationship will continue and that a new agreement should be reached without
work interruptions, although no assurance can be given in this regard. Other
building trades labour agreements expire on April 30, 2001. While Suncor is
not a direct party to these agreements they impact Suncor as these trades
supply labour for much of Project Millennium. Project Millennium management
has developed a working relationship with the trade unions and believes a
satisfactory resolution will be reached that will not impede progress on the
project. Any work interruptions 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, operates under federal, provincial and municipal
legislation, regulation and intervention by governments in such matters as
land tenure, prices, royalties, production rates, environmental protection
controls, income, the exportation of crude oil, natural gas and other
products, as well as other matters. This industry is also subject to
regulation and intervention by governments in such matters as 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 and 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 impact.


                                                                              38
<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, 2000 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, 2000 have been
audited by PricewaterhouseCoopers LLP (formerly Coopers & Lybrand), Chartered
Accountants. Suncor's 2000 audited consolidated financial statements include the
audit report of PricewaterhouseCoopers LLP for each of the years in the
three-year period ended December 31, 2000. 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)
                                                               ----------------------------
                                                                2000        1999       1998
                                                               -----       -----      -----
                                                                  ($ MILLIONS EXCEPT PER
                                                                       SHARE AMOUNTS)

     <S>                                                       <C>         <C>        <C>
     Revenues.........................................         3,388       2,387      2,070
     Net earnings.....................................           377         186        178
     Per common share(1) (undiluted)..................          1.58        0.74       0.81
     Per common share(1) (diluted)....................          1.57        0.73       0.80
     Cash flow provided from operations...............           958         591        580
     Per common share(1)..............................          4.11        2.51       2.64
     Capital and exploration expenditures.............         1,998       1,350        936
</TABLE>

<TABLE>
<CAPTION>
                                                                     AS AT DECEMBER 31,
                                                               ----------------------------
                                                                2000        1999       1998
                                                               -----       -----      -----
                                                                        ($ MILLION)

     <S>                                                       <C>         <C>        <C>
     Total assets.....................................         6,833       5,176      4,104
     Long-term borrowings(2)..........................         2,193       1,307      1,299
     Common shareholders' equity(3)...................         1,958       1,594      1,499
</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)  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 will be 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 2001 has been
declared, payable on March 26, 2001 to shareholders of record on March 15, 2001.

     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 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



                                                                              39
<PAGE>

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. Proceeds from the offerings were used to
repay commercial paper borrowings.

     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,
                                                               -----------------------------
                                                                2000        1999       1998
                                                               ------      ------     ------
     <S>                                                       <C>         <C>        <C>
     Common Shares
     Cash dividends(1)................................         $ 0.34      $ 0.34     $ 0.34
     Preferred Securities
     Cash interest distributions......................         $ 0.21      $ 0.17         --
     Dividends paid in common shares..................             --          --         --

</TABLE>
Note:

(1)  Per share amounts for all years 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 pipeline commitments are described in the following table:

<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------
                                                                          AGGREGATE
     NATURE OF COMMITMENTS             TERM             VOLUME            PRICE/COST       PRICE PER UNIT
- --------------------------------------------------------------------------------------------------------------
                                                                         ($ MILLIONS)
<S>                                  <C>              <C>                 <C>              <C>
Natural gas pipeline commitments:
- --------------------------------------------------------------------------------------------------------------
  Nova                               1998-2008            **                 19            $0.17 per MCF
- --------------------------------------------------------------------------------------------------------------
  Westcoast Energy                   1996-2001        27 mmcf/day             2            $0.23 per MCF
- --------------------------------------------------------------------------------------------------------------
  Foothills                          1997-2003        16 mmcf/day             1            $0.08 per MCF
- --------------------------------------------------------------------------------------------------------------
  Northern Border                    1997-2003        14 mmcf/day             8            $0.52 per MCF
- --------------------------------------------------------------------------------------------------------------
  Alberta Natural Gas                1991-2008        41 mmcf/day             9            $0.07 per MCF
- --------------------------------------------------------------------------------------------------------------
  Pacific Gas Transmission           1995-2023        40 mmcf/day           166            $0.49 per MCF
- --------------------------------------------------------------------------------------------------------------
</TABLE>


     The Company's Natural Gas business has entered into numerous natural gas
purchase and sale commitments, aggregating 71 mmcf/day and 220 mmcf/d,
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 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


                                                                            40
<PAGE>

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 18 to
Suncor's 2000 consolidated financial statements, which note is incorporated by
reference herein.

     Also see note 15 to Suncor's 2000 consolidated financial statements, which
note is incorporated by reference herein, for a further description of the
Company's operating commitments for 2001 and subsequent years.

                      MANAGEMENT'S DISCUSSION AND ANALYSIS

     Suncor's Management's Discussion and Analysis, dated February 28, 2001, 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 40% 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.

                             DIRECTORS AND OFFICERS

     As of the date hereof, Suncor's Board of Directors is comprised of twelve
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, 2001(1)
- ----------------------------     --------------------      ----------------------     ------------------------
<S>                              <C>                       <C>                        <C>

Mel Benson(2)                    April 19, 2000 to         Management Services          1,000 Common Shares
Calgary, Alberta                 Present                   Consultant                     365 Deferred Share
                                                                                              Units(3)



                                                                              41
<PAGE>

                                                                                        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, 2001(1)
- ----------------------------     --------------------      ----------------------     ------------------------
<S>                              <C>                       <C>                        <C>

Brian A. Canfield(2)(4)          November 10, 1995         Chairman                     8,052 Common Shares
Point Roberts, Washington        to Present                TELUS Corporation(a
                                                           telecommunications           2,669 Deferred Share
                                                           company)                            Units(3)

Bryan P. Davies(5)               January 28, 1991          Senior Vice                  6,200 Common Shares
Etobicoke, Ontario               to April 23, 1996         President,
                                                           Regulatory Affairs,            364 Deferred Share
                                 April 19, 2000 to         Royal Bank of Canada                Units(3)
                                 Present                   (a chartered banking
                                                           institution)

John T. Ferguson(5)(6)           November 10, 1995         Chairman, Princeton          8,310 Common Shares
Edmonton, Alberta                to Present                Developments Ltd. (a
                                                           real estate                  1,323 Deferred Share
                                                           development                         Units(3)
                                                           company), Chairman
                                                           and Director,
                                                           TransAlta
                                                           Corporation (an
                                                           electric utility
                                                           company)

Richard L. George(6)             February 1, 1991          President and Chief         94,262 Common Shares
Calgary, Alberta                 to Present                Executive Officer,
                                                           Suncor Energy Inc.(7)

Poul Hansen(2)(5)                April 23, 1996 to         Chairman and General         6,826 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          10,273 Common Shares
Houston, Texas                   to Present                Executive Officer,
                                                           Oceaneering                  2,811 Deferred Share
                                                           International, Inc.                 Units(3)
                                                           (an oilfield
                                                           services company)

Michael M. Koerner(4)(6)(8)      May 31, 1977 to           President, Canada            8,000 Common Shares
Toronto, Ontario                 January 27, 1994          Overseas Investments
                                                           Limited (a venture           3,197 Deferred Share
                                 October 1, 1995 to        capital investment                  Units(3)
                                 Present                   management company)


                                                                              42
<PAGE>

                                                                                        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, 2001(1)
- ----------------------------     --------------------      ----------------------     ------------------------
<S>                              <C>                       <C>                        <C>

Robert W. Korthals(2)(5)(9)      April 23, 1996 to         Corporate Director           8,000 Common Shares
Toronto, Ontario                 Present
                                                                                        1,854 Deferred Share
                                                                                               Units (3)

M. Ann McCaig(2)(5)              October 1, 1995 to        President, VPI               5,120 Common Shares
Calgary, Alberta                 Present                   Investments Ltd. (a
                                                           private investment           3,065 Deferred Share
                                                           holding company)                    Units(3)

JR Shaw(5)(6)                    January 30, 1998          Executive Chairman          37,000 Common Shares
Calgary, Alberta                 to Present                of the Board, Shaw
                                                           Communications Inc.          2,862 Deferred Share
                                                           (a diversified                      Units(3)
                                                           communications
                                                           company)

W. Robert Wyman(4)(6)            November 25, 1987         Chairman of the             32,400 Common Shares
West Vancouver, British          to Present                Board of Directors
Columbia                                                   of Suncor Energy Inc.        4,106 Deferred Share
                                                                                               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. Where a nominee holds a fractional Common Share, the holdings
     reported have been rounded down to the nearest whole Common Share. Certain
     of the Common Shares held by Mr. George and Mr. Hansen 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. 400
     Common Shares held by Mr. Benson are beneficially owned by his spouse, but
     he exercises control or direction over such shares.

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

(3)  Deferred Share Units (DSU's) are not securities but are included for
     informational purposes as they represent an economic interest based on
     Common Shares of the Company.

(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 is also the President and a director of Sunoco Inc., Suncor's
     refining and marketing subsidiary, and Suncor Energy Marketing Inc.,
     Suncor's crude oil marketing subsidiary.


                                                                              43
<PAGE>

(8)  Mr. Koerner, Suncor's longest serving director, will retire from Suncor's
     Board of Directors at the expiry of his current term of office on April 18,
     2001.

(9)  In 1998, Mr. Korthals was a director of Anvil Range Mining Corporation,
     which sought protection under the Companies Creditors Arrangement Act
     (Canada).

     Each of the directors named above has been engaged in the principal
occupation 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. Canfield, who in 1998 was Chairman, BC TELECOM Inc. and
BC TEL, and who from 1993 to 1997 was Chief Executive Officer and Chairman, BC
TELECOM Inc. and BC TEL; Mr. Davies, who in 1999 and prior thereto was Senior
Vice President, Corporate Affairs, Royal Bank of Canada; Mr. Ferguson, who from
1996 to 1998 was also Chief Executive Officer, Princeton Developments Ltd., in
addition to his current position as Chairman, Princeton Developments Ltd.; Mr.
Huff, who in 1998 and prior thereto was also President, Oceaneering
International, Inc., in addition to his current position as Chairman and Chief
Executive Officer, Oceaneering International, Inc.; Mr. Shaw, who in 1998 and
prior thereto was Chairman and Chief Executive Officer of Shaw Communications
Inc.; 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, 2000 and as of the date
hereof.

<TABLE>
<CAPTION>
NAME AND MUNICIPALITY OF RESIDENCE                     OFFICE(1)
- ----------------------------------                     ---------
<S>                                                    <C>
W. ROBERT WYMAN................................        Chairman of the Board
West Vancouver, British Columbia

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

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

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

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

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

BARRY D. STEWART...............................        Executive Vice President, In-situ and International Oil
Calgary, Alberta

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

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

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

JANICE B. ODEGAARD.............................        Assistant Secretary
Calgary, Alberta
</TABLE>


                                                                              44
<PAGE>

Note:

(1)  The principal occupation of each officer is the specified office with
     Suncor, with the exception of Ms. Odegaard, who is also Corporate Director,
     Legal Affairs, of Suncor.

     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. Wyman, who is a non-executive Chairman of Suncor.

     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 Secretary, Suncor Energy Inc., Box 38, 112 - 4 Avenue
S.W., Calgary, Alberta, T2P 2V5, telephone 403-269-8709:

(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 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.


                                                                            45
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-1
<SEQUENCE>2
<FILENAME>a2042188zex-1.txt
<DESCRIPTION>EXHIBIT 1
<TEXT>

<PAGE>

                                    EXHIBIT 1


<PAGE>

                               SUNCOR ENERGY INC.

                         2000 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
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>
- -------------------------------------------------------------------------------------------------------------------------------
                                                                2000                    1999                      1998
- -------------------------------------------------------------------------------------------------------------------------------
(Canadian $ millions)                                       CDN          US          CDN         US            CDN        US
- -------------------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>         <C>          <C>        <C>           <C>        <C>

REVENUES
  Sales & other operating revenues (1)                      3,385       3,481        2,383      2,448         2,068      2,107
  Interest                                                      3           3            4          4             2          2
- -------------------------------------------------------------------------------------------------------------------------------
                                                            3,388       3,484        2,387      2,452         2,070      2,109
- -------------------------------------------------------------------------------------------------------------------------------
EXPENSES
  Purchases of crude oil and products                         807         807          519        519           366        366
  Operating, selling and general (1) (2) (3)                  918       1,036          774        791           698        785
  Exploration                                                  53          53           40         40            40         40
  Royalties                                                   199         199           99         99            78         78
  Taxes other than income taxes                               361         361          334        334           325        325
  Depreciation, depletion & amortization (4)                  365         372          318        318           264        264
  Gain on disposal of assets                                 (148)       (148)         (34)       (34)           (6)        (6)
  Write down of oil shale assets (5)                          125         244            -          -             -          -
  Restructuring                                                65          65            -          -             -          -
  Start-up expenses - Project Millennium (6)                   15          14            -          1             -          -
  Start-up expenses - Other (6)                                 -         (13)           -         31             -          -
  Interest (4)                                                  8          40           26         59            24         24
- -------------------------------------------------------------------------------------------------------------------------------
                                                            2,768       3,030        2,076      2,158         1,789      1,876
- -------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES                                  620         454          311        294           281        233
- -------------------------------------------------------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES
  Current
      Income taxes on earnings                                 45          45           29         29            (3)        (3)
      Income tax refund                                         -           -            -          -           (16)       (16)
- -------------------------------------------------------------------------------------------------------------------------------
                                                               45          45           45         29           (19)       (19)
- -------------------------------------------------------------------------------------------------------------------------------
  Future
      Income taxes on earnings (2) (4) (5) (6) (7)            198         138           96         87           117         98
      Income tax refund                                         -           -            -          -             5          5
- -------------------------------------------------------------------------------------------------------------------------------
                                                              198         138           96         87           122        103
- -------------------------------------------------------------------------------------------------------------------------------
                                                              243         183          125        116           103         84
- -------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS                                                  377         271          186        178           178        149
  Dividends on preferred securities (4)                       (26)          -          (22)         -             -          -
- -------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS              351         271          164        178           178        149
Other comprehensive income, net of tax
  Minimum pension liability (8)                               N/A          (2)         N/A          6           N/A         (6)
- -------------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME                                          N/A         269          N/A        184           N/A        143
- -------------------------------------------------------------------------------------------------------------------------------
PER COMMON SHARE
NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
  Basic                                                      1.58        1.22         0.74       0.81          0.81       0.68
  Diluted                                                    1.57        1.21         0.73       0.80          0.80       0.67
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>

* Per share calculations, for both current and prior years, reflect a
two-for-one split of the company' common shares during 1998 and 2000.

                                                                               2
<PAGE>

<TABLE>
<CAPTION>
                                                            AS AT                              as at
                                                      DECEMBER 31, 2000                  December 31, 1999
                                                    (CANADIAN $ MILLIONS)              (Canadian $ millions)
                                                    AS               U.S.              As               U.S.
                                                 REPORTED            GAAP           reported            GAAP
                                                ----------        ----------       ----------        ----------
<S>                                             <C>               <C>              <C>               <C>
Current assets (8)                                    665               666              457               457
Capital assets, net (4) (5) (6)                     5,883             5,768            4,528             4,503
Deferred charges and other (4)                        166               173              191               205
Future income taxes (4) (6) (7) (8)                   119               125                -                 -
                                                ----------        ----------       ----------        ----------
Total assets                                        6,833             6,732            5,176             5,165
                                                ==========        ==========       ==========        ==========

Current liabilities                                   837               837              710               710
Long-term borrowings (4)                            2,192             2,716            1,306             1,830
Accrued liabilities and other (3) (8)                 252               277              236               236

Future income taxes (5) (7)                         1,080             1,042              816               736

Equity:
  Share capital and retained earnings (4)           2,472             1,862            2,108             1,653
  Accumulated other comprehensive
  Income (8)                                          N/A                (2)             N/A                 -
                                                ----------        ----------       ----------        ----------
                                                    2,472             1,860            2,108             1,653
                                                ==========        ==========       ==========        ==========
Total liabilities and
  shareholders' equity                              6,833             6,732            5,176             5,165
                                                ==========        ==========       ==========        ==========
</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 2000 "Sales and other operating
     revenues" and "Operating, selling and general" expenses by $96 million
     (1999 - $65 million; 1998 - $39 million).


                                                                               3
<PAGE>

(2)  The company is a party to certain off-balance-sheet derivative financial
     instruments, such as crude oil, natural gas and foreign currency swap
     contracts, in respect of future firmly committed and anticipated sales
     transactions. Under Canadian GAAP, foreign currency swap contracts qualify,
     and are accounted for, as hedges of these future transactions. Under U.S.
     GAAP, foreign currency swap contracts used to hedge foreign currency
     exposure to anticipated, but not firmly committed, transactions cannot be
     accounted for as hedges under SFAS No. 52, "Foreign Currency Translation".

     Accordingly, for reporting under U.S. GAAP, gains or losses resulting from
     changes in the market value of foreign currency swap contracts related to
     these anticipated transactions are recognized in earnings when those
     changes in market value occur.

     At December 31, 2000, there were no foreign currency swap contracts
     outstanding to hedge foreign currency exposure to anticipated transactions
     and, therefore, no impact on net earnings.

     As at December 31, 1999, the market value of such contracts was nil
     therefore, the loss recognized in 1998 was reversed. This 1998 loss
     reversal resulted in an increase in 1999 net earnings of $29 million after
     future income taxes of $19 million (1998 - net earnings decreased by $29
     million after future income tax recoveries of $19 million).

(3)  Under U.S. GAAP (APB 25, "Accounting for Stock Issued to Employees"),
     compensation expense is also recorded, over the same vesting period, for
     the portion of these awards payable in common shares.

     The impact of this GAAP difference is to decrease 2000 net earnings by $22
     million (1999 and 1998 - $ nil). Since the common shares awarded under
     these plans are to be issued from treasury, the income tax impact on the
     company is nil.

     STOCK-BASED COMPENSATION

     The company applies APB Opinion 25 in accounting for common share options
     granted to non-employee directors and certain executives. Accordingly, no
     compensation cost has been recognized in the consolidated statements of
     earnings. Had compensation cost been determined on the basis of fair values
     in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation",
     2000 net earnings would have been lower by $7 million ($0.03 per common
     share), 1999 net earnings would have been lower by $5 million ($0.02 per
     common share) and 1998 net earnings would have been lower by $3 million
     ($0.03 per common share).

(4)  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 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.


                                                                               4
<PAGE>

     This difference in classification decreased 2000 net earnings by $31
     million after income tax recoveries of $23 million (1999 net earnings
     decreased $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
     2000 net earnings of $9 million after future income taxes of $6 million
     (1999 net earnings increased $2 million after future income taxes of $2
     million).

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

     Under Canadian GAAP, the 2000 interest distributions of $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
     amortization of issue costs of $7 million are classified as operating
     activities.

(5)  In 2000, the company recorded an impairment write down of the carrying
     value of the Stuart oil shale project to its net recoverable amount, which
     under Canadian GAAP is its 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"), an impairment loss is
     measured based on the fair value of the asset, which in the case of the oil
     shale project is its estimated net cash flows, but calculated on a
     discounted basis.

     The impact of this GAAP difference is to decrease 2000 net earnings by $64
     million, after income tax recoveries of $55 million.

(6)  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 2000:

     o    Certain 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.

     These differences increased 2000 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).

(7)  In December 2000, the Canadian Federal Department of Finance released draft
     legislation that merged federal budget proposals announced earlier in the
     year. Under Canadian GAAP, the budget proposals are considered
     substantially enacted. Accordingly, future income tax assets and
     liabilities have been 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 on temporary differences are only after
     they have been signed into law.


                                                                               5
<PAGE>

     The impact of this GAAP difference was to decrease 2000 net earnings by $6
million (1999 and 1998 - nil).

     At December 31, 2000, future income taxes, under Canadian and U.S. GAAP,
are comprised of the following:

<TABLE>
<CAPTION>
                                                      AS REPORTED                         U.S. GAAP
     ($ millions)                              CURRENT         NON-CURRENT        CURRENT         NON-CURRENT
                                             ------------      ------------     ------------      ------------
     <S>                                     <C>               <C>              <C>               <C>
     Future income tax assets:
          Employee future benefits                   2                39                2                41
          Reclamation and environmental
            remediation costs                        9                23                9                24
          Royalties                                  -                43                -                43
          Employee incentive plans                   -                 4                -                10
          Inventories                               20                 -               21                 -
          Other                                     14                10               14                 -
                                             ------------      ------------     ------------      ------------
                                                    45               119               46               125
                                             ============      ============     ============      ============

     Future income tax liabilities
          Depreciation                               -             1,038                -               992
          Overburden removal costs                   -                23                -                23
          Maintenance shutdown costs                 -                12                -                12
          Other                                      9                 7                9                15
                                             ============      ============     ============      ============
                                                     9             1,080                9             1,042
                                             ============      ============     ============      ============
</TABLE>


(8)  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, 2000, an additional minimum pension liability of $3 million
     and other comprehensive income of $2 million, net of income tax recoveries
     of $1 million, was recognized. At December 31, 2000, unamortized
     liabilities arising from plan amendments were nil.

     At December 31, 1999, the accumulated benefit obligation did not exceed the
     fair value of plan assets and accrued pension costs otherwise recorded.
     Accordingly, as at December 31, 1999 the additional minimum pension
     liability and related intangible asset recognized at


                                                                               6

<PAGE>

     December 31, 1998 was adjusted to nil, and other comprehensive income of $6
     million, net of income taxes of $4 million, was recognized.

EMPLOYEE FUTURE BENEFITS

     Effective January 1, 2000, the company adopted new Canadian accounting
     recommendations with respect to accounting for the costs of employee future
     benefits. The new recommendations were applied in a manner that produced
     recognized and unrecognized amounts for all of its benefit plans the same
     as those determined by the application of U.S. GAAP (SFAS No. 87,
     "Employers Accounting for Pensions; SFAS No. 106, "Employers' Accounting
     for Post-Retirement Benefits Other than Pensions" and SFAS No. 112,
     "Accounting for Post-Employment Benefits").

     For Canadian reporting, the new recommendations were adopted retroactively
     and financial statements of prior periods were restated to give effect to
     them. Accordingly, for U.S. reporting, comparative figures have also been
     restated to reflect the fact that GAAP differences previously reported no
     longer apply.

