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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: October 2000 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
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EXHIBIT INDEX
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<CAPTION>
EXHIBIT DESCRIPTION OF EXHIBIT
<S> <C>
*EXHIBIT 1 Form 40F/A
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EXHIBIT 1
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Page 1 of 101 pages. Exhibit Index begins on page 43.
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 40-F/A
(Check One)
/ / Registration statement pursuant to Section 12 of the Securities
Exchange Act of 1934
or
/X/ Annual report pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934
For fiscal year ended: December 31, 1999
Commission File Number: No. 1-12384
SUNCOR ENERGY INC.
(Exact name of registrant as specified in its charter)
1311,1321,2911,
CANADA 4613,5171,5172 NOT APPLICABLE
(Province or other (Primary standard industrial (I.R.S. employer
jurisdiction of classification code number, identification number, if
incorporation if applicable) applicable)
or organization)
112 - 4TH AVENUE S.W.
BOX 38
CALGARY, ALBERTA, CANADA T2P 2V5
(403) 269-8100
(Address and telephone number of registrant's principal executive office)
CT CORPORATION SYSTEM
111 EIGHTH AVENUE
NEW YORK, NEW YORK, U.S.A. 10011
(212) 894-8940
(Name, address and telephone number of agent for service in the United States)
<PAGE>
Securities registered pursuant to Section 12(b) of the Act:
Title Name of each exchange on which
registered:
COMMON SHARES NEW YORK STOCK EXCHANGE, INC.
Securities registered or to be registered pursuant to Section 12(g) of the Act:
NONE
Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act:
None
For annual reports, indicate by check mark the information filed with this form:
/X/ Annual Information Form /X/ Audited Financial Statements
Indicate the number of outstanding shares of each of the issuer's classes of
capital or common stock as of the close of the period covered by the annual
report:
COMMON SHARES 110,516,205
PREFERRED SHARES, SERIES A NONE
----------------------
Indicate by check mark whether the registrant by filing the information
contained in this form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934
(the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to
the registrant in connection with such rule.
Yes / / No /X/
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13(d) or 15(d) of the Exchange Act during the
proceeding 12 months (or for such shorter period that the registrant has been
required to file such reports); and (2) has been subject to such filing
requirements in the past 90 days.
Yes /X/ No / /
Page 2 of 101
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This Form 40F/A is being filed with one set of typographical corrections as
described below and is otherwise identical to the Form 40F filed in March 2000.
The measurement of "acres" has changed to "hectares" in the table appearing on
page 15 of the Annual Information Form under the heading "Land Holdings".
Consequently, some of the numbers in the table under "Land Holdings" have been
amended to reflect this change.
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SUNCOR ENERGY INC. ANNUAL INFORMATION FORM
FEBRUARY 24, 2000
Amended October 12, 2000
<PAGE>
ANNUAL INFORMATION FORM
TABLE OF CONTENTS
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PAGE
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GLOSSARY OF TERMS............................................................... iii
CONVERSION TABLE................................................................ vi
ITEM 1 INCORPORATION........................................................... 1
Incorporation of the Issuer................................................ 1
Subsidiaries of Suncor..................................................... 1
ITEM 2 GENERAL DEVELOPMENT OF THE BUSINESS..................................... 1
Five-Year Highlights....................................................... 2
ITEM 3 NARRATIVE DESCRIPTION OF THE BUSINESS................................... 4
OIL SANDS..................................................................... 4
Operations................................................................. 4
Leasehold Interests and Royalties.......................................... 5
Estimated Synthetic Crude Oil Reserves..................................... 6
Reserves Reconciliation.................................................... 7
Revenues from Synthetic Crude Oil and Diesel............................... 7
Capital Expenditures....................................................... 8
Environmental Compliance................................................... 8
EXPLORATION AND PRODUCTION.................................................... 8
Reserves and Reserves Reconciliation....................................... 8
Conventional Oil and Non-Conventional Heavy Oil............................ 11
Natural Gas................................................................ 12
Land Holdings.............................................................. 14
Drilling................................................................... 15
Wells...................................................................... 15
Sales and Sales Revenues................................................... 16
Marketing, Pipeline and Other Operations................................... 17
Capital and Exploration Expenditures....................................... 17
Environmental Compliance................................................... 17
SUNOCO........................................................................ 18
Refining................................................................... 18
Retail Marketing........................................................... 20
Capital Expenditures....................................................... 20
Environmental Compliance................................................... 21
SUNCOR EMPLOYEES.............................................................. 21
YEAR 2000 RESULTS............................................................. 21
RISK/SUCCESS FACTORS.......................................................... 21
ITEM 4 SELECTED CONSOLIDATED FINANCIAL INFORMATION............................. 26
Selected Consolidated Financial Information................................ 26
Dividend Policy and Record................................................. 27
ITEM 5 MANAGEMENT'S DISCUSSION AND ANALYSIS.................................... 27
ITEM 6 MARKET FOR THE SECURITIES OF THE ISSUER................................. 28
ITEM 7 DIRECTORS AND OFFICERS.................................................. 28
ITEM 8 ADDITIONAL INFORMATION.................................................. 31
</TABLE>
ii
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GLOSSARY OF TERMS
INDUSTRY TERMS
BITUMEN/HEAVY OIL
Tar-like form of oil that when extracted can be upgraded into light
sour synthetic crude oil, light sweet synthetic crude oil and other petroleum
products.
CAPABILITY
For Oil Sands, the maximum output that can be achieved given that
provisions must be made for planned maintenance, routine outages and required
service.
CAPACITY
Maximum output that can be achieved from a facility given ideal
operating conditions.
CONVENTIONAL CRUDE OIL
Oil produced through wells by normal oil field methods.
DOWNSTREAM
This business segment manufactures, distributes and markets refined
products from crude oil.
DRY HOLE/WELL
An exploration or development well incapable of producing hydrocarbons,
which is plugged, reclaimed and abandoned.
GROSS PRODUCTION/RESERVES
Suncor's interest in gross production or gross reserves, as the case
may be, 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.
IN-SITU OIL
Heavy oil that can be extracted from deep deposits of oil sands
in-situ or in place, that is, without removing the overburden or other ground
cover.
LIGHT SOUR SYNTHETIC CRUDE OIL
Produced by Oil Sands. Requires only partial upgrading and contains a
higher sulphur content than light sweet synthetic crude oil.
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LIGHT SWEET SYNTHETIC CRUDE OIL
Produced by Oil Sands. Blend of hydrocarbons resulting from thermal
cracking and purifying of bitumen.
NATURAL GAS LIQUIDS
Propane, butane, or pentane plus, or a combination thereof, obtained
from processing of raw gas or condensates.
NET PRODUCTION/RESERVES
Suncor's interest in total production or total reserves, as the case
may be, after deducting Crown royalties, freehold and overriding royalty
interests.
NET WELLS/LAND HOLDINGS
Suncor's interest in the gross number of wells or gross number of
acres, as the case may be, after deducting interests of partners.
OVERBURDEN
Material overlying the oil sands that must be removed before mining.
Consists of muskeg, glacial deposits and sand.
PROVED AND PROBABLE OIL SANDS RESERVES
Annual estimates made by Suncor of recoverable bitumen reserves
associated with Company surface mineable oil sands leases. The estimates are
allocated between proven and probable categories based upon criteria agreed
to by management and reviewed by independent consultants. The proved reserves
are considered to be conservative estimates in which there is a very high
degree of confidence. Probable reserves incorporate portions of the mine that
have a lower drilling density and are expected to be recovered under current
approvals for a period in excess of 30 years, if further expansions do not
occur. There is at least a 50% chance that the proved plus probable reserve
estimates will be exceeded. The bitumen estimates are converted to synthetic
crude oil estimates on the basis of yields currently being obtained.
RESERVOIR
Body of porous rock containing an accumulation of water, crude oil or
natural gas.
SYNTHETIC CRUDE OIL
Upgraded or partially upgraded crude oil from oil sands including light
sweet synthetic and light sour synthetic crude oil.
UNDEVELOPED OIL AND GAS LANDS
Lands on which no producing or commercially producible well has been
drilled.
UPSTREAM
These business segments explore for, acquire, develop, produce and
market crude oil and natural gas, including the production of light sweet
synthetic and light sour synthetic crude oil and other oil products from the oil
sands.
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UTILIZATION
The average use of capability given that unplanned outages and
unscheduled maintenance will occur.
WELLS
DEVELOPMENT WELL
A well expected to produce from an oil or gas reservoir known to be
productive.
DRILLED WELL
A well having a defined status: gas well, oil well or dry and
abandoned, after reclamation work.
EXPLORATORY WELL
A well drilled in unproved or semi-proved territory with the intention
to find commercial deposits of crude oil or natural gas in a new reservoir.
ACCOUNTING TERMS
BARREL OF OIL EQUIVALENT (BOE)
Converts natural gas to oil on the approximate long-term economic
equivalent basis that 10,000 cubic feet of natural gas equals one barrel of
oil.
FINDING COSTS
Includes the cost of and investment in undeveloped land, geological
and geophysical activities, exploratory drilling and direct administrative
costs necessary to discover oil and gas reserves.
DEVELOPMENT COSTS
Includes all costs associated with moving reserves from other classes
such as "proved", "proved undeveloped" and "probable" to the "proved developed"
class.
LIFTING COSTS
Includes all expenses related to the operation and maintenance of
producing or producible wells, gas plants and gathering systems.
INTEREST COVERAGE -- CASH FLOW BASIS
Cash provided from operating activities before interest expense and
income tax payments divided by interest expense plus interest capitalized.
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).
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RETURN ON CAPITAL EMPLOYED
Earnings before long-term interest expense as a percentage of
average capital employed. Average capital employed is the total of
shareholders' equity and debt (short-term borrowings and current and
long-term borrowings) less significant capital projects in process at the
beginning and end of the year divided by two.
RETURN ON SHAREHOLDERS' EQUITY
Earnings as a percentage of average shareholders' equity. Average
shareholders' equity is the aggregate of total shareholders' equity at the
beginning and end of the year divided by two.
CONVERSION TABLE
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<CAPTION>
<S> <C>
1 cubic metre m(3) = 6.29 barrels 1 tonne = 0.984 tons (long)
1 cubic metre (natural gas) = 35.49 cubic feet 1 tonne = 1.102 tons (short)
1 cubic metre (overburden) = 1.31 cubic yards 1 kilometre = 0.62 miles
1 hectare = 2.5 acres
</TABLE>
Notes:
Conversion using the above factors on rounded numbers appearing in this Annual
Information Form may produce small differences from reported amounts.
Some information in this Annual Information Form is set forth in metric units
and some in imperial units.
vi
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FORWARD LOOKING STATEMENTS
This Annual Information Form contains certain forward-looking
statements which are based on Suncor's current expectations, estimates,
projections and assumptions and were made by Suncor in light of its
experience and its perception of historical trends. All statements that
address expectations or projections about the future, including statements
about Suncor's strategy for growth, expected expenditures, commodity prices,
costs, schedules and production volumes and operating or financial results,
are forward looking statements. Some of the forward looking statements may be
identified by words like "expects," "anticipates," "plans," "intends,"
"believes," "projects," "indicates," "could" and similar expressions. These
statements are not guarantees of future performance and involve a number of
risks, uncertainties and assumptions. Suncor's business is subject to risks
and uncertainties, some of which are similar to other oil and gas companies
and some of which are unique to Suncor. Suncor's actual results may differ
materially from those expressed or implied by its forward looking statements
as a result of known and unknown risks, uncertainties and other factors. The
risks, uncertainties and other factors that could influence actual results
include: changes in general economic, market and business conditions;
fluctuations in supply and demand for Suncor's products; fluctuations in
commodity prices; fluctuations in foreign currency exchange rates; Suncor's
ability to respond to changing markets; the ability of Suncor to produce and
transport crude oil and natural gas to markets; Suncor's levels of capital
expenditures; the ability of Suncor to receive timely regulatory approvals;
the successful and timely implementation of its growth projects including
Project Millennium; the integrity and reliability of Suncor's capital assets;
the cumulative impact of other resource development projects; Suncor's
ability to comply with current and future environmental laws; the accuracy of
Suncor's production estimates and production levels and its success at
exploration and development drilling and related activities; the maintenance
of satisfactory relationships with unions, employee associations and joint
venturers; competitive actions of other companies, including increased
competition from other oil and gas companies, other oil sands development
projects, or from companies which provide alternative sources of energy; the
uncertainties resulting from potential delays or changes in plans with
respect to exploration or development projects or capital expenditures;
actions by governmental authorities including increasing taxes or changes in
environmental and other regulations; the ability and willingness of parties
with whom Suncor has material relationships to perform their obligations to
Suncor; and the occurrence of unexpected events such as fires, blowouts,
freeze-ups, equipment failures and other similar events affecting Suncor or
other parties whose operations or assets directly or indirectly affect
Suncor. Many of these risk factors are discussed in further detail throughout
this Annual Information Form and in Management's Discussion and Analysis for
the year ended December 31, 1999 and dated February 24, 2000, 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.
vii
<PAGE>
ITEM 1 INCORPORATION
INCORPORATION OF THE ISSUER
Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the
amalgamation under the CANADA BUSINESS CORPORATIONS ACT on August 22, 1979 of
Sun Oil Company Limited, incorporated in 1923, and Great Canadian Oil Sands
Limited, incorporated in 1953. On January 1, 1989, Suncor amalgamated with a
wholly owned subsidiary under the CANADA BUSINESS CORPORATIONS ACT. In September
1995, Suncor's articles were amended to change the location of its registered
office from Toronto, Ontario, to Calgary, Alberta. In April 1997, Suncor's
articles were amended to divide its issued and outstanding shares on a
two-for-one basis, and to change the company's name to Suncor Energy Inc. In
January 2000, Suncor announced its intention to further subdivide its issued and
outstanding shares on a two-for-one basis, subject to all necessary approvals
including shareholder approval, at Suncor's annual and special meeting scheduled
for April 19, 2000.
