FORM 6-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Report of Foreign Private Issuer
Pursuant to Rule 13a - 16 or 15d - 16 of
the Securities Exchange Act of 1934
For the month of: March 2002 Commission File Number: 1-12384
SUNCOR ENERGY INC.
(Name of registrant)
112 FOURTH AVENUE S.W.
P.O. BOX 38
CALGARY, ALBERTA, CANADA, T2P 2V5
Indicate by check mark whether the registrant files or will file annual reports
under cover of Form 20-F or Form 40-F:
Form 20-F Form 40-F X
--------- ---------
Indicate by check mark whether the registrant by furnishing the information
contained in this Form is also thereby furnishing the information to the SEC
pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:
Yes No X
--------- ---------
If "Yes" is marked, indicate the number assigned to the registrant in connection
with Rule 12g3-2(b):
N/A
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM
FEBRUARY 28, 2002
ANNUAL INFORMATION FORM
TABLE OF CONTENTS
ANNUAL INFORMATION FORM..................................................................ii
GLOSSARY OF TERMS.......................................................................iii
CONVERSION TABLE........................................................................vii
CURRENCY................................................................................vii
FORWARD-LOOKING STATEMENTS..............................................................vii
CORPORATE STRUCTURE.......................................................................1
Incorporation of the Issuer..........................................................1
Subsidiaries of Suncor...............................................................1
GENERAL DEVELOPMENT OF THE BUSINESS.......................................................1
Three-Year Highlights................................................................2
NARRATIVE DESCRIPTION OF THE BUSINESS.....................................................5
OIL SANDS..............................................................................5
Operations...........................................................................5
Leasehold Interests and Royalties....................................................7
Estimated Reserves...................................................................8
Reserves Reconciliation.............................................................10
Revenues from Synthetic Crude Oil and Diesel........................................10
Capital Expenditures................................................................11
Environmental Compliance............................................................12
NATURAL GAS...........................................................................12
Reserves and Reserves Reconciliation................................................12
Conventional Crude Oil..............................................................14
Before Royalties at.................................................................15
Natural Gas.........................................................................17
Land Holdings.......................................................................17
Drilling............................................................................18
Wells...............................................................................19
Sales and Sales Revenues............................................................19
Production Costs....................................................................20
Quarterly Volumes and Netback Analysis..............................................21
Marketing, Pipeline and Other Operations............................................22
Capital and Exploration Expenditures................................................22
Environmental Compliance............................................................23
SUNOCO...................................................................................23
Procurement of Feedstocks...........................................................23
Refining Operations.................................................................24
Principal Products..................................................................24
Transportation and Distribution.....................................................26
Capital Expenditures................................................................26
SUNCOR EMPLOYEES.........................................................................27
RISK/SUCCESS FACTORS.....................................................................27
SELECTED CONSOLIDATED FINANCIAL INFORMATION..............................................34
Selected Consolidated Financial Information.........................................34
Dividend Policy and Record..........................................................34
Future Commitments to Buy, Sell, Exchange or Transport Crude Oil And Natural Gas....35
MANAGEMENT'S DISCUSSION AND ANALYSIS.....................................................36
MARKET FOR THE SECURITIES OF THE ISSUER..................................................36
DIRECTORS AND OFFICERS...................................................................37
ADDITIONAL INFORMATION...................................................................40
ii
GLOSSARY OF TERMS
BITUMEN/HEAVY OIL
A naturally occurring viscous tar-like mixture, mainly containing hydrocarbons
heavier than pentane, that is not recoverable at a commercial rate in its
naturally occurring viscous state through a well without using enhanced recovery
methods. When extracted bitumen/heavy oil can be upgraded into crude oil and
other petroleum products.
CAPACITY
Maximum output that can be achieved from a facility in ideal operating
conditions in accordance with current design specifications.
COALBED METHANE
Natural gas produced from wells drilled into a coal formation. Also called coal
seam methane.
CONVENTIONAL CRUDE OIL
Crude oil produced through wells by standard industry recovery methods for the
production of crude oil.
CONVENTIONAL NATURAL GAS
Natural gas produced from all geological strata, excluding coalbed methane.
CRUDE OIL
Unrefined liquid hydrocarbons, excluding natural gas liquids.
DOWNSTREAM
This business segment manufactures, distributes and markets refined products
from crude oil.
DRY HOLE/WELL
An exploration or development well determined, on an economic basis, to be
incapable of producing hydrocarbons that will be plugged, abandoned and
reclaimed.
GROSS PRODUCTION/RESERVES
Suncor's undivided percentage interest in production/reserves before deducting
Crown royalties, freehold and overriding royalty interests.
GROSS WELLS/LAND HOLDINGS
Total number of wells or acres, as the case may be, in which Suncor has an
interest.
HEAVY FUEL OIL
Residue from refining of conventional crude oil that remains after lighter
products such as gasoline, petrochemicals and heating oils have been extracted.
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IN-SITU OIL
In-situ or "in place" refers to methods of extracting heavy crude oil from deep
deposits of oil sands with minimal disturbance of the ground cover.
NATURAL GAS
Hydrocarbons that at atmospheric conditions of temperature and pressure are in a
gaseous state.
NATURAL GAS LIQUIDS
Hydrocarbon products recovered as liquids from raw natural gas by processing
through extraction plants or recovered from field separators, scrubbers or other
gathering facilities. These liquids include the hydrocarbon components ethane,
propane, butane and pentane plus, or a combination thereof.
NET PRODUCTION/RESERVES
Suncor's undivided percentage interest in total production or total reserves, as
the case may be, after deducting Crown royalties and freehold and overriding
royalty interests.
NET WELLS/LAND HOLDINGS
Suncor's undivided percentage interest in the gross number of wells or gross
number of acres, as the case may be, after deducting interests of third parties.
OVERBURDEN
Material overlying oil sands that must be removed before mining. Consists of
muskeg, glacial deposits and sand.
PROBABLE RESERVES
Those reserves which analysis of drilling, geological, geophysical and
engineering data does not demonstrate to be proved under current technology and
existing economic conditions, but where such analysis suggests the likelihood of
their existence and future recovery. Probable additional reserves to be obtained
by the application of enhanced recovery processes will be the increased recovery
over and above proved estimates that can be realistically estimated for the pool
on the basis of enhanced recovery processes which can be reasonably expected to
be instituted in the future.
PROVED RESERVES
Those reserves estimated as recoverable with a high degree of certainty under
current technology and existing economic conditions, from that portion of a
reservoir which can be reasonably evaluated as economically productive on the
basis of analysis of drilling, geological, geophysical and engineering data,
including the reserves to be obtained by enhanced recovery processes
demonstrated to be economic and technically successful in the subject reservoir.
RESOURCES
Resources, with respect to Suncor's oil sands leases, include quantities of oil
and gas that are estimated, on a given date, to be potentially recoverable from
known accumulations and undiscovered accumulations that are not proved or
probable reserves and are of a higher risk than, and are generally believed to
be less likely to be recovered than proved and probable reserves, and also
include proved and probable reserves. Total resources include both synthetic
crude oil estimates for mining leases, and bitumen estimates for in-situ oil
sands leases.
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RESERVOIR
Body of porous rock containing an accumulation of water, crude oil or natural
gas.
SOUR SYNTHETIC CRUDE OIL
Crude oil produced from oil sands that requires only partial upgrading and
contains a higher sulphur content than sweet synthetic crude oil.
SWEET SYNTHETIC CRUDE OIL
Crude oil produced from oil sands consisting of a blend of hydrocarbons
resulting from thermal cracking and purifying of bitumen.
SYNTHETIC CRUDE OIL
Upgraded or partially upgraded crude oil recovered from oil sands including
surface mineable oil sands leases and in-situ heavy oil leases.
UNDEVELOPED OIL AND NATURAL GAS LANDS
Suncor's undivided percentage interest in lands where no producing or
commercially producible well has been drilled.
UPSTREAM
This business segment includes acquisition, exploration, development, production
and marketing of crude oil, natural gas and natural gas liquids; and for greater
clarity includes the production of synthetic crude oil, butimen and other oil
products from oil sands.
UTILIZATION
The average use of capacity taking into consideration planned and unplanned
outages and maintenance.
WELLS
Development Well
A crude oil or natural gas well in a reservoir known to be productive and
expected to produce in future.
DRILLED WELL
A well that has been drilled and has a defined status e.g. gas well, shut-in
well, producing oil well, producing gas well, suspended well or dry and
abandoned well.
EXPLORATORY WELL
A well drilled in unproved or semi-proved territory with the intention to
discover commercial reservoirs or deposits of crude oil and/or natural gas.
v
ACCOUNTING TERMS
BARREL OF OIL EQUIVALENT (BOE)
Suncor converts natural gas to crude oil on the approximate long-term economic
equivalent basis that 6,000 cubic feet of natural gas equals one barrel of crude
oil.
DEVELOPMENT COSTS
Includes all costs associated with moving reserves from other classes such as
"proved undeveloped" and "probable" to the "proved developed" class.
FINDING COSTS
Includes the cost of and investment in undeveloped land, geological and
geophysical activities, exploratory drilling and direct administrative costs
necessary to discover crude oil and natural gas reserves.
INTEREST COVERAGE -- CASH FLOW BASIS
Cash provided from operating activities before interest expense and income tax
payments, divided by the aggregate of interest expense and interest capitalized.
LIFTING COSTS
Includes all expenses related to the operation and maintenance of producing or
producible wells and related facilities, natural gas plants and gathering
systems.
MMCF/E (MILLION CUBIC FEET EQUIVALENT)
Converts crude oil to natural gas on the approximate long-term economic
equivalent basis that one barrel of crude oil equals 6,000 cubic feet natural
gas.
NET DEBT
Long-term borrowings (including the current portion) plus short-term borrowings,
less cash and cash equivalents.
OPERATING WORKING CAPITAL
Current assets (excluding cash and cash equivalents), less current liabilities
(excluding borrowings).
RETURN ON AVERAGE CAPITAL EMPLOYED
Earnings before long-term interest expense as a percentage of average capital
employed. Average capital employed is the total of shareholders' equity and debt
(short-term borrowings and current and long-term portions of long-term
borrowings, less the capitalized cost related to major growth projects in
progress), at the beginning and end of the year, divided by two.
RETURN ON AVERAGE SHAREHOLDERS' EQUITY
Earnings as a percentage of average shareholders' equity. Average shareholders'
equity is the aggregate of total shareholders' equity at the beginning and end
of the year, divided by two.
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CONVERSION TABLE
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
NOTES:
(1) Conversion using the above factors on rounded numbers appearing in this
Annual Information Form may produce small differences from reported
amounts.
(2) Some information in this Annual Information Form is set forth in metric
units and some in imperial units.
CURRENCY
All references in this Annual Information Form to dollar amounts are in Canadian
dollars unless otherwise indicated.
FORWARD-LOOKING STATEMENTS
This Annual Information Form contains certain forward-looking statements that
are based on Suncor's current expectations, estimates, projections and
assumptions and were made by the Company in light of its experience and its
perception of historical trends.
All statements that address expectations or projections about the future,
including statements about Suncor's strategy for growth and future expenditures,
commodity prices, costs, schedules, production volumes, operating and financial
results, are forward-looking statements. Some of the forward-looking statements
may be identified by words like "expects," "anticipates," "plans," "intends,"
"believes," "projects," "indicates," "could", "vision", "goal", "objective" and
similar expressions. These statements are not guarantees of future performance
and involve a number of risks, uncertainties and assumptions. Suncor's business
is subject to risks and uncertainties, some that are similar to other oil and
gas companies and some that are unique to Suncor. Suncor's actual results may
differ materially from those expressed or implied by its forward-looking
statements as a result of known and unknown risks, uncertainties and other
factors.
You are cautioned not to place undue reliance on Suncor's forward looking
statements. The risks, uncertainties and other factors that could influence
actual results include but are not limited to: changes in the general economic,
market and business conditions; fluctuations in supply and demand for Suncor's
products; fluctuations in commodity prices; fluctuations in currency exchange
rates; Suncor's ability to respond to changing markets; the ability of Suncor to
receive timely regulatory approvals; the successful and timely implementation of
its growth projects including the Firebag In-Situ Oil Sands Project and Project
Voyageur; the integrity and reliability of Suncor's capital assets; the
cumulative impact of other resource development projects; Suncor's ability to
comply with current and future environmental laws; the accuracy of Suncor's
reserve estimates, production estimates and production levels and its success at
exploration and development drilling and related activities; the maintenance of
satisfactory relationships with unions, employee associations and joint
venturers; competitive actions of other companies, including increased
competition from other oil and gas companies or from companies that provide
alternative sources of energy; the uncertainties resulting from potential delays
or changes in plans with respect to exploration or development projects or
capital expenditures; actions by governmental authorities including tax
increases and changes in government fees, changes in environmental and other
regulations; the ability and willingness of parties with whom Suncor has
material relationships to perform their obligations to Suncor; the occurrence of
unexpected events such as fires, blowouts, freeze-ups, equipment failures and
other
vii
similar events affecting Suncor or other parties whose operations or assets
directly or indirectly affect Suncor; and other factors, many of which are
beyond Suncor's control.
Suncor cautions that the foregoing list of important factors is not exhaustive.
Many of these risk factors are discussed in further detail throughout this
Annual Information Form and in Management's Discussion and Analysis for the year
ended December 31, 2001 and dated February 28, 2002 ("MD&A"), which MD&A is
incorporated by reference herein. Readers are also referred to the risk factors
described in other documents Suncor files from time to time with securities
regulatory authorities. Copies of these documents are available without charge
from the Company at 112 - 4th Avenue S.W., Calgary, Alberta, T2P 2V5, by calling
1-800-558-9071, or by email request to info@suncor.com.
viii
CORPORATE STRUCTURE
INCORPORATION OF THE ISSUER
Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the
amalgamation under the CANADA BUSINESS CORPORATIONS ACT on August 22, 1979 of
Sun Oil Company Limited, incorporated in 1923 and Great Canadian Oil Sands
Limited, incorporated in 1953. On January 1, 1989, Suncor amalgamated with a
wholly-owned subsidiary under the CANADA BUSINESS CORPORATIONS ACT. Suncor's
articles were amended in 1995 to move its registered office from Toronto,
Ontario, to Calgary, Alberta, and amended again in April 1997, to adopt its
current name, "Suncor Energy Inc.". In April 1997 and May 2000, Suncor's
articles were amended to divide its issued and outstanding shares on a
two-for-one basis. In January 2002, Suncor's Board of Directors authorized a
further two-for-one common share division with a May 15, 2002, record date,
subject to shareholder approval at the Company's annual meeting scheduled for
April 26, 2002.
Suncor's registered and principal office is located at 112 - 4th Avenue, S.W.
Calgary, Alberta, T2P 2V5.
In this Annual Information Form, references to "Suncor" or the "Company" include
Suncor Energy Inc., its subsidiaries and joint venture investments unless the
context otherwise requires.
SUBSIDIARIES OF SUNCOR
Suncor Energy Inc. has two principal subsidiaries.
Sunoco Inc. ("Sunoco") is an Ontario corporation that is wholly-owned by Suncor.