RECENTLY ISSUED ACCOUNTING STANDARDS

DERIVATIVE FINANCIAL INSTRUMENTS

     Effective January 1, 2001, the company will adopt SFAS 133 Accounting for
     Derivative Instruments and Hedging Activities, as amended by SFAS 138,
     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 changes in the
     fair value of the derivative and of the hedged item attributable to the
     hedged risk are recognized in earnings. 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 realized.
     Ineffective portions of changes in the fair value and the cash flow hedges
     are recognized in earnings, immediately.

     The adoption of SFAS 133 is expected to result in a decrease in OCI of $173
     million, net of future income tax recoveries of $87 million and an increase
     in 2001 U.S. GAAP earnings of $47 million net of future income taxes of $28
     million. Assets are expected to increase by $89 million and liabilities are
     expected to increase by $274 million as a result of recording all
     derivative instruments on the consolidated Balance Sheet at fair value.
     Implementation of this accounting standard will not affect the company's
     cash flow 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.


                                                                               7

<PAGE>

COSTS INCURRED

<TABLE>
<CAPTION>
                                                                                  COSTS INCURRED
                                                                                FOR THE YEARS ENDED
                                                                                   DECEMBER 31,
                                                                      --------------------------------------
                                                                      2000             1999             1998
                                                                      ----             ----             ----
                                                                                   ($ MILLIONS)
<S>                                                                   <C>          <C>                  <C>
Property acquisition costs
  Proved properties..............................................       5                 -                -
  Unproved properties............................................      10                48               24
Exploration costs................................................      40                64               92
Development costs................................................      69                70              123
                                                                      ---               ---              ---
                                                                      124               182              239
                                                                      ===               ===              ===
</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,
                                                                         --------------------------------------
                                                                         2000             1999             1998
                                                                         ----             ----             ----
                                                                                      ($ MILLIONS)
<S>                                                                      <C>          <C>                  <C>
 Revenues
   Sales to unaffiliated customers..................................      139               97               80
   Transfers to other operations....................................      183              153              167
                                                                         ----             ----             ----
                                                                          322              250              247
                                                                         ----             ----             ----
 Expenses
   Production costs.................................................       47               63               64
   Depreciation, depletion and amortization.........................       68               76               74
   Exploration......................................................       63               52               50
   Gain on disposal of assets.......................................     (147)             (36)              (4)
   Restructuring costs..............................................       65                -                -
                                                                         ----             ----             ----
   Other related costs..............................................       25               21               18
                                                                         ----             ----             ----
                                                                          121              176              202
                                                                         ----             ----             ----
 Operating profit before income taxes...............................      201               74               45
 Related income taxes...............................................     (103)             (33)             (21)
                                                                         ----             ----             ----
 Results of operations from Natural Gas.............................       98               41               24
                                                                         ====             ====             ====
</TABLE>

     The information noted above does not totally agree to the segmented
     information on page 48 of the company's annual report due to different
     classification of revenues and expenses,

<TABLE>
<CAPTION>
                                                                               RESULTS OF OPERATIONS FOR
                                                                                OIL AND GAS PRODUCTION
                                                                                  FOR THE YEARS ENDED
                                                                                     DECEMBER 31,
                                                                         --------------------------------------
                                                                         2000             1999             1998
                                                                         ----             ----             ----
                                                                                     ($ MILLIONS)
<S>                                                                      <C>         <C>                   <C>
Revenues
  Sales to unaffiliated customers...................................      139               97               80
  Transfers to other operations.....................................      183              153              167
                                                                         ----             ----             ----
                                                                          322              250              247
                                                                         ----             ----             ----
Expenses
  Production costs..................................................       47               63               64
  Depreciation, depletion and amortization..........................       68               76               74
  Exploration.......................................................       63               52               50
  Gain on disposal of assets........................................     (147)             (36)              (4)
  Restructuring costs...............................................       65                -                -
                                                                         ----             ----             ----
  Other related costs...............................................       25               21               18
                                                                         ----             ----             ----
                                                                          121              176              202
                                                                         ----             ----             ----
Operating profit before income taxes................................      201               74               45
Related income taxes................................................     (103)             (33)             (21)
                                                                         ----             ----             ----
Results of operations from Natural Gas..............................       98               41               24
                                                                         ====             ====             ====
</TABLE>


                                                                               8
<PAGE>

<TABLE>
<CAPTION>
                                                                               RESULTS OF OPERATIONS FOR
                                                                                OIL AND GAS PRODUCTION
                                                                                  FOR THE YEARS ENDED
                                                                                     DECEMBER 31,
                                                                         --------------------------------------
                                                                         2000             1999             1998
                                                                         ----             ----             ----
                                                                                      ($ MILLIONS)
<S>                                                                      <C>              <C>              <C>
Revenues
  Sales to unaffiliated customers..................................       139               97               80
  Transfers to other operations....................................       183              153              167
                                                                         ----             ----             ----
                                                                          322              250              247
                                                                         ----             ----             ----
Expenses
  Production costs.................................................        47               63               64
  Depreciation, depletion and amortization.........................        68               76               74
  Exploration......................................................        63               52               50
  Gain on disposal of assets.......................................      (147)             (36)              (4)
  Restructuring costs..............................................        65                -                -
                                                                         ----             ----             ----
  Other related costs..............................................        25               21               18
                                                                         ----             ----             ----
                                                                          121              176              202
                                                                         ----             ----             ----
Operating profit before income taxes...............................       201               74               45
Related income taxes...............................................      (103)             (33)             (21)
                                                                         ----             ----             ----
Results of operations from Natural Gas.............................        98               41               24
                                                                         ====             ====             ====
</TABLE>

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.
     Figures are based on year-end commodity prices.

     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, 2000, 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, 2000, 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".


                                                                               9
<PAGE>

<TABLE>
<CAPTION>
                                                                             2000             1999             1998
                                                                            ------           ------           ------
                                                                                          ($ MILLIONS)

<S>                                                                           <C>         <C>                 <C>
Future cash inflows.....................................................     8,176            3,272            3,382
Future production and development costs.................................      (633)          (1,053)          (1,183)
Other related future costs..............................................      (175)            (133)            (139)
Future income tax expenses..............................................    (3,426)            (789)            (637)
                                                                            ------           ------           ------
Future net cash flows...................................................     3,942            1,297            1,423
Discount at 10%.........................................................    (2,009)            (548)            (626)
                                                                            ------           ------           ------
Standardized measure of discounted future net cash flows from
estimated production of proved oil and gas reserves after
income taxes............................................................     1,933              749              797
                                                                            ======           ======           ======
</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>
                                                                             2000             1999             1998
                                                                            ------           ------           ------
                                                                                          ($ MILLIONS)
<S>                                                                           <C>         <C>                 <C>
Balance, beginning of year..............................................       749              797              678
Increase (decrease) in discounted future net cash flows:
  Sales and transfers of oil and gas net of related costs...............      (275)            (192)            (187)
  Revisions to estimates of proved reserves:
     Prices.............................................................     3,886              458               69
     Development costs..................................................        (3)             (68)             (75)
     Production costs...................................................        55              (25)             (26)
     Quantities.........................................................      (363)            (175)             (19)
     Other..............................................................      (237)             (81)              (6)
  Extensions, discoveries, and improved recovery less related costs.....       177               46              168
  Development costs incurred during the period..........................        69               70              123
  Purchases of reserves in place........................................        41                -                -
  Sales of reserves in place............................................      (989)            (130)             (13)
  Accretion of discount.................................................       115              113              100
  Income taxes..........................................................    (1,292)             (64)             (15)
                                                                            ------           ------           ------
Balance, end of year....................................................     1,933              749              797
                                                                            ======           ======           ======
</TABLE>


                                                                              10
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-2
<SEQUENCE>3
<FILENAME>a2042188zex-2.txt
<DESCRIPTION>EXHIBIT 2
<TEXT>

<PAGE>

                                  EXHIBIT 2
<PAGE>

MANAGEMENT'S STATEMENT ON
FINANCIAL REPORTING

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

The financial statements on pages 56 to 77 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 which 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 56 to 58 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 six 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
interim financial statements prior to their 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 their
approval to the Board of Directors.


/s/ Richard L. George                             /s/ Michael W. O'Brien
- ---------------------                             ------------------------------
RICHARD L. GEORGE                                 MICHAEL W. O'BRIEN
President and                                     Executive Vice President Chief
Executive Officer                                 and Chief Financial Officer
January 18, 2001


54 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

AUDITORS' REPORT

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

To the Shareholders of Suncor Energy Inc:

We have audited the consolidated balance sheets of Suncor Energy Inc. as at
December 31, 2000, 1999 and 1998 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,
2000, 1999 and 1998 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 LLP
- ------------------------------
PRICEWATERHOUSECOOPERS LLP
Chartered Accountants
Calgary, Alberta January 18, 2001


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 55
<PAGE>

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Suncor Energy Inc. is an integrated Canadian energy company, whose three
operating segments are 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 and transportation of natural gas and crude oil in Canada and the
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 company's oil shale project in Queensland, Australia, is currently
being treated as a Corporate project for segmented reporting purposes.

     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 Form 40-F
report, 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

The company deems production from its oil sands plant, excluding diesel sales
and synthetic crude oil sales under long-term agreements, as well as its
conventional crude oil production to be used first for internal refinery
consumption. The company also deems a portion of its natural gas production
to be sold to Sunoco for resale to its natural gas customers. Therefore, on
consolidation, revenues from these deemed 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)  CAPITAL ASSETS

COST

Capital assets 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 following policy.

     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.


56 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 capital assets. Capitalization of
interest ceases when the capital asset is substantially complete and ready
for productive use.

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 capital assets and 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:

Capital assets 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 capital assets as follows:

(i)   mobile equipment over three to 20 years;

(ii)  mine equipment and acquisition costs of original leases #86 and #17 over
      approximately 17 million barrels of proved reserves;

(iii) plant and other capital assets, including new leases, primarily over 10 to
      40 years.

NATURAL GAS:

Unproved properties whose acquisition costs are individually significant are
evaluated for impairment by management. Impairment of unproved properties
whose 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 capital assets 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 operation, 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

Capital assets 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 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 capital assets are generally recognized in
earnings. For oil and gas capital assets, 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 which 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 and oil shale for
mining, including depreciation on overburden removal equipment where
applicable, are deferred. These costs are amortized based on the amount of
oil sands and oil shale mined in the year, the ratio of total overburden to
be removed to total reserves of oil sands and oil shale 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 which varies from
two to seven years. Normal maintenance and repair costs are charged to
expense as incurred.

     Oil sands preproduction costs are amortized on a unit of production
basis over the life of proved producing reserves.


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 57
<PAGE>

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(f)  EMPLOYEE FUTURE BENEFITS

The company has employee future benefit programs as follows:

- -    a defined benefit pension plan 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

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

- -    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
ratably 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 a 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 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 oil shale project in Australia is integrated with the
company's other activities and is 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 which 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.

58 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                             CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF EARNINGS

<TABLE>
<CAPTION>
                                                    for the years ended December 31
- -----------------------------------------------------------------------------------
($ millions)                                              2000      1999      1998
- -----------------------------------------------------------------------------------
<S>                                                      <C>       <C>       <C>
REVENUES

   Sales and other operating revenues (notes 5 and 7)    3 385     2 383     2 068
   Interest                                                  3         4         2
- -----------------------------------------------------------------------------------
                                                         3 388     2 387     2 070
- -----------------------------------------------------------------------------------
EXPENSES
   Purchases of crude oil and products                     807       519       366
   Operating, selling and general (note 13)                918       774       698
   Exploration (note 5)                                     53        40        40
   Royalties (note 4)                                      199        99        78
   Taxes other than income taxes (note 5)                  361       334       325
   Depreciation, depletion and amortization                365       318       264
   Gain on disposal of assets                             (148)      (34)       (6)
   Write-down of oil shale assets (note 2)                 125        --        --
   Restructuring (note 3)                                   65        --        --
   Start-up expenses - Project Millennium (note 9)          15        --        --
   Interest (note 5)                                         8        26        24
- -----------------------------------------------------------------------------------
                                                         2 768     2 076     1 789
- -----------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES                               620       311       281
- -----------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES (note 6)
   Current
      Income taxes on earnings                              45        29        (3)
      Income tax refund                                     --        --       (16)
- -----------------------------------------------------------------------------------
                                                            45        29       (19)
- -----------------------------------------------------------------------------------
   Future
      Income taxes on earnings                             198        96       117
      Income tax refund                                     --        --         5
- -----------------------------------------------------------------------------------
                                                           198        96       122
- -----------------------------------------------------------------------------------
                                                           243       125       103
- -----------------------------------------------------------------------------------
NET EARNINGS                                               377       186       178
Dividends on preferred securities (note 16)                (26)      (22)       --
- -----------------------------------------------------------------------------------
Net earnings attributable to common shareholders           351       164       178
- -----------------------------------------------------------------------------------
PER COMMON SHARE (dollars) (note 17)
Net earnings attributable to common shareholders

- - basic                                                   1.58      0.74      0.81
- - diluted                                                 1.57      0.73      0.80
- -----------------------------------------------------------------------------------

Cash dividends                                            0.34      0.34      0.34
- -----------------------------------------------------------------------------------
</TABLE>

See accompanying summary of accounting policies and notes.


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 59
<PAGE>

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                   as at December 31
- ------------------------------------------------------------------------------------
($ millions)                                               2000      1999      1998
- ------------------------------------------------------------------------------------
<S>                                                       <C>       <C>       <C>
ASSETS
  CURRENT ASSETS
    Cash and cash equivalents                                21         5        26
    Accounts receivable (notes 5 and 7)                     407       277       190
    Current income taxes                                     --        --        10
    Future income taxes (note 6)                             45        14        --
    Inventories (note 8)                                    192       161       175
- ------------------------------------------------------------------------------------
  Total current assets                                      665       457       401
  Capital assets, net (note 9)                            5 883     4 528     3 504
  Deferred charges and other (note 10)                      166       191       199
  Future income taxes (note 6)                              119        --        --
- ------------------------------------------------------------------------------------
Total assets                                              6 833     5 176     4 104
- ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
  CURRENT LIABILITIES
    Short-term borrowings                                    64        32        16
    Accounts payable                                        424       277       125
    Accrued liabilities (notes 13 and 14)                   285       339       169
    Income taxes payable                                     15        15        --
    Future income taxes (note 6)                              9        --        --
    Taxes other than income taxes                            39        46        59
    Current portion of long-term borrowings (note 11)         1         1         1
- ------------------------------------------------------------------------------------
  Total current liabilities                                 837       710       370
- ------------------------------------------------------------------------------------
  Long-term borrowings (notes 11 and 12)                  2 192     1 306     1 298
  Accrued liabilities and other (notes 13 and 14)           252       236       194
  Future income taxes (note 6)                            1 080       816       743

  Commitments and contingencies (note 15)

  SHAREHOLDERS' EQUITY

    Preferred securities (note 16)                          514       514        --
    Share capital (note 17)                                 537       524       518
    Retained earnings                                     1 421     1 070       981
- ------------------------------------------------------------------------------------
    Total shareholders' equity                            2 472     2 108     1 499
- ------------------------------------------------------------------------------------
    Total liabilities and shareholders' equity            6 833     5 176     4 104
- ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------
</TABLE>

See accompanying summary of accounting policies and notes.

Approved on behalf of the Board:

/s/ R.L. George                       /s/ R.W. Korthals
- --------------------                  -----------------------
R.L. George, Director                 R.W. Korthals, Director


60 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                               CONSOLIDATED FINANCIAL STATEMENTS


CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                 for the years ended December 31

- ------------------------------------------------------------------------------------------------
($ millions)                                                      2000        1999        1998
- ------------------------------------------------------------------------------------------------
<S>                                                             <C>         <C>           <C>
OPERATING ACTIVITIES
Cash flow provided from operations (1), (2)                        958         591         580
Decrease (increase) in operating working capital
  Accounts receivable (note 5)                                    (130)       (101)         77
  Inventories                                                      (31)         14         (16)
  Accounts payable and accrued liabilities                          93         322        (114)
  Taxes payable                                                     18          12         (14)
- ------------------------------------------------------------------------------------------------
Cash provided from operating activities                            908         838         513
- ------------------------------------------------------------------------------------------------
CASH USED IN INVESTING ACTIVITIES (2)                           (1 607)     (1 290)       (937)
- ------------------------------------------------------------------------------------------------
NET CASH DEFICIENCY BEFORE FINANCING ACTIVITIES                   (699)       (452)       (424)
- ------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Increase (decrease) in short-term borrowings                        32          16         (20)
Issuance of preferred securities (note 16)                          --         507          --
Stuart Oil Shale Project borrowings                                 --          11          49
Repayment of commercial paper borrowings (note 16)                  --        (507)         --
Repayment of 12% debentures, Series A                               --          --         (55)
Net increase in other long-term borrowings                         792         510         533
Issuance of common shares under stock option plan (note 17)          9           6           5
Dividends paid on preferred securities (3) (note 16)               (47)        (37)         --
Dividends paid on common shares                                    (71)        (75)        (75)
- ------------------------------------------------------------------------------------------------
Cash provided from financing activities                            715         431         437
- ------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                    16         (21)         13
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR                       5          26          13
- ------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR                            21           5          26
- ------------------------------------------------------------------------------------------------
PER COMMON SHARE (dollars) (note 17)

(1) Cash flow provided from operations                            4.32        2.68        2.64
(3) Dividends paid on preferred securities (pre-tax)              0.21        0.17          --
- ------------------------------------------------------------------------------------------------
    Cash flow provided from operations after deducting
    dividends paid on preferred securities                        4.11        2.51        2.64
- ------------------------------------------------------------------------------------------------
(2) See Schedules of Segmented Data on pages 64 and 65
- ------------------------------------------------------------------------------------------------
</TABLE>
See accompanying summary of 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, 1997                                                --         513         878
Net earnings                                                        --          --         178
Dividends paid on common shares                                     --          --         (75)
Issued for cash under stock option plan                             --           4          --
Issued under dividend reinvestment plan                             --           1          --
- ------------------------------------------------------------------------------------------------
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 16)                         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 (note 1)                      --          --          75
- ------------------------------------------------------------------------------------------------
AT DECEMBER 31, 2000                                               514         537       1 421
- ------------------------------------------------------------------------------------------------
</TABLE>
See accompanying summary of accounting policies and notes.


                                       SUNCOR ENERGY INC. 2000 ANNUAL REPORT  61
<PAGE>

CONSOLIDATED FINANCIAL STATEMENTS


SCHEDULES OF SEGMENTED DATA*
<TABLE>
<CAPTION>
                                                                                               for the years ended December 31

- ------------------------------------------------------------------------------------------------------------------------------
                                                Oil Sands                    Natural Gas                     Sunoco
($ millions)                            2000      1999      1998      2000      1999      1998      2000      1999      1998
- ------------------------------------------------------------------------------------------------------------------------------
<S>                                    <C>       <C>       <C>        <C>       <C>       <C>      <C>       <C>        <C>
EARNINGS
REVENUES**
Sales and other
  operating revenues                     544       461       421       237       143       114     2 604     1 779     1 533
Intersegment revenues***                 792       428       347       191       163       176        --        --        --
Interest                                  --        --        --        --        --        --        --        --        --
- ------------------------------------------------------------------------------------------------------------------------------
                                       1 336       889       768       428       306       290     2 604     1 779     1 533
- ------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Purchases of crude oil and products        3         6        10        --        --        --     1 783     1 090       845
Operating, selling and general           467       369       341        74        88        86       310       270       263
Exploration                               --        --        --        53        40        40        --        --        --
Royalties                                 98        51        43       101        48        35        --        --        --
Taxes other than income taxes             12         9         7         3         5         5       345       320       313
Depreciation, depletion
  and amortization                       232       177       128        78        87        84        54        53        51
(Gain) loss on disposal of assets         --         2        (1)     (147)      (36)       (5)       (1)       --        --
Write-down of oil shale assets            --        --        --        --        --        --        --        --        --
Restructuring                             --        --        --        65        --        --        --        --        --
Start-up expenses -
  Project Millennium                      15        --        --        --        --        --        --        --        --
Interest                                  --        --        --        --        --        --        --        --        --
- ------------------------------------------------------------------------------------------------------------------------------
                                         827       614       528       227       232       245     2 491     1 733     1 472
- ------------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE
  INCOME TAXES                           509       275       240       201        74        45       113        46        61
Income taxes                            (194)     (108)      (95)     (103)      (33)      (21)      (32)      (19)      (24)
- ------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)                      315       167       145        98        41        24        81        27        37
- ------------------------------------------------------------------------------------------------------------------------------

As at December 31

TOTAL ASSETS                           5 079     3 178     2 081       762       962       943       911       849       874
- ------------------------------------------------------------------------------------------------------------------------------
CAPITAL EMPLOYED****                   1 412     1 352     1 242       412       727       772       386       405       499
- ------------------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
  CAPITAL EMPLOYED (%)****              22.8      12.9      16.3      17.2       5.5       3.3      20.5       6.0       7.4
- ------------------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
  CAPITAL EMPLOYED (%)*****             10.6       9.2      11.6      17.2       5.5       3.3      20.5       6.0       7.4
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>

*      The company currently has no foreign geographic segments. See note 5
       for information on export sales. Accounting policies for segments are
       the same as those described in the Summary of Significant Accounting
       Policies.

**     Two customers in the Oil Sands segment in 2000 represented 10% or more
       ($493 million and $355 million) of the company's 2000 consolidated
       revenues (1999 - one customer represented 10% or more ($281 million);
       1998 none).

***    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. Long-term borrowings are recorded mainly in the Corporate
       segment.

