SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 40-F
|
(Check One) |
||
|
|
|
|
|
o |
|
Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934 |
|
|
|
|
|
or |
||
|
|
|
|
|
ý |
|
Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 |
|
For fiscal year ended: |
|
December 31, 2003 |
|
|
|
|
|
Commission File Number: |
|
No. 1-12384 |
|
SUNCOR ENERGY INC. |
||||
|
(Exact name of registrant as specified in its charter) |
||||
|
|
||||
|
Canada |
|
1311,1321,2911, |
|
98-0343201 |
|
(Province or
other |
|
(Primary
standard industrial |
|
(I.R.S. employer |
|
|
|
|
|
|
|
112 - 4th Avenue S.W. |
||||
|
(Address and telephone number of registrant’s principal executive office) |
||||
|
|
|
|
|
|
|
CT Corporation System |
||||
|
(Name, address and telephone number of agent for service in the United States) |
||||
Securities registered pursuant to Section 12(b) of the Act:
|
Title of each class |
|
Name of each exchange on which registered: |
|
|
|
|
|
Common shares |
|
New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
For annual reports, indicate by check mark the information filed with this form:
|
|
ý |
Annual Information Form |
ý |
Annual Audited Financial Statements |
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:
|
Common Shares |
|
December 31, |
|
|
|
|
|
Preferred Shares, Series A |
|
None |
Indicate by check mark whether the registrant by filing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the registrant in connection with such rule.
|
|
Yes |
o |
|
No |
|
ý |
|
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13(a) or 15(d) of the Exchange Act during the proceeding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements in the past 90 days.
|
|
Yes |
ý |
|
No |
|
o |
|
2
ANNUAL INFORMATION FORM
3
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM
February 26, 2004
ANNUAL INFORMATION FORM
TABLE OF CONTENTS
ii
|
Audit Committee Pre-Approval Policies for Non Audit Services |
|
iii
GLOSSARY OF TERMS
Bitumen/Heavy Oil
A naturally occurring viscous tar-like mixture, mainly containing hydrocarbons heavier than pentane, that is not recoverable at a commercial rate in its naturally occurring viscous state through a well without using enhanced recovery methods. When extracted bitumen/heavy oil can be upgraded into crude oil and other petroleum products.
Capacity
Maximum output that can be achieved from a facility in ideal operating conditions in accordance with current design specifications.
Coal Bed Methane
Natural gas produced from wells drilled into a coal formation. Also called coal seam methane.
Conventional Crude Oil
Crude oil produced through wells by standard industry recovery methods for the production of crude oil.
Conventional Natural Gas
Natural gas produced from all geological strata, excluding coal bed methane.
Crude Oil
Unrefined liquid hydrocarbons, excluding natural gas liquids.
Developed Reserves
Developed reserves are those proved reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production.
Downstream
These business segments manufacture, distribute and market refined products from crude oil.
iv
Dry Hole/Well
An exploration or development well determined, on an economic basis, to be incapable of producing hydrocarbons that will be plugged, abandoned and reclaimed.
Gross Production
Suncor’s undivided percentage interest in production/reserves before deducting Crown royalties, freehold and overriding royalty interests.
Gross Wells/Land Holdings
Total number of wells or acres, as the case may be, in which Suncor has an interest.
Heavy Fuel Oil
Residue from refining of conventional crude oil that remains after lighter products such as gasoline, petrochemicals and heating oils have been extracted.
In-situ Oil
In-situ or “in place” refers to methods of extracting heavy crude oil from deep deposits of oil sands with minimal disturbance of the ground cover.
MD&A
Suncor’s Management’s Discussion and Analysis dated February 26, 2004, accompanying its audited consolidated comparative financial statements, notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2003, which MD&A is incorporated by reference herein.
Natural Gas
Hydrocarbons that at atmospheric conditions of temperature and pressure are in a gaseous state.
Natural Gas Liquids
Hydrocarbon products recovered as liquids from raw natural gas by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butane and pentane plus, or a combination thereof.
Net Production/Reserves
Suncor’s undivided percentage interest in total production or total reserves, as the case may be, after deducting Crown royalties and freehold and overriding royalty interests.
v
Net Wells/Land Holdings
Suncor’s undivided percentage interest in the gross number of wells or gross number of acres, as the case may be, after deducting interests of third parties.
Overburden
Material overlying oil sands that must be removed before mining. Consists of muskeg, glacial deposits and sand.
Probable Reserves(1)
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely(2) that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(1) Suncor is subject to Canadian disclosure rules in connection with the reporting of its reserves. However, Suncor has received exemptive relief from Canadian securities administrators permitting it to report its proved reserves in accordance with U.S. disclosure practices. In addition, although U.S. companies do not disclose probable reserves for non-mining properties, Suncor voluntarily discloses its probable reserves for its Firebag in-situ leases as it believes this information is useful to investors. As a result, Suncor's Firebag in-situ reserve estimates may not be directly comparable to those made by U.S. companies.
vi
Proved oil and gas reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty(2) to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved Producing Reserves
Proved producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(2) In estimating Suncor’s proved and probable reserves, Suncor’s independent reserves evaluators, GLJ, have targeted the following levels of certainty: at least 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and at least a 50 % probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. However, as Suncor’s reserves, consistent with industry practice, have been prepared using deterministic, rather than probabilistic methods, GLJ’s estimates do not provide a mathematically derived quantitative measure of probability, although in principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
vii
Reservoir
Body of porous rock containing an accumulation of water, crude oil or natural gas.
Sour Synthetic Crude Oil
Crude oil produced from oil sands that requires only partial upgrading and contains a higher sulphur content than sweet synthetic crude oil.
Sweet Synthetic Crude Oil
Crude oil produced from oil sands consisting of a blend of hydrocarbons resulting from thermal cracking and purifying of bitumen.
Synthetic Crude Oil
Upgraded or partially upgraded crude oil recovered from oil sands including surface mineable oil sands leases and in-situ heavy oil leases.
Undeveloped Oil and Natural Gas Lands
Undeveloped acreage is considered to be lands on which wells have not been drilled or completed to a point that would permit production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves.
Upstream
These business segments include acquisition, exploration, development, production and marketing of crude oil, natural gas and natural gas liquids; and for greater clarity include the production of synthetic crude oil, bitumen and other oil products from oil sands.
Utilization
The average use of capacity taking into consideration planned and unplanned outages and maintenance.
Wells
Development Well
A crude oil or natural gas well drilled in a reservoir known to be productive and expected to produce in the future.
Drilled Well
A well that has been drilled and has a defined status e.g. gas well, shut-in well, producing oil well, producing gas well, suspended well or dry and abandoned well.
viii
Exploratory Well
A well drilled in unproved or semi-proved territory with the intention to discover commercial reservoirs or deposits of crude oil and/or natural gas.
ACCOUNTING TERMS
Barrel of Oil Equivalent (BOE)
Suncor converts natural gas to barrels of oil equivalent (BOE) at a 6:1 ratio (converted on the approximate energy equivalent basis that six million cubic feet of natural gas equals one thousand barrels of oil equivalent). BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Development Costs
Includes all costs associated with moving reserves from other classes such as “proved undeveloped” and “probable” to the “proved developed” class.
Finding Costs
Includes the cost of and investment in undeveloped land, geological and geophysical activities, exploratory drilling and direct administrative costs necessary to discover crude oil and natural gas reserves.
Lifting Costs
Includes all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems.
Operating Working Capital
Current assets (excluding cash and cash equivalents), less current liabilities (excluding short-term debt and current portion of long-term borrowings).
Return on Capital Employed (ROCE)
Net earnings adjusted for after-tax financing expenses (income) for the twelve-month period ended December 31; divided by average capital employed. Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt, less cash and cash equivalents, less capitalized costs related to major projects in progress (as applicable), at the beginning and end of the year, divided by two. See “Non GAAP Financial Measures”, below.
ix
Return on Average Shareholders’ Equity
Net earnings as a percentage of average shareholders’ equity. Average shareholders’ equity is the sum of total shareholders’ equity at the beginning and end of the year, divided by two.
CONVERSION TABLE
|
1 cubic metre m(3) = 6.29 barrels |
|
1 tonne = 0.984 tons (long) |
|
1 cubic metre m(3) (natural gas) = 35.49 cubic feet |
|
1 tonne = 1.102 tons (short) |
|
1 cubic metre m(3) (overburden) = 1.31 cubic yards |
|
1 kilometre = 0.62 miles |
|
|
|
1 hectare = 2.5 acres |
Notes:
(1) Conversion using the above factors on rounded numbers appearing in this Annual Information Form may produce small differences from reported amounts.
(2) Some information in this Annual Information Form is set forth in metric units and some in imperial units.
CURRENCY
All references in this Annual Information Form to dollar amounts are in Canadian dollars unless otherwise indicated.
FORWARD-LOOKING STATEMENTS
This Annual Information Form contains certain forward-looking statements that are based on Suncor’s current expectations, estimates, projections and assumptions that were made by the company in light of its experience and its perception of historical trends.
All statements that address expectations or projections about the future, including statements about Suncor’s strategy for growth, expected and future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and expected impact of future commitments, are forward-looking statements. Some of the forward-looking statements may be identified by words like “expects,” “anticipates,” “plans,” “intends, “believes,” “projects,” “indicates,” “could,” “vision,” “goad,” “target,” “objective” and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor’s actual results may differ materially from those expressed or implied by its forward-looking statements and you are cautioned not to place undue reliance on them.
x
The risks, uncertainties and other factors that could influence actual results include but are not limited to: changes in the general economic, market and business conditions, fluctuations in supply and demand for Suncor’s products, commodity prices and currency exchange rates, Suncor’s ability to respond to changing markets, and to receive timely regulatory approvals, the successful and timely implementation of capital projects including growth projects (for example the Firebag In-situ development and Voyageur) and regulatory projects (for example, the clean fuels refinery modifications projects in Suncor’s downstream businesses); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement of conception of the detailed engineering needed to reduce the margin of error or level of accuracy; the integrity and reliability of Suncor’s capital assets, the cumulative impact of other resource development; future environmental laws, the accuracy of Suncor’s reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners, competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy, the uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures, actions by governmental authorities including the imposition of taxes or changes to fees and royalties, 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. The foregoing important factors are not exhaustive.
Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in Suncor’s MD&A, incorporated by reference herein. Readers are also referred to the risk factors described in other documents Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the Company at 112 – 4th Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, or by email request to info@suncor.com.
References herein to Suncor’s 2003 Consolidated Financial Statements mean Suncor’s audited consolidated comparative financial statements, notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2003.
NON GAAP FINANCIAL MEASURES
Certain financial measures referred to in this AIF that are not prescribed by GAAP, namely, ROCE, cash flow from operations per common share and Oil Sands operating costs, are described and reconciled in the “Non GAAP Financial Measures”, section of MD&A, incorporated by reference herein.
xi
CORPORATE STRUCTURE
Name and Incorporation
Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the Canada Business Corporations Act on August 22, 1979 of Sun Oil Company Limited, incorporated in 1923 and Great Canadian Oil Sands Limited, incorporated in 1953. On January 1, 1989, Suncor amalgamated with a wholly-owned subsidiary under the Canada Business Corporations Act. Suncor’s articles were amended in 1995 to move its registered office from Toronto, Ontario, to Calgary, Alberta, and amended again in April 1997, to adopt its current name, “Suncor Energy Inc.”. In April 1997, May 2000 and May 2002, Suncor’s articles were amended to divide its issued and outstanding shares on a two-for-one basis.
Suncor’s registered and principal office is located at 112 - 4th Avenue, S.W. Calgary, Alberta, T2P 2V5.
In this Annual Information Form, references to “Suncor” or the “Company” include Suncor Energy Inc., its subsidiaries and joint venture investments unless the context otherwise requires.
Intercorporate Relationships
Suncor Energy Inc. has two principal subsidiaries.
Suncor Energy Products Inc. (“SEPI”) (formerly Sunoco Inc.) is an Ontario corporation that is wholly-owned by Suncor Energy Inc.. SEPI refines and markets petroleum products and petrochemicals directly and indirectly through subsidiaries and joint ventures. SEPI operates its retail business under the Sunoco brand in Canada. SEPI is unrelated to Sunoco, Inc. (formerly known as Sun Company, Inc.), headquartered in Philadelphia, Pennsylvania.
Suncor Energy Marketing Inc.(“SEMI”), wholly-owned by SEPI, is incorporated under the laws of Alberta. SEMI markets, mainly to customers in Canada and the United States, the crude oil, diesel fuel and byproducts such as petroleum coke, sulphur and gypsum, produced by Suncor’s Oil Sands business unit. It also markets certain third party products, and procures crude oil feedstocks for Suncor’s downstream businesses. SEMI also has a petrochemical marketing division that holds a 50% interest in Sun Petrochemicals Company, a petrochemical products joint venture. Commencing in 2002, SEMI procures the natural gas supply for Suncor’s Oil Sands and Energy Marketing and Refining (“EM&R”) businesses, and administers Suncor’s energy trading activities. Commencing in 2003, SEMI began marketing certain natural gas produced by Suncor’s Natural Gas (“NG”) business unit.
Suncor has a number of other subsidiary companies. However, the total assets of such subsidiaries combined, and their total sales and operating revenues, do not constitute more than 20 per cent of the consolidated assets, or consolidated sales and operating revenues, respectively, of Suncor.
1
GENERAL DEVELOPMENT OF THE BUSINESS
Overview
Suncor is an integrated energy company, with its corporate headquarters in Calgary, Alberta, Canada. Suncor explores for, acquires, develops, produces and markets crude oil and natural gas, transports and refines crude oil and markets petroleum and petrochemical products. Periodically Suncor also markets third party petroleum products. Suncor also carries on energy trading activities focused principally on buying and selling futures contracts and other derivative instruments based on the commodities Suncor produces. These activities are intended to earn revenues for the Company, optimize returns from assets and improve market intelligence.
