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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: March 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
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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
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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
EXHIBIT DESCRIPTION OF EXHIBIT
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EXHIBIT 1 Reconciliation to U.S. GAAP
EXHIBIT 2 Audited Consolidated Financial Statements of Suncor
Energy Inc. for the fiscal year ended December 31, 1999
EXHIBIT 3 Management's Discussion and Analysis for the fiscal
year ended December 31, 1999, dated February 24, 2000
EXHIBIT 4 Consent of PricewaterhouseCoopers LLP
EXHIBIT 5 Consent of Gilbert Laustsen Jung Associates Ltd.
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SUNCOR ENERGY INC. ANNUAL INFORMATION FORM
FEBRUARY 24, 2000
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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
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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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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
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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.
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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.
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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
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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
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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
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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 ACRES(1) NET ACRES(1) GROSS ACRES(1) NET ACRES(1) GROSS ACRES(1) NET ACRES(1)
-------------- ------------ -------------- ------------ -------------- ------------
(THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Canada
CONVENTIONAL ......... 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 ............ - - 1,371 1,371 1,371 1,371
--- --- ----- ----- ----- -----
Total
Non-Conventional ..... 26 13 1,661 1,470 1,687 1,483
--- --- ----- ----- ----- -----
Total Landholdings ... 248 139 2,184 1,867 2,432 2,006
--- --- ----- ----- ----- -----
--- --- ----- ----- ----- -----
</TABLE>
Note:
(1) "Gross Acres" means all acres in which Suncor has an interest. "Net
Acres" 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>
EXHIBIT 1
<PAGE>
SUNCOR ENERGY INC.
1999 RECONCILIATION OF RESULTS
FROM CANADIAN GAAP TO U.S. GAAP
<PAGE>
CANADIAN AND UNITED STATES ACCOUNTING PRINCIPLES
The consolidated financial statements of Suncor Energy Inc. have been
prepared in accordance with Canadian generally accepted accounting principles
(GAAP). These principles conform in all material respects to those in the
United States (U.S.) except for the following:
<TABLE>
<CAPTION>
1999 1998 1997
------------ ------------ ------------
($ millions)
<S> <C> <C> <C>
Net earnings as shown in
financial statements 200 188 223
Impact of U.S. accounting
principles:
Post-retirement benefits
other than pensions (1) (4) (4) (4)
Pensions - rate effect (2) (10) (6) (6)
Derivative financial
instruments (3) 29 (29) -
Preferred securities (4) (20) - -
Capitalized interest (5) 2 - -
Start-up activities (6) (19) - -
------------ ------------ ------------
Net earnings according to
U.S. GAAP 178 149 213
Other comprehensive income, net of tax:
Minimum pension liability (7) 6 (6) -
------------ ------------ ------------
Comprehensive income according to U.S.
GAAP 184 143 213
------------ ------------ ------------
Net earnings per share according
to U.S. GAAP (dollars)*
Basic 1.61 1.35 1.95
------------ ------------ ------------
Diluted 1.60 1.34 1.93
------------ ------------ ------------
</TABLE>
* Per share calculations, for both current and prior years, reflect a
two-for-one split of the company's common shares during 1997.
2
<PAGE>
The adjustments under U.S. GAAP result in changes to the Consolidated Balance
Sheets of the company as follows:
<TABLE>
<CAPTION>
AS AT as at
DECEMBER 31, 1999 December 31, 1998
($ MILLIONS) ($ millions)
AS U.S. As U.S.
REPORTED GAAP reported GAAP
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Current assets 457 457 401 401
Capital assets, net (5)(6) 4,528 4,503 3,504 3,504
Deferred charges and
other (4)(6)(7) 191 205 199 209
------------ ------------ ------------ ------------
Total assets 5,176 5,165 4,104 4,114
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Current liabilities (1)(4) 710 712 370 372
Long-term borrowings (4) 1,306 1,830 1,298 1,298
Accrued liabilities and
other (1)(2)(3)(7) 179 234 161 261
Deferred income taxes (1)(2)(3)
(4)(5)(6)(7)(8) 839 736 756 645
Equity:
Share capital and retained earnings (4) 2,142 1,653 1,519 1,544
Accumulated other comprehensive
income (7) - - - (6)
------------ ------------ ------------ ------------
2,142 1,653 1,519 1,538
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Total liabilities and
shareholders' equity 5,176 5,165 4,104 4,114
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
</TABLE>
(1) The company provides certain health care and life insurance benefits for
its retired employees and eligible surviving dependents. Under U.S. GAAP
(SFAS No. 106 "Employers' Accounting for Post-Retirement Benefits Other
than Pensions"), the expected cost of these benefits is actuarially
determined and accrued ratably from the date of hire to the date the
employee is fully eligible to receive the benefits. Under Canadian GAAP,
costs of these benefits are charged to earnings as payments are made by
the company on behalf of retirees and dependents.
The incremental expense under SFAS 106 decreased 1999 net earnings by $4
million after related income tax recoveries of $3 million, decreased 1998
net earnings by $4 million after related income tax recoveries of $2
million and decreased 1997 net earnings by $4 million after related income
tax recoveries of $2 million.
3
<PAGE>
The current portion of the postretirement benefit liability of $2 million
(1998 - $2 million) is included in current liabilities in the consolidated
balance sheets. The long-term portion of the post retirement benefit
liability of $56 million (1998 - $49 million) is included in accrued
liabilities and other in the consolidated balance sheets. See the section
"Pensions and Other Postretirement Benefits" for disclosure under SFAS No.
132, "Employers' Disclosures about Pensions and Other Postretirement
Benefits".
(2) Under U.S. GAAP (SFAS No. 87, "Employers' Accounting for Pensions"),
defined benefit pension plans expense was determined using a discount rate
of 6% for 1999 and 7% for 1998 and 1997. Projected benefit obligations,
calculated at December 31 of each year, were determined using a discount
rate of 7 1/4% for 1999, 6% for 1998 and 7% for 1997. Under Canadian GAAP,
defined benefit pension plans expense was determined using a discount rate
of 8% for 1999, 1998 and 1997. Projected benefit obligations were
determined using a discount rate of 7 1/4% for 1999 and 8% for 1998 and
1997. In 1999, the impact of the discount rate differences resulted in a
pension expense that was $16 million higher under U.S. GAAP than under
Canadian GAAP (1998 and 1997 - $10 million higher). This incremental
expense under SFAS 87 decreased 1999 net earnings by $10 million after
related income tax recoveries of $6 million, and decreased both 1998 and
1997 net earnings by $6 million after related income tax recoveries of $4
million.
Under U.S. GAAP, the recorded benefit obligations were $1 million lower at
December 31, 1999, than recorded under Canadian GAAP (1998 - $17 million
lower). See the section "Pensions and Other Postretirement Benefits" for
disclosure under SFAS 132, "Employers' Disclosures about Pensions and
Other Postretirement Benefits".
(3) The company is a party to certain off-balance-sheet derivative financial
instruments, such as crude oil, natural gas and foreign currency swap
contracts, in respect of future firmly committed and anticipated sales
transactions. Under Canadian GAAP, foreign currency swap contracts
qualify, and are accounted for, as hedges of these future transactions.
Under U.S. GAAP, foreign currency swap contracts used to hedge foreign
currency exposure to anticipated, but not firmly committed, transactions
cannot be accounted for as hedges under SFAS No. 52, "Foreign Currency
Translation".
Accordingly, for reporting under U.S. GAAP, gains or losses resulting from
changes in the market value of foreign currency swap contracts related to
these anticipated transactions are recognized in earnings when those
changes in market value occur. Since the market value of these contracts at
December 31, 1999 was nil, the loss in 1998 has been reversed, resulting in
an increase in 1999 net earnings of $29 million after income taxes of $19
million (1998 - net earnings decreased by $29 million after income tax
recoveries of $19 million; 1997 - no impact on net earnings).
(4) Under Canadian GAAP, the preferred securities issued in 1999 are
classified as share capital in the consolidated balance sheets and the
interest distributions thereon, net of income taxes, are accounted for
as dividends in the consolidated statements of changes in shareholders'
equity. Under US GAAP, the preferred securities are classified as
long-term borrowings in the consolidated balance sheets and the interest
distributions thereon and the related income tax impact are accounted
for in the consolidated statements of earnings.
Under Canadian GAAP, issue costs of the preferred securities, net of the
related income tax credits, are charged against share capital. Under US
GAAP, issue costs are deferred on the consolidated balance sheets and
amortized to earnings over the term of the related long-term borrowings.
4
<PAGE>
This difference in classification decreased 1999 net earnings by $20
million after income tax recoveries of $17 million.
These preferred securities, which are publicly traded, had a fair value,
based on quoted market prices, of $492 million at December 31, 1999.
Under Canadian GAAP, the interest distributions of $37 million on the
preferred securities are classified as financing activities in the
consolidated statements of cash flows. Under U.S. GAAP (SFAS No.95,
"Statement of Cash Flows"), the interest distributions are classified as
operating activities.
(5) Under the company's interest capitalization accounting policy, the
interest distributions on the preferred securities referred to in note
(4) above are eligible for interest capitalization under U.S. GAAP,
resulting in an increase in 1999 net earnings of $2 million after income
taxes of $2 million.
(6) Effective January 1, 1999, the company adopted AICPA Statement of
Position 98-5, "Reporting the Costs of Start-Up Activities" (SOP 98-5)
for reporting under U.S. GAAP. Under SOP 98-5, all costs relating to
start-up activities are expensed as incurred. Under Canadian GAAP, costs
of the company's start-up activities are initially capitalized and then
amortized over the estimated useful lives of the related assets.
The initial application of SOP 98-5 has been recognized in 1999 earnings
as the cumulative effect of a change in accounting principle, resulting
in a charge of $ 7 million ($0.06 per common share) after related income
tax credits of $ 5 million. Financial statements of prior years have not
been restated.
Excluding the cumulative effect, the incremental expense attributable to
adoption of SOP 98-5 decreased 1999 net earnings by $ 12 million after
related income tax credits of $ 8 million.
(7) Under U.S. GAAP (SFAS No.87, "Employers' Accounting for Pensions"),
recognition of an additional minimum pension liability is required when
the accumulated benefit obligation exceeds the fair value of plan assets
to the extent that such excess is greater than accrued pension costs
otherwise recorded. No such adjustment is required under Canadian GAAP.
Recording the additional minimum liability affects the consolidated
balance sheet only and has no impact on net earnings or cash flows. An
intangible asset equal to the amount of any unamortized liabilities
arising from plan amendments is recognized. Any excess of the additional
minimum liability over the amount recognized as an intangible asset is
recorded as a separate component of equity (net of any related income
tax recoveries), and is included as a component of comprehensive income
under SFAS No. 130, "Reporting Comprehensive Income".
At December 31, 1998, an additional minimum pension liability of $20
million, an intangible asset of $10 million and other comprehensive income
of $6 million, net of income tax recoveries of $4 million, was recognized.
As at December 31, 1999, the accumulated benefit obligation did not
exceed the fair value of plan assets and accrued pension costs otherwise
recorded. Accordingly, as at December 31, 1999 the additional minimum
pension liability and related intangible asset have been adjusted to
nil, and other comprehensive income of $6 million, net of income taxes
of $4 million has been recognized.
5
<PAGE>
(8) Under SFAS No. 109, "Accounting for Income Taxes", the company computes
deferred income taxes using the liability method. Under Canadian GAAP,
deferred income taxes are computed using the deferred method. This GAAP
difference had no effect on 1999, 1998, and 1997 net earnings. Since the
deferred tax assets and liabilities will have to be adjusted for any
future enacted changes in tax rates, the company's net earnings under
U.S. GAAP may be subject to increased volatility.
Under the liability method of SFAS No. 109, the tax effects of temporary
differences which comprise the deferred tax assets and liabilities are as
follows:
<TABLE>
<CAPTION>
DECEMBER 31 December 31
1999 1998
------------------- -------------------
($ millions)
<S> <C> <C>
Deferred tax assets:
Pension liabilities 28 30
Reclamation and environmental
remediation costs 9 10
Post-retirement benefits other than
pensions 23 20
Foreign currency swap contracts - 19
Preferred securities 17 -
Start-up costs 13 -
Other 39 12
------------------- -------------------
129 91
------------------- -------------------
Deferred tax liabilities:
Depreciation 820 690
Overburden removal costs 30 33
Maintenance shutdown costs 15 13
------------------- -------------------
865 736
------------------- -------------------
Net deferred income tax liability 736 645
------------------- -------------------
</TABLE>
6
<PAGE>
PENSIONS AND OTHER POSTRETIREMENT BENEFITS
The following presents information about the company's defined benefit pension
and other postretirement benefit plans under SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits".
<TABLE>
<CAPTION>
Pension benefits Other benefits
($ millions) 1999 1998 1997 1999 1998 1997
-------- --------- --------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year 403 334 322 72 64 53
Service costs 15 11 10 4 2 2
Interest costs 24 23 22 4 5 4
Plan participant's contribution 2 2 2 0 0 0
Amendments 0 0 0 (8) 3 6
Actuarial (gain) loss (61) 51 (4) (1) 0 0
Benefits paid (19) (18) (18) (2) (2) (1)
-------- --------- --------- --------- -------- --------
Benefit obligation at end of year 364 403 334 69 72 64
-------- --------- --------- --------- -------- --------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning
of year 278 250 223 0 0 0
Actual return on plan assets 39 28 28 0 0 0
Employer contribution 16 16 15 0 0 0
Plan participants' contribution 2 2 2 0 0 0
Benefits paid (19) (18) (18) 0 0 0
-------- --------- --------- --------- -------- --------
Fair value of plan assets at end of year 316 278 250 0 0 0
-------- --------- --------- --------- -------- --------
Funded status at end of year (48) (125) (84) (69) (72) (64)
Unrecognized transitional asset (16) (24) (31) 0 0 0
Unrecognized net actuarial loss 18 108 73 11 21 19
Intangible asset (4) - (10) 0 0 0 0
Accumulated other comprehensive
income (4) - (10) 0 0 0 0
-------- --------- --------- --------- -------- --------
Accrued benefit cost at end of year (46) (61) (42) (58) (51) (45)
-------- --------- --------- --------- -------- --------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost 15 11 10 4 2 2
Interest cost 24 23 22 4 5 4
Expected return on plan assets (22) (20) (18) 0 0 0
Recorded net actuarial (gain) loss 4 1 2 1 1 1
-------- --------- --------- --------- -------- --------
Net periodic benefit cost 21 15 16 9 8 7
-------- --------- --------- --------- -------- --------
</TABLE>
<TABLE>
<CAPTION>
Pension benefits Other benefits
1999 1998 1997 1999 1998 1997
-------- --------- --------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
</TABLE>
7
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
WEIGHTED-AVERAGE ASSUMPTIONS AS AT
DECEMBER 31
U.S. GAAP
Discount rate 7.25 6.0 7.0 7.25 6.0 6.0
-------- --------- --------- --------- -------- --------
Expected return on plan assets 7.25 8.0 8.0 0 0 0
-------- --------- --------- --------- -------- --------
Rate of compensation increase 4.25 4.5 4.5 4.25 4.5 4.5
-------- --------- --------- --------- -------- --------
Canadian GAAP
Discount rate 7.25 8.0 8.0
-------- --------- ---------
Expected return on plan assets 7.25 8.0 8.0
-------- --------- ---------
Rate of compensation increase 4.25 4.5 4.5
-------- --------- ---------
</TABLE>
In order to measure the expected cost of other postretirement benefits, a 10%
annual rate of increase in the per capita cost of covered health care benefits
was assumed for 2000. The rate was assumed to decrease gradually each year to a
rate of 5% for 2010 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for other postretirement benefit obligations. A 1% change in assumed
health care cost trend rates would have the following effects:
<TABLE>
<CAPTION>
($ millions) 1% INCREASE 1% DECREASE
----------- -----------
<S> <C> <C>
Effect on total of service and interest cost
components of net periodic postretirement health
care benefit cost 1 (1)
Effect on the health care component of the
accumulated postretirement benefit obligation 11 (9)
</TABLE>
STOCK-BASED COMPENSATION
The company applies APB Opinion 25 in accounting for common share options
granted to non-employee directors and certain executives. Accordingly, no
compensation cost has been recognized in the consolidated statements of
earnings. Had compensation cost been determined on the basis of fair values in
accordance with SFAS No. 123, "Accounting for Stock-Based Compensation", 1999
net earnings would have been lower by $5 million ($0.05 per common share), 1998
net earnings would have been lower by $3 million ($0.03 per common share) and
1997 net earnings would have been lower by $2 million ($0.01 per common share).
8
<PAGE>
RECENTLY ISSUED ACCOUNTING STANDARDS
(1) DERIVATIVE FINANCIAL INSTRUMENTS
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" was issued. The company expects to adopt SFAS No.
133 for U.S. reporting purposes effective January 1, 2001 when adoption
is mandatory. Under SFAS No. 133, all derivative contracts will be
recognized on the consolidated balance sheets at their fair value.
Changes in the fair value of derivative contracts that are not accounted
for as hedges will be recognized in net earnings as those changes occur.
Changes in the fair value of derivative contracts accounted for as
hedges will either be offset in net earnings against the fair value of
the related hedged items, or reflected initially as a separate component
of shareholders' equity and subsequently recognized in net earnings when
the hedged items are recognized in net earnings. The ineffective portion
of changes in the fair value of derivative contracts designated as
hedges will be recognized immediately in net earnings.
(2) EMPLOYEE FUTURE BENEFITS
In March 1999, the Accounting Standards Board of the Canadian Institute
of Chartered Accountants (CICA) issued CICA Handbook Section 3461,
"Employee Future Benefits". Section 3461 is based on the U.S. standards
on accounting for pension and other postemployment and postretirement
benefits costs and obligations (see notes (1) and (2) above under
"Canadian and United States Accounting Principles"). The company will
adopt Section 3461 for Canadian reporting purposes effective January 1,
2000 when adoption is mandatory.
(3) INCOME TAXES
In December 1997, Section 3465 of the CICA Handbook, "Income Taxes" was
issued. Section 3465 is based on the U.S. standard, SFAS No. 109,
"Accounting for Income Taxes", under which deferred income taxes are
computed using the liability method (see note (8) above under "Canadian
and United States Accounting Principles"). The company will adopt
Section 3465 for Canadian reporting purposes effective January 1, 2000
when adoption is mandatory.
The company is currently assessing the impact that adoption of the new
accounting standards referred to above will have on the company's net earnings
and financial position. It is expected, however, that adoption of the Employee
Future Benefits and Income Taxes accounting standards will have an unfavourable
impact on the company's 2000 net earnings. Implementation of these accounting
standards will not affect the company's cash flow or liquidity.
9
<PAGE>
EXHIBIT 2
<PAGE>
Management's Statement on
Financial Reporting
The financial statements on pages 42 to 62
which consolidate the financial results of Suncor Energy Inc., its subsidiaries
and joint ventures, and all information in this annual report, are the
responsibility of management.
The financial statements have been prepared in accordance with Canadian
generally accepted accounting principles. They include some amounts which are
based on estimates and judgments relating to matters not concluded by year-end.
Financial information presented elsewhere in this annual report is consistent
with that in the financial statements.
In management's opinion the financial statements have been properly prepared
within reasonable limits of materiality and within the framework of the
accounting policies summarized on pages 42 to 44. In meeting its
responsibilities for the integrity of the financial statements, management
maintains a system of internal controls and an internal audit program.
Management also administers a program of proper business conduct compliance.
PricewaterhouseCoopers LLP, the company's independent auditors, have audited
the accompanying financial statements. Their report accompanies this statement.
The Audit Committee of the Board of Directors, composed of five independent
directors, meets regularly with management, the internal auditors and
PricewaterhouseCoopers LLP to review their activities and to discuss auditing,
management information systems, internal control, accounting policy and
financial reporting matters. The Audit Committee also meets quarterly to review
interim financial statements prior to their release. The internal auditors and
PricewaterhouseCoopers LLP have unrestricted access to the company, the Audit
Committee and the Board of Directors. The Audit Committee reviews the financial
statements and Management's Discussion and Analysis and recommends their
approval to the Board of Directors.
/s/ Richard L. George /s/ Michael W. O'Brien
Richard L. George Michael W. O'Brien
President and Chief Financial Officer
Chief Executive Officer
January 20, 2000
Auditors' Report
To the Shareholders of Suncor Energy Inc.
We have audited the consolidated balance sheets of Suncor Energy Inc. as at
December 31, 1999, 1998 and 1997 and the consolidated statements of earnings,
cash flows and changes in shareholders' equity for each of the years then ended.
These financial statements are the responsibility of the company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in Canada. Those standards require that we plan and perform an audit to
obtain reasonable assurance whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation.
In our opinion, these consolidated financial statements present fairly, in
all material respects, the financial position of the company as at December 31,
1999, 1998 and 1997 and the results of its operations and cash flows for each of
the years then ended in accordance with accounting principles generally accepted
in Canada.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
January 20, 2000
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 41
<PAGE>
Summary of Significant Accounting Policies
Suncor Energy Inc. is an integrated oil and gas company, whose three operating
segments are Oil Sands, Exploration and Production and Sunoco.
Oil Sands includes the production of light sweet and light sour crude oil,
diesel fuel and various custom blends from oil sands mined in the Athabasca
region of northeastern Alberta, and the marketing of these products in Canada
and the United States.
Exploration and Production includes the exploration, acquisition,
development, production, marketing and transportation of crude oil and natural
gas in Canada and the marketing of natural gas in Canada and the United States.