*****  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 accounting policies and notes.


62  SUNCOR ENERGY INC. 2000 ANNUAL REPORT

<PAGE>

                                               CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
                                       Corporate and eliminations              Total
($ millions)                            2000      1999      1998      2000      1999      1998
- ------------------------------------------------------------------------------------------------
<S>                                     <C>       <C>       <C>      <C>       <C>       <C>
EARNINGS
REVENUES**
Sales and other
  operating revenues                      --        --        --     3 385     2 383     2 068
Intersegment revenues***                (983)     (591)     (523)       --        --        --
Interest                                   3         4         2         3         4         2
- ------------------------------------------------------------------------------------------------
                                        (980)     (587)     (521)    3 388     2 387     2 070
- ------------------------------------------------------------------------------------------------
EXPENSES
Purchases of crude oil and products     (979)     (577)     (489)      807       519       366
Operating, selling and general            67        47         8       918       774       698
Exploration                               --        --        --        53        40        40
Royalties                                 --        --        --       199        99        78
Taxes other than income taxes              1        --        --       361       334       325
Depreciation, depletion
  and amortization                         1         1         1       365       318       264
(Gain) loss on disposal of assets         --        --        --      (148)      (34)       (6)
Write-down of oil shale assets           125        --        --       125        --        --
Restructuring                             --        --        --        65        --        --
Start-up expenses -
  Project Millennium                      --        --        --        15        --        --
Interest                                   8        26        24         8        26        24
- ------------------------------------------------------------------------------------------------
                                        (777)     (503)     (456)    2 768     2 076     1 789
- ------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE
  INCOME TAXES                          (203)      (84)      (65)      620       311       281
Income taxes                              86        35        37      (243)     (125)     (103)
- ------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)                     (117)      (49)      (28)      377       186       178
- ------------------------------------------------------------------------------------------------

As at December 31

TOTAL ASSETS                              81       187       206     6 833     5 176     4 104
- ------------------------------------------------------------------------------------------------
CAPITAL EMPLOYED****                      22      (121)      (72)    2 232     2 363     2 441
- ------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
  CAPITAL EMPLOYED (%)****                                            16.6       8.3       9.5
- ------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
  CAPITAL EMPLOYED (%)*****               --        --        --       9.3       6.4       7.6
- ------------------------------------------------------------------------------------------------
</TABLE>


                                       SUNCOR ENERGY INC. 2000 ANNUAL REPORT  63
<PAGE>

CONSOLIDATED FINANCIAL STATEMENTS


SCHEDULES OF SEGMENTED DATA*
<TABLE>
<CAPTION>
                                                                                               for the years ended December 31

- --------------------------------------------------------------------------------------------------------------------------------
                                                  Oil Sands                    Natural Gas                     Sunoco
($ millions)                              2000      1999      1998      2000      1999      1998      2000      1999      1998
- --------------------------------------------------------------------------------------------------------------------------------
<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)                      315       167       145        98        41        24        81        27        37
  Exploration expenses
    Cash                                    --        --        --        12        12        16        --        --        --
    Dry hole costs                          --        --        --        41        28        24        --        --        --
  Non-cash items included
    in earnings
    Depreciation, depletion
      and amortization                     232       177       128        78        87        84        54        53        51
    Future income taxes                    189       102        76       101        31        14       (16)      (33)       13
    Current income tax provision
      allocated to Corporate                 5         6        19         2         2         7        48        52        11
    (Gain) loss on disposal of assets       --         2        (1)     (147)      (36)       (5)       (1)       --        --
    Write-down of oil shale assets          --        --        --        --        --        --        --        --        --
    Restructuring                           --        --        --        56        --        --        --        --        --
    Other                                  (12)       --        (4)       (4)        6         3         6         3         1
  Overburden removal outlays               (48)      (53)      (46)       --        --        --        --        --        --
  Overburden removal outlays -
    Project Millennium                     (27)       --        --        --        --        --        --        --        --
  Increase (decrease) in deferred
    credits and other                        1         4         3         1         1        --         2         1        (1)
- --------------------------------------------------------------------------------------------------------------------------------
Total cash flow provided from
  (used in) operations                     655       405       320       238       172       167       174       103       112
Decrease (increase) in operating
  working capital                         (169)       83        (8)       27        27       (13)       40        69         7
- --------------------------------------------------------------------------------------------------------------------------------
Total cash provided from (used in)
  operating activities                     486       488       312       265       199       154       214       172       119
- --------------------------------------------------------------------------------------------------------------------------------
CASH PROVIDED FROM (USED IN)
  INVESTING ACTIVITIES:
Capital and exploration
  expenditures                          (1 808)   (1 057)     (507)     (127)     (200)     (242)      (45)      (42)      (60)
Deferred maintenance
  shutdown expenditures                     (3)      (22)       (7)       (1)       --        (1)       (9)       --        (2)
Deferred outlays and
  other investments                         (5)       (7)       (1)       --        --         1        (7)       (2)       (3)
Proceeds from disposals                    101         1         1       314        90         9         2         1         1
- --------------------------------------------------------------------------------------------------------------------------------
Total cash provided from (used in)
  investing activities                  (1 715)   (1 085)     (514)      186      (110)     (233)      (59)      (43)      (64)
- --------------------------------------------------------------------------------------------------------------------------------
NET CASH SURPLUS (DEFICIENCY)
  BEFORE FINANCING ACTIVITIES           (1 229)     (597)     (202)      451        89       (79)      155       129        55
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>

*  The company currently has no foreign geographic segments. See note 5 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 accounting policies and notes.


64  SUNCOR ENERGY INC. 2000 ANNUAL REPORT

<PAGE>

                                               CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
                                           Corporate and eliminations              Total
($ millions)                                2000      1999      1998      2000      1999      1998
- ----------------------------------------------------------------------------------------------------
<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)                       (117)      (49)      (28)      377       186       178
  Exploration expenses
    Cash                                      --        --        --        12        12        16
    Dry hole costs                            --        --        --        41        28        24
  Non-cash items included
    in earnings
    Depreciation, depletion
      and amortization                         1         1         1       365       318       264
    Future income taxes                      (76)       (4)       19       198        96       122
    Current income tax provision
      allocated to Corporate                 (55)      (60)      (37)       --        --        --
    (Gain) loss on disposal of assets         --        --        --      (148)      (34)       (6)
    Write-down of oil shale assets           125        --        --       125        --        --
    Restructuring                             --        --        --        56        --        --
    Other                                     (7)        4         3       (17)       13         3
  Overburden removal outlays                  --        --        --       (48)      (53)      (46)
  Overburden removal outlays -
    Project Millennium                        --        --        --       (27)       --        --
  Increase (decrease) in deferred
    credits and other                         20        19        23        24        25        25
- ----------------------------------------------------------------------------------------------------
Total cash flow provided from
  (used in) operations                      (109)      (89)      (19)      958       591       580
Decrease (increase) in operating
  working capital                             52        68       (53)      (50)      247       (67)
- ----------------------------------------------------------------------------------------------------
Total cash provided from (used in)
  operating activities                       (57)      (21)      (72)      908       838       513
- ----------------------------------------------------------------------------------------------------
CASH PROVIDED FROM (USED IN)
  INVESTING ACTIVITIES:
Capital and exploration
  expenditures                               (18)      (51)     (127)   (1 998)   (1 350)     (936)
Deferred maintenance
  shutdown expenditures                       --        --        --       (13)      (22)      (10)
Deferred outlays and
  other investments                           (1)       (1)        1       (13)      (10)       (2)
Proceeds from disposals                       --        --        --       417        92        11
- ----------------------------------------------------------------------------------------------------
Total cash provided from (used in)
  investing activities                        (19)     (52)     (126)   (1 607)   (1 290)     (937)
- ----------------------------------------------------------------------------------------------------
NET CASH SURPLUS (DEFICIENCY)
  BEFORE FINANCING ACTIVITIES                 (76)     (73)     (198)     (699)     (452)     (424)
- ----------------------------------------------------------------------------------------------------
</TABLE>


                                       SUNCOR ENERGY INC. 2000 ANNUAL REPORT  65
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.   CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2000, the company adopted new recommendations issued by
the Accounting Standards Board of the Canadian Institute of Chartered
Accountants with respect to accounting for the costs of employee future
benefits; accounting for income taxes; and, the computation, presentation and
disclosure of earnings per share.

EMPLOYEE FUTURE BENEFITS:
The new recommendations on accounting for the costs of employee future
benefits, which will not affect the company's cash flows or liquidity, have
been adopted retroactively and financial statements of all prior periods
presented for comparative purposes have been restated to give effect to them.
Accordingly, at January 1, 2000, retained earnings were decreased by $34
million, accrued liabilities and other were increased by $57 million and
future income taxes were decreased by $23 million.

     The impact of the new recommendations for the year ended December 31,
2000 was to increase operating, selling and general expenses by $14 million
(1999 - $24 million; 1998 - $16 million) and decrease net earnings by $8
million (1999 - $14 million; 1998 - $10 million).

FUTURE INCOME TAXES:
The new recommendations on accounting for income taxes, which will not affect
the company's cash flows or liquidity, have been adopted retroactively as an
adjustment to opening retained earnings to reflect the cumulative effect of the
change on prior periods. The financial statements of prior periods presented for
comparative purposes have not been restated. Accordingly, at January 1, 2000,
retained earnings were increased and future income taxes were decreased by $75
million.

     The impact of the new recommendations for the year ended December 31,
2000 was to increase net earnings by $23 million.

EARNINGS PER SHARE:
The new recommendations on earnings per share, which bring Canadian accounting
requirements in line with U.S. and international standards, require use of the
treasury stock method to determine the dilutive effect of warrants, options and
equivalents. Previously, the company used the current imputed earnings approach
to determine the dilutive effect.

     The new recommendations have been adopted retroactively and earnings per
share figures of all prior periods presented for comparative purposes have been
restated to give effect to them.

     This change in accounting policy had no effect on basic earnings per share
and no material effect on diluted earnings per share for the years ended
December 31, 2000, 1999 and 1998.

2.   OIL SHALE PROJECT
In the third quarter of 2000, the company reviewed the carrying value of the
company's costs associated with the Stuart Oil Shale Project as a result of
operational issues, increased costs and delayed oil production. Based upon
management's current operating assumptions and best estimates of the most
probable set of economic conditions associated with the development of the
project, the carrying value of the assets exceeded the net future cash flows
from the project. As a result, the company recorded a write-down of the carrying
value of the project of $125 million. The impact of this write-down was to
decrease net earnings by $80 million.

     As at December 31, 2000, the company's records included the following
significant amounts related to the oil shale project:

     Net capital assets of $134 million, after the above write-down.

     Investments in partly paid Restricted Class Shares of the Australian joint
     venture participants in the Stuart Oil Shale Project, Central Pacific
     Minerals NL (CPM) and Southern Pacific Petroleum NL (SPP), totalling $4
     million. These shares convey to the company a right, but not an obligation,
     to fully pay for additional Restricted Class Shares of CPM and SPP,
     respectively, for an additional investment of approximately $57 million.
     Ownership of these shares would represent approximately a 14% interest in
     CPM and SPP as at December 31, 2000. The Restricted Class Shares would
     automatically convert to an equal number of common shares in June 2004, or
     earlier in certain circumstances. The market value of these common shares
     at December 31, 2000, based on quoted market prices, was approximately $144
     million (1999 - $222 million; 1998 - $157 million). It is uncertain,
     however, whether the quoted market price would be fully realized upon any
     future sale of these shares.

     Long-term borrowings of $73 million and accrued interest of $16 million.
     Principal and interest repayable from project net cash flows.

     The success of the Stuart Oil Shale Project is subject to uncertainty.
If the project is unsuccessful, the above amounts would be eliminated. The
impact on future earnings, should this occur, is currently estimated to not
be significant.

3.   RESTRUCTURING CHARGE
In 2000, the carrying value 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, as follows:


66  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
- ---------------------------------------------
($ millions)
- ---------------------------------------------
<S>                                       <C>
Non-cash charges:
  Impairment of non-core
    proved properties                     21
  Impairment of non-core
   unproved properties                    18
  Write-down of capitalized
    development costs on
    proved properties                     17

Cash charges:
  Employee terminations                    6
  Consultants and other                    3
- ---------------------------------------------
                                          65
- ---------------------------------------------
- ---------------------------------------------
</TABLE>

     The impact of these charges is to decrease net earnings by $30 million.
At December 31, 2000, current liabilities include $2 million related to
termination and other costs to be paid in 2001.

4.   ROYALTIES

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------
                        2000                 1999                 1998
($ millions)    Crown   Other  Total  Crown  Other  Total  Crown  Other  Total
- ------------------------------------------------------------------------------
<S>             <C>     <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
Oil Sands          87      11     98     48      3     51     35      8     43
Natural Gas        90      11    101     40      8     48     28      7     35
- ------------------------------------------------------------------------------
Total             177      22    199     88     11     99     63     15     78
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
</TABLE>

     Alberta Crown royalties totalling $8 million (1999 - $7 million; 1998 -
$5 million) were paid in kind, and are not shown in the company's revenues
and expenses.

5.   SUPPLEMENTAL INFORMATION

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
($ millions)                                   2000        1999         1998
- ----------------------------------------------------------------------------
<S>                                            <C>         <C>          <C>
Export sales (1)                                478         233          231
- ----------------------------------------------------------------------------
Exploration expenses
  Geological and geophysical                     10          10           14
  Other                                           2           2            2
- ----------------------------------------------------------------------------
  Cash costs                                     12          12           16
  Dry hole costs                                 41          28           24
- ----------------------------------------------------------------------------
  Cash and dry hole costs (2)                    53          40           40
  Leasehold impairment (3)                       10          12           10
- ----------------------------------------------------------------------------
                                                 63          52           50
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
Taxes other than income taxes
  Excise taxes (4)                              336         311          305
  Production, property and other taxes           25          23           20
- ----------------------------------------------------------------------------
                                                361         334          325
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
Interest expense
  Long-term interest cost                       112          71           67
  Less interest capitalized                    (104)        (45)         (43)
- ----------------------------------------------------------------------------
                                                  8          26           24
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
Cash interest payments                          104          63           64
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
Allowance for doubtful accounts                   3           3            3
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
</TABLE>

In 2000, the company had in place a securitization program to sell, on an
ongoing basis, up to $122 million of accounts receivable (1999 - $83 million)
on a limited recourse basis, to a third party. As at December 31, 2000, $122
million (1999 - $83 million) in accounts receivable had been sold under the
program. On December 31, 1998, the company sold, on a limited recourse basis,
approximately $50 million in accounts receivable to third parties. The
company believes it has no significant exposure to credit loss under the
recourse provisions.

(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.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  67
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6.   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, WHICH COULD 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 AMOUNT SHOWN ON THE BALANCE SHEETS AS FUTURE INCOME TAXES REPRESENTS
NON-DISCOUNTED 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 which
differs from the statutory tax rate. A reconciliation of the two rates and
the dollar effect is as follows:

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------
                                                2000                1999               1998
($ millions)                              AMOUNT        %     Amount        %     Amount        %
- -------------------------------------------------------------------------------------------------
<S>                                       <C>         <C>     <C>         <C>     <C>         <C>
Federal tax rate                             236       38        118       38        107       38
Provincial abatement                         (62)     (10)       (31)     (10)       (28)     (10)
Federal surtax                                 7        1          3        1          3        1
Provincial tax rates                          96       16         48       16         46       16
- -------------------------------------------------------------------------------------------------
STATUTORY TAX AND RATE                       277       45        138       45        128       45
Add (deduct) the tax effect of:
Crown royalties (see note 4)                  83       13         44       13         31       11
Resource allowance                          (101)     (17)       (56)     (17)       (49)     (16)
Large corporations tax                        10        2         10        3          9        3
Income tax refund*                            --       --         --       --        (11)      (4)
Tax rate changes on future income taxes      (13)      (2)        --       --         --       --
Attributed Canadian royalty income           (13)      (2)        --       --         --       --
Other                                         --       --        (11)      (4)        (5)      (2)
- -------------------------------------------------------------------------------------------------
INCOME TAXES AND EFFECTIVE RATE              243       39        125       40        103       37
- -------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
</TABLE>

2000 income tax payments totalled $22 million (1999 - payments of $5 million;
1998 - net refund of $19 million).

*    During 1998, settlements were reached with Canada Customs and Revenue
     Agency (formerly Revenue Canada) on a number of taxation issues resulting
     in refunds totalling $34 million, $11 million of which were reflected in
     1997 net earnings ($0.05 per common share). The impact of the refund in
     1998 is to increase net earnings by $11 million ($0.05 per common share)
     reflecting a reduction of prior years income taxes of $5 million and
     taxable interest of $6 million (after a provision for income taxes of $5
     million).

     At December 31, 2000, future income taxes are comprised of the following:

<TABLE>
<CAPTION>
- ---------------------------------------------------------
($ millions)                       Current    Non-current
- ---------------------------------------------------------
<S>                                <C>        <C>
Future income tax assets:
  Employee future benefits               2             39
  Reclamation and
    environmental
    remediation costs                    9             23
  Royalties                             --             43
  Employee incentive plans              --             10
  Inventories                           20             --
  Other                                 14              4
- ---------------------------------------------------------
                                        45            119
- ---------------------------------------------------------
- ---------------------------------------------------------
Future income tax liabilities:
  Depreciation                          --          1 038
  Overburden removal costs              --             23
  Maintenance shutdown costs            --             12
  Other                                  9              7
- ---------------------------------------------------------
                                         9          1 080
- ---------------------------------------------------------
- ---------------------------------------------------------
</TABLE>

7.   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)                             2000      1999      1998
- -----------------------------------------------------------------
<S>                                      <C>       <C>       <C>
Revenues
  Sales to Sunoco joint ventures:
    Refined products                      600       395       309
    Petrochemicals                        128       108        85
- -----------------------------------------------------------------
At the end of the year, amounts
  due from related parties are
  as follows:

Sunoco joint ventures                      58        45        41
- -----------------------------------------------------------------
</TABLE>


68  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Sales to and balances with Sunoco joint ventures are exchange amounts
established and agreed to by the related parties, before application of the
proportionate consolidation method of accounting.

     The company has exclusive supply agreements with two Sunoco joint
ventures for the sale of refined products. One agreement expires in 2002,
after which the company will continue to be the exclusive supplier of refined
products as long as it remains a shareholder. The company plans to maintain
its relationship with this joint venture. The other agreement expires in 2003
and will be automatically renewed thereafter for one-year terms until
terminated upon twelve months' prior written notice. No notice has been given
by either party.

     The company also has a non-exclusive supply agreement with a Sunoco
joint venture for the sale of petrochemicals. The agreement is automatically
renewed on an annual basis until it is terminated by either party upon twelve
months' written notice. No notice has been given by either party.

8. INVENTORIES

<TABLE>
<CAPTION>
- -------------------------------------------------------------
($ millions)                         2000      1999      1998
- -------------------------------------------------------------
<S>                                  <C>       <C>       <C>
Crude Oil                              83        47        58
Refined products                       55        67        62
Materials and supplies                 54        47        55
- -------------------------------------------------------------
   Total                              192       161       175
- -------------------------------------------------------------
- -------------------------------------------------------------
</TABLE>

     The replacement cost at December 31, 2000, of all inventories valued at
LIFO exceeded their carrying value by $61 million (1999 - $37 million; 1998
- -nil).

     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.

9.   CAPITAL ASSETS

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
                                                       2000                      1999                       1998
                                                            ACCUM.                    Accum.                     Accum.
($ millions)                                    COST     PROVISION        Cost     Provision        Cost      Provision
- -----------------------------------------------------------------------------------------------------------------------
<S>                                            <C>       <C>             <C>       <C>             <C>        <C>
Oil Sands
  Plant                                        1 814           496       1 770           487       1 548            449
  Mine and mobile equipment                      918           313         850           243         828            191
  Capitalized energy services asset lease        101             2          --            --          --             --
  Capitalized aircraft lease                       8            --          --            --          --             --
  Project Millennium*
    - in-service                                 102             6          --            --          --             --
    - in-progress                              2 434            --         905            --          99             --
- -----------------------------------------------------------------------------------------------------------------------
                                               5 377           817       3 525           730       2 475            640
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
Natural Gas
  Proved properties (note 3)                     877           366       1 190           487       1 242            506
  Unproved properties (note 3)                   125            56         344           171         288            169
  Pipeline                                        20            17          22            18          22             18
  Other support facilities and equipment          13             6          19            12          18             10
- -----------------------------------------------------------------------------------------------------------------------
                                               1 035           445       1 575           688       1 570            703
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
Sunoco
  Refinery                                       745           367         740           350         724            327
  Marketing and transportation                   405           187         380           165         362            148
- -----------------------------------------------------------------------------------------------------------------------
                                               1 150           554       1 120           515       1 086            475
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
Corporate
  Stuart Oil Shale Project (note 2)              134            --         237            --         187             --
  Other                                            6             3           7             3           6              2
- -----------------------------------------------------------------------------------------------------------------------
                                                 140             3         244             3         193              2
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
                                               7 702         1 819       6 464         1 936       5 324          1 820
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
Net capital assets                                           5 883                     4 528                      3 504
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>

Interest capitalized during 2000 totalled $104 million (1999 - $45 million;
1998 - $43 million).
Capitalized costs related to the in-progress phase of Project Millennium and
the Stuart Oil Shale Project are not being amortized.
Depreciation will begin when the facilities are substantially complete and
ready for commercial production to commence.

*    Start-up costs incurred in the commissioning of Project Millennium have
     been expensed.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  69
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEFERRED CHARGES AND OTHER

<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------
($ millions)                                         2000        1999        1998
- ---------------------------------------------------------------------------------
<S>                                                  <C>         <C>         <C>
Oil sands overburden removal costs (see below)         76          85          95
Deferred maintenance shutdown costs                    35          45          44
Investments                                             8           8           8
Other                                                  47          53          52
- ---------------------------------------------------------------------------------
                                                      166         191         199
- ---------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------
Oil sands overburden removal costs
  Balance - beginning of year                          85          95          86
  Outlays during year                                  75          53          46
  Depreciation on equipment during year                 8           6           2
- ---------------------------------------------------------------------------------
                                                      168         154         134
  Amortization during year                            (92)        (69)        (39)
- ---------------------------------------------------------------------------------
  Balance - end of year                                76          85          95
- ---------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------
</TABLE>

11.  LONG-TERM BORROWINGS

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------
($ millions)                                                             2000      1999      1998
- -------------------------------------------------------------------------------------------------
<S>                                                                     <C>       <C>       <C>
FIXED RATE BORROWINGS
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 with interest at 7.75% (note 2)        73        82        71
Sunoco joint venture borrowings with interest at
  rates averaging 7.7% at December 31, 2000
  (1999 - 7.6%; 1998 - 7.1%)                                                4         5         5
- -------------------------------------------------------------------------------------------------
                                                                          712       722       711
Capital leases***                                                         109        --        --
Less current portion of fixed rate long-term borrowings                     1         1         1
- -------------------------------------------------------------------------------------------------
                                                                          820       721       710
- -------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
VARIABLE RATE BORROWINGS****
Borrowings with interest at variable rates averaging
  6.0% at December 31, 2000 (1999 - 5.2%; 1998 - 5.3%)
  under or with support of lines of credit                              1 372       585       588
- -------------------------------------------------------------------------------------------------
TOTAL LONG-TERM BORROWINGS                                              2 192     1 306     1 298
- -------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
</TABLE>

*    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 U.S. $91 million obligation back to a fixed rate Canadian
     $125 million obligation. Both contracts will remain in place for the term
     of the debenture. The net effect of the two swap transactions is to reduce
     the effective interest rate on the debentures from 7.3% (7.4% coupon rate)
     to 5.5%. The principal obligation remains unchanged.