Suncor's registered and principal office is currently 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 has two principal subsidiaries. Sunoco Inc. is wholly owned by
Suncor, and is incorporated under the laws of Ontario. Sunoco refines and
markets petroleum products and petrochemicals directly and indirectly through
subsidiaries and joint ventures. In this Annual Information Form, references to
"Sunoco" mean Sunoco Inc., its subsidiaries and joint venture investments,
unless the context otherwise requires. Sunoco is unrelated to Sunoco, Inc.
(formerly known as Sun Company, Inc.), which has offices in Pennsylvania.
Suncor's second principal subsidiary is Suncor Energy Marketing Inc.,
which carries on business primarily in Ontario and Alberta, is wholly owned by
Sunoco Inc. and is incorporated under the laws of Alberta. Suncor Energy
Marketing Inc. has two divisions: the first, a crude oil marketing division,
which markets certain products produced by Suncor's oil sands business unit
("Oil Sands") and Suncor's exploration and production business unit
("Exploration and Production" or "E&P"), as well as other third party products;
the second is a petrochemicals marketing division, which principally manages its
participation in a petrochemical products joint venture partnership.
ITEM 2 GENERAL DEVELOPMENT OF THE BUSINESS
Suncor is a Canada-based integrated energy company. Suncor explores
for, acquires, produces and markets crude oil and natural gas, refines crude
oil, and markets petroleum and petrochemical products.
Suncor has three principal operating business units. Oil Sands, based
near Fort McMurray, Alberta, produces light sweet synthetic and light sour
synthetic crude oil, diesel fuel and various custom blends from oil sands mined
in the Athabasca region of northeastern Alberta, and markets these products in
Canada and the United States. Exploration and Production , based in Calgary,
Alberta, explores for, acquires, develops, produces and markets natural gas
throughout North America and crude oil in Canada. Sunoco, headquartered in
Toronto, refines crude oil and markets a broad range of petroleum products
mostly in Ontario, and markets petrochemical products in the United States and
Europe. In 1997 Sunoco started an energy marketing business and began marketing
natural gas to residential and commercial customers in Ontario. Effective
November 1, 1998 Suncor established a marketing subsidiary, Suncor Energy
Marketing Inc., which among other things markets the products produced by
Suncor's Oil Sands and E&P business units. In addition, on January 1, 2000,
Suncor created an In-Situ and International Oil business development unit, which
includes the Stuart Oil Shale Project in Australia and the Company's recently
announced Firebag in-situ project.
Sunoco completed construction and started commissioning of the Stuart
Oil Shale demonstration plant in Queensland, Australia in 1999. Commissioning is
behind schedule and a review is underway which will help
1
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determine when the project will be able to achieve reliable production. This
project is currently being treated as a corporate project for segmented
reporting purposes in the consolidated financial statements. A decision as to
whether the technology is viable will be made in 2000.
In 1999 Suncor produced approximately 120,200 barrels per day of crude
oil and natural gas liquids (approximately 6 percent of Canada's crude oil
production) and 226 million cubic feet per day of natural gas. In 1998, Suncor
was the 3rd largest crude oil and gas liquids producer and 19th largest natural
gas producer in Canada.
In 1999, Suncor sold approximately 87,000 barrels (13,800 m3) per day
of refined products, mainly in its core regional market of Ontario, with some
exports to the United States and Europe. Suncor's refined product sales in
Ontario represented approximately 16 % percent of Ontario's total refined
product sales in 1999.
FIVE-YEAR HIGHLIGHTS
In 1994 and 1995 Suncor announced a series of plans to increase
production capability at the Oil Sands plant. Also in 1994 Suncor announced
plans to expand its mining operation to leases and lots directly across the
Athabasca River from the existing operation (the "Steepbank Mine"). The
Steepbank Mine and fixed plant expansion were designed to operate for 20 years
at an average production rate of 105,000 barrels a day. Regulatory approval to
increase production relating to the Steepbank Mine and fixed plant expansion was
received in 1997. Production from the Steepbank Mine commenced in the third
quarter of 1998. During 1999, Oil Sands production averaged 105,600 barrels per
day.
In 1995, Sunoco, Inc. (formerly Sun Company, Inc.), Suncor's former
principal shareholder, sold its 55 percent holding of Suncor common shares to a
group of Canadian underwriters for resale to investors.
In 1997, separate pipeline projects announced by Suncor and Enbridge
Inc. ("Enbridge") (formerly IPL Energy Inc.) were combined into a single project
to be constructed and owned by Enbridge Pipelines (Athabasca) Inc., a subsidiary
of Enbridge, and initially operated by Suncor. Suncor expects the combined
project will have capacity sufficient to meet Suncor's anticipated crude oil
shipping requirements for the foreseeable future. Enbridge placed the pipeline
into service in the second quarter of 1999.
In June 1997, Sunoco and joint venture participants, Southern Pacific
Petroleum NL ("SPP") and Central Pacific Minerals NL ("CPM") of Australia,
announced the first stage of the Stuart Oil Shale Project in Gladstone,
Queensland, Australia. The first phase is a 4,500-barrel per day demonstration
plant. Sunoco's portion of the cost at the end of 1999 was $214 million ($237
million including capitalized interest of $23 million), an increase from the
original estimated cost of $210 million. $82 million of this amount has been
funded by way of project financing from SPP and CPM. The higher costs are due to
the delay in the start up of the facility. The success of the Stuart Oil Shale
Project is subject to uncertainty because of the developmental nature of the
project and the inherent risks associated with the use of the new technology. If
the project is unsuccessful, capitalized costs, including capitalized interest,
investments in CPM and SPP and the project financing liability would be written
off. The impact on future earnings, should this occur, is currently estimated to
be a reduction in earnings of $55 million to $65 million. If the first stage of
the project proves successful, the subsequent stages have the potential to
increase production to 85,000 barrels per day within 10 years. Sunoco and
SPP/CPM will ultimately have a 50/50 interest in the project. Suncor is the
operator of the demonstration plant.
In 1997, Suncor made investments in partly paid Restricted Class shares
of SPP and CPM totalling $4 million. These investments convey to Suncor a right,
but not an obligation, to fully pay for 18,850,000 and 57,000,000 Restricted
Class shares of CPM and SPP, respectively, for an additional investment of
approximately $64 million. The balance is payable within six months of the
project becoming fully operational. If Suncor does not pay the balance owing on
the shares as stipulated, its Restricted Class shares would be forfeited and the
$4 million charged to expense. These Restricted Class Shares would be
convertible into an equal number of common shares in June 2004, or earlier in
certain circumstances.
In July 1997, Suncor announced plans to invest $2.2 billion in a
project ("Project Millennium") designed to increase Oil Sands' production
capacity. Detailed engineering studies conducted in 1998 resulted in a revision
of Project Millennium design capacity from the original estimate of 210,000
barrels per day to the current estimate of 225,000 barrels per day. The first
phase of Project Millennium was a $190 million investment in the existing Oil
2
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Sands plant designed to increase production to an estimated 130,000 barrels per
day by 2001. The $2 billion second phase includes a $90 million technical,
environmental and socio-economic assessment to determine an efficient and
responsible approach to Project Millennium, which assessment was completed in
1998. Project Millennium was approved in 1999 by both Suncor's Board of
Directors and by the Alberta Energy & Utilities Board. In February 1999, Suncor
announced the integrated project team of Canadian based companies including
Suncor who would undertake the engineering, procurement, construction,
commissioning and start-up of Project Millennium. Project Millennium
construction began in April 1999. At the end of 1999, construction of Phase 2
was 17% complete with engineering 79% complete. Also in 1997, Sunoco entered the
natural gas marketing business in Ontario.
In the first quarter of 1998 Suncor arranged syndicated credit
facilities totaling $1.296 billion. Borrowings under the syndicated credit
facilities will be used for general corporate purposes and have been arranged in
anticipation of the Company's planned multi-billion dollar capital expenditure
program over the next three years, primarily related to Project Millennium. The
facilities are unsecured and rank equally with other unsecured and
unsubordinated indebtedness of Suncor.
During 1998, TransAlta Energy Corporation ("TransAlta") announced plans
to build a cogeneration facility in Sarnia. Sunoco continues to evaluate its
participation in TransAlta's project. Such involvement will be subject to
enabling rules and regulations emanating from the Ontario government's
electricity deregulation process. These rules and regulations include acceptable
tariff structures currently under a rate hearing by the Ontario Energy Board.
Due to the length of the deregulation process, start-up is now estimated to be
in mid-2002, as opposed to the 1998 estimate of completion in 2001. If the
project proceeds, it is expected to supply some of Sarnia's power consuming
industries, including Sunoco's Sarnia refinery, with lower-cost power and steam.
In March 1999, Suncor and TransAlta announced TransAlta's plans to
build, own and operate a $315 million cogeneration facility at Suncor's Oil
Sands site near Fort McMurray, to meet a portion of Oil Sands' electricity and
steam requirements and to supply electricity to the Alberta power grid. The
cogeneration facility is being built in phases and is designed to generate 360
megawatts of electricity when fully operational, which is expected to be in
2001. TransAlta estimates the first phase consisting of two gas turbines
producing 220 megawatts of electricity will begin operation in early 2000.
Commissioning of other cogeneration equipment is expected to continue throughout
2000. In October 1999 TransAlta also took over operation of Suncor's existing
energy services plant.
In September 1999, Dow Jones announced that Suncor was to be included
in the newly formed Dow Jones Sustainability Index, which is the world's first
family of global equity indices tracking the performance of 200 leading
sustainability-driven companies in 68 industry groups in 22 countries.
On January 27, 2000, Suncor announced a $750 million plan to further
expand its Oil Sands business by adding a commercial scale in-situ project and
increasing the upgrading capacity of its Fort McMurray operations. The plan is
subject to Board of Directors and regulatory approval. The in-situ portion of
the project, which will cost an estimated $450 million, is to be integrated with
Suncor's open pit mining operation, and is designed to add up to 35,000 barrels
of bitumen per day in 2004. Long-term plans call for further investments to
increase in-situ production capacity in stages to approximately an additional
140,000 barrels of bitumen per day by the end of the decade.
To give Suncor the capability to process the additional bitumen, the
Company plans to expand its upgrading facilities by adding a vacuum tower
complex. This $300 million upgrader expansion will be designed to enable
Suncor's plant output to reach an estimated 260,000 barrels per day in 2004.
Suncor also has plans to invest at least $100 million over the next
five years to pursue alternative and renewable energy opportunities that include
the capture and sequestration of carbon dioxide.
For further information on the status of the Oil Sands Project
Millennium, reference is made to the information under the headings "Outlook" in
the OIL SANDS section of Suncor's Management's Discussion and Analysis for the
year ended December 31, 1999 and dated February 24, 2000 ("MD&A"), which MD&A is
incorporated by reference herein. For further information on the highlights of
1999, reference is also made to MD&A.
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ITEM 3 NARRATIVE DESCRIPTION OF THE BUSINESS
OIL SANDS
Suncor produces light sweet synthetic and light sour synthetic crude
oil and other petroleum products 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 90 percent of
Suncor's conventional and synthetic crude oil production, represent a
significant portion of Suncor's asset base, cash flow and earnings.
OPERATIONS
Suncor's integrated Oil Sands business involves four operations: a
mining operation using trucks and shovels to mine the oil sand; extraction which
involves extracting bitumen from the oil sands; a heavy oil upgrading process,
where bitumen is converted into lighter crude products and an energy services
plant (operated by TransAlta), which provides the site with steam and electric
power.
The first step of the open pit mining operation is the removal of
overburden with trucks and shovels to access the oil sands -- a mixture of sand,
clay, and bitumen. The oil sands ore is transported to one of four sizing plants
by a fleet of trucks. The ore is dumped into sizers where it is crushed and then
transported to the extraction plant. On the west bank of the Athabasca river,
the ore is transported by a conveyor system which stretches approximately three
miles. On the east bank, a slurry of partially processed ore from the Steepbank
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.
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 light sour synthetic crude oil, is either sold
directly to customers or is further upgraded into light sweet synthetic 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. Theese product blends are shipped approximately 270
miles in Suncor's pipeline to Edmonton, Alberta for sale and distribution to
Suncor's Sarnia, Ontario refinery, as well as other customers in Canada and the
United States. For a term that commenced in 1999 and extends to 2028, Oil Sands
entered into a transportation service agreement with Enbridge for additional
pipeline capacity. This agreement now allows for the shipment of light sour
synthetic crude oil and bitumen from Fort McMurray, Alberta to Hardisty,
Alberta. As the initial shipper on the pipeline, Suncor's annual tolls payable
under the agreement could be subject to annual adjustments.
Most of Oil Sands current energy needs are met by its energy services
plant which uses mainly petroleum coke, a by-product of the coking process, as
fuel. The operation also consumes natural gas. The natural gas used includes
volumes produced by Suncor, as well as gas purchased from others. TransAlta
began operating this facility in October 1999. In the future, Suncor's energy
needs will be met from its existing energy services plant and the new TransAlta
onsite cogeneration facility.