Sunoco includes the manufacture, transportation and marketing of petroleum
and petrochemical products, primarily in Ontario and Quebec, and, commencing in
1997, the marketing of natural gas in Ontario. Petrochemical products are also
sold in the United States and Europe.
The company is also in the commissioning phase of an oil shale project in
Queensland, Australia, which is currently being treated as a Corporate project
for segmented reporting purposes. Commercial production from this first phase is
expected to commence in 2000, at which time the oil shale operation will be a
separate foreign geographic segment.
The significant accounting policies of the company are summarized below:
(a) PRINCIPLES OF CONSOLIDATION AND THE PREPARATION OF FINANCIAL STATEMENTS
These consolidated financial statements are prepared and reported in Canadian
dollars in accordance with Canadian generally accepted accounting principles
(GAAP), which differ in some respects from GAAP in the United States. The
significant differences in GAAP, as applicable to these consolidated financial
statements and notes, are described in the company's Form 40-F report, which is
filed with the United States Securities and Exchange Commission and is available
on request.
The consolidated financial statements include the accounts of Suncor Energy
Inc. and its subsidiaries and the company's proportionate share of the assets,
liabilities, revenues, expenses and cash flows of its joint ventures.
The timely preparation of financial statements in conformity with generally
accepted accounting principles requires that management make estimates and
assumptions, and use judgment, regarding certain types of assets, liabilities,
revenues and expenses. Such estimates primarily relate to unsettled transactions
and events as of the date of the financial statements. Accordingly, actual
results may differ from estimated amounts as future confirming events occur.
(b) CASH EQUIVALENTS AND INVESTMENTS
The company considers all highly liquid investments with a remaining maturity of
three months or less at the time of purchase to be cash equivalents. These cash
equivalents consist primarily of term deposits and certificates of deposit.
Investments with maturities from greater than three months to one year are
classified as short-term investments, while those with maturities in excess of
one year are classified as long-term investments. Cash equivalents and
short-term investments are stated at cost, which approximates market value.
(c) REVENUES
The company deems production from its oil sands plant, excluding diesel sales
and synthetic crude oil sales under long-term agreements, as well as its
conventional crude oil production to be used first for internal refinery
consumption. The company also deems a portion of its natural gas production to
be sold to Sunoco for resale to its natural gas customers. Therefore, on
consolidation, revenues from these deemed sales are eliminated from sales and
other operating revenues and purchases of crude oil and products.
The company also uses a portion of its natural gas production for internal
consumption at its oil sands plant and refinery. On consolidation, revenues from
these sales are eliminated from sales and other operating revenues and
operating, selling and general expenses.
(d) CAPITAL ASSETS
Capital assets are recorded at cost less accumulated provisions for
depreciation, depletion and amortization. Capital assets are reviewed for
impairment whenever events or conditions indicate that their net carrying amount
may not be recoverable from estimated future cash flows.
The company follows the successful efforts method of accounting for its crude
oil and natural gas operations. Under the successful efforts method, acquisition
costs of proved and unproved properties are capitalized. Costs of unproved
properties are transferred to proved properties when proved reserves are
confirmed. Exploration costs, including geological and geophysical costs, are
expensed as incurred. Exploratory drilling costs are capitalized initially. If
it is determined that the well does not contain proved reserves, the capitalized
exploratory drilling costs are charged to expense, as dry hole costs, at that
time. The related land costs are expensed through the amortization of unproved
properties as covered under the Exploration and Production section of the
following policy.
Development costs, which include the costs of wellhead equipment, development
drilling costs, gas plants and handling facilities, applicable geological and
geophysical costs and the costs of acquiring or constructing support facilities
and equipment are capitalized. Costs incurred to operate and maintain wells and
equipment and to lift oil and gas to the surface are expensed.
Costs specifically related to the construction and development of major
projects such as the oil sands projects and the Stuart oil shale project are
capitalized. Depreciation commences when the facilities are substantially
complete and ready for commercial production to begin.
(e) DEPRECIATION, DEPLETION AND AMORTIZATION
OIL SANDS
Capital assets are depreciated over their useful lives, except for lease
acquisition costs and certain mine assets, which are
42 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
depreciated over the life of proved reserves. Depreciation over useful lives
is on a straight line basis. Depreciation over the life of proved reserves is
on a unit of production basis.
The company is depreciating capital assets as follows:
(i) mobile equipment over 3 to 15 years;
(ii) mine equipment and acquisition costs of original operating Leases #86
and #17 over approximately 36 million barrels of proved reserves;
(iii) plant and other capital assets primarily over 10 to 40 years.
EXPLORATION AND PRODUCTION
Unproved properties whose acquisition costs are individually significant are
evaluated for impairment by management. Impairment of unproved properties whose
acquisition costs are not individually significant is provided for through
amortization of the portion not expected to become producing, based on
historical experience, over the average projected holding period.
Acquisition costs of proved properties are depleted using the unit of
production method based on proved reserves. Capitalized exploratory drilling
costs and development costs are depleted on the basis of proved developed
reserves. For purposes of the depletion calculation, production and reserves
volumes for oil and natural gas are converted to a common unit of measure on the
basis of their approximate relative energy content. Gas plants, support
facilities and equipment are depreciated on a straight line basis over their
useful lives, which average 13 years.
SUNOCO
Depreciation of capital assets is on a straight line basis over their useful
lives. The refinery and additions thereto are depreciated over an average of 30
years, service stations and related equipment over an average of 20 years and
other facilities and equipment over 3 to 25 years.
(f) DISPOSALS
Gains or losses on disposals of capital assets are generally recognized in
earnings. For oil and gas capital assets, gains or losses are recognized in
earnings for significant disposals or disposal of an entire property. However,
the acquisition cost of an unproved property surrendered or abandoned which is
not individually significant or a partial abandonment of a proved property is
charged to accumulated depreciation, depletion or amortization, as appropriate.
(g) DEFERRED CHARGES
Overburden removal costs incurred to expose oil sands and oil shale for mining,
including depreciation on overburden removal equipment where applicable, are
deferred. These costs are amortized based on the amount of oil sands and oil
shale mined in the year, the ratio of total overburden to be removed to total
reserves of oil sands and oil shale to be mined and the removal cost, determined
on a last-in, first-out (LIFO) basis, per unit of overburden.
The cost of major maintenance shutdowns is deferred and amortized on a
straight line basis over the period to the next shutdown which varies from two
to seven years. Normal maintenance and repair costs are charged to expense as
incurred.
Oil sands preproduction costs are amortized on a unit of production basis
over the life of proved producing reserves.
(h) RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS
Reclamation and environmental remediation costs for identified sites are
estimated and charged against earnings when there exists a regulatory or
statutory requirement or contractual agreement, or when management has made a
decision to decommission or restore a site, providing that assessments indicate
that such costs are probable and reasonably estimable.
Estimated reclamation costs in the company's upstream operations are accrued
on the unit of production basis. Estimated environmental remediation costs,
which are predominantly in the company's downstream operation, are accrued for
those sites where assessments indicate that such work is required.
Costs are accrued based upon currently known information, estimated timing of
remedial actions, and existing requirements and technology. Changes in these
factors may result in material changes to estimated costs, which will be
recognized prospectively when known.
(i) EMPLOYEE FUTURE BENEFITS
PENSION EXPENSE
The company has a defined benefit pension plan, under which employees do not
make contributions (non-contributory), and a defined contribution pension plan
providing retirement benefits for its eligible employees. The company also has
supplementary non-contributory defined benefit pension plans providing
additional retirement benefits for its executives and senior employees.
Pension expense related to the defined benefit plans includes the current
service costs, interest costs and the amortization of adjustments arising from
plan amendments, changes in assumptions and experience gains and losses over the
expected average remaining service life of the employees. This expense reflects
management's estimates of the pension plans' expected investment yield, salary
escalation, mortality of members, terminations and the ages at which members
will retire. Company contributions to the defined contribution plan are expensed
as incurred.
OTHER POST-RETIREMENT BENEFITS
The company provides certain health care and life insurance benefits for its
retired employees and eligible surviving dependants. Costs of these benefits are
charged to earnings as payments are made by the company on behalf of retirees
and dependants.
New recommendations on employee future benefits, approved in 1998 by the
Accounting Standards Board of the Canadian Institute of Chartered Accountants
will be adopted effective January 1, 2000.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 43
<PAGE>
(j) INCOME TAXES
By law, some costs and revenues may be deducted from or added to earnings in the
calculation of taxable income in years earlier or later than the year that they
are actually recorded in the consolidated statements of earnings. The income
taxes in the consolidated statements of earnings are based upon the revenues and
expenses actually recorded but differ from taxes actually paid or payable. The
cumulative effect of these differences is shown in the consolidated balance
sheets as "deferred income taxes".
New recommendations issued in 1997 by the Accounting Standards Board of the
Canadian Institute of Chartered Accountants will be adopted effective January 1,
2000.
(k) INVENTORIES
Inventories of crude oil and refined products are valued at the lower of cost
using the last-in, first-out (LIFO) method and net realizable value.
Materials and supplies are valued at the lower of average cost and net
realizable value.
(l) DERIVATIVE FINANCIAL INSTRUMENTS
The company periodically enters into derivative financial instrument contracts
such as forwards, futures and swaps to hedge against the potential adverse
impact of market prices for its petroleum and natural gas products and to
protect its Canadian dollar income and cash flows against adverse foreign
currency exchange movements. The company also periodically enters into
derivative financial instrument contracts such as interest rate swaps when there
is an opportunity to lower the cost of borrowed funds. The company does not use
derivative financial instruments involving multipliers or leverage.
Derivative contracts are initiated within the guidelines of the company's
risk management policies, which require stringent authorities for approval and
commitment of contracts, designation of the contracts by management as hedges of
the related transactions, and monitoring of the effectiveness of such contracts
in reducing the related risks. Contract maturities are consistent with the
settlement dates of the related hedged transactions.
Derivative contracts accounted for as hedges are not recognized in the
consolidated balance sheets. Gains or losses on these contracts are recognized
in earnings and cash flows when the related sales revenue, interest expense and
cash flows are recognized.
Gains or losses resulting from changes in the fair value of derivative
contracts not accounted for as hedges are recognized in earnings and cash flows.
(m) INTEREST CAPITALIZATION
Interest costs relating to the construction and pre-operating stages of major
development projects and to the portion of non-producing oil and gas properties
expected to become producing are capitalized as part of the cost of such capital
assets.
(n) FOREIGN CURRENCY TRANSLATION
Monetary assets and liabilities in foreign currencies are translated to Canadian
dollars at rates of exchange in effect at the end of the period. Other assets
and related depreciation, depletion and amortization, other liabilities,
revenues and expenses are translated at rates of exchange in effect at the
respective transaction dates. The resulting exchange gains and losses are
included in earnings, except for unrealized exchange gains and losses arising on
translation of long-term liabilities with fixed or ascertainable lives. These
gains and losses are deferred and amortized over the remaining terms of the
liabilities.
The company's oil shale project in Australia is integrated with the company's
other activities and is translated in the manner described above.
(o) STOCK-BASED COMPENSATION PLANS
Under the company's Executive Stock Plan and Employee Stock Option Program,
common share options are granted to certain executives, senior employees and
non-employee directors. The company does not recognize compensation expense on
the issuance of common share options under these programs because the exercise
price of the share options is equal to the market value of the common shares at
the date of grant.
The company has established long-term employee incentive plans which provide
awards to certain senior executives and employees based on the market price of
the company's common shares and achievement of certain performance measurement
criteria relating to the company's business segments. These awards vest on April
1, 2002 and are payable at that time, generally in equal amounts of cash and
common shares of the company. The estimated costs of the cash portion of these
awards, based on share price and expected performance achievement, are recorded
as compensation expense over the vesting period. Changes in the share price, up
or down, will change the compensation expense. Such changes will be recognized
prospectively when they occur.
The company has also established a directors' compensation plan whereby
directors of the company may elect to receive half or all of their annual
remuneration as directors in common share equivalents referred to as Deferred
Share Units (DSU). The estimated costs of directors' compensation in the form of
DSU, based on share price, are recorded as compensation expense annually.
44 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statements of Earnings for the years ended December 31
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
($ millions) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES
Sales and other operating revenues (notes 2 and 4) 2 383 2 068 2 148
Interest 4 2 6
- -------------------------------------------------------------------------------------------------------------------
2 387 2 070 2 154
- -------------------------------------------------------------------------------------------------------------------
EXPENSES
Purchases of crude oil and products 519 366 429
Operating, selling and general (note 10) 750 682 705
Exploration (note 2) 40 40 50
Royalties (note 1) 99 78 80
Taxes other than income taxes (note 2) 334 325 312
Depreciation, depletion and amortization 318 264 234
Gain on disposal of assets (34) (6) (9)
Interest (note 2) 26 24 13
- -------------------------------------------------------------------------------------------------------------------
2 052 1 773 1 814
- -------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES 335 297 340
- -------------------------------------------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES (note 3)
Current
Income taxes on earnings 29 (3) 16
Income tax refund -- (16) (11)
- -------------------------------------------------------------------------------------------------------------------
29 (19) 5
- -------------------------------------------------------------------------------------------------------------------
Deferred
Income taxes on earnings 106 123 112
Income tax refund -- 5 --
- -------------------------------------------------------------------------------------------------------------------
106 128 112
135 109 117
- -------------------------------------------------------------------------------------------------------------------
NET EARNINGS 200 188 223
Dividends on preferred securities (note 13) (22) -- --
- -------------------------------------------------------------------------------------------------------------------
Net earnings attributable to common shareholders 178 188 223
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
PER COMMON SHARE (dollars) (note 14)
Net earnings 1.81 1.70 2.04
Dividends on preferred securities (0.20) -- --
- -------------------------------------------------------------------------------------------------------------------
Net earnings attributable to common shareholders
Basic 1.61 1.70 2.04
Diluted 1.60 1.70 2.02
- -------------------------------------------------------------------------------------------------------------------
Cash Dividends 0.68 0.688 0.68
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying summary of accounting policies and notes
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 45
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets as at December 31
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
($ millions) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents 5 26 13
Accounts receivable (notes 2 and 4) 291 190 267
Income taxes recoverable -- 10 --
Inventories (note 5) 161 175 159
- -------------------------------------------------------------------------------------------------------------------
Total current assets 457 401 439
Capital assets, net (note 6) 4 528 3 504 2 817
Deferred charges and other (note 7) 191 199 201
- -------------------------------------------------------------------------------------------------------------------
Total assets 5 176 4 104 3 457
- -------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term borrowings 32 16 36
Accounts payable 277 125 179
Accrued liabilities (notes 10 and 11) 339 169 229
Income taxes 15 -- 10
Taxes other than income taxes 46 59 53
Current portion of long-term borrowings (note 8) 1 1 6
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 710 370 513
- -------------------------------------------------------------------------------------------------------------------
Long-term borrowings (notes 8 and 9) 1 306 1 298 767
Accrued liabilities and other (note 10) 179 161 166
Deferred income taxes 839 756 610
Commitments and contingencies (note 12)
SHAREHOLDERS' EQUITY
Preferred securities (note 13) 514 -- --
Share capital (note 14) 524 518 513
Retained earnings 1 104 1 001 888
- -------------------------------------------------------------------------------------------------------------------
Total shareholders` equity 2 142 1 519 1 401
- -------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity 5 176 4 104 3 457
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying summary of accounting policies and notes.
Approved on behalf of the Board:
/s/ R. L. George /s/ R. W. Korthals
R. L. George, Director R. W. Korthals, Director
46 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statements of Cash Flows for the years ended December 31
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
($ millions) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Cash flow provided from operations (1), (2) 591 580 575
Decrease (increase) in operating working capital
Accounts receivable (note 2) (101) 77 25
Inventories 14 (16) (12)
Accounts payable and accrued liabilities 322 (114) (21)
Taxes payable 12 (14) 14
- -------------------------------------------------------------------------------------------------------------------
CASH PROVIDED FROM OPERATING ACTIVITIES 838 513 581
- -------------------------------------------------------------------------------------------------------------------
CASH USED IN INVESTING ACTIVITIES (2) (1 290) (937) (884)
- -------------------------------------------------------------------------------------------------------------------
NET CASH DEFICIENCY BEFORE FINANCING ACTIVITIES (452) (424) (303)
- -------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Increase (decrease) in short-term borrowings 16 (20) 12
Issuance of preferred securities (note 13) 507 -- --
Stuart oil shale project borrowings 11 49 22
Issuance of medium term notes -- -- 400
Repayment of commercial paper borrowings (note 13) (507) -- --
Repayment of 12% debentures, Series A -- (55) (5)
Net increase (decrease) in other long-term borrowings 510 533 (45)
Issuance of common shares under stock option plan (note 14) 6 5 5
Dividends paid on preferred securities (3) (note 13) (37) -- --
Dividends paid on common shares (75) (75) (74)
- -------------------------------------------------------------------------------------------------------------------
CASH PROVIDED FROM FINANCING ACTIVITIES 431 437 315
- -------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (21) 13 12
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 26 13 1
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR 5 26 13
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
PER COMMON SHARE (dollars) (note 14)
(1) Cash flow provided from operations 5.36 5.27 5.24
(3) Dividends paid on preferred securities (pre-tax) (0.34) -- --
- -------------------------------------------------------------------------------------------------------------------
Cash flow provided from operations
after deducting dividends paid on preferred securities 5.02 5.27 5.24
- -------------------------------------------------------------------------------------------------------------------
(2) See Schedules of Segmented Data on pages 50 and 51.
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying summary of accounting policies and notes.
Consolidated Statements of Changes
in Shareholders' Equity
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Preferred Share Retained
($ millions) Securities Capital Earnings
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
AT DECEMBER 31, 1996 -- 508 739
Net earnings -- -- 223
Dividends paid -- -- (74)
Issued for cash under stock option plan -- 5 --
- -------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1997 -- 513 888
Net earnings -- -- 188
Dividends paid -- -- (75)
Issued for cash under stock option plan -- 4 --
Issued under dividend reinvestment plan -- 1 --
- -------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1998 -- 518 1 001
Net earnings -- -- 200
Dividends paid -- -- (97)
Issuance of preferred securities (note 13) 514 -- --
Issued for cash under stock option plan -- 6 --
- -------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1999 514 524 1 104
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying summary of accounting policies and notes.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 47
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
Schedules of Segmented Data for the years ended December 31
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Oil Sands Exploration and Production Sunoco
($ millions) 1999 1998 1997 1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EARNINGS
REVENUES**
Sales and other
operating revenues 461 421 281 143 114 194 1 779 1 533 1 673
Intersegment revenues*** 428 347 470 163 176 108 -- -- --
Interest -- -- -- -- -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------
889 768 751 306 290 302 1 779 1 533 1 673
- -------------------------------------------------------------------------------------------------------------------
EXPENSES
Purchases of crude oil and products 6 10 -- -- -- -- 1 090 845 988
Operating, selling and general 357 333 334 85 84 87 264 258 269
Exploration -- -- -- 40 40 50 -- -- --
Royalties 51 43 31 48 35 49 -- -- --
Taxes other than income taxes 9 7 8 5 5 4 320 313 300
Depreciation, depletion
and amortization 177 128 109 87 84 74 53 51 51
(Gain) loss on disposal of assets 2 (1) (2) (36) (5) (9) -- -- 2
Interest -- -- -- -- -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------
602 520 480 229 243 255 1 727 1 467 1 610
- -------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE
INCOME TAXES 287 248 271 77 47 47 52 66 63
Income taxes (113) (98) (92) (34) (22) (23) (21) (26) (24)
- -------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS) 174 150 179 43 25 24 31 40 39
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
As at December 31
TOTAL ASSETS 3 178 2 081 1 689 962 943 819 849 874 908
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
CAPITAL EMPLOYED**** 1 371 1 254 543 730 774 658 413 503 500
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
CAPITAL EMPLOYED (%)**** 13.2 16.7 33.0 5.7 3.5 4.0 6.8 7.9 7.9
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
* The company currently has no foreign geographic segments. See note 2 for
information on export sales. Accounting policies for segments are the same as
those described in the Summary of Significant Accounting Policies.
** One customer in the Oil Sands segment in 1999 represented 10% or more of the
company's 1999 consolidated revenues. There were none in 1998 and 1997.
*** Intersegment revenues are recorded at prevailing fair market prices and
accounted for as if the sales were to third parties.
**** Capital Employed - the total of shareholders' equity and debt (short-term
borrowings and current and long-term portions of long-term borrowings), less
capitalized costs related to major projects in progress. Long-term borrowings
are recorded mainly in the Corporate segment.
See accompanying summary of accounting policies and notes.