**   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.


70  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*** Obligations under capital leases are as follows:

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

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

<TABLE>
<CAPTION>
- ---------------------------------------------------------------
                                                   ($ millions)
- ---------------------------------------------------------------
<S>                                                <C>
2001                                                          8
2002                                                          8
2003                                                          8
2004                                                        108
2005                                                          1
Later years                                                   6
- ---------------------------------------------------------------
Total minimum lease payments                                139
Less amount representing imputed interest                   (30)
- ---------------------------------------------------------------
Present value of obligation under capital leases            109
- ---------------------------------------------------------------
- ---------------------------------------------------------------
</TABLE>

**** During 1999, the company entered into a cross-currency interest rate swap
     transaction to convert U.S. $183 million of variable rate borrowings with
     interest based on 90-day LIBOR to Canadian $278 million with interest
     based on 90-day bankers' acceptances.

LONG-TERM BORROWINGS

<TABLE>
<CAPTION>
- -------------------------------------------
(percentages)        2000     1999     1998
- -------------------------------------------
<S>                  <C>      <C>      <C>
Variable rate          63       45       45
Fixed rate             37       55       55
</TABLE>

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)
- ---------------------------------------------------------------
<S>                                                <C>
2001                                                          1
2002                                                          1
2003                                                          2
2004                                                      1 608
2005                                                         --
- ---------------------------------------------------------------
</TABLE>

12.  LINES OF CREDIT

At December 31, 2000, the company had available $2 411 million in credit and
term loan facilities, of which $917 million had been drawn, as follows:

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

     A facility for $500 million, which is fully revolving for 364 days and
expires in 2001.

     A facility for U.S. $183 million (Cdn $278 million), which is
non-revolving, has been fully drawn and expires in 2004.

     A facility for $1 018 million, which is fully revolving for six years
and expires in 2004.

     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 $600 million
having a term not to exceed 364 days. At December 31, 2000, the company had
$565 million in commercial paper outstanding.

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

13.  ACCRUED LIABILITIES AND OTHER

<TABLE>
<CAPTION>
- -------------------------------------------------------
($ millions)                     2000     1999     1998
- -------------------------------------------------------
<S>                              <C>      <C>      <C>
Reclamation & environmental
  remediation costs (a)            70       86       87
Pension costs (see note 14)        95       96       83
Other (b)                          87       54       24
- -------------------------------------------------------
Total                             252      236      194
- -------------------------------------------------------
- -------------------------------------------------------
</TABLE>

(a)  RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS
Total accrued reclamation and environmental remediation costs also include
$27 million in current liabilities (1999 - $13 million; 1998 - $14 million).
Payments during 2000 totalled $15 million (1999 - $13 million; 1998 - $11
million).

     The estimate of remaining reclamation costs for the company's oil sands
operation is $525 million for its current mining operation and its Project
Millennium. Factors such as inflation and changes in technology and proved
reserves may materially change the cost estimate.

     The Natural Gas segment's reclamation and environmental remediation cost
estimate decreased in 2000 from $57 million to $32 million, reflecting the
divestment of properties (see note 3). A total of $26 million has been
accrued to December 31, 2000. The remaining $6 million will be accrued over
future years on a unit of production basis.

(b)  EMPLOYEE AND DIRECTOR INCENTIVE PLANS
Compensation expense recorded under the company's long-term employee
incentive plans was $32 million (1999 - $26 million; 1998 - $4 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.

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


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  71
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14.  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, 2000 WAS
$483 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 2000, PLAN ASSETS TO MEET THE
BENEFIT OBLIGATION WERE $322 MILLION.

     THE EXCESS OF THE BENEFIT OBLIGATION OVER PLAN ASSETS OF $161 MILLION
REPRESENTS THE NET UNFUNDED OBLIGATION. SEE BELOW FOR THE 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 which covers most
employees, and unfunded supplementary benefit plans which 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.

     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
(percentages)              2000     1999     1998     2000     1999     1998
- ---------------------------------------------------------------------------
<S>                       <C>      <C>      <C>      <C>      <C>      <C>
Discount rate             7.00     7.25     6.00     7.00     7.25     6.00
Expected return
  on plan assets          7.25     7.25     8.00       --       --       --
Rate of compensation
  increase                4.25     4.25     4.50     4.25     4.25     4.50
</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>
- -----------------------------------------------------------------------------------------------------------
                                                                                            Other
                                                         Pension benefits          post-retirement benefits
                                                     2000      1999      1998      2000      1999      1998
- -----------------------------------------------------------------------------------------------------------
<S>                                                  <C>       <C>       <C>       <C>       <C>       <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year               364       403       334        69        72        64
Service costs                                          12        15        11         3         4         2
Interest costs                                         26        24        23         5         4         5
Plan participants' contribution                         3         2         2        --        --        --
Amendments                                             --        --        --        --        (8)        3
Actuarial (gain) loss                                  23       (61)       51         4        (1)       --
Benefits paid                                         (24)      (19)      (18)       (2)       (2)       (2)
- -----------------------------------------------------------------------------------------------------------
Benefit obligation at end of year                     404       364       403        79        69        72
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS*
Fair value of plan assets at beginning of year        316       278       250        --        --        --
Actual return on plan assets                           15        39        28        --        --        --
Employer contribution                                  12        16        16        --        --        --
Plan participants' contribution                         3         2         2        --        --        --
Benefits paid                                         (24)      (19)      (18)       --        --        --
- -----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year              322       316       278        --        --        --
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
Net unfunded obligation                               (82)      (48)     (125)      (79)      (69)      (72)
Items not yet recognized in earnings:
Unamortized transitional asset                         (8)      (16)      (24)       --        --        --
Unamortized net actuarial loss                         45        18        108       13        11        21
- -----------------------------------------------------------------------------------------------------------
Accrued benefit liability*                            (45)      (46)      (41)      (66)      (58)      (51)
- -----------------------------------------------------------------------------------------------------------
* Current portion                                     (15)       (8)       (8)       (2)       (2)       (2)
- -----------------------------------------------------------------------------------------------------------
Long-term portion                                     (30)      (38)      (33)      (64)      (56)      (49)
- -----------------------------------------------------------------------------------------------------------
                                                      (45)      (46)      (41)      (66)      (58)      (51)
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
</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.


72  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
                                                  Pension benefits                  Other post-retirement benefits
                                         2000          1999          1998          2000          1999          1998
- -------------------------------------------------------------------------------------------------------------------
<S>                                      <C>           <C>           <C>           <C>           <C>           <C>
Funded plan                               334           309           332            --            --            --
Unfunded plans                             70            55            71            79            69            72
- -------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year         404           364           403            79            69            72
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
</TABLE>

     The unamortized asset determined at January 1, 1987, the transition
date, is being amortized on a straight-line basis over 15 years to 2001. 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 (1999 and 1998 -
13 years), and over the expected average future service life to full
eligibility age of 11 years for post-retirement benefits.

     The components of net periodic benefit cost are as follows:

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
                                                  Pension benefits                  Other post-retirement benefits
                                         2000          1999          1998          2000          1999          1998
- -------------------------------------------------------------------------------------------------------------------
<S>                                      <C>           <C>           <C>           <C>           <C>           <C>
Service costs                              12            15            11             3             4             2
Interest costs                             26            24            23             5             4             5
Expected return on plan assets            (22)          (22)          (20)           --            --            --
Amortization of transitional asset         (8)           (8)           (8)           --            --            --
Amortization of net actuarial loss          6            12             9             1             1             1
- -------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost                  14            21            15             9             9             8
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
</TABLE>

     In order to measure the expected cost of other post-retirement benefits,
a 10% annual rate of increase in the per capita cost of covered health care
benefits was assumed for 2000. 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           13         (10)
- -------------------------------------------------------------
</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 (1999 - $4 million; 1998 - $3 million), are based on employees'
earnings and contributions.

15.  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, 2000, future minimum amounts payable under these leases and
agreements are as follows:

<TABLE>
<CAPTION>
- --------------------------------------------------------
                       Pipeline capacity       Operating
($ millions)        and energy services*          leases
- --------------------------------------------------------
<S>                 <C>                        <C>
2001                                 101              43
2002                                 116              25
2003                                 115              19
2004                                 115              16
2005                                 123              15
Later years                        3 159              70
- --------------------------------------------------------
                                   3 729             188
- --------------------------------------------------------
- --------------------------------------------------------
</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.

     A major energy company is in the process of building a cogeneration
     facility at the oil sands site with expected completion during the first
     quarter of 2001. Under long-term energy agreements, Suncor has a commitment
     to obtain a portion of the power and all of the steam generated by this
     facility to meet the energy needs of its oil sands operation. Effective
     October 1999, this company also commenced managing the operations of
     Suncor's existing energy services facility.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  73
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(b)  CAPITAL EXPENDITURE COMMITMENTS AND CONTINGENCIES
At December 31, 2000, the company had outstanding commitments of $193 million
for capital expenditures on Project Millennium.

(c)  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.

     Under the company's business interruption insurance coverage, the
company would bear the first $70 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 that might arise pertaining to such matters would not be expected
to have a material effect on the company's consolidated financial position.

16.  PREFERRED SECURITIES
During 1999, the company completed a Canadian offering of $276 million of
9.05% preferred securities and a U.S. offering of U.S.$163 million of 9.125%
preferred securities, the proceeds of which totalled Canadian $507 million
after issue costs of $17 million ($10 million after tax). 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.

17.  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, 1997               219 813 266            513
Issued for cash under
  stock option plan                   594 930              4
Issued under dividend
  reinvestment plan                    25 460              1
- ------------------------------------------------------------
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
- ------------------------------------------------------------
- ------------------------------------------------------------
</TABLE>


74  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

COMMON SHARE OPTIONS

(i)  EXECUTIVE STOCK PLAN
Under this program, 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 of 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 has granted 1 067 290 share options to
certain executives and 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.

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

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Exercise price per share
                                                                                 Weighted
(dollars)                                     Number               Range          Average
- -----------------------------------------------------------------------------------------
<S>                                        <C>               <C>                 <C>
Outstanding, December 31, 1997             5 196 582          4.75-26.08            14.27
  Granted                                    893 036         24.55-26.38            24.66
  Exercised                                 (594 978)         4.75-15.69             7.25
  Cancelled                                  (97 402)        10.55-26.08            21.38
- -----------------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------

Exercisable, December 31
  1998                                     2 266 874          4.75-26.08            10.44
- -----------------------------------------------------------------------------------------
  1999                                     2 609 816          4.75-26.98            12.89
- -----------------------------------------------------------------------------------------
  2000                                     3 067 594          4.75-31.98            15.42
- -----------------------------------------------------------------------------------------
</TABLE>

AVAILABLE FOR GRANT, DECEMBER 31

<TABLE>
<CAPTION>
- ----------------------------------------------------------------
(number of common shares)         2000         1999         1998
- ----------------------------------------------------------------
<S>                          <C>          <C>          <C>
                             6 336 377    7 076 468    8 120 258
- ----------------------------------------------------------------
</TABLE>

The following table is an analysis of outstanding and exercisable common
share options as at December 31, 2000:

<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>
 4.75-10.44             572 148                        3                    7.91          572 148                    7.91
10.55-15.69           1 595 815                        5                   13.43        1 595 815                   13.43
20.25-24.85           1 695 992                        7                   22.15          800 230                   22.96
26.08-26.98           1 094 290                        6                   26.11           41 334                   26.96
28.12-38.55             902 630                        9                   31.45           58 067                   31.94
- -------------------------------------------------------------------------------------------------------------------------
Total                 5 860 875                        6                   20.55        3 067 594                   15.42
- -------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  75
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(iii) FAIR VALUE OF OPTIONS GRANTED
The weighted average fair value of common share options granted in 2000 is
$7.12 per share (1999 - $7.01 per share; 1998 - $9.05 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>
- ---------------------------------------------------------
                               2000       1999       1998
- ---------------------------------------------------------
<S>                         <C>        <C>        <C>
Dividend                     $0.34/     $0.34/     $0.34/
                              SHARE      share      share
Risk-free interest rate       6.45%      4.89%      5.31%
Expected life               7 YEARS    7 years    7 years
Expected volatility             37%        32%        32%
- ---------------------------------------------------------
</TABLE>

18.  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, investment in CPM and SPP,
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, 2000, the company had outstanding crude oil and U.S.
dollar swap contracts maturing in July 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 $10 million at December 31, 2000 (1999 -$(2) million; 1998 - $nil).

     The fair value of the company's investment in the shares of CPM and SPP
is not determinable. Information about the terms, conditions and
characteristics of this investment is presented in note 2.

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

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
                                             2000                       1999                       1998
                                   CARRYING        FAIR       Carrying        Fair       Carrying        Fair
($ millions)                         AMOUNT       VALUE         Amount       Value         Amount       Value
- -------------------------------------------------------------------------------------------------------------
<S>                                <C>            <C>         <C>            <C>         <C>            <C>
Long-term borrowings
  - fixed rate                          525         528            525         516            525         548
  - variable rate                     1 482       1 482            695         695            698         698
  - Sunoco joint ventures                 3           3              4           4              4           4
  - Stuart Oil Shale Project             73          73             82          82             71          71
  - capital leases                      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, proportionate
share of the long-term borrowings of its Sunoco joint ventures, and the
Stuart Oil Shale Project borrowings approximates the 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.


76  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contracts outstanding at December 31 were as follows:

CONTRACT AMOUNTS

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
                                                                 Average price*         Revenue hedged
($ millions except for average price)           Quantity                   Cdn$                    Cdn$         Hedge Period
- ----------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                    <C>                    <C>                     <C>
REVENUE HEDGES
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                                U.S.$81                   1.41                     114                 2001
                                                U.S.$289                   1.41                     408                 2002
- ----------------------------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 1998
Crude oil swaps*                          23 700 bbl/day                     28                     242                 1999
                                           6 000 bbl/day                     28                      61                 2000
U.S. dollar swaps                               U.S.$115                   1.39                     160                 1999
                                                U.S.$274                   1.39                     381                 2000
                                                U.S.$312                   1.41                     440                 2001
                                                U.S.$314                   1.42                     446                 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

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
                                                                 Average margin          Margin hedged
($ millions except for average price)           Quantity              U.S.$/bbl                  U.S.$          Hedge period
- ----------------------------------------------------------------------------------------------------------------------------
<S>                                        <C>                  <C>                      <C>                    <C>
MARGIN HEDGES
Refined product sale and
  crude purchase swaps                     6 575 bbl/day                      5                     12                  2001
- ----------------------------------------------------------------------------------------------------------------------------
</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, 2000 are detailed in note 11,
Long-Term Borrowings.

FAIR VALUE OF UNRECOGNIZED 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>
- --------------------------------------------------------------
($ millions)                      2000        1999        1998
- --------------------------------------------------------------
<S>                               <C>         <C>         <C>
Revenue hedge
  swaps and options               (247)       (136)         77
Margin hedge swaps                 (11)         --          --
U.S. dollar swaps                   --          (1)       (108)
Interest rate and cross-
  currency interest
  rate swaps                         5          --          10
- --------------------------------------------------------------
                                  (253)       (137)        (21)
- --------------------------------------------------------------
- --------------------------------------------------------------
</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, 2000, the company had exposure to credit risk
with counterparties as follows:

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


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  77
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-3
<SEQUENCE>4
<FILENAME>a2042188zex-3.txt
<DESCRIPTION>EXHIBIT 3
<TEXT>

<PAGE>

                                   EXHIBIT 3
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS

HEDGING

Companies use derivatives to hedge or counteract possible fluctuations in the
price of commodities or interest rates. This permits mitigation of price or
interest rate risk due to market fluctuations.

OVERVIEW***

Suncor Energy Inc. is a Canadian company comprised of three operating
businesses: an oil sands operation (Oil Sands); a natural gas business
(Natural Gas - NG, formerly the Exploration and Production business); and a
refining and marketing operation (Sunoco). Suncor markets its crude oil
production, diesel fuel and byproducts through its wholly owned subsidiary
Suncor Energy Marketing Inc. Suncor's corporate centre is located in Calgary,
Alberta, Canada. Suncor is currently commissioning an oil shale demonstration
project known as the Stuart Oil Shale Project.

2000 EARNINGS INCREASED 103%

Net earnings for the year increased to $377 million, from $186 million in
1999. Cash flow from operations was $958 million, compared with $591 million
in 1999. During the year, several transactions impacted net earnings and cash
flow from operations that were not viewed as ongoing operational earnings and
cash flow. These transactions included Suncor's write-down of the carrying
value of the Stuart Oil Shale Project, restructuring costs and divestment
gains in NG and Project Millennium start-up costs. Refer to Notes 2 and 3 in
Suncor's Consolidated Financial Statements for further information.

Operational earnings in 2000 increased to $427 million from $167 million in
1999. Operational cash flow from operations was over $1 billion, representing
the eighth consecutive year of cash flow growth. Operational cash flow in
1999 was $591 million. The non-operational transactions are explained in the
Notes to the Consolidated Financial Statements. See the tables below for the
components of net earnings and cash flow from operations.

<TABLE>
<CAPTION>
NET EARNINGS COMPONENTS
- ----------------------------------------------------------------------------------------------
($ millions after income taxes)                                     2000       1999      1998
- ----------------------------------------------------------------------------------------------
<S>                                                                <C>         <C>       <C>
Operational earnings                                                 427        167       175
NATURAL GAS
  Asset divestments                                                   69         19         3
  Restructuring                                                      (30)        --        --
STUART OIL SHALE PROJECT
  Partial asset write-down                                           (80)        --        --
OIL SANDS
  Start-up expenses - Project Millennium                              (9)        --        --
- ----------------------------------------------------------------------------------------------
Net earnings                                                         377        186       178
- ----------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
CASH FLOW FROM OPERATIONS COMPONENTS
- ----------------------------------------------------------------------------------------------
($ millions)                                                        2000       1999      1998
- ----------------------------------------------------------------------------------------------
<S>                                                                <C>         <C>       <C>
Operational cash flow                                              1,009        591       580
NATURAL GAS
  Restructuring costs                                                 (9)        --        --
OIL SANDS
  Start-up expenses & overburden removal - Project Millennium        (42)        --        --
- ----------------------------------------------------------------------------------------------
  Cash flow from operations                                          958        591       580
- ----------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------
</TABLE>

Quarterly Data: For information related to quarterly sales, net income and
net income per share for the years 2000 and 1999 refer to page 78 of the 2000
annual report and the section "Financial Data".


28 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                          MANAGEMENT'S DISCUSSION AND ANALYSIS

The $260 million increase in consolidated operational earnings in 2000 compared
to 1999 resulted primarily from higher commodity prices and record Oil Sands
sales volumes. Other factors that increased earnings include improved refining
margins and volumes, reduced income tax rates and higher Australian/Canadian
foreign exchange rate gains. These positive factors were partially offset by
higher HEDGING losses and operating expenses, lower natural gas volumes, Stuart
Oil Shale Project costs and reduced retail gasoline margins.

Operational cash flow in 2000 increased over 1999 primarily due to the same
factors that increased earnings.

<TABLE>
<CAPTION>

CONSOLIDATED FINANCIAL RESULTS
- ---------------------------------------------------------------------------------------------
($ millions)                                           2000            1999             1998
- ---------------------------------------------------------------------------------------------
<S>                                                   <C>             <C>              <C>
Net earnings                                            377             186              178
Cash flow provided from operations                      958             591              580
Investing activities                                  1,607           1,290              937
Dividends - common shares                                75              75               75
          - preferred securities                         47              37                0
Long-term borrowings                                  2,192           1,306            1,298
- ---------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
RELATIVE SEGMENT CONTRIBUTION
- ---------------------------------------------------------------------------------------------
(before the impact of corporate and elimination
 adjustments, expressed as %)                          2000            1999             1998
- ---------------------------------------------------------------------------------------------
<S>                                                   <C>             <C>              <C>
NET EARNINGS
  Oil Sands                                              64              71               70
  Natural Gas                                            20              17               12
  Sunoco                                                 16              12               18
CASH FLOW PROVIDED FROM OPERATIONS
  Oil Sands                                              62              60               53
  Natural Gas                                            22              25               28
  Sunoco                                                 16              15               19
CAPITAL EMPLOYED
  Oil Sands                                              64              55               49
  Natural Gas                                            19              29               31
  Sunoco                                                 17              16               20
- ---------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
INDUSTRY INDICATORS
- -----------------------------------------------------------------------------------------------------
(average of the year unless otherwise noted)                       2000           1999          1998
- -----------------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>           <C>
West Texas Intermediate (WTI) crude oil U.S.$/barrel at Cushing   30.25          19.30         14.40
Canadian 0.3% par crude Cdn$/barrel at Edmonton                   44.56          27.50         20.45
Light/heavy crude oil differential U.S.$/barrel -
  WTI @ Cushing/Bow River @ Hardisty                               6.84           3.42          4.54
Natural gas U.S.$/thousand cubic feet at Henry Hub                 3.90           2.27          2.14
Natural gas (Alberta spot) Cdn$/thousand cubic feet at Empress     5.08           3.00          2.25
Natural gas exports to the U.S. trillions of cubic feet            3.5*           3.4           3.1
New York Harbour 3-2-1 crack U.S.$/barrel**                        5.45           2.47          2.85
Refined product demand (Ontario) percentage change
  over prior year                                                  2.0*           3.8           2.6
Exchange rate: Cdn$:U.S.$                                          0.67           0.67          0.67
Exchange rate: Cdn$:Australian$                                    1.16           1.04          1.07
- -----------------------------------------------------------------------------------------------------
</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.