Suncor has four principal operating business units. Oil Sands, based near Fort McMurray, Alberta, extracts bitumen from oil sands ore principally through its mining operations, but also periodically acquires bitumen from third parties and, commencing in 2004, through Suncor’s in-situ Firebag operations. The bitumen is then upgraded into sweet and sour crude oil and diesel fuel. Natural Gas (“NG”), based in Calgary, Alberta, explores for, acquires, develops and produces natural gas. The sale of NG’s production provides a price hedge for natural gas purchased for consumption at Suncor’s Oil Sands facility and its refineries in Sarnia, Ontario and near Denver, Colorado. In addition, Suncor’s U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., is acquiring land and exploring for coal bed methane in the United States. Energy Marketing and Refining - Canada (“EM&R”), headquartered in Toronto, Ontario, refines crude oil at Suncor’s refinery in Sarnia, Ontario, into a broad range of petroleum products, and markets the company’s refined products to industrial, wholesale and commercial customers principally in Ontario and Quebec, and to retail customers in Ontario through Sunoco-branded and joint venture operated retail networks. The business also encompasses third party energy marketing activities and energy trading activities. Refining and Marketing – U.S.A. (“R&M”), headquartered in Denver, Colorado transports crude oil on its wholly or partly owned pipelines in Wyoming and Colorado, refines crude oil at Suncor’s refinery in Commerce City, Colorado, near Denver, into a broad range of petroleum products, and markets the company’s refined products to industrial, wholesale and commercial customers principally in Colorado and to retail customers in Colorado through Phillips 66 - branded sites.
While it provides hydrocarbon-based resources for the immediate energy needs of consumers, Suncor also pursues the development of low-emission and no-emission energy sources that have a reduced environmental impact. Segmented financial data for these activities is reported under the results of Suncor’s “Corporate” segment for financial reporting purposes.
In 2003, Suncor produced approximately 251,500 BOE per day, comprised of 220,300 barrels per day (bpd) of crude oil and natural gas liquids and 187 million cubic feet per day of natural gas. In 2002, the most recent period with published results, Suncor was the 7th largest crude oil (approximately 9% of Canada’s crude oil production) and natural
2
gas liquids producer and the 11th largest natural gas producer in Canada.
In 2003, Suncor sold approximately 94,400 bpd (2002 – 91,100 bpd) or 15,000 m3 per day (2002 - 14,500 m3 per day) of refined products, mainly in Ontario but also in the United States and Europe through its EM&R business unit. Suncor’s refined product sales in Ontario represented approximately 19% (2002-17%) of Ontario’s total refined product sales in 2003. Since the August 1, 2003 acquisition of the R&M business, that business sold approximately 56,900 bpd or 9,100 m3 per day of refined products in Colorado, which includes approximately 43,700 bpd or 7,000 m3 per day of light oils (gasoline and distillates). R&M supplies approximately 23% of Colorado’s light oil product demand.
Three-Year History
Oil Sands
Oil Sands Growth Projects. In late 2001, Suncor completed construction of Project Millennium, an expansion of its Oil Sands plant near Fort McMurray, Alberta. The Project Millennium expansion involved an expanded mine, the addition of mining equipment, and twinning of the bitumen extraction and upgrading process through the construction of a second upgrading train (Upgrader #2). The project increased total design capacity of Suncor’s Oil Sands operations to 225,000 bpd. The final capital cost of Project Millennium was $3.4 billion. The capital costs were financed by internally generated cash flow and additional borrowings.
Prior to completion of Project Millennium, Suncor announced a plan to further expand its Oil Sands operations and in 2001 Suncor received regulatory approval to proceed with development of a four-stage in-situ oil sands project on its Firebag oil sands leases (“Firebag”). The approval is conditioned on providing the regulators with project updates at least six months prior to any development on each stage after stage one. Combined with associated investments in the upgrading facility, the first stage of Firebag is expected to contribute to a planned increase in total Oil Sands production capacity to 260,000 bpd in 2005. The first stage of Firebag and the associated addition of a vacuum unit to the Oil Sands Millennium upgrader are estimated to cost approximately $1 billion. Subsequent to the end of 2003, Suncor began upgrading bitumen from the first stage of the Firebag in-situ oil sands development. Firebag stage one is expected to reach full production capacity of 35,000 bpd of bitumen production in 2005.
In late 2001, Suncor issued a public disclosure document for its Voyageur growth strategy, which targets production between 500,000 bpd to 550,000 bpd in 2010 to 2012. When Suncor originally released these plans, the Company stated it would apply for regulatory approval in late 2002. Following initial stakeholder consultation and preliminary engineering, Suncor modified its Voyageur plan, deferring applications for regulatory approval pending development of further details about each stage. Plans for the first stage of Voyageur were submitted to regulators in 2003. On April 3, 2003, Suncor announced details of its first Voyageur development, with plans to spend an estimated $3 billion to further increase production capacity to 330,000 bpd by late 2007. The production increase calls for expansion to Upgrader #2 principally through the addition of a coker unit, and development of three additional stages of Firebag. The $3 billion estimate is preliminary, and is subject to material variances as the plans and the final scope evolve and engineering work progresses to more detailed stages. Suncor’s Board must approve the expansion plan and budget prior to construction beginning. A decision by the Board is expected in November 2004.
3
The final stage of Voyageur, including construction of a third Oil Sands’ upgrader and proportionate increases in bitumen supply, is intended to increase production capacity to 500,000 to 550,000 bpd in the 2010 to 2012 timeframe. Preliminary cost estimates for this stage of production growth have not been announced. Contract costs will ultimately be dependent on engineering, market analysis, stakeholder consultation and an environmental and socio-economic impact assessment. All of this work is in its preliminary stages.
Other Highlights. On December 17, 2002, the Government of Canada announced its ratification of the Kyoto Protocol. For a discussion of the Kyoto Protocol and management’s assessment of its possible impact on Suncor, refer to the “Outlook – Climate Change” section under “Suncor Overview and Strategic Priorities”, in Suncor’s MD&A.
On December 11, 2003, Suncor and Petro-Canada announced a 10-year agreement under which Suncor will process, on a fee for service basis, at least 27,000 bpd of Petro-Canada’s bitumen into sour crude oil and in addition, sell 26,000 bpd of Suncor sour crude to Petro-Canada. Specific pricing terms of the agreement vary according to market conditions. Processing of bitumen and supply of Suncor sour crude oil pursuant to the terms of this agreement is expected to begin in 2008.
On December 18, 2003, Suncor announced it would launch an Environmental Impact Assessment in January 2004 on a proposed extension of its Oil Sands mining operations. The proposed development, an extension of Suncor’s Steepbank Mine, would replace ore production that is expected to be depleted prior to the end of the decade. The proposed extension, which is expected to have an 11-year life, is part of Suncor’s strategy to increase oil production through development of three bitumen sources: surface mining, in-situ development and third party sources. Operation is planned for 2010 with capital development costs currently estimated at $350 million. This estimate is preliminary and subject to material variances as plans advance and engineering work progresses to more detailed levels.
Energy Marketing & Refining - Canada (EM&R)
Sarnia Regional Co-Generation Project - In 2001, EM&R entered into a 20-year energy supply agreement with TransAlta Corporation (“TransAlta”). Under the agreement, the TransAlta Sarnia Regional co-generation Project, a multi-user co-generation project in Sarnia, Ontario, that commenced operation in the fourth quarter of 2002, supplies all of the steam and electricity requirements of EM&R’s Sarnia Refinery. The agreement is expected to help mitigate EM&R’s exposure to increases in energy costs and supply steam to the Sarnia Refinery at a competitive cost, while eliminating the need for EM&R to build its own steam generating boilers.
Sale of Retail Natural Gas Marketing Business - In the second quarter of 2002, to sharpen its focus on refining and marketing, EM&R sold its retail natural gas marketing business, resulting in an after-tax gain of $35 million. EM&R entered the retail natural gas marketing business in 1997. At the time of sale, the business was supplying natural gas to approximately 125,000 commercial and residential customer accounts in Ontario.
Desulphurization Projects - Federal legislation passed in 1999 mandates sulphur levels in gasoline of an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. EM&R finalized an investment plan in 2001 to meet these sulphur content limits. Construction of the 10,250 barrels per day capacity gasoline desulphurization unit was completed in the fourth quarter of 2003 with the unit placed into service before the year-end, at an approximate total installed cost of $40 million.
4
In 2002, the Canadian government passed legislation limiting the concentration of sulphur in diesel fuel produced or imported for use in on-road vehicles to a maximum of 15 ppm, by June 1, 2006. The current maximum is 500 ppm. To meet these requirements, in October 2003, Suncor and Shell Canada Products Inc. (“Shell”) entered into a 20-year agreement under which Suncor will build hydrotreating facilities at its Sarnia refinery to process high-sulphur diesel from both Suncor’s and Shell’s Sarnia refineries, to produce low sulphur diesel in compliance with the new on-road diesel limits. Under the agreement Shell will pay Suncor a processing fee. Operating a single hydrotreating unit, instead of two separate units, is expected to result in cost synergies to Suncor and Shell and environmental benefits for the Sarnia-Lambton community as one larger unit is expected to consume comparatively less energy and have lower greenhouse gas emissions. Engineering and construction details of the new facilities are in development. Subject to regulatory approval, construction of the new diesel desulphurization facilities is expected to begin in 2004, with project completion expected in early 2006.
The on-road diesel desulphurization project is currently estimated to cost $300 million. As this is a preliminary cost estimate, it is subject to change as scope is finalized and detailed engineering is developed. In Suncor’s 2002 Annual Report, the company originally estimated it would cost $225 million to meet diesel desulphurization regulations. The estimate increased after Suncor entered into the agreement with Shell, which required expansion of the project scope to accommodate the higher capacity.
Regulations reducing sulphur in off-road diesel and light fuel oil are also expected to take effect later in the decade. Suncor believes that if the regulations are finalized as currently proposed, the new diesel desulphurization facilities for reducing sulphur in on-road diesel, should also allow it to meet the requirements for reducing sulphur in off-road diesel and light fuel oil.
In combination with the diesel desulphurization project, Suncor is currently assessing plans to modify the Sarnia refinery to permit the processing of additional Oil Sands crude oil. These modifications, as currently envisioned, are expected to increase refinery production capacity by about 10 per cent, and make the refinery more competitive through lower feedstock costs over the long term. Cost estimates for any such modification will be released once preliminary engineering is complete.
Ethanol - Suncor is continuing to review the feasibility of building a proposed ethanol plant in the Sarnia region. The proposed plant would produce approximately 200 million litres of ethanol annually for blending in fuels. The cost of constructing the facility is currently estimated to be $120 million. In February 2004, Suncor announced that its proposal for funding was approved by the federal government Ethanol Expansion Program. Subject to final approvals Suncor will receive a $22 million contribution towards the construction of an ethanol production facility. There are certain performance requirements that will determine if any of these funds may need to be repaid.
Other - In 2001, Suncor commenced an energy marketing business to generate additional income by buying and selling the crude oil and bitumen production of other companies. The activity conducted by this business, which increased Oil Sands revenue by $147 million in 2002, did not have a significant impact on the Company’s earnings or cash flow in 2002. In 2003 this activity, with revenue of $132 million in 2003, was reclassified and is now reported in the EM&R business.
In 2002, Suncor’s Board of Directors approved commencement of energy trading activities and after developing an appropriate control framework, Suncor began limited energy trading activities in November 2002. A separate risk management function monitors practices and policies and provides independent verification and valuation of Suncor’s trading and marketing activities. Trading activities are principally focused on the commodities the Company produces, adding potential for new revenue and
5
providing a new window into energy product markets. Net trading losses (before tax) were negligible for the period ended December 31, 2002 and were $3 million for the period ended December 31, 2003.
Refining & Marketing – U.S.A.
On August 1, 2003, Suncor acquired a Denver-area refinery and related pipeline and retail assets from ConocoPhillips Company (“ConocoPhillips”). The acquisition is expected to provide Suncor with the flexibility to move additional Oil Sands production into the U.S. marketplace. Suncor paid US$150 million (about Cdn$210 million) for the assets, plus the cost of crude oil, product inventories and other closing adjustments, which totaled approximately US$44 million (about Cdn$62 million).
The acquisition includes:
• a 60,000 bpd refinery located in the Denver area;
• 43 Phillips 66 - branded retail stations, primarily in the Denver area, plus contract agreements with approximately 150 Phillips-branded marketer outlets throughout Colorado; and
• the Rocky Mountain and Centennial pipeline systems, located in Wyoming and Colorado. Suncor has 100% ownership of the 480 kilometre (300 mile) Rocky Mountain pipeline system and 65% ownership of the 140 kilometre (87 mile) Centennial pipeline system.
R&M currently estimates it will spend approximately $250 million to $325 million (approximately US$175 million to US$225 million) between 2003 and 2006 to meet requirements of fuels desulphurization legislation and to enable the refinery to integrate about 20,000 bpd of Oil Sands crude oil blends, with up to 15,000 bpd of Oil Sands sour crude oil. The legislation requires lower diesel sulphur levels (15 ppm) by June 2006 and lower gasoline sulphur levels (30 ppm average, 80 ppm cap) by 2009. The environmental permit application for all these proposed changes has been submitted. Construction for the diesel requirements is planned to be completed in early 2006, and includes a new desulphurization unit, a new hydrogen plant and a new tail gas treating unit for the existing sulphur recovery plants, and modifications to other existing units. Current cost estimates are preliminary and will be updated as scope design and engineering work progresses.
Suncor is currently assessing its plans for potential additional refinery modifications post 2006 in order to have the potential to integrate up to an additional 30,000 bpd of Oil Sands crude oil, including additional barrels of Oil Sands sour crude oil. Cost estimates for this project are not yet available.
As part of the agreement to acquire these assets, Suncor assumed obligations of ConocoPhillips at the refinery pursuant to a Consent Decree with the United States Environmental Protection Agency, the United States Department of Justice and the State of Colorado. These obligations are expected to require expenditures between $35 million to $45 million (approximately US$25 million to $30 million) between 2003 and 2006. The expenditures, intended to reduce air emissions at the refinery, are expected to be primarily capital.
With the acquisition of the R&M assets, Suncor assumed a workforce of approximately 585 employees, including about 300 retail employees, and has added approximately 50 employees since the acquisition.
6
Suncor also assumed the existing contract with the local Paper, Allied-Industrial Chemical and Energy Workers International Union, which covers approximately 150 employees at the refinery. This four-year contract is scheduled to expire in January 2006.
Other
Financing Activities
In 2001, Suncor issued $500 million in principal amount of Series 2 6.70% Medium Term Notes with a ten-year maturity.
In January 2002, Suncor issued US$500 million principal amount of 7.15% unsecured Notes due February 1, 2032, to investors in the United States (the “US”) under it’s $1 billion shelf prospectus.