Sunoco refines and markets petroleum products and petrochemicals directly and
indirectly through subsidiaries and joint ventures. In this Annual Information
Form, references to "Sunoco" mean Sunoco Inc., its subsidiaries and joint
venture investments, unless the context otherwise requires. Sunoco is unrelated
to Sunoco, Inc. (formerly known as Sun Company, Inc.) that is headquartered in
Philadelphia, Pennsylvania.
Suncor Energy Marketing Inc., wholly-owned by Sunoco, is incorporated under the
laws of Alberta. Suncor Energy Marketing Inc. manages Company and certain third
party Alberta-based pipeline operations and markets, mainly to customers in
Canada and the United States, certain crude oil, diesel fuel products, and
byproducts such as petroleum coke, sulphur and gypsum produced by Suncor's Oil
Sands and Natural Gas (NG) business units as well as certain other third party
products. Commencing in 2002, Suncor Energy Marketing Inc. will also market the
Company's natural gas production to customers in Canada and the United States
and supply natural gas to Oil Sands and Sunoco. Suncor Energy Marketing Inc.
also has a petrochemical marketing division that principally manages its
participation in Sun Petrochemicals Company, a petrochemical product joint
venture partnership.
GENERAL DEVELOPMENT OF THE BUSINESS
OVERVIEW
Suncor is a Canada-based integrated energy company. Suncor explores for,
acquires, develops, produces, and markets crude oil and natural gas, refines
crude oil and markets petroleum and petrochemical products.
Suncor has three principal operating business units. Oil Sands, based near Fort
McMurray, Alberta, produces sweet and sour crude oil, diesel fuel and custom
blended feedstocks. Natural Gas ("NG") (formerly Exploration and Production),
based in Calgary, Alberta, explores for, acquires, develops and produces natural
gas. Sunoco, headquartered in Toronto, Ontario, refines crude oil, markets a
broad range of petroleum products, mostly in Ontario, markets petrochemical
products in the United States and Europe, and markets natural gas to residential
and commercial customers in Ontario.
1
While it provides hydrocarbon-based resources for the immediate energy needs of
consumers, Suncor also pursues the development of low-emission and no-emission
energy sources that have a reduced environmental impact. Suncor announced plans
to place its renewable energy projects under the management of NG beginning in
2002. While NG will manage these projects, segmented financial data will be
reported under the results for the "Corporate" segment in Suncor's financial
reporting.
In 2001, Suncor produced approximately 127,100 barrels per day (bpd) of crude
oil and natural gas liquids (approximately 6% of Canada's crude oil production)
and 177 million cubic feet per day of natural gas. In 2000, the most recent
period with published results, Suncor was the third largest crude oil and
natural gas liquids producer and the 26th largest natural gas producer in
Canada.
In 2001, Suncor sold approximately 93,400 bpd (14,800 m3 per day) of refined
products, mainly in Ontario but also in the United States and Europe. Suncor's
refined product sales in Ontario represented approximately 18% of Ontario's
total refined product sales in 2001.
THREE-YEAR HIGHLIGHTS
OIL SANDS
In April 1999, following approval from Suncor's Board of Directors and
regulatory authorities, Suncor commenced construction of Project Millennium, an
expansion of its Oil Sands plant near Ft. McMurray, Alberta. Through an expanded
mine, additional mining equipment, increased energy services support and
twinning of the bitumen extraction and upgrading process, Project Millennium was
ultimately designed to increase production capacity of the plant to 225,000 bpd
by 2002.
Project Millennium was completed in 2001 at a final capital cost of $3.4
billion, up from the original estimate of $2 billion. The increase in project
costs over both the original, and subsequent interim estimates, was primarily
attributable to rising labour, fabrication and material costs and a $150 million
change in the project's scope. The additional capital costs were financed by
internally generated cash flow and additional borrowing.
In October 1999, pursuant to an agreement entered into with TransAlta Energy
Corporation ("TransAlta"), TransAlta assumed the role of operator of Suncor's
existing Oil Sands energy services plant. Also in 1999, TransAlta commenced
construction of a $315 million co-generation facility at Suncor's Oil Sands
plant site. Fully operational in 2001, this TransAlta owned and operated
facility is meeting a portion of Oil Sands' electricity and steam requirements
as well as supplying electricity to the Alberta power grid.
In early 2000, Suncor announced a plan to further expand its Oil Sands
operations beyond Project Millennium and in 2001 Suncor received regulatory
approval to proceed with development of the Firebag In-situ Oil Sands Project.
Combined with the construction of an associated vacuum tower at the site of its
plant, the first stage of Firebag is designed to add 35,000 barrels per day of
bitumen production at an estimated cost of $1 billion. The current cost estimate
is up from the original estimate of $750 million. Firebag construction, which
commenced in 2001, is expected to continue through to 2005 when Suncor is
targeting to achieve a total Oil Sands production capacity of 260,000 bpd. Three
additional stages of development of the Firebag leases, which have received
regulatory approval, have the potential to increase production from these leases
to a total of 140,000 barrels of bitumen per day by the end of the decade.
Approval from Suncor's Board of Directors is required before construction beyond
the first stage can begin.
In 2001, Suncor also announced plans for Voyageur, a phased expansion of the
Company's oil sands mining and in-situ operations and related extraction and
upgrading facilities. Management believes Voyageur has the potential to increase
production capacity at Oil Sands to 500,000 to 550,000 bpd in 2010 to 2012.
Suncor plans to develop Voyageur in phases with engineering, construction and
production plans for each phase to be aligned with long term marketing
strategies. In 2002, Suncor plans to undertake a
2
comprehensive stakeholder consultation program and integrate recommendations, as
appropriate, into engineering, design and project development for Voyageur.
Preliminary cost estimates for Voyageur are expected to be available in late
2002. Development of Voyageur requires approval of regulators and Suncor's Board
of Directors, as well as favourable fiscal and market conditions, among other
things.
In 2001, Suncor commenced a crude oil brokerage business to generate additional
income by buying and selling crude oil production of other companies. The
activity conducted by this business did not have a significant impact on the
Company's earnings or cash flow in 2001.
NATURAL GAS (NG)
In April 2000, Suncor's Board of Directors approved a repositioning of the
Exploration and Production business and renamed it Natural Gas ("NG") to reflect
the sharpened focus on natural gas production to meet growing demand, both
internally and externally.
In 2000, NG set a target to decrease annualized operating costs by a total of
$18 million to $20 million by year-end 2001. Approximately $15 million of this
target was reached in 2000. Annualized operating costs decreased an additional
$5 million in 2001 through a focus on administrative cost controls and reduced
lifting costs.
NG's goal is to achieve a return on average capital employed (see Glossary) of
at least 12% in 2002 and at least 15% in 2004 at mid-cycle natural gas prices
(U.S. $3.00 to $3.50/mcf price range). Management will work toward this goal by
building existing operating areas and developing new production and revenue
streams. Achievement of this goal cannot be assured. See "Forward-looking
statements" at the beginning of this AIF.
SUNOCO
In 2001, Sunoco entered into an energy supply agreement with TransAlta. Under
the agreement, steam from the TransAlta Sarnia Regional Co-generation Project, a
multi-user cogeneration project in Sarnia, Ontario, will be supplied to Sunoco's
Sarnia Refinery. The agreement is expected to help mitigate Sunoco's exposure to
increases in energy costs and supply steam to the Sarnia Refinery at a
competitive cost, while eliminating the need for Sunoco to build its own steam
generating boilers. According to TransAlta, the new facility is expected to
commence operation in the fourth quarter of 2002. Under this agreement with
TransAlta, Sunoco has the right to take a portion of the electricity output from
the TransAlta Sarnia Regional Co-generation Project. If Sunoco exercised this
right prior to startup of the new facility, the electricity requirements of the
Sarnia Refinery would also be supplied under the agreement with TransAlta.
Sunoco had entered into a conditional fixed-rate electricity supply contract
with a third party in 2000 to lock-in costs on a portion of its electricity
requirements for three years following deregulation of the Ontario electricity
market. However, due to the delay in deregulation, this contract terminated
automatically in accordance with its terms. Sunoco continues to evaluate
available options with respect to long-term electricity supply and no decision
has been taken by Sunoco to date with respect to the exercise of its option
under the TransAlta contract.
Federal legislation passed in 1999 mandates sulphur levels in gasoline to an
average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a
maximum of 30 ppm by 2005. Sunoco finalized an investment plan in 2001 to meet
the sulphur content limits. Capital required to achieve compliance is expected
to be approximately $40 million, which includes the addition of a
desulphurization unit. Construction of the unit is planned for 2002 and 2003.
In 2001, Sunoco completed a strategic assessment of its retail natural gas
marketing business. Sunoco is currently exploring alternatives with respect to
the business, including a possible disposition, joint venture or other
transaction involving such business.
3
OTHER
FINANCING ACTIVITIES
During 1999, the Company completed a Canadian offering of $276 million of 9.05%
preferred securities and a U.S. offering of U.S.$162.5 million of 9.125%
preferred securities, the proceeds of which totaled Canadian $507 million after
issue costs of $17 million ($10 million after income tax credits of $7 million).
The preferred securities are unsecured junior subordinated debt of the Company,
due in 2048 and redeemable at the Company's option on or after March 15, 2004.
See "Dividend Policy and Record."
During 2000, the Company put in place a borrowing facility for $500 million that
is fully revolving for 364 days and was scheduled to expire in 2001. In 2001
this facility was extended to June 2002 and increased to $550 million.
In 2001 Suncor issued $500 million of Series 2 Medium Term Notes with a ten year
maturity. The notes have a coupon of 6.7% and will yield 6.74%.
In January 2002, Suncor issued U.S. $500 million principal amount of 7.15%
unsecured notes due February 1, 2032, to investors in the United States (the
"U.S."). The notes were sold at a price of 99.595% per note to yield 7.183% to
maturity. The sale of the notes was under Suncor's shelf prospectus dated
January 10, 2002, which allows for the issuance of debt securities and common
shares in an aggregate principal amount of up to U.S. $1 billion. Also in
January 2002, Suncor filed a base shelf prospectus with Canadian securities
regulatory authorities, enabling it to issue up to a further $500 million in
medium term notes in Canada, if required. To date, no notes have been issued
under this prospectus.
SALE OF STUART OIL SHALE PROJECT
In April 2001, Sunoco sold its interest in the Stuart Oil Shale Project to its
Australian joint venture co-owners, Southern Pacific Petroleum NL ("SPP") and
Central Pacific Minerals NL ("CPM") (together, "SPP/CPM"). The first stage of
the Queensland, Australia project, originally announced by Suncor and SPP/CPM in
1997, was designed as a 4,500 barrel per day demonstration plant to test the
commercial viability of producing crude oil from oil shale. Construction of the
demonstration plant was completed and commissioning commenced in 1999.
Operational issues were experienced during commissioning, including issues
relating to plant reliability, noise, odours and the discovery of low levels of
dioxin and other emissions. In the third quarter of 2000, Suncor recorded an
after-tax write-down of $80 million, reflecting increased costs and delayed oil
production, and thereafter, all future expenditures on the Project were
expensed. Suncor's investment in the Project up to the date of sale, excluding
$4 million invested by Suncor in partially paid SPP/CPM shares that were
cancelled as part of the sale transaction, and $5 million in shares acquired in
2001, as discussed below, was approximately $275 million.
Under the terms of the sale, Suncor retained a 5% royalty interest in the first
stage of the project, and SPP/CPM and Suncor retained worldwide rights to the
project technology. Suncor made total payments as part of the transaction in the
amount of Aus$7 million (approximately Cdn$5 million) for which Sunoco received
2.5 million SPP shares and 0.926 million CPM shares. In addition, SPP/CPM issued
to Suncor 12.5 million SPP share options and 4.6 million CPM share options, and
Suncor surrendered the partly paid SPP/CPM restricted class shares it had
originally acquired in 1997.
As a result of the sale an after-tax charge to earnings of $3 million was
recorded in the second quarter of 2001. At the end of 2001 Suncor also partially
wrote-down the carrying value of the shares acquired by $3 million.
OTHER HIGHLIGHTS
In September 1999, Suncor was included in the newly formed Dow Jones
Sustainability Index, the world's first global equity index tracking the
performance of 200 leading sustainability-driven companies in 68 industry groups
in 22 countries. Suncor continued to be part of the Sustainability Index in 2000
and 2001.
Suncor announced in 2000 plans to invest at least $100 million over five years
to pursue renewable energy opportunities. As of December 31, 2001, Suncor
hadexpended approximately $16 million with the
4
majority of these funds expended on the SunBridge Wind Power Project in Gull
Lake, Saskatchewan. This project is a 50-50 partnership with Enbridge Inc.
("Enbridge"). In 2001, the first electricity was generated from this project.
For further information on the status of the ongoing projects and issues
referred to above and other highlights of 2001, refer to "Outlook" and other
sections of Suncor's MD&A.
NARRATIVE DESCRIPTION OF THE BUSINESS
OIL SANDS
Suncor produces a variety of refinery feedstocks and diesel fuel by mining the
Athabasca oil sands in northeastern Alberta and upgrading the bitumen extracted
at its plant near Fort McMurray, Alberta. The Oil Sands operations, accounting
for over 99% of Suncor's conventional and synthetic crude oil production in
2001, represents a significant portion of Suncor's asset base, cash flow and
earnings.
OPERATIONS
Suncor's integrated Oil Sands business involves four operations: a mining
operation using trucks and shovels to mine the oil sand ore; extraction
facilities to recover the bitumen from the oil sand ore; a heavy oil upgrading
process, where bitumen is converted into crude oil products; and an energy
services plant (operated by TransAlta), which together with TransAlta's
natural-gas fired co-generation plant that commenced operations at the Oil Sands
plant site in 2001, provides the site with steam and electric power. Suncor's
energy services plant primarily uses petroleum coke, a by-product of the coking
process, as fuel. It also consumes natural gas.
The first step of the open pit mining operation is to remove the overburden with
trucks and shovels to access the oil sands - a mixture of sand, clay and
bitumen. The oil sands ore is transported to one of four sizing plants by a
fleet of trucks. The ore is dumped into sizers where it is crushed and then
transported to the extraction plant. On the west bank of the Athabasca River,
the ore is transported by a conveyor system that stretches approximately five
kilometers. On the east bank, a slurry of partially processed ore from the mine
is transported by a hydrotransport system to the extraction plant on the west
side of the river. Bitumen is extracted from the oil sands with a hot water
process. After the final removal of impurities and minerals, naphtha is added as
diluent to facilitate transportation to the upgrading plant. Periodically
bitumen is sold rather than being upgraded. In 2001 approximately 8,500 bpd of
bitumen were sold, representing approximately seven percent of 2001 production.