*** 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. 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 expenditures, commodity prices,
costs, schedules and production volumes, operating or 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 of which are
similar to other oil and gas companies and some of which 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
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 Project Millennium; the
integrity and reliability of Suncor's capital assets; the cumulative impact
of the 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 which 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, 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.


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 29
<PAGE>

MANAGEMENT'S DISCUSSION
AND ANALYSIS

Oil Sands

BITUMEN

A thick, sticky form of crude oil. At room temperature, bitumen is like cold
molasses. It must be heated or diluted before it will flow into a well or
through a pipeline.

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

OVERVIEW

Suncor has more than 30 years' experience in mining and upgrading oil sands
to produce crude oil on a commercial basis, more experience than any other
company in the world.

Suncor uses the following proven technology and processes to produce oil from
its leases in the Athabasca oil sands, near Fort McMurray, Alberta:

- -    Giant trucks and shovels mine the bitumen-laden oil sands.

- -    The BITUMEN is separated from the oil sands in the extraction process. It
     can then be sold directly to customers or upgraded into a variety of
     refinery feedstocks, including sweet and sour crude oil products and diesel
     fuel. The resulting products can be blended to customer specifications and
     sent by pipeline to markets in Canada and the United States.

The Oil Sands business also has an on-site energy plant, operated and
partially owned by TransAlta Energy Corporation (TransAlta). The energy plant
generates steam and electricity using natural gas and petroleum coke, a
byproduct of the upgrading process.

In 1999, Suncor received government approval to proceed with Project
Millennium, Suncor's oil sands expansion project. By the end of 2000, all
engineering and 70% of the total project was completed. Commissioning is
expected to begin in the second half of 2001, with full production capacity
of 225,000 barrels per day targeted by 2002. Total Oil Sands production in
2000 averaged 113,900 barrels per day.

RESULTS OF OPERATIONS AND INVESTING ACTIVITIES

2000 VS. 1999

OIL SANDS - SUMMARY OF RESULTS

<TABLE>
<CAPTION>
- -----------------------------------------------------------------
($ millions unless otherwise noted)      2000      1999      1998
- -----------------------------------------------------------------
<S>                                     <C>       <C>       <C>
Revenue                                 1 336       889       768
Production
  (thousands of barrels per day)        113.9     105.6      93.6
Average sales price
  ($ per barrel)                        31.67     23.84     22.18
Earnings                                  315       167       145
Cash provided
  from operations                         655       405       320
Total assets                            5 079     3 178     2 081
Investing activities                    1 715     1 085       514
ROCE (%)                                 22.8      12.9      16.3
- -----------------------------------------------------------------
</TABLE>

EARNINGS ANALYSIS

RECORD PRODUCTION AND INCREASED SELLING PRICES CONTRIBUTE TO INCREASED
EARNINGS

Oil Sands earned $315 million in 2000 compared with $167 million in 1999,
representing an 88% increase in earnings. Higher earnings were mainly
attributable to record Oil Sands production volumes and an increase in crude
oil prices. The benchmark WTI crude price increased by 57% over 1999 levels.
These favourable factors were partially offset by higher hedging losses,
increases in cash and non-cash expenses and lower sour crude oil prices due
to widening of the light/heavy crude oil differential. Sour crude oil sales
represented about 35% of sales volumes in 2000. Start-up expenses on Project
Millennium, totalling $9 million (after tax) also reduced earnings in 2000.

The combined impact of pricing factors increased earnings in 2000 by $212
million from 1999 levels.


30  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                              MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS

[GRAPHIC OF NORTH AMERICA HIGHLIGHTING ALBERTA CITIES]

[PHOTOGRAPGH OF MIKE ASHAR]

The year 2001 is a turning point for Oil Sands. We look forward to steady
base plant operations and bringing Millennium operations up to a production
capacity of 225,000 barrels per day by 2002.

MIKE ASHAR
Executive Vice President,
Oil Sands

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

OIL SANDS PRODUCTION INCREASES 8%, SALES VOLUMES UP 13%

Oil Sands increased production in 2000 for the eighth consecutive year to an
average of 113,900 barrels per day, from 105,600 barrels per day in 1999.
This was due to increased mining from the Steepbank Mine and enhancements to
base plant operations. Three weeks of prolonged cold weather in December
impacted fourth-quarter production which averaged 110,000 barrels per day.

The 5C9 fractionating tower is scheduled to be shut down for maintenance
before mid-2001 for approximately eight days, resulting in no oil production
during this period. Suncor's 130,000 barrels per day average production
target for 2001 includes the estimated impact of this maintenance work and
its impact on production.

Higher production increased sales volumes to a record 115,600 barrels per day
in 2000, up from 102,200 barrels per day in 1999. This volume increase
resulted in a year-over-year earnings improvement of $80 million. As sales
exceeded production in 2000, inventory levels in 2000 declined.

<TABLE>
<CAPTION>
BRIDGE ANALYSIS
OF EARNINGS
(CDN$ MILLIONS)
- --------------------------------
1999
<S>                          <C>
- --------------------------------
  Total                      167
- --------------------------------
- --------------------------------

2000
  Volume                      80
  Oil Price                  212
  Royalties                  (29)
  Cash Expenses              (69)
  Non-cash Expenses          (37)
  Earnings Before
    the Following            324
  Project Millennium
    Start-up                  (9)
- --------------------------------
  Total                      315
- --------------------------------
- --------------------------------
</TABLE>

Record sales volume and increased crude price, partially offset by higher
expenses and increased hedging losses, resulted in an 88% earnings
improvement.

ROYALTIES

Crown royalties payable by Suncor to the Government of Alberta increased 81%
from $48 million in 1999 to $87 million in 2000 as a result of higher sales
volumes and prices. The higher Crown royalties were partly offset by a $8
million decrease in royalties paid to Union Pacific (Union Resources Inc. now
owned by Anadarko Petroleum Corporation) because Suncor mined fewer barrels
in 2000 from the lease on which Union has a royalty interest. Mining is
currently expected to be completed on the Union lease in the 2001/2002 time
period.

The combined impact of the above factors was a net increase in total
royalties expensed, which reduced earnings by $29 million after tax.

Crown royalties in effect for Suncor's existing Oil Sands operations require
payments to the Government of Alberta of 25% of revenues less allowable costs
(including capital expenditures), subject to a minimum payment of 5% of gross
revenues. In 2000, Suncor made Crown royalty payments based on the 5% minimum
royalty. Suncor

<TABLE>
<CAPTION>
BRIDGE ANALYSIS OF
NET CASH DEFICIENCY
(CDN$ MILLIONS)
- -------------------------------------------
1999
<S>                                     <C>
- -------------------------------------------
  Total                                (597)
- -------------------------------------------
- -------------------------------------------

2000
  Operations                            292
  Working Capital                      (252)
  Investing Activities                 (630)
  Cash Flow Before the Following     (1 187)
  Project Millenium                     (42)
- -------------------------------------------
  Total                              (1 229)
- -------------------------------------------
- -------------------------------------------
</TABLE>

Capital spending on Project Millenium reached its peak in 2000, which is
reflected in increased investing activities and working capital increase due
to increased inventory value and lower payables at the end of the year. This
was only partly offset by impoved cash flow operations.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  31
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS

OVERBURDEN                                   MAINTENANCE SHUTDOWN
Material lying on top of the oil sands       Preventative maintenance activities
that must be removed before mining.          that involve shutting down major
Consists of muskeg, glacial deposits         parts of, or an entire facility.
and sand.

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 10 years (related to
Suncor's original investment in the Oil Sands facility). In 2001, the minimum
royalty rate will change to 1% of gross revenues. Suncor currently expects to
pay Crown royalties at the minimum 1% rate until 2008. This is based on
assumptions relating to future oil prices, production levels, operating costs
and capital expenditures.

EXPENSES INCREASED

Expenses in 2000 increased by 35% over 1999 levels. The increase in expenses
reduced Oil Sands earnings by approximately $115 million after tax. Cash
expenses increased, resulting in a $69 million reduction in earnings. This
was largely a result of increased sales levels and higher energy costs. Ore
quality variability encountered during the year also contributed to the
increase in costs, as operations were modified to minimize the impact. Ore
quality can be expected to vary from time to time as different parts of an
ore body are mined. Suncor will continue to assess ore quality for its impact
on operations and costs. In addition, there were higher maintenance and
operating costs relating to concurrently mining leases on both sides of the
Athabasca River. Mining operations on the original leases west of the
Athabasca River are expected to be shut down in 2001/2002, thereby
eliminating these inefficiencies.

In addition to factors related to the current operations, cash expenses
increased due to Project Millennium start-up costs of $9 million after tax.

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
CASH AND
TOTAL OPERATING COSTS
(CDN$ PER BARREL)            1996         1997        1998        1999        2000
- ----------------------------------------------------------------------------------
<S>                         <C>          <C>         <C>         <C>         <C>
Cash Operating Cost         12.40        13.25       11.75       11.70       12.55
Start-up Expenditures
  Project Millennium           --           --          --          --        1.00
Total Cash Cost             12.40        13.25       11.75       11.70       13.55
Non-cash Cost                2.40         2.55        2.25        3.35        3.70
- ----------------------------------------------------------------------------------
Total                       14.80        15.80       14.00       15.05       17.25
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
</TABLE>

Cash operating costs increased, reflecting higher operating and maintenance
costs. Non-cash costs are up as a result of the higher asset base associated
with the increased production and the acceleration of depreciation costs
associated with the original leases.

Non-cash charges (depreciation, depletion and amortization) increased by $55
million due to:

- -    mine plan changes that increased OVERBURDEN amortization charges by $11
     million,

- -    increased overburden amortization charges of $13 million due to the
     increase in production volumes,

- -    a higher depreciation expense of $18 million due to capital additions that
     increased production,

- -    higher depreciation of $11 million associated with the closing of the
     original leases earlier than anticipated, due to a 20 million barrel
     reduction in reserves recognized in 1999, and

- -    higher turnaround amortization charges of $2 million as a result of planned
     MAINTENANCE SHUTDOWN work in 1999. The $55 million increase in non-cash
     charges reduced earnings by $37 million.

PER BARREL OPERATING COSTS INCREASED

Cash operating costs increased to $13.55 per barrel in 2000, including $1 per
barrel related to Project Millennium start-up and overburden expenditures.
This compares to $11.70 in 1999. Excluding the Project Millennium component,
the increase of $0.85 per barrel is due to costs associated with higher
energy expenses and variable ore quality. The negative impact of these cost
factors was partially offset by higher volumes.

Total operating costs per barrel in 2000 were $17.25 compared with $15.05 per
barrel in 1999. Higher total operating costs were due to the same factors
that affected cash operating costs, as well as increased amortization and
depreciation expenses.


32  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                              MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS

WORKING CAPITAL                              *  This section contains forward-
The excess of current assets (excluding         looking information. Also refer
cash) over current liabilities. The excess      to the Overview *** on page 29
measures the ability of a business to           of this report.
finance current operations; for
example, whether debt will need to
be incurred to fund growth activities.

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
OPERATING MARGINS
(CDN$ PER BARREL)      1996         1997        1998        1999              2000
- ----------------------------------------------------------------------------------
<S>                   <C>          <C>          <C>          <C>       <C>
Selling Price         26.84        26.36       22.18       23.84             31.67
Cash Margin           11.75        12.05        9.25       10.75       15.80-16.80
- ----------------------------------------------------------------------------------
</TABLE>

The increase in margin in 2000 reflects a 57% increase in crude oil price
realizations and higher cash operating costs. The margin improvement was
reduced by losses associated with Suncor's hedging program that reduced the
margin by $7.55 per barrel. The variation in cash margin shows the margin
with and without the effect of start-up expenses for Project Millennium
incurred in 2000 only. Without start-up expenses, the cash margin was $16.80,
and with those expenses it was $15.80.

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.

CASH MARGIN INCREASED 47% TO $15.80 PER BARREL IN 2000

Oil Sands' cash operating margin was $15.80 in 2000 compared with $10.75 per
barrel in 1999. The following factors influenced cash margins during the year:

- -    higher crude prices (before hedging) had a favourable impact of $15.40 per
     barrel,

- -    hedging losses had an unfavourable net impact of $7.55 per barrel,

- -    cash operating costs had an unfavourable impact of $0.85 per barrel,

- -    Millennium start-up and overburden removal costs had an unfavourable impact
     of $1 per barrel, and

- -    higher royalties had an unfavourable impact of approximately $0.95 per
     barrel.

NET CASH DEFICI ENCY ANALYSIS

Cash flow provided from operations was $655 million in 2000 compared with
$405 million in 1999. An increase of $292 million was primarily due to
improved earnings. These earnings were partially offset by Project
Millennium's $42 million start-up and overburden removal costs.

Oil Sands had an increase in WORKING CAPITAL of $252 million relative to
1999. The increase was primarily due to increased inventory value and lower
accounts payable and accruals that reflected lower Project Millennium
activity at the end of 2000. Payables were lower because major components of
the project were received and paid for by the end of 2000. These factors were
partly offset by lower trade receivables in 2000 compared with 1999,
primarily due to the sale of $11 million of receivables.

Investing activities at Oil Sands increased by $630 million to $1.7 billion
in 2000 from $1.1 billion in 1999. The increase was primarily due to $1.6
billion in spending on Project Millennium (including capitalized interest of
$90 million).

These combined factors resulted in an increase in net cash deficiency from
$597 million in 1999 to $1.229 billion in 2000.

OUTLOOK*

PROJECT MILLENNIUM

Suncor's $2.8 billion Project Millennium is designed to further increase Oil
Sands production capacity, improve operational reliability and reduce
operating costs.

Project Millennium is designed to increase production capacity to 225,000
barrels per day by 2002. Suncor's production goal for 2002 is estimated at an
average of 210,000 barrels per day due to planned maintenance shutdown work
that year. In 2000, Suncor announced a long-term sales agreement with
Consumers' Co-operative Refineries Limited (CCRL). Suncor expects to begin
supplying CCRL with 20,000 barrels per day of sour crude oil production from
its Millennium expansion facilities by late 2002.

Project Millennium calls for an expanded mine, additional mining equipment,
increased energy services support and twinning of the bitumen extraction and
upgrading processes. The twinning of these facilities is expected to allow
some level of cash flow to continue during scheduled plant maintenance work
by allowing a portion of the operations to continue production while
maintenance work elsewhere at the plant is carried out.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  33
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS

PROVEN AND PROBABLE RESERVES
Annual estimates are made by Suncor of recoverable bitumen reserves
associated with Company surface mineable oil sands leases. The estimates are
allocated between proven and probable categories based upon criteria agreed
to by management and reviewed by independent consultants. The proven reserves
are considered to be conservative estimates in which there is a very high
degree of confidence. Probable reserves incorporate portions of the mine that
have a lower drilling density and are expected to be recovered under current
approvals for a period in excess of 30 years, if further expansions do not
occur. There is at least a 50 per cent chance that the proven plus probable
reserve estimates will be exceeded. The bitumen estimates are converted to
synthetic crude estimates on the basis of yields currently being obtained.

Assuming estimated economies of scale and reliability improvements are
achieved, management believes Oil Sands could reduce its cash operating costs
from its 2000 level of $12.55 per barrel (excluding Project Millennium costs)
to the $8.50 to $9.50 per barrel range in 2002. These estimates were
developed in 1998 based on an assumed natural gas price of approximately
$2.30 per thousand cubic feet (mcf), and other assumptions relating to key
variables, including the targeted level of oil production. Accordingly, these
estimates are subject to change and their achievement cannot be assured. For
example, these estimates do not include the impact of maintenance activities
now scheduled for 2002, or changes in natural gas prices which potentially
impact cash operating costs by approximately $0.50 per barrel for every $1
per mcf variance from the $2.30 per mcf assumption.

Oil Sands has PROVEN AND PROBABLE RESERVES of 422 million barrels and 2.034
billion barrels respectively on the leases it currently has regulatory
approval to mine. Management believes these reserves are sufficient to
support Project Millennium's planned production target of 225,000 barrels per
day for a period in excess of 30 years. These reserve totals do not include
the Firebag in-situ heavy oil leases described below or other oil sands
leases that Suncor owns because regulatory approval to proceed with recovery
from these leases must be obtained before reserves are recognized. Additional
reserves would only be recognized as Suncor completes further drilling and
analysis on these leases and receives approval to proceed with the Firebag
Project from the Board of Directors and regulatory authorities.

REVISED COST ESTIMATE FOR PROJECT MILLENNIUM

In October 2000, a thorough analysis was completed on Suncor's Project
Millennium that resulted in a revised capital cost estimate of $2.8 billion.
In the first quarter of 2000, Suncor had estimated project costs could be as
high as $2.45 billion, up from the original estimate of $2 billion. The
capital cost estimate increased to $2.8 billion as a result of higher labour,
fabrication and material costs and a $150 million change in the project's
scope. The additional capital costs are expected to be financed through
internally generated cash flow and additional borrowing.

Management believes that despite the added costs, Project Millennium is able
to yield economic returns in excess of its 11% cost of capital if the
benchmark WTI price averages U.S.$15 per barrel (and escalated at 2% per
year).

At year-end, the project was 70% complete with engineering finished and all
significant materials purchased. The focus for 2001 is to complete
construction and begin commissioning in the second half of 2001. Full
production capacity of 225,000 barrels per day is targeted by 2002.

RISK FACTORS RELATED TO PROJECT MILLENNIUM

At this stage, the main risks to Project Millennium execution include the
potential for reduced productivity and increased costs that can be associated
with weather or unforeseen disruptions in the supply of labour. While Project
Millennium design mainly utilizes established technologies, the commissioning
and integration of the new facilities with the existing asset base could
cause delays in achieving the targeted production capacity of 225,000 barrels
per day by 2002.

BEYOND PROJECT MILLENNIUM

In early 2000, Suncor announced a plan to further expand its oil sands
facilities beyond the Project Millennium expansion currently in process, with
a proposed investment of $750 million in the Firebag IN-SITU Oil Sands
Project and further Oil Sands plant expansion. The commercial-scale Firebag
Project is targeted to add approximately 35,000 barrels of bitumen per day in
2005. To process the additional bitumen, Suncor plans to add a vacuum tower
complex to increase Oil Sands upgrading capacity to 260,000 barrels of oil
per day in 2005. These plans are subject to Board of Directors and provincial
regulatory approvals. Suncor submitted regulatory approval applications for
the Firebag Project in 2000, and expects a regulatory decision in 2001.
Subject to these approvals, construction of facilities for the first stage is
scheduled to begin in the second half of 2001, with start-up in late 2003 and
commissioning in 2004-2005.


34  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                              MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS

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

CO-GENERATION
The simultaneous production of electricity and steam from one energy source,
e.g. natural gas.

The Company's long-term vision is to ultimately produce 140,000 barrels of
bitumen per day from the Firebag Project by the end of this decade, and to
increase total production at its Oil Sands facilities, through a combination
of oil sands mining and in-situ development, to approximately 400,000 to
450,000 barrels of oil a day in 2008. Any such plans toward realizing this
long-term vision would be subject to Board of Directors and regulatory
approvals.

LEVERAGING ALLIANCES TO SUPPORT OIL SANDS EXPANSION

In March 1999, Suncor signed an agreement with TransAlta to build, own and
operate a CO-GENERATION facility at Oil Sands with a portion of its output to
help meet Suncor's long-term electricity and steam needs. This facility
commenced operations early in 2001. TransAlta also assumed responsibility for
operating Suncor's existing utility plant at Oil Sands on October 1, 1999.

In Spring 2000, Suncor and Williams Energy Canada, Inc. (Williams) began
construction of the Hydrocarbon Liquids Conservation Project. This project is
designed to extract and separate natural gas liquids and olefins from
"off-gas," a byproduct of the Oil Sands upgrading process. The recovered
liquids and olefins will be transported in batches via Suncor's Oil Sands
pipeline to Williams' Redwater, Alberta facility for further processing.
Management believes the project will help reduce sulphur dioxide emissions at
Oil Sands and provide additional revenue for Suncor.

RISK/SUCCESS FACTORS AFFECTING OVERALL PERFORMANCE

The profitability of Suncor's Oil Sands business is influenced by world crude
oil price levels that are difficult to predict and impossible to control. In
addition, the light/heavy oil differential can have an impact on earnings. In
2000, this differential widened resulting in reduced earnings. Management
believes the differential will trend toward more historical ranges in 2001 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 from time to time.

Suncor's relationship with its employees and provincial building trade unions
is important to its future success because work disruptions have the
potential to adversely affect Oil Sands operations and growth projects.
Suncor's collective agreement with the Communications, Energy and
Paperworkers Union Local 707 expires on May 1, 2001. Management believes its
positive working relationship will continue and that a new agreement should
be reached without work interruptions.

Labour agreements with other building trades expire on April 30, 2001. While
Suncor is not a direct party to these agreements, they impact the Company as
these trades supply labour for much of Project Millennium. Project Millennium
management has developed a working relationship with the trade unions and
believes a satisfactory resolution will be reached and progress on the
project will not be impeded.

Also refer to "Environmental Regulation, Risk/Success Factors" in the
Corporate section of this MD&A.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  35
<PAGE>

MANAGEMENT'S DISCUSSION
AND ANALYSIS

NATURAL GAS

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

OVERVIEW

Suncor's Natural Gas (NG) business, based in Calgary, Alberta, explores for,
develops, produces and markets natural gas and natural gas liquids from the
Western Canada Sedimentary Basin.

In addition to conventional production, NG is acquiring land to explore for,
develop and produce coal bed methane, and is developing new service offerings
to the resource sector. To date, the coal bed methane business and service
offerings have not engaged in any material operations and have not earned any
revenues.