In 2003 Suncor replaced its available credit and term loan facilities of approximately $1.8 billion with new facilities of $1.7 billion. Suncor’s undrawn and uncommitted lines of credit at December 31, 2003 were approximately $1.6 billion. Suncor’s current long-term debt ratings are A- (Standard & Poor’s), A(low) (Dominion Bond Rating Service), and A3 (Moody’s Investors Service). All debt ratings have a stable outlook. In 2003 Moody’s removed its negative outlook in response to Suncor’s debt reduction over the last two years.
In December 2003 Suncor issued US$500 million of 5.95% unsecured Notes under the remaining capacity of its US$1 billion shelf prospectus. Suncor now has utilized the complete capacity that was available under this shelf. The net proceeds of the debt offering, together with borrowings under the company’s available credit and term loan facilities will be used to repay the company’s 7.4% Debentures maturing February 2004 ($125 million) and to redeem the company’s 9.05% and 9.125% Preferred Securities in March 2004 ($276 million and US$162.5 million, respectively).
Other Three Year Highlights
In April 2001, Suncor sold its interest in the Stuart Oil Shale Project to its Australian joint venture co-owners, Southern Pacific Petroleum NL (“SPP”) and Central Pacific Minerals NL (“CPM”) (together, “SPP/CPM”). Suncor’s investment in the Project up to the date of sale, was approximately $285 million, including approximately $10 million invested in SPP/CPM shares. These investments were completely written off by 2002. Under the terms of the sale, Suncor retained a 5% royalty interest in the first stage of the project, and SPP/CPM and Suncor retained worldwide rights to the project technology. Suncor made total payments to SPP/CPM of Aus$7 million (approximately Cdn$5 million) for which Suncor received SPP/CPM shares and options which were subsequently sold or written off.
For further information on developments and issues referred to above and other highlights of 2003, and a discussion of other trends known to Suncor’s management that could reasonably be expected to have a material effect on Suncor, refer to the
7
“Outlook” and other sections of Suncor’s MD&A, and to “Risk/Success Factors” in this Annual Information Form.
NARRATIVE DESCRIPTION OF THE BUSINESS
OIL SANDS
Suncor produces a variety of refinery feedstock and diesel fuel by developing 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 virtually all of Suncor’s conventional and synthetic crude oil production in 2002 and 2003, represent a significant portion of Suncor’s 2003 capital employed (76%)(3), cash flow from operations (2) (78%) and net earnings (81%). These percentages have been determined excluding the corporate and eliminations segment information.
Operations
Suncor’s integrated Oil Sands business involves four operations. Bitumen is supplied from a combination of a mining operation using trucks and shovels, third party bitumen supply and commencing in 2004, supply from the Firebag in-situ operation. Extraction facilities recover the bitumen from the oil sand ore that is mined. A heavy oil upgrading process converts bitumen into crude oil products. Suncor’s energy service needs are met through Oil Sands facilities (operated by TransAlta), that provides steam and electricity to the operations along with energy from TransAlta’s proprietary natural gas fired co-generation plant that commenced operations in 2001. Suncor uses all of the steam and a portion of the power from the TransAlta co-generation facility. Suncor’s energy services facilities primarily use petroleum coke, a by-product of the upgrading process, as fuel. They also consume natural gas.
The first step of the open pit mining operation is to remove the overburden with trucks and shovels to access the oil sands - a mixture of sand, clay and bitumen. Oil sands ore is then excavated, and transported to one of five sizing plants by a fleet of trucks. The ore is dumped into sizers where it is crushed and sent to the ore preparation plants where it is mixed into a hot water slurry and pumped through hydrotransport pipelines to extraction plants on the east and west sides of the Athabasca River. The bitumen begins to separate from the sand as the slurry is pumped through the lines. Bitumen is extracted from the oil sands ore with a hot water process. After the final removal of impurities and minerals, naphtha is added to the bitumen as diluent to facilitate transportation to the upgrading plant. Periodically bitumen is sold rather than being upgraded. In 2003, approximately 6,400 bpd of bitumen were sold, representing approximately three percent of Oil Sands’ 2003 sales. In 2002 bitumen sales of 9,300 bpd represented five percent of Oil Sands’ sales.
After the diluted bitumen is transferred to the upgrading plant, the naphtha is removed and recycled to be used again as diluent. The bitumen is upgraded through a coking and distillation process. The upgraded product, referred to as sour crude oil, is either sold directly to customers or is further upgraded into sweet crude oil by removing the sulphur and nitrogen using a hydrogen treating process. Three separate streams of refined crude oil are produced: naphtha, kerosene and gas oil.
(3) Refer to “Non GAAP Financial Measures” on page xi of this AIF.
8
While there is virtually no finding cost associated with synthetic crude oil, delineation of the resources and development and expansion of production can entail significant outlays of funds. The costs associated with synthetic crude oil production are largely fixed for the same reason and, as a result, operating costs per unit are largely dependent on levels of production. Natural gas is used or consumed in the production of synthetic crude oil, particularly under the steam assisted gravity drainage (SAGD) method of bitumen production from Suncor’s Firebag operations, and accordingly natural gas prices are a key variable component of synthetic crude oil production cost. Operating costs to produce synthetic crude oil are generally higher than lifting and administrative costs to produce conventional crude oil from the Western Canada Sedimentary Basin.
Transportation
Oil Sands entered into a transportation service agreement with a subsidiary of Enbridge for a term that commenced in 1999 and extends to 2028. Under the agreement, Suncor’s initial pipeline capacity was 60,000 bpd in 1999, increasing to 170,000 bpd in 2005, of synthetic crude oil and bitumen from Fort McMurray, Alberta to Hardisty, Alberta. This pipeline, together with Suncor’s proprietary pipeline, is expected to meet Suncor’s anticipated crude oil shipping requirements for expected future production levels up to 2008.
Suncor markets its crude oil product blends for sale and distribution to customers in Canada, the United States and periodically, to offshore markets.
Suncor has a 20 year agreement with TransCanada Pipeline Ventures Limited Partnership (“TCPV”), to provide Suncor with firm capacity on a natural gas pipeline that came into service in 1999. The natural gas pipeline ships natural gas to Suncor’s Oil Sands facility.
Suncor also transports natural gas to its Oil Sands operations on the Suncor-owned and operated Albersun pipeline, constructed in 1968. It extends approximately 300 kilometres south of the plant and connects with the TCPL Alberta intra-provincial pipeline system. The Albersun pipeline has the capacity to move in excess of 100 mmcf/day of natural gas. Suncor arranges for natural gas supply and controls most of the natural gas on the system under delivery based contracts. The pipeline moves natural gas both north and south for Suncor and other shippers. In 2003, throughput on the Albersun pipeline was approximately 50 mmcf/day.
Suncor’s Oil Sands facilities are readily accessible by public road.
Competitive Conditions
Competitive conditions affecting Oil Sands are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.
9
Seasonal Impacts
Severe climatic conditions at Oil Sands can cause reduced production during the winter season and in some situations can result in higher costs.
Sales of Synthetic Crude Oil and Diesel
Aside from on site fuel use, all of Oil Sands’ production is sold to, and subsequently marketed by, Suncor Energy Marketing Inc.
In 1997, Suncor entered into a long-term agreement with Koch Industries Inc. (“Koch”) to supply Koch with up to 30,000 bpd (approximately 14% of Suncor’s average 2003 total production) of sour crude from Suncor’s Oil Sands operation. Suncor began shipping the crude to Koch’s terminal at Hardisty (from which Koch ships the product to its 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 by either party. Neither party has provided notice at this time.
In 2000, Suncor announced a long term sales agreement with Consumers’ Co-operative Refineries Limited (“CCRL”) under which Suncor expected to begin supplying CCRL with 20,000 bpd of sour crude oil production from its Project Millennium expansion facilities by late 2002. After certain construction delays, CCRL began accepting delivery of sour crude in the first quarter of 2003.
Prices for sour crude oil under these agreements are set at agreed differentials to market benchmarks.
In 2001, Suncor announced a long-term agreement with Petro-Canada to supply up to 30,000 barrels per day of diluent to dilute bitumen produced by Petro-Canada. Deliveries under the contract have commenced. The agreement is for four years and may be extended unless terminated by either party. The diluent supply agreement is expected to end when the bitumen processing and sour crude oil supply agreement, described below, takes effect.
Bitumen to feed the planned upgrader expansion is expected to be provided under a processing agreement between Suncor and Petro-Canada, expected to take effect in 2008. Under the agreement, Suncor will process at least 27,000 bpd of Petro-Canada bitumen on a fee for service basis. Petro-Canada will retain ownership to the bitumen and resulting sour crude oil production of about 22,000 bpd. In addition, Suncor will sell an additional 26,000 bpd of Suncor proprietary sour crude oil production to Petro-Canada. Both the processing and sales components of the agreement will be for a minimum 10-year term. This agreement with Petro-Canada is subject to regulatory and Board approvals.
There were no customers that represented 10% or more of Suncor’s consolidated revenues in 2003. There was one customer in 2002 that represented 10% or more of Suncor’s consolidated revenues.
A portion of Oil Sands production is used in connection with Suncor’s Sarnia refining operations. During 2003, the Sarnia refinery processed approximately 10% (2002 -12%) of Oil Sands crude oil production. With the acquisition of the Denver area refinery in August 2003, there were some minor sales volumes to this facility.
10
Environmental Compliance
For a description of the impact of environmental protection requirements on Oil Sands, refer to “Environmental Regulation and Risk” and “Governmental Regulation” in the “Risk/Success Factors” section of this Annual Information Form, and “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies and Estimates” in the “Suncor Overview and Strategic Priorities” section of MD&A.
NATURAL GAS
Suncor’s Natural Gas business, based in Calgary, Alberta, explores for, develops and produces conventional natural gas in western Canada, supplying it to markets throughout North America. The sale of NG’s production provides a price hedge for natural gas purchased for consumption at Suncor’s Oil Sands facility and its refineries in Sarnia, Ontario and near Denver, Colorado. In addition, Suncor’s U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., is acquiring land and exploring for coal bed methane in the United States.
In 2003, natural gas and natural gas liquids accounted for approximately 96% of the NG business unit’s production.
NG’s exploration program is focused on multiple geological zones in three core asset areas: Northern (northeast British Columbia and northwest Alberta), Foothills (western Alberta and portions of northeast British Columbia) and Central Alberta. Suncor drills primarily medium to high-risk wells focusing on prospects that can be connected to existing infrastructure.
During 2003 NG disposed of its interest in Frontier properties (the Arctic and Northwest Territories) including 28 long-term “significant discovery licences”. There was no production from these interests.
Marketing, Pipeline and Other Operations
Suncor operates natural gas processing plants at South Rosevear, Pine Creek, Boundary Lake South, Progress and Simonette with a total design capacity of approximately 206 mmcf/day. Suncor’s capacity interest in these gas processing plants is approximately 128 mmcf/day. Suncor also has varying undivided percentage interests in natural gas processing plants operated by other companies and processing agreements in facilities where it does not hold an ownership interest.
Approximately 75% of Suncor’s natural gas production is marketed under direct sales arrangements to customers in Alberta, British Columbia, eastern Canada, and the United States. Contracts for these direct sales arrangements are of varied terms, with a majority having terms of one year or less, and incorporate pricing which is either fixed over the term of the contract or determined on a monthly basis in relation to a specified market reference price. Under these contracts, Suncor is responsible for transportation arrangements to the point of sale. Some of the direct sales arrangements include some of the natural gas consumed in Suncor’s Oil Sands plant at Fort McMurray and in the EM&R operations.
11
Approximately 25% 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 Suncor’s system sales volumes are contracted to TransCanada Gas Services and Pan-Alberta Gas Ltd. These companies resell this natural gas primarily to eastern Canadian and Midwest and eastern United States markets.
To provide exposure to the Pacific North West and California markets, Suncor has entered into a long-term gas pipeline transportation contract on the National Energy Group Transmission Pipeline (formerly Pacific Gas Transmission).
NG’s conventional crude oil production is generally sold under spot contracts or under contracts that are terminable on relatively short notice. Suncor’s conventional crude oil production is shipped on pipelines operated by independent pipeline companies. The NG business currently has no pipeline commitments related to the shipment of crude oil.
Competitive Conditions
Competitive conditions affecting Suncor’s NG business are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.
Environmental Compliance
For a description of the impact of environmental protection requirements on NG, refer to “Environmental Regulation and Risk” and “Government Regulation” in the “Risk/Success Factors” section of this Annual Information Form, and “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies and Estimates” in the “Suncor Overview and Strategic Priorities” section of MD&A.
ENERGY MARKETING & REFINING - CANADA
Suncor’s EM&R business unit operates a refining and marketing business in Central Canada, and an energy marketing and trading business. Its refinery in Sarnia, Ontario, refines petroleum feedstock from Oil Sands and other sources into gasoline, distillates, and petrochemicals with the majority of them being distributed in its primary market of Ontario. For information about EM&R’s energy marketing business, refer to “Energy Marketing and Refining – Canada (EM&R) Three-Year Highlights”, under the “Other” heading.
Approximately 58% of EM&R’s petroleum products sales in 2003 (2002 – 62%) was sold through a distribution network in Ontario that sells gasoline and diesel fuel to retail customers. Approximately 37% (2002 – 33%) was sold to industrial, commercial, wholesale and refining customers in Ontario and Quebec, representing primarily jet fuels, diesel and gasoline. The remaining 5% (2002 - 5%) represents petrochemical sales to the United States and Europe through Sun Petrochemicals Company, a 50% joint venture between a Suncor subsidiary and a U.S. company.
12
EM&R’s financial reporting is based on its Rack Back / Rack Forward organizational structure. The Rack-Back division procures and refines crude oil and feedstocks, and sells and distributes refined products to the Sarnia refinery’s largest industrial and reseller customers. The Rack-Forward division is comprised of retail operations, retail natural gas marketing (which was sold in the second quarter of 2002), cardlock and industrial / commercial sales, and the UPI Inc. (“UPI”) and Pioneer joint venture businesses. UPI is a joint venture company owned 50% by each of EM&R and GROWMARK Inc., a U.S. Midwest agricultural supply and grain marketing cooperative. Pioneer is a 50% joint venture partnership between EM&R and The Pioneer Group Inc.
Procurement of Feedstocks
EM&R’s refining operation uses both synthetic and conventional crude oil. In 2003, the Sarnia refinery procured approximately 53% (2002 – 58%) of its synthetic crude oil feedstock from Suncor’s Oil Sands production. In 2003, 64% (2002 – 65%) of the crude oil refined at the Sarnia Refinery was synthetic crude oil. The balance of the refinery’s synthetic crude oil, as well as its conventional and condensate feedstocks, were purchased from others under month to month contracts. In the event of a significant disruption in the supply of synthetic crude oil, the refinery has the flexibility to substitute other sources of sweet or sour conventional crude oil.