48 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Corporate and Eliminations Total
($ millions) 1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
EARNINGS
REVENUES**
Sales and other
operating revenues -- -- -- 2 383 2 068 2 148
Intersegment revenues*** (591) (523) (578) -- -- --
Interest 4 2 6 4 2 6
- -------------------------------------------------------------------------------------------------------------------
(587) (521) (572) 2 387 2 070 2 154
- -------------------------------------------------------------------------------------------------------------------
EXPENSES
Purchases of crude oil and products (577) (489) (559) 519 366 429
Operating, selling and general 44 7 15 750 682 705
Exploration -- -- -- 40 40 50
Royalties -- -- -- 99 78 80
Taxes other than income taxes -- -- -- 334 325 312
Depreciation, depletion
and amortization 1 1 -- 318 264 234
(Gain) loss on disposal of assets -- -- -- (34) (6) (9)
Interest 26 24 13 26 24 13
- -------------------------------------------------------------------------------------------------------------------
(506) (457) (531) 2 052 1 773 1 814
- -------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE
INCOME TAXES (81) (64) (41) 335 297 340
Income taxes 33 37 22 (135) (109) (117)
- -------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS) (48) (27) (19) 200 188 223
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
As at December 31
TOTAL ASSETS 187 206 41 5 176 4 104 3 457
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
CAPITAL EMPLOYED**** (117) (70) (90) 2 397 2 461 1 611
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
RETURN ON AVERAGE
CAPITAL EMPLOYED (%)****
8.8 9.9 14.8
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 49
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
Schedules of Segmented Data* for the years ended December 31
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Oil Sands Exploration and Production Sunoco
($ millions) 1999 1998 1997 1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CASH FLOW BEFORE
FINANCING ACTIVITIES
CASH PROVIDED FROM (USED IN)
OPERATING ACTIVITIES:
Cash flow provided from
(used in) operations
Net earnings (loss) 174 150 179 43 25 24 31 40 39
Exploration expenses
Cash -- -- -- 12 16 25 -- -- --
Dry hole costs -- -- -- 28 24 25 -- -- --
Non-cash items included
in earnings
Depreciation, depletion
and amortization 177 128 109 87 84 74 53 51 51
Deferred income taxes 107 79 85 32 15 10 (31) 15 5
Current income tax provision
allocated to Corporate 6 19 7 2 7 13 52 11 19
(Gain) loss on disposal of assets 2 (1) (2) (36) (5) (9) -- -- 2
Other (12) (12) (9) 3 1 -- (3) (4) (5)
Overburden removal outlays (53) (46) (34) -- -- -- -- -- --
Increase (decrease) in
deferred credits and other 4 3 (4) 1 -- -- 1 (1) 10
- -------------------------------------------------------------------------------------------------------------------
Total cash flow
provided from
(used in) operations 405 320 331 172 167 162 103 112 121
Decrease (increase)
in operating
working capital 83 (8) 33 27 (13) (2) 69 7 (36)
- -------------------------------------------------------------------------------------------------------------------
Total cash provided from
(used in) operating
activities 488 312 364 199 154 160 172 119 85
- -------------------------------------------------------------------------------------------------------------------
CASH USED IN INVESTING
ACTIVITIES:
Capital and exploration
expenditures (1 057) (507) (491) (200) (242) (240) (42) (60) (54)
Deferred maintenance
shutdown expenditures (22) (7) (36) -- (1) 1 -- (2) --
Deferred outlays and
other investments (7) (1) (6) -- 1 -- (2) (3) (1)
Proceeds from disposals 1 1 2 90 9 13 1 1 --
- -------------------------------------------------------------------------------------------------------------------
Total cash used in
investing activities (1 085) (514) (531) (110) (233) (226) (43) (64) (55)
- -------------------------------------------------------------------------------------------------------------------
NET CASH SURPLUS
(DEFICIENCY) BEFORE
FINANCING ACTIVITIES (597) (202) (167) 89 (79) (66) 129 55 30
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
* The company currently has no foreign geographic segments. See note 2 for
information on export sales. Accounting policies for segments are the same as
those described in the Summary of Significant Accounting Policies.
See accompanying summary of accounting policies and notes.
50 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Corporate and Eliminations Total
($ millions) 1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
CASH FLOW BEFORE
FINANCING ACTIVITIES
CASH PROVIDED FROM (USED IN)
OPERATING ACTIVITIES:
Cash flow provided from
(used in) operations
Net earnings (loss) (48) (27) (19) 200 188 223
Exploration expenses
Cash -- -- -- 12 16 25
Dry hole costs -- -- -- 28 24 25
Non-cash items included
in earnings
Depreciation, depletion
and amortization 1 1 -- 318 264 234
Deferred income taxes (2) 19 12 106 128 112
Current income tax provision
allocated to Corporate (60) (37) (39) -- -- --
(Gain) loss on disposal of assets -- -- -- (34) (6) (9)
Other 1 2 2 (11) (13) (12)
Overburden removal outlays -- -- -- (53) (46) (34)
Increase (decrease) in
deferred credits and other 19 23 5 25 25 11
- -------------------------------------------------------------------------------------------------------------------
Total cash flow
provided from
(used in) operations (89) (19) (39) 591 580 575
Decrease (increase)
in operating
working capital 68 (53) 11 247 (67) 6
- -------------------------------------------------------------------------------------------------------------------
Total cash provided from
(used in) operating
activities (21) (72) (28) 838 513 581
- -------------------------------------------------------------------------------------------------------------------
CASH USED IN INVESTING
ACTIVITIES:
Capital and exploration
expenditures (51) (127) (62) (1 350) (936) (847)
Deferred maintenance
shutdown expenditures -- -- -- (22) (10) (35)
Deferred outlays and
other investments (1) 1 (10) (10) (2) (17)
Proceeds from disposals -- -- -- 92 11 15
- -------------------------------------------------------------------------------------------------------------------
Total cash used in
investing activities (52) (126) (72) (1 290) (937) (884)
- -------------------------------------------------------------------------------------------------------------------
NET CASH SURPLUS
(DEFICIENCY) BEFORE
FINANCING ACTIVITIES (73) (198) (100) (452) (424) (303)
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 51
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Notes to the Consolidated Financial Statements
1. ROYALTIES
Alberta Crown royalties totalling $7 million (1998 - $5 million; 1997 - $9
million) were paid in kind, and are not shown in the company's revenues and
expenses.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
-------------------------------------------------------------------------
($ millions) Crown Other Total Crown Other Total Crown Other Total
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
[GRAPH]
- ------------------------------------------------------------------------------------------------------------------------------
Oil Sands 48 3 51 35 8 43 8 23 31
- ------------------------------------------------------------------------------------------------------------------------------
Exploration & Production 40 8 48 28 7 35 41 8 49
- ------------------------------------------------------------------------------------------------------------------------------
Total 88 11 99 63 15 78 49 31 80
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* Lower 1997 Oil Sands Crown royalties reflect the realization of an
environmental royalty credit from the Government of Alberta in the
amount of $31 million. The program for claiming this credit ended
at the end of 1997.
2. SUPPLEMENTAL INFORMATION
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
<S> <C> <C> <C>
- -------------------------------------------------------------------------------------------------------------------------------
Export sales (1) 233 231 292
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Exploration expenses
Geological and geophysical 10 14 23
Other 2 2 2
- -------------------------------------------------------------------------------------------------------------------------------
Cash costs 12 16 25
Dry hole costs 28 24 25
- -------------------------------------------------------------------------------------------------------------------------------
Cash and dry hole costs (2) 40 40 50
Leasehold impairment (3) 12 10 7
- -------------------------------------------------------------------------------------------------------------------------------
52 50 57
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Taxes other than income taxes
Excise taxes (4) 311 305 292
Production, property
and other taxes 23 20 20
- -------------------------------------------------------------------------------------------------------------------------------
334 325 312
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Interest expense
Long-term interest cost 71 67 38
Less interest capitalized (45) (43) (25)
- -------------------------------------------------------------------------------------------------------------------------------
26 24 13
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Cash interest payments 63 64 28
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Allowance for
doubtful accounts 3 3 3
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
During 1999, the company put in place a securitization program to sell, on an
ongoing basis, up to $83 million of accounts receivable, on a limited recourse
basis, to a third party. As at December 31, 1999, $83 million in accounts
receivable had been sold under the program.
On December 31, 1998, the company sold, on a limited recourse basis,
approximately $50 million in accounts receivable to third parties.
The company's potential exposure to credit loss under the recourse provisions is
not material.
(1) Sales of mainly petrochemicals, natural gas and diesel to customers in the
United States and petrochemicals in Europe.
(2) Exploration expenses in the Consolidated Statements of Earnings.
(3) Included in depreciation, depletion and amortization in the Consolidated
Statements of Earnings.
(4) Excise taxes are also included in sales and other operating revenues in the
Consolidated Statements of Earnings.
52 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. INCOME TAXES
The provision for income taxes reflects an effective tax rate which differs from
the statutory tax rate. A reconciliation of the two rates and the dollar effect
is as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
($ millions) AMOUNT % Amount % Amount %
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Federal tax rate 127 38 113 38 130 38
Provincial abatement (34) (10) (30) (10) (34) (10)
Federal surtax 4 1 3 1 4 1
Provincial tax rates 52 16 48 16 53 16
- -------------------------------------------------------------------------------------------------------------------------------
STATUTORY TAX AND RATE 149 45 134 45 153 45
Add (deduct) the tax effect of:
Crown royalties (see note 1) 44 13 31 11 27 8
Resource allowance (56) (17) (49) (16) (54) (16)
Large corporations tax 10 3 9 3 5 1
Income tax refund* -- -- (11) (4) (11) (3)
Other (12) (4) (5) (2) (3) (1)
- -------------------------------------------------------------------------------------------------------------------------------
INCOME TAXES AND EFFECTIVE RATE 135 40 109 37 117 34
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
1999 income tax payments totalled $5 million (1998 - net refund of $19 million;
1997 - net refund of $10 million).
* During 1998, settlements were reached with Canada Customs and Revenue Agency
(formerly Revenue Canada) on a number of taxation issues resulting in refunds
totalling $34 million, $11 million of which were reflected in 1997 net
earnings ($0.10 per common share). The impact of the refund in 1998 is to
increase net earnings by $11 million ($0.10 per common share) reflecting a
reduction of prior years income taxes of $5 million and taxable interest of
$6 million (after a provision for income taxes of $5 million).
4. RELATED PARTY TRANSACTIONS
The following table summarizes the company's related party transactions for the
year and balances at the end of the year. These transactions are in the normal
course of operations and have been carried out on the same terms as would apply
with unrelated parties.
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
- -----------------------------------------------------------------
<S> <C> <C> <C>
Revenues
Sales to Sunoco
joint ventures:
Refined products 395 309 353
Petrochemicals 108 85 90
- -----------------------------------------------------------------
At the end of the year,
amounts due from related
parties are as follows:
Sunoco joint ventures 45 41 49
- -----------------------------------------------------------------
- -----------------------------------------------------------------
</TABLE>
Sales to and balances with Sunoco joint ventures are exchange amounts
established and agreed to by the related parties, before application of the
proportionate consolidation method of accounting.
The company has exclusive supply agreements with two Sunoco joint ventures
for the sale of refined products. One agreement expires in 2002, after which the
company will continue to be the exclusive supplier of refined products as long
as it remains a shareholder. The company plans to maintain its relationship with
this joint venture. The other agreement expires in 2003 and will be
automatically renewed thereafter for one year terms until terminated upon twelve
months prior written notice. No notice has been given by either party.
The company also has a non-exclusive supply agreement with a Sunoco joint
venture for the sale of petrochemicals. The agreement is automatically renewed
on an annual basis until it is terminated by either party upon twelve months
written notice. No notice has been given by either party.
5. INVENTORIES
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
- -----------------------------------------------------------------
<S> <C> <C> <C>
[GRAPH]
- -----------------------------------------------------------------
/ / Crude oil 47 58 63
/ / Refined products 67 62 54
/ / Materials and supplies 47 55 42
Total 161 175 159
- -----------------------------------------------------------------
</TABLE>
The replacement cost at December 31, 1999 of all inventories valued at LIFO
exceeded their carrying value by $37 million (1998 - nil; 1997 - $7 million).
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 53
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. CAPITAL ASSETS
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
ACCUMULATED Accumulated Accumulated
($ millions) COST PROVISION Cost Provision Cost Provision
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Oil Sands
Plant 1 598 485 1 461 449 1 106 410
Mine and mobile equipment 850 243 828 191 330 158
Plant expansion* -- -- -- -- 267 --
Steepbank Mine* -- -- -- -- 238 --
Project Millennium**
Production enhancement phase 172 2 87 -- 17 --
Millennium expansion 905 -- 99 -- 16 --
- ------------------------------------------------------------------------------------------------------------------------------
3 525 730 2 475 640 1 974 568
- ------------------------------------------------------------------------------------------------------------------------------
Exploration and Production
Proved properties 1 190 487 1 242 506 1 093 450
Unproved properties 344 171 288 169 263 166
Pipeline 22 18 22 18 21 17
Other support facilities and equipment 19 12 18 10 15 9
- ------------------------------------------------------------------------------------------------------------------------------
1 575 688 1 570 703 1 392 642
- ------------------------------------------------------------------------------------------------------------------------------
Sunoco
Refinery 740 350 724 327 701 304
Marketing and transportation 380 165 362 148 337 137
- ------------------------------------------------------------------------------------------------------------------------------
1 120 515 1 086 475 1 038 441
- ------------------------------------------------------------------------------------------------------------------------------
Corporate
Stuart oil shale project** 237 -- 187 -- 61 --
Other 7 3 6 2 5 2
- ------------------------------------------------------------------------------------------------------------------------------
244 3 193 2 66 2
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
6 464 1 936 5 324 1 820 4 470 1 653
Net capital assets 4 528 3 504 2 817
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Interest capitalized during 1999 totalled $45 million (1998 - $43 million; 1997
- - $25 million).
* During the fourth quarter of 1998, plant expansion and Steepbank Mine assets
were put into service. At that time, costs associated with these projects
were transferred to Plant assets and Mine and mobile equipment, and
depreciation of these costs commenced.
** The depreciation and depletion of costs related to these major projects will
begin when the facilities are substantially complete and ready for commercial
production to begin.
7. DEFERRED CHARGES AND OTHER
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Oil sands overburden removal costs (see below) 85 95 86
Oil sands preproduction costs 8 9 11
Deferred maintenance shutdown costs 45 44 52
Investments* 8 8 8
Goodwill** 13 14 14
Other 32 29 30
- ------------------------------------------------------------------------------------------------------------------------------
191 199 201
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Oil sands overburden removal costs
Balance - beginning of year 95 86 80
Outlays during year 53 46 34
Depreciation on equipment during year 6 2 3
- ------------------------------------------------------------------------------------------------------------------------------
154 134 117
Amortization during year (69) (39) (31)
- ------------------------------------------------------------------------------------------------------------------------------
Balance - end of year 85 95 86
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* Includes investments in partly paid Restricted Class Shares of the Australian
joint venture participants in the Stuart oil shale project, Central Pacific
Minerals NL (CPM) and Southern Pacific Petroleum NL (SPP), in 1997 totalling
$4 million. These investments are accounted for on the cost basis. They
convey to the company 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. This amount may change
in the future as foreign exchange rates change. The balance owing is payable
within six months of the project becoming fully operational. If Suncor does
not pay the balance owing, its Restricted Class Shares would be forfeited and
the investment of $4 million charged to expense. Ownership of these shares
would represent approximately a 14% interest in CPM and SPP as at December
31, 1999. The Restricted Class Shares would automatically convert into an
equal number of common shares in June 2004, or earlier in certain
circumstances.
The market value of these common shares at December 31,1999, based on quoted
market prices, was approximately $222 million (1998 - $157 million; 1997 -
$245 million). It is uncertain, however, whether the quoted market prices
would be fully realized upon any future sale of these shares.
** The company's proportionate share of goodwill of its Sunoco joint ventures is
being amortized to earnings on a straight line basis over 40 years, subject
to annual review for impairment.
54 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
8. LONG-TERM BORROWINGS
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
FIXED RATE BORROWINGS
Medium Term Notes, maturing in 2007. Interest payable semi-annually* 400 400 400
7.4% Debentures, Series C, maturing in 2004. Redeemable at any time,
at the company's option** 125 125 125
Borrowings under or with support of lines of credit converted to fixed rate
obligations by interest rate swap transactions, maturing in 2003.
Interest payable quarterly at rates averaging 5.6%*** 110 110 --
12% Debentures, Series A, maturing in 2003. Repayable at the rate of
$5 million annually, redeemable at any time, at the company's option**** -- -- 55
Stuart oil shale project borrowings with interest at 7.75%.
Australian $87 million. Principal and interest repayable from project
net cash flows (note 12 (b) ) 82 71 22
Sunoco joint venture borrowings with interest at rates averaging 7.6% at
December 31, 1999 (1998 - 7.1%; 1997 - 7.2%) 5 5 6
- ------------------------------------------------------------------------------------------------------------
722 711 608
Less current portion of fixed rate long-term borrowings 1 1 6
- ------------------------------------------------------------------------------------------------------------
721 710 602
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
VARIABLE RATE BORROWINGS*****
Borrowings with interest at variable rates averaging
5.2% at December 31, 1999 (1998 - 5.3%; 1997 - 4.3%)
under or with support of lines of credit 585 588 165
- ------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM BORROWINGS 1 306 1 298 767
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
</TABLE>
* During 1997, the company issued $400 million of medium term notes, $250
million in the first quarter at an interest rate of 6.8%, and $150 million
in the third quarter at an interest rate of 6.1%. The money received was
used to repay short-term promissory notes and borrowings under the
company's lines of credit.
** During 1996, the company entered into a cross-currency interest rate swap
transaction to convert its 7.4% Debentures to a 6.2% fixed interest rate
U.S. dollar obligation of approximately $91 million. Also in 1996, the
company entered into another cross-currency interest rate swap transaction
to convert the U.S. $91 million obligation back to a fixed rate Canadian
$125 million obligation. Both contracts will remain in place for the term
of the debenture. The net effect of the two swap transactions is to reduce
the effective interest rate on the debentures from 7.3% (7.4% coupon rate)
to 5.5%. The principal obligation remains unchanged.
*** During 1998, the company entered into interest rate swap transactions to
convert $50 million and $60 million of variable rate borrowings to fixed
interest rate obligations at 5.5% and 5.7%, respectively.
**** During 1998, the company exercised its option to redeem the remaining $50
million of 12% Debentures, Series A outstanding after a $5 million sinking
fund redemption on the same date. The purpose of the early redemption was
to replace the debenture with lower interest rate financing.
***** During 1999, the company entered into a cross-currency interest rate swap
transaction to convert U.S. $183 million of variable rate borrowings with
interest based on 90 day LIBOR to Canadian $278 million with interest
based on 90 day bankers acceptances.
LONG TERM BORROWING
<TABLE>
<CAPTION>
- ------------------------------------------------------------
(percentages) 1999 1998 1997
- ------------------------------------------------------------
<S> <C> <C> <C>
[GRAPH]
- ------------------------------------------------------------
/ / Variable rate 45 45 22
- ------------------------------------------------------------
/ / Fixed rate 55 55 78
- ------------------------------------------------------------
</TABLE>
Principal repayments of long-term borrowings in each of the next five years
are as follows:
<TABLE>
($ millions)
- -------------------------------------------------------
<S> <C>
2000 6
2001 4
2002 4
2003 374
2004 458
- -------------------------------------------------------
</TABLE>
Principal repayments for the period 2000 to 2004 include $22 million of
Stuart oil shale project borrowings estimated to be repayable from project
net cash flows. Actual amounts repayable and the timing of repayments could
differ from those estimates.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 55
<PAGE>
9. LINES OF CREDIT
At December 31, 1999, the company had available $1 926 million in credit and
term loan facilities, of which $328 million had been drawn, as follows:
- - A facility for $600 million which is fully revolving for 364 days, has a term
period of three years and expires in 2003.
- - A facility for U.S. $183 million (Cdn $278 million) which is non-revolving,
has been fully drawn and expires in 2004.
- - A facility for $1 018 million which is fully revolving for six years and
expires in 2004.
- - Uncommitted facilities totalling $30 million, which can be terminated at any
time at the option of the lenders.
The company is also authorized, supported by unutilized credit and term loan
facilities, to issue commercial paper to a maximum of $600 million having a term
not to exceed 364 days. At December 31, 1999, the company had $367 million in
commercial paper outstanding.
These credit facilities are subject to commitment fees, the amounts of which
are not material.
10. ACCRUED LIABILITIES AND OTHER
<TABLE>
<CAPTION>
- ------------------------------------------------------------
($ millions) 1999 1998 1997
- ------------------------------------------------------------
<S> <C> <C> <C>
[GRAPH]
- ------------------------------------------------------------
/ / Reclamation and environmental
remediation costs (a) 86 87 90
- ------------------------------------------------------------
/ / Pension costs (see note 12) 39 50 61
- ------------------------------------------------------------
/ / Other (b) 54 24 15
- ------------------------------------------------------------
Total 179 161 166
- ------------------------------------------------------------
</TABLE>
(a) RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS
Total accrued reclamation and environmental remediation costs also include
$13 million in current liabilities (1998 - $14 million; 1997 - $13 million).
Payments during 1999 totalled $13 million (1998 - $11 million; 1997 - $18
million).
The estimate of remaining reclamation costs for the company's oil sands
operation is $525 million for its current mining operation and its Project
Millennium. $79 million has been accrued at December 31, 1999. The remaining
$446 million will be accrued over future years on a unit of production basis.
Factors such as inflation and changes in technology and proved reserves may
materially change the cost estimate.
The exploration and production segment's reclamation and environmental
remediation cost estimate decreased in 1999 from $64 million to $57 million,
reflecting the divestment of non-strategic properties. $27 million has been
accrued to December 31, 1999. The remaining $30 million will be accrued over
future years on a unit of production basis.
(b) EMPLOYEE INCENTIVE PLANS
In 1997, the company established the following long-term employee incentive
plans.
The Special Performance Incentive Plan (SPIP) provides awards of Special
Performance Units (SPU) for senior executives of the company. These awards,
granted on April 1, 1997, will vest on April 1, 2002. The number of SPU that
will vest at that date is based on the value at April 1, 2002, assuming
reinvestment of dividends, of a notional $100 investment in common shares of
the company at the grant date. A maximum of 790,000 SPU will vest if the
value of the notional investment doubles to $200. No SPU will vest if the
value of the notional investment is $150 or lower. Vested SPU entitle the
holder to receive either an equivalent number of common shares of the
company, half the value of which will be paid in cash and the other half in
common shares purchased by the company in the open market, or an equivalent
number of Deferred Share Units (DSU), which are equal in value to SPU. Of the
790,000 DSU available, executives have elected to receive 721,500.These
executives will be required to hold DSU as long as they remain with the
company, and will receive additional DSU equivalent in value to future
notional dividend reinvestments. Upon the retirement, death or employment
termination of the holder, DSU will be paid in cash, based on the value at
that time of an equivalent number of common shares of the company.