After transfer to the upgrading plant, the diluted bitumen is separated into
naphtha and bitumen. The naphtha is recycled to be used again as diluent and the
bitumen is upgraded through a coking and distillation process. The upgraded
product, referred to as sour crude oil, is either sold directly to customers or
is further upgraded into sweet crude oil by removing the sulphur and nitrogen
using a hydrogen treating process. Three separate streams of refined crude oil
are blended together according to customer specifications. Suncor Energy
Marketing Inc. purchases and ships these product blends by pipeline for sale and
distribution to Suncor's Sarnia, Ontario refinery, as well as other customers in
Canada and the United States. Oil Sands entered into a transportation service
agreement with a subsidiary of Enbridge for a term that commenced in 1999 and
extends to 2028, for pipeline capacity that allows for the initial shipment of
60,000 and increasing to 170,000 barrels per day of sour crude oil and bitumen
from Fort McMurray, Alberta to Hardisty, Alberta. As the initial shipper on the
pipeline, Suncor's tolls payable under the agreement are subject to annual
adjustments. The pipeline is operated by Suncor Energy Marketing Inc. This
pipeline, together with Suncor's proprietary oil sands pipeline, is expected to
meet Suncor's anticipated crude oil shipping requirements for expected future
production levels up to 2008.
Suncor has an agreement TransCanada Pipeline Ventures Limited Partnership
("TCPV"), to provide Suncor with firm capacity on a new natural gas pipeline
constructed by TCPV. This pipeline came into service in 1999.
5
The oil sands plant is susceptible to loss of production due to the
interdependence of its component systems. In 1999 two unplanned outages of the
5C9 fractionator lasted a total of 16 days and resulted in approximately 1.8
million barrels of lost production. Parts of the 5C9 unit that failed were
redesigned during the second outage in September 1999, with the objective of
improving reliability and helping to achieve targeted production rates. Suncor
shut down the same unit for maintenance twice in 2001, also for a total of 16
days. It is estimated that the lost production from these 2001 outages was
approximately 1.8 million barrels. Management will continue to monitor the
performance of this unit and evaluate whether further repairs or other remedial
actions are required to address the operational issues.
Through expansion projects like Millennium, Suncor expects improved operational
flexibility by reducing the cash flow impact of complete plant-wide shutdowns.
For example, Millennium adds a second complete processing operation. This "dual
train" approach increases production capacity and provides the flexibility to
schedule periodic plant maintenance on one train while continuing to generate
production and cash flow from the other. Oil Sands base plant (which excludes
Millennium facilities) is currently scheduled to undergo a maintenance shutdown
in 2002. Suncor plans to continue producing from the Project Millennium
facilities during this scheduled maintenance. During these partial shutdown
maintenance periods, work can be done while the rest of the plant continues to
operate. This reduces both the cost and scope of shutdowns and allows for
continued production of sour crude oil during the shutdown period.
Suncor has also undertaken other work to improve operational performance. Over
the past several years, backup components and systems have been introduced in
critical areas to improve reliability. In addition to ongoing preventive
maintenance programs, full plant maintenance shutdowns are completed
approximately every four years. In addition to complete shutdowns, partial
shutdowns in the upgrader are undertaken periodically.
Severe climatic conditions at Oil Sands can cause reduced production and in some
situations result in higher costs.
6
LEASEHOLD INTERESTS AND ROYALTIES
Set out in the table below is a summary of Suncor's oil sands mining and in-situ
leasehold interests as of December 31, 2001.
Percentage of
Proved Reserves
Number of Gross (bbl of synthetic
Acres crude oil for mining
Referred (Net Acres if leases / bbl bitumen
Description Legal Description to as applicable) for in-situ leases)
------------------------ ---------------------- ------------ --------------------- ----------------------
MINING LEASES:
--------------
Mine Expansion:
Leases 7280100T25 25 17,644
7279080T19 19 18,760 Mine Expansion
7597030T11 97 2,483 Leases and Fee Lots
7280060T23 36,954 represent 99%
7498050014 243
Fee Lots(1) 1 N/A 1,894 (1)
3 N/A 1,967 (1)
4 N/A 1,886 (1)
Original Mine 7387060T04 86 4,522 Original Mine
Leases 7279120092 17 1,619 Leases represent 1%
TOTAL MINING LEASES 87,972
FIREBAG LEASES:
-------------------
Firebag(2) 7285100T85 85 39,594 (1)
7097110062 N/A 7,040 (1)
7097110063 N/A 5,760 (1)
7097110064 N/A 4,800 (1)
7097120065 N/A 13,440 (1)
7097120066 N/A 18,560 (1)
7097120067 N/A 19,200 (1)
7099120072 N/A 23,040 (1)
7099120073 N/A 23,040 (1)
7099120074 N/A 16,640 (1)
7099120075 N/A 23,040 (1)
7001100001 N/A 22,400 (1)
7401100027 N/A 23,040 (1)
7401100029 N/A 10,240 (1)
7401100013 N/A 7,360 (1)
Firebag(2) Various(3) Various 84,480 (1)
TOTAL FIREBAG LEASES 341,674
TOTAL LEASES
429,646
7
Notes:
(1) No proved reserves are attributable to these leases.
(2) Leases are principally in-situ.
(3) Suncor holds a beneficial interest in 13 leases totaling 84,480 gross
and net acres.
The Government of Alberta is entitled to royalties under Leases 17, 19, 25, 86
and 97 and the Fee Lots at rates which the Government establishes from time to
time.
Under the Alberta Suncor Crown Royalty Agreement, Crown royalties are 25% of net
revenues less allowable costs (including capital expenditures), subject to a
minimum payment of 5% of gross revenues. In 2001, the minimum royalty rate
changed to 1% of gross revenues. Suncor currently expects to pay Crown royalties
at the minimum 1% rate until 2009, based on assumptions relating to future crude
oil prices, production levels, operating costs and capital expenditures. In
2000, Suncor made Crown royalty payments based upon the 5% minimum royalty.
Suncor transitioned to a generic Oil Sands royalty agreement with the Alberta
government in 1999 that provides Suncor with additional allowable cost
deductions to a maximum of $158 million per year for ten years (related to
Suncor's original investment in the Oil Sands facility).
Anadarko Inc. (a successor to Norcen Energy Resources Limited) has a gross
overriding royalty on Lease 86 pursuant to an agreement dated March 1, 1989 (the
"Anadarko Royalty"). The Anadarko Royalty is based on a graduated scale
dependent on the synthetic crude oil price expressed as a percentage of gross
revenue from production of the lease. As of December 31, 2001, under the
Anadarko Royalty, no payment is required if synthetic crude prices are below
$20.15 per barrel. Payment of 1.5% of gross revenue is required if the synthetic
crude price ranges from $20.15 to $21.14 per barrel. For every $1.00 per barrel
increase in the price of synthetic crude in the range of $21.15 to $26.14 per
barrel, the percentage rate of the royalty increases by 0.5%. For every $1.00
per barrel increase in the price of synthetic crude in the range of $26.15 to
$37.14 per barrel, the percentage rate of the royalty increases by a further
0.25 % until a maximum royalty of 7% is reached. All synthetic crude prices are
calculated on a monthly average basis and the crude price break points are
adjusted annually on March 1 of each year by a contractually determined
inflation component. Suncor currently expects to complete mining on the Anadarko
lease in 2002.
Petro-Canada has a royalty on Lease 19 pursuant to an agreement dated October 6,
1992. The royalty is calculated as 1.5% of net sale proceeds. Net sale proceeds
are calculated based upon a formula by which the sale proceeds for the period
exceeds the sum of allowed deductions for the period.
The Crown royalty regime applicable to the Firebag in-situ leases will be the
same regime as described for Suncor's oil sands mining leases above. To date,
Suncor has had no commercial production from this area and none is expected
until 2004-2005.
ESTIMATED RESERVES
Suncor estimates its mining leases, on a combined basis, contain proved plus
probable reserves of synthetic crude oil totaling 2.405 billion barrels, with
376 million barrels classified as proved. Its in-situ leases, on a combined
basis, contain probable reserves of 2.029 billion barrels of bitumen. In the
case of Firebag in-situ bitumen reserves, Suncor has the option of selling this
bitumen production and/or upgrading the bitumen to synthetic crude oil. Suncor's
current upgrading operations have a synthetic crude oil yield of 80%. These
estimates are before deduction of Crown and applicable royalties on the leases.
Under the Crown Royalty Agreement the Crown royalty is dependent on deemed net
revenues (Revenue-Cost, or R-C); therefore the calculation of net reserves would
vary depending upon production rates, prices and operating and capital costs.
The mining reserve estimates are based upon a detailed geological assessment
including drilling density
8
and laboratory tests and also consider current production capacity and upgrading
yields, current mine plans, operating life and regulatory constraints. Based on
these factors, additional proved reserves are anticipated to be recognized as
the mine is further developed. The current proved plus probable reserve estimate
is based on an additional 30 years of operations without further expansion.
Suncor engaged Gilbert Laustsen Jung Associates Ltd. ("GLJ"), independent
petroleum engineering consultants, to audit Suncor's estimate of proved and
probable reserves of synthetic crude oil on its mining leases, as of December
31, 2001. A synthetic crude oil yield of 80% has been utilized in the
determination of the proved and probable reserves. The proved reserves exclude
areas within the current pit designed not drilled up to a density of at least 10
holes per square kilometer. The proved plus probable reserves are based upon a
production forecast recognizing 30 additional years of mining operations
(210,000 bpd in 2002 and 220,000 bpd thereafter). Suncor is considering pit
design changes to the Millennium mine associated with higher stripping ratio
areas, permitted under operating criteria issued by the Alberta Energy and
Utilities Board in 2001. The current proved plus probable volumes are now 58
million barrels higher than current model estimates which reflect the proposed
changes. This difference in estimates corresponds to about 9 months of
anticipated production, and is considered to be within the accuracy of the model
estimates. The pit designs will continue to be impacted by both additional
drilling data and operating experience, as well as technology developments and
economic considerations. Furthermore, the potential exists to expand mining
operations north across the Steepbank River, to develop an ore body not yet
classified as a reserve. In their opinion dated January 16, 2002, GLJ state they
believe there is at least a 90% and 50% confidence the proved and proved plus
probable mining reserves estimates will be exceeded, respectively. Their opinion
is qualified to the extent that it assumes Suncor will comply with any
amendments that may be made to regulatory approvals.
At Suncor's request GLJ has prepared an independent resource and economic
analysis of Suncor's Firebag in-situ oil sands project leases. Suncor's geologic
interpretation of the leases was provided to GLJ, who reviewed Suncor's
methodology and interpretation and then prepared independent interpretations.
GLJ's interpretation was based on an analysis of individual well data and 3D and
2D seismic data supplied by Suncor. GLJ based its interpretation on current
pricing and royalty assumptions. In addition, GLJ utilized estimates and
assumptions for factors such as recovery efficiencies and operating costs, based
on GLJ's experience with similar projects. Cost and construction schedule
estimates were supplied by Suncor.
Based upon the work conducted by GLJ as described above, GLJ estimates that
there are 9.6 billion barrels of bitumen resources on the Firebag leases, which
includes a total 2.029 billion barrels that are probable nonproducing bitumen
working interest reserves within the project approved area.
Suncor continues to conduct its evaluation program in the Firebag area in 2002,
utilizing a combination of seismic and corehole drilling. This process is
expected to be ongoing over a number of years. The program is intended to assist
Suncor in evaluating the potential bitumen resources in order satisfy oil sands
lease tenure regulations, obtain sufficient geological data to quantify the
resources on the leases, and gain a more detailed understanding of the resource
to facilitate future design and layout of production wells.
To date Suncor has drilled approximately 300 coreholes and acquired
approximately 400 miles of seismic data in the Firebag area. Programs are
conducted annually to gain the information needed to guide resource development.
9
RESERVES RECONCILIATION
The following table sets out a reconciliation of Suncor's proved and probable
reserves of synthetic crude oil and bitumen from December 31, 2000 to December
31, 2001, based on reports issued by GLJ as described above (the "GLJ Oil Sands
Reports").
Mining Reserves(2) Insitu Firebag(3)
------------------ ----------------- Total Mining
(millions of barrels of synthetic crude (millions of barrels of and In-Situ
oil) bitumen)
Proved and
Proved Probable Total Probable Probable
-------- -------- ----- -------- -----------
December 31, 2000.......... 422 2,034 2,456 - 2,456
Revisions(1)............... (1) (5) (6) - (6)
Additions.................. - - - 2,029 2,029
Production................. (45) - (45) - (45)
---- - ---- - ----
December 31, 2001.......... 376 2,029 2,405 2,029 4,434
Note:
(1) Revisions relate to drilling activity, revisions to the pit design
based upon both geotechnical and economic data related to the Mine
Expansion leases (see the table under the heading "Leasehold Interests
and Royalties") and operational issues.
(2) Synthetic crude oil reserves based upon a net coker, or synthetic crude
oil yield of 80%.
(3) Suncor has the option of selling the bitumen production from these
leases and/or upgrading the bitumen to synthetic crude oil.
REVENUES FROM SYNTHETIC CRUDE OIL AND DIESEL
Although revenues after royalties per barrel are higher for synthetic crude oil
than for conventional crude oil, operating costs to produce synthetic crude oil
are higher than lifting and administrative costs to produce conventional crude
oil from the Western Canada Sedimentary Basin. While there is no finding cost
associated with synthetic crude oil, mine development and expansion of
production can entail significant outlays of funds. The costs associated with
synthetic crude oil production are largely fixed for the same reason and, as a
result, operating costs per unit are largely dependent on levels of production.
Aside from onsite fuel use, all of Oil Sands production is sold to Suncor Energy
Marketing Inc., a wholly owned subsidiary of Sunoco, which then markets the
production.
In 1997, Suncor and Shell Canada ("Shell") renewed a purchase agreement whereby
Shell agreed to purchase and receive approximately 95,000 cubic metres
(approximately 600,000 barrels) of sweet synthetic crude oil per month. The
original term of the agreement was to December 31, 1997, with 60-day evergreen
terms thereafter. The price received is based on a formula involving postings
for sweet crude oil. With Millennium start-up, Suncor also entered into a
one-year agreement effective January 1, 2002 to sell an additional 28,600 cubic
meters (180,000 barrels) per month to Shell under the same pricing terms.
In 1997 Suncor entered into a long-term agreement with Koch Oil Co. Ltd.
("Koch") to supply Koch with up to 30,000 barrels per day (approximately 26% of
Suncor's average 2001 total production) of sour crude from Suncor's Oil Sands
operation. Suncor began shipping the crude to Koch's refinery in Minnesota under
this long-term agreement effective January 1, 1999. The initial term of the
agreement extends to January 1, 2009, with month to month evergreen terms
thereafter, subject to termination after January 1, 2004, on twenty-four months'
notice. In 2000, Suncor announced a long term sales agreement with Consumers
Co-operative Refineries Limited ("CCRL") under which Suncor expects to begin
supplying CCRL with 20,000 barrels per day of sour crude oil production from its
Project Millennium expansion facilities by late 2002. Prices for sour crude oil
under these agreements are set at agreed differentials to market benchmarks. In
2001, Suncor announced a long-term agreement with Petro-
10
Canada to supply up to 30,000 barrels per day of diluent to dilute bitumen
produced by Petro-Canada. The contract is expected to commence in 2002 and is a
four year agreement that will be extended unless terminated by either party.
In 2001, Koch was the only customer that represented 10% or more of Suncor's
consolidated revenues, while there were two such customers in 2000, Koch and
Shell.
A portion of Oil Sands production is used in connection with Suncor's Sarnia
refining operations. During 2001, the Sarnia refinery processed approximately
14% (2000 -- 25%) of Oil Sands crude oil production.