Suncor procures conventional crude oil feedstock for its refinery primarily from western Canada, supplemented from time to time with crude oil from the United States and other countries. Foreign crude oil is delivered to Sarnia via pipeline from the United States Gulf Coast or via the Interprovincial Pipeline from Montreal. Suncor has not made any firm commitments for capacity on these pipeline systems. Crude oil is procured from the market on a spot basis or under contracts terminable on short notice.
In 1998, EM&R signed a 10-year synergistic feedstock agreement with a Sarnia-based petrochemical refinery, Nova Chemicals (Canada) Ltd. Under this buy/sell agreement, EM&R obtains feedstock that is more suitable for production of transportation fuels in exchange for feedstock more suitable for petrochemical cracking. EM&R also enters into reciprocal buy/sell or exchange arrangements with other refining companies from time to time as a means of minimizing transportation costs, balance product availability and enhance refinery utilization. EM&R also purchases refined products in order to meet customer requirements.
Refining Operations
The Sarnia refinery produces transportation fuels (gasoline, diesel, propane and jet fuel), heating fuels, liquefied petroleum gases, residual fuel oil, asphalt feedstock, benzene, toluene, mixed xylenes and orthoxylene, as well as the petrochemicals A-100 and A-150 that are used in the manufacture of paint and chemicals.
The refinery has the capacity to refine 70,000 bpd of crude oil. Refining sales in 2003 averaged approximately 92,100 bpd (2002 – 91,100) from the Sarnia refinery. The refinery is configured to allow for operational flexibility. In addition to conventional sweet and sour crudes, the refinery is capable of processing sweet synthetic crude oil, which yields a more valuable product mix. A hydrocracker, jet fuel tower and low-sulphur diesel tower further increase the refinery’s ability to produce premium-value transportation fuels, distillates and naphtha, and its flexibility to vary the gasoline/distillate ratio. The hydrocracker has capacity to process approximately 23,300 barrels per day. Additional flexibility in gasoline, octane and petrochemical production is provided by the complementary operations of an alkylation unit with a capacity of 5,400 barrels per day. The alkylation unit produces a high octane gasoline blending component. The petrochemical facilities have a capacity of 13,100 barrels per day and
13
produce benzene, toluene, mixed xylenes, orthoxylene and A-100 and A-150. A gasoline desulphurization unit that came into service in the fourth quarter of 2003 has a capacity to process 10,250 bpd of gasoline components.
The refinery has a cracking capacity of 40,200 barrels per day from a Houdry catalytic cracker (“catcracker”) and a hydrocracker. Approximately 40% of the cracking capacity is attributable to the catcracker, which uses older cracking technology.
In 2003, EM&R completed a planned maintenance shutdown on a portion of the refinery, involving a crude unit, alkylation unit, and the catcracker. In addition, utilization was less than capacity in 2003 primarily due to impacts of a widespread power outage that struck the northeastern United States and southern Ontario in August. As a result, the refinery operated with lower utilization rates in the last two quarters of the year. In 2004 Suncor will, as part of an ordinary course asset review, conduct a study to assess the catcracker. This unit is one of the original refinery assets built in the 1950’s.
Overall, crude utilization averaged 95% for the year, unchanged from 2002. The following chart sets out daily crude input, average refinery utilization rates, and cracking capacity utilization of the Sarnia Refinery over the last two years.
|
Sarnia Refinery Capacity |
|
2003 |
|
2002 |
|
|
|
|
|
|
|
|
|
Average daily crude input (barrels per day) |
|
66,300 |
|
66,400 |
|
|
Average crude utilization rate (%)(1) |
|
95 |
|
95 |
|
|
Average cracking capacity utilization (%)(2) |
|
87 |
|
91 |
|
Notes:
(1) Based on crude unit capacity and input to crude units.
(2) Based on cracking capacity and input to the hydrocracker and catalytic cracker.
The refinery’s steam and electricity needs are currently being met by supply from the Sarnia Regional Co-generation Project. For more details, see the EM&R section under “Three Year Highlights” in this Annual Information Form.
Principal Products
Sales of gasoline and other transportation fuels represented 79% of EM&R’s consolidated operating revenues in 2003 compared to 77% in 2002. Set forth below is information on daily sales volumes and percentage of EM&R’s consolidated operating revenues contributed by product group for the last two years.
14
|
Product: |
|
2003 |
|
2002 |
|
||||
|
|
|
(thousands |
|
(% of |
|
(thousands |
|
(% of |
|
|
Transportation Fuels |
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
|
|
|
|
|
|
|
|
Retail |
|
4.4 |
|
32 |
|
4.5 |
|
33 |
|
|
Joint Ventures |
|
3.1 |
|
18 |
|
3.2 |
|
18 |
|
|
Other |
|
1.1 |
|
11 |
|
1.2 |
|
10 |
|
|
Jet Fuel |
|
0.7 |
|
3 |
|
0.4 |
|
2 |
|
|
Diesel |
|
3.0 |
|
15 |
|
2.9 |
|
14 |
|
|
Sub-total – Transportation Fuels |
|
12.3 |
|
79 |
|
12.2 |
|
77 |
|
|
Petrochemicals |
|
0.8 |
|
5 |
|
0.6 |
|
4 |
|
|
Heating Fuels |
|
0.5 |
|
4 |
|
0.4 |
|
3 |
|
|
Heavy Fuel Oils |
|
0.8 |
|
2 |
|
0.6 |
|
2 |
|
|
Other |
|
0.6 |
|
2 |
|
0.7 |
|
2 |
|
|
Total Refined Products |
|
15.0 |
|
92 |
|
14.5 |
|
88 |
|
|
Other Non-Refined Products(1) |
|
|
|
3 |
|
|
|
6 |
|
|
Energy Marketing & Trading (2) |
|
|
|
5 |
|
|
|
6 |
|
|
Total % |
|
|
|
100 |
|
|
|
100 |
|
Notes:
(1) Includes ancillary revenues including non-fuel retail sales.
(2) Includes all energy marketing and trading revenues.
Principal Markets
Approximately 58% (2002 – 62%) of EM&R’s total sales volumes are marketed through retail networks, including the EM&R Sunoco-branded retail network, joint-venture operated retail stations and cardlock operations. This network is comprised of:
279 (2002 – 287) Sunoco-branded retail service stations
147 (2002 – 148) Pioneer-operated retail service stations
53 (2002 – 50) UPI-operated service stations and a network of 14 bulk distribution facilities for rural and farm fuels
18 (2002 – 18) Sunoco branded Fleet Fuel Cardlock sites
Refined petroleum products (excluding petrochemicals) are marketed under several brands, including the Company’s Canadian “Sunoco” trademark. EM&R’s other principal trademarks include “Ultra 94” in respect of its premium high octane gasoline, and “Gold Diesel” used in respect of its premium low sulphur diesel product.
Approximately 37% (2002 – 33%) of EM&R’s total sales volumes are sold to industrial, commercial, wholesale, and refining customers, primarily in Ontario. EM&R also supplies industrial and commercial customers in Quebec through long-term arrangements with other regional refiners, or through Group Petrolier Norcan Inc., a 25% EM&R-owned fuels terminal and product supply business in Montreal.
EM&R markets toluene, mixed xylenes, orthoxylene and petrochemicals, primarily in Canada and the U.S., through Sun Petrochemicals Company. EM&R has a 50% interest in Sun Petrochemicals
15
Company, a petrochemical marketing joint venture that markets products from EM&R’s Sarnia Refinery and from a Toledo, Ohio, refinery owned by the joint venture partner. Sun Petrochemicals Company markets petrochemicals used to manufacture plastics, rubber, synthetic fibres, industrial solvents and agricultural products, and as gasoline octane enhancers. All benzene production is sold directly to other petrochemical manufacturers in Sarnia.
EM&R’s share of total refined product sales in its primary market of Ontario was approximately 19% in 2003 (2002 – 17%). Transportation fuels accounted for 82% of EM&R’s total sales volumes in 2003 (2002 – 83%); and petrochemicals accounted for 5% (2002 – 4%). The remaining volumes included other refined products such as heating fuels, heavy oils and liquefied petroleum gases, and were sold to industrial users and resellers.
EM&R supplies refined petroleum products to the Pioneer and UPI joint ventures. Suncor has a separate supply agreement with each of UPI and Pioneer. These supply agreements are evergreen, subject to termination only in accordance with the various agreements between the parties.
Transportation and Distribution
EM&R uses a variety of transportation modes to deliver products to market, including pipeline, water, rail and road. EM&R owns and operates petroleum transportation, terminal and dock facilities, including storage facilities and bulk distribution plants in Ontario. The major mode of transporting gasoline, diesel, jet fuel and heating fuels from the Sarnia Refinery to core markets in Ontario is the Sun-Canadian Pipe Line, which is 55% owned by Suncor and 45% owned by another refiner. The pipeline operates as a private facility for its owners. It serves terminal facilities in Toronto, Hamilton and London, and has a capacity of 126,000 bpd (20,000 cubic metres). EM&R utilized 53% of this capacity in 2003. Total utilization of the pipeline was 83% in 2003.
EM&R also has direct pipeline access to petroleum markets in the Great Lakes region of the United States by way of connection to a pipeline system in Sarnia operated by a U.S. based refiner. This link to the U.S. allows EM&R to move products to market or obtain feedstocks/products when market conditions are favourable in the Michigan and Ohio markets.
EM&R believes its own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet its current and foreseeable storage needs.
Competitive Conditions
Competitive conditions affecting Suncor’s EM&R business are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.
16
Environmental Compliance
For a description of the impact of environmental protection requirements on EM&R, please refer to the sections entitled “Outlook” and “Risk/Success Factors Affecting Performance” in the EM&R section of MD&A. Also refer to “Environmental Regulation and Risk” and “Governmental Regulation” in the “Risk/Success Factors” section and the EM&R “Three Year History” section, of this Annual Information Form, and “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies and Estimates” in the “Suncor Overview and Strategic Priorities” section of MD&A.
REFINING & MARKETING – U.S.A.
Suncor’s R&M business unit, which was acquired August 1, 2003, operates a pipeline transportation, refining and marketing business primarily in Colorado and Wyoming. Its Denver area refinery, located in Commerce City, Colorado, has a crude distillation capacity of 60,000 bpd, processing a mixture of Canadian heavy, high sulphur crudes, and domestic heavy, high sulphur and low sulphur crudes. The majority of the refined products from Suncor’s Denver refinery are distributed in its primary market of Colorado.
Approximately 30% of R&M’s petroleum products sales from August 1, 2003 until the end of the year were sold through a distribution network in Colorado that sells gasoline and diesel fuel to retail customers. R&M’s retail network includes 43 Phillips 66-branded company operated sites, as well as contractual agreements with approximately 150 Phillips 66 - branded marketer outlets throughout Colorado. Approximately 51% of R&M’s petroleum product sales were to industrial, commercial, wholesale and refining customers in Colorado, representing primarily jet fuels, diesel and gasoline. Asphalt sales comprise the remaining 19% of R&M’s refined product sales for 2003.
Procurement of Feedstocks
R&M’s refining operation uses conventional crude oil. Approximately 45% of the Denver refinery’s crude oil is purchased from Canadian sources, with the remainder supplied from sources in the United States, primarily in the Rocky Mountain region. The refinery’s crude oil purchase contracts have terms ranging from month-to-month to one year. In the event of a significant disruption in the supply of crude oil, the refinery has the flexibility to substitute other sources of sweet or sour crude oil on a spot purchase basis.
R&M has a processing agreement with a third party refinery located in Cheyenne, Wyoming, that has coking capabilities. Under the agreement, which terminates in May 2004, R&M sends residual coke from its refinery to the third party refinery to be processed into coker gas oil, which is then sent to R&M’s refinery where it can then be further processed into finished products. R&M is currently reviewing options for renewal or replacement of this contract.
17
Refining Operations
The Denver refinery has a crude distillation capacity of 60,000 bpd, processing a mixture of Canadian heavy, high sulphur crudes, and domestic heavy, high sulphur and low sulphur crudes. Upgrading units of the Denver refinery include a 19,000 bpd fluidized catalytic cracker, a 12,500 bpd distillate hydrotreater and a 14,000 bpd gas oil hydrotreater. The refined gasoline products from the Denver refinery supply R&M’s marketing operations in Colorado. Refining sales in 2003 averaged approximately 56,900 bpd (9,100 m3 per day).
The Denver refinery is a high conversion refinery that produces a full range of products, including gasoline, jet fuels, diesel and asphalt. The refinery’s upgrading units enable it to process a crude slate containing nearly 50 percent heavy, high sulphur crude. Overall, crude utilization averaged 98% for the period from August 1, 2003 to December 31, 2003. The following chart sets out daily crude input, average refinery utilization rates and cracking capacity utilization for this five month period.
|
Denver Refinery Capacity |
|
August 1, |
|
|
|
|
|
|
|
Average daily crude input (barrels per day) |
|
58,800 |
|
|
Average crude utilization rate (%)(1) |
|
98 |
|
|
Average fluidized catalytic cracker capacity utilization rate (%)(2) |
|
95 |
|
Notes:
(1) Based on crude unit capacity and input to crude units.
(2) Based on cracking capacity and input to other units or sales made to customers.
18
Principal Products
Sales of gasoline and other transportation fuels represented 85% of R&M’s consolidated operating revenues in the period from August 1, 2003 to December 31, 2003. Set forth below is information on daily sales volumes and percentage of R&M’s consolidated operating revenues contributed by product group for this five-month period.
|
Product: |
|
August 1,
2003 to December 31, |
|
||
|
|
|
(thousands |
|
(% of
R&M’s |
|
|
Transportation Fuels |
|
|
|
|
|
|
Gasoline |
|
|
|
|
|
|
Retail |
|
.7 |
|
13 |
|
|
Other |
|
3.5 |
|
40 |
|
|
Jet Fuel |
|
.5 |
|
6 |
|
|
Diesel |
|
2.3 |
|
26 |
|
|
Total Transportation Fuels |
|
7.0 |
|
85 |
|
|
Asphalt |
|
1.7 |
|
10 |
|
|
Other |
|
.4 |
|
2 |
|
|
Total Refined Product Sales |
|
9.1 |
|
97 |
|
|
Other Non-Refined Product (1) |
|
|
|
3 |
|
|
|
|
|
|
100 |
|
Note:
(1) Ancillary revenues include non-fuel retail sales.