In 1998, Suncor entered into an agreement with Nova Pipeline Ventures
Limited Partnership, now known as TransCanada Pipeline Ventures Limited
Partnership ("TCPV"), to provide Suncor with firm capacity on a new natural gas
pipeline constructed by TCPV. This pipeline came into service in 1999.
In 1998, Suncor's Steepbank Mine project on the east side of the
Athabasca River began operations. The project included a mine site facilities
complex, a 250 tonne capacity bridge over the Athabasca River, and a new ore
preparation process. The new process utilizes crushers, slurry preparation
equipment, and hydrotransport pumps to deliver an oil sand slurry across the
Athabasca River through hydro-transport pipelines to the existing extraction
plant.
The Oil Sands plant is susceptible to loss of production due to the
interdependence of its component systems. In 1999 two unplanned outages lasted a
total of 16 days and resulted in approximately 1.8 million barrels of
4
<PAGE>
lost production. These outages were precipitated by a change in feedstock
resulting from the operation of the new vacuum tower, a component of the
fixed plant expansion. Parts of the unit that failed were redesigned during
the second outage in September, with the objective of improving reliability
and helping to achieve targeted production rates. Project Millennium will
involve the duplication of some facilities, thereby reducing the potential
for a total loss of production.
Severe climatic conditions can cause reduced production and in some
situations result in higher costs. Over the past several years, backup
components and systems have been introduced in critical areas to improve
reliability. In addition to ongoing preventive maintenance programs, full plant
maintenance shutdowns are completed approximately every four years. The next
complete shutdown is scheduled for 2002. In addition to complete shutdowns,
partial shutdowns in the upgrader are undertaken periodically. During these
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 light sour synthetic crude oil during the shutdown
period. In 1999, a 28-day partial maintenance shutdown was completed at a cost
of $22 million. During the shutdown, only light sour synthetic crude oil was
produced as opposed to the normal mix of light sweet synthetic and light sour
synthetic crude oil.
LEASEHOLD INTERESTS AND ROYALTIES
In 1997, regulatory approval was obtained to allow Suncor to mine
additional leases as part of its Steepbank Mine development and the Millennium
development (together, the "Mine Expansion"). Mining activity on the Mine
Expansion located east of the Athabasca River and south of the Steepbank River,
commenced during the third quarter of 1998. Set out in the table below is a
summary of Suncor's oil sands leasehold interests.
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
Description of Legal Description Referred to as Number of Acres Percentage of
Mine Crude Oil Proved
Reserves
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Mine Expansion: Mine Expansion
Leases 7280100T25 25 47,915 Leases and Fee
7279080T19 19 18,760 Lots represent
7597030T11 97 2,225 92.4%
Fee Lots 1 N/A 1,894
3 N/A 1,967
4 N/A 1,886
--------------------------------------------------------------------------------------------------------------------
Original Mine Leases 7387060T04 86 4,500 Original Mine
7279120092 17 1,600 Leases represent
7.6%
--------------------------------------------------------------------------------------------------------------------
</TABLE>
The Government of Alberta is entitled to royalties under Leases 17, 19,
25, 86 and 97 and fee lots one, three and four at rates which the Government
establishes from time to time. Under the Alberta Suncor Crown Royalty Agreement,
the royalty is set at a rate of 25% of revenues less allowable costs (which
include capital expenditures) ("R--C") with a minimum payment of five percent of
gross revenues. The Crown receives the royalty in the form of a cash payment.
In 1997 Suncor and the Alberta government finalized an agreement
governing the transition of the Company's Oil Sands operations to the new,
generic oil sands royalty terms. Suncor's transition royalty agreement with the
Alberta government took effect in 1999. As agreed, the transition in 1999 of the
Company's Oil Sands operations to the new, generic oil sands royalty terms was
initiated because more than 50% of Oil Sands production was derived from the
Steepbank Mine. The agreement provides Suncor with additional allowable cost
deductions to a maximum of $158 million per year for 10 years (related to
Suncor's original investment in the Oil Sands facility). Royalty rates beginning
in 1999, the first year of the transition period, will be based on 25% of
revenues less allowable costs with a minimum royalty of 5% of gross revenue. The
5% rate will change to a 1% rate beginning in the third year of the transition
(2001).
5
<PAGE>
Union Pacific Resources Inc. (formerly Norcen Energy Resources Limited)
has a gross overriding royalty on Lease 86 pursuant to an agreement dated March
1, 1989 (the "Norcen Royalty"). The Norcen 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, 1999, under the Norcen
Royalty, no payment is required if synthetic crude prices are below $19.42 per
barrel. Payment of one and one half percent of gross revenue is required if the
synthetic crude price ranges from $19.42 to $20.41 per barrel. For every $1.00
per barrel increase in the price of synthetic crude in the range of $20.42 to
$25.41 per barrel, the percentage rate of the royalty increases by one half
percent. For every $1.00 per barrel increase in the price of synthetic crude in
the range of $25.42 to $36.41 per barrel, the percentage rate of the royalty
increases by a further one quarter percent until a maximum royalty of seven
percent 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.
Petro-Canada has a royalty on Lease 19 pursuant to an agreement dated
October 6, 1992. The royalty is calculated as one and one half percent of net
sale proceeds. Net sale proceeds is calculated based upon a formula by which the
sale proceeds for the period exceeds the sum of allowed deductions for the
period.
ESTIMATED SYNTHETIC CRUDE OIL RESERVES
Suncor estimates that Leases 86 and 17, combined with the Mine
Expansion, contain proved plus probable reserves of synthetic crude oil totaling
2.5 billion barrels, with 476 million barrels classified as proved. These
estimates are before deduction of Crown and applicable royalties on the leases.
Under the Crown Royalty Agreement the Crown royalty is dependent on deemed net
revenues (R--C); therefore, the calculation of net reserves will vary depending
upon production rates, prices and operating and capital costs.
During the fourth quarter of 1999, Suncor received approval from the
Alberta Energy and Utilities Board to leave in place a portion of reserves that
is uneconomic. This decision reduced Suncor's proved reserves by approximately
20 million barrels. The effect of the reduction in reserves will result in an
increase in the amount of the write-off of overburden related to these leases.
This increase will reduce earnings by approximately $7 million in 2000, and $3
million in 2001. The benefit is that it will allow Suncor to cease operating two
open pit mines at the same time one year sooner than originally anticipated.
The reserve estimates are based upon a detailed geological assessment
including drilling and laboratory tests and also consider current production
capability and upgrading yields, current mine plans, operating life and
regulatory constraints. Based on these factors, additional reserves may be
identified when more work on the mine is completed. The current proved plus
probable reserve estimate is based on the mine plan approved by the Alberta
Energy and Utilities Board. With additional drilling during 2000, it is
anticipated that additional proved reserves could be recorded to reflect an
increase in the portion of the mine that has high well drill density. Drilling
density is a factor in determining the classification of reserves as either
proved or probable.
Suncor engaged Gilbert Laustsen Jung Associates Ltd. ("GLJ"),
independent petroleum consultants, to audit Suncor's estimate of proved and
probable reserves of synthetic crude oil as of December 31, 1999. In their
opinion dated January 20, 2000, GLJ state that they believe that there is at
least a 90 percent confidence that the current proved, and 50 percent confidence
that the current proved plus probable, reserve estimates will be exceeded. Their
opinion is qualified to the extent that it assumes Suncor will comply with any
amendments that may be made to regulatory approvals. Planned future improvements
in the extraction (bitumen production) and upgrading processes have not been
considered in their report. On-site fuel consumption has been deducted. The
independent GLJ audit does not take into account the economic aspects of future
reserves.
6
<PAGE>
RESERVES RECONCILIATION
The following table sets out a reconciliation of Suncor's proved and
probable reserves of synthetic crude oil from December 31, 1998 to December 31,
1999.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
Millions of barrels Proved Reserves Probable Reserves Total
-------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
December 31, 1998 302 464 766
-------------------------------------------------------------------------------------------------------------
Revisions(1) (10) (13) (23)
-------------------------------------------------------------------------------------------------------------
Additions 222 1,577 1,799
-------------------------------------------------------------------------------------------------------------
Production (38) - (38)
-------------------------------------------------------------------------------------------------------------
December 31, 1999 476 2,028 2,504
-------------------------------------------------------------------------------------------------------------
</TABLE>
Note:
(1) A proposal submitted to the Alberta Energy and Utilities Board in 1998
requesting approval of a plan for reducing the final pit wall design of
leases 86 and 17 was approved in October 1999. As a result, the
recovery from these leases will be reduced by approximately 20 million
barrels of synthetic crude oil. This reduction is reflected in the 1999
proved reserves net revision of 10 million barrels.
REVENUES FROM SYNTHETIC CRUDE OIL, DIESEL AND BITUMEN
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. While there is no finding cost associated with synthetic
crude oil, mine development and expansion of production can entail significant
outlays. 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. Cost reduction efforts, including the change
in the equipment used in the mining operation and higher production levels, have
been successful in reducing unit costs.
In 1997, Suncor and Shell Canada ("Shell") signed a purchase agreement
whereby Shell agreed to purchase and receive approximately 95,000 cubic metres
(approximately 600,000 barrels) of light 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 light sweet crude oil.
There was only one customer in 1999, Koch Oil Co. Ltd. ("Koch"), that
represented 10% or more of Suncor's consolidated revenues in 1999. There were
none in 1998. In 1997 Suncor entered into an agreement with Koch to supply Koch
with up to 30,000 barrels per day (approximately 28% of Suncor's average 1999
production) of light sour synthetic crude oil 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.
A portion of Oil Sands production is used in connection with Suncor's
Sarnia refining operations. During 1999, the Sarnia refinery processed
approximately 26% (1998 -- 29%) of Oil Sands crude oil production.
The balance of Oil Sands production, including light sweet synthetic
crude oil, light sour synthetic crude oil and diesel, after sales to Shell, the
Sarnia refinery and Koch, is sold to others on a spot basis or under contracts
terminable on short notice.
In 1999 Suncor's consolidated revenues included $147 million (1998:
$166 million) from sales of light sweet synthetic crude oil, $203 million (1998:
$159 million) from sales of light sour synthetic crude oil, $82 million (1998:
$96 million) from sales of diesel and $29 million (1998 - nil) from the sale of
diluted bitumen.
7
<PAGE>
CAPITAL EXPENDITURES
Capital spending information for Oil Sands is set out in the table
under the caption "Capital and Exploration Investing Expenditures" in the
CORPORATE section of the MD&A.
ENVIRONMENTAL COMPLIANCE
For a description of the impact of environmental protection
requirements on Oil Sands, refer to "Environmental Risks" and "Government
Regulation" under the RISKS/SUCCESS FACTORS section of this Annual Information
Form.
EXPLORATION AND PRODUCTION
Suncor, through its Exploration and Production business unit, explores
for, acquires, develops, produces and markets natural gas, natural gas liquids,
crude oil and various byproducts from the Western Canada Sedimentary Basin.
Suncor's strategy is to increase its conventional natural gas reserve and
production base. During 1999, E&P continued its natural gas focus in Western
Canada, by concentrating on natural gas prospects and selling some of its
conventional crude oil properties. E&P plans to continue with its non core asset
disposal plan by selling $100 million to $200 million of properties in 2000,
with a focus on divesting oil properties.
Suncor's exploration program is focused on multiple geological zones in
northeast British Columbia, northwest and central Alberta and the Northwest
Territories. In 1999, Suncor's major development projects located in Alberta
included the Grande Prairie area, the Foothills area and the Simonette area, in
British Columbia in the Blueberry area and at Netla in the Northwest
Territories. Suncor drills primarily medium to high-risk wells with a focus on
prospects that management believes have significant reserve upside.
Additionally, a pilot project to evaluate steam assisted gravity drainage
("SAGD") technology in the production of heavy oil at Suncor's Burnt Lake
property commenced production in 1997. (See "Conventional Oil and
Non-Conventional Heavy Oil" section of this Annual Information Form). Suncor
continues to look at all options to optimize the value of Burnt Lake, including
the possible sale of the property.
An in-house natural gas direct 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.
RESERVES AND RESERVES RECONCILIATION
On January 25, 2000 GLJ reported on Suncor's estimated proved and
probable reserves of crude oil (other than synthetic crude oil), natural gas and
natural gas liquids as of December 31, 1999. Information with respect to these
reserves is set out in the tables below and in the tables under the headings
"Conventional Oil and Non-Conventional Heavy Oil" and "Natural Gas" (the
"Reserves Tables"). Both the crude oil and natural gas liquids and the natural
gas reserve estimates in the Reserves Tables include drilling results that were
finalized by Suncor subsequent to the work of GLJ. Historically any such
additions are evaluated in the subsequent year by GLJ and any adjustments, as
necessary, are made and reflected on the line referred to as "Revisions of
previous estimates". GLJ's determination of Suncor's estimated proved and
probable recoverable reserves are based on constant year end prices and costs
determined as of the dates indicated with no escalation into the future. The
accuracy of any reserve estimate is a function of the quality and quantity of
available data and of engineering interpretation and judgment. While reserve and
production estimates presented are considered reasonable, the estimates should
be viewed with the understanding that reservoir performance subsequent to the
date of the estimate may justify revision, either upward or downward.
In the Reserves Tables:
(1) Proved reserves are considered recoverable under current technology and
existing economic conditions, from reservoirs that are evaluated on
known drilling, geological, geophysical and engineering data.
8
<PAGE>
(2) Proved developed reserves are on production, or reserves that could be
recovered from existing wells or facilities, if the Company placed them
on production.