The following table sets forth the average sales price received per barrel of
synthetic crude oil from Oil Sands on a quarterly basis for the years 2001 and
2000, after the impact of hedging activities.
--------------------------------------------------------------------------------------------------------------------
2001 2000
------------------------------------------------ -------------------------------------------------
--------------------------------------------------------------------------------------------------------------------
$/bbl 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q
----- -- -- -- -- -- -- -- --
Average sales 24.43 31.43 31.40 30.85 31.33 32.39 31.12 31.84
price
--------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Capital spending at Oil Sands is expected to total approximately $600 million in
2002, $420 million with respect to the in-situ phase of Suncor's Oil Sands
development and expansion of the upgrading facilities and $180 million in
capital investments for the current facility. Capital expenditures in 2001 were
approximately $1.5 billion.
Suncor's in-situ spending of $420 million in 2002 is part of $1 billion in total
spending on in-situ projects planned for the period 2002 to 2005.
The following table sets out, for the quarters indicated, capital expenditures
by Suncor's Oil Sands business unit:
-----------------------------------------------------------------------------------------------------------------------
2001 2000
-----------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES BY QUARTER 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q
-- -- -- -- -- -- -- --
-----------------------------------------------------------------------------------------------------------------------
Property acquisitions 4 - - 9 13 4 - -
-----------------------------------------------------------------------------------------------------------------------
Drilling activity 4 - 4 14 1 - - -
-----------------------------------------------------------------------------------------------------------------------
Capital Additions to Facilities (1) 305 384 392 363 466 363 552 409
-----------------------------------------------------------------------------------------------------------------------
Note:
(1) Includes capital spending on Project Millennium, Firebag Oil Sands
Projects, acquisition of mining equipment, and other capital spending
11
ENVIRONMENTAL COMPLIANCE
For a description of the impact of environmental protection requirements on Oil
Sands, refer to "Environmental Risks" and "Government Regulation" in the
"Risk/Success Factors" section of this AIF.
NATURAL GAS
Suncor's Natural Gas business, based in Calgary, Alberta, explores for, develops
and produces conventional natural gas in western Canada, supplying it to markets
throughout North America. The sale of NG production provides an internal hedge
for natural gas consumption at Suncor's Oil Sands and Sunoco businesses. In
addition, Suncor's U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., is
acquiring land and exploring for coal bed methane in the United States.
In April 2000, Suncor's Board of Directors approved a repositioning of the
Exploration and Production business and renamed it Natural Gas to reflect a
sharpened focus on natural gas production. The repositioning entailed the
consolidation of production in three core natural gas areas, and a restructuring
of business processes to support the new focus.
During 2000, NG targeted its natural gas focus in Western Canada by
concentrating on natural gas prospects and selling most of its conventional
crude oil properties. Exiting 2001, natural gas and natural gas liquids
accounted for approximately 94% of the NG business unit's production.
Suncor's exploration program is focused on multiple geological zones in three
core asset areas: Northern (northeast British Columbia and northwest Alberta),
Foothills (western Alberta and portions of northeast British Columbia) and
Central Alberta. Suncor drills primarily medium to high-risk wells focusing on
prospects that can be connected to existing infrastructure.
An in-house natural gas marketing group sells Suncor's proprietary natural gas
and natural gas acquired from other producers. During 1997, Suncor entered into
a five-year agreement with Enron Capital and Trade Resources Canada Corp.
("ECT") for ECT to provide operational and administrative services to Suncor
related to its natural gas portfolio. This agreement was terminated without cost
to Suncor in December 2001. ECT continues to provide natural gas related
operational and administrative services to Suncor under a short-term agreement.
RESERVES AND RESERVES RECONCILIATION
GLJ reported January 29, 2002, on Suncor's estimated proved and probable
reserves of natural gas, natural gas liquids and crude oil (other than reserves
from Suncor's mining leases and the Firebag in-situ reserves), as of December
31, 2001. Information with respect to these reserves is set out in the tables
below and in the tables under the headings "Crude Oil and Natural Gas Liquids"
and "Natural Gas" (the "Reserves Tables"). GLJ's determination of Suncor's
estimated proved and probable recoverable reserves are based on constant year
end prices and costs determined as of the dates indicated with no escalation
into the future. The accuracy of any reserve estimate is a function of the
quality and quantity of available data and of engineering interpretation and
judgment. While reserve and production estimates presented are considered
reasonable, the estimates should be viewed with the understanding that reservoir
performance subsequent to the date of the estimate may justify revision, either
upward or downward.
IN THE RESERVES TABLES:
(1) Proved reserves and probable reserves have the meanings set out
in the Glossary of Terms at the front of this Annual Information
Form. All proved and probable reserves are in Canada.
(2) Proved developed reserves are on production, or reserves that could
be recovered from existing wells or facilities, if the Company placed
them on production.
12
(3) Gross reserves represent the aggregate of Suncor's undivided percentage
interest in reserves including the royalty interest of governments and
others in such reserves and Suncor's royalty interest in reserves of
others. Net reserves are gross reserves less that royalty interest
share of others including governments. Royalties can vary depending
upon selling prices, production volumes, and timing of initial
production and changes in legislation. Net reserves have been
calculated following generally accepted guidelines, on the basis of
prices and the royalty structure in effect at year-end and anticipated
production rates. Such estimates by their very nature are inexact and
subject to constant revision.
The following tables set out a reconciliation of NG's estimated proved reserves
from December 31, 2000 to December 31, 2001.
ESTIMATED PROVED RESERVES RECONCILIATION(1)
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
-------------------- ------------------- -------------------- -------------------
(MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC
FEET) FEET)
December 31, 2000............... 16(1) 797 11 567
Revisions of previous estimates. (1) (3) - 4
Extension and discoveries....... - 27 - 20
Production...................... (1) (65) (1) (45)
Sales of minerals in place...... - (1) - (1)
------- ------ ------ -------
December 31, 2001............... 14(1) 755 10 545
======= ====== ====== =======
Note:
(1) Includes 8.6 million barrels of natural gas liquids as at December 31,
2001 (9.2 million barrels as at December 31, 2000).
Estimated proved reserves are comprised of developed and undeveloped reserves.
The following tables show the breakdown between these categories.
ESTIMATED PROVED DEVELOPED RESERVES RECONCILIATION
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
-------------------- ------------------- -------------------- -------------------
(MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC
FEET) FEET)
December 31, 2000............... 13 573 9 409
Revisions of previous estimates. (1) 31 - 27
Extension and discoveries....... - 34 - 25
Production...................... (1) (65) (1) (45)
Sales of minerals in place...... - - - -
------- -------- ------- ------
December 31, 2001............... 11 573 8 416
======= ======== ======= ======
13
ESTIMATED PROVED UNDEVELOPED RESERVES RECONCILIATION
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
-------------------- ------------------- -------------------- -------------------
(MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC
FEET) FEET)
December 31, 2000................ 3 224 2 158
Revisions of previous estimates.. - (34) - (23)
Extension and discoveries........ - (7) - (5)
Sales of minerals in place....... - (1) - (1)
----- ----- ----- -----
December 31, 2001................ 3 182 2 129
===== ===== ===== =====
The following table sets out a reconciliation of NG's estimated probable
reserves from December 31, 2000 to December 31, 2001.
ESTIMATED PROBABLE RESERVES RECONCILIATION
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
-------------------- ------------------- -------------------- -------------------
(MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC
FEET) FEET)
December 31, 2000................ 7 304 5 217
Revisions of previous estimates.. (1) (80) - (57)
Purchases of minerals in place... - - - -
Extension and discoveries........ - 16 - 11
Sales of minerals in place....... - (3) - (2)
December 31, 2001................ 6 237 5 169
===== ====== ===== =======
CONVENTIONAL CRUDE OIL
The following table shows estimates of NG's proved crude oil reserves before
royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation") and
Suncor's average daily production of crude oil before royalties, in Alberta and
British Columbia, represented by the conventional fields identified in this
table.
14
PROVED RESERVES 2001 AVERAGE
BEFORE ROYALTIES AT DAILY PRODUCTION
DECEMBER 31, 2001(1) BEFORE ROYALTIES(3)
-------------------- -------------------
(MILLIONS OF (BARRELS OF
FIELDS BARRELS) % OIL PER DAY) %
---------------------------
Simonette.............................. 2.3 47 647 44
Blueberry.............................. 1.8 37 374 25
McKinley............................... 0.2 4 120 8
Bonanza................................ 0.2 4 61 4
Rosevear............................... 0.1 2 133 9
Boundary Lake.......................... 0.1 2 25 2
Other(2)............................... 0.3 4 110 8
--- --- ------ ---
Total-- gross.......................... 5 100 1,470 100
=== === ====== ===
Notes:
(1) The reserves and production in this table do not include natural gas
liquids.
(2) Includes fields in which Suncor holds overriding royalty interests.
(3) Production in 2001 was materially different from 2000 due to strategic
divestments.
Most of the large conventional oil fields in the western provinces have been in
production for a number of years and the rate of production in these fields is
subject to natural decline. In some cases, additional amounts of crude oil can
be recovered by using various methods of enhanced crude oil recovery, infill
drilling and production optimization techniques. At the end of 2001,
approximately 90% of Suncor's proved conventional oil reserves were under
enhanced oil recovery programs.
15
NATURAL GAS LIQUIDS
The following table shows estimates of NG's proved natural gas liquids reserves
before royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation")
and Suncor's average daily production of natural gas liquids before royalties,
in Alberta and British Columbia, represented by the conventional fields
identified in this table.
PROVED RESERVES 2001 AVERAGE
BEFORE ROYALTIES AT DAILY PRODUCTION
DECEMBER 31, 2001 BEFORE ROYALTIES
-------------------- -------------------
(MILLIONS OF (BARRELS OF
FIELDS BARRELS) % OIL PER DAY) %
---------------------------
Simonette............................... 2.0 23 502 21
Grande Prairie.......................... 1.4 16 183 8
Knopcik................................. 1.2 14 389 16
Pine Creek.............................. 0.8 9 247 10
Glacier................................. 0.5 6 94 4
Stolberg................................ 0.5 6 49 2
Blueberry............................... 0.5 6 164 7
Rosevear................................ 0.4 5 227 10
Blackstone.............................. 0.3 4 68 3
Phoenix................................. 0.2 2 36 2
George.................................. 0.1 1 175 7
Hinton.................................. 0.1 1 53 2
Mountain Park........................... 0.1 1 18 1
Boundary Lake........................... 0.1 1 23 1
Other(1)................................ 0.8 5 141 6
--- --- ------ ---
Total-- gross........................... 9 100 2,369 100
=== === ====== ===
Note:
(1) Includes fields in which Suncor holds overriding royalty interests.
16
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.
PROVED RESERVES 2001 AVERAGE
BEFORE ROYALTIES AT DAILY PRODUCTION
DECEMBER 31, 2001 BEFORE ROYALTIES
-------------------- -------------------
(MILLIONS OF (BARRELS OF
FIELDS BARRELS) % OIL PER DAY) %
---------------------------
Stolberg............................... 216 29 22 12
Blackstone/Brown Creek................. 79 11 21 12
Grande Prairie area.................... 59 8 7 4
Mountain Park.......................... 52 7 11 6
Knopcik area........................... 50 7 16 9
Glacier................................ 49 6 8 5
Simonette.............................. 40 5 9 5
Rosevear............................... 39 5 21 12
Blueberry.............................. 38 5 11 6
Sinclair............................... 20 3 7 4
Pine Creek............................. 18 2 6 3
Cutbank................................ 16 2 12 7
Other(1)............................... 79 10 26 15
--- --- --- ---
Total-- Gross.......................... 755 100 177 100
=== === === ===
Note:
(1) Includes fields in which Suncor holds overriding royalty interests.
LAND HOLDINGS
The following table sets out the undeveloped and developed lands in which the NG
business unit held crude oil and natural gas interests at the end of 2001.
Undeveloped lands are lands within their primary term upon which no well has
been drilled. Developed lands are lands past their primary term or upon which a
well has been drilled.
The petroleum and natural gas interests include Suncor's undivided percentage
interest in leases, licenses, reservations, permits or exploration agreements
(collectively, the "Agreements"). In general, Agreements confer upon the lessee
the right to explore for and remove crude oil and natural gas from the lands,
with the lessee paying exploration and development costs, operating costs,
abandonment costs and reclamation costs, subject to paying rentals, taxes and
royalties. Interests in Agreements (excluding freehold agreements) are acquired
from the federal or provincial governments through competitive bidding or by
undertaking work commitments, or by joint venture agreements with industry
companies.
17
UNDEVELOPED ACRES
-----------------
GROSS ACRES(1) NET ACRES(1)
-------------- ------------
(THOUSANDS)
CANADA
Western provinces 627 508
INTERNATIONAL 1,685 1,227
===== =====
Total Undeveloped Landholdings 2,312 1,735
===== =====
Note:
(1) "Gross Acres" means all of the acres in which Suncor has either an
entire or undivided percentage interest in. "Net Acres" represents the
acres remaining after deducting the undivided percentage interests of
others from the gross acres.
DRILLING
The following table sets forth the gross and net exploratory and development
wells, in Western Canada, the United States and Australia, which were completed,
capped or abandoned in which Suncor participated during the years indicated.
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000
---- ----
GROSS NET GROSS NET
----- --- ----- ---
Exploratory Wells
Crude oil............................ - - - -
Gas.................................. 5 4 3 1
Dry (1).............................. 22 16 17 15
Total Exploratory Wells................... 27 20 20 16
---- ---- ---- ----
Development Wells
Crude oil............................ 1 - 5 2
Gas.................................. 24 16 23 14
Dry.................................. 4 2 4 3
- - - -
Total Development Wells .................. 29 18 32 19
---- ---- ---- ----
Total..................................... 56 38 52 35
==== ==== ==== ====
NOTE:
(1) Includes 18 gross (14 net) coal bed methane wells in 2001.
Not included are earning wells completed by other companies under farmout
agreements relating to lands in which Suncor has an undivided percentage
interest, since Suncor did not incur cash expenditures in connection with such
wells. In addition to the above wells, Suncor had interests in 27 gross (14 net)
exploratory wells in progress and 12 gross (seven net) development wells in
progress at the end of 2001.
Suncor continues to hold interests in frontier properties (Arctic and Northwest
Territories) including 28 long-term "significant discovery licences".
18
WELLS
The following table summarizes the wells in which the NG business unit has a
working interest or a royalty interest as at December 31, 2001.
Producing Non-Producing
Wells(1)(2) Wells(1)(3)
----------- -------------
Gross Net Gross Net
----- ---- ----- ----
CONVENTIONAL CRUDE OIL WELLS
Alberta.............................................................. 47 32 20 17
British Columbia..................................................... 24 11 6 3
Total Conventional Crude Oil Wells........................................ 71 43 26 20
-- -- -- --
CONVENTIONAL NATURAL GAS WELLS
Alberta.............................................................. 269 148 48 25
British Columbia..................................................... 49 24 17 12
TOTAL CONVENTIONAL NATURAL GAS WELLS...................................... 318 172 65 37
--- --- -- --
TOTAL WELLS 389 215 91 57
=== === == ==
Notes:
(1) Gross wells represent the number of wells in which NG has an undivided
percentage interest and net wells represent NG's aggregate undivided
percentage interest share in such wells.