Principal Markets
Approximately 30% of R&M ‘s total sales volumes are marketed through Phillips 66 - branded retail outlets. This network is comprised of:
• 43 owned Phillips 66 - branded retail sites, which account for approximately 9% of R&M’s sales volumes.
• Supply agreements with more than 150 Phillips-66 branded marketer outlets throughout the state of Colorado, which account for approximately 21% of R&M’s sales volumes. These agreements are typically for three year terms with provision for automatic three year renewal periods on an evergreen basis.
Suncor has an exclusive license from ConocoPhillips to use the Phillips 66 and related trademarks and brand names in Colorado from August 1, 2003 until December 31, 2012.
The Denver refinery also supplies all of its asphalt production to KC Asphalt, a joint venture between ConocoPhillips and Koch Industries, Inc. Asphalt sales made up about 19% of R&M’s total 2003 sales volumes.
Approximately 51% of R&M’s total sales volumes are sold to industrial, commercial, wholesale, and
19
refining customers, primarily in Colorado, of which approximately two thirds was sold under a long-term supply agreement with ConocoPhillips in 2003. Under this agreement, R&M supplies ConocoPhillips with gasoline and distillates. Under the terms of the agreement, the supplied volumes are to decrease over time until approximately half of the current volumes will be supplied in the 10th year of the agreement.
R&M estimates its sales of total light fuels refined product in 2003 represented a market share, in its primary market of Colorado, of approximately 23%. Within this market, R&M’s Phillips 66 - branded sites represent a 13% market share.
Transportation and Distribution
Almost all crude oil processed at the Denver refinery is transported via pipeline. R&M owns and operates crude transportation systems from Guernsey, Wyoming to Denver, Colorado. The Rocky Mountain Crude system is a common carrier pipeline that transports crude for the Denver refinery as well as for other shippers. R&M also operates a joint venture crude pipeline from Guernsey, Wyoming to Cheyenne, Wyoming. The joint venture pipeline is approximately 65% owned by Suncor. The other 35% is owned by another area refiner. From August 1, 2003 to December 31, 2003, the Rocky Mountain Crude system utilized more than 100% of capacity due the use of a drag reducing agent, with average throughput of 39,000 barrels per day in the Guernsey to Cheyenne leg of the pipeline, and 70,000 barrels per day in the higher capacity Cheyenne to Denver leg. During the same period, the joint venture pipeline utilized approximately 99% of capacity, with an average throughput of approximately 63,500 barrels per day.
R&M has its own 30,000 bpd capacity truck-loading terminal at the Denver area refinery where customers can pick up product, a one mile long 7,000 bpd jet fuel pipeline that connects to a common carrier pipeline system for deliveries to the Denver International Airport, and a four mile long 14,000 bpd diesel pipeline that delivers diesel product directly to the Union Pacific railroad yard in Denver, Colorado.
R&M believes its own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet its current and foreseeable storage needs.
Competitive Conditions
Competitive conditions affecting Suncor’s Refining & Marketing – U.S.A. business are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.
20
Environmental Compliance
Due to increasingly stringent regulations regarding water discharges, the Denver Refinery will have to add additional water treating equipment for the discharge of process waste water. It is estimated that this will cost approximately $3 million and be completed in the 2006-2008 timeframe. For a description of other impacts of environmental protection requirements on Refining & Marketing – U.S.A., please refer to the R&M section of “Three Year History” of this Annual Information Form, and the sections entitled “Outlook” and “Risk/Success Factors Affecting Performance” in the Refining & Marketing – U.S.A. section of the MD&A. Also refer to “Environmental Regulation and Risk” and “Governmental Regulation” in the “Risk/Success Factors” section of this Annual Information Form, and “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies and Estimates” in the “Suncor Overview and Strategic Priorities” section of MD&A.
RESERVES ESTIMATES
In 2003, Suncor engaged Gilbert Laustsen Jung Associates Ltd. (“GLJ”), independent petroleum consultants, to evaluate, as at December 31, 2003, Suncor’s oil and gas reserves. In reports dated February 20, 2004, GLJ evaluated Suncor’s proved and probable reserves of synthetic crude oil on its oil sands mining leases and in-situ oil sands Firebag leases. Together, these two reports are the “GLJ Oil Sands Reports”. In the GLJ Oil Sands Reports, GLJ estimates Suncor’s gross proved plus probable reserves of synthetic crude oil from oil sands mining and in situ leases total 3.9 billion barrels. This total includes estimates from Suncor’s mining leases that account for 1.8 billion barrels, consisting of 0.9 billion barrels of proved and 0.9 billion barrels of probable reserves, as well as in-situ leases containing 0.4 billion barrels of proved and 1.7 billion barrels of probable reserves. These values are before deduction of Crown and other royalties on the leases. The Oil Sands reserves from both mining and in-situ leases are presented in this paragraph on a gross basis for purposes of showing the aggregate estimate of Oil Sands proved and probable reserves. However, as required by U.S. disclosure practices, reserves from our Firebag in-situ leases are presented under “U.S. Oil and Gas Disclosure” on a net basis and accordingly will not be comparable to the gross reserves total referenced in this paragraph.
GLJ’s estimates consider recovery from leases for which regulatory approvals have been granted. The mining reserve estimates are based upon a detailed geological assessment and also consider industry practice, drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life, and regulatory constraints. For Firebag reserve estimates, GLJ considered similar factors such as Suncor’s regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects, and drill density. Suncor’s proved and probable reserves are contained within the AEUB approval area. Suncor’s proved reserves are delineated with 40 to 80 acre spacing plus 3D seismic control while Suncor’s probable reserves are delineated with 80 to 160 acre spacing plus 3D seismic control. Firebag is currently on production in early 2004. The major facility expenditures to develop Suncor’s proved undeveloped reserves have obtained final approval by the company’s board. Plans to develop the company’s probable undeveloped reserves in subsequent phases are under way but have not yet received final approval from the company’s board.
GLJ also issued a report dated February 20, 2004, with respect to GLJ’s evaluation of Suncor’s proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from Suncor’s mining leases and the Firebag in-situ reserves) (the “GLJ NG Report”) as at December 31, 2003. In the GLJ NG Report, GLJ estimates Suncor’s proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from Suncor’s mining leases and the Firebag in-situ reserves) total 456
21
billion cubic feet (bcf) of natural gas and 8 million barrels of crude oil and natural gas liquids for a total of 84 million barrels of oil equivalent. NG reserves are expressed on a net basis, to exclude interests of third parties, and Crown, freehold and other royalties. Royalties can vary, depending upon selling prices, production volumes, 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.
Suncor’s reserves estimates will continue to be impacted by both drilling data and operating experience, as well as technological developments and economic considerations.
Oil Sands Mining and In-Situ Firebag Reserves Reconciliation
The following table sets out, on a gross(1) basis, a reconciliation of Suncor’s proved and probable reserves of synthetic crude oil from its Oil Sands mining leases and its in-situ Firebag leases, from December 31, 2002 to December 31, 2003, based on the GLJ Oil Sands Reports.
(1) See footnote (4) in the Estimated Proved and Probable Reserves Reconciliation below.
Estimated Proved and Probable Oil Sands Reserves Reconciliation
|
(millions
of barrels of |
|
Oil Sands Mining Leases |
|
In-situ Firebag Leases(2) |
|
Total |
|
||||||||
|
|
|
Proved(3) |
|
Probable |
|
Proved & |
|
Proved(3) |
|
Probable |
|
Proved & |
|
Proved & |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2002 |
|
358 |
|
1,563 |
|
1,921 |
|
144 |
|
1,696 |
|
1,840 |
|
3,761 |
|
|
Revisions of previous estimates |
|
599 |
|
(611 |
) |
(12 |
) |
243 |
|
25 |
|
268 |
|
256 |
|
|
Extensions and discoveries |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
Production |
|
(79 |
) |
— |
|
(79 |
) |
— |
|
— |
|
— |
|
(79 |
) |
|
December 31, 2003 |
|
878 |
|
952 |
|
1,830 |
|
387 |
|
1,721 |
|
2,108 |
|
3,938 |
|
Notes:
(1) Synthetic crude oil reserves based upon a net coker, or synthetic crude oil yield of between 80% and 82%.
(2) Suncor has the option of selling the bitumen production from these leases and/or upgrading the bitumen to synthetic crude oil.
(3) All of Suncor’s proved mining reserves are classified as proved producing reserves. The reclassification of mining reserves from the probable to proved category in 2003, reflects the 2003 drilling program and use of revised criteria for classifying portions of the ore body as proved. All of Suncor’s Firebag In-situ proved reserves are classified as proved non-producing reserves as at December 31, 2003. Subsequent to the end of 2003, Suncor began upgrading bitumen from the first stage of the Firebag in-situ oil sands development. Firebag phase one is expected to reach full production capacity of 35,000 bpd of bitumen production in 2005.
(4) Our Oil Sands reserves from mining leases and in-situ leases are both presented in this reconciliation on a gross basis for purposes of showing the aggregate estimate of Oil Sands proved and probable reserves. However, as required in connection with U.S. disclosure practices, reserves from our Firebag In-situ leases are presented under the heading “U.S. Oil and Gas Disclosure” below on a net basis and accordingly will not be comparable to the gross reserves referenced in this reconciliation.
22
U.S. OIL AND GAS AND MINING DISCLOSURE
|
(millions
of barrels of |
|
Oil Sands Mining Leases |
|
||||
|
|
|
Proved(2) |
|
Probable |
|
Proved & |
|
|
|
|
|
|
|
|
|
|
|
December 31, 2002 |
|
358 |
|
1,563 |
|
1,921 |
|
|
Revisions of previous estimates |
|
599 |
|
(611 |
) |
(12 |
) |
|
Extensions and discoveries |
|
— |
|
— |
|
— |
|
|
Production |
|
(79 |
) |
— |
|
(79 |
) |
|
December 31, 2003 |
|
878 |
|
952 |
|
1,830 |
|
(1) Synthetic crude oil reserves based upon a net coker, or synthetic crude oil yield of 80%.
(2) All of Suncor’s proved mining reserves are classified as proved producing reserves. The reclassification of mining reserves from the probable to proved category in 2003, reflects the 2003 drilling program and use of revised criteria for classifying portions of the ore body as proved.
These mining reserves have been presented on a gross basis, that is before deducting royalties.
The following table sets out certain operating statistics for the Oil Sands mining operations. Statistics for the Oil Sands Firebag in-situ operations are not included but are addressed in the information below under the heading “Proved Conventional Oil and Gas Reserves” and “Sales, Production, Well Data, Land Holdings and Drilling - Conventional”.
|
|
|
2003 |
|
2002 |
|
2001 |
|
|
Total mined volume (millions of tonnes)(1) |
|
316.9 |
|
291.0 |
|
232.2 |
|
|
Mined volume to tar sands ratio(1) |
|
48.1 |
% |
50.6 |
% |
42.2 |
% |
|
Tar sands mined (millions of tonnes) |
|
152.5 |
|
147.3 |
|
97.9 |
|
|
Average bitumen grade (weight%) |
|
11.3 |
|
11.2 |
|
11.1 |
|
|
Crude bitumen in mined tar sands (millions of tonnes) |
|
17.2 |
|
16.6 |
|
10.1 |
|
|
Average extraction recovery% |
|
92.0 |
% |
91.3 |
% |
88.0 |
% |
|
Crude bitumen production (millions of cubic meters)(2) |
|
15.7 |
|
15.0 |
|
8.9 |
|
|
Average upgrading yield% (net) |
|
79.4 |
% |
79.1 |
% |
80.6 |
% |
|
Gross synthetic crude oil produced (thousands of barrels per day)(3) |
|
216.6 |
|
205.8 |
|
123.2 |
|
Notes:
(1) Includes pre-stripping of mine areas and reclamation volumes.
(2) Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.
(3) Cubic meters are converted to barrels at the conversion factor of 6.29.
23
Proved Conventional Oil and Gas Reserves
The following data is provided on a net basis in accordance with the provisions of the Financial Accounting Standards Board’s Statement No. 69 (Statement 69). This statement requires disclosure about conventional oil and gas activities only, and therefore the Company’s Oil Sands mining activities are excluded, while in-situ Firebag reserves are included.
|
|
|
NET PROVED RESERVES |
|
||||||
|
|
|
Crude Oil, Natural Gas Liquids and Natural Gas |
|
||||||
|
|
|
Oil Sands |
|
Natural
Gas |
|
Total |
|
Natural
Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2000 |
|
— |
|
11 |
|
11 |
|
567 |
|
|
Revisions of previous estimates |
|
— |
|
— |
|
— |
|
4 |
|
|
Extensions and discoveries |
|
— |
|
— |
|
— |
|
20 |
|
|
Production |
|
— |
|
(1 |
) |
(1 |
) |
(45 |
) |
|
Sales of minerals in place |
|
— |
|
— |
|
— |
|
(1 |
) |
|
December 31, 2001 |
|
— |
|
10 |
|
10 |
|
545 |
|
|
Revisions of previous estimates |
|
— |
|
— |
|
— |
|
(18 |
) |
|
Extensions and discoveries |
|
124 |
|
1 |
|
125 |
|
39 |
|
|
Production |
|
— |
|
(1 |
) |
(1 |
) |
(48 |
) |
|
Sales of minerals in place |
|
— |
|
— |
|
— |
|
(2 |
) |
|
December 31, 2002 |
|
124 |
|
10 |
|
134 |
|
516 |
|
|
Revisions of previous estimates |
|
224 |
|
(2 |
) |
222 |
|
(50 |
) |
|
Extensions and discoveries |
|
— |
|
1 |
|
1 |
|
40 |
|
|
Production |
|
— |
|
(1 |
) |
(1 |
) |
(50 |
) |
|
Sales of minerals in place |
|
— |
|
— |
|
— |
|
— |
|
|
December 31, 2003 |
|
348 |
|
8 |
|
356 |
|
456 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
|
|
|
|
|
|
|
|
|
December 31, 2000 |
|
— |
|
10 |
|
10 |
|
414 |
|
|
December 31, 2001 |
|
— |
|
8 |
|
8 |
|
416 |
|
|
December 31, 2002 |
|
— |
|
8 |
|
8 |
|
426 |
|
|
December 31, 2003 |
|
77 |
|
6 |
|
83 |
|
403 |
|
All reserves are located in Canada. There has been no major discovery or other favourable or adverse event that caused a significant change in estimated proved reserves since December 31, 2003. The Company has no long-term supply agreements or contracts with governments or authorities in which it acts as producer nor does it have any interest in oil and gas operations accounted for by the equity method.