(3) Probable reserves are those reserves for which the analysis of
drilling, geological, geophysical and engineering data does not
demonstrate to be proved under current technology and existing economic
conditions, but where analysis suggests the likelihood of their
existence and future recovery. Probable reserves to be obtained by the
application of enhanced recovery processes will be the increased
recovery, over and above that estimated in the proved category, that
can be realistically estimated for the pool on the basis of enhanced
recovery processes which can be reasonably expected to be instituted in
the future.
(4) Gross reserves represent the aggregate of Suncor's working interest in
reserves including the royalty interest of governments and others in
such reserves and Suncor's royalty interest in reserves of others. Net
reserves are gross reserves less the 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 periodic
revision.
The following tables set out a reconciliation of E&P's estimated proved
reserves from December 31, 1998 to December 31, 1999.
ESTIMATED PROVED RESERVES RECONCILIATION(1)
<TABLE>
<CAPTION>
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
------------------- ------------ ------------------- ------------
(MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF
BARRELS) CUBIC FEET) BARRELS) CUBIC FEET)
<S> <C> <C> <C> <C>
December 31, 1998..................................... 69 1,197 56 915
Revisions of previous estimates....................... (2) (103) (2) (80)
Purchases of minerals in place........................ - 1 - 1
Extension and discoveries............................. - 53 - 41
Production............................................ (5) (82) (4) (68)
Sales of minerals in place............................ (11) (53) (9) (45)
---- ------ --- ----
December 31, 1999..................................... 51 1,013 41 764
---- ------ --- ----
---- ------ --- ----
</TABLE>
Note:
(1) This table includes 3.5 million barrels related to Suncor's Burnt Lake
heavy oil extraction pilot project.
Estimated proved reserves are comprised of developed and undeveloped
reserves. The following tables show the breakdown between these categories.
9
<PAGE>
ESTIMATED PROVED DEVELOPED RESERVES RECONCILIATION(1)
<TABLE>
<CAPTION>
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
------------------- ----------- ------------------- -----------
(MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF
BARRELS) CUBIC FEET) BARRELS) CUBIC FEET)
<S> <C> <C> <C> <C>
December 31, 1998..................................... 53 730 43 557
Revisions of previous estimates....................... - 3 - 3
Purchases of minerals in place........................ - 1 - 1
Extension and discoveries............................. - 13 - 10
Production............................................ (5) (82) (4) (68)
Sales of minerals in place............................ (10) (38) (9) (32)
--- --- -- ---
December 31, 1999..................................... 38 627 30 471
--- --- -- ---
--- --- -- ---
</TABLE>
Note:
(1) This table includes 2.5 million barrels of crude oil related to
Suncor's Burnt Lake heavy oil extraction pilot project.
ESTIMATED PROVED UNDEVELOPED RESERVES RECONCILIATION(1)
<TABLE>
<CAPTION>
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
------------------- ----------- ------------------- -----------
(MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF
BARRELS) CUBIC FEET) BARRELS) CUBIC FEET)
<S> <C> <C> <C> <C>
December 31, 1998....................................... 16 467 13 358
Revisions of previous estimates......................... (2) (106) (2) (83)
Purchases of minerals in place.......................... - - - -
Extension and discoveries............................... - 40 - 31
Sales of minerals in place.............................. (1) (15) - (13)
--- --- -- ---
December 31, 1999....................................... 13 386 11 293
--- --- -- ---
--- --- -- ---
</TABLE>
Note:
(1) This table includes 1.1 million barrels of crude oil related to
Suncor's Burnt Lake heavy oil extraction pilot project.
The following table sets out E&P's estimated probable reserves as of December
31, 1998 and December 31, 1999.
ESTIMATED PROBABLE RESERVES(1)
<TABLE>
<CAPTION>
GROSS NET
----- ---
CRUDE OIL AND CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS
------------------- ----------- ------------------- -----------
(MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF
BARRELS) CUBIC FEET) BARRELS) CUBIC FEET)
<S> <C> <C> <C> <C>
December 31, 1998...................................... 24 472 19 359
December 31, 1999...................................... 20 428 15 322
</TABLE>
Note:
(1) This table includes 0.5 million barrels related to Suncor's Burnt Lake
heavy oil extraction pilot project.
10
<PAGE>
CONVENTIONAL OIL AND NON-CONVENTIONAL HEAVY OIL
The following table shows estimates of E&P's proved crude oil reserves
before royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation")
and Suncor's average daily production of crude oil before royalties, in Alberta,
British Columbia and Saskatchewan, represented by the major conventional and
non-conventional heavy oil fields identified in this table.
<TABLE>
<CAPTION>
PROVED RESERVES 1999 AVERAGE
BEFORE ROYALTIES AT DAILY PRODUCTION
DECEMBER 31, 1999(1) BEFORE ROYALTIES(2)
------------------------- ------------------------
FIELDS (MILLIONS OF (BARRELS OF
BARRELS) % OIL PER DAY) %
<S> <C> <C> <C> <C>
CONVENTIONAL OIL
Medicine River................................ 4.1 13 2,061 23
Simonette..................................... 4.0 13 1,148 13
Oungre........................................ 4.6 15 765 8
Ante Creek.................................... 5.9 19 945 10
Youngstown.................................... 1.7 5 589 6
Blueberry..................................... 2.1 7 452 5
Valhalla/Laglace.............................. 0.7 2 400 4
Nothingham/Alda............................... 0.5 1 293 3
Swan Hills.................................... 1.7 5 269 3
Boudreau ..................................... 0.6 2 85 1
Cache 0.3 1 125 1
Other (2)..................................... 5.5 17 2,047 23
---- ---- ------ ---
Total -- gross................................ 31.7 100 9,179 100
NON-CONVENTIONAL HEAVY OIL
Burnt Lake.................................... 3.5 100 1,190 100
---- ---- ------ ---
Total -- gross................................ 35.2 100 10,369 100
---- ---- ------ ---
---- ---- ------ ---
</TABLE>
Notes:
(1) The reserves and production in this table do not include natural gas
liquids.
(2) Includes fields in which Suncor holds overriding royalty interests.
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 oil recovery, infill
drilling and production optimization techniques. At the end of 1999
approximately 60 percent of Suncor's proved conventional oil reserves were under
enhanced oil recovery programs.
Suncor's E&P business unit has a 79% working interest in a heavy oil
extraction pilot project at Burnt Lake, Alberta. This project is continuing to
evaluate the SAGD technology to mobilize the oil using steam injection and
horizontally drilled well pairs. In 1997, Suncor invested $16 million in an
additional 27,500 hectares of heavy oil leases in the Firebag area, near its oil
sands operation north of Fort McMurray. In 1999 Suncor invested a further $24
million in an additional 34,304 hectares of heavy oil leases in the Firebag
area. For further information on the Burnt Lake pilot project and Suncor's other
heavy oil activities reference is made to the information under the heading
"In-Situ Oil Sands " in the E&P section of the MD&A.
11
<PAGE>
NATURAL GAS
The following table shows estimates of E&P's proved natural gas
reserves, before royalties, as prepared by GLJ (see "Reserves and Reserves
Reconciliation") and Suncor's average daily production of natural gas before
royalties, in Alberta and British Columbia, represented by the major natural gas
fields identified in the table.
<TABLE>
<CAPTION>
PROVED RESERVES 1999 AVERAGE
BEFORE ROYALTIES AT DAILY PRODUCTION
FIELDS DECEMBER 31, 1999 BEFORE ROYALTIES
------ ------------------------ ---------------------------
(MILLIONS OF
(BILLIONS OF CUBIC FEET
CUBIC FEET) % PER DAY) %
<S> <C> <C> <C> <C>
Stolberg...................................... 188 19 12 5
Grande Prairie area........................... 59 6 12 5
Glacier....................................... 54 5 10 4
Rosevear...................................... 53 5 21 10
Blueberry..................................... 50 5 9 4
Simonette..................................... 54 5 12 5
Netla......................................... 49 5 - -
Pine Creek.................................... 22 2 7 3
Bonanza....................................... 8 1 6 3
Blackstone/Brown Creek........................ 75 7 10 4
Knopcik area.................................. 61 6 24 11
Sinclair...................................... 27 3 9 4
Mountain Park................................. 56 6 13 6
George........................................ 11 1 16 7
Medicine River................................ 21 2 8 4
Cutbank....................................... 18 2 - -
Elmworth...................................... 21 2 - -
Hinton........................................ 14 1 - -
Berland River................................. 10 1 11 5
Boundary Lake................................. 7 1 1 -
Other(1)...................................... 155 15 45 20
----- --- --- ---
Total -- Gross................................ 1,013 100 226 100
----- --- --- ---
----- --- --- ---
</TABLE>
Note:
(1) Includes fields in which Suncor holds overriding royalty interests.
12
<PAGE>
OIL AND GAS DATA
The following oil and gas disclosure is provided in accordance with the
provisions of the United States Financial Accounting Standards Board's Statement
(SFAS) No. 69. This statement requires disclosure about conventional oil and gas
activities only, and therefore the Company's Oil Sands activities are excluded.
<TABLE>
<CAPTION>
COSTS INCURRED
FOR THE YEARS ENDED
DECEMBER 31,
-------------------
1999 1998 1997
---- ---- ----
($ MILLIONS)
<S> <C> <C> <C>
Property acquisition costs
Proved properties................................................... - - 6
Unproved properties................................................. 48 24 48
Exploration costs..................................................... 64 92 79
Development costs..................................................... 70 123 101
--- --- ---
182 239 234
--- --- ---
--- --- ---
RESULTS OF OPERATIONS FOR
OIL AND GAS PRODUCTION
FOR THE YEARS ENDED
DECEMBER 31,
-------------------------
1999 1998 1997
---- ---- ----
($ MILLIONS)
<S> <C> <C> <C>
Revenues
Sales to unaffiliated customers...................................... 97 80 147
Transfers to other operations........................................ 153 167 95
--- --- ---
250 247 242
--- --- ---
Expenses
Production costs..................................................... 63 64 60
Depreciation, depletion and Amortization............................. 76 74 67
Exploration.......................................................... 52 50 57
Gain on disposal of assets........................................... (36) (4) (9)
Other related costs.................................................. 18 16 20
--- --- ---
173 200 195
--- --- ---
Operating profit before income taxes................................... 77 47 47
Related income taxes................................................... (34) (22) (23)
--- --- ---
Results of operations from Exploration and production.................. 43 25 24
--- --- ---
--- --- ---
</TABLE>
The information noted above does not totally agree to the segmented
information in the "Schedules of Segmented Data" section of the Company's
consolidated financial statements for the year ended December 31, 1999 due to
different classifications of revenues and expenses.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED
PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES
In computing the standardized measure of discounted future net cash
flows from estimated production of proved oil and gas reserves after income
taxes, assumptions other than those mandated by SFAS No. 69 could produce
substantially different results. The Company cautions against viewing this
information as a forecast of future economic conditions or revenues.
The standardized measure of discounted future net cash flows is
determined by using estimated quantities of proved reserves and taking into
account the future periods in which they are expected to be developed and
produced based on year-end economic conditions. The estimated future production
is priced at year-end prices, except that future gas prices are increased, where
applicable, for fixed and determinable price escalations provided by contract.
At December 31, 1999, no such contractual arrangements existed. The resulting
estimated future cash inflows are reduced by estimated future costs to develop
and produce the proved reserves based on year-end cost levels. In addition, the
Company has also deducted certain other estimated costs deemed necessary to
derive the estimated pretax future net cash flows from the proved reserves
including direct general and administrative costs of exploration and production
operations and reclamation and environmental remediation costs. The estimated
pretax
13
<PAGE>
future net cash flows are then reduced further by deducting future income
tax expenses. Such income taxes are determined by applying the appropriate
year-end statutory tax rates, with consideration of future tax rates already
legislated, to the future pretax cash flows relating to the Company's proved oil
and gas reserves less the tax basis of the properties involved. At December 31,
1999, there were no legislated future tax rate changes. The future income tax
expenses give effect to permanent differences and tax credits and allowances
relating to the Company's proved oil and gas reserves. The resultant future net
cash flows are reduced to present value amounts by applying the SFAS No. 69
mandated ten percent discount factor. The result is referred to as "Standardized
Measure of Discounted Future Net Cash Flows from Estimated Production of Proved
Oil and Gas Reserves after Income Taxes".
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
($ MILLIONS)
<S> <C> <C> <C>
Future cash inflows ............................................................. 3,272 3,382 2,926
Future production and development costs ......................................... (1,053) (1,183) (1,041)
Other related future costs ...................................................... (133) (139) (139)
Future income tax expenses ...................................................... (789) (637) (558)
------- ------- ------
Future net cash flows ........................................................... 1,297 1,423 1,188
Discount at 10 percent .......................................................... (548) (626) (510)
------- ------- ------
Standardized measure of discounted future net cash flows from
estimated production of proved oil and gas reserves after income taxes........ 749 797 678
------- ------- ------
------- ------- ------
</TABLE>
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME
TAXES
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
($ MILLIONS)
<S> <C> <C> <C>
Balance, beginning of year ........................................ 797 678 557
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas net of related costs ......... (192) (187) (181)
Revisions to estimates of proved reserves:
Prices ....................................................... 458 69 140
Development costs ............................................ (68) (75) (68)
Production costs ............................................. (25) (26) (5)
Quantities ................................................... (175) (19) 29
Other ........................................................ (81) (6) (58)
Extensions, discoveries, and improved recovery less related costs 46 168 149
Development costs incurred during the period .................... 70 123 101
Purchases of reserves in place .................................. - -- 6
Sales of reserves in place ...................................... (130) (13) (2)
Accretion of discount ........................................... 113 100 81
Income taxes .................................................... (64) (15) (71)
----- ----- -----
Balance, end of year .............................................. 749 797 678
----- ----- -----
----- ----- -----
</TABLE>
LAND HOLDINGS
The following table sets out the undeveloped and developed lands in
which the E&P business unit held petroleum and natural gas interests at the end
of 1999. 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 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 land, with the lessee paying
development and operating costs, subject to paying rental, tax and royalty
expenses. Agreements (excluding freehold agreements) are acquired from the
federal or provincial governments through competitive bidding or by undertaking
work commitments.