(2) Producing wells are wells producing hydrocarbons or having the
potential to produce, excluding shut-in wells. As at December 31, 2001
Suncor has interests in four oil fields and 29 gas fields.
(3) Non-Producing Wells represent management's estimate of shut-in wells
that could be capable of economic production but were not on production
as at December 31, 2001.
SALES AND SALES REVENUES
The following table shows the breakdown of NG's sources of revenues.
YEAR ENDED
GROSS REVENUES(1) DECEMBER 31,
------------------
2001 2000
---- ----
($ MILLIONS)
Crude oil and natural gas liquids......................................................... 45 77
Natural gas............................................................................... 394 344
Pipeline.................................................................................. 5 6
Other..................................................................................... 5 1
--- ---
Total..................................................................................... 449 428
=== ===
Note:
(1) Includes intersegment revenues.
19
PRODUCTION COSTS
The following shows production (lifting) costs in connection with NG's crude oil
and natural gas operations for the years indicated. In 2001, Suncor began to
convert natural gas to barrels of oil equivalent (BOE) at a 6:1 ratio (thousand
cubic feet of natural gas: barrel of oil); previously, conversion was on a 10:1
basis. Figures prior to 2001 have been restated on a 6:1 basis.
YEAR ENDED
PRODUCTION (LIFTING) COSTS DECEMBER 31,
------------------
2001 2000
---- ----
($ PER BOE OF
GROSS PRODUCTION)
Average production (lifting) cost of conventional crude oil and gas(1)................................ 2.96 3.11
Note:
(1) Production (lifting) costs include all expenses related to the
operation and maintenance of producing or producible wells and related
facilities, natural gas plants and gathering systems. It does not
include an estimate for future reclamation costs.
20
QUARTERLY VOLUMES AND NETBACK ANALYSIS
The following table shows Suncor's average production volumes, pricing,
royalties, operating expenses and netbacks for natural gas, conventional crude
oil and natural gas liquids, for the periods indicated.
2001 2000
------------------------------------------------------ -----------------------------------------------------
4Q 3Q 2Q 1Q 2001 4Q 3Q 2Q 1Q 2000
-------- -------- ------- ------- -------- -------- --------- ------- ------- -------
NATURAL GAS
Production Volume
(mmcf/day) 180 176 177 177 177 183 200 195 222 200
-------- -------- ------- ------- -------- -------- --------- ------- ------- -------
Price ($/mcf) 3.10 3.90 6.78 10.73 6.09 8.02 4.63 3.70 2.96 4.72
Royalties ($/mcf) (0.54) (0.85) (1.58) (2.91) (1.46) (2.14) (1.09) (0.85) (0.61) (1.17)
Operating Expenses
($/mcf) (1) (0.97) (0.79) (0.95) (0.73) (0.86) (0.95) (0.68) (0.77) (0.66) (0.76)
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
Netback ($/mcf) 1.59 2.26 4.25 7.09 3.77 4.93 2.86 2.08 1.69 2.79
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
CONVENTIONAL CRUDE
OIL
Production Volume
(kbbls/d) (2) 1.3 1.5 1.5 1.7 1.5 1.6 3.6 3.5 8.1 4.2
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
Price ($/bbl) 27.17 33.17 36.75 37.35 34.35 36.01 33.09 30.04 26.30 29.50
Royalties ($/ bbl) (1.84) (2.46) (2.60) (2.89) (2.45) (11.52) (9.70) (8.29) (8.31) (9.46)
Operating Expenses
($/ bbl) (1) (7.25) (4.76) (5.69) (3.85) (5.17) (9.47) (6.79) (7.65) (6.62) (7.63)
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
Netback ($/bbl) 18.08 25.95 28.46 30.61 26.73 15.02 16.60 14.10 11.37 12.41
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
NATURAL GAS LIQUIDS
Production Volume
(kbbls/d) (2) 2.4 2.4 2.3 2.3 2.4 2.5 2.8 3.1 3.5 3.0
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
Price ($/bbl) 23.47 30.26 39.32 45.07 34.38 43.00 39.56 32.80 33.16 36.66
Royalties ($/ bbl) (5.96) (10.26) (10.77) (12.86) (9.93) (12.62) (11.50) (9.55) (9.25) (10.73)
Operating Expenses
($/ bbl) (1) (5.83) (4.75) (5.72) (4.40) (5.17) (9.47) (6.79) (7.65) (6.62) (7.63)
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
Netback ($/bbl) 11.68 15.25 22.83 27.81 19.28 20.91 21.27 15.60 17.29 18.30
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
--------- -------- ------- ------- -------- -------- --------- -------- -------- -------
Note:
(1) Operating expenses includes production (lifting) costs and administrative
expenses.
(2) Thousands of barrels per day
21
MARKETING, PIPELINE AND OTHER OPERATIONS
Suncor operates gas processing plants at South Rosevear, Pine Creek, Boundary
Lake South, Progress and Simonette with a total design capacity of approximately
206 million cubic feet per day (mmcf/day). Suncor's capacity interest in these
gas processing plants is approximately 128 mmcf/day. Suncor also has varying
undivided percentage interests in natural gas processing plants operated by
other companies.
Approximately 69% of Suncor's natural gas production is marketed under direct
sales arrangements to customers in Alberta, eastern Canada, and the United
States. Contracts for these direct sales arrangements are of varied terms, with
a majority having terms of one year or less, and incorporate pricing which is
either fixed over the term of the contract or determined on a monthly basis in
relation to a specified market reference price. Under these contracts, NG is
responsible for transportation arrangements to the point of sale. Sales to the
United States are made under a variety of arrangements with different
transportation and pricing terms. NG's direct sales arrangements include some of
the natural gas consumed in Suncor's Oil Sands plant at Fort McMurray and in its
downstream operations.
Approximately 31% of Suncor's natural gas production is sold under existing
contracts to aggregators ("system sales"). Proceeds received by producers under
these sales arrangements are determined on a netback basis, whereby each
producer receives revenue equal to its proportionate share of sales less
regulated transportation charges and a marketing fee. Most of NG's system sales
volumes are contracted to TransCanada Gas Services and Pan-Alberta Gas Ltd.
These companies resell this natural gas primarily to eastern Canadian and
midwest and eastern United States markets.
To ensure ongoing direct sales access to markets in the United States, NG has
entered into long-term gas pipeline transportation contracts. Suncor currently
has 14 million cubic feet per day of firm capacity on the Northern Border
Pipeline to the U.S. midwest that expires October 31, 2003. Suncor also has firm
capacity of 40 mmcf/day on the Pacific Gas Transmission ("PGT") pipeline to the
California border extending to the year 2023.
Suncor's conventional crude oil production is used in its refining operations,
exchanged for other crude oil with Canadian or U.S. refiners, or sold to
Canadian and U.S. purchasers. Sales are generally made under spot contracts or
under contracts that are terminable on relatively short notice. Suncor's
conventional crude oil production is shipped on pipelines operated by
independent pipeline companies. NG currently has no pipeline commitments related
to the shipment of crude oil.
The Suncor-owned Albersun pipeline, operated by Suncor Energy Marketing Inc.,
was constructed in 1968 to transport natural gas to the Oil Sands plant. It
extends approximately 300 kilometres south of the plant and connects with the
TCPL Alberta intra-provincial pipeline system. The Albersun pipeline has the
capacity to move in excess of 100 mmcf/day of natural gas. Suncor arranges for
natural gas supply and controls most of the natural gas on the system under
delivery based contracts. The pipeline moves natural gas both north and south
for Suncor and other shippers. In 2001, throughput on Albersun pipeline was 66
mmcf/day and revenues were approximately $5 million.
CAPITAL AND EXPLORATION EXPENDITURES
The following table sets out, for the quarters indicated, capital expenditures
by Suncor's NG business unit:
--------------------------------------------------------------------------------------------------------------------
2001 2000
--------------------------------------------------------------------------------------------------------------------
($ millions) 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q
--------------------------------------------------------------------------------------------------------------------
Property Acquisition - - - - 8 - 2 1
--------------------------------------------------------------------------------------------------------------------
Exploration 29 4 14 3 17 9 6 18
--------------------------------------------------------------------------------------------------------------------
Development 19 20 17 26 8 13 3 42
--------------------------------------------------------------------------------------------------------------------
22
NG expects to spend $140 million in 2002 to support the Company's goal of
increasing natural gas production.
ENVIRONMENTAL COMPLIANCE
For a description of the impact of environmental protection requirements on NG,
refer to "Environmental Risks" and "Government Regulation" in the "Risk/Success
Factors" section of this AIF.
SUNOCO
Suncor refines and markets petroleum products in central Canada through its
wholly owned subsidiary, Sunoco Inc.. Its refinery in Sarnia, Ontario, refines
petroleum feedstocks from Oil Sands and other sources into gasoline, distillates
and petrochemicals.
Sunoco's controlled distribution channels enhance its position in the Ontario
market. Approximately 59% of Sunoco's sales volume in 2001 was sold through
controlled distribution networks in Ontario that sell gasoline and diesel to
retail customers. Approximately 38% was sold to industrial, commercial,
wholesale and refining customers in Ontario and Quebec, primarily jet fuels,
diesel and gasolines. The remaining 3% represents petrochemical sales through
Sun Petrochemicals Company, a 50% joint venture between Sunoco and a U.S.
refinery.
Sunoco also markets natural gas to approximately 125,000 commercial and
residential customer accounts in Ontario. In 2001, Sunoco completed a strategic
assessment of this business, and is currently exploring alternatives including a
possible disposition, joint venture, or other transaction involving such
business.
Sunoco's financial reporting in 2001 is based on its Rack Back / Rack Forward
organizational structure. The Rack-Back division procures and refines crude oil
and feedstocks, and sells and distributes to the Sarnia refinery's largest
industrial and reseller customers. The Rack-Forward division is comprised of
retail operations, retail natural gas marketing, cardlock and industrial /
commercial sales, and the UPI Inc. ("UPI") and Pioneer Group Inc. ("Pioneer")
joint venture businesses. UPI is a 50% joint venture company owned by Sunoco and
GROWMARK Inc., a U.S. Midwest agricultural supply and grain marketing
cooperative. Pioneer is an independent retailer with which Sunoco has a 50%
joint venture partnership.
PROCUREMENT OF FEEDSTOCKS
Sunoco's refining operation uses both synthetic and conventional crude oil.
Sunoco procured approximately 47% of its synthetic crude oil feedstock from
Suncor's Oil Sands production in 2001, compared with 56% in 2000. In 2001, 55%
of the crude oil refined at the Sarnia Refinery was synthetic crude oil,
compared with 64% in 2000. The balance of the refinery's synthetic crude oil, as
well as its conventional and condensate feedstocks, were purchased from others
under month to month contracts. In the event of a significant disruption in the
supply of synthetic crude oil, the refinery has the flexibility to substitute
other sources of sweet or sour conventional crude oil.
Sunoco procures its conventional crude oil feedstock primarily from western
Canada, supplemented from time to time with crude oil from the United States and
other countries. Foreign crude oil is delivered to Sarnia via pipeline from the
United States Gulf Coast or via the Interprovincial Pipeline from Montreal.
Sunoco has made no firm commitments for capacity on these pipeline systems.
Crude oil is procured from the market on a spot basis or under contracts
terminable on short notice.
In 1998, Sunoco signed a 10-year synergistic feedstock agreement with a
Sarnia-based petrochemical refinery, Nova Chemicals (Canada) Ltd. Under this
buy/sell agreement, Sunoco obtains feedstock that is more suitable for
production of transportation fuels in exchange for feedstock more suitable for
petrochemical cracking. Sunoco also enters into reciprocal buy/sell or exchange
arrangements with other refining companies from time to time as a means to
minimize transportation costs, balance product
23
availability and enhance refinery utilization. Sunoco also purchases refined
products in order to meet customer requirements.
REFINING OPERATIONS
Sunoco's Sarnia Refinery produces transportation fuels (gasoline, diesel,
propane and jet fuel), heating fuels, liquefied petroleum gases, residual fuel
oil, asphalt feedstock, benzene, toluene, mixed xylenes and orthoxylene, as well
as the petrochemicals A-100 and A-150 that are used in the manufacture of paint
and chemicals.
The refinery has the capacity to refine 70,000 barrels of crude oil per day.
Refining sales in 2001 averaged approximately 93,400 barrels per day. The Sarnia
Refinery is configured to allow for operational flexibility. In addition to
conventional sweet and sour crudes, the refinery is capable of processing sweet
synthetic crude oil, which yields a more valuable product mix. A hydrocracker,
jet fuel tower and low-sulphur diesel tower further increase the refinery's
ability to produce premium-value transportation fuels, distillates and naphtha,
and its flexibility to vary the gasoline/distillate ratio. The hydrocracker has
a capacity to process approximately 23,300 barrels per day. Additional
flexibility in gasoline, octane and petrochemical production is provided by the
complementary operations of an alkylation unit with a capacity of 5,400 barrels
per day. The petrochemical facilities, which have a capacity of 13,100 barrels
per day, produce benzene, toluene, and mixed xylenes, and recover orthoxylene
from mixed xylenes, as well as petrochemicals A-100 and A-150.
The refinery has a cracking capacity of 40,200 barrels per day from a Houdry
Catalytic Cracker ("catcracker") and a hydrocracker. Approximately 40% of the
cracking capacity is attributable to the catcracker, which uses older cracking
technology. In 2001, The refinery completed planned maintenance on Plant One,
which consists of a crude unit, catalytic cracker, alkylation unit, and other
treating units. However, the refinery also experienced unplanned outages
involving the catcracker, the BTX unit and the vacuum unit. As a result, crude
utilization declined 6% to 92% in 2001. The following chart sets out daily crude
input, average refinery utilization rates, and cracking capacity utilization of
the Sarnia refinery over the last two years.
Sarnia Refinery Capacity 2001 2000
------------------------------------ ---- ----
Average daily crude input (barrels per day) 64,200 68,900
Average utilization rate (%)(1) 92 98
Average cracking capacity utilization (%)(2) 88 91
Notes:
(1) Based on crude unit capacity and input to crude units.
(2) Based on cracking capacity and input to the hydrocracker and catalytic
cracker.
In 2001 Sunoco entered into an energy supply agreement with TransAlta, under
which steam will be supplied to Sunoco's Sarnia Refinery. For more details, see
the "Sunoco" section under "Three Year Highlights" in this Annual Information
Form.
PRINCIPAL PRODUCTS
Sales of gasolines and other transportation fuels represented 80% of Sunoco's
consolidated revenues and other operating revenues in 2001 compared to 83% in
2000. Set forth below is information on daily sales volumes and percentage of
Sunoco's consolidated revenues contributed by product group for the last two
years.
24
DAILY SALES VOLUMES 2001 2000
------------------- ---- ----
(THOUSANDS OF CUBIC % OF SUNOCO'S (THOUSANDS OF % OF SUNOCO'S
METRES PER DAY) CONSOLIDATED CUBIC METRES CONSOLIDATED
REVENUES PER DAY) REVENUES
Transportation fuels
Gasoline 5.6 42 5.5 44
Retail (1)..................