STRATEGIC FOCUS

In the first quarter of 2000, a study was initiated to examine ways to
improve financial and operating performance and to identify profitable growth
areas for Exploration and Production (E&P), the Company's conventional oil
and natural gas business. The information from the study was used to create
the E&P long-term strategy that repositioned the business with a focus on
natural gas and natural gas liquids, and renamed it Natural Gas (NG). NG has
a goal to achieve at least 10% return on capital within five years (at
mid-cycle commodity prices in the U.S. $3 - U.S. $3.50/mcf price range). The
strategy for improving profitability is built on a much sharper focus on
natural gas, building more competitive operating areas, improving base
business efficiency and creating new services for the resource sector.

Specific strategies implemented as a result of this repositioning have had a
significant impact on financial and operating results for 2000.

A portfolio optimization program was initiated in 1997 to improve the quality
of the conventional asset base and net cash position through the sale of
non-strategic properties. Divestments associated with the optimization were
accelerated in 2000 to sharpen NG's focus on natural gas. Divestment of
non-core assets contributed $314 million in 2000 to net cash surplus, an
increase of $224 million over 1999 contributions and $64 million over the
Company's target of $250 million. Property dispositions represented
production of 10,000 barrels of oil equivalent per day (BOE/d) (100 million
cubic feet equivalent per day (mmcfe/d)) at the time of the sale, including
7,000 BOE/d of crude oil and bitumen. As a result, NG's annual average
production for 2000 declined to 27,200 BOE/d or 272 mmcfe/d. Production came
principally from three key asset areas in western Alberta and northeastern
British Columbia. Natural gas and natural gas liquids accounted for
approximately 92% of production volume at the end of 2000.

RESULTS OF OPERATIONS/
INVESTING/EXPLORATION ACTIVITIES

2000 VS. 1999

<TABLE>
<CAPTION>

NATURAL GAS - SUMMARY OF RESULTS
- -------------------------------------------------------------------
($ millions unless otherwise noted)          2000     1999    1998
- -------------------------------------------------------------------
<S>                                         <C>      <C>      <C>
Revenue                                       428      306      290
Conventional production
  (thousands BOE/d)                          27.2     36.0     41.0
Average sales price
(including impact of hedging)
  Natural gas
    ($/thousand cubic feet)                  4.72     2.44     1.95
  Crude oil ($/barrel)                      29.50    20.94    20.14
Operational earnings                           59       22       21
Net earnings                                   98       41       24
Cash flow provided
  from operations                             238      172      167
Total assets                                  762      962      943
Capital and exploration
  expenditures                                127      200      242
Return on capital
  employed (%)                               17.2      5.5      3.3
- -------------------------------------------------------------------
</TABLE>


36 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                            MANAGEMENT'S DISCUSSION AND ANALYSIS - NATURAL GAS

[GRAPHIC OF NORTH AMERICA HIGHLIGHTING ALBERTA CITIES]

We have made significant progress in our strategy to sharpen our focus on
natural gas and reduce our costs. We'll continue to look for profitable
opportunities for growth.

[PHOTOGRAPH OF DAVE BYLER]

DAVE BYLER
Executive Vice President,
Natural Gas

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

EARNINGS ANALYSIS

EARNINGS INCREASED BY 139% ON ASSET DIVESTMENT GAINS AND STRONGER COMMODITY
PRICES

Net earnings were up more than 139% over 1999 levels to $98 million, primarily
due to divestment gains and stronger natural gas prices. Operational earnings,
which exclude the impact of asset divestments and restructuring charges,
increased by $37 million to $59 million in 2000 from $22 million in 1999. This
was primarily due to higher commodity prices and was partially offset by lower
production volumes and higher exploration and royalty expenses.

Cash flow from operations rose to $238 million from $172 million in 1999,
again mainly due to higher natural gas prices.

NATURAL GAS PRICES INCREASED 93%

In 2000, NG's price averaged $4.72 per thousand cubic feet (mcf) of natural gas,
compared with $2.44 per mcf in 1999.

<TABLE>
<CAPTION>
- --------------------------------
BRIDGE ANALYSIS
OF EARNINGS
(CDN$ MILLIONS)
- --------------------------------
1999
<S>                         <C>
- --------------------------------
  Total                       41
- --------------------------------
- --------------------------------

2000
  Price                       94
  Volume                     (35)
  Royalties                  (28)
  Expenses                     6
  Earnings Before
    the Following             78
  Divestment
    Gains                     50
  Restructuring
    Costs                    (30)
- --------------------------------
  Total                       98
- --------------------------------
- --------------------------------
</TABLE>

Higher commodity prices and divestment gains more than offset the decline in
production from divestments and restructuring costs.

Increased prices in 2000 were a result of increased demand and improved
access to U.S. markets coupled with a relatively flat natural gas supply in
North America. While crude oil made up only 15% of NG's production in 2000,
crude prices were also higher, averaging $29.50 per barrel (after hedging
losses), compared to $20.94 per barrel (after hedging losses) in 1999.

The combined impact of the above pricing factors increased earnings by
$94 million.

PRODUCTION DECLINED 24% FROM 1999 LEVELS

NG's natural gas and liquids volumes declined to an average of 27,200 BOE/d
(272 mmcfe/d) in 2000, from an average of 36,000 BOE/d in 1999. The main
reasons for production declines were asset divestments associated with
portfolio optimization during 1999 and 2000 (representing annual production
of 1,500 and 5,500 BOE/d respectively) and natural reservoir declines. The
decrease in volumes reduced earnings by $35 million compared to 1999.

<TABLE>
<CAPTION>
- --------------------------------
BRIDGE ANALYSIS
OF NET CASH SURPLUS
(CDN$ MILLIONS)
- --------------------------------
1999
<S>                          <C>
- --------------------------------
  Total                       89
- --------------------------------
- --------------------------------

2000
- --------------------------------
  Operations                  66
  Capital and
    Exploration
    Expenditures              72
  Divestment
    Proceeds                 224
- --------------------------------
  Total                      451
- --------------------------------
- --------------------------------
</TABLE>

Year-over-year improvement of $362 million in NG's net cash flow was the
result of lower capital and exploration spending, proceeds from property
dispositions and higher operating cash flow due to higher commodity prices.


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 37
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - NATURAL GAS

* This section contains forward-       RESTRUCTURING CHARGES
  looking information. Also refer to   See note 3 to the Consolidated
  the Overview *** on page 29 of       Financial Statements.
  this report.

ROYALTIES INCREASED WITH HIGHER COMMODITY PRICES

Royalties increased to $11 per BOE ($1.10 per mcfe) in 2000, from $4.26 per BOE
($0.43 per mcfe) in 1999 due mainly to the increase in commodity prices. The
increase in royalties reduced earnings by $28 million.

TOTAL EXPENSES REDUCED FROM 1999 LEVELS

Total expenses, excluding royalties and RESTRUCTURING CHARGES, were reduced by
$12 million in 2000 from 1999 levels. This reflected divestment activity in 1999
and 2000. Lower non-cash expenses and lower operating expenses were partially
offset by higher exploration expenses.

Non-cash expenses (depreciation, depletion and amortization) decreased by $9
million as a result of asset divestments. Operating expenses were reduced by
$14 million compared to 1999 levels, due to asset divestments and improved
base business efficiency. Exploration expenses were up $13 million in 2000
over 1999 due primarily to an increase in dry hole costs.

Combined, the above factors increased earnings by $6 million year-over-year.

ASSET DIVESTMENT GAINS

Completion of NG's portfolio optimization program in 2000 yielded after-tax
gains of $69 million, $50 million higher than the gains reported in 1999.

RESTRUCTURING CHARGES

As a result of restructuring, charges of $65 million were recorded in the
year. Earnings were reduced by $30 million.

NET CASH SURPLUS ANALYSIS

NG had a net cash surplus of $451 million in 2000, an improvement of $362
million compared to the net cash surplus of $89 million in 1999. This
improvement was due to an increase in divestment proceeds of $224 million, a
reduction in capital and exploration investing activities of $72 million and
an improvement in cash from operating activities of $66 million.

<TABLE>
<CAPTION>
- ---------------------------------------------------------------------
TOTAL PROVED RESERVES
(MILLIONS OF BARRELS OF
 OIL EQUIVALENT)             1996     1997     1998     1999     2000
- ---------------------------------------------------------------------
<S>                          <C>      <C>      <C>      <C>      <C>
Natural Gas                    99      109      120      101       80
Liquids                        65       70       69       51       16
- ---------------------------------------------------------------------
Total                         164      179      189      152       96
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
</TABLE>

During 2000, Natural Gas focused on rationalizing its asset base, primarily
through the sale of oil properties, and bringing proven undeveloped reserves
into production.

CAPITAL AND EXPLORATION INVESTING ANALYSIS

In 2000, NG's capital expenditures were $127 million, $73 million less than
in 1999. This resulted from less exploration drilling, no heavy oil
expenditures and lower gas plant, facility and well equipment expenditures.
Divestment proceeds increased $224 million as a result of completing the
strategic divestment program. The positive cash flow from net investing
activities was part of NG's cash flow management program to support other
Suncor growth initiatives.

During 2000, Natural Gas focused on rationalizing its asset base and bringing
proven undeveloped reserves into production. This increased the five-year
finding and development costs (excluding acquisitions) to $11 per BOE, for
the five-year period ended 2000, from $8.25 per BOE, for the five-year period
ended 1999.

During 2000, negative proven reserve revisions of eight million BOE
(approximately 5.5% of reserves at the beginning of 2000) were recorded. This
adjustment reflected a combination of lower than expected production and new
information, which resulted in the downward revision. Future revisions
- - positive or negative - are dependent upon such factors as actual production
from reservoirs, operating costs, price assumptions and plans associated with
the presence of infrastructure. These revisions were partially offset by
reserve additions of five million BOE.

OUTLOOK*

Management expects the Company's natural gas strategy announced in April of
2000 will improve the bottom line of the Natural Gas business that is
strategically important to Suncor. Natural gas production continues to
benefit Suncor because it diversifies the Company's product portfolio and
supplies a cleaner burning fuel, relative to crude oil, to meet growing
market demand in North America.

Natural gas production also provides a natural hedge against growing internal
natural gas demands.

<TABLE>
<CAPTION>
- ---------------------------------------------------------------------
NATURAL GAS PRICING
VS. INDUSTRY AVERAGE
(CDN$/THOUSAND
 CUBIC FEET)                 1996     1997     1998     1999     2000
- ---------------------------------------------------------------------
<S>                          <C>      <C>      <C>      <C>      <C>
Suncor Average
  Annual Price               1.50     1.93     1.95     2.44     4.72
Industry Average
  Reference Price            1.64     1.98     1.95     2.47     4.43
- ---------------------------------------------------------------------
</TABLE>

NOTE: 2000 Industry average reference price is an estimate.


38 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                            MANAGEMENT'S DISCUSSION AND ANALYSIS - NATURAL GAS

During 2000, NG reduced annualized costs by approximately $15 million,
approximately 80% of its $18 million to $20 million target. Consolidation of
the asset base, organizational restructuring and a reduction of about 70
positions in the NG workforce contributed to reduced operating costs.

The remainder of the $18 million to $20 million annualized cost reduction
target is expected to be achieved through active management of general and
administrative costs. Plans to further improve efficiency and lower operating
costs will focus on strategic partnerships, operating alliances and
technology applications.

Divestments associated with portfolio optimization generated $314 million for
the Company in 2000. With this transition now complete, management expects
any acquisitions and divestments of conventional assets that may occur in
2001 will further focus NG on growth and consolidation around its three core
areas in western Alberta and northeastern British Columbia.

COAL BED METHANE

In 2000, NG continued to investigate coal bed methane (CBM) as a new natural
gas source for the Company. Other companies have commercially viable CBM
production in the United States. Suncor is currently examining the viability
of CBM projects in the United States, Australia and Canada. At year-end,
Suncor had no CBM operations, but did have property in Australia, the United
States and Canada, and options with respect to property in the United States.

In addition to its potential to add to Suncor's natural gas volumes, some
methods of CBM production may have unique environmental benefits. Suncor is
participating in research and development initiatives to investigate the
potential of coal beds to sequester carbon dioxide (CO2), awaste greenhouse
gas emission. In addition, CO2 pumped into the coal bed may provide an
economic means of increasing production of natural gas from the coal.

<TABLE>
<CAPTION>
- -----------------------------------------------------
2000 SUNCOR NATURAL GAS MARKETS
- -----------------------------------------------------
                                   (mmcf/d)      (%)
<S>                                <C>           <C>
System                                   59       30
Direct                                  141       70
- -----------------------------------------------------
Total                                   200      100
- -----------------------------------------------------
- -----------------------------------------------------
</TABLE>

Natural Gas believes its gas portfolio is positioned to take advantage of
improved pricing fundamentals.

RISK/SUCCESS FACTORS AFFECTING PERFORMANCE

The risks associated with Suncor's natural gas activities and commodity pricing
should not be underestimated or viewed as predictable. Suncor expects that both
natural gas and crude oil pricing will continue to be volatile due to the
cyclical nature of supply and demand for these commodities.

Management continues to believe the single most important factor that will
influence Natural Gas' 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. The Company continues to work at reducing
these risks through proactive consultation with stakeholders.

Also refer to "Environmental Regulation Risk/Success Factors" in the
Corporate section of this MD&A.

<TABLE>
<CAPTION>
- -----------------------------------------------------
DIRECT PROPRIETARY GAS SALES
- -----------------------------------------------------
                                   (mmcf/d)      (%)
<S>                                <C>           <C>
British Columbia                         13        9
Midwest U.S.                             15       11
Eastern Canada                           26       19
California                               40       28
Alberta                                  47       33
- -----------------------------------------------------
Total                                   141      100
- -----------------------------------------------------
- -----------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
- -----------------------------------------------------
SYSTEM PROPRIETARY GAS
- -----------------------------------------------------
                                   (mmcf/d)      (%)
<S>                                <C>           <C>
TransCanada Gas Services                 31       53
Pan Alberta                              17       29
Canwest                                   2        3
Other                                     9       15
- -----------------------------------------------------
Total                                    59      100
- -----------------------------------------------------
- -----------------------------------------------------
</TABLE>


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 39
<PAGE>

MANAGEMENT'S DISCUSSION
AND ANALYSIS

DISTILLATES
Diesel, jet fuels and heating oils.

Sunoco

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

OVERVIEW

Sunoco Inc., Suncor's wholly owned subsidiary, operates a refining and
marketing business in central Canada. Sunoco is strategically integrated with
Suncor's upstream Oil Sands operations in western Canada. Its Sarnia Refinery
effectively integrates Suncor's upstream and downstream businesses as part of
the "value chain." The refinery has the capacity to refine 70,000 barrels of
petroleum feedstocks from Oil Sands and other sources into gasoline,
DISTILLATES and petrochemicals. Sunoco, in turn, benefits from having access
to a reliable, long-term supply of Oil Sands feedstocks. This integration
strengthens the Company as a whole.

Sunoco markets 57% of the refinery's production through controlled
distribution networks in Ontario that sell gasolines and diesel to retail
customers. These are:

- -    301 Sunoco retail service stations,

- -    11 Sunoco-branded Fleet Fuel Cardlock sites,

- -    154 Pioneer-operated retail service stations (Pioneer Group Inc. is an
     independent retailer with whom Sunoco has a 50% joint venture partnership),
     and

- -    54 UPI-operated retail service stations and a network of bulk distribution
     facilities for rural and farm fuels. (UPI Inc. is a 50% joint venture
     company owned by Sunoco and GROWMARK Inc., a Midwest U.S. agricultural
     supply and grain marketing co-operative.)

Approximately 40% of Sunoco's refined products were sold to wholesale and
industrial accounts in Ontario and Quebec. Jet fuels, diesel and gasolines
comprised the highest volume of sales.

The remaining 3% of Sunoco's total refined products sales were petrochemicals
sold through Sun Petrochemicals Company, a 50% joint venture between Sunoco
and a U.S. refinery.

Sunoco's Integrated Energy Solutions business has been marketing natural gas
in Ontario since 1997. Sunoco serves more than 130,000 commercial and
residential customer accounts in Ontario.

RESULTS OF OPERATIONS AND INVESTING ACTIVITIES

2000 VS. 1999

SUNOCO RESULTS SUMMARY

<TABLE>
<CAPTION>
- -----------------------------------------------------------------
($ millions unless otherwise noted)      2000      1999      1998
- -----------------------------------------------------------------
<S>                                     <C>       <C>       <C>
Revenue                                 2 604     1 779     1 533
Refined product sales
(thousands of cubic metres)
  Sunoco retail gasoline                1 539     1 500     1 496
Total                                   5 360     5 080     5 037
Earnings (loss) breakdown:
  Refining/wholesale                       66        10        22
  Retail marketing                          9        21        16
  Energy marketing                         (7)       (4)       (1)
  Others (tax adjustments)                 13        --        --
Total                                      81        27        37
Cash flow provided
  from operations                         174       103       112
Investing activities                       59        43        64
Net cash surplus                          155       129        55
Return on capital
  employed (%)                           20.5       6.0       7.4
- -----------------------------------------------------------------
</TABLE>


40  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                 MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO

[GRAPHIC OF NORTH AMERICA HIGHLIGHTING ONTARIO CITIES]

[PHOTOGRAPGH OF TOM RYLEY]

We continue to assess opportunities to expand Sunoco's customer offering in
Ontario, and that includes marketing more environmentally focused fuels and
possibly electricity.

TOM RYLEY
Executive Vice President,
Sunoco

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

<TABLE>
<CAPTION>
- -----------------------------------------------------------
SUNOCO SALES BY CHANNEL
(PERCENTAGE)
- -----------------------------------------------------------
<S>                                                     <C>
Sunoco Retail Service Stations, Cardlock Sites,
  and Joint-Venture Operated Sites*                      57
Wholesale/Industrial                                     40
Sun Petrochemicals Company                                3
- -----------------------------------------------------------
</TABLE>

*Controlled distribution channel

<TABLE>
<CAPTION>
BRIDGE ANALYSIS
OF EARNINGS
(CDN$ MILLIONS)
- --------------------------------
1999
<S>                          <C>
- --------------------------------
  Total                       27
- --------------------------------
- --------------------------------

2000
  Margin                      45
  Volume                       8
  Ancillary Income             9
  Joint Ventures               1
  Integrated Energy
    Solutions                 (3)
  Expenses                   (19)
  Tax Rate Adjustment         13
- --------------------------------
  Total                       81
- --------------------------------
- --------------------------------
</TABLE>

Higher refining margins and volumes were the key factors of improved
operating earnings in 2000. Tax adjustments related to revaluation of future
income tax balances further increased total earnings by $13 million.

EARNINGS AND BUSINESS ANALYSIS

OVERALL EARNINGS HIGHEST ON RECORD

Sunoco's earnings rose to $81 million in 2000, compared with $27 million in
1999 - its best earnings on record. This improvement was mainly due to higher
volumes and refining margins, but was partially offset by lower retail
margins, higher expenses and losses in Integrated Energy Solutions.
Reductions in income tax rates in 2000 increased earnings by a further $13
million due to the revaluation of future income tax balances. Return on
capital employed rose to 20.5%, compared with 6% in 1999, due primarily to
improved earnings.

<TABLE>
<CAPTION>
BRIDGE ANALYSIS OF
NET CASH DEFICIENCY
(CDN$ MILLIONS)
- -------------------------------------------
1999
<S>                                     <C>
- -------------------------------------------
  Total                                 129
- -------------------------------------------
- -------------------------------------------

2000
  Operations                             71
  Working Capital                       (29)
  Investing Activities                  (16)
- -------------------------------------------
  Total                                 155
- -------------------------------------------
- -------------------------------------------
</TABLE>

Improvement in cash flow from operations was partially offset by a lower
reduction in working capital compared to 1999. Total capital spending was
higher than 1999 due to planned maintenance work completed at the Sarnia
Refinery.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  41
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO

REFINING EARNINGS UP $56 MILLION OVER LAST YEAR

Earnings from refining activities increased to $66 million in 2000 compared
with $10 million in 1999. Sales of refined products averaged 92,200 barrels
per day (bpd), compared with 86,800 bpd in 1999. The higher refining earnings
were largely a result of an increase in refining margins to 5.9 cents per
litre (cpl) compared with 4 cpl in 1999, due to tight international supply
and demand for gasoline and distillates. This factor alone increased
year-over-year earnings by $47 million. Higher wholesale gasoline and
distillate sales volumes increased refining earnings by $6 million over 1999.
Improved performance in joint venture investments also increased earnings by
$2 million over last year, due primarily to improved margins. Refining
earnings were further improved as a result of a $5 million benefit from
selling lower cost inventory as described in Note 8 to the Consolidated
Financial Statements.

During the year, the Sarnia Refinery completed a planned turnaround on time
and within budget. However, several unplanned outages at the refinery during
the year tightened the product supply and required additional purchases to
meet customer demand. Total expenses increased by $7 million over 1999. This
was due to higher natural gas and steam costs, and higher freight costs due
to operational outages. The increase in expenses was partially offset by a $3
million mark-to-market gain on the forward purchase of crude oil.

Sunoco cardlock diesel sales volumes doubled in 2000 due to marketing
initiatives and an expansion of the diesel cardlock network. At the end of
the year, Sunoco signed a joint venture agreement with Fifth Wheel
Corporation, a major truck stop operator, which will provide Sunoco with
another controlled distribution channel for distillates sales.

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
MARGIN
(CDN CENTS PER LITRE)        1996         1997        1998        1999        2000
- ----------------------------------------------------------------------------------
<S>                          <C>          <C>         <C>         <C>         <C>
Sunoco-based Retail
  Gasoline Margin             5.7          6.8         7.0         7.4         6.6
Refining Margin               4.4          4.6         4.1         4.0         5.9
- ----------------------------------------------------------------------------------
</TABLE>

Refining margins improved from last year due to the tight supply situation
North America experienced during the year. Retail margins declined, on the
other hand, as the rapidly rising costs of crude oil could not be fully
recovered.

REDUCED MARGINS IMPACT RETAIL MARKETING PROFITABILITY

Earnings from retail marketing declined to $9 million in 2000 compared with
$21 million in 1999. Total retail volumes at Sunoco retail service stations
grew more than 2% in 2000, increasing earnings by $2 million over 1999.
However, retail gasoline margins from the Sunoco branded network decreased $7
million from 1999 (6.6 cpl in 2000 compared with 7.4 cpl in 1999). Margins
were negatively impacted because the rapidly increasing crude costs could not
be fully recovered. Similarly, joint venture profitability declined $1
million from prior year, although total sales volumes improved by more than
5% over 1999.