24
Capitalized Costs Relating to Oil and Gas Activities
|
|
|
For the years ended December 31 |
|
||
|
($millions) |
|
2003 |
|
2002 |
|
|
|
|
|
|
|
|
|
Proved properties |
|
2,525 |
|
1,723 |
|
|
Unproved properties |
|
114 |
|
128 |
|
|
Other support facilities and equipment |
|
18 |
|
16 |
|
|
Total cost |
|
2,657 |
|
1,867 |
|
|
Accumulated depreciation and depletion |
|
(590 |
) |
(532 |
) |
|
Net capitalized costs |
|
2,067 |
|
1,335 |
|
Costs Incurred in Oil and Gas Acquisition, Exploration and Developmental Activities
|
|
|
For the years ended December 31, |
|
||||
|
($millions) |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs |
|
|
|
|
|
|
|
|
Proved properties |
|
— |
|
2 |
|
— |
|
|
Unproved properties |
|
29 |
|
12 |
|
5 |
|
|
Exploration costs |
|
46 |
|
17 |
|
27 |
|
|
Development costs |
|
753 |
|
510 |
|
256 |
|
|
Total capital and exploration expenditures |
|
828 |
|
541 |
|
288 |
|
Results of Operations for Oil and Gas Production
|
|
|
For the years ended December 31, |
|
||||
|
($millions) |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
Sales to unaffiliated customers |
|
319 |
|
200 |
|
286 |
|
|
Transfers to other operations |
|
61 |
|
16 |
|
58 |
|
|
|
|
380 |
|
216 |
|
344 |
|
|
Expenses |
|
|
|
|
|
|
|
|
Production costs |
|
44 |
|
39 |
|
36 |
|
|
Depreciation, depletion and amortization |
|
76 |
|
66 |
|
61 |
|
|
Exploration |
|
86 |
|
27 |
|
31 |
|
|
Gain on disposal of assets |
|
(12 |
) |
(4 |
) |
(8 |
) |
|
Restructuring costs |
|
— |
|
— |
|
(2 |
) |
|
Other related costs |
|
37 |
|
10 |
|
30 |
|
|
|
|
231 |
|
138 |
|
148 |
|
|
Operating profit before income taxes |
|
149 |
|
78 |
|
196 |
|
|
Related income taxes |
|
(40 |
) |
(43 |
) |
(79 |
) |
|
Results of operations |
|
109 |
|
35 |
|
117 |
|
25
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 Statement 69 could produce substantially different results. The Company cautions against viewing this information as a forecast of future economic conditions or revenues, and does not consider it to represent the fair market value of Firebag in-situ and Natural Gas properties. Figures are based on Suncor’s actual year-end commodity prices. Readers are cautioned that commodity prices are volatile. To illustrate this volatility, the following table sets out certain commodity benchmark prices over the past three years:
|
|
|
2003 |
|
2002 |
|
2001 |
|
|
Year end natural gas price assumptions (AECO- CDN$/GJ) |
|
5.28 |
|
5.21 |
|
3.55 |
|
|
Year end crude oil price assumption (WTI US$/bbl) |
|
32.50 |
|
29.40 |
|
19.40 |
|
Actual future net cash flows may differ from those estimated due to, but not limited to, the following:
• Production rates could differ from those estimated both in terms of timing and amount;
• Future prices and economic conditions will likely differ from those at year-end;
• Future production and development costs will be determined by future events and may differ from those at year-end; and
• Estimated income taxes and royalties may differ in terms of amounts and timing due to the above factors as well as changes in enacted rates and the impact of future expenditures on unproved properties.
The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and taking into account the future periods in which they are expected to be developed and produced based on year-end economic conditions. The estimated future production is priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and determinable price escalations provided by contract. At December 31, 2003, no such contractual arrangements existed. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. In addition, the Company has also deducted certain other estimated costs deemed necessary to derive the estimated pretax future net cash flows from the proved reserves including direct general and administrative costs of exploration and production operations and reclamation and environmental remediation costs. Deducting future income tax expenses then reduces the estimated pre-tax future net cash flows further. Such income taxes are determined by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax cash flows relating to the Company’s proved oil and gas reserves less the tax basis of the properties involved. Royalties are determined based upon the appropriate royalty rates and regimes in effect at year end for Firebag and natural gas production, and in the case of Firebag, assumes that Firebag is classified as a separate operation, for royalty purposes, as described in MD&A. (See “Oil Sands Crown Royalties and Cash Income Taxes” in the “Suncor Overview and Strategic Priorities” Section of MD&A). The resultant future net cash flows are reduced to present value amounts by applying the Statement 69 mandated 10% discount factor. The result is referred to as “Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes”.
26
|
($millions) |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
Future cash flows |
|
11,655 |
|
8,964 |
|
2,266 |
|
|
Future production and development costs |
|
(5,141 |
) |
(3,007 |
) |
(652 |
) |
|
Other related future costs |
|
(391 |
) |
(314 |
) |
(283 |
) |
|
Future income tax expenses |
|
(1,694 |
) |
(2,094 |
) |
(521 |
) |
|
Subtotal |
|
4,429 |
|
3,549 |
|
810 |
|
|
Discount at 10% |
|
(2,578 |
) |
(1,822 |
) |
(370 |
) |
|
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes |
|
1,851 |
|
1,727 |
|
440 |
|
|
|
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
|
$ |
|
|
|
|
Balance, beginning of year |
|
1,727 |
|
440 |
|
1,933 |
|
|
Sales and transfers of oil and gas produced, net of production costs |
|
(306 |
) |
(192 |
) |
(297 |
) |
|
Net changes in prices and production costs |
|
(1,023 |
) |
626 |
|
(3,114 |
) |
|
Extensions, discoveries and improved recovery, less related costs |
|
95 |
|
1,387 |
|
23 |
|
|
Development costs incurred during the period |
|
329 |
|
112 |
|
81 |
|
|
Revisions of previous quantity estimates |
|
712 |
|
(45 |
) |
(2 |
) |
|
Accretion of discount |
|
260 |
|
68 |
|
361 |
|
|
Net changes in income taxes |
|
272 |
|
(697 |
) |
1,472 |
|
|
Other |
|
(215 |
) |
28 |
|
(17 |
) |
|
Balance, end of year |
|
1,851 |
|
1,727 |
|
440 |
|
Sales, Production, Well Data, Land Holdings and Drilling - Conventional
The following tables set out additional information on the Company’s conventional oil and gas producing activities. Information with respect to Suncor’s Oil Sands mining operations is not covered by the information below but is addressed in the information above under “Oil Sands Mining Operations”.
Sales Prices(1) (Based on working interest production before royalties)
|
|
|
Average Sales Price(2) |
|
||||
|
|
|
2003 |
|
2002 |
|
2001 |
|
|
Crude Oil ($/bbl) |
|
40.29 |
|
31.72 |
|
33.92 |
|
|
NGL ($/bbl) |
|
36.08 |
|
29.35 |
|
34.38 |
|
|
Natural Gas ($/mcf) |
|
6.42 |
|
3.91 |
|
6.09 |
|
Notes:
(1) Production is based in Western Canada.
(2) Prices are calculated using our working interest production after royalties.
27
Production Costs
|
($ per BOE of gross production) |
|
2003 |
|
2002 |
|
2001 |
|
|
Average production (lifting) cost of conventional crude oil and gas(1) |
|
3.48 |
|
3.15 |
|
2.96 |
|
Note:
(1) Production (lifting) costs include all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems. It does not include an estimate for future reclamation costs. As Suncor’s Firebag in-situ leases were not in commercial operations for the year-end December 31, 2003, the above production costs only include the costs associated with Suncor’s Natural Gas business.
Producing Oil and Gas Wells
|
|
|
2003 |
|
||||||||||
|
|
|
Crude Oil |
|
Natural Gas |
|
Total |
|
||||||
|
|
|
Gross(1) |
|
Net(2) |
|
Gross(1) |
|
Net(2) |
|
Gross(1) |
|
Net(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alberta |
|
40 |
|
28 |
|
316 |
|
180 |
|
356 |
|
208 |
|
|
British Columbia |
|
22 |
|
10 |
|
53 |
|
25 |
|
75 |
|
35 |
|
|
Total |
|
62 |
|
38 |
|
369 |
|
205 |
|
431 |
|
243 |
|
Notes:
(1) Gross wells are the total number of wells in which an interest is owned.
(2) Net wells are the sum of fractional interests owned in gross wells.
(3) As Suncor’s Firebag in-situ leases were not in commercial operation for the years ended December 31, 2003 and 2002, well information only includes wells associated with Suncor’s Natural Gas business.
Oil and Gas Acreage
|
(thousands of acres) |
|
2003 |
|
||||||||||
|
|
|
Developed |
|
Undeveloped(1) |
|
Total |
|
||||||
|
|
|
Gross(1) |
|
Net(2) |
|
Gross(1) |
|
Net(2) |
|
Gross(1) |
|
Net(2) |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
663 |
|
531 |
|
542 |
|
428 |
|
1,205 |
|
959 |
|
|
Firebag |
|
1 |
|
1 |
|
290 |
|
290 |
|
291 |
|
291 |
|
|
Total |
|
664 |
|
532 |
|
832 |
|
718 |
|
1,496 |
|
1,250 |
|
Notes:
(1) Undeveloped acreage is considered to be those on which wells have not been drilled or completed to a point that would permit production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves. Gross acres means all the acres in which Suncor has either an entire or undivided percentage interest in.
(2) Net acres represents the acres remaining after deducting the undivided percentage interest of others from the gross acres.
28
Drilling Activity
|
(number of net wells) |
|
2003 |
|
||||||||||
|
|
|
Net Exploratory |
|
Net Development |
|
||||||||
|
|
|
Productive |
|
Dry Holes |
|
Total |
|
Productive |
|
Dry Holes |
|
Total |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
3 |
|
6 |
|
9 |
|
17 |
|
4 |
|
21 |
|
|
Firebag |
|
— |
|
— |
|
— |
|
20 |
|
— |
|
20 |
|
|
Total |
|
3 |
|
6 |
|
9 |
|
37 |
|
4 |
|
41 |
|
|
(number of net wells) |
|
2002 |
|
||||||||||
|
|
|
Net Exploratory |
|
Net Development |
|
||||||||
|
|
|
Productive |
|
Dry Holes |
|
Total |
|
Productive |
|
Dry Holes |
|
Total |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
2 |
|
4 |
|
6 |
|
18 |
|
4 |
|
22 |
|
|
Firebag |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
Total |
|
2 |
|
4 |
|
6 |
|
18 |
|
4 |
|
22 |
|
|
(number of net wells) |
|
2001 |
|
||||||||||
|
|
|
Net Exploratory |
|
Net Development |
|
||||||||
|
|
|
Productive |
|
Dry Holes |
|
Total |
|
Productive |
|
Dry Holes |
|
Total |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
4 |
|
2 |
|
6 |
|
16 |
|
2 |
|
18 |
|
|
Firebag |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
Total |
|
4 |
|
2 |
|
6 |
|
16 |
|
2 |
|
18 |
|
At December 31, 2003, the company was participating in the drilling of 15 gross (8 net) exploratory and development wells.
Future Commitments to Sell or Deliver Crude Oil and Natural Gas
The Company’s Natural Gas business has entered into a number of natural gas sale commitments aggregating approximately 62 mmcf/day. These sales commitments consist of both short-and long-term contracts ranging from one year and for one agreement, for the life of a specified production field. All production comes from Suncor’s reserves. All pricing under these agreements is based upon both a combination of variable, fixed and index-based terms.
Oil Sands has also entered into long-term contracts to sell crude oil products to customers, some of which are described under the heading, “Sales of Synthetic Crude Oil and Diesel” in the “Oil Sands” section of this Annual Information Form. In addition, the Company enters into crude oil, and periodically foreign currency swap and option contracts to protect its future Canadian dollar earnings and cash flows from the potential adverse impact of low petroleum prices and an unfavourable U.S./Canadian dollar exchange rate. For further particulars of these hedging arrangements, see the information under the heading “Derivative Financial Instruments”, under “Risk/Success Factors Affecting Performance” in the “Suncor Corporate Overview and Strategic Priorities” section of the Company’s MD&A, and Note 6 to Suncor’s 2003 Consolidated Financial Statements, which note is incorporated by reference herein.
29
SUNCOR EMPLOYEES
The following table shows the distribution of employees among Suncor’s four business units and its corporate office for the past two years.
|
|
|
as at |
|
||
|
|
|
2003 |
|
2002 |
|
|
|
|
|
|
|
|
|
Oil Sands |
|
2,390 |
|
2,324 |
|
|
Natural Gas |
|
187 |
|
191 |
|
|
Energy Marketing & Refining – Canada(1) |
|
555 |
|
576 |
|
|
Marketing & Refining – U.S.A. |
|
633 |
|
— |
|
|
Corporate (2) |
|
496 |
|
331 |
|
|
Total (3) |
|
4,261 |
|
3,422 |
|
Notes:
(1) Excludes joint venture employees.
(2) The increase in 2003 numbers principally reflect the addition of in-house engineering, procurement, construction and project management personnel.
(3) In addition to Suncor employees, independent contractors supply a range of services to the Company.
The Communications, Energy and Paperworkers Union Local 707 represents approximately 1,500 Oil Sands employees. Suncor entered into a three-year collective agreement with the union effective May 1, 2004. The terms of the agreement include a 9.5 per cent wage increase over a three-year term.
Employee associations represent approximately 170 of EM&R’s Sarnia refinery and Sun-Canadian Pipe Line Company employees. In March 2002, a three-year agreement was signed with the Sarnia employee association that will be renegotiated in 2005. The agreement with the employee association of Sun-Canadian Pipe Line Company was signed in 1993, and it is renewed automatically each year unless terminated by written notice by either party at least 60 days prior to the anniversary date of the agreement. No notice under such agreement has been received or given to date. Management believes the agreement will be automatically renewed on its anniversary. The National Automobile, Aerospace, Transportation and General Workers Union of Canada (CAW-Canada) Local 27 represents three employees at EM&R’s London Terminal. A three year agreement was signed with the CAW-Canada effective April 1, 2003. Management believes Suncor’s positive working relationship with these unions and associations will continue.
The local Paper, Allied-Industrial Chemical and Energy Workers International Union, represents approximately 150 employees at R&M’s Denver area refinery. A four-year contract, assumed from ConocoPhillips in August 2003, will expire in January 2006.