Other (2)................... 3.1 17 2.8 16
Jet fuel............................ 0.7 4 1.1 5
Other............................... 3.1 17 3.1 18
----- ---- ----- ----
12.5 80 12.5 83
----- ---- ----- ----
Petrochemicals...................... 0.5 4 0.5 4
Heating fuels....................... 0.4 2 0.4 2
Heavy fuel oils..................... 0.8 2 0.6 2
Other............................... 0.6 2 0.6 2
----- ---- ----- ----
Total Refined Products.............. 14.8 90 14.6 93
----- ---- ----- ----
Other Non Refined Products.......... - 10 - 7
----- ---- ----- ----
Total %............................. 100 100
----- ---- ----- ----
----- ---- ----- ----
Notes:
(1) Excludes joint ventures.
(2) Joint ventures
PRINCIPAL MARKETS
Approximately 59% of Sunoco's total sales volumes are marketed through
controlled retail networks, including the Sunoco retail network, joint-venture
operated retail stations, and cardlock operations. This controlled network is
comprised of:
- 302 Sunoco retail service stations
- 154 Pioneer-operated retail service stations
- 47 UPI-operated service stations and a network of bulk distribution facilities
for rural and farm fuels
- 18 Sunoco branded Fleet Fuel Cardlock sites
Refined petroleum products (excluding petrochemicals), and natural gas sold to
commercial and residential accounts are marketed under several brands, including
the Company's Canadian "Sunoco" trademark. Sunoco's other principal trademarks
include "Ultra 94" in respect of its premium high octane gasoline, and "Gold
Diesel" used in respect of its premium low sulphur diesel product.
Approximately 38% of Sunoco's total sales volumes are sold to industrial,
commercial, wholesale, and refining customers, primarily in Ontario. Sunoco also
supplies industrial and commercial customers in Quebec through long-term
arrangements with other regional refiners, or through Group Petrolier Norcan
Inc., a 25% Sunoco-owned fuels terminal and product supply business in Montreal.
Sunoco markets toluene, mixed xylenes, orthoxylene and petrochemicals, primarily
in Canada and the U.S., through Sun Petrochemicals Company. Suncor Energy
Marketing Inc. has a 50% interest in Sun Petrochemicals Company, a petrochemical
marketing joint venture company, to market products from Sunoco's Sarnia
Refinery and a Toledo, Ohio, refinery owned by the joint venture partner. Sun
Petrochemicals Company markets petrochemicals used to manufacture plastics,
rubber, synthetic fibres, industrial solvents and agricultural products, and as
gasoline octane enhancers. All of Sunoco's benzene production is sold directly
to other petrochemical manufacturers in Sarnia.
25
Sunoco's share of total refined product sales in its primary market of Ontario
is approximately 18% in 2001 compared with approximately 17% in 2000.
Transportation fuels accounted for over 84% of Sunoco's total sales volumes in
2001; petrochemicals accounted for 3%. The remaining volumes included other
refined products such as heating fuels, heavy oils and liquefied petroleum
gases, and were sold to industrial users and resellers.
Sunoco supplies refined petroleum products to the Pioneer and UPI joint ventures
under exclusive supply agreements. The UPI joint venture expires in 2002, and
thereafter will be automatically renewed unless terminated upon 120 days prior
written notice. The shareholder agreement between UPI and Sunoco provides that
Sunoco has the exclusive right to supply petroleum products to the joint venture
as long as Sunoco remains as a shareholder of UPI. No notice of termination has
been received or given to date.
In addition to refined product sales, Sunoco also markets natural gas to
approximately 125,000 commercial and residential customer accounts in Ontario.
Margins improved in the natural gas business in 2001 due to a restructuring of
customer contracts that locked in fixed price sales to fixed price supply.
TRANSPORTATION AND DISTRIBUTION
Sunoco uses a variety of transportation modes to deliver products to market,
including pipeline, water, rail and road. Sunoco owns and operates petroleum
transportation, terminal and dock facilities, including storage facilities and
bulk distribution plants in Ontario. The major mode of transporting gasoline,
diesel, jet fuel and heating fuels from the Sarnia Refinery to core markets in
Ontario is the Sun-Canadian Pipe Line, which is 55% owned by Sunoco and 45%
owned by another refiner. The pipeline operates as a private facility for its
owners. It serves terminal facilities in Toronto, Hamilton and London, and has a
capacity of 126,000 barrels per day (20,000 cubic metres). Sunoco utilized 85%
of this capacity in 2001 compared with 84% in 2000.
Sunoco also has direct pipeline access to petroleum markets in the Great Lakes
region of the United States by way of connection to a pipeline system in Sarnia
operated by a U.S.-based refiner. This link to the U.S. allows Sunoco to move
products to market or obtain feedstocks/products when market conditions are
favourable in the Michigan and Ohio markets.
Sunoco believes that its own storage facilities, and those under long-term
contractual arrangements with other parties, are sufficient to meet its current
and foreseeable needs.
CAPITAL EXPENDITURES
Sunoco plans to spend approximately $96 million in 2002 compared with $54
million in 2001. Expenditures in 2002 will include funds associated with meeting
sulphur-in-gasoline limit regulations at its Sarnia refinery. In 2002 and 2003
Sunoco plans to spend $40 million to meet the new 2005 sulphur-in-gasoline
regulated limits. See "Risk / Success Factors Affecting Performance" in the
Sunoco section of MD&A and "Risks Specifically Respecting Sunoco" in the "Risk /
Success Factors" section of this AIF.
ENVIRONMENTAL COMPLIANCE
For a description of the impact of environmental protection requirements on
Sunoco, please refer to the sections entitled "Outlook" and "Risk/Success
Factors Affecting Performance" in the Sunoco section of Management's Discussion
and Analysis in Suncor's 2001 Annual Report. Also refer to "Environmental Risks"
and "Government Regulation" in the "Risk/Success Factors" section of this AIF.
26
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.
YEAR ENDED
DECEMBER 31,
-----------------
2001 2000
-----------------
Oil Sands............................................ 2,367 2,057
Natural Gas.......................................... 190 182
Sunoco(1)............................................ 561 590
Stuart Project....................................... - 77
Corporate(2)......................................... 189 137
----- -----
Total......................................................3,307 3,043
===== =====
Notes:
(1) Excludes joint venture employees.
(2) Reflects inclusion of Calgary-based employees providing technical
support to the Firebag In-Situ Project, as well as some information
technology employees who were previously counted within the individual
business units.
(3) In addition to Suncor employees, independent contractors supply a range
of services to the Company.
The Communications, Energy and Paperworkers Union Local 707 represents
approximately 1,423 Oil Sands employees. Suncor entered into a three-year
collective agreement with the union effective May 1, 2001. Management believes
Suncor's positive working relationship with the union will continue.
Employee associations represent approximately 170 Sunoco Sarnia refinery and
Sun-Canadian Pipe Line Company employees. In March 2001, Sunoco and the Sarnia
employee association signed a one-year agreement that will be renegotiated in
2002. Sunoco management believes Sunoco's positive working relationship with
this association will continue and a new agreement should be reached. The
agreement with the employee association of Sun-Canadian Pipe Line Company was
signed in 1993, and it is renewed automatically each year unless terminated by
written notice by either party at least 60 days prior to the anniversary date of
the agreement. No notice under such agreement has been received or given to
date. Sunoco management believes Sunoco's positive working relationship with
this association will continue and the agreement will be automatically renewed
on its anniversary.
RISK/SUCCESS FACTORS
VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES. Suncor's future financial
performance is closely linked to oil prices, and to a lesser extent natural gas
prices. The price of these commodities can be influenced by global and regional
supply and demand factors. Worldwide economic growth, political developments,
compliance or non-compliance with quotas imposed upon members of the
Organization of Petroleum Exporting Countries and weather, among other things,
can affect world oil supply and demand. Natural gas prices realized by Suncor
are affected primarily by North American supply and demand and by prices of
alternate sources of energy. All of these factors are beyond Suncor's control
and can result in a high degree of price volatility not only in crude oil and
natural gas prices, but also fluctuating price differentials between heavy and
light grades of crude oil, which can impact prices for sour crude. In 2001, the
heavy-light differential widened and reduced earnings. Management believes the
differential will trend toward more historical levels in 2002 if the demand for
heavy oil increases as anticipated. Oil and natural gas
27
prices have fluctuated widely in recent years and Suncor expects continued
volatility and uncertainty in crude oil and natural gas prices. A prolonged
period of low crude oil prices could affect the value of Suncor's crude oil and
gas properties and the level of spending on development projects, and could
result in curtailment of production at some properties, and accordingly could
have an adverse impact on Suncor's financial condition and liquidity and results
of operations. Suncor cannot control the factors that influence supply and
demand or the prices of crude oil or natural gas.
Suncor cannot control the prices of crude oil or natural gas, or currency
exchange rates. However, the Company has a hedging program that fixes the price
of crude oil, and periodically, natural gas, and the associated exchange for a
percentage of Suncor's total production volume. Suncor's objective is to lock-in
prices on a portion of its future production today to reduce exposure to market
volatility and ensure the Company's ability to finance growth. If an operational
upset occurred that reduced or eliminated crude oil and/or natural gas
production for a period of time, Suncor would be required to continue to make
payments under its hedging program if the actual price was higher than the price
hedged. For particulars of Suncor's hedging position as of year-end 2001, see
Note 17 of Suncor's consolidated financial statements.
Suncor conducts an assessment of the carrying value of its assets to the extent
required by Canadian general accepted accounting principles ("GAAP"). If crude
oil and natural gas prices decline, the carrying value of Suncor's assets could
be subject to downward revisions, and Suncor's earnings could be adversely
affected.
RISK FACTORS RELATED TO FIREBAG AND VOYAGEUR PROJECTS. There are certain risks
associated with the execution of the proposed Firebag In-Situ Oil Sands Project
and Voyageur, including: regulatory approvals, schedule, resources and costs,
including the availability and cost of materials, equipment and qualified
labour; the impact of general economic, business and market conditions; the
impact of weather conditions; Suncor's ability to finance Oil Sands growth if
commodity prices were to stay at low levels for an extended period; the impact
of new entrants to the oil sands business which could take the form of
competition for skilled people, increased demands on the Fort McMurray, Alberta
infrastructure (for example, housing, roads and schools), or price competition
for products sold into the marketplace; the potential ceiling on the demand for
synthetic crude oil; and the effect of changing standards of government
regulation and public expectations in relation to the impact of oil sands
development on the environment. The commissioning and integration of new
facilities with the existing asset base could cause delays in achieving targeted
production capacity. Suncor management believes the planned increases in Oil
Sands production through these projects present issues that require prudent risk
management.
RISKS ASSOCIATED WITH INTEGRATION OF PROJECT MILLENNIUM WITH BASE PLANT
OPERATIONS. With Project Millennium commissioning complete by year-end 2001, the
main risks to final Project Millennium execution are associated with integration
of the new facilities with the existing asset base, particularly during the
winter months where risks associated with weather are increased. These risks
could cause unforeseen outages and costs, and delays in achieving full
utilization of the combined production capacity of 225,000 barrels per day.
INCREASED DEPENDENCE ON OIL SANDS BUSINESS. The Company's significant capital
commitment to further its growth projects at Oil Sands, including the Firebag
In-Situ Oil Sands Project, and Voyageur if approved, may require Suncor to
forego investment opportunities in other segments of its operations. The
completion of Project Millennium, and the other future projects to increase
production at Oil Sands, will substantially increase the Company's dependence on
the Oil Sands segment of its business. For example, assuming achievement of Oil
Sands' 2002 production target of 210,000 barrels per day, the Oil Sands business
will account for approximately 86% of Suncor's upstream production in 2002
compared to 79% in 2001 and 74% in 2000.
RISKS ASSOCIATED WITH IN-SITU EXTRACTION. Current steam-assisted gravity
drainage (SAGD) technologies for in-situ recovery of heavy oil and bitumen are
energy intensive, requiring significant consumption of natural gas and other
fuels to produce steam. Although there have been a number of SAGD technology
28
pilot projects and several commercial scale projects are under development and
are scheduled to be on production by the end of 2002, commercial application of
this technology is not yet commonplace.
COMPETITION. The petroleum industry is highly competitive in all aspects,
including the exploration for, and the development of, new sources of supply,
the acquisition of crude oil and gas interests, and the refining, distribution
and marketing of petroleum products and chemicals. Suncor competes in virtually
every aspect of its business with other energy companies. The petroleum industry
also competes with other industries in supplying energy, fuel and related
products to consumers. Suncor offers custom blends of synthetic crude oil to
meet specific customer demands. Suncor believes that the competition for its
custom blended synthetic crude oil production is Canadian conventional and
synthetic sweet and sour crude oil.
A number of other companies have entered or have indicated they are planning to
enter the oil sands business and begin production of bitumen and synthetic crude
oil, or expand existing operations. If all announced competing projects were to
be built, they could quadruple Canada's production of bitumen and upgraded
synthetic crude oil to more than two and half million barrels (400,000 cubic
metres) per day by the end of the decade. The recent trend toward industry
consolidation has created more competitors with financial capacity who may enter
into similar and competing oil sands businesses. Expansion of existing
operations and development of new projects could materially increase the supply
of bitumen and synthetic crude oil and other competing crude oil products in the
marketplace. Depending on the levels of future demand, increased supplies could
have a negative impact on prices.
In the western Canadian diesel market demand and supply can fluctuate. Currently
there is excess supply of diesel fuel and Suncor expects the market could be
impacted by this excess supply and have a negative impact on margins. Margins
for diesel are typically higher than the margins for synthetic and conventional
crude oil. The above noted expansion plans of Suncor's competitors could also
result in an increase in the supply of diesel and further weakening of margins.
Historically, the industry-wide oversupply of refined petroleum products and the
overabundance of retail outlets have kept pressure on downstream margins.
Management expects that fluctuations in demand for refined products, margin
volatility and overall marketplace competitiveness will continue. In addition,
as Suncor's downstream business unit, Sunoco, participates in new product
markets, such as natural gas, it could be exposed to margin risk and volatility
from either cost and/or selling price fluctuations.
NEED TO REPLACE CONVENTIONAL NATURAL GAS RESERVES. The future natural gas
reserves and production of the Company's NG business unit and, therefore, both
NG's cash flow from such production and Suncor's ability to maintain an internal
hedge against growing consumption of natural gas in its Oil Sands and Sunoco
operations, are highly dependent on its success in discovering or acquiring
additional reserves and exploiting its current reserve base. Without natural gas
reserve additions through exploration and development or acquisition activities,
NG's conventional natural gas reserves and production will decline over time as
reserves are depleted. For example, in 2001, Suncor's natural gas average
reservoir decline rates were in the 28% range, consistent with industry
experience. Decline rates will vary with the nature of the reservoir, life-cycle
of the well, and other factors. Therefore past decline rates are not necessarily
indicative of future performance. Exploring for, developing and acquiring
reserves is highly capital intensive. To the extent cash flow from operations is
insufficient to generate sufficient capital and external sources of capital
become limited or unavailable, NG's ability to make the necessary capital
investments to maintain and expand its conventional natural gas reserves could
be impaired. In addition, NG's long term performance is dependent on its ability
to consistently and competitively find and develop low cost, high-quality
reserves that can be economically brought on stream. Market demand for land and
services can also increase or decrease finding and development costs. There can
be no assurance that Suncor will be able to find and develop or acquire
additional reserves to replace production at acceptable costs.