The Incremental Value Payout Program (IVPP) component of the Employee
Long-Term Incentive Plan (ELTIP) provides incentive awards, payable on April
1, 2002, mainly to those employees of the company who are not eligible for
SPIP or the Employee Stock Option Program component of the ELTIP (see note
14(b)). One half of the award is based on the average market price of the
company's common shares during the twelve weeks prior to April 1, 2002. The
other half of the award is based on achievement of certain performance
measurement criteria relating to the company's business segments. No award is
payable if the market price of the company's common shares is lower than $54.
The awards will be paid in equal amounts of cash and common shares of the
company.
In 2001, projected cash awards will reduce cash flow provided from
operations as long-term liabilities are transferred to current liabilities in
anticipation of cash payments in 2002. At December 31, 1999, 790,000 SPU were
earned under the SPIP. The resulting 1999 impact was a charge to expense of
$21 million (1998 - $4 million; 1997 - $2 million), and a decrease in net
earnings of $13 million or $0.12 per common share (1998 - $3 million or $0.03
per common share; 1997 -$1 million or $0.01 per common share). The 1999
impact of the IVPP was a charge to expense of $5 million and a decrease in
net earnings of $3 million or $0.03 per common share (1998 and 1997 - nil).
(c) DIRECTORS' COMPENSATION PLAN
In 1999, the company established the Directors' Deferred Share Unit Plan.
Under this plan, non-employee directors of the company may elect annually to
receive their compensation as
56 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
directors for that year in cash, in equal amounts of cash and Deferred Share
Units (DSU), or entirely in DSU. The value of one DSU is the market value of
one common share of the company. DSU are payable in cash upon the retirement
as director or death of the holder. The 1999 impact of this plan on net
earnings was not material.
11. PENSION COSTS AND OBLIGATIONS
The company's pension plans include defined benefit plans under which
employees do not make contributions, and which provide a pension benefit at
retirement based upon years of service and final average earnings.
The company also has a defined contribution plan, under which both the
company and employees make contributions. Company contributions are based on
employees' earnings and contributions.
DEFINED BENEFIT PENSION PLANS
These pension plans consist of a funded plan which covers most employees, and
unfunded supplementary benefit plans which primarily provide supplemental
retirement benefits to executives and senior employees. Under the funded
plan, the company makes contributions to an independent trustee to cover
pension payment obligations to retired employees. The trustee acts as the
depository for contributions, the disbursing agent and custodian of the
pension plan's assets. These assets are managed by a pension fund investment
committee, on behalf of the beneficiaries, which retains independent
investment managers and advisors. Pension plan assets are not the company's
assets and therefore are not included in the consolidated balance sheets.
Company contributions to the funded pension plan as well as the present
value of pension benefit obligations and current period pension expense are
determined by an independent actuary based on the following actuarial
assumptions and management's estimates, and in accordance with regulatory
requirements.
ASSUMPTIONS AND ESTIMATES
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
(percentage) 1999 1998 1997
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
[GRAPH]
- -----------------------------------------------------------------------------
/ / Discount rate 7.25 8.0 8.0
- -----------------------------------------------------------------------------
/ / Long-term rate of return
on plan assets 7.25 8.0 8.0
- -----------------------------------------------------------------------------
/ / Rate of compensation
increase 4.25 4.5 4.5
- -----------------------------------------------------------------------------
</TABLE>
The following funded status table identifies the present value of the net
unfunded obligation, which is the amount by which pension plan obligations
exceed the market value of plan assets available to satisfy these obligations at
December 31:
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
- ---------------------------------------------------------------------
<S> <C> <C> <C>
Pension benefit obligations:
Funded plan 308 259 247
Unfunded supplementary plans 51 44 40
- ---------------------------------------------------------------------
Total obligations 359 303 287
Less market value of plan assets* 316 278 250
- ---------------------------------------------------------------------
Net unfunded obligation 43 25 37
- ---------------------------------------------------------------------
</TABLE>
* Assets in the company's pension plan consist of marketable equity securities,
government and corporate bonds and short-term notes.
The above net unfunded obligation is reflected as a liability in the
company's balance sheet before recognition of the unamortized asset
determined at January 1, 1987, the transition date, and other unamortized
plan gains and losses, which represent annually calculated differences
between actual and projected plan performance. These actuarial
charges/credits to earnings, which are already reflected in the net unfunded
obligation, are recorded over the expected average remaining service life of
employees, which is currently 13 years (1998 and 1997 - 13 years).
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
- ---------------------------------------------------------------
<S> <C> <C> <C>
Pension liability* 47 58 69
Unamortized transitional asset (13) (20) (26)
Unamortized net (gain) loss 9 (13) (6)
- ---------------------------------------------------------------
Net unfunded obligation 43 25 37
- ---------------------------------------------------------------
- ---------------------------------------------------------------
* Current portion 8 8 8
Long-term portion 39 50 61
- ---------------------------------------------------------------
47 58 69
- ---------------------------------------------------------------
- ---------------------------------------------------------------
Company contributions
to funded plan 15 14 13
- ---------------------------------------------------------------
- ---------------------------------------------------------------
</TABLE>
PENSION EXPENSE
<TABLE>
<CAPTION>
- ------------------------------------------------------------
($ millions) 1999 1998 1997
- ------------------------------------------------------------
<S> <C> <C> <C>
[GRAPH]
- ------------------------------------------------------------
/ / Defined benefit plan 5 5 6
- ------------------------------------------------------------
/ / Defined contribution plan 4 3 3
- ------------------------------------------------------------
Total 9 8 9
- ------------------------------------------------------------
</TABLE>
12. COMMITMENTS AND CONTINGENCIES
(a) OPERATING COMMITMENTS
In order to ensure continued availability of, and access to, facilities and
services to meet its operational requirements, the company enters into
non-cancellable operating leases for service stations, office space and other
property and equipment, as well as transportation service agreements for
pipeline capacity and an energy services agreement. Under contracts existing
at December 31, 1999, future minimum amounts payable under these leases and
agreements are as follows:
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 57
<PAGE>
<TABLE>
<CAPTION>
Pipeline capacity Operating
($ millions) and energy services* leases
- -----------------------------------------------------------------------
<S> <C> <C>
2000 64 33
2001 97 29
2002 111 24
2003 112 20
2004 112 17
Later years 3 274 91
- -----------------------------------------------------------------------
3 770 214
- -----------------------------------------------------------------------
</TABLE>
* Includes annual tolls payable under a transportation service agreement
with a major pipeline company to use a portion of its pipeline capacity
and tankage for the shipment, commencing in 1999 and extending to 2028, of
crude oil from Fort McMurray to Hardisty, Alberta. As the initial shipper
on the pipeline, Suncor's annual tolls payable under the agreement could
be subject to annual adjustments.
A major energy company is in the process of building a cogeneration
facility at the oil sands site with expected completion during the first
quarter of 2001. Under long-term energy agreements, Suncor has a
commitment to obtain a portion of the power and all of the steam generated
by this facility to meet the energy needs of its oil sands operation.
Effective October 1999, this company also commenced managing the
operations of Suncor's existing energy services facility.
(b) CAPITAL EXPENDITURE COMMITMENTS AND CONTINGENCIES
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 Central Pacific Minerals
NL and Southern Pacific Petroleum NL (see note 7), and the project financing
liability would be written off. The impact on future earnings, should this
occur, is currently estimated to be $55 million to $65 million.
At December 31, 1999, the company had outstanding commitments of $402 million
for capital expenditures on Project Millennium.
(c) UNCERTAINTY DUE TO THE YEAR 2000 ISSUE
The Year 2000 Issue arises because many computerized systems use two digits
rather than four to identify a year. Date-sensitive systems may recognize the
year 2000 as 1900 or some other date, resulting in errors when information using
year 2000 dates is processed. In addition, similar problems may arise in some
systems which use certain dates in 1999 to represent something other than a
date. The effects of the Year 2000 Issue may be experienced before, on, or after
January 1, 2000, and, if not addressed, the impact on operations and financial
reporting may range from minor errors to significant systems failures which
could affect the company's ability to conduct normal business operations. It is
not possible to be certain that all aspects of the Year 2000 Issue affecting the
company, including those related to the efforts of customers, suppliers, or
other third parties, will be fully resolved.
(d) CONTINGENCIES
The company is subject to various regulatory and statutory requirements relating
to the protection of the environment. These requirements, in addition to
contractual agreements and management decisions, result in the accrual of
estimated reclamation and environmental remediation costs. These costs are
accrued at the company's exploration and production and oil sands operations on
the unit of production basis. Estimated environmental remediation costs at
service stations are also accrued upon completion of site investigations. These
costs are reduced by any estimated gains likely to be realized on a sale of
these sites. Any changes in these estimates will affect future earnings.
Under the company's business interruption insurance coverage, the company
would bear the first $70 million of any loss arising from a future insured
incident at its oil sands operations.
The company is defendant and plaintiff in a number of legal actions that
arise in the normal course of business.
Costs attributable to these commitments and contingencies are expected to be
incurred over an extended period of time and to be funded mainly from the
company's cash provided from operating activities. Although the ultimate impact
of these matters on net earnings cannot be determined at this time, it could be
material for any one quarter or year. The company believes that any liabilities
which might arise pertaining to such matters would not be expected to have a
material effect on the company's consolidated financial position.
13. PREFERRED SECURITIES
During 1999, the company completed a Canadian offering of $276 million of 9.05%
preferred securities and a U.S. offering of U.S. $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 $7 million).
The preferred securities are unsecured junior subordinated debentures, due in
2048 and redeemable at the company's option on or after March 15, 2004. Subject
to certain conditions, the company has the right to defer payment of interest on
the securities for up to 20 consecutive quarterly periods. Deferred interest and
principal amounts are payable in cash, or, at the option of the company, from
the proceeds on the sale of equity securities of the company delivered to the
trustee of the preferred securities. Accordingly, the preferred securities are
classified as share capital in the consolidated balance sheet and the interest
distributions thereon, net of income taxes, are classified as dividends.
Proceeds from the offerings were used to repay commercial paper borrowings.
58 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
14. SHARE CAPITAL
(a) AUTHORIZED:
COMMON SHARES
The company is authorized to issue an unlimited number of common shares
without nominal or par value.
PREFERRED SHARES
The company is authorized to issue an unlimited number of preferred shares
without nominal or par value in series.
(b) ISSUED:
The number of common shares and common share options outstanding, common
share prices and per share calculations, for both current and prior periods,
reflect a two-for-one split of the company's common shares during 1997.
<TABLE>
<CAPTION>
Common Shares
($ millions) Number Amount
- --------------------------------------------------------------------
<S> <C> <C>
Balance as at
December 31, 1996 109 573 672 508
Issued for cash under
stock option plan 326 138 5
Issued under dividend
reinvestment plan 6 823 --
- --------------------------------------------------------------------
Balance as at
December 31, 1997 109 906 633 513
Issued for cash under
stock option plan 297 465 4
Issued under dividend
reinvestment plan 12 730 1
- --------------------------------------------------------------------
Balance as at
December 31, 1998 110 216 828 518
Issued for cash under
stock option plan 293 925 6
Issued under dividend
reinvestment plan 5 366 --
- --------------------------------------------------------------------
Balance as at
December 31, 1999 110 516 119 524
- --------------------------------------------------------------------
- --------------------------------------------------------------------
</TABLE>
COMMON SHARE OPTIONS
(i) EXECUTIVE STOCK PLAN
Under this plan, the company has granted common share options to non-employee
directors and certain executives of the company and its subsidiaries. The
exercise price of an option is equal to the market value of the common shares
at the date of grant. Options granted to non-employee directors are
exercisable immediately. Options granted to employees are exercisable as
follows: one-third after one year, the second third after two years and the
final third after three years of the grant date. No option may be exercisable
more than 10 years after the grant date.
(ii) EMPLOYEE STOCK OPTION PROGRAM
Under this component of the ELTIP, the company granted 621110 common share
options to certain executives and senior employees. The exercise price for
these grants was equal to or greater than the market value of the common
shares at the grant date. Options are exercisable on April 1, 2002, one half
on a time basis and the other half based on achievement of certain
performance measurement criteria.
The following tables cover common share options granted by the company:
<TABLE>
<CAPTION>
Exercise price per share
Weighted
(dollars) Number Range Average
- --------------------------------------------------------------------------
<S> <C> <C> <C>
Outstanding,
December 31, 1996 1 778 468 9.50-25.60 17.03
Granted 1 181 570 31.07-52.15 41.72
Exercised (326 138) 9.50-21.09 13.77
Cancelled (35 609) 16.44-31.07 25.64
- --------------------------------------------------------------------------
Outstanding,
December 31, 1997 2 598 291 9.50-52.15 28.54
Granted 446 518 49.10-52.75 49.31
Exercised (297 489) 9.50-31.38 14.50
Cancelled (48 701) 21.09-52.15 42.76
- --------------------------------------------------------------------------
Outstanding,
December 31, 1998 2 698 619 9.50-52.75 33.27
Granted 545 228 40.50-60.35 41.39
Exercised (291 520) 9.50-49.10 19.51
Cancelled (23 334) 31.07-52.15 51.45
- --------------------------------------------------------------------------
Outstanding,
December 31, 1999 2 928 993 9.50-60.35 36.01
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
Exercisable,
December 31
1997 923 543 9.50-31.38 16.58
- --------------------------------------------------------------------------
1998 1 133 437 9.50-52.15 20.88
- --------------------------------------------------------------------------
1999 1 304 908 9.50-53.95 25.78
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
</TABLE>
AVAILABLE FOR GRANT, DECEMBER 31
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
(number of common shares) 1999 1998 1997
- --------------------------------------------------------------------------
<S> <C> <C> <C>
[GRAPH]
- --------------------------------------------------------------------------
3 538 234 4 060 129 4 457 945
- --------------------------------------------------------------------------
</TABLE>
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 59
<PAGE>
The following table is an analysis of outstanding and exercisable common
share options as at December 31, 1999:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
OUTSTANDING EXERCISABLE
Weighted Weighted Weighted
Average Remaining Average Exercise Average Exercise
Exercise Price Number Contractual Life Price Per Share Number Price Per Share
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$ 9.50 - $10.79 45 678 3 9.89 45 678 9.89
$15.18 - $15.66 85 510 4 15.61 85 510 15.61
$16.44 - $20.88 298 791 5 16.83 298 791 16.83
$21.09 - $25.60 458 616 6 22.11 358 616 21.13
$31.07 - $31.38 512 098 7 31.09 344 761 31.10
$40.50 - $60.35 1 528 300 8 47.50 171 552 49.71
- --------------------------------------------------------------------------------------------------
TOTAL 2 928 993 7 36.01 1 304 908 25.78
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
</TABLE>
(iii) FAIR VALUE OF OPTIONS GRANTED
The weighted average fair value of common share options granted in 1999 is
$14.01 per share (1998 - $18.09 per share; 1997 - $11.33 per share). The fair
value of common share options granted is estimated as at the grant date using
the Black-Scholes option-pricing model, using the following assumptions:
<TABLE>
<CAPTION>
1999 1998 1997
- ---------------------------------------------------------------
<S> <C> <C> <C>
Dividend $0.68/ $0.68/ $0.68/
share share share
Risk-free interest rate 4.89% 5.31% 5.69%
Expected life 7 years 7 years 7 years
Expected volatility 32% 32% 20%
- ---------------------------------------------------------------
</TABLE>
15. FINANCIAL INSTRUMENTS
(a) BALANCE SHEET FINANCIAL INSTRUMENTS
The company's financial instruments recognized in the consolidated balance
sheets consist of cash and cash equivalents, accounts receivable, investments
in CPM and SPP, substantially all current liabilities and long-term
borrowings.
The estimated fair values of recognized financial instruments have been
determined based on the company's assessment of available market information
and appropriate valuation methodologies; however, these estimates may not
necessarily be indicative of the amounts that could be realized or settled in
a current market transaction.
The fair values of cash and cash equivalents, accounts receivable and
current liabilities approximate their carrying amounts due to the short-term
maturity of these instruments.
The fair value of the company's investment in the shares of CPM and SPP is
not determinable. Information about the terms, conditions and characteristics
of these investments is presented in note 7.
The following table summarizes estimated fair value information about the
company's long-term borrowings at December 31:
<TABLE>
<CAPTION>
1999 1998 1997
Carrying Fair Carrying Fair Carrying Fair
($ millions) amount value amount value amount value
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Long-term borrowings
- fixed rate 525 516 525 548 575 595
- variable rate 695 695 698 698 165 165
- Sunoco joint ventures 4 4 4 4 5 5
- Stuart oil shale
project 82 82 71 71 22 22
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
</TABLE>
The fair value of the company's fixed rate long-term borrowings, which are
publicly traded, is based on quoted market prices. The fair value of the
company's variable-rate long-term borrowings, proportionate share of the
long-term borrowings of its Sunoco joint ventures, and the Stuart oil shale
project borrowings approximates the carrying amount.
(b) DERIVATIVE FINANCIAL INSTRUMENTS
The company is also a party to certain derivative financial instruments which
are not recognized in the consolidated balance sheets, as follows:
REVENUE HEDGES
The company enters into crude oil, natural gas and foreign currency swap
contracts to protect its future Canadian dollar earnings and cash flows from
the potential adverse impact of low petroleum and natural gas prices and an
unfavourable U.S./Canadian dollar exchange rate. The swap contracts reduce
fluctuations in sales revenues by locking in fixed prices and exchange rates
on the portion of its sales covered by the contracts. While the swap
contracts reduce the risk of exposure to adverse changes in commodity prices
and exchange rates, they also reduce the potential benefit of favourable
changes in commodity prices and exchange rates.
60 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
The swap contracts do not require the payment of premiums or cash margin
deposits prior to settlement. On settlement, these contracts result in cash
receipts (payments) by the company for the difference between the contract
and market rates for the applicable dollars and volumes hedged during the
contract term. Such cash receipts (payments) offset corresponding decreases
(increases) in the company's sales revenues. For accounting purposes, amounts
received (paid) on settlement are recorded as part of the related hedged
sales transactions.
Contracts outstanding at December 31 were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
CONTRACT AMOUNTS
($ millions except Average price* Revenue hedged
for average price) Quantity $ Canadian $ Canadian Hedge period
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
AS AT DECEMBER 31, 1999
Crude oil swaps* 52 655 bbl/day 26 503 2000
9 845 bbl/day 19(a) 67(a) 2000
35 000 bbl/day 26 327 2001
4 000 bbl/day 26 38 2002
U.S. dollar swaps U.S.$81 1.41 114 2001
U.S.$289 1.41 408 2002
- --------------------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 1998
Crude oil swaps* 23 700 bbl/day 28 242 1999
6 000 bbl/day 28 61 2000
Natural gas swaps* 2 mmcf/day 2.75 2 1999
U.S. dollar swaps U.S.$115 1.39 160 1999
U.S.$274 1.39 381 2000
U.S.$312 1.41 440 2001
U.S.$314 1.42 446 2002
- --------------------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 1997
Crude oil swaps* 31 500 bbl/day 28 325 1998
23 700 bbl/day 28 241 1999
6 000 bbl/day 28 60 2000
Natural gas swaps* 19 mmcf/day 1.87 13 1998
U.S. dollar swaps U.S.$15 1.43 21 1998
U.S.$98 1.39 136 1999
U.S.$159 1.37 218 2000
U.S.$100 1.39 139 2001
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
* Average price for crude oil swaps is WTI per barrel at Cushing, Oklahoma.
Average price for natural gas swaps is dollars per thousand cubic feet.
(a) Average price and revenue hedged is in U.S. dollars.
INTEREST RATE HEDGES
The company enters into interest rate and cross-currency interest rate swap
contracts when there is an opportunity to lower the cost of borrowed funds.
The interest rate swap contracts involve an exchange of floating rate and
fixed rate interest payments between the company and a financial institution.
The cross-currency swap contracts involve an exchange of Canadian dollar
interest payments and U.S. dollar interest payments between the company and a
financial institution, and an exchange of Canadian and U.S. dollar principal
amounts at the maturity date of the underlying borrowing to which the swaps
relate. The swap transactions are completely independent from and have no
direct effect on the relationship between the company and its lenders. The
differentials on the exchange of periodic interest payments are recognized in
the accounts as an adjustment to interest expense.
The notional amounts of interest rate and cross-currency interest rate
swap contracts outstanding at December 31, 1999 are detailed in note 8,
Long-Term Borrowings.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 61
<PAGE>
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS
The fair value of these hedging derivative financial instruments is the
estimated amount, based on brokers' quotes, that the company would receive
(pay) to terminate the contracts. Such amounts, which also represent the
unrecognized and unrecorded gain (loss) on the contracts, were as follows at
December 31:
<TABLE>
<CAPTION>
($ millions) 1999 1998 1997
- ----------------------------------------------------------
<S> <C> <C> <C>
Crude oil swaps (136) 77 40
U.S. dollar swaps (1) (108) (9)
Natural gas swaps -- -- (1)
Australian dollar forwards -- -- (6)
Interest rate and cross-currency
interest rate swaps -- 10 13
- ----------------------------------------------------------
(137) (21) 37
- ----------------------------------------------------------
- ----------------------------------------------------------
Unrecognized gain
exposed to credit risk
as at December 31, 1999 2
- ---------------------------------------
</TABLE>
The company may be exposed to certain losses in the event that other
parties to the financial instruments are unable to meet the terms of the
contracts. The company's exposure is generally limited to those other parties
holding contracts with net unrecognized gains at the reporting date. The
company, however, minimizes this risk by entering into agreements only with
highly rated financial institutions, and through regular management review of
potential exposure to, and credit ratings of, such financial institutions.