Sales of premium products, such as Ultra 94, also declined due to the
significant crude oil-driven increase in retail prices during the year. In
2000, a new retailer agreement with different cost and revenue allocations
was implemented, contributing to a $15 million increase in total expenses
over 1999. This increase was partially offset by a corresponding increase of
$9 million in ancillary income and royalties under the new arrangement. The
net increase of $6 million was due mostly to commencement of a pilot internet
marketing site and higher costs associated with customer loyalty programs and
bank credit cards. These cost increases resulted from higher retail prices.

Average throughput at Sunoco-branded sites grew 4% in 2000, to 5.3 million
litres per site from 5.1 million litres per site in 1999. The increased
efficiency reflects improvement in retail volumes resulting from marketing
initiatives.

Sunoco's customer loyalty program with the Canadian Automobile Association's
(CAA) Ontario clubs has continued to gain popularity since its introduction
in 1998. In 2000, Sunoco encouraged an additional 15% of CAA members to use
their cards to earn savings on CAA membership when purchasing Sunoco products
and services. Sunoco now serves more than 66% of the 1.8 million CAA members
in Ontario.


42  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                 MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO

*  This section contains forward-
   looking information. Also refer
   to the Overview *** on page
   29 of this report.

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
SUNOCO-BRANDED RETAIL
NETWORK EFFICIENCY*
(MILLIONS OF LITRES PER SITE)        1996         1997        1998        1999        2000
- ------------------------------------------------------------------------------------------
<S>                                  <C>          <C>         <C>         <C>         <C>
Throughput                            4.2          4.3         5.0         5.1         5.3
Number of Sites                       333          332         310         305         301
- ------------------------------------------------------------------------------------------
</TABLE>

Site throughput continued to improve, reflecting higher volumes that resulted
from marketing initiatives such as the loyalty program with the Canadian
Automobile Association (CAA).

*  THROUGHPUT PER SITE - Millions of litres per site based on the average
   number of sites at the beginning and end of the year.

   SITES - Number at year-end, excluding joint venture owned sites.

Sunoco launched a branded Affinity Card Program in July to further strengthen
customer loyalty. This program offers discounts to natural gas customers to
encourage retail product purchases.

Sunoco's joint venture investment, Pioneer Petroleums, was named a winner of
"Canada's 50 Best Managed Private Companies Program" for 2000, sponsored by
Arthur Andersen, CIBC and the NATIONAL POST.

INTEGRATED ENERGY SOLUTIONS LOSES $7 MILLION

Integrated Energy Solutions (IES), Sunoco's retail natural gas marketing
division, lost $7 million in 2000 compared with a loss of $4 million in 1999.
The rapid increase in natural gas prices during 2000 was a major factor,
since some of Sunoco's customer contracts were tied to regulated rates that
lagged the rising market prices. Over 95% of these agreements have now been
restructured to match fixed price sales contracts with fixed price supply,
and yield a positive margin in 2001.

IES exited the heating, ventilation and air conditioning market in 2000, and
closed its Home Energy Dealer Network. These decisions do not affect Sunoco's
interests in the natural gas marketing business. Costs associated with the
shutdown were not material to Sunoco's overall earnings.

NET CASH SURPLUS ANALYSIS

Net cash flow increased to $155 million in 2000 compared with $129 million in
1999. Cash flow from operations increased to $174 million compared with $103
million in 1999. This was primarily a result of the higher earnings from the
refining operations, which were partially offset by lower retail earnings.

Working capital decreased by $40 million in 2000, down $29 million compared
with a $69 million decrease in 1999. The decline was due to a $25 million
unfavourable change in current assets, due mostly to higher trade receivables
reflecting the increased sales volumes and higher product prices, and lower
reduction in inventory compared with 1999. Net change in cur rent liabilities
was $4 million lower than 1999, resulting from the increased costs of
feedstocks purchased.

Capital spending increased to $59 million versus $43 million in 1999,
primarily due to a major hydrocracker maintenance shutdown at the Sarnia
Refinery.

OUTLOOK*

Sunoco has identified five focus areas:

- -    Maximize refinery competitiveness,

- -    Increase business integration,

- -    Continue to grow core business,

- -    Capitalize on long-term growth opportunities, and

- -    Continue to improve environmental performance.

MAXIMIZING REFINERY COMPETITIVENESS

Sunoco's goal is to achieve levels of profitability and efficiency at the
Sarnia Refinery by 2002 to position it in the top one-third of North American
refineries of similar size and complexity. A three-year organizational
realignment to reduce refining costs is expected to be completed in 2001.
Plans are in place to improve energy efficiency and enhance systems processes.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  43
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO

ANCILLARY INCOME
Income earned from such activities
as car washes, sale of fast foods and
confectionary items.

To reduce exposure to energy cost increases expected when the electricity
market deregulates, the refinery negotiated a fixed rate supply contract to
lock in the cost of a portion of its electricity for three years from the
date that electricity deregulation begins. In addition, negotiations continue
with TransAlta Energy Corporation to purchase steam and electricity from the
Sarnia Regional Co-generation Project that is expected to commence at the end
of 2002.

INCREASED BUSINESS INTEGRATION

Sunoco restructured in 2000 to increase operating efficiencies. The changes
are designed to enable Sunoco to better execute its business strategies by
providing greater focus on Sunoco-wide performance. No significant changes
have been made to Sunoco's business strategies. The reorganization reduces
the number of business units from three to two, called Rack-Back and
Rack-Forward. Sunoco will base its financial reporting on this structure
starting January 1, 2001.

Under the new structure, Rack Forward will include retail operations,
wholesale and commercial sales, natural gas marketing, and the UPI and
Pioneer joint venture investments. Rack Back will include refining operations
and sales to the refinery's largest industrial and reseller customers,
including Sun Petrochemicals Company.

CONTINUED CORE BUSINESS GROWTH

Rack-Forward will continue to focus on marketing Sunoco-branded products,
managing retail assets, wholesale and commercial sales, joint venture
investments, UPI and Pioneer, and natural gas retail sales.

Plans are in place to:

- -    Integrate marketing strategies across all sales channels to increase
     effectiveness and reduce costs,

- -    Implement initiatives to increase sales of premium products, such as Gold
     Diesel, and to reposition and regain sales volumes of Ultra 94,

- -    Grow non-fuel revenues (ANCILLARY INCOME) in a capital-effective manner
     through value-added strategic alliances, and

- -    Continue to develop strategies to increase distillates sales.

Rack-Back is responsible for the procurement and manufacturing of a
cost-competitive and reliable supply of petroleum and other energy products.
In addition, Rack-Back is responsible for managing sales and distribution to
the refinery's largest industrial and reseller customers.

Rack Back will also focus on:

- -    Creating strategies to reduce product costs, optimize production and
     improve supply-chain and energy-cost management for long-term growth and
     competitiveness,

- -    Positioning Sunoco to meet legislated limits on sulphur content in gasoline
     and diesel, which will be phased in between 2002-2005, and

- -    Developing economic options to reduce air emissions at the Sarnia Refinery
     to help meet Suncor's vision of long-term sustainability.

CAPITALIZE ON LONG-TERM GROWTH OPPORTUNITIES

Sunoco continues to assess the potential to market electricity in Ontario
subsequent to the pending deregulation of electricity services. In
conjunction with Suncor's Alternative and Renewable Energy business
development group, Sunoco will continue to explore additional energy
opportunities in its markets.

To further integrate Suncor's upstream and downstream businesses, Sunoco
continues to assess new marketing and refining investment opportunities to
grow the future value of Suncor and to capture the greatest long-term value
from the increasing production from Oil Sands.


44  SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                                 MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO

CONTINUE TO IMPROVE ENVIRONMENTAL PERFORMANCE

Sunoco continues to focus on environmental issues facing Ontario and Canada
and to develop more environmentally responsible products. For example, in an
effort to reduce carbon monoxide and carbon dioxide emissions, the
Sunoco-branded retail network introduced ethanol-enhanced gasoline in late
1997. In 2000, Pioneer Petroleums, Sunoco's joint venture partner, expanded
the market share of ethanol-enhanced gasoline when it joined Sunoco and UPI
stations in selling the product.

Sunoco's certification to display Environment Canada's EcoLogo at its
gasoline pumps and car washes demonstrates Sunoco's active commitment to
offer products and services that meet the Canadian government's environmental
labelling guidelines.

Reducing smog is an important goal for Sunoco. Sunoco continues to
participate in Ontario's Pilot Emission Reduction Project by using a gasoline
additive that reduces nitrogen oxides (NOX) from tailpipe emissions. This
generated a total of 825 tons of NOX credits for Sunoco in 2000 compared with
275 tons of NOX emission credits in 1999. The 1999 emission reduction credits
were sold to Ontario Power Generation Inc., and the proceeds were used to
conduct a refinery-wide emission inventory assessment in 2000.

To support Suncor's goal of meeting or exceeding national and international
commitments on greenhouse gas emissions, Sunoco is developing a plan in 2001
to reduce emissions at the Sarnia Refinery by 25% from 1995 levels by 2005.

In 2000, Sunoco worked with Conestoga-Rovers and Associates to pursue
opportunities to produce energy from Ontario landfills. Methane gas from
landfill sites has the potential to provide a reliable source of fuel for
heating and generating electricity and carbon dioxide for possible commercial
use. Landfill gas recovery also reduces greenhouse gas emissions and landfill
odours.

RISK/SUCCESS FACTORS AFFECTING PERFORMANCE

While the downstream business environment improved in 2000 (as reflected in
the overall performance), management expects fluctuations in demand for
refined products, margin volatility and overall marketplace competitiveness
will continue. Management believes the margin and price volatility and the
below average inventory levels in crude and refined products that North
America experienced in 2000 will continue to impact the business environment
in which Sunoco operates in 2001. As Sunoco enters new markets, such as
electricity retailing, it could be exposed to margin risk and volatility from
either cost and/or selling price fluctuations or risks inherent in entering
new markets.

The Canadian refining industry faces significant capital spending to
construct sulphur removal facilities. This capital expenditure is required
following the passage of legislation that limits 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. Actual capital spending required to
meet the new standard is subject to the findings of a strategic assessment
that is under way. A detailed implementation plan will be completed in 2001.
No regulations have been tabled at this time with respect to sulphur levels
in diesel, although Suncor expects limits that will be lower than its current
capabilities. The cost to comply with these anticipated sulphur in diesel
limits could be significant but are not expected to place the Company at a
competitive disadvantage.

Also refer to "Environmental Regulation Risk/Success Factors" in the
Corporate section of this MD&A.


                                     SUNCOR ENERGY INC. 2000 ANNUAL REPORT  45
<PAGE>


MANAGEMENT'S DISCUSSION AND ANALYSIS

CORPORATE

SALE                                  LONG-TERM EMPLOYEE INCENTIVE PLAN
See note 5 to the Consolidated        See note 13 (b) to the Consolidated
Financial Statements.                 Financial Statements.

LINES OF CREDIT
See note 12 the the Consolidated
Financial Statements.

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

OVERVIEW

Suncor's corporate centre fulfills a number of roles that include supporting the
Company's business units and Board of Directors. Corporate centre personnel are
accountable for functions such as legal, taxation, risk management, company-wide
human resource programs, treasury, corporate finance, alternative and renewable
energy investment assessments, planning and business development, corporate
communications and regulatory reporting at the corporate level.

RESULTS OF OPERATIONS AND INVESTING ACTIVITIES

2000 VS. 1999
EXPENSES INCREASED

Corporate expenses increased to $117 million in 2000 from $49 million in
1999. The primary reasons for the $68 million increase were an $80 million
write-down of the carrying value of Suncor's investment in the Stuart Oil
Shale Project in Australia and the expensing of additional costs of $12
million on the Stuart Project. These were partially offset by a foreign
exchange gain of $11 million as the Australian dollar weakened against the
Canadian dollar. Higher corporate expenses were partially offset by a lower
interest expense of $10 million and a reduction in other expenses of $3
million. The reduction in interest expense is due to higher capitalization of
interest expenses associated with Project Millennium capital spending.

The corporate centre had a net cash deficiency of $76 million in 2000,
largely unchanged compared to the net cash deficiency of $73 million in 1999.

CONSOLIDATED BALANCE SHEET ANALYSIS

Higher commodity and refined petroleum product prices and higher sales
volumes at the end of 2000 compared to the end of 1999 increased accounts
receivable by $165 million. This increase was partially offset by the SALE of
$35 million in accounts receivable.

An inventory increase of $31 million represents an increase in upstream
inventory levels to reflect crude oil sales in transit at year-end. It is
expected there will be a reduction in the inventory level in the first
quarter of 2001.

Net capital assets increased by $1.4 billion in 2000. Capital assets
increased by $1.7 billion due to Suncor's Project Millennium. These increases
were partially offset by the sale in 2000 of Natural Gas capital assets with
a net book value of $167 million and a $56 million write-down of capital
assets in the Natural Gas business due to the change in strategy. There was
also a before-tax write-down of $125 million in the carrying value of the
Stuart Oil Shale Project asset.

Trade payables and accrued liabilities were $709 million at the end of 2000,
$93 million higher than at the end of 1999. With the majority of material
purchases now completed on Project Millennium, the project liabilities
decreased by $86 million from year-end 1999. More than offsetting this
decrease were higher liabilities associated with buying crude oil, feedstocks
and refined products from third parties. A portion of the refined product
purchases were required in the downstream business due to several unplanned
outages at the Sarnia Refinery. Other factors that increased year-end
payables and accrued liabilities were higher royalties, resulting from higher
commodity prices, and an increase in reclamation activities in all three
operating businesses.

Excluding cash, short-term borrowings and the current portion of long-term
borrowings, Suncor had a working capital deficiency of $128 million at the
end of 2000 compared to a deficiency of $225 million at the end of 1999. This
$97 million improvement primarily reflected the impact of higher commodity
prices. Suncor had in place $1.5 billion in unused LINES OF CREDIT to cover
working capital deficiencies. With Project Millennium targeted to be in
operation at the end of 2001, the working capital position is expected to
improve, with the additional revenue resulting from the anticipated higher
production levels.


46 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                              MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE

[GRAPHIC OF NORTH AMERICA HIGHLIGHTING ALBERTA CITIES]

Corporate Office employees are charged with supporting the goals of each of
Suncor's businesses and developing strategic growth plans for the Company that
ensure growth occurs in a sustainable manner and maximum shareholder value is
created and optimized.

[PHOTOGRAPH OF MIKE O'BRIEN]

MIKE O'BRIEN
Executive Vice President,
Corporate Development and
Chief Financial Officer

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

For a description of future income tax assets and liabilities on the balance
sheet refer to Note 6 in the Consolidated Financial Statements. These balances
are expected to fluctuate based upon future earnings and capital expenditure
levels. They could also fluctuate if government tax laws and regulations change.

CONSOLIDATED EARNINGS ANALYSIS

Sales and other operating revenues increased to $3,385 million in 2000, up
from $2,383 million in 1999. The impact of higher commodity prices, both in
the upstream and downstream businesses, increased revenues by $928 million.
There were two factors that partially offset the benefit of the higher prices
and are reflected in the $928 million figure. One is the impact of hedging
activity in 2000, which reduced year-over-year revenues by $336 million. The
second factor that reduced revenues in 2000 was lower prices from sour crude
oil sales due to widening of the light/heavy crude oil differential.

Management believes the differential in 2001 will return to levels within a
more historical range as demand is expected to increase, but the timing is
difficult to predict because the determining factors are beyond Suncor's
control. While crude oil sales volumes increased due to record Oil Sands
sales levels, a decrease in conventional liquids and natural gas volumes
resulted in a net $42 million negative impact on revenue. Downstream sales
volumes increased 6%, adding $98 million to consolidated revenues. Additional
ancillary income of $18 million was also recorded in the year.

The impact of higher feedstock and refined product prices in 2000 impacted
Suncor's downstream business, which purchased both feedstocks and refined
products. In 2000, a planned 32-day maintenance shutdown of the hydrocracker
unit that produces transportation fuels, and operating difficulties in the
fourth quarter, necessitated the purchase of additional finished product to
meet customers' requirements. These factors increased costs for the year by
$288 million.

Operating, selling and general expenses increased by $144 million, to $918
million in 2000 from $774 million in 1999. Higher operating costs in all
operations represented $147 million of the year-over-year increase. The
higher operating costs were due mainly to higher Oil Sands volumes, variable
ore quality, higher energy costs, higher reclamation expense activities and
higher maintenance costs at both Oil Sands and the Sarnia Refinery. The
higher maintenance costs reflected a three-week period of extremely cold
weather at Oil Sands and problems with major units at the Sarnia Refinery
during the fourth quarter.

Increased operating costs were also due to higher expenditures in Sunoco's
branded marketing operations. These included costs associated with increasing
ancillary revenue, higher advertising expenses, as well as increased bank
credit card costs due to the impact of higher crude oil prices that were
reflected in higher selling prices and higher volumes. In addition, expenses
also increased by $8 million due to a higher provision for LONG-TERM EMPLOYEE
INCENTIVE PLAN costs in 2000. Costs associated with the Stuart Oil Shale
Project were expensed after the asset write-down in the third quarter. This
treatment resulted in $19 million in Stuart Project costs being expensed in
2000. Partially offsetting these increases was a foreign exchange gain of $11
million due to the weakening of the Australian dollar against the Canadian
dollar related to the Stuart Project loan obligations. Volume-related
expenses in NG were $19 million lower because volumes decreased due to
property divestments.

Exploration expenses increased by $13 million in 2000 to $53 million,
primarily as a result of higher dry hole costs.

Royalty expenses increased by $100 million in 2000 to $199 million. The
increase was primarily due to higher commodity prices which were partially
offset by the lower volumes resulting from divestments by the NG business.


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 47
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE

* This section contains forward-                FUTURE INCOME TAXES
  looking information. Also refer               See Note 6 to the Consolidated
  to the Overview *** on page 29                Financial Statements.
  of this report.

Taxes, other than income taxes, increased by $27 million primarily due to
higher sales volumes of taxable products (mainly transportation fuels) in the
downstream business.

Depreciation, depletion and amortization (DD&A) increased by $47 million to
$365 million in 2000 over 1999. An increase of $55 million was recorded in
the Oil Sands business as explained on page 32 under the Oil Sands section
(Expenses Increased). DD&A was reduced by $8 million primarily due to the
lower asset base in the NG business after it divested nearly 30% of proven
reserves held at the beginning of the year.

While interest costs increased in 2000 to $112 million from $71 million in
1999, net interest expense charged to the income statement in 2000 decreased
to $8 million from $26 million in 1999. This reflected the high level of
investment in Project Millennium and the resulting interest capitalization
associated with this project. Interest costs associated with the Stuart Oil
Shale Project have been charged to the income statement in the second half of
2000 with the decision to write down a portion of the carrying value of the
project at the end of the second quarter.

With Project Millennium expected to begin commercial operations by 2002,
interest charges now being capitalized will be expensed, thereby reducing
future earnings.

Suncor's effective tax rate in both 2000 and 1999 was approximately 40%. The
adoption in 2000 of the new standard for FUTURE INCOME TAXES resulted in the
recognition of a $13 million reduction on the balance sheet and a
corresponding increase in net earnings due to the revaluation of future
income tax balances. This change was due to a reduction in the income tax
rates by federal and provincial governments. These reductions only applied to
Suncor's downstream business (Sunoco). Under the previous accounting
standard, such adjustments would not have been made. As well, there was the
recognition of a provincial benefit of $13 million due to provincial Crown
royalties being in excess of the federal resource allowance deduction. This
benefit was a result of the high commodity prices that increased Crown
royalties and a high level of tax depreciation due to the high investing
expenditures.

Suncor believes the effective tax rate in 2001 will be approximately 40%.

OUTLOOK*

In 2001, Suncor priorities include:

EXPAND OIL SANDS PRODUCTION AND INCREASE INTEGRATION

In 2001, Suncor's priority is to commission Project Millennium, a $2.8
billion project that is expected to increase Oil Sands' production capacity
to 225,000 barrels per day by 2002. By increasing production capacity and
improving efficiencies, Project Millennium is expected to reduce Oil Sands'
unit cash costs.

Suncor's next stage of expansion is expected to progress in 2001 as the
Firebag In-situ Oil Sands Project proceeds through the regulatory approval
process. This commercial-scale in-situ project is targeted to add
approximately 35,000 barrels of bitumen per day in 2005. To process the
additional bitumen, Suncor plans to add a vacuum tower complex to increase
the Oil Sands upgrading capacity to 260,000 barrels of oil per day in 2005.
These plans are subject to Board of Directors and regulatory approvals.

The Company's long-term vision is to ultimately increase total production at
its Oil Sands facilities through a combination of oil sands mining and
in-situ development to approximately 400,000 to 450,000 barrels of oil per
day in 2008. Any such plans toward realizing this long-term vision would be
subject to Board of Directors and regulatory approvals.

Suncor's Oil Sands expansion will be supported by the continuing effort to
further integrate the Company to capture more of the value between our
upstream production and the end consumer. Suncor continues to evaluate
several approaches to secure markets and transportation for its increasing
Oil Sands production including the possible acquisition or joint venture of a
refinery. In addition, the Company will continue efforts to enter into
long-term sales agreements with other refiners in both Canada and the United
States.

FOCUS ON BASE BUSINESS EXCELLENCE

Although the Oil Sands expansion is a critical part of Suncor's growth
strategy, the Company realizes that properly managing its base business is
important to achieving strong financial returns. Safe and efficient
operations reduce the risk of production loss, environmental liability and
the higher costs incurred in conducting unscheduled maintenance. In 2001, all
of Suncor's businesses will continue to make base business excellence a
priority and will focus on improving operational reliability. A key focus for
the future will be to apply technological advancements that increase the
efficiency of each business, reduce costs and improve


48 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                              MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE

                                        DUAL TRAINS
                                        The creation of parallel processes
                                        for the existing extraction and
                                        upgrading facilities along with
                                        additional mining equipment and
                                        increased energy services support.

environmental performance. Suncor's goal is to be one of the lowest-cost oil
producers in North America and a top quartile competitor in each of its
businesses.