RISKS RELATED TO COALBED METHANE. Coalbed Methane (CBM) exploration is being
undertaken by Suncor in Canada and the U.S. through a wholly owned subsidiary,
Suncor Energy (Natural Gas) America Inc. The identification of gas in coals is
necessary but not sufficient for establishing commercial success.
29
Effective production technology, water handling, well productivity, requirement
for large land blocks, and a pilot production period are risk elements unique to
CBM. In Canada, CBM as a gas resource has not yet been proven commercial, and
bears the additional risk that significant commercial production may require new
technology or only be available in limited areas or at higher long term gas
prices than currently exist.
CBM is a commercial gas resource in the U.S.. The risks associated with CBM
activities in the U.S. vary by geographic region but can include: constraints on
land access from federal, state and individual land holders; local opposition to
well drilling and CBM development; high costs of treating water produced with
CBM gas; limited regional pipeline exit capacity; and strong competition for
mineral leases and services. The regulatory framework and stakeholder
environment varies by region. The physical operation of drilling and ultimately
producing gas in a location distant from Suncor's key management presents risks
of inadequate oversight of operations. Business activity in the U.S. has
different political risk than in Canada, and is conducted in an environment
where litigation and legal risk are more prevalent and substantial.
OPERATING HAZARDS AND OTHER UNCERTAINTIES. Each of Suncor's three principal
business units, Oil Sands, NG and Sunoco, require high levels of investment and
have particular economic risks and opportunities. Generally, Suncor's operations
are subject to hazards and risks such as fires, explosions, gaseous leaks,
migration of harmful substances, blowouts and oil spills, any of which can cause
personal injury, damage to property, equipment and the environment, as well as
interrupt operations. In addition, all of Suncor's operations are subject to all
of the risks normally incident to the transportation, processing and storing of
crude oil, natural gas and other related products.
At Oil Sands, mining oil sand, extracting bitumen from the oil sand, and
upgrading bitumen into synthetic crude oil and other products, involve
particular risks and uncertainties. Oil Sands is susceptible to loss of
production, slowdowns, or restrictions on its ability to produce higher value
products due to the interdependence of its component systems. Severe climatic
conditions at Oil Sands can cause reduced production and in some situations
result in higher costs. While there is no finding cost associated with oil sands
resources, the costs associated with production, including mine development and
drilling of wells for SAGD operations, and the costs associated with upgrading
bitumen into synthetic crude oil, can entail significant capital outlays. The
costs associated with synthetic crude oil production at Oil Sands are largely
fixed and, as a result, operating costs per unit are largely dependent on levels
of production.
Aboriginal peoples have claimed aboriginal title and rights to a substantial
portion of western Canada. Certain aboriginal peoples have filed a claim against
the government of Canada, certain governmental entities and the Regional
Municipality of Wood Buffalo (which includes the city of Fort McMurray,
Alberta), claiming, among other things, a declaration that the plaintiffs have
aboriginal title to large areas of lands surrounding Fort McMurray, including
the lands on which Oil Sands and most of the other oil sands operations in
Alberta are situated. To Suncor's knowledge the aboriginal peoples have made no
claims against Suncor and Suncor is unable to assess the effect, if any, the
claim would have on its Oil Sands operations.
In Suncor's NG business unit, the risks and uncertainties associated with the
exploration for, and the development, production, transportation and storage of
crude oil, natural gas and natural gas liquids should not be underestimated or
viewed as predictable. NG's operations are subject to all of the risks normally
incident to drilling for natural gas wells, the operation and development of
such properties, including encountering unexpected formations or pressures,
premature declines of reservoirs, blow-outs, equipment failures and other
accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or
well fluids, adverse weather conditions, pollution, and other environmental
risks.
Suncor's downstream business unit, Sunoco, is subject to all of the risks
normally incident to the operation of a refinery, terminals and other
distribution facilities, as well as service stations, including loss of product
or slowdowns due to equipment failures or other accidents.
Although Suncor maintains a risk management program, including an insurance
component, such insurance may not provide adequate coverage in all
circumstances, nor are all such risks insurable.
30
Losses resulting from the occurrence of these risks could have a material
adverse impact on Suncor. Under the Company's business interruption insurance
coverage, the Company would bear the first $U.S.260 million of any loss arising
from a future insured incident at its Oil Sands operations.
In addition, there are risks associated with growth projects that rely largely
or partly on new technologies and the incorporation of such technologies into
new or existing operations. The success of projects incorporating new
technologies, such as the Firebag In-Situ Oil Sands Project, cannot be assured.
There are also inherent risks, including political and foreign exchange risk, in
investing in business ventures internationally. To date, Suncor does not have
material international investments but is investigating coalbed methane
opportunities in the United States. However, export sales in 2001 represented
15% of Suncor's 2001 consolidated revenue (2000 - 14%).
INTEREST RATE RISK. Suncor is exposed to fluctuations in short-term Canadian
interest rates as a result of the use of floating rate debt. Suncor maintains a
substantial portion of its debt capacity in revolving, floating rate bank
facilities and commercial paper, with the remainder issued in fixed rate
borrowings. To minimize its exposure to interest rate fluctuations, Suncor
occasionally enters into interest rate swap agreements and exchange contracts to
either effectively fix the interest rate on floating rate debt or to float the
interest rate on fixed rate debt. For more details, see the "Liquidity and
Capital Resources" section of MD&A.
EXCHANGE RATE FLUCTUATIONS. Suncor's consolidated financial statements are
presented in Canadian dollars. Results of operations are affected by the
exchange rates between the Canadian dollar and the U.S. dollar. These exchange
rates have varied substantially in the last five years. A substantial portion of
Suncor's revenue is received by reference to U.S. dollar denominated prices. Oil
prices are generally set in U.S. dollars, while Suncor's sales of refined
products are primarily in Canadian dollars. Fluctuations in exchange rates
between the U.S. and Canadian dollar may therefore give rise to foreign currency
exposure, either favorable or unfavorable, creating another element of
uncertainty. In the future, the strength of the Canadian dollar relative to
foreign currencies could create additional uncertainties for Suncor as it
pursues its international growth plans.
ENVIRONMENTAL RISKS. Environmental legislation affects nearly all aspects of
Suncor's operations. These regulatory regimes are laws of general application
that apply to Suncor in the same manner as they apply to other companies and
enterprises in the energy industry. The regulatory regimes require Suncor to
obtain operating licenses and permits in order to operate, and impose certain
standards and controls on activities relating to mining, oil and gas
exploration, development and production, and the refining, distribution and
marketing of petroleum products and petrochemicals. Environmental assessments
and regulatory approvals are required before initiating most new major projects
or undertaking significant changes to existing operations. In addition to these
specific, known requirements, Suncor expects future changes to environmental
legislation will likely impose further requirements on companies operating in
the energy industry. Some of the issues include the possible cumulative impacts
of oil sands development in the Athabasca region; storage, treatment, and
disposal of hazardous or industrial waste, the need to reduce or stabilize
various emissions, issues relating to global climate change including the
potential impacts of government regulation; land reclamation and restoration;
Great Lakes water quality; and reformulated gasoline to support lower vehicle
emissions. Changes in environmental legislation could have a potentially adverse
effect on Suncor from the standpoint of product demand, product reformulation
and quality, methods of production and distribution and costs. For example,
requirements for cleaner-burning fuels could cause additional costs to be
incurred, which may or may not be recoverable in the marketplace. The complexity
and breadth of these issues make it extremely difficult to predict their future
impact on Suncor. Management anticipates capital expenditures and operating
expenses could increase in the future as a result of the implementation of new
and increasingly stringent environmental regulations. Compliance with
environmental legislation can require significant expenditures and failure to
comply with environmental legislation may result in the imposition of fines and
penalties, liability for clean up costs and damages and the loss of important
permits.
31
Suncor is required to and has posted annually with Alberta Environment an
irrevocable letter of credit equal to $0.03 per bbl of crude oil produced ($15
million as at December 31, 2001) as security for the estimated cost of its
reclamation activity on Leases 86 and 17, and the Steepbank Mine. For Project
Millennium, Suncor has posted an irrevocable letter of credit equal to
approximately $26 million, representing security for the estimated cost of
reclamation activities relating to Project Millennium up to the end of January,
2002.
UNCERTAINTY OF RESERVE AND RESOURCE ESTIMATES. The reserve data and resource
estimates for Suncor's Oil Sands and NG business units, included in Suncor's
Annual Information Form, represent estimates only. There are numerous
uncertainties inherent in estimating quantities and quality of these proved and
probable reserves and other resources, including many factors beyond the control
of Suncor.
In general, estimates of economically recoverable reserves are based upon a
number of variable factors and assumptions, such as historical production from
the properties, the assumed effect of regulation by governmental agencies and
future operating costs, all of which may vary considerably from actual results.
The accuracy of any reserve estimate is a matter of engineering interpretation
and judgment and is a function of the quality and quantity of available data,
which may have been gathered over time. In the Oil Sands business unit, reserve
estimates are based upon a geological assessment, including drilling and
laboratory tests, and also consider current production capacity and upgrading
yields, current mine plans, operating life and regulatory constraints. The
Firebag reserves and resource estimates are based upon a geological assessment
based upon the data gathered from evaluation drilling, the testing of core
samples and seismic operations. In the NG business unit, reservoir performance
subsequent to the date of the estimate may justify revision, either upward or
downward. For these reasons, estimates of the economically recoverable reserves
attributable to any particular group of properties, and in NG the classification
of such reserves based on risk of recovery prepared by different engineers or by
the same engineers at different times, may vary substantially. At Oil Sands, the
independent audit does not take into account the economic aspects of future
reserves. Suncor's actual production, revenues, taxes and development and
operating expenditures with respect to its reserves will vary from such
estimates, and such variances could be material.
Certain information included in this annual information form to describe
Suncor's reserves and resources, such as "probable reserves" and "resources", is
prohibited in filings with the United States Securities and Exchange Commission
by U.S. companies. The differences between Canadian and U.S. standards of
reporting reserves and resources may make it difficult to compare Suncor's
reserve and resource information with the reserve information of companies
subject to the U.S. standards of reporting.
RISKS SPECIFICALLY RESPECTING SUNOCO. Sunoco's operations are sensitive to
wholesale and retail margins for its refined products, including gasoline.
Margin volatility is influenced by overall marketplace competitiveness, weather,
the cost of crude oil (See "Volatility of Crude Oil and Natural Gas Prices.")
and fluctuations in supply and demand for refined products. Sunoco expects that
margin and price volatility and overall marketplace competitiveness will
continue.
In 1999, the Canadian government passed legislation limiting sulphur levels in
gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end
of 2004, and a maximum of 30 ppm by 2005. The Canadian refining industry faces
significant capital spending to construct sulphur removal facilities to meet
these requirements. In 2001 Sunoco finalized an investment plan to meet those
limits. Capital spending to achieve compliance is expected to be approximately
$40 million, and will involve the addition of a new desulphurization unit.
Construction of the unit is planned for 2002 and 2003.
The federal government has proposed a regulation under the CANADIAN
ENVIRONMENTAL PROTECTION ACT that will limit the level of sulphur in diesel fuel
used in on-road vehicles to a maximum of 15 ppm. The proposed regulation is
expected to come into effect in June 2006 for producers and importers, and in
September 2006 for sellers. Regulations with respect to off-road diesel and
light fuel oil are also expected. Sunoco continues to examine strategic options
to comply with the pending regulations. Actual capital required to meet the new
standards is subject to further development of such regulations and
32
strategic assessment by Sunoco. The cost to comply with the sulphur-in-diesel
limits could be significant but is not currently expected to place the Company
at a competitive disadvantage.
LABOUR RELATIONS. Suncor's hourly employees at its Oil Sands facility near Fort
McMurray and its Sarnia refinery are represented by a labour union and an
employee association, respectively. Suncor's collective agreement with the
Communications, Energy and Paperworkers Union Local 707 at Oil Sands was
renegotiated in May 2001 for a three-year term. Any work interruptions involving
Suncor's employees, or contract trades utilized in its growth projects, could
materially and adversely affect Suncor's business and financial position.
GOVERNMENTAL REGULATION. The oil and gas industry in Canada, including the oil
sands industry and the downstream segment of the Company, operates under
federal, provincial and municipal legislation. This industry is also subject to
regulation and intervention by governments in such matters as land tenure,
royalties, government fees, production rates, environmental protection controls,
the export of crude oil, natural gas and other products, the awarding or
acquisition of exploration and production, oil sands or other interests, the
imposition of specific drilling obligations, environmental protection controls,
control over the development and abandonment of fields and mine sites (including
restrictions on production) and possibly expropriation or cancellation of
contract rights. Before proceeding with most major projects, including
significant changes to existing operations, Suncor must obtain regulatory
approvals. The regulatory approval process can involve stakeholder consultation,
environmental impact assessments and public hearings, among other things. In
addition, regulatory approvals may be subject to conditions including security
deposit obligations and other commitments. Failure to obtain regulatory
approvals, or failure to obtain them on a timely basis, could result in delays,
abandonment or restructuring of projects and increased costs, all of which could
negatively affect future earnings and cash flow. Such regulations may be changed
from time to time in response to economic or political conditions. The
implementation of new regulations or the modification of existing regulations
affecting the crude oil and natural gas industry could reduce demand for crude
oil and natural gas, increase Suncor's costs and have a material adverse affect
on its financial condition.
33
SELECTED CONSOLIDATED FINANCIAL INFORMATION
SELECTED CONSOLIDATED FINANCIAL INFORMATION
The following selected consolidated financial information for each of the years
in the three-year period ended December 31, 2001 is derived from Suncor's
consolidated financial statements. The consolidated financial statements for
each of the years in the three-year period ended December 31, 2001 have been
audited by PricewaterhouseCoopers LLP, Chartered Accountants. Suncor's 2001
audited consolidated financial statements accompanied by the audit report of
PricewaterhouseCoopers LLP for each of the years in the three-year period ended
December 31, 2001. The information set forth below should be read in conjunction
with the MD&A and Suncor's consolidated comparative financial statements and
related notes.
YEAR ENDED DECEMBER 31,(1)
----------------------------
2001 2000 1999
---- ---- ----
($ MILLIONS EXCEPT PER SHARE
AMOUNTS)
Revenues................................................. 3,995 3,388 2,387
Net earnings............................................. 388 377 186
Per common share(1) (undiluted).......................... 1.63 1.58 0.74
Per common share(1) (diluted)............................ 1.61 1.57 0.73
Cash flow provided from operations....................... 831 958 591
Per common share(1)...................................... 3.52 4.11 2.51
Capital and exploration expenditures..................... 1,678 1,998 1,350
AS AT DECEMBER 31,
---------------------------
2001 2000 1999
---- ---- ----
($ MILLION)
Total assets.............................................. 8,094 6,833 5,176
Long-term borrowings(2)................................... 3,113 2,193 1,307
Accrued liabilities and other(3) 251 252 236
Common shareholders' equity(4)............................ 2,263 1,958 1,594
Notes:
(1) Per share amounts for all years reflect a two-for-one share split in 2000
and payments on the preferred securities issued in 1999.