14
<PAGE>
LAND HOLDINGS
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL ACRES
--------------- ----------------- -----------
GROSS HECTARES(1) NET HECTARES(1) GROSS HECTARES(1) NET HECTARES(1) GROSS HECTARES(1) NET HECTARES(1)
----------------- --------------- ----------------- --------------- ----------------- ---------------
(THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Canada
CONVENTIONAL ........ 158 99 379 291 537 390
Alberta .............
British Columbia .... 60 24 144 106 204 130
Saskatchewan ........ 4 3 - - 4 3
--- --- ----- ----- ----- -----
Total Conventional .. 222 126 523 397 745 523
--- --- ----- ----- ----- -----
NON-CONVENTIONAL
Alberta ............. 17 6 76 71 93 77
Frontier ............ 9 7 214 28 223 35
Australia ........... - - 541 548 548 548
--- --- ----- ----- ----- -----
Total
Non-Conventional .... 26 13 838 647 864 660
--- --- ----- ----- ----- -----
Total Landholdings .. 248 139 1,361 1,044 1,609 1,183
--- --- ----- ----- ----- -----
--- --- ----- ----- ----- -----
</TABLE>
Note:
(1) "Gross Hectares" means all acres in which Suncor has an interest. "Net
Hectares" represents gross acres after deducting interests of others.
DRILLING
The following table sets forth the gross and net exploratory and
development wells, all in Western Canada, which were completed, capped or
abandoned in which Suncor participated during the years indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1999 1998
---- ----
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
Exploratory Wells
Oil........................................................... 1 1 3 2
Gas........................................................... 6 5 16 10
Dry........................................................... 17 13 25 18
--- --- --- ---
Total Exploratory Wells......................................... 24 19 44 30
--- --- --- ---
Development Wells
Oil........................................................... 14 2 56 15
Gas........................................................... 9 4 24 16
Dry........................................................... 3 1 12 8
Total Development Wells ........................................ 26 7 92 39
--- --- --- ---
Total........................................................... 50 26 136 69
--- --- --- ---
--- --- --- ---
</TABLE>
Not included are wells completed under farmout agreements on Suncor
properties, since Suncor did not incur cash expenditures in connection with such
wells. In addition to the above wells, Suncor had interests in 6 gross (5 net)
exploratory wells in progress at the end of 1999.
In 1999 a well was drilled on the Netla property in the Northwest
Territories. The well drilled was classified as dry. Suncor is planning to
undertake further drilling in 2000.
Suncor continues to hold interests in frontier properties (Arctic and
Northwest Territories) including 29 long-term "significant discovery licences".
Suncor is planning to undertake further work in the Northwest Territories in
2000.
WELLS
The following table summarizes the wells in which the Exploration and
Production business unit has a working interest or a royalty interest as at
December 31, 1999. Gross wells represent the number of wells in which
Exploration and Production has a working interest and net wells represent
Exploration and Production's aggregate working interest share in such wells.
15
<PAGE>
<TABLE>
<CAPTION>
PRODUCING NON-PRODUCING
WELLS(1) WELLS(2)
--------- -------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
Conventional Oil Wells
Alberta ............................... 225 126 58 28
British Columbia ...................... 36 16 20 12
NWT ................................... - - 4 4
----- --- --- ---
Total Conventional Oil Wells ............ 261 142 82 44
----- --- --- ---
Conventional Natural Gas Wells
Alberta ............................... 1,148 218 228 38
British Columbia ...................... 36 18 3 2
Saskatchewan .......................... 146 63 26 4
----- --- --- ---
Total Conventional Natural Gas Wells .... 1,330 299 257 44
----- --- --- ---
Non-Conventional Heavy Oil
Alberta ............................... 6 5
----- ---
Total Wells ............................. 1,597 446 339 88
----- --- --- ---
----- --- --- ---
</TABLE>
Notes:
(1) Producing wells are wells producing hydrocarbons or having the
potential to produce, excluding shut-in wells. As at December 31, 1999
Suncor has interests in 37 oil fields and 51 gas fields.
(2) 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, 1999.
SALES AND SALES REVENUES
The following table shows the breakdown of the sources of revenues for
E&P.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------
1999 1998
---- ----
($ MILLIONS)
<S> <C> <C>
Gross Revenues(1)
Crude oil and natural gas liquids ............ 100 108
Natural gas .................................. 198 174
Pipeline ..................................... 5 7
Other ........................................ 3 1
--- ---
Total ........................................ 306 290
--- ---
--- ---
</TABLE>
Note:
(1) Includes intersegment revenues.
PRODUCTION COSTS
The following shows the production (lifting) costs in connection with
Suncor's crude oil and natural gas operations for the years indicated.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------
1999 1998
---- ----
($ PER BOE OF
GROSS PRODUCTION)
<S> <C> <C>
Average production (lifting) cost of conventional oil and gas(1)............... 4.40 3.91
</TABLE>
Note:
(1) Production (lifting) costs include all expenses related to the
operation and maintenance of producing or producible wells, gas plants
and gathering systems. It does not include an estimate for future
reclamation costs.
16
<PAGE>
MARKETING, PIPELINE AND OTHER OPERATIONS
Suncor's crude oil production is used in its refining operations,
exchanged for other crude oil with Canadian and U.S. refiners, or sold to
Canadian and U.S. purchasers. Sales are generally made under spot contracts or
under contracts which are terminable by relatively short notice. Suncor's
conventional crude oil production is shipped on pipelines operated by
independent pipeline companies. E&P currently has no pipeline commitments
related to the shipment of crude oil.
Suncor operates gas processing plants at South and North Rosevear, Pine
Creek, Boundary Lake South, Progress, Joffre and Simonette with a total design
capacity of approximately 254 million cubic feet per day. Suncor's interest in
these gas processing plants is approximately 168 million cubic feet per day.
Suncor also has varying working interests in natural gas processing plants
operated by other companies.
Approximately 29 percent 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 E&P's system
sales volumes are contracted to TransCanada Gas Services and Pan-Alberta Gas
Ltd. These companies resell this natural gas primarily to eastern Canadian and
midwest and eastern U.S. markets.
Approximately 71 percent of Suncor's natural gas production is marketed
under direct sales arrangements to customers in Alberta, eastern Canada, and the
U.S. midwest and west coast. This includes a significant volume of natural gas
consumed in Suncor's Oil Sands plant at Fort McMurray and in its Sarnia
refinery. E&P contracts for the supply of natural gas to each of these
facilities. Natural gas consumption at the Oil Sands plant in 1999 was 25
million cubic feet per day. Natural gas consumption at the Sarnia refinery in
1999 was 21 million cubic feet per day. Contracts for these direct sales
arrangements are of varied terms, with a majority having terms of one year or
less, and incorporate pricing which is either fixed over the term of the
contract or determined on a monthly basis in relation to a specified market
reference price. Under these contracts, E&P is responsible for transportation
arrangements to the point of sale. Sales to the U.S. west coast are made under a
variety of arrangements with differing transportation and pricing terms.
To ensure ongoing direct sales access to U.S. markets, E&P 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, expiring October 31, 2003. Suncor also has firm capacity of 40
million cubic feet per day on the Pacific Gas Transmission ("PGT") pipeline to
the California border extending to the year 2023.
The Albersun pipeline, owned and operated by Suncor, was originally
constructed in 1968 to transport natural gas to the Oil Sands plant. It extends
approximately 180 miles south of the plant and connects with the intraprovincial
pipeline system of NOVA Gas Transmission Ltd. The Albersun pipeline has the
capacity to move in excess of 100 million cubic feet per day of natural gas.
Suncor contracts and controls most of the gas on the system under delivery based
contracts. The pipeline moves gas both north and south for Suncor and other
shippers. In 1999, throughput on Albersun pipeline was 82 million cubic feet per
day and revenues were approximately $5 million.
CAPITAL AND EXPLORATION EXPENDITURES
Capital and exploration spending information for Suncor's E&P business
unit is set out in the table under the caption "Capital and Exploration
Investing Expenditures" in the CORPORATE section of MD&A.
ENVIRONMENTAL COMPLIANCE
For a description of the impact of environmental protection
requirements on E&P, refer to the information under the headings, "Risk/Success
Factors Affecting Performance" in the EXPLORATION AND PRODUCTION Section of the
MD&A, and also to "Environmental Risks" and "Government Regulation" under the
RISK/SUCCESS FACTORS section of this Annual Information Form.
17
<PAGE>
SUNOCO
Suncor conducts its refining and retail marketing of petroleum products
and petrochemicals through its subsidiary, Sunoco Inc., and its subsidiaries and
joint ventures. Sunoco's operations are carried out by three divisions: Refining
(including wholesale), Retail Marketing and Integrated Energy Solutions.
REFINING
SARNIA REFINERY. Located in Sarnia, Ontario, the Sunoco refinery has an
economic refining capacity of 70,000 barrels of crude oil per day and average
1999 refining sales of approximately 87,000 barrels per day. This complex
refinery has the flexibility to produce a high proportion of transportation
fuels and value-added petrochemicals. The configuration of the refinery permits
the processing of a high percentage of light sweet synthetic crude oil, in
addition to conventional light sweet and sour crudes. The competitive advantage
of processing synthetic crude oil is that it is low in sulphur and heavy
petroleum products (less valuable products) yielding a more valuable product
mix.
The refinery has cracking capacity of 40,200 barrels per day from a
Houdry catalytic cracker and a hydrocracker.
Approximately 40 percent of the cracking capacity at the refinery is
attributable to the Houdry catalytic cracker, which was built in the early 1950s
and uses an older cracking technology. A comprehensive risk assessment on the
Houdry catalytic cracker was completed in January 1995. No major expenditures
other than regular maintenance included as part of the planned maintenance work
in 1996, were identified as a result of this assessment. In 1998 and 1999, some
additional maintenance costs were incurred as the result of unplanned outages.
The next major maintenance on the Houdry catalytic cracker is expected in 2001.
The hydrocracker, which is capable of processing approximately 23,300
barrels per day, adds flexibility by producing premium distillate and napthas.
An alkylation unit, capable of processing 5,400 barrels per day, complements a
petrochemical plant for flexibility in gasoline, octane and petrochemical
production. The addition of a jet fuel tower in 1993 and a low sulphur diesel
tower in 1995 further added to the refinery's ability and flexibility to produce
premium-valued transportation fuels. As a result of this configuration, the
refinery has flexibility to vary its gasoline/distillate ratio.
The following chart sets out average daily crude input, average
refinery utilization rate, and cracking capacity utilization of the Sarnia
refinery over the last two years:
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Crude input -- barrels per day ............................ 66,500 69,000
Average utilization rate (%)(1) ........................... 95 99
Average cracking capacity utilization (%)(2) .............. 96 100
</TABLE>
Notes:
(1) based upon crude unit processing capacity and input to crude units.
(2) based upon rated throughput capacity and input to units.
SOURCES OF FEEDSTOCK. Sunoco's refining operation uses both synthetic and
conventional crude oil. In 1999, 65 percent of the crude oil refined at the
Sarnia refinery was synthetic crude oil, compared with 62 percent in 1998, the
remainder being conventional crude oil and condensate. Of the synthetic crude
oil, approximately 63 percent in 1999 was from Suncor's Oil Sands plant
production compared to 64 percent in 1998, with the balance purchased from
others under month to month contracts. In the event of a significant disruption
in the supply of synthetic crude oil from either Suncor's Oil Sands business
unit or the other suppliers of synthetic crude oil, additional sweet or sour
conventional crude oil would be processed. Conventional crude oil refined by
Sunoco comes mainly from the production of Suncor and others in western Canada,
supplemented from time to time with crude oil from the United States, which is
purchased or obtained in exchange for Canadian crude. Crude oil from other
countries can also be delivered to Sarnia via pipeline from the United States
Gulf Coast providing additional flexibility and security of supply. The market
for crude oil generally is conducted on a spot basis or under contracts
terminable by short notice.
18
<PAGE>
Production of transportation fuels is enhanced through buy/sell
agreements with Nova Chemicals (Canada) Ltd., a petrochemical refinery in which
feedstocks more suitable for gasoline blending are taken by Sunoco in exchange
for feedstocks more suitable for petrochemical cracking. Reciprocal product
buy/sell and exchange agreements are also used with other refiners to minimize
transportation costs, balance product availability in particular locations, and
enhance refinery utilization. These agreements are entered into from time to
time, and renewed as necessary. On occasion, Sunoco purchases refined products
to supplement its own refinery production.
By the end of 1997 Sunoco was marketing ethanol-enhanced gasolines to
all of its Sunoco branded service stations. In order to secure supply, Sunoco
signed an exclusive 10-year ethanol fuel supply agreement with Commercial
Alcohols Inc., which constructed a 150 million litre per year capacity ethanol
plant near Chatham, Ontario.