16. RECENTLY ISSUED ACCOUNTING STANDARDS
In March 1999, the Accounting Standards Board of the Canadian Institute of
Chartered Accountants (CICA) issued new recommendations for the recognition,
measurement and disclosure of the cost of employee future benefits. The
company will adopt the new recommendations, effective January 1, 2000, in a
manner that produces recognized and unrecognized amounts for all of its
benefit plans the same as those determined by the application of accounting
principles generally accepted in the United States. Adoption will result in
the recognition of a liability and an expense for all employee future
benefits in the reporting period in which an employee has provided the
service that gives rise to the benefits.
In December 1997, the Accounting Standards Board of the CICA issued new
recommendations dealing with accounting for income taxes. This standard
requires the use of the liability method for computing deferred income taxes.
Under current rules, deferred income taxes are computed using the deferred
method. The company will adopt the new recommendations effective January 1,
2000.
These new standards issued by the CICA serve to harmonize Canadian and
U.S. generally accepted accounting principles in respect to employee future
benefits and income taxes.
62 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
EXHIBIT 3
<PAGE>
PREFERRED SECURITIES
See note 13 to the financial statements
HEDGING
Companies use derivatives to hedge or counteract possible fluctuations in the
price of commodities or interest rates. This permits mitigation of price or
interest rate risk due to market fluctuations.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW***
Suncor Energy Inc.'s corporate centre is located in Calgary, Alberta. The
company is currently comprised of three operating businesses: an oil sands
operation (Oil Sands); a conventional oil and gas business (Exploration and
Production - E&P); and a refining and marketing operation (Sunoco).
In 2000, Suncor established an In-situ and International Oil development
unit, which includes the Stuart Oil Shale Development Project in Australia and
the company's recently announced Firebag in-situ project 40 kilometres from Fort
McMurray.
1999 - EARNINGS INCREASED 6%
Earnings in 1999 increased 6% to $200 million ($1.61 per common share), from
$188 million ($1.70 per common share) in 1998. Cash flow from operations was
$591 million ($5.02 per common share), representing the seventh consecutive year
of cash flow growth. Cash flow from operations in 1998 was $580 million ($5.27
per common share). Revenue in 1999 was $2.4 billion compared with $2.1 billion
in 1998. Per share amounts for earnings and cash flow from operations in 1999
reflect payments on the PREFERRED SECURITIES issued in 1999.
The increase in consolidated earnings was primarily the result of higher
crude oil prices in the last three quarters of 1999, higher natural gas prices,
record Oil Sands sales volumes, gains on asset sales and improved retail
margins. The impact of these positive factors was partially offset by crude oil
and natural gas HEDGING losses ($56 million in 1999 compared to gains of $47
million in 1998), increased costs, lower conventional oil and gas production,
lower refining earnings due to higher crude oil and feedstock costs and higher
taxes. Cash flow from operations increased only slightly, despite the earnings
increase, because the cash associated with gains on disposal of assets ($92
million in 1999; $11 million in 1998) is not included in cash flow from
operations. The cash associated with gains on divested assets is reported as a
reduction in cash used in investing activities. 1998 cash flow from operations
of $580 million included $34 million in income tax refunds. There was no such
benefit in 1999.
CONSOLIDATED FINANCIAL RESULTS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
($ millions) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Earnings 200 188 223
Cash flow provided from operations 591 580 575
Investing activities 1 290 937 884
Dividends - common shares 75 75 74
- preferred securities 37 0 0
Long-term borrowings 1 306 1 298 767
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
20 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
RELATIVE SEGMENT CONTRIBUTION
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
(before the impact of corporate and elimination adjustments,
expressed as %) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS
Oil Sands 70 70 74
Exploration and Production 17 11 10
Sunoco 13 19 16
CASH FLOW PROVIDED FROM OPERATIONS
Oil Sands 60 53 54
Exploration and Production 25 28 26
Sunoco 15 19 20
CAPITAL EMPLOYED
Oil Sands 55 53 48
Exploration and Production 29 28 29
Sunoco 16 19 23
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
INDUSTRY INDICATORS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
(average for the year unless otherwise noted) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
West Texas Intermediate (WTI) crude oil U.S.$/barrel at Cushing 19.30 14.40 20.60
Canadian 0.3% par crude C$/barrel at Edmonton 27.50 20.45 27.80
Light/sour crude oil price differential C$/barrel at Edmonton 2.80 3.20 3.45
Natural gas U.S.$/thousand cubic feet at Henry Hub 2.27 2.14 2.55
Natural gas (Alberta spot) C $/thousand cubic feet at Empress 3.00 2.25 1.95
Natural gas exports to the U.S. trillions of cubic feet 3.2* 3.1 2.9
New York Harbour 3-2-1 crack U.S.$ barrel** 2.47 2.85 4.09
Refined product demand (Ontario/Quebec) percentage
change over prior year 1.5* 4.2 2.0
Exchange rate: C$ : U.S.$ 0.67 0.67 0.72
Exchange rate: C$ : Australian$ 1.04 1.07 0.97
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
* Estimate
** New York Harbour 3-2-1 crack is an industry indicator measuring the margin on
a barrel of oil for gasoline and distillate. It is calculated by taking 2
times the New York Harbour gasoline margin plus 1 times the New York Harbour
distillate margin and dividing by 3.
***The tables and charts in this document form an integral part of Management's
Discussion and Analysis and should be referred to when reading the narrative.
References to Suncor or the company include Suncor Energy Inc. and its
subsidiaries and investment in joint ventures, unless otherwise stated.
Management's Discussion and Analysis contains certain forward-looking
statements which are based on Suncor's current expectations, estimates,
projections and assumptions and were made by the company in light of its
experience and its perception of historical trends. All statements that
address expectations or projections about the future, including statements
about Suncor's strategy for growth, expected expenditures, commodity prices,
costs, schedules and production volumes, operating or financial results, are
forward-looking statements. Some of the forward-looking statements may be
identified by words like "expects," "anticipates," "plans," "intends,"
"believes," "projects," "indicates," "could" and similar expressions. These
statements are not guarantees of future performance and involve a number of
risks, uncertainties and assumptions. Suncor's business is subject to risks
and uncertainties, some of which are similar to other oil and gas companies
and some of which are unique to Suncor. Suncor's actual results may differ
materially from those expressed or implied by its forward-looking statements
as a result of known and unknown risks, uncertainties and other factors. The
risks, uncertainties and other factors that could influence actual results
include: changes in the general economic, market and business conditions;
fluctuations in supply and demand for Suncor's products; fluctuations in
commodity prices; fluctuations in exchange rates; Suncor's ability to respond
to changing markets; the ability of Suncor to receive timely regulatory
approvals; the successful implementation of its growth projects, including
Project Millennium; the integrity and reliability of Suncor's capital assets;
the cumulative impact of the resource development projects; Suncor's ability
to comply with current and future environmental laws; the accuracy of
Suncor's production estimates and production levels and its success at
exploration and development drilling and related activities; the maintenance
of satisfactory relationships with unions, employee associations and joint
venturers; competitive actions of other companies, including increased
competition from other oil and gas companies or from companies which provide
alternative sources of energy; the uncertainties resulting from potential
delays or changes in plans with respect to exploration or development
projects or capital expenditures; actions by governmental authorities
including increasing taxes, changes in environmental and other regulations;
the ability and willingness of parties with whom Suncor has material
relationships to perform their obligations to Suncor; and the occurrence of
unexpected events such as fires, blowouts, freeze ups, equipment failures and
other similar events affecting Suncor or other parties whose operations or
assets directly or indirectly affect Suncor.
Many of these risk factors are discussed in further detail throughout this
Management's Discussion and Analysis and in the company's annual information
form on file with the Alberta Securities Commission and certain other
securities regulatory authorities. Readers are also referred to the risk
factors described in other documents that Suncor files from time to time with
securities regulatory authorities. Copies of these documents are available
without charge from the company.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
BITUMEN
Tar-like form of oil that cannot be produced by conventional means. When
extracted from oil sands, it can be upgraded into light sweet crude and other
products.
MAINTENANCE SHUTDOWN
Long-term preventative maintenance activities that involve shutting down major
parts of, or an entire facility.
[ MAP ]
OIL SANDS
OVERVIEW
Suncor has more than 30 years' experience in mining and upgrading oil sands to
produce crude oil on a commercial basis - more than any other company in the
world.
Suncor uses the following proven technology and processes to produce oil from
its leases in the Athabasca oil sands, near Fort McMurray, Alberta:
- - Giant trucks and shovels mine the oil sands.
- - The BITUMEN is separated from the sand in the extraction process, then
upgraded to high quality "light sweet" and "light sour" crude oil products
and diesel fuel.
- - The crude oil products are blended to customer specifications and sent by
pipeline to markets in Canada and the U.S.
The Oil Sands business also has an on-site energy plant operated by TransAlta
Energy Corporation (TransAlta) that generates steam and electricity using
petroleum coke - a byproduct of the upgrading process - and natural gas.
Suncor's top growth priority is to expand its Oil Sands business. In 1999,
Suncor received government approval for Phase 2 of the $2.2-billion Project
Millennium, which entails a staged expansion of production to an estimated
225,000 barrels per day in 2003, up from production of 105,600 barrels per day
in 1999. By the end of 1999, construction on the project was 17% complete and
detailed engineering was 79% complete.
In early 2000 Suncor announced plans to invest $750 million to further expand
its oil sands business by adding a commercial scale in-situ project and
bolstering the upgrading capacity of its Fort McMurray operation. This plan is
subject to Board of Directors and regulatory approvals.
RESULTS OF OPERATIONS AND INVESTING ACTIVITIES
1999 VS 1998
OIL SANDS - SUMMARY OF RESULTS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------
($ millions unless otherwise noted) 1999 1998 1997
- -------------------------------------------------------------------
<S> <C> <C> <C>
Revenue 889 768 751
Production
(thousands of barrels per day) 105.6 93.6 79.4
Average sales price
(including the impact of hedging)
($ per barrel) 23.84 22.18 26.36
Earnings 174 150 179
Cash flow provided
from operations 405 320 331
Total assets 3 178 2 081 1 689
Investing activities 1 085 514 531
- -------------------------------------------------------------------
</TABLE>
EARNINGS ANALYSIS
INCREASED SALES AND SELLING PRICE CONTRIBUTE TO A 16% INCREASE IN EARNINGS
Oil Sands earned $174 million in 1999 compared with $150 million in 1998. This
increase was mainly attributable to a 7.5% increase in sales volumes and a 7.5%
increase in Oil Sands crude oil price. These factors were partly offset by
higher operating costs.
Benchmark crude prices increased 34% over 1998. This increase was tempered by
a loss on Suncor's hedging program which decreased year-over-year Oil Sands
earnings by $88 million as well as an increase in pipeline costs for Oil Sands
that impacted year-over-year earnings by $15 million. The higher pipeline costs
relate to the Athabasca Pipeline, which was commissioned in April 1999 and on
which Oil Sands ships sour crude oil.
During a 28-day, $20-million planned MAINTENANCE SHUTDOWN in 1999, Oil Sands
halted production of sweet (low-sulphur) crude oil and produced only
lower-priced sour crude oil. In addition, the selling price of sour crude
declined during this period as a result of short-term market conditions.
The combined impact of the above price factors resulted in a year-over-year
increase in earnings of $46 million.
22 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1998 1999
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
EARNINGS
ANALYSIS
($ millions)
[GRAPH]
- -------------------------------------------------------------------------------
150 36 46 (10) (17) (31) 174
- -------------------------------------------------------------------------------
Total Volume Oil Price Royalties Cash Non-Cash Total
Expenses Expenses
- -------------------------------------------------------------------------------
</TABLE>
RECORD SALES VOLUMES AND HIGHER OIL PRICES, PARTLY OFFSET BY HIGHER EXPENSES,
RESULTED IN A 16% EARNINGS IMPROVEMENT.
OIL SANDS PRODUCTION INCREASES 13%
Oil Sands increased production in 1999 for the seventh consecutive year to an
average of 105,600 barrels per day from 93,600 barrels per day in 1998. This
increase was attributable to Suncor's new Steepbank Mine and fixed plant
expansion (a vacuum tower and diluent recovery unit), which had its first full
year of production in 1999.
Two unplanned outages at Oil Sands in 1999 lasted a total of 16 days and
resulted in approximately 1.8 million barrels of lost production. These outages
were precipitated by a change in feedstock resulting from the operation of the
new fixed plant expansion. Parts of the unit that failed were redesigned during
the second outage in September, with the objective of improving reliability.
Due to a build in inventory, primarily associated with filling the Athabasca
Pipeline, only 102,200 barrels per day were sold in 1999. Sales volumes in 1998
were 95,100 barrels per day. This volume increase resulted in a year-over-year
improvement in earnings of $36 million.
ROYALTIES
Crown royalties payable by Suncor to the Government of Alberta increased 39% in
1999, to $48 million, as a result of higher sales volumes and prices. The higher
Crown royalties were partly offset by a $5-million (pre-tax) decrease in
royalties paid to Union Pacific Resources Inc. ("Union"), a reduction that
occurred because Suncor mined fewer barrels in 1999 from the lease where Union
has a royalty interest. The combined impact of the above factors was a net
increase in total royalties expensed that reduced earnings by $10 million.
Crown royalties in effect for Suncor's existing Oil Sands operations
require payments to the Government of Alberta of 25% of revenues less
allowable costs (including capital
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
1998 1999
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
NET CASH DEFICIENCY
ANALYSIS
($ millions)
[GRAPH]
- ----------------------------------------------------------------------------------------------
(202) 92 (7) 91 (21) (550) (597)
- ----------------------------------------------------------------------------------------------
Total Operations Overburden Working Deferred Other Total
Capital Spending Investing
Activities
- ----------------------------------------------------------------------------------------------
</TABLE>
SUNCOR'S GROWTH PLANS FOR ITS OIL SANDS BUSINESS IS REFLECTED IN THE
$550-MILLION INCREASE IN INVESTING EXPENDITURES THAT WERE ONLY PARTIALLY
OFFSET BY THE IMPROVED CASH FLOW FROM OPERATIONS AND THE WORKING CAPITAL
REDUCTION. THE REDUCTION IN WORKING CAPITAL WAS DUE TO THE HIGH LEVEL OF
PROJECT SPENDING ACTIVITY.
expenditures), subject to a minimum payment of 5% of gross revenues. In 1999
Suncor made royalty payments based upon a 5% minimum royalty.
Suncor's transition royalty agreement with the Alberta government took effect
in 1999. 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%. The 5% rate will change to a 1% rate beginning in the third year
of the transition (2001). Suncor currently expects to remain at the 5% rate for
the year 2000 and then be at the 1% rate until the middle of this decade. This
assumption is based on expected future oil prices, production levels, operating
costs and capital expenditures.
EXPENSES INCREASE BY 16%
The increase in expenses in 1999 reduced Oil Sands' earnings by approximately
$48 million. Expenses were higher in 1999 as a result of increased costs in the
following areas:
Non-cash charges (depreciation, depletion and amortization) increased,
reducing 1999 earnings by $31 million. The increase is due to:1) changes to the
mine plan that resulted in higher overburden amortization charges; 2) an
increase in depreciation expense related to capital additions that increased
production capacity, partly offset by an extension of the useful life of some
fixed plant assets; and 3) an increase in amortization of turnaround
expenditures as a result of the 1999 planned partial maintenance shutdown.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS
OVERBURDEN WORKING CAPITAL
Material overlying the oil sands that The excess of current assets (excluding
must be removed before mining. cash) over current liabilities. The
Consists of muskeg, glacial deposits excess measures the ability of a
and sand. business to finance current operations,
for example, whether debt will need to
be incurred to fund growth activities.
* THIS SECTION CONTAINS FORWARD-
LOOKING INFORMATION. ALSO REFER TO
THE OVERVIEW*** ON PAGE 21 OF THIS
REPORT.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
1995 1996 1997 1998 1999
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
CASH AND TOTAL
OPERATING COSTS
(dollars per barrel)
[GRAPH]
- --------------------------------------------------------------------------
/ / Cash Operating Cost 12.00 12.30 13.00 11.50 11.40
- --------------------------------------------------------------------------
/ / Non-cash Operating Cost 2.55 2.40 2.55 2.25 3.35
- --------------------------------------------------------------------------
Total 14.55 14.70 15.55 13.75 14.75
- --------------------------------------------------------------------------
</TABLE>
NON-CASH COSTS INCREASED FROM THE 1998 LEVEL DUE TO HIGHER OVERBURDEN COSTS
AND INCREASED DEPRECIATION RESULTING FROM RECENT CAPITAL ADDITIONS.
Cash expenses increased, resulting in a $17-million reduction in earnings.
The drivers of the increase were caused by: 1) higher production volumes; 2)
mining and extraction operations being conducted on both sides of the Athabasca
River (original mine expected to be shut down in the 2001 / 2002 time frame);
and 3) increased natural gas prices.
PER-BARREL OPERATING COSTS INCREASE
Cash operating costs did not change significantly from 1998. Per barrel costs
were $11.40 in 1999 - the first full year of operation for the Steepbank Mine
and fixed plant expansion - compared with $11.50 in 1998.
Total operating costs per barrel in 1999 were $14.75 - against a target of
$13.85 - compared with $13.75 per barrel in 1998. (Total operating costs are
equal to the total expenses - including non-cash charges, but excluding
royalties - divided by sales volumes). The increase in total operating costs is
driven primarily by the increases in non-cash charges described above.
CASH MARGIN INCREASED 17% TO $11.10 PER BARREL IN 1999
Oil Sands' cash operating margin was $11.10 per barrel in 1999 compared with
$9.50 per barrel in 1998. The factors that influenced cash margins in the year
were: 1) higher selling prices (before hedging) had a favourable impact of $5.50
per barrel; 2) hedging gains and losses had an unfavourable net impact of $3.85
per barrel; 3) cash operating costs had a favourable impact of $0.10 per barrel;
and 4) higher royalties had an unfavourable impact of approximately $0.15 per
barrel.
NET CASH DEFICIENCY ANALYSIS
Cash flow provided from operations was $405 million in 1999 compared with
$320 million in 1998. The positive impact of improved cash margins and
increased volumes ($92 million) was partly offset by a $7-million increase in
OVERBURDEN spending.
Oil Sands had an increase in funds from WORKING CAPITAL of $91 million
relative to 1998. The increase was primarily due to a higher amount of accounts
payable related to Project Millennium. This positive factor was partially offset
by increases in accounts receivable and inventory levels.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
1995 1996 1997 1998 1999
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
OPERATING MARGINS
($ per barrel)
[GRAPH]
- --------------------------------------------------------------------------
/ / Selling Price 24.46 26.84 26.36 22.18 23.84
- --------------------------------------------------------------------------
/ / Cash Margin 10.20 11.85 12.30 9.50 11.10
- --------------------------------------------------------------------------
</TABLE>
THE INCREASE IN THE MARGIN IN 1999 PRIMARILY REFLECTS A 7% INCREASE IN THE
CRUDE OIL SELLING PRICE. THE MARGIN IMPROVEMENT OF $1.60 PER BARREL WAS
TEMPERED BY PAYMENTS ASSOCIATED WITH SUNCOR'S HEDGING PROGRAM THAT REDUCED
THE MARGIN BY $2.05 PER BARREL.
SELLING PRICE - THE AVERAGE PRICE FROM THE SALE OF CRUDE OIL, INCLUDING THE
IMPACT OF HEDGING ACTIVITIES.
CASH MARGIN - THE DIFFERENCE BETWEEN THE SELLING PRICE RECEIVED FOR PRODUCTS
SOLD, AND CASH OPERATING COST PER BARREL PLUS ROYALTIES PER BARREL.
Investing activities at Oil Sands increased from $514 million in 1998 to $1.1
billion in 1999. The increase was primarily due to spending of $891 million on
Project Millennium and planned maintenance shutdown spending increases of $15
million. The increases were partly offset by a reduction in spending on the
Steepbank Mine and fixed plant expansion.
OUTLOOK*
PHASED GROWTH
Project Millennium, currently estimated at a cost of $2.2 billion, is designed
to further increase Oil Sands' production capacity in two growth phases. The
first phase of the project - the Production Enhancement Phase (PEP) - is
expected to increase production to 130,000 barrels per day by 2001 at an
estimated cost of $190 million. The second phase is expected to increase
production to 225,000 barrels a day in 2003.
Suncor's average production goal for 2002 is 210,000 barrels per day, down
from the original target of 220,000 barrels per day. This change in the
production target is due to planned maintenance shutdown work in 2002 that was
previously scheduled for 2001. Project Millennium calls for an expanded mine,
additional mining equipment, increased energy-services support, and twinning of
the bitumen extraction and upgrading processes.
In 2000 Suncor announced a plan to further expand its oil sands facilities
beyond 2003 with a proposed investment of $750 million in an in-situ project and
further expansion of the oil sands plant. The in-situ portion of the project
would be integrated with Suncor's open pit mining operation, and, combined with
plans to expand upgrading capacity, would enable output from Suncor's plant to
reach an estimated 260,000 barrels of oil per day in 2004. These plans are
subject to Board of Directors and regulatory approval.
The company's long-term vision is to increase oil sands production to about
400,000 to 450,000 barrels of oil a day in 2008 through a combination of oil
sands mining and in-situ development.