30
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 prices of these commodities can be influenced by global and regional supply and demand factors. Worldwide economic growth, political developments, compliance or non-compliance with quotas imposed upon members of the Organization of Petroleum Exporting Countries and weather, among other things, can affect world oil supply and demand. Natural gas prices realized by Suncor are affected primarily by North American supply and demand and by prices of alternate sources of energy. All of these factors are beyond Suncor’s control and can result in a high degree of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials between heavy and light grades of crude oil, which can impact prices for sour crude 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 and natural gas prices could affect the value of Suncor’s crude oil and gas properties and the level of spending on growth projects, and could result in curtailment of production at some properties. Accordingly, low crude oil prices in particular could have an adverse impact on Suncor’s financial condition and liquidity and results of operations. A key component of Suncor’s business strategy is to produce sufficient natural gas to meet or exceed internal demands for natural gas purchased for consumption in its operations, creating a price hedge which reduces Suncor’s exposure to gas prices volatility. However, there are no assurances that the Company will be able to continue to increase production to keep pace with growing internal natural gas demands.
Suncor cannot control the factors that influence supply and demand for, or the prices of, crude oil or natural gas. However, the Company has a hedging program that fixes the price or a range of prices for its crude oil, natural gas, and periodically the associated Canada/U.S. dollar exchange rate for a percentage of Suncor’s total production volume. Suncor’s objective is to manage exposure to market volatility and lend more certainty to the Company’s ability to finance growth. If an operational upset occurred that reduced or eliminated crude oil and/or natural gas production for a period of time, Suncor would be required to continue to make payments under its hedging program if the actual price was higher than the hedged price. In addition, Suncor’s hedging program is subject to many of the risks described under the heading, “Risks Associated with Energy Trading Activities”, below. For particulars of Suncor’s hedging position as of year-end 2003, see Note 6 of Suncor’s 2003 Consolidated Financial Statements, which note is incorporated by reference herein, as well as Risk/Success Factors Affecting Performance in the Corporate Overview Section of MD&A.
Suncor conducts an assessment of the carrying value of its assets to the extent required by Canadian generally accepted accounting principles. If crude oil and natural gas prices decline, the carrying value of Suncor’s assets could be subject to downward revisions, and Suncor’s earnings could be adversely affected.
31
Volatility of Downstream Margins. EM&R and R&M operations are sensitive to wholesale and retail margins for their 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. EM&R and R&M expect that margin and price volatility and overall marketplace competitiveness, including the potential for new market entrants, will continue. As a result, our operating results for EM&R and R&M can be expected to fluctuate.
Major Projects. There are certain risks associated with the execution of Suncor’s major projects, including without limitation, each of the Firebag stages, the Voyageur growth strategy, and the “clean fuels” environmental capital projects in Suncor’s downstream businesses. These risks include: Suncor’s ability to obtain the necessary environmental and other regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; Suncor’s ability to finance growth if commodity prices were to stay at low levels for an extended period; the impact of new entrants to the oil sands business which could take the form of competition for skilled people, increased demands on the Fort McMurray, Alberta infrastructure (for example, housing, roads and schools) and price competition for products sold into the marketplace; the potential ceiling on the demand for synthetic crude oil; and the effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment. The commissioning and integration of new facilities with the existing asset base could cause delays in achieving targets and objectives. Suncor management believes the execution of major projects presents issues that require prudent risk management. There are also risks associated with project cost estimates provided by Suncor. Some cost estimates are provided at the conceptual stage of projects and prior to commencement or completion of the final scope design and detailed engineering needed to reduce the margin of error. Accordingly, actual costs can vary from estimates and the variances can be material.
In-situ Extraction. Current steam-assisted gravity drainage (SAGD) technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam which is used in the recovery process. The amount of steam required in the production process can also vary and impact costs. The performance of the reservoir can also impact the timing and levels of production using this technology. Suncor has been advised by GLJ that in 2003, a number of operational commercial SAGD projects were in service, although no such projects have been operational for any extended period of time. Commercial application of this technology is not yet commonplace and accordingly in the absence of operating history there can be no assurances with respect to the sustainability of SAGD operations.
32
Increased Dependence on Oil Sands business. The Company’s significant capital commitment to further its growth projects at Oil Sands, including Firebag and if approved, Voyageur, may require Suncor to forego investment opportunities in other segments of its operations. The completion of future projects to increase production at Oil Sands will further increase the Company’s dependence on the Oil Sands segment of its business. For example, in 2003, the Oil Sands business accounted for approximately 86% (86% in 2002) of Suncor’s upstream production, 81% (89% in 2002) of Suncor’s net earnings and 78% (85% in 2002) of Suncor’s cash flow from operations(4). These percentages have been determined excluding the corporate and eliminations segment information.
Interdependence of Oil Sands Systems. The Oil Sands plant is susceptible to loss of production due to the interdependence of its component systems. Through growth projects, Suncor expects to mitigate adverse impacts of its interdependent systems and to reduce the production and cash flow impacts of complete plant-wide shutdowns. For example, Millennium added a second complete processing operation, which provides Suncor with the flexibility to conduct periodic plant maintenance on one operation while continuing to generate production and cash flow from the other.
Competition. The petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of crude oil and natural 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 believes the competition for its crude oil production is other Canadian conventional and synthetic sweet and sour crude oil producers.
A number of other companies have entered or have indicated they are planning to enter the oil sands business and begin production of bitumen and synthetic crude oil, or expand existing operations. It is difficult to assess the number, level of production and ultimate timing of all of the potential new producers or where existing production levels may increase. Based on management’s knowledge of other projects derived from publicly available information, Canada’s production of bitumen and upgraded synthetic crude oil could increase from approximately 925,000 bpd to almost two and a half million bpd by the end of the decade. The trend toward industry consolidation has created more competitors with financial capacity who may enter into similar and competing oil sands businesses. The expansion of existing operations and development of new projects could materially increase the supply of bitumen and synthetic crude oil and other competing crude oil products in the marketplace. Depending on the levels of future demand, increased supplies could have a negative impact on prices.
In the western Canadian diesel fuel market demand and supply can fluctuate. Margins for diesel fuel are typically higher than the margins for synthetic and conventional crude oil. The above noted expansion plans of Suncor’s competitors could result in an increase in the supply of diesel fuel and weaken margins.
(4) Refer to “Non GAAP Financial Measures” on page xi of this AIF.
33
Historically, the industry-wide oversupply of refined petroleum products and the overabundance of retail outlets have kept pressure on downstream margins. Management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. In addition, to the extent that Suncor’s downstream business units, EM&R and R&M, participate in new product markets, they could be exposed to margin risk and volatility from either cost and/or selling price fluctuations.
Need to Replace Conventional Natural Gas Reserves. Future natural gas reserves and production of the Company’s NG business unit are highly dependent on its success in discovering or acquiring additional reserves and exploiting its current reserve base. This impacts both Suncor’s cash flow from such production and its ability to maintain a price hedge against growing consumption of natural gas in its operations. Without natural gas reserve additions through exploration and development or acquisition activities, Suncor’s conventional natural gas reserves and production will decline over time as reserves are depleted. For example, in 2003, Suncor’s average natural gas reservoir decline rates were in the 24% range (2002 – 25%). Decline rates will vary with the nature of the reservoir, life-cycle of the well, and other factors. Therefore past decline rates are not necessarily indicative of future performance. Exploring for, developing and acquiring reserves is highly capital intensive. To the extent cash flow from operations(3) is insufficient to generate sufficient capital and external sources of capital become limited or unavailable, Suncor’s ability to make the necessary capital investments to maintain and expand its conventional natural gas reserves could be impaired. In addition, the long term performance of Suncor’s NG business 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.
Coal Bed Methane. Coal Bed Methane (CBM) exploration is being undertaken by Suncor in Canada, and in the U.S. through a wholly owned subsidiary, Suncor Energy (Natural Gas) America Inc. The identification of gas in coals is necessary but not sufficient for establishing commercial success. Effective production technology, water handling, well productivity and surface access, a requirement for large land blocks, and a pilot production period are risk elements unique to CBM. Other Canadian producers’ activities in CBM have progressed to the pilot test stage with several projects that have wells producing saleable gas. Suncor views the ultimate viability and profitability of these plays as uncertain.
CBM is a commercial gas resource in the U.S. The risks associated with CBM activities in the U.S. vary by geographic region but can include: constraints on land access from federal, state and individual land holders; local opposition to well drilling and CBM development; high costs of treating water produced with CBM gas development; limited regional pipeline exit capacity; and strong competition for mineral leases and services. The regulatory framework and stakeholder environment varies by region. The physical
34
operation of drilling and ultimately producing gas in a location distant from Suncor’s key management presents risks of inadequate oversight of operations. Business activity in the U.S. has different political risks than in Canada, and is conducted in an environment where litigation and legal risk are more prevalent and substantial.
Operating Hazards and Other Uncertainties. Each of Suncor’s four principal businesses, Oil Sands, NG, EM&R, and R&M require high levels of investment and have particular economic risks and opportunities. Generally, Suncor’s operations are subject to hazards and risks such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts, power outages and oil spills, any of which can cause personal injury, damage to property, equipment and the environment, as well as interrupt operations. In addition, all of Suncor’s operations are subject to all of the risks normally incident to the transportation, processing and storing of crude oil, natural gas and other related products.
(3) Refer to “Non GAAP Financial Measures” on page xi of this AIF
At Oil Sands, mining oil sands and producing bitumen through in-situ methods, extracting bitumen from the oil sands, and upgrading bitumen into synthetic crude oil and other products, involves particular risks and uncertainties. Oil Sands is susceptible to loss of production, slowdowns, shutdowns, or restrictions on its ability to produce higher value products due to the interdependence of its component systems. Severe climatic conditions at Oil Sands can cause reduced production during the winter season and in some situations can result in higher costs. While there is virtually no finding cost associated with oil sands resources, delineation of the resources, the costs associated with production, including mine development and drilling of wells for SAGD operations, and the costs associated with upgrading bitumen into synthetic crude oil, can entail significant capital outlays. The costs associated with production at Oil Sands are largely fixed and, as a result, operating costs per unit are largely dependent on levels of production.
There are risks and uncertainties associated with NG’s operations including all of the risks normally incident to drilling for natural gas wells, the operation and development of such properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution, and other environmental risks.
Suncor’s downstream business units, EM&R and R&M are subject to all of the risks normally incident to the operation of a refinery, terminals and other distribution facilities, as well as service stations, including loss of product or slowdowns due to equipment failures or other accidents.
Although Suncor maintains a risk management program, including an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable. Losses resulting from the occurrence of these risks could have a material adverse impact on Suncor. Refer to note 10(b) to Suncor’s 2003
35
Consolidated Financial Statements, which is incorporated by reference herein, for further description of Suncor’s insurance coverage.
Land Claims. First Nations peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Certain First Nations peoples have filed a claim against the Government of Canada, certain governmental entities and the Regional Municipality of Wood Buffalo (which includes the city of Fort McMurray, Alberta), claiming, among other things, a declaration that the plaintiffs have aboriginal title to large areas of lands surrounding Fort McMurray, including the lands on which Oil Sands and most of the other oil sands operations in Alberta are situated. In addition, First Nations peoples have filed claims against industry participants generally, relating in part to land claims which may affect Suncor’s Natural Gas business. Suncor is unable to assess the effect, if any, these claims would have on its Oil Sands or other operations. Other than these claims, to Suncor’s knowledge the First Nations peoples have asserted no other land claims against Suncor.
Technology Risk. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies, such as in-situ technology, cannot be assured.
Risks of International Investments. There are also inherent risks, including political and foreign exchange risk, in investing in business ventures internationally. Suncor’s capital projects planned for the R&M business are expected to be partially funded from Canadian operations. A weaker Canadian dollar relative to the U.S. dollar would result in a higher funding requirements for these projects. However, a weaker Canadian dollar would positively impact the Canadian dollar value of earnings from R&M. (See “Exchange Rate Fluctuations”, below). Other than the R&M business, Suncor does not have material international investments, although it continues to assess downstream integration and coal bed methane opportunities in the U.S.
Interest Rate Risk. Suncor is exposed to fluctuations in short-term Canadian interest rates as a result of the use of floating rate debt. Suncor maintains a substantial portion of its debt capacity in revolving, floating rate bank facilities and commercial paper, with the remainder issued in fixed rate borrowings. To minimize its exposure to interest rate fluctuations, Suncor occasionally enters into interest rate swap agreements and exchange contracts to either effectively fix the interest rate on floating rate debt or to float the interest rate on fixed rate debt. For more details, see the “Liquidity and Capital Resources” section of MD&A.
Exchange Rate Fluctuations. Suncor’s 2003 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, and a significant portion of Suncor’s debt is denominated in U.S. dollars. Crude oil and natural gas prices are generally based in U.S. dollars, while a large portion of Suncor’s sales of refined products are in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollar may therefore give rise to foreign currency exposure, either favorable
36
or unfavorable, creating another element of uncertainty. In the future, the strength of the Canadian dollar relative to foreign currencies could create additional uncertainties for Suncor.
Environmental Regulation and Risk. Environmental regulation affects nearly all aspects of Suncor’s operations. These regulatory regimes are laws of general application that apply to Suncor in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require Suncor to obtain operating licenses and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are required before initiating most new major projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, Suncor expects future changes to environmental legislation, including anticipated legislation to implement Canada’s ratification of the Kyoto Accord, will impose further requirements on companies operating in the energy industry. Some of the issues that are or may in future be subject to environmental regulation include the possible cumulative impacts of oil sands development in the Athabasca region; storage, treatment, and disposal of hazardous or industrial waste; the need to reduce or stabilize various emissions to air and discharges to water; issues relating to global climate change, land reclamation and restoration; Great Lakes water quality; and reformulated gasoline to support lower vehicle emissions (For example, see the discussion relating to Suncor’s clean fuels capital projects, under the “Three Year Highlights” section of this AIF.). Changes in environmental regulation could have a potentially adverse effect on Suncor from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on Suncor. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Compliance with environmental regulation can require significant expenditures and failure to comply with environmental regulation may result in the imposition of fines and penalties, liability for clean up costs and damages and the loss of important permits.