PRINCIPAL PRODUCTS. The refinery produces transportation fuels, heating
oils, heavy fuel oils, and petrochemicals and liquefied petroleum gases.
Sunoco's petrochemical facilities, with a design capacity of 10,000 barrels per
day (approximately 1,590 cubic metres), produce benzene, toluene and mixed
xylenes and recover orthoxylene from mixed xylenes. Noted below is information
on daily sales volumes for the last two years.
<TABLE>
<CAPTION>
1999 1998
---- ----
(THOUSANDS OF
CUBIC METRES
PER DAY)
<S> <C> <C>
Transportation fuels
Gasoline -- retail (1)................................................................. 4.1 4.1
-- other...................................................................... 3.7 3.5
Jet fuel............................................................................... 1.1 1.0
Other.................................................................................. 2.7 2.5
---- ----
11.6 11.1
---- ----
Petrochemicals......................................................................... 0.7 0.7
Heating oils........................................................................... 0.4 0.6
Heavy fuel oils........................................................................ 0.5 0.7
Other.................................................................................. 0.6 0.7
---- ----
Total.................................................................................. 13.8 13.8
---- ----
---- ----
</TABLE>
Note:
(1) Excludes sales through joint ventures.
Sales of gasolines and other transportation fuels represented 62
percent of Suncor's consolidated sales and other operating revenues in 1999
compared to 60 percent in 1998.
TRANSPORTATION AND DISTRIBUTION. A variety of transportation modes are
used to deliver products, including pipeline, water, rail and road. Sunoco owns
and operates petroleum transportation, terminal and dock facilities in support
of its refining and marketing activities. Such assets include storage facilities
and bulk distribution plants in Ontario and a 55 percent interest in a refined
products pipeline between Sarnia and Toronto.
The major mode of transportation for gasolines, diesel, jet fuel and
heating oils from the Sarnia refinery to its core markets in Ontario is the
refined products pipeline owned and operated by Sun-Canadian Pipe Line Company
Limited. The pipeline serves terminal facilities in London, Hamilton and
Toronto, and has a capacity of 126,000 (20,000 m3) barrels per day of which 83
percent was utilized in 1999 and 85 percent utilized in 1998. Ownership of the
pipeline company is divided between Suncor with a 55 percent interest, and
another integrated refiner with a 45 percent interest. The pipeline operates
as a private facility for its owners.
Sunoco also has direct pipeline access to petroleum markets in the
Great Lakes region of the United States by way of connection to a pipeline
system operated by Sunoco, Inc. (formerly Sun Company, Inc.) ("Sun") at Sarnia.
This link to the United States allows Sunoco to quickly move products to market
or obtain feedstocks or products when market conditions are favourable in the
Michigan and Ohio markets.
19
<PAGE>
Sunoco believes that its own facilities and those on long-term
contractual arrangements with other parties will provide a sufficient level of
storage for its current and foreseeable needs.
PRINCIPAL MARKETS. Sunoco markets transportation fuels (gasoline,
diesel, propane and jet fuel), heating oils, liquefied petroleum gases, residual
fuel oil and asphalt feedstock to its retail marketing business and industrial,
commercial and wholesale customers and refiners, primarily in Ontario. In
Quebec, Sunoco supplies its industrial and commercial customers through
long-term arrangements with other regional refiners or through Group Petrolier
Norcan Inc., a 25% Suncor-owned fuels terminal and product supply business in
Montreal, Quebec.
Sunoco also markets toluene, mixed xylenes and orthoxylene primarily in
Canada and the United States through Sun Petrochemicals Company, a 50 percent
petrochemical marketing joint venture established in 1992 between subsidiaries
of Sun and Sunoco respectively, to market products from Sun's Toledo, Ohio
refinery and Sunoco's Sarnia refinery. Under this arrangement, petrochemicals
used to manufacture plastics, rubber, synthetic fibres, industrial solvents and
agricultural products, and as gasoline octane enhancers, are marketed worldwide.
Most sales are currently made in North America. All Sunoco's benzene production
is sold directly by pipeline to other petrochemical manufacturers in Sarnia.
Sunoco also sells liquified petroleum gases to various industrial users and to
resellers.
Approximately 93 percent (1998 -- 93%) of the Sarnia refinery's
gasoline production is sold through the retail marketing channels referred to
under the heading "Retail Marketing" below. The remainder is sold through
wholesale, commercial and industrial accounts in Ontario and Quebec which sell
transportation fuels (including gasoline, diesel and jet fuels) and heating oil.
Sunoco also sells diesel through eight Fleet Fuel Cardlocks in Southern Ontario.
Sunoco's share of total refined product sales in its primary market of Ontario
is approximately 16 percent (1998 -- approximately 17%). Sunoco's volumes of
transportation fuels, which have higher margins than other refined products,
except petrochemicals, represented 84 percent of its total refined product sales
volumes in 1999 (1998 -- 85%).
RETAIL MARKETING
RETAIL DISTRIBUTION CHANNELS. Sunoco's retail marketing division has
three distinct distribution channels:
- 305 Sunoco retail service stations in Ontario, located primarily along
the main Windsor-Kingston-Ottawa transportation corridors;
- 156 retail services stations in Ontario operated by The Pioneer Group
Inc., an independent retailer with whom Sunoco has a 50 percent joint
venture partnership; and
- 60 service stations in rural Ontario operated by UPI Inc., a joint
venture company owned by 50% by each of Sunoco and GROWMARK, Inc. (a
large U.S. Midwest agricultural supply and grain marketing
co-operative). UPI sites sell conventional and ethanol-blended
gasolines, diesel and heating oil to residential, commercial and farm
customers.
Volumes to the Pioneer and UPI joint ventures are supplied under
exclusive supply agreements. The agreement with UPI expires in 2002, after which
Sunoco will continue to be the exclusive supplier of refined products as long as
it remains a shareholder. Sunoco plans to maintain its relationship with this
joint venture. The Pioneer agreement expires in 2003 and it will be
automatically renewed thereafter for one-year terms until terminated upon twelve
months prior written notice.
CAPITAL EXPENDITURES
Capital spending information for Sunoco is set out in the table under
the caption, "Capital and Exploration Investing Expenditures" in the CORPORATE
section of the MD&A.
20
<PAGE>
ENVIRONMENTAL COMPLIANCE
For a description of the impact of environmental protection
requirements on Sunoco, refer to "Environmental Responsibility" and
"Risk/Success Factors Affecting Performance" in the SUNOCO section of MD&A, and
also to "Environmental Risks" and "Government Regulation" under the RISK/SUCCESS
FACTORS section of this Annual Information Form.
SUNCOR EMPLOYEES
The following table shows the distribution of employees among Suncor's
three business units, its corporate office and the Stuart Oil Shale Project for
the past two years.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------
1999 1998
----- -----
<S> <C> <C>
Oil Sands ................................ 1,741 1,647
Exploration and Production ............... 314 295
Sunoco(1) ................................ 591 598
Stuart Project ........................... 68 43
Corporate ................................ 82 76
----- -----
Total .................................... 2,796 2,659
----- -----
----- -----
</TABLE>
Note:
(1) Excludes joint venture employees.
In addition to Suncor employees, independent contractors supply a range
of services to the Company. Approximately 1,035 Oil Sands employees are
represented by a labour union. Suncor entered into a two-year contract effective
May 1, 1999 with the Oil Sands labour union. Approximately 180 Sunoco Sarnia
refinery and Sun-Canadian Pipe Line Company employees are represented by
employee associations. In September 1999, Sunoco signed a new two-year agreement
with the employee associations. Relations with these associations have been
constructive for many years.
YEAR 2000 RESULTS
For a description of Year 2000 results, refer to "Year 2000 Results" in
the CORPORATE section of the MD&A.
RISK/SUCCESS FACTORS
VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES. Suncor's future financial
performance is closely linked to oil prices, and to a lesser extent natural gas
prices. The price of these commodities can be influenced by global and regional
supply and demand factors. Worldwide economic growth, political developments,
compliance or non-compliance with quotas imposed upon members of the
Organization of Petroleum Exporting Countries and weather can affect world oil
supply and demand. Natural gas prices realized by Suncor are affected primarily
by North American supply and demand and by prices of alternate sources of
energy. All of these factors are beyond Suncor's control and can result in a
high degree of price volatility not only in crude oil and natural gas prices,
but as well in fluctuating price differentials between heavy and light grades of
crude oil. Oil and natural gas prices have fluctuated widely in recent years and
Suncor expects continued volatility and uncertainty in crude oil and natural gas
prices. A prolonged period of low crude oil prices may affect the value of
Suncor's oil and gas properties, the level of spending on development projects,
or curtailment in production at some properties and could have an adverse impact
on Suncor's financial condition and liquidity and results of operations. Suncor
cannot control the factors that influence supply and demand or the prices of
crude oil or natural gas.
Suncor cannot control the prices of crude oil or natural gas, or
currency exchange rates. However, the Company has a hedging program that fixes
the price of crude oil and natural gas and the associated exchange for a
percentage of Suncor's total production volume. Suncor's objective is to lock in
prices on a portion of the
21
<PAGE>
Company's future production today to reduce exposure to market volatility and
ensure the Company's ability to finance growth. If there was an operational
upset 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 in the situation were the actual price was higher than
the price hedged.
Suncor conducts an annual assessment of the carrying value of its
assets in accordance with Canadian GAAP. If 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. There were no downward
revisions to the carrying value of Suncor's assets in 1999.
RISK FACTORS RELATED TO PROJECT MILLENNIUM. The present cost estimate for
completion of Project Millennium is approximately $2.2 billion. A significant
portion of Suncor's current and future financial performance is linked to the
performance of its Oil Sands operations.
There are also certain risks associated with the Project Millennium
schedule, resources (including securing materials, skilled labour and equipment)
and costs. While Project Millennium is intended to use established technologies,
it is a significant construction project that could be subject to construction
delays due to work stoppages and other problems typically associated with these
types of construction projects. In an effort to obtain adequate resources and
manage the schedule and costs for Project Millennium, Suncor has established an
alliance agreement with major engineering and construction organizations for the
design, engineering, procurement, construction and commissioning of the project,
but no assurance can be given that such agreement will be successful in
addressing the risks identified. Projects of this magnitude can result in the
final cost being higher or lower than original estimates. Management believes in
the current competitive environment there are risks that Project Millennium
costs could be higher than the original estimate. Management is targeting
commissioning of Phase 2 of Project Millennium in the second half of 2001.
Suncor believes that the planned increases in Oil Sands production
present issues that require prudent risk management, including, but not limited
to: Suncor's ability to finance Oil Sands growth if commodity prices were at low
levels for an extended period; potential competition from new entrants in 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 preservation and protection of the environment.
The Company's significant capital commitment to complete Project
Millennium may require it to forego investment opportunities in other segments
of its operations. In addition, completion of the project will substantially
increase the Company's dependence on the Oil Sands segment of its business.
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 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 that competitors may be able to meet. Suncor
believes that the competition for its custom blended synthetic crude oil
production is Canadian conventional and synthetic light sweet crude oil.
A number of other companies have indicated they are planning to enter
the oil sands business and begin production of synthetic crude oil. In December
1999 Shell Canada Limited and its partners, Chevron Canada Resources Limited and
Western Oil Sands Inc., announced they were moving forward with their Athabasca
Oil sands Project 70 kilometres north of Fort McMurray. In addition, Syncrude
Canada, the only other current producer of synthetic crude oil in the Fort
McMurray area of Alberta, announced plans to increase its production. Increases
in the supply of synthetic crude oil could create downward pressure on prices
received by Suncor.
In the western Canadian diesel market demand and supply can fluctuate.
Currently there is excess supply with 1999 margins lower than in 1998. Margins
for diesel are typically higher than the margins relative to 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.
22
<PAGE>
Over the past five years the industry-wide oversupply of refined
petroleum products and the overabundance of retail outlets have kept pressure on
downstream margins. Management expects that fluctuations in demand for refined
products, margin volatility and overall marketplace competitiveness will
continue. In addition, as Suncor's downstream business unit, Sunoco,
participates in new product markets, such as natural gas and potentially
electricity, it could be exposed to margin risk and volatility from either cost
and/or selling price fluctuations.
NEED TO REPLACE CONVENTIONAL NATURAL GAS RESERVES. The future natural gas
reserves and production of the Company's E&P business unit and, therefore, E&P's
cash flow from such production are highly dependent on its success in
discovering or acquiring additional reserves and exploiting its current reserve
base. Without natural gas reserve additions through exploration and development
or acquisition activities, E&P's conventional natural gas reserves and
production will decline over time as reserves are depleted. 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, E&P's ability to make
the necessary capital investments to maintain and expand its conventional
natural gas reserves could be impaired. In addition, E&P'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.
E&P is in the process of divesting of an estimated $100 to $200 million
of properties in 2000. It is expected that the majority of properties to be
divested will be oil properties as E&P intends to focus on natural gas.
ABORIGINAL LAND CLAIMS. 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 city of Fort McMurray, Alberta claiming, among other things, a
declaration that the plaintiffs have aboriginal title to large areas of lands
surrounding Fort McMurray, including the lands on which Oil Sands and most of
the other oil sand operations in Alberta are conducted. 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.
OPERATING HAZARDS AND OTHER UNCERTAINTIES. Each of Suncor's three principal
operating business units, Oil Sands, E&P and Sunoco, require high levels of
investment and have particular economic risk 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 oil, gas and other related products.