(2) Includes current portion.
(3) See Notes 12 and 13 to Suncor's 2001 Consolidated Financial Statements,
which Notes are incorporated by reference herein.
(4) Excludes Preferred Securities issued in 1999. See Dividend Policy and
Record.
DIVIDEND POLICY AND RECORD
Suncor's Board of Directors has established a policy of paying dividends on a
quarterly basis. This policy is reviewed from time to time in light of Suncor's
financial position, its financing requirements for growth, its cash flow and
other factors considered relevant by Suncor's Board of Directors. A dividend of
$0.085 per common share for the first quarter of 2002 has been declared, payable
on March 25, 2002 to shareholders of record on March 15, 2002.
34
During 1999, the Company completed a Canadian offering of $276 million of 9.05%
preferred securities and a U.S. offering of U.S.$162.5 million of 9.125%
preferred securities, the proceeds of which totalled Canadian $507 million after
issue costs of $17 million ($10 million after income tax credits of $7 million).
The preferred securities are unsecured junior subordinated debt of the Company,
due in 2048 and redeemable at the Company's option on or after March 15, 2004.
Subject to certain conditions, the Company has the right to defer payment of
interest on the securities for up to 20 consecutive quarterly periods. Deferred
interest and principal amounts are payable in cash, or, at the option of the
Company, from the proceeds on the sale of equity securities of the Company
delivered to the trustee of the preferred securities. For accounting purposes,
the preferred securities are classified as share capital in the consolidated
balance sheet and the interest distributions thereon, net of income taxes, are
classified as dividends.
The following table sets forth the per share amount of dividends paid by Suncor
during the last three years.
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
---- ---- ----
Common Shares
Cash dividends(1).................................. $0.34 $0.34 $0.34
Preferred Securities
Cash interest distributions........................ $0.21 $0.21 $0.17
Dividends paid in common shares.................... -- -- --
Note:
(1) Per share amounts for 2000 and 1999 have been adjusted to reflect a
two-for-one share split in 2000.
FUTURE COMMITMENTS TO BUY, SELL, EXCHANGE OR TRANSPORT CRUDE OIL AND NATURAL GAS
In order to ensure continued availability of, and access to, transportation
facilities for the crude oil and natural gas products of its Oil Sands and
Natural Gas business units, the Company has entered into long-term contracts for
pipeline capacity on various third party systems.
The Company's Oil Sands business unit has entered into a long-term commitment
with Enbridge for the transportation of sour crude oil and bitumen from Suncor's
oil sands plant near Ft. McMurray, Alberta, to Hardisty, Alberta. Particulars of
that commitment are described under the heading "Operations" in the "Oil Sands"
section of this Annual Information Form.
Natural gas product pipeline commitments are described in the following table:
35
--------------------------------------------------------------------------------------------------------------
AGGREGATE
--------------------------------------------------------------------------------------------------------------
NATURE OF COMMITMENTS TERM VOLUME PRICE/COST PRICE PER THOUSAND
(MMCF/DAY) CUBIC FEET
--------------------------------------------------------------------------------------------------------------
($ MILLIONS)
--------------------------------------------------------------------------------------------------------------
Natural gas pipeline commitments:
--------------------------------------------------------------------------------------------------------------
Nova 1998-2008 ** 30 $0.17
--------------------------------------------------------------------------------------------------------------
Westcoast Energy 2001-2006 27 9 $0.23
--------------------------------------------------------------------------------------------------------------
Foothills 1997-2003 16 1 $0.08
--------------------------------------------------------------------------------------------------------------
Northern Border 1997-2003 14 5 $0.52
--------------------------------------------------------------------------------------------------------------
Alberta Natural Gas 1991-2008 41 8 $0.07
--------------------------------------------------------------------------------------------------------------
Pacific Gas Transmission 1995-2023 40 164 $0.49
--------------------------------------------------------------------------------------------------------------
** volume varies on an annual basis
The Company's Natural Gas business has entered into numerous natural gas
purchase and sale commitments, aggregating 90 mmcf/day and 180 mmcf/day,
respectively. Purchase commitment terms vary from one to three years and pricing
varies, representing a combination of fixed and index-based pricing. Sales
commitments consist of both short- and long- term contracts ranging from one to
eight years in duration, with varying pricing generally based on a combination
of fixed and index-based terms.
Oil Sands has also entered into long-term contracts to sell crude oil products
to customers, some of which are described under the heading, "Revenues from
Synthetic Crude Oil and Diesel", in the "Oil Sands" section of this Annual
Information Form. In addition, the Company enters into crude oil and foreign
currency swap and option contract to protect its future Canadian dollar earnings
and cash flows from the potential adverse impact of low petroleum prices and an
unfavourable U.S./Canadian dollar exchange rates. For further particulars of
these hedging arrangements, see the information under the heading "Hedging",
under "Risk/Success Factors Affecting Performance" in the "Corporate" section of
the Company's MD&A, incorporated by reference herein, and Note 17 to Suncor's
2001 Consolidated Financial Statements, which note is incorporated by reference
herein.
Also see Note 14 to Suncor's 2001 Consolidated Financial Statements, which note
is incorporated by reference herein, for a further description of the Company's
operating commitments for 2002 and subsequent years.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Suncor's MD&A is incorporated by reference into and forms an integral part of
this Annual Information Form, and should be read in conjunction with the
consolidated comparative financial statements and the notes thereto.
MARKET FOR THE SECURITIES OF THE ISSUER
The common shares of Suncor are listed on The Toronto Stock Exchange in Canada,
and on the New York Stock Exchange in the United States. To the best of
management's knowledge, approximately 50% of Suncor's common shares are
beneficially held by residents of the United States. Suncor's 9.05% preferred
securities are listed on The Toronto Stock Exchange in Canada, and Suncor's
9.125% preferred securities are listed on the New York Stock Exchange in the
United States.
36
DIRECTORS AND OFFICERS
As of the date hereof, Suncor's Board of Directors is comprised of eleven
directors. The term of office of each director is from the date of the meeting
at which he or she is elected or appointed until the next annual meeting of
shareholders or until a successor is elected or appointed. The Board of
Directors is required to have, and has, an Audit Committee. The Board of
Directors also has a Board Policy, Strategy Review and Governance Committee, a
Human Resources and Compensation Committee, and an Environment, Health and
Safety Committee.
The following table sets out certain information with respect to Suncor's
directors.
VOTING SECURITIES OF
PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY
OR EMPLOYMENT, AND OWNED OR OVER WHICH
MAJOR POSITIONS AND CONTROL OR DIRECTION
NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT
RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2002(1)
---------------------------- -------------------- ----------------------- ----------------------
Mel Benson(2) (5) April 19, 2000 to Management Services 2,565 Common Shares
Calgary, Alberta Present Consultant
367 Deferred Share
Units(3)
Brian A. Canfield(2)(4) November 10, 1995 Chairman 6,000 Common Shares
Point Roberts, Washington to Present TELUS Corporation (a
telecommunications 3,770 Deferred Share
company) Units(3)
Bryan P. Davies(2)(5) January 28, 1991 Senior Vice 6,200 Common Shares
Etobicoke, Ontario to April 23, 1996 President, Regulatory
Affairs, Royal Bank 1,644 Deferred Share
April 19, 2000 to of Canada (a Units(3)
Present chartered banking
institution)
John T. Ferguson(5)(6) November 10, 1995 Chairman, Princeton 8,374 Common Shares
Edmonton, Alberta to Present Developments Ltd. (a
real estate 1,955 Deferred Share
development company), Units(3)
Chair of the Board,
TransAlta Corporation
(an electric utility
company)
37
VOTING SECURITIES OF
PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY
OR EMPLOYMENT, AND OWNED OR OVER WHICH
MAJOR POSITIONS AND CONTROL OR DIRECTION
NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT
RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2002(1)
---------------------------- -------------------- ----------------------- ----------------------
Richard L. George(6) February 1, 1991 President and Chief 99,277 Common Shares
Calgary, Alberta to Present Executive Officer,
Suncor Energy Inc.(7)
Poul Hansen(2)(5)(9) April 23, 1996 to Chairman and General 7,291 Common Shares
Vancouver, British Columbia Present Manager, Sperling
Hansen Associates
Inc. (an
environmental
engineering
consulting company)
John R. Huff(4)(6) January 30, 1998 Chairman and Chief 10,354 Common Shares
Houston, Texas to Present Executive Officer,
Oceaneering 4,047 Deferred Share
International, Inc. Units(3)
(an oilfield services
company)
Robert W. Korthals(5)(6)(8) April 23, 1996 to Corporate Director 8,000 Common Shares
Toronto, Ontario Present
3,343 Deferred Share
Units (3)
M. Ann McCaig(2)(4) October 1, 1995 to President, VPI 5,144 Common Shares
Calgary, Alberta Present Investments Ltd. (a
private investment 4,227 Deferred Share
holding company) Units(3)
JR Shaw(4)(6) January 30, 1998 Executive Chair, Shaw 41,600 Common Shares
Calgary, Alberta to Present Communications Inc.
(a diversified 6,234 Deferred Share
communications Units(3)
company); Chairman
of the Board of
Directors of Suncor
Energy Inc.
38
VOTING SECURITIES OF
PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY
OR EMPLOYMENT, AND OWNED OR OVER WHICH
MAJOR POSITIONS AND CONTROL OR DIRECTION
NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT
RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2002(1)
---------------------------- -------------------- ----------------------- ----------------------
W. Robert Wyman(4)(6)(9) November 25, 1987 Retired Chairman of 32,400 Common Shares
West Vancouver, British to Present the Board of
Columbia Directors of Suncor 4,138 Deferred Share
Energy Inc. Units(3)
Notes:
(1) The information relating to holdings of Common Shares, not being within
the knowledge of Suncor, has been furnished by the respective nominees
individually. Fractional Common Shares have been excluded from the
numbers shown. Certain of the Common Shares held by Mr. George, Mr.
Hansen and Mr. Shaw are held jointly with their respective spouses. The
number of Common Shares held by Mr. George includes 82,486 Common
Shares over which he exercises control or direction but which are
beneficially owned by members of his family. Certain Common Shares held
by Mr. Benson (400) and Mr. Shaw (1,000) are beneficially owned by
their respective spouses, but they respectively exercise control or
direction over such shares.
(2) Member of the Environment, Health and Safety Committee.
(3) Deferred Share Units (DSU's) are not voting securities but are included
for informational purposes as they are Common Share equivalents.
(4) Member of the Human Resources and Compensation Committee.
(5) Member of the Audit Committee.
(6) Member of the Board Policy, Strategy Review and Governance Committee.
(7) Mr. George also serves as director and/or officer of certain
subsidiaries of Suncor.
(8) In 1998, Mr. Korthals was a director of Anvil Range Mining Corporation,
which sought protection under the COMPANIES CREDITORS ARRANGEMENT ACT
(Canada).
(9) Retiring from the Board in April 2002.
Each of the nominees has been engaged in the principal occupation (or in other
executive capacities for the same, affiliated or predecessor entities) indicated
above for the past five years, except for Mr. Benson, who from 1996 to 2000 was
the Senior Operations Advisor, African Development, Exxon Co. International, Mr.
Shaw, who became the Chairman of the Board of Suncor in 2001 and Mr. Wyman, who
in 1999 and prior thereto was Vice Chairman of the Board of Directors of
Fletcher Challenge Canada Limited.
The following are officers of the Corporation. Except where otherwise indicated,
the persons named in the table below held the offices set out opposite their
respective names as at December 31, 2001 and as of the date hereof.
39
NAME AND MUNICIPALITY OF RESIDENCE OFFICE(1)
---------------------------------- ---------
JR SHAW..............................................Chairman of the Board
Calgary, Alberta
RICHARD L. GEORGE....................................President and Chief Executive Officer
Calgary, Alberta
M.M. (MIKE) ASHAR....................................Executive Vice President, Oil Sands
Fort McMurray, Alberta
DAVID W. BYLER.......................................Executive Vice President, Natural Gas and Renewable
M.D. of Rockyview, Alberta Energy
MICHAEL W. O'BRIEN...................................Executive Vice President, Corporate Development and
Canmore, Alberta Chief Financial Officer
THOMAS L. RYLEY......................................Executive Vice President, Sunoco
Toronto, Ontario
TERRENCE J. HOPWOOD..................................Senior Vice President and General Counsel
Calgary, Alberta
SUE LEE..............................................Senior Vice President, Human Resources and
Calgary, Alberta Communications
KEVIN NABHOLZ Senior Vice President, Major Projects
Fort McMurray, Alberta
J. KENNETH ALLEY.....................................Vice.President, Finance
Calgary, Alberta
JANICE B. ODEGAARD...................................Vice.President, Associate General Counsel and
Calgary, Alberta Corporate Secretary
Note:
(1) The principal occupation of each officer is the specified office with
Suncor except Mr. Shaw, who is also Executive Chair of Shaw
Communications Inc.
All of the foregoing officers of the Company have, for the past five years, been
actively engaged as executives or employees of Suncor or its affiliates, except
Mr. Shaw, as described in Note (1) to the above table.
The percentage of Common Shares of Suncor owned beneficially, directly or
indirectly, or over which control or direction is exercised by Suncor's
directors and senior officers, as a group, is less than 1%.
ADDITIONAL INFORMATION
Copies of the documents set out below may be obtained without charge by any
person upon request to the Company at 112 - 4 Avenue S.W., Calgary, Alberta, T2P
2V5, by calling 1-800-558-9071, by e-mail request to info@suncor.com.
----------------
(i) The current Suncor Annual Information Form together with any pertinent
information incorporated by reference therein;
(ii) The current Suncor comparative financial statements for the most
recently completed financial
40
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.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. UNDERTAKING
Suncor Energy Inc. (the "Registrant") undertakes to make available, in
person or by telephone, representatives to respond to inquiries made by the
staff of the Securities and Exchange Commission ("SEC"), and to furnish
promptly, when requested to do so by the SEC staff, information relating to the
securities in relation to which the obligation to file an annual report on Form
40-F arises or transactions in said securities.
B. CONSENT TO SERVICE OF PROCESS
The Registrant has filed previously with the SEC a Form F-X in connection
with the Common Shares.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
SUNCOR ENERGY INC.
Date: March 28, 2002 BY: "DAVID W. BYLER"
-----------------------------------
DAVID W. BYLER
Executive Vice President, Natural
Gas and Renewable Energy
EXHIBIT INDEX
EXHIBIT DESCRIPTION OF EXHIBIT
------------- ----------------------
EXHIBIT 1 Reconciliation to U.S. GAAP
EXHIBIT 2 Audited Consolidated Financial Statements of Suncor Energy Inc. for the
fiscal year ended December 31, 2001
EXHIBIT 3 Management's Discussion and Analysis for the fiscal year ended December 31,
2001, dated February 28, 2002
EXHIBIT 4 Excerpt from pages 69 and 70 of Suncor Energy Inc.'s 2001 Annual Report to
Shareholders
EXHIBIT 5 Consent of PricewaterhouseCoopers LLP
EXHIBIT 6 Consent of Gilbert Laustsen Jung Associates Ltd.