24 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS
PROVEN AND PROBABLE RESERVES Annual estimates are made by Suncor of recoverable
bitumen reserves associated with company surface mineable oil sand leases. The
estimates are allocated between proven, probable and possible 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 per cent chance that the proved
plus probable reserve estimates will be exceeded. The bitumen estimates are
converted to synthetic crude estimates on the basis of yields currently being
obtained.
Oil Sands has recognized PROVEN AND PROBABLE RESERVES of 476 million barrels
and 2,028 million barrels, respectively, on the leases it currently has
regulatory approval to mine. Management believes that these reserves are
sufficient to support Project Millennium's planned production target of 225,000
barrels per day for a period in excess of 30 years. This does not include any
reserves for the Firebag in-situ heavy oil leases. Additional reserves will be
recorded as Suncor completes further drilling and analysis on these leases.
Prior to mining additional leases, regulatory approval must be obtained.
Accordingly, Suncor has not yet recognized as proven or probable reserves any of
the resources on these additional leases. Management believes that, assuming
estimated economies of scale and reliability improvements are achieved, Oil
Sands could reduce the cash operating cost to about $8.50 to $9.50 per barrel in
2002 from the 1999 level of $11.40 per barrel. Total operating costs, which
include cash operating costs as well as non-cash costs, are targeted to be
reduced to the $11.65 to $12.75 per barrel range from the 1999 level of $14.75
per barrel.
PROJECT MILLENNIUM
Construction of the $2-billion second phase of Project Millennium began on
schedule in the second quarter of 1999 after Suncor received Suncor Board of
Directors and regulatory approvals.
Engineering on Project Millennium is expected to be completed by mid-year
2000. The project is on track for commissioning to begin in the third quarter of
2001, with full production targeted for the year 2002.
RISK/SUCCESS FACTORS RELATED TO PROJECT MILLENNIUM
In addition to potentially volatile crude prices, there are certain risks
associated with the Project Millennium schedule, resources and costs. With
competing projects in Alberta, there will be increased demand for labour and
material and the associated risk of delay in material delivery and scheduled
completion. The project management has developed a working relationship with the
trade unions, including workshops and joint initiatives. The project schedule
has been developed with recognition of the needs of competing projects. Projects
of this magnitude can result in the final cost being higher or lower than
original estimates. Management believes in the current environment that there
are risks that Project Millennium costs could be higher than the original
estimate.
In response to Suncor's Canadian Environmental Assessment Act process for
Project Millennium, three non-governmental environmental organizations have
challenged the federal Minister of Environment's decision to declare the project
environmentally acceptable. This challenge is directed primarily at the federal
assessment process rather than the project itself. Suncor continues to work with
regulators, both provincial and federal, to ensure the project meets or exceeds
all regulatory requirements. The federal challenge is not expected to impact the
construction of Project Millennium.
LEVERAGING ALLIANCES TO SUPPORT OIL SANDS EXPANSION
In 1999, Suncor signed a long-term agreement with TransAlta whereby TransAlta
will build, own and operate a cogeneration facility that will help meet a
portion of Suncor's long-term energy needs at Oil Sands. As of October 1, 1999,
TransAlta assumed operating responsibility for Suncor's existing energy plant.
TransAlta announced plans to begin operating its new gas turbines commercially
in the first quarter of 2000, and commissioning of other cogeneration equipment
is expected to continue throughout 2000.
The April 1999 start-up of the Enbridge Athabasca Pipeline (owned by Enbridge
Pipelines (Athabasca) Inc.) expanded Oil Sands' ability to ship to new markets.
Suncor's agreement with Enbridge provides Suncor long-term pipeline access of up
to 170,000 barrels per day. The pipeline has a potential capacity of up to
550,000 barrels per day. The pipeline provides a new transportation link between
Fort McMurray and Hardisty, a major Alberta crude oil hub that connects onward
to markets in the U.S. and Eastern Canada.
The Hydrocarbon Liquids Conservation Project based on an agreement between
Suncor and Novagas Canada Limited Partnership, operating as TransCanada
Midstream (TCM), received regulatory approval in 1999. This project is designed
to extract and separate natural gas liquids and olefins from "off-gas," a
byproduct of the oil sands upgrading process. The recovered liquids and olefins
will be transported in batches via Suncor's Oil Sands Pipeline to TCM's
Redwater, Alberta fractionation facility for further processing. Management
believes the project will help to reduce sulphur dioxide emissions at Oil Sands
as well as provide additional revenue for Suncor.
In April 1999, TransCanada Pipeline Ventures Limited Partnership (formerly
Nova Pipeline Ventures Limited Partnership) completed construction of its
pipeline, which is anticipated to meet Suncor's foreseeable needs for
transporting natural gas to its Oil Sands facility. Gas is now being delivered
to the Suncor site via the new line.
RISK/SUCCESS FACTORS AFFECTING OVERALL PERFORMANCE
The profitability of Suncor's Oil Sands business is influenced by crude oil
prices, which are difficult to predict and impossible to control. Unplanned
production or operational outages and slowdowns, particularly those related to
severe climatic conditions, including those that affect quality of products
produced, can be expected from time to time.
Suncor's relationship with its employees is important to its future
success as work disruptions have the potential to adversely affect Oil Sands
operations. Suncor entered into a new two-year collective agreement with the
Communications, Energy and Paperworkers Union Local 707 effective May 1, 1999.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 25
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
EXPLORATION AND PRODUCTION
[MAP]
OVERVIEW
Suncor's Exploration and Production (E&P) business, based in Calgary, Alberta,
explores for, acquires, develops, produces and markets natural gas, natural gas
liquids, crude oil and various byproducts from the Western Canada Sedimentary
Basin.
A significant factor impacting E&P's 1999 financial and operating results was
a disappointing finding and development (F&D) program. E&P invested $151 million
to add six million barrels of new proved reserves. E&P's total proved reserves
declined 37 million BOE to 152 million BOE as a result of property dispositions,
downward technical revisions, and current-year production less new reserve
additions. As a result, E&P's three-year F&D performance increased to $11.40 per
BOE from $6.90 per BOE for the three-year period ending in 1998. The 1999
three-year average reserve replacement ratio was 120% compared with 200% for the
three years ended 1998.
E&P initiated a portfolio optimization program in 1997 to improve the quality
of its asset base and to improve its net cash position by selling non-strategic
properties and assets. This program positively impacted 1999 financial results.
Proceeds from the property dispositions contributed $90 million towards the net
cash surplus, an increase of $81 million over 1998 levels. Property dispositions
associated with the program represented annual production of 3,300 BOE per day.
The program has generated proceeds of over $110 million since its inception. E&P
plans to continue the program in 2000 with a focus on divesting oil properties.
The property divestments planned for 2000 could generate $100 to $200 million in
proceeds.
In the fourth quarter of 1999, E&P initiated a strategic study to examine
ways to improve the financial and operating performance of its natural gas
business as well as focus on defining new and profitable opportunities for
growth. The study is expected to be completed by the end of the second quarter
2000.
RESULTS OF OPERATIONS/INVESTING/EXPLORATION ACTIVITIES
1999 VERSUS 1998
EXPLORATION AND PRODUCTION - SUMMARY OF RESULTS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------
($ millions unless otherwise noted) 1999 1998 1997
- -----------------------------------------------------------------
<S> <C> <C> <C>
Revenue 306 290 302
Production (thousands of BOE* per day) 37.2 42.2 40.3
Average sales price (including the
impact of hedging)
Natural gas ($/ thousand cubic feet) 2.44 1.95 1.93
Conventional crude oil ($/ barrel) 20.94 20.14 22.75
Earnings 43 25 24
Cash flow provided from operations 172 167 162
Total assets 962 943 819
Capital and exploration expenditures 200 242 240
- -----------------------------------------------------------------
</TABLE>
* BOE is a measure which converts gas to oil on the approximate long-term
economic equivalent basis that 10,000 cubic feet of gas equals one barrel of
oil.
EARNINGS ANALYSIS
EARNINGS INCREASE BY 72% ON ASSET DIVESTMENT GAINS
E&P's earnings increased to $43 million in 1999, up 72% from $25 million in
1998. During the year, cash flow from operations rose to $172 million from $167
million in 1998. The earnings increase was driven principally by a $16-million
increase in gains on asset dispositions and by stronger natural gas prices. The
increase in cash flow from operations was mainly attributed to higher natural
gas prices.
NATURAL GAS PRICES INCREASE 25%
In 1999, E&P's natural gas price averaged $2.44 per thousand cubic feet (mcf)
compared with $1.95 per mcf in 1998, an improvement of 25%. Prices
strengthened throughout the year as a result of stronger demand and improved
access to export markets in the U.S. The 1999 price includes the impact
26 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - EXPLORATION AND PRODUCTION
RESERVOIR
Body of porous rock containing an accumulation of water, crude oil or natural
gas.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1998 1999
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
EARNINGS
ANALYSIS
($ millions)
[GRAPH]
- -------------------------------------------------------------------------------
25 30 (20) (8) 16 0 43
- -------------------------------------------------------------------------------
Total Price Volume Royalties Asset Expenses Total
Divestment
Gains
- -------------------------------------------------------------------------------
</TABLE>
PRICE IMPROVEMENT AND ASSET DIVESTMENT GAINS MORE THAN OFFSET THE SHORTFALL
IN PRODUCTION VOLUMES RESULTING IN THE EARNINGS IMPROVEMENT.
of E&P's hedging program, which decreased the price by $0.04 per mcf.
E&P's average realized crude oil price increased $0.80 per barrel, to $20.94
per barrel in 1999, due to the increase in world oil prices. The price realized
in 1999 was reduced by $2.72 per barrel due to the impact of crude oil hedging.
The increase in oil and gas prices, partially offset by hedging program losses,
resulted in a net $30-million increase in earnings compared with 1998.
PRODUCTION DECLINES 12% OVER 1998 LEVEL
E&P's oil and natural gas volumes declined to 37,200 BOE per day in 1999, from
42,200 BOE per day in 1998. The main factors for the production decline were
asset dispositions (representing annual production of 3,300 BOE per day)
combined with natural RESERVOIR declines, disappointing drilling results and
delays in bringing new production on stream.
The decline in volumes in 1999 over 1998 had a negative impact on earnings of
$20 million.
ROYALTIES INCREASE WITH HIGHER COMMODITY PRICES
Royalties increased to $4.26 per BOE in 1999 from $2.75 per BOE in 1998 mainly
due to the significant increase in natural gas prices. The increase in royalties
reduced earnings by $8 million.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1998 1999
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
NET CASH SURPLUS
(DEFICIENCY)
ANALYSIS
($ millions)
[GRAPH]
- -------------------------------------------------------------------------------
(79) 5 40 123 89
- -------------------------------------------------------------------------------
Total Operations Working Investing Total
Capital Activities
- -------------------------------------------------------------------------------
</TABLE>
LOWER CAPITAL AND EXPLORATION SPENDING AND $81 MILLION IN HIGHER PROCEEDS
FROM PROPERTY DISPOSITIONS RESULT IN A $168-MILLION YEAR-OVER-YEAR
IMPROVEMENT IN E&P'S NET CASH FLOW.
TOTAL EXPENSES REMAIN AT 1998 LEVELS
Total cash expenses in 1999 were $2 million lower than in 1998, mainly due to
lower administrative costs. Depreciation, depletion and amortization expenses
(non-cash) increased by $2 million in 1999 over 1998 as a result of higher
per-barrel, non-cash costs. The net result of lower administrative and higher
non-cash costs was no net increase in year-over-year expenses.
ASSET DIVESTMENT GAINS
As part of E&P's ongoing portfolio optimization program, gains from the sale of
non-strategic assets were $19 million in 1999, a $16-million increase as
compared to 1998.
NET CASH SURPLUS ANALYSIS
E&P had a net cash surplus of $89 million in 1999, an improvement of $168
million when compared to the deficiency of $79 million in 1998. The improvement
was driven by an increase in divestment proceeds of $81 million, a reduction in
capital and exploration investing activities of $42 million, a $40-million
decrease in working capital and an improvement in cash from operating activities
of $5 million.The working capital improvement was due to inventory and other
asset reductions, and an increase in accounts payable related to high year-end
capital spending.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 27
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - EXPLORATION AND PRODUCTION
* THIS SECTION CONTAINS FORWARD- IN-SITU
LOOKING INFORMATION. ALSO REFER TO In-situ or "in place" refers to
THE OVERVIEW*** ON PAGE 21 OF methods of extracting heavy oil from
THIS REPORT. deep deposits of oil sands without
removing ground cover.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
1995 1996 1997 1998 1999
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
TOTAL PROVED RESERVES
(millions of barrels
of oil equivalent)
[GRAPH]
- --------------------------------------------------------------------------
/ / Natural Gas 91 99 109 120 101
- --------------------------------------------------------------------------
/ / Liquids 58 65 70 69 51
- --------------------------------------------------------------------------
Total 149 164 179 189 152
- --------------------------------------------------------------------------
</TABLE>
POOR DRILLING RESULTS, NEGATIVE RESERVE REVISIONS AND HIGHER THAN PLANNED
DIVESTMENTS RESULT IN A DECREASE IN TOTAL PROVED RESERVES.
CAPITAL AND EXPLORATION INVESTING ACTIVITIES
E&P's net investing activities declined from $233 million in 1998 to $110
million in 1999. The decline in capital spending is a result of lower
exploration and development drilling and lower lease and well equipment
expenditures. Divestment proceeds increased $81 million as a result of the
ongoing portfolio optimization program. The decline in net investing activities
was part of E&P's net cash flow management program supporting other Suncor
growth initiatives.
OUTLOOK*
FOCUS ON NATURAL GAS
E&P has been increasing its natural gas focus for the past seven years, based on
management's belief that commodity prices will strengthen and market access for
natural gas will improve. The outlook for Alberta natural gas prices remains
positive due to strong U.S. demand and further increases in export pipeline
capacity. Suncor expects U.S. gas demand to continue growing, supported by
improving industrial demand and increased use of natural gas in electricity
generation.
Suncor's strategy is to continue to position its E&P business to benefit from
any increase in Canadian natural gas prices. Through its portfolio optimization
program, management will continue to evaluate the strategic fit of conventional
oil properties. E&P will focus its exploration and production program on
developing natural gas from the Western Canada Sedimentary Basin. The company
will also continue its pursuit of coal bed methane resources in North America
and Australia as a source of natural gas.
Suncor launched a comprehensive strategic review to determine ways to
improve financial and operational performance and define new and profitable
opportunities for growth. Further property divestments in 2000 could generate
$100 to $200 million in proceeds. E&P's divestment program will consist
mainly of the sale
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
1995 1996 1997 1998 1999
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVE REPLACEMENT RATIO
(percentage - three-year
average)
[GRAPH]
- --------------------------------------------------------------------------
/ / F&D and Acquisitions 263 255 230 200 120
- --------------------------------------------------------------------------
/ / F&D 240 240 220 200 120
- --------------------------------------------------------------------------
</TABLE>
A DISAPPOINTING DRILLING PROGRAM AND RESERVE REVISIONS OF 12.5 MILLION BOE
(7% OF RESERVES AT THE BEGINNING OF THE YEAR) PUSH THREE-YEAR RESERVE
REPLACEMENT RATIO TO LOWEST LEVEL IN LAST FIVE YEARS.
of oil properties and reflects an increasing emphasis on natural
gas. Suncor will use cash generated by the sales to support Project Millennium
oil sands expansion and other growth projects. E&P's current goal is to achieve
an average finding and development cost of $6.75 per BOE for the year 2000 and
profitably grow reserves and production.
IN-SITU OIL SANDS
Suncor advanced its heavy oil strategy in 1999 by conducting additional
delineation, engineering and cost assessments, and an initial review of
environmental issues. In December, the company acquired an additional four oil
sands permits in the Firebag area which, when combined with leases already held
by the company, create one of the largest continuous landholdings in the
Athabasca region at 785 square kilometres.
Subsequent to the end of 1999, Suncor announced plans to invest $750 million
in an oil sands expansion (see Oil Sands Outlook section). This expansion
includes a proposed investment of $450 million towards a commercial scale
IN-SITU operation using steam-assisted gravity drainage (SAGD) on the company's
Firebag leases north of Fort McMurray. The first phase of the project proposes
to add 35,000 barrels of bitumen per day in 2004. Long-term plans call for
further investment to increase in-situ production in stages to 140,000 barrels
of bitumen per day by the end of the decade.
Management believes Suncor has several competitive advantages to develop its
Firebag In-situ Oil Sands Project including the quality of its in-situ leases,
the ability to upgrade bitumen and access other infrastructure efficiencies at
its Oil Sands facilities, and the opportunity to apply knowledge gained from
operating the Burnt Lake pilot project.
The Burnt Lake pilot project achieved a milestone in 1999, producing its
millionth barrel of bitumen. Burnt Lake completed its third full year of
production in 1999, producing 1,500 barrels
28 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - EXPLORATION AND PRODUCTION
CARBON SINK
A pool (reservoir), such as forests or soils, that absorbs or takes up
released carbon from another part of the carbon cycle (i.e. from the
atmosphere).
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
<S> <C>
1999 SUNCOR NATURAL GAS MARKETS
(226 mmcf/d) (percentage)
[GRAPH]
- --------------------------------------------------------------------------
/ / System 29
- --------------------------------------------------------------------------
/ / Direct 71
- --------------------------------------------------------------------------
</TABLE>
E&P BELIEVES ITS GAS PORTFOLIO IS POSITIONED TO TAKE ADVANTAGE OF IMPROVED
ALBERTA PRICING FUNDAMENTALS.
per day (Suncor's share of this production was 1,200 barrels per day). The
successful application of SAGD technology at Burnt Lake has given Suncor the
confidence to invest in a commercial application of the technology at
Firebag. The company continues to look at all options to optimize the value
of Burnt Lake, including the possible sale of the property.
EVALUATING COAL BED METHANE OPPORTUNITIES
In 1998 Suncor began evaluating coal bed methane opportunities in North America
and Australia. The company is also participating in research and development
initiatives to investigate the potential of coal beds to sequester carbon
dioxide. These initiatives are directed towards capturing the potential that
subsurface coal provides as a source of natural gas and a potential "CARBON
SINK" for greenhouse gas emissions.
In the fourth quarter of 1999 the company's application to explore natural
gas resources in the Australian state of New South Wales was approved. The
petroleum exploration licence gives Suncor the right to develop coal bed methane
and other petroleum resources on over a million acres in the northeastern region
of New South Wales. Over the next two years, Suncor will review technical data,
conduct seismic work, drill wells and assess gas markets to evaluate the
opportunity.
In addition to pursuing coal bed methane in Australia, Suncor is evaluating
opportunities in North America.
SUNCOR'S ACTIVE INVESTIGATION INTO SOUTH AMERICAN OPPORTUNITIES COMPLETED
Suncor has completed the investigation into conventional oil and natural gas
opportunities in South America.The company's focus on its oil sands expansion
and its current natural gas business contributed to a decision to conclude
current efforts. The company may reactivate its investigation into natural gas
exploration and production opportunities in South America in the longer term.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
<S> <C>
SYSTEMS GAS
(percentage)
[GRAPH]
- --------------------------------------------------------------------------
/ / TransCanada Gas Services 46
- --------------------------------------------------------------------------
/ / Pan Alberta 29
- --------------------------------------------------------------------------
/ / Canwest 5
- --------------------------------------------------------------------------
/ / Other 20
- --------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
<S> <C>
DIRECT GAS SALES
(percentage)
[GRAPH]
- --------------------------------------------------------------------------
/ / British Columbia 8
- --------------------------------------------------------------------------
/ / Midwest U.S. 9
- --------------------------------------------------------------------------
/ / Eastern Canada 25
- --------------------------------------------------------------------------
/ / California 25
- --------------------------------------------------------------------------
/ / Alberta 33
- --------------------------------------------------------------------------
</TABLE>
RISK/SUCCESS FACTORS AFFECTING PERFORMANCE
The risks associated with Suncor's natural gas and crude oil activities and
commodity pricing should not be underestimated or viewed as predictable. Suncor
expects that both natural gas and crude oil pricing will continue to be volatile
due to the cyclical nature of supply and demand for these commodities.
Management continues to believe the single most important factor that will
influence E&P's long-term performance is 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. Management believes there
are risks and uncertainties associated with obtaining regulatory approval for
exploration and development activities. Working in other countries could
increase these risks and add to costs or cause delays to these projects. The
company works to reduce these risks through proactive consultation with
stakeholders.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 29
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
SUNOCO
[MAP]
OVERVIEW
Suncor's wholly owned subsidiary, Sunoco Inc., has three Ontario-based business
divisions: Refining (including wholesale sales), Retail Marketing and Integrated
Energy Solutions.
Located in Sarnia, Ontario, Sunoco's refinery is "complex" because it has the
flexibility to produce a high proportion of transportation fuels and
petrochemicals. This refinery has capacity to refine 70,000 barrels of crude oil
per day. For the past three years, the refinery has utilized 95% or higher of
its crude refining capacity. The refinery's average utilization rate in 1999 was
95% (1998 - 99%). In 1999, sales of refined products averaged 86,800 barrels per
day.
Sunoco sells approximately 87% of its total refined product volume in the
Ontario market, which is its primary market. In 1999, Sunoco's share of total
refined product sales in Ontario was approximately 16% (1998 approximately 17%).
The majority of production from the Sarnia Refinery, including approximately
93% of gasoline production, is marketed through Sunoco-controlled distribution
channels in five distinct markets. The remaining production is sold to wholesale
and industrial accounts in Ontario and Quebec.