At Oil Sands, the mining of oil sands, the extraction of bitumen from
the oil sands, the upgrading of such bitumen into synthetic crude oil and other
products involve particular risks and uncertainties. The Oil Sands plant located
near Fort McMurray in northern Alberta is susceptible to loss of production,
slowdowns, or restrictions on its ability to produce higher value products due
to the interdependence of its component systems. In 1999, Oil Sands experienced
two separate outages in its upgrader facility totaling 16 days. The outages were
related to a change in feedstock resulting from the operation of the new fixed
plant expansion. 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 synthetic crude oil, mine development and expansion
of production can entail significant capital outlays. The costs associated with
synthetic crude oil production at Oil Sands are largely fixed and, as a result,
operating costs per unit are largely dependent on levels of production.
In Suncor's E&P business unit, the risks and uncertainties associated
with the acquisition, development, exploration for, and production,
transportation and storage of crude oil, natural gas and natural gas liquids
should not be underestimated or viewed as predictable. E&P's operations are
subject to all of the risks normally incident to the drilling of natural gas and
oil wells, the operation and development of gas and oil properties, including
encountering unexpected formations or pressures, premature declines of
reservoirs, blow- outs, equipment failures and other accidents, sour gas
releases, uncontrollable flows of oil, natural gas or well fluids, adverse
weather conditions, pollution, and other environmental risks. As noted above,
E&P plans to divest its crude oil properties.
23
<PAGE>
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. During 1999, Sunoco
experienced four minor slowdowns of its refinery as a result of equipment
failure.
Although Suncor maintains a risk management program, including an
insurance component, such insurance may not provide adequate coverage in all
circumstances, nor are all such risks insurable. Losses resulting from the
occurrence of these risks could have a material adverse impact on Suncor. Under
the Company's business interruption insurance coverage, the Company would bear
the first $70 million of any loss arising from a future insured incident at its
Oil Sands operations.
Suncor's Stuart Oil Shale Project in Gladstone, Australia, is also
developmental in nature and involves the inherent risk associated with the use
of new technology. Accordingly, the success of the project is not assured.
In addition, there are also inherent risks, including political and
foreign exchange risk, in investing in business ventures internationally.
INTEREST RATE RISK. Suncor is exposed to fluctuations in short term Canadian
interest rates as a result of the use of floating rate debt. Suncor maintains a
substantial portion of its debt capacity in revolving, floating rate bank
facilities and commercial paper, with the remainder issued in fixed rate
borrowings. To minimize its exposure to interest rate fluctuations, Suncor
occasionally enters into interest rate swap agreements and exchange contracts to
effectively fix the interest rate on floating rate debt.
EXCHANGE RATE FLUCTUATIONS. Suncor's Consolidated Financial Statements are
presented in Canadian dollars. Results of operations are affected by the
exchange rates between the Canadian dollar and the U.S. dollar. These exchange
rates have varied substantially in the last five years. A substantial portion of
Suncor's revenue is received by reference to U.S. dollar denominated prices. Oil
prices are generally set in U.S. dollars, while Suncor's sales of refined
products are primarily in Canadian dollars. Fluctuations in exchange rates
between the U.S. and Canadian dollar may therefore give rise to foreign currency
exposure, either favorable or unfavorable. In the future, the strength of the
Canadian dollar relative to foreign currencies could create additional
uncertainties for Suncor as it pursues its international growth plans.
ENVIRONMENTAL RISKS. Environmental legislation affects nearly all aspects of
Suncor's operations. These regulatory regimes are laws of general application
that apply to Suncor in the same manner as they apply to other companies and
enterprises in the energy industry. The regulatory regimes require Suncor to
obtain operating licenses and impose certain standards and controls on
activities relating to mining, oil and gas exploration, development and
production, and the refining, distribution and marketing of petroleum products
and petrochemicals. Environmental assessments are required before initiating
most new major projects or undertaking significant changes to existing
operations. In addition to these specific, known requirements, Suncor expects
further changes will likely be required to preserve and protect the environment
and quality of life. Some of the issues under discussion by Suncor include:
possible cumulative impacts of oil sands development in the Athabasca region;
reducing or stabilizing various emissions, including greenhouse gases; land
reclamation and restoration; Great Lakes water quality; and reformulated
gasoline to support lower vehicle emissions. Changes in environmental
legislation could have a potentially adverse effect on Suncor from the
standpoint of product demand, product reformulation and quality, and methods and
costs of production and distribution. For example, cleaner-burning fuels may be
mandated, causing additional costs, which may or may not be recoverable in the
marketplace. The complexity and breadth of these issues make it extremely
difficult to predict their future impact on Suncor. Management anticipates
capital expenditures and operating expenses will increase in the future as a
result of the implementation of new and increasingly stringent environmental
regulations. Compliance with environmental legislation can require significant
expenditures and failure to comply with environmental legislation may result in
the imposition of fines and penalties, liability for clean up costs and damages
and the loss of important permits.
Suncor is required to and has posted with the Department of Alberta
Environmental Protection annually an irrevocable letter of credit, bond or other
security equal to $0.03 per barrel of oil produced ($12 million as at December
31, 1999) as security for its reclamation activity. For the second phase of
Project Millennium, Suncor
24
<PAGE>
has posted with the Department of Alberta Environmental Protection an
irrevocable letter of credit equal to approximately $11 million, representing
security for the estimated cost of reclamation activities relating to Project
Millennium up to the end of the year 2000.
UNCERTAINTY OF RESERVE ESTIMATES. The reserve data for Suncor's Oil Sands and
E&P business units included herein represent estimates only. There are numerous
uncertainties inherent in estimating quantities of reserves, including many
factors beyond the control of Suncor. In general, estimates of economically
recoverable reserves are based upon a number of variable factors and
assumptions, such as historical production from the properties, the assumed
effect of regulation by governmental agencies, and future operating costs, all
of which may vary considerably from actual results. The accuracy of any reserve
estimate is a function of the quality and quantity of available data and of
engineering interpretation and judgment. In the Oil Sands business unit, reserve
estimates are based upon a geological assessment, including drilling and
laboratory tests, and also consider current production capability and upgrading
yields, current mine plans, operating life and regulatory constraints. In the
E&P 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 E&P the classification of such reserves based on risk of
recovery and estimates of future net revenues expected therefrom, 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.
IMPACT OF MARGIN VOLATILITY ON SUNOCO. Sunoco's operations are sensitive to
wholesale and retail margins for its refined products, including gasoline.
Margin volatility is influenced by overall marketplace competitiveness, weather,
the cost of crude oil (See "Volatility of Crude Oil and Natural Gas Prices") and
fluctuations in supply and demand for refined products. Sunoco expects that
margin volatility and overall marketplace competitiveness will continue.
In December 1997 the National Energy Board authorized reversal of the
flow of the Interprovincial Pipeline (Line 9) from Sarnia to Montreal. The
reversal had been advocated by a number of Ontario refiners in order to provide
access to competitively priced offshore crude oil. Sunoco did not participate in
this industry initiative. The National Energy Board ruling makes 20% of the
capacity of Line 9 available to shippers, including Sunoco, who were outside the
group of refiners advocating the flow reversal. The flow reversal could result
in Sunoco's competitors having greater access than Sunoco has to lower priced
offshore crude oil.
IMPACT OF REFORMULATED FUELS ON SUNOCO. The automobile and manufacturing
industry has put forward specifications for a worldwide, harmonized fuel
standard. These new specifications, if adopted, could result in higher refining
costs. In addition, new technology is enabling vehicles to use fuel more
efficiently, could also increase refinery costs and reduce product demand. In
late 1998 the Canadian government proposed a regulation mandating reduced
sulphur levels in gasoline by 2002. Legislation was passed in 1999 that limits
sulphur levels in gasoline to an average of 150 parts per million (ppm) from
mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. The Canadian
refining industry will be faced with significant capital spending to as a result
of implementing these regulations. Although the spending required by Sunoco to
meet the new standards could be significant, Sunoco believes it will not be
material to Suncor on a consolidated basis and that compliance spending will not
put Sunoco at a competitive disadvantage. In the downstream, requirements with
respect to fuels reformulation, together with legislative requirements, could
result in higher costs that may not be fully recovered through increased prices
to customers.
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 expires on
May 1, 2001. Suncor believes that the current positive working relationship will
continue and that a new agreement should be reached without work interruptions,
although no assurance can be given in this regard. Any work interruptions could
materially and adversely affect Suncor's business and financial position.
25
<PAGE>
GOVERNMENTAL REGULATION. The oil and gas industry in Canada, including the oil
sands industry, operates under federal, provincial and municipal legislation,
regulation and intervention by governments in such matters as land tenure,
prices, royalties, production rates, environmental protection controls, income,
the export of oil, natural gas and other products, as well as other matters.
This industry is also subject to regulation and intervention by governments in
such matters as the awarding or acquisition of exploration and production, oil
sands or other interests, the imposition of specific drilling obligations,
environmental protection controls, control over the development and abandonment
of fields and mine sites (including restrictions on production) and possibly
expropriation or cancellation of contract rights. Before proceeding with most
major projects, including significant changes to existing operations, Suncor
must obtain regulatory approvals. The regulatory approval process can involve
stakeholder consultation, environmental impact assessments and public hearings,
among other things. In addition, regulatory approvals may be subject to
conditions including security deposit obligations and other commitments. Failure
to obtain regulatory approvals, or failure to obtain them on a timely
cost-effective basis, could result in delays and abandonment or restructuring of
projects and increased costs, all of which could negatively affect future
earnings and cash flow. Such regulations may be changed from time to time in
response to economic or political conditions. The implementation of new
regulations or the modification of existing regulations affecting the oil and
natural gas industry could reduce demand for crude oil and natural gas, increase
Suncor's costs and have a material adverse impact on Suncor's operations.
ITEM 4 SELECTED CONSOLIDATED FINANCIAL INFORMATION
SELECTED CONSOLIDATED FINANCIAL INFORMATION
The following selected consolidated financial information for each of
the years in the five-year period ended December 31, 1999 is derived from
Suncor's consolidated financial statements. The consolidated financial
statements for each of the years in the five year period ended December 31, 1999
have been audited by PricewaterhouseCoopers LLP (formerly Coopers & Lybrand),
Chartered Accountants. Suncor's 1999 audited consolidated financial statements
include the audit report of PricewaterhouseCoopers LLP for each of the years in
the three-year period ended December 31, 1999. The information set forth below
should be read in conjunction with the MD&A and Suncor's consolidated
comparative financial statements and related notes.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,(1)
--------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
($ MILLIONS EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Revenues ..................................... 2,387 2,070 2,154 2,100 1,901
Net earnings ................................. 200 188 223 187 151
Per common share(1) .......................... 1.61 1.70 2.04 1.71 1.38
Cash flow provided from operations ........... 591 580 575 491 395
Per common share(1) .......................... 5.02 5.27 5.24 4.49 3.62
Capital and exploration expenditures ......... 1,350 936 847 563 436
</TABLE>
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
($ MILLION)
<S> <C> <C> <C> <C> <C>
Total assets ................................. 5,176 4,104 3,457 2,824 2,440
Long-term borrowings(2) ...................... 1,307 1,299 773 401 259
Common shareholders' equity (3) .............. 1,628 1,519 1,401 1,247 1,127
</TABLE>
Notes:
(1) Per share amounts for all years reflect a two-for-one share split in
1997 and payments on the preferred securities issued in 1999.
(2) Includes current portion.
(3) Excludes Preferred Securities issued in 1999. See "Dividend Policy and
Record".
26
<PAGE>
<TABLE>
THREE MONTHS ENDED
------------------
DEC. 31, SEPT. 30, JUNE 30, MAR. 31, DEC. 31, SEPT. 30, JUNE 30, MAR. 31,
1999 1999 1999 1999 1998 1998 1998 1998
-------- --------- -------- -------- -------- --------- -------- --------
($ MILLION EXCEPT PER SHARE AMOUNTS -- UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues .............................. 715 639 564 469 498 531 498 543
Net earnings .......................... 75 74 36 15 44 49 45 50
Per common share(1) ................... 0.61 0.61 0.27 0.12 0.39 0.44 0.41 0.46
Cash flow provided from operations ... 222 147 129 93 128 170 138 144
Per common share(1) ................... 1.90 1.22 1.05 0.85 1.16 1.55 1.25 1.31
</TABLE>
Note:
(1) Per share amounts for all quarters reflect a two-for-one share split in
1997 and payments on the preferred securities issued in 1999.
DIVIDEND POLICY AND RECORD
Suncor's board of directors has established a policy of paying
dividends on a quarterly basis. A dividend for the first quarter of 1999 has
been declared of $0.17 per common share payable on March 24, 2000 to
shareholders of record on March 15, 2000. This policy will be reviewed from time
to time in light of Suncor's financial position, its financing requirements for
growth, its cash flow and other factors considered relevant by Suncor's board of
directors.
During 1999, the Company completed a Canadian offering of $276 million
of 9.05% preferred securities and a U.S. offering of US$162.5 million of 9.125%
preferred securities, the proceeds of which totalled Canadian $507 million after
issue costs of $17 million ($10 million after income tax credits of $7 million).
The preferred securities are unsecured junior subordinated debt of the Company,
due in 2048 and redeemable at the Company's option on or after March 15, 2004.
Subject to certain conditions, the Company has the right to defer payment of
interest on the securities for up to 20 consecutive quarterly periods. Deferred
interest and principal amounts are payable in cash, or, at the option of the
Company, from the proceeds on the sale of equity securities of the Company
delivered to the trustee of the preferred securities. For accounting purposes,
the preferred securities are classified as share capital in the consolidated
balance sheet and the interest distributions thereon, net of income taxes, are
classified as dividends. Proceeds from the offerings were used to repay
commercial paper borrowings.