INCREASE EMPHASIS ON SUSTAINABILITY

As the Company expands its hydrocarbon-based businesses with the accompanying
increases in greenhouse gas emissions, management believes Suncor also needs
to work concurrently toward the development of alternative and renewable
sources of energy. Alternative energy sources have the potential for lower
environmental impacts as well as creating additional business investment
opportunities.

Early in 2000, Suncor announced plans to invest $100 million in alternative
and renewable energy projects over a five-year period. During 2000, many
opportunities were investigated and evaluated and Suncor expects that its
plans to establish renewable energy businesses in the areas of wind, solar,
run-of-river hydro, biomass and landfill gas, will result in investment
decisions in 2001.

Suncor's effort to reduce greenhouse gas emissions will also be reflected in
its pursuit of greater energy efficiency as an investment in the future
viability of the business that could yield cost savings and improve
competitive, as well as environmental, performance. Suncor's goal is to meet
or exceed relevant national and international commitments to limit greenhouse
gases in the atmosphere. In the context of current Canadian commitments, this
involves lowering net greenhouse gas emissions to 6% below 1990 levels by
2010; an ambitious target given the Company's vision to produce 400,000 to
450,000 barrels of oil per day by 2008. Achievement of this commitment
requires access to the flexibility mechanisms in the Kyoto Protocol, and the
implementation of a meaningful credit for early action program in Canada.

LONG-TERM CORPORATE DEVELOPMENT

Suncor will continue to emphasize development of long-term strategic plans
aimed at growing its current businesses and identifying ways to broaden the
scope of the products and services the Company provides. As the Company moves
forward it will work to introduce new strategies and technologies into its
business model that will strengthen its economic performance and enhance
shareholder value while also furthering its commitment to sustainable
development and growth.

In 2001, Suncor will continue to examine development opportunities in surface
mineable oil deposits. The Company is currently testing the commercial
viability of producing oil from oil shale with the Stuart Oil Shale Project
in Australia and has also assessed potential oil shale deposits in a number
of other locations. Suncor is operating the Stuart Oil Shale Project, which
is a joint venture with Southern Pacific Petroleum NL/Central Pacific
Minerals NL (SPP/CPM).

During 2000, Suncor experienced operational issues with the first phase of
the Stuart Oil Shale Project including the discovery of low levels of dioxin
in plant emissions. The next stage of this project's commercial development
has been put on hold until these issues and concerns about environmental and
social impacts are addressed.

RISK/SUCCESS FACTORS AFFECTING PERFORMANCE

OIL SANDS

When Project Millennium is completed, an even greater portion of Suncor's
financial performance is expected to be dependent on the performance of its
Oil Sands operations. The Oil Sands business could account for 90% of
Suncor's upstream production in 2002 compared to 70% in 1998. Assuming
estimated economies of scale and reliability improvements are achieved,
management believes its per barrel cash operating costs will decrease from
2000 levels in 2002 largely as a result of increased production associated
with Project Millennium. See the Outlook section under "Oil Sands" for a more
detailed discussion.

Suncor believes the planned increases in Oil Sands production present
strategic advantages, as well as issues that require prudent risk management.
The strategic advantages of Oil Sands growth include:

- -    Economies of scale associated with higher levels of production from the
     existing Oil Sands infrastructure,

- -    DUAL TRAINS in the extraction and upgrading processes provide flexibility
     to schedule periodic plant maintenance while continuing to generate
     production,

- -    The ability to leverage demonstrated operational experience and
     technologies, and

- -    Production growth without the exploration risk associated with conventional
     oil and gas operations.

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

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


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 49
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE


- -    Competition from new entrants in the oil sands business. This could take
     the form of competition for skilled people, increased demands on the Fort
     McMurray infrastructure (housing, roads, schools, etc.), or higher prices
     for the products and services required to operate and maintain the plant.

     Suncor has addressed these issues by developing a comprehensive recruitment
     strategy, working with the community to determine infrastructure needs,
     designing Oil Sands' expansion to reduce unit costs, capitalizing on
     technology advancements and seeking strategic alliances with service
     providers.

- -    Potential changes in the demand for refinery feedstocks and diesel. 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 customers'
     specifications.

- -    Preservation and protection of the environment. (See Environmental
     Regulation Risk/Success Factors on page 51.)


COMMODITY PRICES

Suncor's future financial performance remains closely linked to hydrocarbon
commodity prices, which can be influenced by a number of factors including
global and regional supply and demand factors, worldwide political events and
the weather. These factors, amongst others, can result in a high degree of price
volatility as illustrated over the last three years when the monthly average
price for the benchmark WTI crude oil ranged from a low of U.S.$11.30 per barrel
to a high in 2000 of U.S.$34.25 per barrel.

Suncor has partially offset the impact of crude oil price volatility by
pursuing economies of scale and improving reliability at Oil Sands over the past
five years. Crude oil and natural gas prices are based on a U.S. dollar
benchmark, which results in Suncor's earned prices being influenced by the
Canadian/U.S. currency exchange rate. This creates another element of
uncertainty. The continued weakness in the Canadian dollar versus the U.S.
dollar for the last three years ($0.67 Cdn:U.S.$ compared to $0.72 in 1997)
increased Suncor's revenues, as measured in Canadian dollars. In the future, the
strength of the Canadian dollar relative to foreign currencies could create
uncertainties for Suncor. For example, a one cent change in the
Australian/Canadian exchange rate on the Stuart Oil Shale Project borrowings
will impact Suncor's after-tax earnings by approximately $1 million. (See Note 2
to the Consolidated Financial Statements.)

<TABLE>
<CAPTION>

- -------------------------------------------------------------------------------------
CRUDE OIL HEDGING PROGRAM
(AT DECEMBER 31, 2000)               2001       2002       2003       2004      2005
- -------------------------------------------------------------------------------------
<S>                                <C>        <C>        <C>        <C>       <C>
Barrels per day of Annual
  Crude Oil Hedged                 57,500     48,000          0          0         0
Current Annual Limits (barrels)    57,500     63,000     63,000     67,500    70,000
Hedged Price - Cdn$ per barrel      28.69      29.04         --         --        --
- -------------------------------------------------------------------------------------
</TABLE>

Suncor uses hedging as a risk management tool to reduce earnings and cash
flow volatility. The annual limits may change, subject to Board approval, to
reflect management's ongoing assessment of the risk it is willing to accept.
The hedged price is a combination of the price for swaps and costless
collars, and reflects the hedged foreign exchange rate and spot price, where
appropriate. Refer to Note 18 in the Consolidated Financial Statements for
additional information.

HEDGING

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 prices
of crude oil and natural gas and the associated foreign exchange, for a
percentage of Suncor's total production volume. Suncor's risk management
objective with the hedging program is to lock in prices on a portion of the
Company's future production today, to reduce exposure to market volatility and
ensure the Company's ability to finance its growth.

The Board of Directors meets 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 its 2000 and 2001 capital
programs, the Board authorized hedging up to 50% of its crude oil volumes in
2000 and 2001 with the authorized limit returning to 30% in 2002, 2003 and
2004. For natural gas, the Board authorized a hedging program that allows up
to 50% of Suncor's volume to be hedged in the current year and subsequent
year, 30% for the third year, and 15% for the fourth year. See Note 18 to the
Consolidated Financial Statements for details of Suncor's hedge position as
of December 31, 2000.

In 2000, crude oil, natural gas and currency exchange hedging activities
decreased Suncor's earnings by $259 million. In 1999, hedging activities
decreased earnings by $56 million.

OTHER FACTORS

Other critical factors affecting Suncor's financial results include volumes
of refined product sales, margins on the sale of refined products, success of
the exploration program, interest rates and the Company's ability to manage
costs. Also refer to the note *** at the beginning of the MD&A, and to the
Company's Annual Information Form, on file with securities regulators or
available without charge from the Company.


50 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                              MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE

SENSITIVITY ANALYSIS

The following sensitivity analysis shows the main factors affecting Suncor's
annual pretax cash flow from operations and after-tax earnings based on
actual 2000 operations. The table illustrates the potential financial impact
of these factors applied to Suncor's 2000 results. It should be noted that
Natural Gas production in 2001 is expected to be lower than the 2000 average
due to property divestments and natural reservoir declines. As well, with
Project Millennium commissioning planned for the second half of 2001, Oil
Sands production is expected to increase over 2000 levels. A change in any
one factor could compound or offset other factors. Because this table does
not incorporate potential cross-relationships, it would not necessarily
accurately predict future results.

SENSITIVITY ANALYSIS

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
                                                                              Approximate change in
                                                                          Pre-tax cash flow   After-tax
($ millions)                                   2000 Average     Change     from operations    earnings
- -------------------------------------------------------------------------------------------------------
<S>                                            <C>             <C>        <C>                 <C>
Oil Sands
  Price of crude oil ($/barrel)                     31.67      U.S.$1.00        26                15
  Light/heavy differential ($/barrel)                9.38      U.S.$1.00        15                 9
  Sales (barrels/day)                             115,600          1,000        12                 7
Natural gas
  Price of natural gas ($/thousand cubic feet)       4.72           0.10         5                 3
  Production of natural gas
  (millions of cubic feet/day)                        200             10        11                 4
Sunoco
  Retail gasoline margin (cents/litre)                6.6            0.1         2                 1
  Refining/wholesale margin (cents/litre)             5.9            0.1         4                 2
Consolidated
  Exchange rate: Cdn$:U.S.$                          0.67           0.01        13                 7
  Interest rate                                      6.0%*            1%         1                 0
- -------------------------------------------------------------------------------------------------------
</TABLE>

* Borrowings with interest at variable rates averaging 6.0% at December 31.

ENVIRONMENTAL REGULATION RISK/SUCCESS FACTORS

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 that they apply to other companies and enterprises in the
energy industry. They require Suncor to obtain operating licences and to
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 are required before initiating most new projects or
undertaking significant changes to existing operations.

In addition to these specific, known requirements, Suncor expects further
changes will likely be required. Some of the issues under discussion 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 and greenhouse gas, including the potential impacts of
government regulation as it relates to these issues; land reclamation and
restoration; water quality; and reformulated gasoline to support lower
vehicle emissions. Changes in regulation could have an adverse effect on
Suncor from the standpoint of product demand, product formulation and
quality, and methods of production and distribution and cost of operations.
For example, cleaner-burning fuels may be mandated, causing additional costs
that 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 the Company. Management anticipates capital expenditures and
operating expenses will increase in the future as a result of the
implementation of new and increasingly stringent environmental regulations.


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 51
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE

LIQUIDITY AND CAPITAL RESOURCES

Suncor's growth initiatives have increased net debt to $2.2 billion at December
2000 from $1.3 billion at December 1999. Capital investment from 2001 to 2003,
including spending for the completion of Project Millennium, is currently
planned in the $2.5 billion to $3 billion range. This is similar to the
three-year period from 2000-2002.

In light of the revised Project Millennium capital cost estimate of $2.8
billion and the unpredictability of crude oil prices, Suncor has arranged an
additional $500 million credit facility for one year. Suncor management
believes its sufficient borrowing capacity and cash flow from operations will
be sufficient to fund the completion of Project Millennium and ongoing
operations and investing activities.

Crude oil prices, and to a lesser degree natural gas prices, and capital
investing plans are important components in determining Suncor's yearly
earnings and cash flow and net debt levels. In 2000, as in 1999, crude oil
prices experienced extremes that were unanticipated. In 1999, the benchmark
WTI price reached a low in the U.S.$10 per barrel range and reached a high of
U.S.$40 per barrel at one point in 2000.

Suncor management does not believe crude oil prices will be sustained at the
2000 price level of an average U.S.$30 per barrel. In the preparation of its
business plan for the next three years, Suncor has used a crude oil price
assumption that is below the consensus of third party consultants. Suncor's
business plans are based on assumptions that are generally at the
conservative end of the range of such assumptions.

Suncor's financing and capital spending plans are based upon the following
planning assumptions:

<TABLE>
<CAPTION>

- ------------------------------------------------------------------------
RATIO OF NET DEBT/CASH FLOW
FROM OPERATIONS                 1996    1997     1998     1999     2000
- ------------------------------------------------------------------------
<S>                             <C>     <C>      <C>      <C>      <C>
Number of times                  0.9     1.4      2.2      2.3      2.3
- ------------------------------------------------------------------------
</TABLE>

Ratio could remain in the 2.0-2.5 times range depending upon commodity price
assumptions and the timely completion and successful implementation of
Project Millenium.

With the higher forecasted spending associated with Project Millennium,
Suncor believes the debt/cash flow ratio could climb from its 2000 year-end
level of 2.3 times to a short-term peak in the 3.5 times range. This reflects
Suncor's current planning assumptions, especially the WTI price assumption.
Utilizing assumptions for WTI that would average approximately U.S.$25 per
barrel and a Henry Hub natural gas price assumption of U.S.$6.10, this ratio
would be expected to be in the 2.0 - 2.5 times range. This is subject to the
timely completion and successful implementation of Project Millennium and
contingent on the Company's financial assumptions. Management believes
expected increases in cash flow will reduce the debt/cash flow ratio to
Suncor's long-term goal of 1.5 - 2.0 times range by the year 2002.

Based upon the prior year's capital investment levels and currently planned
future investment levels, Suncor does not expect its upstream operations to
be cash taxable until the middle of the current decade.

<TABLE>
<CAPTION>

- -----------------------------------------------------------------------------------------------------------
                                                       2000 Actual        Current Plan    Last Year's Plan
- -----------------------------------------------------------------------------------------------------------
<S>                                                    <C>                <C>             <C>
PLANNING ASSUMPTIONS                                   Average for        Average next        Average next
                                                          the year        3-year range        3-year range
- -----------------------------------------------------------------------------------------------------------
Crude oil - WTI U.S.$ per barrel                             30.25       18.00 - 19.00       17.50 - 18.00
Natural gas - U.S.$/thousand cubic feet @ Henry Hub           3.90        3.00 -  3.50        2.45 -  2.55
Exchange rate: Cdn$:U.S.$                                     0.67        0.69 -  0.71        0.68 -  0.70
- -----------------------------------------------------------------------------------------------------------
</TABLE>

Note: The foregoing are planning assumptions and are not estimates or
predictions of actual future events or circumstances.

52 SUNCOR ENERGY INC. 2000 ANNUAL REPORT
<PAGE>

                              MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE

OPERATING COMMITMENTS

Throughout Suncor's more than 30-year involvement in its Oil Sands operations in
northern Alberta, it has had to invest in assets and related services that in
more developed geographic areas would be provided by third parties. These
include assets such as crude oil and natural gas pipelines, electrical and steam
generation facilities and accommodation for contract workers.

Suncor believes organizations with the specific expertise associated with
such assets can provide more cost-effective services. As part of the Oil
Sands growth initiatives, the Company will look to exit such businesses and
obtain services from third parties whenever feasible. One example is Suncor's
long-term agreement with TransAlta Energy Corporation to have that company
build, own and operate a co-generation facility at Oil Sands with a portion
of its output to help meet Suncor's long-term electricity and steam needs.
While these existing arrangements, and any new arrangements, will continue to
result in long-term operating commitments, the Company believes this approach
has the potential to reduce operating and administrative expenses.

DIVIDENDS

During 2000, Suncor's quarterly common share dividend was $0.085 per share,
unchanged from 1999 (after taking into consideration the two-for-one share split
in the second quarter of 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.


<TABLE>
<CAPTION>
CAPITAL AND EXPLORATION INVESTING EXPENDITURES
- -----------------------------------------------------------------------------------------------------
($ millions)                                        2001 Plan          2000 Actual       1999 Actual
- -----------------------------------------------------------------------------------------------------
<S>                                                 <C>                <C>               <C>
OIL SANDS (EXCLUDING PROJECT MILLENNIUM)
  Sustaining capital                                      107                    6                28
  Environmental                                             8                    1                 1
  Heavy oil - Firebag In-situ Oil Sands Project           124                   33                40
  Strategic
    Production improvements                                60                  132               203
    Expansion                                                                                      6
    Steepbank                                               0                    5                13
- -----------------------------------------------------------------------------------------------------
Total                                                     299                  177               291
- -----------------------------------------------------------------------------------------------------
PROJECT MILLENNIUM                                        450                1 631               806
- -----------------------------------------------------------------------------------------------------
NATURAL GAS
  Exploration                                              11                   42                75
  Development                                              60                   65                75
  Environmental                                             1                    1                 1
- -----------------------------------------------------------------------------------------------------
Subtotal finding and development capital                   72                  108               151
  Coal bed methane                                         10                    4                 2
  Other                                                    18                   15                 7
- -----------------------------------------------------------------------------------------------------
Total                                                     100                  127               160
- -----------------------------------------------------------------------------------------------------
SUNOCO
  Refining and distribution                                34                   20                18
  Retail marketing                                         24                   21                19
  Environmental                                            12                    3                 3
  Other                                                     3                    1                 2
- -----------------------------------------------------------------------------------------------------
Total                                                      73                   45                42
- -----------------------------------------------------------------------------------------------------
CORPORATE
  Stuart Oil Shale Project                                 --                   18                51
  Other                                                    --                   --                --
  Alternative and renewable energy                         13                   --                --
- -----------------------------------------------------------------------------------------------------
GRAND TOTAL                                               935                1 998             1 350
- -----------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------
</TABLE>


                                      SUNCOR ENERGY INC. 2000 ANNUAL REPORT 53

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4
<SEQUENCE>5
<FILENAME>a2042188zex-4.txt
<DESCRIPTION>EXHIBIT 4
<TEXT>

<PAGE>


                                    EXHIBIT 4
<PAGE>

QUARTERLY SUMMARY

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)          2000   2000  2000   2000  2000    1999   1999   1999  1999   1999   1998   1998  1998  1998   1998
- ------------------------------------------------------------------------------------------------------------------------------
<S>                         <C>    <C>   <C>    <C>   <C>     <C>    <C>    <C>   <C>  <C>     <C>     <C>   <C>  <C>    <C>
REVENUES                     779   820    862    927  3 388    469    564    639   715  2 387    543    498   531   498  2 070
- ------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)

Oil Sands                     90    81     76     68    315     17     34     43    73    167     49     29    34    33    145
Natural Gas                    8    16     43     31     98      3     13     20     5     41      3      4     7    10     24
Sunoco                        19    20     19     23     81      5      3     12     7     27      7     16     7     7     37
Corporate and eliminations   (12)   (6)   (88)   (11)  (117)   (14)   (17)    (5)  (13)   (49)   (12)    (6)   (1)   (9)   (28)
- ------------------------------------------------------------------------------------------------------------------------------
                             105   111     50    111    377     11     33     70    72    186     47     43    47    41    178
==============================================================================================================================
PER COMMON SHARE
  - net earnings
    attributable to
    common shareholders
  - basic                   0.45  0.47   0.19   0.47   1.58   0.04   0.12   0.29  0.29   0.74   0.22   0.19  0.21  0.19   0.81
  - diluted                 0.45  0.47   0.19   0.46   1.57   0.04   0.12   0.29  0.28   0.73   0.22   0.19  0.21  0.18   0.80
==============================================================================================================================
  - 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                    199   181    156    119    655     53     90    104   158    405     96     74    86    64    320
Natural Gas                   48    42     64     84    238     42     43     39    48    172     39     36    42    50    167
Sunoco                        46    38     49     41    174     23     17     37    26    103     24     39    26    23    112
Corporate and eliminations   (24)  (17)   (40)   (28)  (109)   (25)   (21)   (33)  (10)   (89)   (15)   (11)   16    (9)   (19)
- ------------------------------------------------------------------------------------------------------------------------------
                             269   244    229    216    958     93    129    147   222    591    144    138   170   128    580
==============================================================================================================================
</TABLE>

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-5
<SEQUENCE>6
<FILENAME>a2042188zex-5.txt
<DESCRIPTION>EXHIBIT 5
<TEXT>

<PAGE>

                                    EXHIBIT 5

<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
                                                     Direct Fax (403) 781-1825




CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS

We hereby consent to the incorporation, by reference, in the annual report of
Suncor Energy Inc. on Form 40-F, of our report dated January 18, 2001 on our
audits of the consolidated financial statements, including the additional
information provided on Exhibit 1 to Form 40-F, as of December 31, 2000, 1999
and 1998.


Chartered Accountants
Calgary, Alberta
February 28, 2001




COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE

In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) when there are
changes in accounting principles that have a material effect on the
comparability of the company's financial statements, such as the changes
described in Note 1 to the consolidated financial statements. Our report to the
shareholders dated January 18, 2001 is expressed in accordance with Canadian
reporting standards which to not require a reference to such a change in
accounting principles in the auditors' report when the change is properly
accounted for and adequately disclosed in the financial statements.


"PRICEWATERHOUSECOOPERS LLP"

Chartered Accountants
January 18, 2001


AlmG:\AmacDona\RC\Suncor\Letters2001\Consent_Feb26 01


PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP
and other members of the worldwide PricewaterhouseCoopers organization.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-6
<SEQUENCE>7
<FILENAME>a2042188zex-6.txt
<DESCRIPTION>EXHIBIT 6
<TEXT>

<PAGE>

                                    EXHIBIT 6


<PAGE>

                                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.:

o    the letter reports dated January 15, 2001, as to the synthetic crude oil
     reserves effective December 31, 2000 associated with the Suncor Energy Inc.
     oil sands operations located near Fort McMurray, Alberta;

o    the Reserve Determination and Evaluation of the Canadian Oil and Gas
     Properties of Suncor Energy Inc. Natural Gas effective December 31, 2000,
     dated January 26, 2001;

o    the Suncor Energy Inc. Natural Gas Constant Price Analysis effective
     December 31, 2000, dated January 24, 2001;

(collectively the "Reports")

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 2000
fiscal year (AIF), and to the incorporation by reference of the AIF in the
annual report of Suncor Energy Inc. on Form 40-F.

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.

                                       "WAYNE CHOW"

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

Calgary, Alberta
Date: February 28, 2001


<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 23, 2001                  BY: "MICHAEL W. O'BRIEN"
                                           -----------------------------------
                                           MICHAEL W. O'BRIEN
                                           Executive Vice President,
                                           Corporate Development and Chief
                                           Financial Officer
</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----