Sunoco's controlled distribution channels include:
- - 305 Sunoco retail service stations in Ontario, located primarily along the
main Windsor-Kingston-Ottawa transportation corridors;
- - 156 Pioneer-operated retail service stations in Ontario (the Pioneer Group
Inc. is an independent retailer with whom Sunoco has a 50% joint venture
partnership);
- - 60 UPI-operated service stations in rural Ontario; UPI Inc. is a 50% joint
venture company owned by Sunoco and GROWMARK Inc. (a large U.S. Midwest
agricultural supply and grain marketing cooperative). UPI sites sell
conventional and ethanol-blended gasolines, diesel and heating oil to
residential, commercial and farm customers;
- - Eight Sunoco diesel Fleet Fuel Cardlock sites in southern Ontario; and
- - Sun Petrochemicals Company, a 50% joint venture between Sunoco and U.S.-based
Sunoco, Inc.'s (an unrelated company) refinery in Toledo, Ohio. The joint
venture markets an average of 15,150 barrels of petrochemicals per day
worldwide.
Sunoco's Integrated Energy Solutions business, launched in 1997, sells natural
gas to Ontario homeowners and commercial customers and offers heating,
ventilation and air conditioning (HVAC) products and services through 29
dealers.
RESULTS OF OPERATIONS AND INVESTING ACTIVITIES
1999 VERSUS 1998
SUNOCO RESULTS SUMMARY
<TABLE>
<CAPTION>
- -----------------------------------------------------------------
($ millions unless otherwise stated) 1999 1998 1997
- -----------------------------------------------------------------
<S> <C> <C> <C>
Revenue 1 779 1 533 1 673
Refined product sales
(thousands of cubic metres)
Retail gasoline 1 500 1 496 1 387
Total 5 080 5 037 5 182
Earnings (loss) breakdown:
Refining/wholesale 13 24 34
Retail marketing 22 17 10
Energy marketing (4) (1) (5)
Total 31 40 39
Cash flow provided
from operations 103 112 121
Investing activities 43 64 55
Net Cash Surplus 129 55 30
- -----------------------------------------------------------------
</TABLE>
30 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO
ANCILLARY REVENUE
Revenue earned from such activities as car washes, sale of fast foods and
confectionary items.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
1998 1999
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
EARNINGS
ANALYSIS
($ millions)
[GRAPH]
- ----------------------------------------------------------------------------------------------
40 (3) 2 (2) (3) (5) 2 31
- ----------------------------------------------------------------------------------------------
Total Margin Volume Joint Integrated Expenses Ancillary Total
Ventures Energy Income
Solutions
- ----------------------------------------------------------------------------------------------
</TABLE>
INCREASING CRUDE OIL AND FEEDSTOCK PRICES OVER THE YEAR THAT COULD NOT BE
FULLY RECOVERED IN THE MARKETPLACE AND MILD WINTER CONDITIONS COMBINED TO
REDUCE REFINING EARNINGS. THE LOWER REFINING EARNINGS AND HIGHER LOSS IN THE
INTEGRATED ENERGY SOLUTIONS BUSINESS WERE RESPONSIBLE FOR THE EARNINGS
DECLINE.
EARNINGS ANALYSIS
EARNINGS DOWN $9 MILLION COMPARED WITH 1998
Sunoco's 1999 earnings were $31 million compared with $40 million in 1998.
This decrease is largely attributable to lower refining margins caused by
high product inventories at the beginning of the year and quickly rising
crude oil prices which could not be fully recovered in the marketplace,
although margins improved in the second half of the year. Refining earnings
were also negatively impacted by higher feedstock costs. Higher Integrated
Energy Solutions losses also contributed to the earnings decline. Retail
margins, however, were stronger in 1999 compared to 1998, and earnings from
sales of non-petroleum ancillary products increased, partially offsetting the
effect of lower refining margins.
REDUCED REFINING MARGINS IMPACT REFINING PROFITABILITY
Earnings from refining activities declined to $13 million in 1999 compared
with $24 million in 1998, primarily because Sunoco's refining margin
decreased to an average of 4.0 cents per litre (cpl) in 1999 compared with
4.1 cpl in 1998. This factor alone reduced year-over-year refining earnings
by $5 million. Rapidly rising and volatile crude prices and high
international inventories of crude and petroleum products combined to reduce
refining margins early in the year. Sunoco's refining margins improved in the
last half of the year as global inventories declined. The earnings decline
was positively impacted by a $2-million improvement over 1998 due to higher
wholesale gasoline and distillate sales volumes. Earnings from Sun
Petrochemicals Company joint venture were down $2 million from 1998 due
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1998 1999
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
NET CASH SURPLUS
ANALYSIS
($ millions)
[GRAPH]
- -------------------------------------------------------------------------------
55 (9) 62 21 129
- -------------------------------------------------------------------------------
Total Operations Working Investing Total
Capital Activities
- -------------------------------------------------------------------------------
</TABLE>
ACCOUNTS RECEIVABLE AND INVENTORY REDUCTIONS WERE THE PRIMARY FACTORS
CONTRIBUTING TO THE $74-MILLION IMPROVEMENT IN CASH FLOW.
largely to weaker margins. Also contributing to the earnings decline were
expenses that were $6 million higher than in 1998. The increase was due to
higher energy costs, additional purchases to cover demand due to lower crude
runs, and fourth quarter operational outages.
In 1999, Sunoco confirmed its ten-year agreement signed in 1998 with Nova
Chemicals (Canada) Ltd. to further optimize both companies' Sarnia-based
operations through the exchange of feedstocks and finished products.
RETAIL MARKETING EARNINGS UP 29% OVER LAST YEAR
Sunoco's retail marketing division achieved its best earnings in over 11 years -
$22 million in 1999 compared with $17 million in 1998. Earnings from Sunoco's
retail networks improved primarily due to an increase of $2 million in gasoline
margins from Sunoco's branded retail network (7.4 cpl in 1999 compared with 7.0
cpl in 1998), a $2-million increase in ANCILLARY REVENUES and a $1-million
reduction in expenses.
Based on independent market survey data, Sunoco retained its market share of
18.5% in the overall Ontario retail gasoline market in 1999. Independent survey
data shows that Sunoco's branded retail network continues to be in the top
decile of all Ontario retailers as measured by throughput per site. Sunoco's
customer loyalty program with the Canadian Automobile Association's Ontario
clubs gained popularity among customers with an increased number of CAA Ontario
members using their SWIPE-AND-SAVE CARDS at Sunoco retail sites since 1998.
Retail marketing initiatives to broaden Sunoco's non-petroleum offering of
products and services, such as Country Style
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 31
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO
* THIS SECTION CONTAINS FORWARD
LOOKING INFORMATION. ALSO REFER TO
THE OVERVIEW*** ON PAGE 21 OF
THIS REPORT.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
1995 1996 1997 1998 1999
- -------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
MARGIN
(cents per litre)
[GRAPH]
- -------------------------------------------------------------------------------------
/ / Sunoco Branded Retail Gasoline Margin 5.8 5.7 6.8 7.0 7.4
- -------------------------------------------------------------------------------------
/ / Refining Margin 5.0 4.4 4.6 4.1 4.0
- -------------------------------------------------------------------------------------
</TABLE>
RETAIL MARGINS IMPROVED YEAR-OVER-YEAR WHILE REFINERY MARGINS SAW A DECLINE
IN THE FIRST HALF OF THE YEAR. THE DECLINE WAS PARTIALLY OFFSET BY A RECOVERY
IN THE SECOND HALF OF THE YEAR.
branded coffee, resulted in a 21% improvement in ancillary revenues in the
year.
SUNOCO EXPANDS HOME ENERGY DEALER NETWORK
Sunoco's Integrated Energy Solutions business had a loss of $4 million in 1999
compared with a loss of $1 million in 1998. The higher loss was primarily due to
floating rate contractual sale price commitments that were less than the cost of
supply of natural gas.
The Ontario Energy Board has recently approved Sunoco's proposal to convert
its floating rate customer contracts to fixed rate contracts effective July
2000. This change should improve Sunoco's ability to make a positive margin in
its natural gas business.
As part of its goal to broaden its energy offerings, Sunoco expanded the
number of dealer members in the Home Energy Dealer Network to 29 dealers in just
over one year's time.
NET CASH SURPLUS ANALYSIS
Net cash flow increased to $129 million in 1999 compared with $55 million in
1998. Cash flow from operations decreased to $103 million compared with $112
million in 1998, primarily as a result of lower margins from the Sunoco refining
operations.
Working capital improved by $62 million primarily due to the reduced amounts
of accounts receivable and crude oil inventory. Capital spending decreased to
$43 million compared with $64 million in 1998.
OUTLOOK*
EMPHASIS ON REFINERY COMPETITIVENESS
The competitive plans of the refinery include a goal of being rated in the
top third of North American refineries of the same size and complexity - in
profitability and efficiency, as reported
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
1995 1996 1997 1998 1999
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SUNOCO ONTARIO BRANDED
RETAIL NETWORK EFFICIENCY*
(millions of litres per site)
[GRAPH]
- ---------------------------------------------------------------------------
/ / Throughput 4.2 4.2 4.3 5.0 5.1
- ---------------------------------------------------------------------------
/ / Sites 284 333 332 310 305
- ---------------------------------------------------------------------------
</TABLE>
* THROUGHPUT PER SITE - MILLIONS OF LITRES PER SITE BASED ON THE AVERAGE
NUMBER OF SITES AT THE BEGINNING AND END OF THE YEAR.
SITES - NUMBER AT YEAR-END, EXCLUDING JOINT-VENTURE-OWNED SITES.
SITE THROUGHPUT INCREASED 2% OVER 1998 DUE TO EFFORTS TO IMPROVE EFFICIENCY
AND A NET REDUCTION IN THE NUMBER OF SITES.
by independent survey data. The target date for the refinery to achieve this
goal has been moved to 2002 from 2000, due in part to the delay of the Sarnia
regional cogeneration project. Sunoco continued implementing the refinery
organizational realignment it launched in 1997 with 90% completion planned
for the end of 2000. Overall, these initiatives are designed to reduce
refining costs, which in turn should have a positive impact on Sunoco's
earnings.
Sunoco continues to evaluate its participation in TransAlta Energy
Corporation's proposed Sarnia regional cogeneration project. Such involvement
will be subject to enabling rules and regulations emanating from the Ontario
government's electricity deregulation process. These include acceptable
transmission tariff structures currently under a rate hearing by the Ontario
Energy Board. Due to the length of the deregulation process, the start-up is now
estimated to be mid-2002.
In 1999, Sunoco's refinery achieved ISO 14000 certification, an accreditation
that endorses effective environmental management systems based on international
standards. The Sunoco refinery was the first refinery in Canada and the fourth
in North America to be certified. This is consistent with Suncor's goal of
leadership in the areas of environment, health and safety and aids in effective
environment risk management.
EXPANSION OF DIESEL MARKETS
In 1999, Sunoco continued to expand its offering to the on road diesel market by
adding three additional sites to its Fleet Fuel Cardlock network. The cardlock
margin adds value over traditional distribution channels. Sunoco will continue
its plans for cardlock network growth that were initiated in 1998. Marketing
efforts focused on a premium diesel fuel, Gold Diesel, with Sunoco more than
doubling the volume sold in 1999 compared to 1998.
32 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO
RETAIL MARKETING CONTINUES TO DEVELOP THROUGH STRATEGIC ASSOCIATIONS
Sunoco-branded retail marketing continues to focus on differentiating itself by
implementing its vision of becoming the neighbourhood choice for energy, comfort
and convenience retailing in Ontario. Management believes Sunoco's relationships
with retailers, suppliers, customers and communities facilitate potential
revenue growth and an enhanced understanding of stakeholder requirements.
Ancillary revenue from non-petroleum products grew 21% in 1999 due to
marketing programs and capital improvements in the business that added and
improved facilities to support marketing initiatives.
The company's exclusive five-year loyalty program signed January 1, 1999 with
the Ontario clubs of the CAA provides Sunoco access to the association's 1.8
million members to market retail gasoline, natural gas and other products and
services.
JOINT MARKETING INITIATIVES PLANNED FOR INTEGRATED ENERGY SOLUTIONS (IES) AND
RETAIL
Sunoco launched its retail natural gas marketing business in 1997 to take
advantage of opportunities in the broader energy market in Ontario resulting
from deregulation. Due to delays in the regulatory process, IES has shifted its
focus from aggressive growth to retention and extension of new products and
services to Sunoco's existing customer base. IES and retail marketing piloted
several joint marketing initiatives in 1999 to capitalize on integration
opportunities. Additional programs are planned in 2000, including an expanded
customer loyalty program and development of internet marketing, which are being
designed to attract more customers to buy more Sunoco products more often.
In addition, Sunoco continues to assess the potential for marketing
electricity in Ontario, a new growth opportunity resulting from the pending
deregulation of electricity services in the province.
RISK/SUCCESS FACTORS AFFECTING PERFORMANCE
Margin and crude oil price volatility and overall marketplace competitiveness,
compounded by a warm winter and higher petroleum product inventories, reduced
margins in 1999. In the last half of 1999, crude prices increased rapidly,
resulting in refining margin volatility. Management expects that fluctuations in
demand for refined products, margin volatility and overall marketplace
competitiveness will continue. As 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.
The Canadian refining industry faces significant capital spending to
construct sulphur removal facilities following the passage of legislation that
limits sulphur levels in gasoline to an average of 150 parts per million (ppm)
from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. Although the
spending required 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.
A Sunoco task force has completed a strategic study of the implications of
fuels reformulation, technical alternatives, and technological change for the
industry in general and on Sunoco in particular. As a result of the study,
management believes Sunoco will be positioned competitively in the future.
Sunoco's refinery has complied with more stringent national standards for
cleaner-burning gasolines, including limits on benzene emissions, which came
into effect on July 1, 1999, with minimal capital spending.
ENVIRONMENTAL RESPONSIBILITY
Sunoco continues to focus on and address environmental issues facing Ontario and
Canada. In 1999, Sunoco introduced a new gasoline additive that reduces nitrogen
oxides (N0x) from tailpipe emissions. This initiative generated over 275 tons of
N0x credits under Ontario's Pilot Emission Reduction Trading project. Sunoco
then sold the credits to Ontario Power Generation Inc. and intends to use a
portion of the proceeds from the emissions trade to fund additional pollution
prevention projects.
In 1999 Sunoco increased the percentage of ethanol in gasoline sold at all
Sunoco-branded retail sites. Ethanol-enhanced gasoline reduces carbon monoxide
and greenhouse gas emissions compared with conventional gasoline. Sunoco's
gasoline and car washes are certified to display Environment Canada's EcoLogo
certification, which demonstrates active commitment to offering products and
services which meet Canada's environmental labelling guidelines.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 33
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
LONG TERM INCENTIVE PLAN
See note 10(b) to the financial statements.
SALE
Also see note 2 to the financial statements.
CORPORATE
[MAP]
OVERVIEW
Suncor's Calgary corporate centre fulfills a number of roles, including support
to the company's business units and Board of Directors. Corporate centre
personnel are accountable for functions such as legal, taxation, risk
management, company-wide human resource programs, treasury, corporate finance,
planning and business development, corporate communications and regulatory
reporting at the corporate level.
RESULTS OF OPERATIONS AND INVESTING ACTIVITIES 1999 VERSUS 1998
Corporate expenses increased from $27 million in 1998 to $48 million in 1999,
mainly due to higher taxes ($11 million) and higher costs related to Suncor's
LONG-TERM INCENTIVE PLAN ($10 million).
The corporate centre had a net cash deficiency of $73 million in 1999
compared to a net cash deficiency of $198 million in 1998. The $125 million
reduction in cash deficiency was primarily due to a $74-million reduction in
investing activities in 1999 due to the completion of construction of the Stuart
oil shale demonstration plant in Australia (also see note 12(b) to the financial
statements) and a reduction in working capital. The decrease in working capital
was associated with hedging losses, higher income taxes and increased
operational payables.
CONSOLIDATED BALANCE SHEET ANALYSIS
Higher commodity and refined petroleum product prices at the end of 1999
compared to the end of 1998 were the primary factors for a $101-million increase
in accounts receivable. The impact of higher prices was partially offset by the
SALE of a portion of accounts receivable.
An inventory decrease of $14 million was due to the reduction of a portion of
the company's crude oil inventory and the sale of some midstream natural gas
equipment. The benefit of these sales was partially offset by an increase in Oil
Sands inventory related to the start-up of the Enbridge Athabasca Pipeline and a
temporary increase in year-end inventories at Oil Sands.
Net capital assets increased by over $1 billion in 1999 with $941 million of
the increase coming from Suncor's Project Millennium and the Stuart Oil Shale
Project in Australia. Capital assets are reduced by depreciation, depletion and
amortization once they are placed into service. In 1999 capital assets with a
net book value of $58 million were sold and this reduced net capital assets. The
majority of assets disposed of were associated with E&P's divestment program.
Trade payables and accrued liabilities were $322 million higher in 1999 than
in 1998. A major factor in this increase was the activity level associated with
Project Millennium, which accounted for approximately $190 million of this
increase. Higher crude oil and natural gas prices at the end of 1999 compared
with year-end 1998 and higher sales volumes in Oil Sands resulted in higher
royalties and hedging payables. The higher crude oil prices also increased the
cost of crude oil and other feedstocks purchased in Suncor's downstream
business. These purchases were higher than in 1998 due to an operational problem
at the Sarnia Refinery late in 1999 that required the purchase of finished
product to ensure that all customer requirements were met.
Excluding cash and short-term borrowings and the current portion of long-term
borrowings, Suncor had a working capital deficiency of $225 million at the end
of 1999 compared to a surplus of $22 million at the end of 1998. Over 80% of the
$247-million change was due to Project Millennium spending and hedging
activities. Suncor had in place unused lines of credit of $1.2 billion at the
end of 1999. These unused lines of credit expire at the end of 2004.
The increase in 1999 of deferred income taxes resulted primarily from income
tax deductions associated with certain capital investments at Oil Sands and the
Stuart Oil Shale Project.
34 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CORPORATE
* This Section contains forward
looking information. Also refer to
the Overview*** on page 21 of
this report.
CONSOLIDATED EARNINGS ANALYSIS
Sales and other operating revenues increased from $2,068 million in 1998 to
$2,383 million in 1999. The impact of higher commodity prices increased
revenues by $321 million. This figure is after the impact of hedging activity
undertaken in 1999. While crude oil sales volumes increased due to record Oil
Sands sales levels, a decrease in conventional liquids and natural gas
volumes resulted in a $6-million negative impact on revenue.
The impact of higher crude oil prices in 1999 was also reflected in
Suncor's purchases of crude oil and products, which increased by $153 million
in 1999. Crude oil, other feedstocks and products purchased by Sunoco's
Sarnia Refinery increased by $157 million in 1999 while Oil Sands decreased
its purchases of bitumen from third parties by $4 million. The increase in
purchases at the Sarnia Refinery primarily reflects the impact of higher
market prices in buying from third parties. This increase was also affected
by production interruptions in the fourth quarter at the Sarnia Refinery that
necessitated refined product purchases to meet customer requirements.
Operating, selling and general expenses increased $68 million from $682
million in 1998 to $750 million in 1999. Higher operating costs in all
operations represented $53 million of the year-over-year increase. The higher
operating costs were primarily a result of higher mining and extraction costs
at Oil Sands, higher unit operating costs in the E&P business and higher
operating expenses at Sunoco's Sarnia Refinery. These higher operating costs
were partially offset by lower volume-related expenses in E&P ($7 million).
Expenses were also increased by $22 million due to a higher provision for
employee incentive plan costs in 1999.
Royalty expenses increased $21 million, to $99 million in 1999. Higher
commodity prices increased royalties by $31 million. A combination of lower
conventional oil and natural gas volumes and a change in sales mix at Oil
Sands decreased royalties by $10 million. The change in sales mix is a result
of a planned partial maintenance shutdown that resulted in the production of
only sour crude oil for one month at Oil Sands. There is no planned Oil Sands
maintenance shutdown work in 2000.
Taxes other than income taxes increased by $9 million due to higher sales
volumes of taxable products (mainly transportation fuels) in the downstream
business ($7 million). Higher property taxes in Oil Sands due to the
increased property tax base with the expansion of operations in late 1998
increased costs by $2 million.
Depreciation, depletion and amortization (DD&A) increased in 1999 over
1998 by $54 million, to $318 million. The increase was largely due to
increased DD&A costs at Oil Sands. Higher depreciation was due to a higher
capital base resulting from the completion of Oil Sands' Steepbank Mine and
fixed plant expansion in late 1998. DD&A was also higher at Oil Sands due to
higher overburden amortization ($30 million). This overburden amortization
increase reflects the impact of three factors: a 17% increase in Oil Sands
production; an increase in the estimated amount and cost of overburden
removal; and the impact of ceasing mining activity on the original oil sands
leases sooner than anticipated. The impact of closing the original mine
earlier than planned and the resulting reduction in reserves, is to increase
the amortization of overburden associated with the original mine by $7
million per year for about a year. This increase in the write-off is due to a
20-million-barrel reduction in reserves.
Net financing costs were unchanged year-over-year as additional interest
income was offset by higher borrowing costs in the first half of 1999
compared to 1998. 1999 capitalized interest costs exceeded the 1998 level.
The increase in interest capitalized is due to the spending on Project
Millennium.
The effective tax rate increased from 37% in 1998 to 40% in 1999. This
reflects the refund of $11 million received in 1998. Excluding the refund,
1998's rate would be approximately 41%.