The following table sets forth the per share amount of dividends paid
by Suncor during the last five years.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Common Shares
Cash dividends(1) ..................... $ 0.68 $ 0.68 $ 0.68 $ 0.64 $ 0.57
Preferred Securities
Cash interest distributions ........... $ 0.34 -- -- -- --
</TABLE>
Note:
(1) Per share amounts for all years reflect a two-for-one share split
in 1997.
ITEM 5 MANAGEMENT'S DISCUSSION AND ANALYSIS
Suncor's Management's Discussion and Analysis, dated February 24, 2000,
is incorporated by reference into and forms an integral part of this Annual
Information Form, and should be read in conjunction with Suncor's consolidated
comparative financial statements and the notes thereto.
27
<PAGE>
ITEM 6 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 35% 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.
ITEM 7 DIRECTORS AND OFFICERS
As of the date hereof, Suncor's Board of Directors is comprised of
eleven directors, increasing to thirteen at the April 19, 2000, Annual and
Special Meeting. 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 but does not have an
Executive 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 as of February 24, 2000.
<TABLE>
<CAPTION>
SECURITIES OF SUNCOR
PRINCIPAL OCCUPATION BENEFICIALLY OWNED OR
OR EMPLOYMENT, AND OVER WHICH CONTROL OR
MAJOR POSITIONS AND DIRECTION IS EXERCISED
NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST AS AT FEBRUARY 24,
RESIDENCE AS A DIRECTOR(1) FIVE YEARS 2000(2)
--------------------------- ------------------ --------------------- -----------------------
<S> <C> <C> <C>
Brian A. Canfield(5)(6) November 10, 1995 President and Chief 4,026 Common Shares
Point Roberts, Washington to Present Executive Officer,
BCT.TELUS 734.18 Deferred Share
Communications Inc. Units(8)
(a telecommunications
company)
John T. Ferguson(4)(5) November 10, 1995 Chairman, Princeton 4,114 Common Shares
Edmonton, Alberta to Present Developments Ltd. (a
real estate 344.69 Deferred Share
development Units(8)
company), Chairman
and Director,
TransAlta
Corporation (an
electric utility
company)
Richard L. George(4)(5) February 1, 1991 President and Chief 49,439 Common Shares
Calgary, Alberta to Present Executive Officer,
Suncor Energy Inc.(7)
Poul Hansen(3)(4) April 23, 1996 to Chairman and General 3,413 Common Shares
Vancouver, British Columbia Present Manager, Sperling
Hansen Associates
Inc. (an environmental
engineering consulting
company)
</TABLE>
28
<PAGE>
<TABLE>
<CAPTION>
SECURITIES OF SUNCOR
PRINCIPAL OCCUPATION BENEFICIALLY OWNED OR
OR EMPLOYMENT, AND OVER WHICH CONTROL OR
MAJOR POSITIONS AND DIRECTION IS EXERCISED
NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST AS AT FEBRUARY 24,
RESIDENCE AS A DIRECTOR(1) FIVE YEARS 2000(2)
--------------------------- ------------------ --------------------- -----------------------
<S> <C> <C> <C>
John R. Huff(4)(5) January 30, 1998 Chairman and Chief 5,046 Common Shares
Houston, Texas to Present Executive Officer,
Oceaneering 754.34 Deferred Share
International, Inc. Units(8)
(an oilfield
services company)
Michael M. Koerner(5)(6) May 31, 1977 to President, Canada 4,000 Common Shares
Toronto, Ontario January 27, 1994; Overseas Investments
October 1, 1995 to Limited (a venture 872.63 Deferred Share
Present capital investment Units(8)
management company)
Robert W. Korthals(3)(6) April 23, 1996 to Corporate Director 4,000 Common Shares
Toronto, Ontario Present
917.43 Deferred Share
Units(8)
M. Ann McCaig(3)(4) October 1, 1995 to President, VPI 2,544 Common Shares
Calgary, Alberta Present Investments Ltd. (a
private investment 787.45 Deferred Share
holding company) Units(8)
Bill N. Rutherford(3)(6) November 22, 1988 Retired Senior Vice 2,029 Common Shares
Naples, Florida to April 28, 1993; President, Human
April 28, 1994 to Resources and 468.79 Deferred Share
Present Administration, Units(8)
Sunoco, Inc.,
formerly Sun
Company, Inc. (an
energy resources
company)
JR Shaw(3)(4) January 30, 1998 Executive Chairman 16,000 Common Shares
Calgary, Alberta to Present of the Board, Shaw
Communications Inc. 734.18 Deferred Share
(a diversified Units(8)
communications
company)
W. Robert Wyman(5)(6) November 25, 1987 Chairman of the 16,200 Common Shares
West Vancouver, British to Present Board of Directors
Columbia of Suncor Energy Inc. 1,006.13 Deferred
Share Units(8)
</TABLE>
-------------------------
(1) Suncor was formed by the amalgamation of Great Canadian Oil Sands
Limited and Sun Oil Company Limited on August 22, 1979. On January 1,
1989, Suncor amalgamated with a wholly owned subsidiary under the
CANADA BUSINESS CORPORATIONS ACT. Each nominee has been a director of
Suncor or one of the amalgamating companies for the periods described.
(2) The information relating to holdings of Common Shares, not being within
the knowledge of Suncor, has been furnished by the respective nominees
individually. Where a nominee holds a fractional Common Share, the
holdings reported have been rounded down to the nearest whole Common
Share. Certain of the Common Shares held by Mr. George and Mr. Hansen
are held jointly with their respective spouses. The number of Common
Shares held by Mr. George includes 740 Common Shares over which he
exercises control or direction but which are beneficially owned by
members of his family.
29
<PAGE>
(3) Member of the Audit Committee.
(4) Member of the Environment, Health and Safety Committee.
(5) Member of the Board Policy, Strategy Review and Governance Committee.
(6) Member of the Human Resources and Compensation Committee.
(7) Mr. George is also the President and a director of Sunoco Inc.
("Sunoco"), Suncor's refining and marketing subsidiary.
(8) Deferred Share Units (DSU's) are not securities but are included in
this table for informational purposes. DSU's are issued to outside
directors electing to receive same in lieu of cash compensation, and
entitle directors to a cash payment when he or she ceases to hold
office as a director, equal to the number of DSU's multiplied by the
market value of a Suncor common share at the time of payment.
Each of the directors named above has been engaged in the principal
occupation indicated above for the past five years, except for: Mr. Canfield,
who in 1998 was Chairman, BC TELECOM Inc. and BC TEL, and who from 1993 to 1997
was Chief Executive Officer and Chairman, BC TELECOM Inc. and BC TEL; Mr.
Ferguson, who from 1996 to 1998 was also Chief Executive Officer, Princeton
Developments Ltd., in addition to his current position as Chairman, Princeton
Developments Ltd., and who prior to 1996 was President and Chief Executive
Officer, Princeton Developments Ltd.; Mr. Hansen, who, in 1995 and prior
thereto, was President, Highland Valley Copper (a mining company); Mr. Huff, who
in 1998 and prior thereto was also President, Oceaneering International, Inc.,
in addition to his current position as Chairman and Chief Executive Officer,
Oceaneering International, Inc.; Mr. Korthals, who in 1995 and prior thereto,
was President of The Toronto-Dominion Bank (a chartered bank); Mr. Shaw, who in
1998 and prior thereto was Chairman and Chief Executive Officer of Shaw
Communications Inc.; and Mr. Wyman, who served as Chairman of the Board of
Finning Ltd. (a heavy duty construction equipment marketing and leasing company)
from 1992 to 1996 and 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 Company. Except where otherwise
indicated, the persons named in the table below held the offices set out
opposite their respective names as at December 31, 1999 and as of the date
hereof.
<TABLE>
<CAPTION>
NAME AND MUNICIPALITY OF RESIDENCE OFFICE(1)
---------------------------------- ---------
<S> <C>
W. Robert Wyman...................................... Chairman of the Board
West Vancouver, British Columbia
Richard L. George.................................... President and Chief Executive Officer
Calgary Alberta
Barry D. Stewart..................................... Group Executive Vice President, Exploration and Production
Calgary, Alberta (prior to January 1, 2000)
Executive Vice President, In-Situ and International Oil (from
January 1, 2000)
Mike Ashar........................................... Executive Vice President, Oil Sands
Fort McMurray, Alberta
Michael W. O'Brien................................... Executive Vice President, Sunoco (prior to January 1, 2000)
Canmore, Alberta Executive Vice President, Corporate Development and Chief
Financial Officer (from January 1, 2000)
David W. Byler....................................... Chief Financial Officer (prior to January 1, 2000)
M.D. of Rockyview, Alberta Executive Vice President, Exploration and Production (from
January 1, 2000
Thomas L. Ryley...................................... Vice President, Planning and Corporate Development (prior to
Toronto, Ontario January 1, 2000)
Executive Vice President, Sunoco (from January 1, 2000)
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
NAME AND MUNICIPALITY OF RESIDENCE OFFICE(1)
---------------------------------- ---------
<S> <C>
Terrence J. Hopwood.................................. Vice President, General Counsel and Secretary
Calgary, Alberta
Sue Lee.............................................. Senior Vice President, Human Resources and
Calgary, Alberta Communications
J. Kenneth Alley..................................... Treasurer (prior to January 1, 2000)
Calgary, Alberta Vice President, Finance (from January 1, 2000)
Janice B. Odegaard................................... Assistant Secretary
Calgary, Alberta
</TABLE>
Note:
(1) The principal occupation of each officer is the specified office with
Suncor, with the exception of Ms. Odegaard, who is also Corporate
Director, Legal Affairs, of Suncor.
All of the foregoing officers of the Company have, for the past five
years, been actively engaged as executives or employees of Suncor or its
affiliates, except: Mr. Wyman, who is a non-executive Chairman of Suncor; Ms.
Lee, who prior to March 1996 was Vice President, Human Resources, TransAlta
Corporation; and Ms. Odegaard, who prior to July 1995 was a partner, Atkinson
Milvain.
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 one percent.
ITEM 8 ADDITIONAL INFORMATION
Copies of the documents set out below may be obtained without charge by
any person upon request to the Secretary, Suncor Energy Inc., Box 38, 112 - 4
Avenue S.W., Calgary, Alberta, T2P 2V5:
(i) The current Suncor Annual Information Form together with any pertinent
information incorporated by reference therein;
(ii) The current Suncor comparative financial statements for the most
recently completed financial year and the report of the auditors
relating thereto, together with any subsequent interim financial
statements;
(iii) Suncor's management proxy circular in respect of its most recent
annual meeting of shareholders that involved the election of
directors; and
(iv) Any other documents incorporated by reference into Suncor's most
recent preliminary short form prospectus or short form prospectus if
securities of Suncor are in the course of distribution pursuant to
such documents.
Additional information, including directors' and officers' remuneration
and indebtedness, principal holders of Suncor's securities, options to purchase
securities and interests of insiders in material transactions, where applicable,
is contained in Suncor's most recent management proxy circular for its most
recent annual meeting of its shareholders. Additional financial information is
provided in Suncor's comparative financial statements for its most recently
completed financial year.
31
<PAGE>
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. UNDERTAKING
Suncor Energy Inc. (the "Registrant") undertakes to make available, in
person or by telephone, representatives to respond to inquiries made by the
staff of the Securities and Exchange Commission ("SEC"), and to furnish
promptly, when requested to do so by the SEC staff, information relating to the
securities in relation to which the obligation to file an annual report on Form
40-F arises or transactions in said securities.
B. CONSENT TO SERVICE OF PROCESS
The Registrant has filed previously with the SEC a Form F-X in
connection with the Common Shares.
Page 41 of 101
<PAGE>
SIGNATURES
Pursuant to the requirements of the Exchange Act, the registrant
certifies that it meets all of the requirements for filing on Form 40-F and has
duly caused this annual report to be signed on its behalf by the undersigned,
thereto duly authorized.
SUNCOR ENERGY INC.
BY: "MICHAEL W. O'BRIEN"
--------------------------------------------
Michael W. O'Brien
Executive Vice President, Corporate
Development and Chief Financial Officer
DATE: October 12, 2000
Page 42 of 101
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
SEQUENTIALLY
NUMBERED
EXHIBIT NO. DESCRIPTION PAGE
<S> <C> <C> <C>
* 1 Reconciliation to U.S. GAAP 44
* 2 Audited Consolidated Financial Statements of Suncor 54
Energy Inc. for the fiscal year ended December 31, 1999
* 3 Management's Discussion and Analysis for the fiscal year 76
ended December 31, 1999, dated February 24, 2000
98
* 4 Consent of PricewaterhouseCoopers LLP
100
* 5 Consent of Gilbert Laustsen Jung Associates Ltd.
</TABLE>
* Previously filed on Form 40F dated March 16, 2000
Page 43 of 101
<PAGE>
EXHIBIT 1
Page 44 of 101
<PAGE>
EXHIBIT 2
Page 54 of 101
<PAGE>
EXHIBIT 3
Page 76 of 101
<PAGE>
EXHIBIT 4
Page 98 of 101
<PAGE>
EXHIBIT 5
Page 100 of 101
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
SUNCOR ENERGY INC.
Date: October 12, 2000 BY: "MICHAEL W. O'BRIEN"
-----------------------------------
MICHAEL W. O'BRIEN
Executive Vice President,
Corporate Development and Chief
Financial Officer