OUTLOOK*
GROWTH PRIORITIES
In 1998's MD&A, Suncor outlined its six long-term growth priorities. As a
result of continued review and assessment, the company has consolidated its
growth priorities to a total of four. In order of priority, they are:
1. EXPAND OIL SANDS PRODUCTION. In 1999 Suncor received regulatory approval for
the second phase of its $2.2-billion Project Millennium. The company
commenced the first phase in 1998, called the Production Enhancement Phase
(PEP). Phase 2 commenced in 1999 with the receipt of regulatory approval.
Combined, these two phases are designed to increase Oil Sands production to
225,000 barrels per day in 2003, from the 1999 production of 105,600 barrels
per day.
In 2000 Suncor announced a plan to further expand its oil sands
facilities beyond 2003 with a proposed investment of $750 million in an
in-situ project and a further expansion of the oil sands plant. The
in-situ portion of the project is scheduled to be integrated with Suncor's
open pit mining operation, and, combined with plans to expand upgrading
capacity, would enable output from Suncor's plant to reach an estimated
260,000 barrels of oil per day in 2004. In-situ
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 35
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CORPORATE
Sequestration of Carbon Dioxide
The storage of carbon in large-scale
carbon sinks, such as forests or
underground reservoirs, that reduce
greenhouse gas concentrations in
the atmosphere.
technology recovers bitumen with less impact to the air, water and land
than traditional mining methods and allows Suncor to develop oil sands
deposits not accessible through open pit operations. Potential advantages
of the current plans to integrate the in-situ project with the existing
oil sands plant include:
MINIMAL DISRUPTION OF LAND. The physical plant structure will disturb less
than 10% of the surface land area over the deposit being developed.
SELF-SUFFICIENT WATER USE. The water used in the operation will be
recycled and will come from the waste water streams from Suncor's oil
sands plant.
STEAM GENERATION FUELLED BY NATURAL GAS. The SAGD process will be fuelled
by natural gas which is the cleanest burning fossil fuel.
ENHANCED RECOVERY RESEARCH. Suncor is conducting research into the
potential of injecting carbon dioxide and light hydrocarbons into the
in-situ deposit to decrease the amount of the steam needed, thereby
further reducing emissions.
POTENTIAL FOR CARBON SEQUESTRATION. Suncor will examine the potential use
of the in-situ reservoir as a permanent repository to inject greenhouse
gas emissions.
These plans are subject to Board of Directors and regulatory approval.
The company's long-term vision is to increase oil sands production to
about 400,000 to 450,000 barrels of oil a day in 2008 through a
combination of oil sands mining and in-situ development. The company has
not yet identified specific plans to achieve this vision, and any such
plans would be subject to Board of Directors and regulatory approval.
2. TRANSFER OIL SANDS TECHNOLOGY AND EXPERTISE TO NEW BUSINESSES. Suncor is
pursuing growth opportunities in surface mineable oil deposits (both sand
and shale). Prior to the end of 1999, Suncor had completed construction of
a demonstration plant at the Stuart Oil Shale Project in Australia. The
first phase of this project is designed to test the commercial viability
of producing oil from oil shale. Operational testing and commissioning
work is now under way, but has proven to take longer than initially
expected. Hot commissioning trials have demonstrated that oil can be
produced from oil shale, but further assessment is required to determine
whether the technology is commercially viable. This decision is expected
to be made by the end of 2000. Also refer to note 12(b) to the financial
statements for further information with respect to this project.
The company is also assessing potential oil shale deposits in a number
of other geographic locations, including Jordan and Estonia.
3. FURTHER INTEGRATE SUNCOR'S UPSTREAM AND DOWNSTREAM BUSINESSES, including
potential expansion of the company's refining and marketing presence. In
1999 Suncor continued to actively evaluate several approaches to secure
markets and transportation for its increasing Oil Sands production,
including joint ventures, possible acquisitions, or long-term agreements
with other refiners in both Canada and the United States.
4. FOCUS ON NATURAL GAS AND ALTERNATIVE AND RENEWABLE ENERGY -- Suncor intends
to further strengthen its emphasis on natural gas exploration and
development as it reduces its interests in conventional crude oil assets.
As Suncor works to grow its natural gas business in Western Canada, it
will also assess potential opportunities for the production of natural gas
from coal bed methane, both in North America and internationally.
In addition, as the company develops its fossil-fuel-based businesses,
management believes that Suncor also needs to work concurrently toward the
development of alternative and renewable sources of energy. Early in 2000,
Suncor announced plans to invest $100 million in alternative and renewable
energy projects over the next five years. The money is likely to be spent
on research and development projects and commercial ventures which could
include investments in producing fuel from biomass conversion of municipal
solid waste to energy, recovering methane from landfills and capturing and
sequestration of carbon dioxide. Suncor plans to examine potential
opportunities in solar and wind power.
RISK/SUCCESS FACTORS AFFECTING PERFORMANCE
OIL SANDS
When Project Millennium is completed, an even greater portion of Suncor's
future financial performance is expected to be linked to the performance of
its Oil Sands operations. Project Millennium is designed to increase Oil
Sands production to 225,000 barrels per day in 2003. This business division
would then account for over 80% of Suncor's upstream production compared to
72% in 1990. Suncor's cash operating cost at Oil Sands is expected to fall
from its 1999 level of $11.40 per barrel to the $8.50 to $9.50 per barrel
range in 2002. Suncor believes that the planned increases in Oil Sands
production present strategic advantages as well as issues that require
prudent risk management. The strategic advantages of Oil Sands growth may
include:
36 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CORPORATE
- - Economies of scale associated with higher levels of production from the
existing Oil Sands infrastructure;
- - Lower unit costs and improved reliability;
- - The ability to leverage demonstrated operational experience and
technologies; and
- - Production growth without the exploration risk associated with
conventional oil and gas operations.
The issues that Suncor must manage include, but are not limited to:
- - Suncor's ability to finance Oil Sands growth in a volatile commodity
pricing environment (also refer to the section on Liquidity and Capital
Resources, page 39.);
- - Competition from new entrants in the oil sands business. This could take
the form of competition for skilled people, increased demands on the Fort
McMurray infrastructure (housing, roads, schools etc.), or higher prices
for the products and services required to operate and maintain the plant.
Suncor is addressing this issue by developing a comprehensive recruiting
strategy, working with the community to determine infrastructure needs,
designing oil sands expansion to reduce unit costs and capitalize on
technology advancements, and seeking strategic alliances with service
providers;
- - Potential changes in demand for synthetic crude oil. Suncor believes it
can reduce the impact of this issue by entering into long-term supply
agreements with major customers, expanding its customer base and offering
customized blends of synthetic crude oil to meet customer specifications;
- - Operational reliability;
- - Regulatory and/or governmental change; and
- - Preservation and protection of the environment. Suncor has an Environment,
Health and Safety policy designed to mitigate the impact of its operations
on the environment.
COMMODITY PRICES
Suncor's future financial performance remains closely linked to hydrocarbon
commodity prices, which can be influenced by global and regional supply and
demand factors, worldwide political events and the weather. This can result
in a high degree of price volatility, as occurred when benchmark crude oil
prices increased by 131% from December 1998 to December 1999. Suncor has
partially offset the impact of crude oil price volatility by reducing cash
costs and improving reliability at Oil Sands over the past five years.
Because prices of crude oil and natural gas are based on a U.S. dollar
benchmark, Suncor's earned prices are influenced by the Canadian/U.S.
currency exchange
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
2000 2001 2002 2003 2004
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
[GRAPH]
CRUDE OIL HEDGING PROGRAM
- ----------------------------------------------------------------------------------------------
/ / Annual Oil Product Hedge (percentage)* 49 23 2 0 0
- ----------------------------------------------------------------------------------------------
- Current Annual Limits** 50 30 30 30 30
- ----------------------------------------------------------------------------------------------
Hedged Price -- Cdn. $/bbl 26 26 26 0 0
- ----------------------------------------------------------------------------------------------
</TABLE>
* Percentage of annual crude oil production hedged as of December 31, 1999.
** Current annual limits for hedged volumes/dollars authorized by
Board of Directors (percentage).
Suncor uses hedging as a risk management tool to reduce earnings and cash
flow volatility. The annual limits may change, subject to Board approval, to
reflect management's ongoing assessment of the risk it is willing to accept.
Refer to note 15 in the consolidated financial statements for additional
information.
rate, creating another element of uncertainty. The weakness in the Canadian
dollar versus the U.S. dollar in 1999 increased Suncor's revenues as measured
in Canadian dollars. In the future, the strength of the Canadian dollar
relative to foreign currencies could create uncertainties for Suncor as it
pursues its international growth plans. For example, a one-cent change in the
Canadian/Australian exchange rate on the Stuart Oil Shale borrowings (see
note 8 to the financial statements) will impact Suncor's pre-tax earnings by
approximately $1 million.
HEDGING
Suncor cannot control the prices of crude oil or natural gas, or currency
exchange rates. However, the company has a hedging program that fixes the
price of crude oil and natural gas and the associated foreign exchange for a
percentage of Suncor's total production volume. Suncor's objective is to lock
in prices on a portion of the company's future production today to reduce
exposure to market volatility and ensure the company's ability to finance its
growth.
The Board of Directors meets with management regularly to assess Suncor's
hedging thresholds in light of its price forecast and cash requirements. To
add assurance to Suncor's ability to finance its 2000 capital program, the
Board authorized hedging 50% of its crude oil volumes in 2000, with the
authorized limit returning to 30% in 2001, 2002, 2003 and 2004. For natural
gas, the Board has authorized a hedging program that allows up to 50% of
Suncor's volume to be hedged in the current year and subsequent year, 30% for
the third year, and 15% for the fourth year.
In 1999, crude oil, natural gas and currency exchange hedging activities
decreased Suncor's earnings by $56 million. In 1998, hedging activities
increased earnings by $47 million.
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 37
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CORPORATE
OTHER FACTORS
Other critical factors affecting Suncor's financial results include: volumes
of refined product sales; margins on the sale of refined products; the
success of the exploration program; interest rates; and the company's ability
to manage costs. Also refer to the note (***) on page 21 of the MD&A.
YEAR 2000 RESULTS
Suncor and its subsidiaries did not experience any material adverse
consequences as a result of the changeover from the year 1999 to 2000 and the
rollover to February 29, 2000.
As of the end of 1999, the total cost of the company's Year 2000 Project
was $25 million, of which $11 million was incurred in 1999. Substantially all
costs were recorded as expenses in Suncor's 1999 Statements of Earnings. The
company does not separately track the internal costs incurred for its Year
2000 Project, such costs principally being the related payroll costs for
information technology personnel.
SENSITIVITY ANALYSIS
The sensitivity analysis shows the main factors affecting Suncor's annual
pre-tax cash flow from operations and after-tax earnings based on actual 1999
operations, including the impact of hedging activity. The table below
illustrates the potential financial impact of these factors applied to
Suncor's 1999 financial results. A change in any one factor could compound or
offset other factors. Because this table does not incorporate potential
cross-relationships, the analysis is not necessarily accurate.
ENVIRONMENTAL REGULATION RISK/SUCCESS FACTORS
Environmental legislation affects nearly all aspects of Suncor's operations.
These regulatory regimes are laws of general application that apply to Suncor
in the same manner as they apply to other companies and enterprises in the
energy industry. They require Suncor to obtain operating licences, and they
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 include possible
cumulative impacts of oil sands development in the Athabasca region; the need
to reduce or stabilize various emissions; potential impacts of government
regulation as it relates to the reduction of greenhouse gas emissions; land
reclamation and restoration; Great Lakes water quality; and reformulated
gasoline and diesel to support lower vehicle emissions. Changes in regulation
could have a potentially adverse effect on Suncor from the standpoint of
product demand, product formulation and quality, and methods 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
SENSITIVITY ANALYSIS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
APPROXIMATE CHANGE IN
PRE-TAX CASH FLOW AFTER-TAX
($ MILLIONS) 1999 AVERAGE CHANGE FROM OPERATIONS EARNINGS
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Oil Sands
Price of crude oil ($/barrel) 23.84 U.S.$1.00 31 18
Sales (barrels per day) 102 200 1,000 6 4
Exploration and Production
Price of crude oil ($/barrel) 20.94 U.S.$1.00 6 3
Price of natural gas ($/thousand cubic feet) 2.44 0.10 7 4
Production of natural gas (millions of cubic feet per day) 226 10 7 4
Sunoco
Retail gasoline margin (cents/litre) 7.4 0.1 2 1
Refining/wholesale margin (cents/litre) 4.0 0.1 5 3
Consolidated
Exchange rate: C$: U.S.$ 0.67 0.01 12 7
Interest rate 5.2%* 1% 9 5
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
* Borrowings with interest at variable rates averaging 5.2% at December 31.
38 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CORPORATE
NET DEBT
includes long-term borrowings, the
current portion of long-term
borrowings, short-term borrowings
less cash and cash equivalents.
future impact on the company. Management anticipates capital expenditures and
operating expenses will increase in the future in part as a result of the
implementation of new and increasingly stringent environmental regulations.
LIQUIDITY AND CAPITAL RESOURCES
Suncor's growth initiatives have increased NET DEBT from $796 million in
December 1997 to $1.3 billion at December 1999. Capital investment in the
next three years, which includes spending for Project Millennium, is expected
to be over $3 billion, a similar level to the last three years.
Suncor management believes that it has sufficient borrowing capacity to
fund Project Millennium and that cash flow from operations will be sufficient
to fund ongoing operations and investing activities excluding funding on
Project Millennium.
Crude oil prices, and to a lesser degree natural gas prices, are important
components in determining Suncor's yearly earnings and cash flow, as well as
net debt levels. In 1999, crude oil prices experienced extremes that were
unanticipated. The benchmark WTI price dropped to below US$12 per barrel in
early 1999 and reached a high of over US$26 per barrel in December 1999.
While Suncor does not believe that crude oil prices will be sustained at the
December 1999 monthly average of over US$26 per barrel, management believes
prices will be higher than the company forecast last year. Suncor's financing
and capital spending plans are based upon the following financial
assumptions: the yearly average WTI crude oil price will be in the range of
US$17.50 per barrel to US$18.00 per barrel over the next three years (last
year's three-year forecast: US$13.00 in 1999 to U.S.$17.50 in 2001); there
will be an increase in demand for natural gas, moving prices from $2.44 per
thousand cubic feet in 1999, to approximately $2.50 to $3.00 per thousand
cubic feet in 2002 (last year's three-year forecast: $1.95 per thousand cubic
feet, moving to approximately $2.50 per thousand cubic feet in 2002); and the
Canadian dollar will strengthen versus the U.S. dollar from the 1999 average
of $0.67, to $0.70 by 2002.
During the two years ending December 31, 2001, Suncor's debt/cash flow
ratio is expected to climb from its current level of 2.3 times to a
short-term peak in the 2.5 to 3.0 times range, due to planned growth
expenditures. This is unchanged from last year's forecast. Subject to the
timely completion, final project cost and successful implementation of
Project Millennium and contingent on the company's financial assumptions,
management believes that expected increases in cash flow will reduce the
debt/cash flow ratio to
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
1995 1996 1997 1998 1999
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RATIO OF NET DEBT / CASH FLOW
FROM OPERATIONS
[GRAPH]
- ----------------------------------------------------------------------------------------------
/ / Number of times .7 .9 1.4 2.2 2.3
- ----------------------------------------------------------------------------------------------
</TABLE>
RATIO IS EXPECTED TO REMAIN IN THE 2.5 - 3 TIMES RANGE UNTIL THE COMPLETION
OF PROJECT MILLENNIUM.
Suncor's long-term goal of 1.5 to 2.0 times after the year 2001.
In 1999 a number of financing initiatives were completed to support
Suncor's growth initiatives. These included the issuance of preferred
securities and the sale of accounts receivable (see notes 13 and 2,
respectively, to the financial statements). However, internally generated
cash over the next three years is expected to be insufficient to support the
increased spending based on the company's current outlook for commodity
prices. A financing plan has been developed that management believes will
allow Suncor to raise additional capital if necessary. Components of the plan
include the following:
- - Maintain sufficient debt capacity. Suncor currently has $525 million of
public debt, and credit and term loan facilities of $1.9 billion, of which
$695 million had been used as at December 31, 1999;
- - Manage each business unit with a view to achieving positive net cash flow
targets (excluding Project Millennium);
- - Examine all growth opportunities with a view to reducing the need for
Suncor to invest its own capital through mutually beneficial relationships
with third parties;
- - Pursue the sale of non-core assets;
- - Evaluate further opportunities to hedge commodity prices; and
- - Issue equity if required.
This approach to financial management could change in scope, timing and
magnitude depending on factors such as commodity prices, production volumes,
interest rates, exchange rates, and capital market conditions.
OPERATING COMMITMENTS
When Suncor commenced its Oil Sands operations in northern Alberta over 30
years ago, and until recently, it has had to invest in assets and related
services that in more developed geographic areas would be provided by third
parties. These include assets such as crude oil and natural gas pipelines,
electrical and steam generation facilities, and housing accommodations for
contract workers. Suncor believes
SUNCOR ENERGY INC. 1999 ANNUAL REPORT 39
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CORPORATE
organizations with the specific expertise associated with such assets can
provide more cost-effective services. As part of the Oil Sands growth
initiatives, it will look to exit such businesses and obtain services from
third parties. Suncor's long-term transportation service agreement for access
to a portion of the Enbridge Athabasca Pipeline and its agreement with
TransAlta to have that company build, own and operate a cogeneration facility
that will meet a portion of the energy needs of Suncor's Oil Sands operation,
are examples of such opportunities. While these existing arrangements have,
and the new arrangements will, result in long-term operating commitments, the
company believes this approach has the potential to reduce operating and
administrative expenses.
During 1999, Suncor's quarterly dividend was $0.17 per share, unchanged from
1998. Dividend levels are reviewed quarterly in light of Suncor's
growth-related initiatives, financial position, financing requirements, cash
flow and other factors considered relevant by the Board of Directors.
CAPITAL AND EXPLORATION INVESTING EXPENDITURES
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
2000 1999 1998
($ millions) Goal Actual Actual
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OIL SANDS (EXCLUDING PROJECT MILLENNIUM)
Sustaining capital 56 28 32
Environmental 4 1 4
Heavy oil 21 -- --
Strategic
Production improvements 56 118 81
Expansion 6 46
Steepbank 3 13 192
- -------------------------------------------------------------------------------------------------------------------
140 166 355
- -------------------------------------------------------------------------------------------------------------------
PROJECT MILLENNIUM
Production enhancement phase 11 85 70
Millennium Phase 2 1 015 806 82
- -------------------------------------------------------------------------------------------------------------------
1 026 891 152
- -------------------------------------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
Exploration 52 75 93
Development 77 75 126
Environmental 2 1 2
- -------------------------------------------------------------------------------------------------------------------
Finding and development capital 131 151 221
Coal bed methane 5 2 --
Heavy oil -- 40 10
Other 9 7 11
- -------------------------------------------------------------------------------------------------------------------
145 200 242
- -------------------------------------------------------------------------------------------------------------------
SUNOCO
Refining and distribution 30 18 25
Retail marketing 24 19 28
Environmental 5 3 6
Other 1 2 1
- -------------------------------------------------------------------------------------------------------------------
60 42 60
- -------------------------------------------------------------------------------------------------------------------
CORPORATE
Stuart Oil Shale Project 15 50 127
Other -- 1 --
Alternative and renewable energy 20 -- --
- -------------------------------------------------------------------------------------------------------------------
TOTAL 1 351 1 350 936
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
40 SUNCOR ENERGY INC. 1999 ANNUAL REPORT
<PAGE>
EXHIBIT 4
<PAGE>
[LETTERHEAD]
Consent of Independent Chartered Accountants
We hereby consent to the incorporation, by reference, in the annual report of
Suncor Energy Inc. on Form 40-F, of our report dated January 20, 2000 on our
audits of the consolidated financial statements, including the additional
information provided in Exhibit 1 to Form 40-F, as of December 31, 1999, 1998
and 1997.
"PricewaterhouseCoopers LLP"
Chartered Accountants
Calgary, Alberta
February 24, 2000
<PAGE>
EXHIBIT 5
<PAGE>
LETTER OF CONSENT
TO: Suncor Energy Inc.
The Securities and Exchange Commission
The Securities Regulatory Authorities of each Province of Canada
RE: SUNCOR ENERGY INC.
We refer to the following reports prepared by Gilbert Laustsen Jung Associates
Ltd.:
- - the letter reports dated January 20, 2000, as to the synthetic crude oil
reserves effective December 31, 1999 associated with the Suncor Energy Inc.
oil sands operations located near Fort McMurray, Alberta;
- - the Reserve Determination and Evaluation of the Canadian Oil and Gas
Properties of Suncor Energy Inc. Exploration and Production effective
December 31, 1999, dated January 25, 2000;
- - the Suncor Energy Inc. Exploration and Production Constant Price Analysis
effective December 31, 1999, dated January 13, 2000;
(collectively the "Reports")
We hereby consent to the use of our name, reference to and excerpts from the
said reports by Suncor Energy Inc. in its Annual Information Form for the 1999
fiscal year (AIF), and to the incorporation by reference of the AIF in the
annual report of Suncor Energy Inc. on Form 40-F.
We have read the AIF and have no reason to believe that there are any
misrepresentations in the information contained in it that is derived from our
Reports or that are within our knowledge as a result of the services which we
performed in connection with the preparation of the Reports.
Yours very truly,
GILBERT LAUSTSEN JUNG
ASSOCIATES LTD.
(signed) "Wayne W. Chow"
Wayne W. Chow, P. Eng.
Vice-President
Calgary, Alberta
Date: February 24, 2000
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
SUNCOR ENERGY INC.
Date: March 22, 2000 BY: "JANICE B. ODEGAARD"
------------------------------
JANICE B. ODEGAARD
Corporate Director, Legal
Affairs