Suncor is required to and has posted annually with Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced as of December 31, 2003 ($14 million as at December 31, 2003) as security for the estimated cost of its reclamation activity on Leases 86 and 17. For the Millennium and Steepbank mines, Suncor has posted an irrevocable letter of credit equal to approximately $54 million, representing security for the estimated cost of reclamation activities up to the end of December 2003. For Firebag, Suncor has posted an irrevocable letter of credit equal to approximately $5 million, representing security for the estimated cost of reclamation activities relating to Firebag up to the end of December 2003. For more information about Suncor’s reclamation and environmental mediation obligations, refer to “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies” in the “Suncor Overview and Strategic Priorities” section of MD&A.
Over the past few years, legislation has been passed in Canada and the United States to reduce permitted levels of sulphur in transportation fuels. For a discussion of projects planned or underway at Suncor’s EM&R and R&M operations, see the information under the EM&R and R&M sections of “Narrative Description of the Business”, and under “Three Year Highlights”, in this Annual Information Form. Projects to retrofit existing facilities to comply with these standards are subject to all risks inherent in large capacity projects, and to the additional risk that failure to meet legislated deadlines
37
could have a material impact on the Company’s ability to market its products, potentially having a material impact on revenues and earnings.
Uncertainty of Reserve and Resource Estimates. The reserves data and resource estimates for Suncor’s Oil Sands and Natural Gas (NG) business units, included in Suncor’s Annual Information Form, represent estimates only. There are numerous uncertainties inherent in estimating quantities and quality of these proved and probable reserves and resources, including many factors beyond the control of Suncor.
In general, estimates of economically recoverable reserves are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effect of regulation by governmental agencies, future royalties and future operating costs, all of which may vary considerably from actual results. The accuracy of any reserve estimate is a matter of engineering interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time. In the Oil Sands business unit, reserve and resource estimates are based upon a geological assessment, including drilling and laboratory tests, and also consider current production capacity and upgrading yields, current mine plans, operating life and regulatory constraints. The Firebag reserves and resource estimates are based upon a geological assessment of data gathered from evaluation drilling, the testing of core samples and seismic operations and demonstrated commercial success of the in-situ process. In the NG business unit, reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. For these reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, and in NG the classification of such reserves based on risk of recovery prepared by different engineers or by the same engineers at different times, may vary substantially. At Oil Sands, the independent evaluation of mining reserves does not take into account the economic aspects of future reserves. Suncor’s actual production, revenues, royalties, taxes and development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material.
Although Suncor is subject to Canadian disclosure rules in connection with the reporting of its reserves, Suncor has received exemptive relief from Canadian securities administrators permitting it to report its proved reserves in accordance with U.S. disclosure practices. In addition, although U.S. companies do not disclose probable reserves or resources for non-mining properties, Suncor voluntarily discloses its probable reserves and resources for its Firebag in-situ leases as it believes this information is useful to investors. As a result, Suncor’s Firebag in-situ estimates may not be directly comparable to those made by U.S. companies.
Labour Relations. Suncor’s hourly employees at its Oil Sands facility near Fort McMurray, its London terminal operation, its Sarnia refinery, its Denver refinery, and Sun-Canadian Pipeline Company are represented by labour unions or employee associations. Any work interruptions involving Suncor’s employees, or contract trades utilized in its projects or operations, could materially and adversely affect Suncor’s business and financial position.
Energy Trading Activities. The nature of trading activities creates exposure to financial risks. These include risks that movements in prices or values will result in a financial
38
loss to the Company; a lack of counterparties will leave the Company unable to liquidate or offset a position, or unable to do so at or near the previous market price; the Company will not receive funds or instruments from its counterparty at the expected time; the counterparty will fail to perform an obligation owed to the Company; the Company will suffer a loss as a result of human error or deficiency in its systems or controls; or the Company will suffer a loss as a result of contracts being unenforceable or transactions being inadequately documented. A separate risk management function within Suncor develops and monitors practices and policies and provides independent verification and valuation of Suncor’s trading and marketing activities. However, Suncor may experience significant financial losses as a result of these risks.
Governmental Regulation. The oil and gas industry in Canada and the United States, including the oil sands industry and the downstream segment of the Company, operates under federal, provincial, state and municipal legislation. This industry is also subject to regulation and intervention by governments in such matters as land tenure, royalties, government fees, production rates, environmental protection controls, the reduction of greenhouse gas emissions, the export of crude oil, natural gas and other products, the awarding or acquisition of exploration and production, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights. Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain regulatory approvals. The regulatory approval process can involve stakeholder consultation, environmental impact assessments and public hearings, among other things. In addition, regulatory approvals may be subject to conditions including security deposit obligations and other commitments. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment or restructuring of projects and increased costs, all of which could negatively affect future earnings and cash flow. Such regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas, increase Suncor’s costs and have a material adverse effect on its financial condition.
SELECTED CONSOLIDATED FINANCIAL INFORMATION
Selected Consolidated Financial Information
The following selected consolidated financial information for each of the years in the three-year period ended December 31, 2003 is derived from Suncor’s 2003 Consolidated Financial Statements. Suncor’s consolidated financial statements for each of the years in the three-year period ended December 31, 2003 have been audited by PricewaterhouseCoopers LLP, Chartered Accountants. The information set forth below should be read in conjunction with MD&A and Suncor’s 2003 Consolidated Financial Statements.
39
|
|
|
Year ended December 31,(1) |
|
||||
|
($ millions except per share amounts) |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
6,306 |
|
5,032 |
|
4,294 |
|
|
Net earnings |
|
1,084 |
|
761 |
|
388 |
|
|
Per common share (undiluted) |
|
2.43 |
|
1.64 |
|
0.79 |
|
|
Per common share (diluted) |
|
2.26 |
|
1.61 |
|
0.78 |
|
|
Cash flow from operations(1) |
|
2,081 |
|
1,440 |
|
831 |
|
|
Capital, acquisition and exploration expenditures |
|
1,588 |
|
877 |
|
1,678 |
|
(1) See non-GAAP financial measures on page xi
|
|
|
Year ended December 31, |
|
||||
|
($ millions) |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
10,427 |
|
8,683 |
|
8,094 |
|
|
Long-term debt |
|
2,448 |
|
2,686 |
|
3,113 |
|
|
Accrued liabilities and other(1) |
|
296 |
|
226 |
|
251 |
|
|
Common shareholders’ equity(2) |
|
3,949 |
|
2,935 |
|
2,255 |
|
Notes:
(1) See Note 7 to Suncor’s 2003 Consolidated Financial Statements, which Notes are incorporated by reference herein.
(2) Excludes Preferred Securities issued in 1999. See Dividend Policy and Record.
The following table sets forth, for each of the two most recently completed financial years, the revenues for each category of Suncor’s principal products or services that accounted for 15 per cent or more of Suncor’s total consolidated revenues.
|
Revenues from |
|
2003 |
|
% |
|
2002 |
|
% |
|
|
|
|
($ millions) |
|
|
|
($ millions) |
|
|
|
|
Transportation fuel sales |
|
2,983 |
|
47 |
|
2,266 |
|
45 |
|
|
Crude oil sales |
|
2,368 |
|
38 |
|
2,082 |
|
41 |
|
|
Other |
|
949 |
|
15 |
|
682 |
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
6,300 |
(1) |
100 |
|
5,030 |
(1) |
100 |
|
Note:
(1) Excludes interest income.
40
Dividend Policy and Record
Suncor’s Board of Directors has established a policy of paying dividends on a quarterly basis. This policy is reviewed from time to time in light of Suncor’s financial position, its financing requirements for growth, its cash flow and other factors considered relevant by Suncor’s Board of Directors.
During 1999, the Company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of U.S.$162.5 million of 9.125% preferred securities, the proceeds of which totaled Canadian $507 million after issue costs of $17 million ($10 million after income tax credits of $7 million). The preferred securities are unsecured junior subordinated debt of the Company, due in 2048 and redeemable at the Company’s option on or after March 15, 2004 for proceeds equal to the original principal amount of the preferred securities plus any accrued and unpaid interest as at the date of redemption. The Company has given notice of its intention to redeem the preferred securities as of March 15, 2004. 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 in the Company’s 2003 Consolidated Financial Statements, but generally treated as interest income to the recipient for Canadian or U.S. tax purposes.
The following table sets forth the per share amount of dividends paid by Suncor during the last three years.
|
|
|
Year ended December 31, |
|
|||||||
|
|
|
2003 |
|
2002 |
|
2001 |
|
|||
|
Common Shares cash dividends |
|
$ |
0.1925 |
|
$ |
0.17 |
|
$ |
0.17 |
|
|
Preferred securities cash interest distributions(1) |
|
$ |
0.10 |
|
$ |
0.11 |
|
$ |
0.11 |
|
|
|
|
|
|
|
|
|
|
|||
|
Dividends paid in common shares |
|
— |
|
— |
|
— |
|
|||
Note:
(1) Per share preferred securities cash interest distributions are calculated as total preferred securities dividends divided by the weighted average outstanding common shares in the year.
41
MANAGEMENT’S DISCUSSION AND ANALYSIS
Suncor’s MD&A, dated February 26, 2004, is incorporated by reference into and forms an integral part of this Annual Information Form, and should be read in conjunction with Suncor’s 2003 Consolidated Financial Statements and the notes thereto.
MARKET FOR THE SECURITIES OF THE ISSUER
The common shares of Suncor are listed on the Toronto Stock Exchange in Canada, and on the New York Stock Exchange in the United States. To the best of management’s knowledge, approximately 40% of Suncor’s common shares are beneficially held by residents of the United States. Suncor’s 9.05% preferred securities are listed on the Toronto Stock Exchange in Canada, and Suncor’s 9.125% preferred securities are listed on the New York Stock Exchange in the United States.
DIRECTORS AND EXECUTIVE OFFICERS
Directors
Reference is made to the information under the heading, “Election of Directors” on pages 2 - 6 inclusive of Suncor’s Management Proxy Circular dated February 26, 2003 for information regarding Suncor’s directors, which information is incorporated by reference into this Annual Information Form.
Executive Officers
The following are the executive officers of the Corporation. Except where otherwise indicated, the persons named in the table below held the offices set out opposite their respective names as at December 31, 2003 and as of the date hereof.
|
Name and
Municipality of |
|
Office(1) |
|
|
|
|
|
|
|
J.
KENNETH ALLEY |
|
Senior Vice President and Chief Financial Officer |
|
|
|
|
|
|
|
MIKE
M. ASHAR |
|
Executive Vice President, Refining and Marketing – U.S.A. |
|
|
|
|
|
|
|
DAVID
W. BYLER |
|
Executive Vice President, Natural Gas and Renewable Energy |
|
42
|
Name and
Municipality of |
|
Office(1) |
|
|
|
|
|
|
|
RICHARD
L. GEORGE |
|
President and Chief Executive Officer |
|
|
|
|
|
|
|
TERRENCE
J. HOPWOOD |
|
Senior Vice President and General Counsel |
|
|
|
|
|
|
|
SUE
LEE |
|
Senior Vice President, Human Resources and Communications |
|
|
|
|
|
|
|
KEVIN
D. NABHOLZ |
|
Senior Vice President, Major Projects |
|
|
|
|
|
|
|
THOMAS
L. RYLEY |
|
Executive Vice President, Energy, Marketing and Refining – Canada |
|
|
|
|
|
|
|
STEVEN
W. WILLIAMS |
|
Executive Vice President, Oil Sands |
|
Notes:
(1) Offices shown are positions held by the officers in relation to business units of Suncor Energy Inc. and its subsidiaries on a consolidated basis. On a legal entity basis, Mr. Ashar is President of Suncor Energy (U.S.A.) Inc., Suncor’s U.S. based downstream subsidiary, Mr. Ryley is the President of Suncor’s marketing Canada based downstream subsidiaries, Suncor Energy Marketing Inc. and Suncor Energy Products Inc., respectively, and Mr. Nabholz is President of Suncor Energy Services Inc., which provides major projects and other shared services to the Suncor group of companies.
All of the foregoing executive officers of the Company have, for the past five years, been actively engaged as executives or employees of Suncor or its affiliates, except Mr. Williams, who joined the Company in May 2002. Prior to joining Suncor, Mr. Williams held various executive positions with Octel Corporation, a global chemicals company. Prior to joining Octel Corporation in 1995, Mr. Williams held executive positions with Esso Petroleum Company Limited, an affiliate of Exxon.
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 executive officers, as a group, is less than 1%.
Additional Disclosure for Directors and Executive Officers
To the best of our knowledge, having made due inquiry, Suncor confirms that, as at December 31, 2003:
(i) in the last ten years, no director or executive officer of Suncor is or has been a director or officer of another issuer that, while that person was acting in that capacity,
43
(a) was the subject of a cease trade or similar order, or an order that denied the other issuer access to any exemptions under Canadian securities legislation for a period of more than 30 consecutive days; or
(b) became bankrupt or made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromises with creditors or had a receiver, receiver manager or trustee appointed to hold its assets, other than Mr. Canfield, a director of Suncor who was a director of Royal Trust Co. in 1994 when it entered into a plan of arrangement with creditors and Mr. Korthals, a director of Suncor who was a director of Anvil Range Mining Corporation, which sought protection under the Companies Creditors Arrangement Act (Canada) in 1998;
(ii) no director or executive officer of Suncor has
(a) been subject to any penalties or sanctions imposed by a court relating to Canadian securities legislation or by a Canadian securities regulatory authority or has entered into a settlement agreement with a Canadian securities regulatory authority; or
(b) has been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision;
(iii) no director or executive officer of Suncor nor any personal holding company controlled by such person has become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of the director or executive officer; and
(iv) no director or executive officer has any direct or indirect material interest in respect of any matter that has materially affected or will materially affect Suncor or any of its subsidiaries.
FEES PAID TO AUDITORS
Fees Paid to Auditors
Reference is made to the information under the heading, “Appointment of Auditors” on page 27 of Suncor’s Management Proxy Circular dated February 26, 2004 for information regarding fees paid by Suncor to its auditors for the last two completed fiscal years, which information is incorporated by reference into this Annual Information Form.
44
Audit Committee Pre-Approval Policies for Non Audit Services
Suncor’s Audit Committee has considered whether the provision of services other than audit services is compatible with maintaining the auditors’ independence and has a policy governing the provision of these services. The policy requires that all non-audit services provided by Suncor’s auditors be approved by the Audit Committee in compliance with the Sarbanes Oxley Act of 2002. For the year ended December 31, 2003, all non-audit fees were approved by the audit committee pursuant to paragraph (c)(7)(i)(A) of Rule 2-01 of Regulation S-X, with the exception of approximately 1% of non-audit fees (approximately $2,500 out of a total $186,000 in non-audit fees) which were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
RELIANCE ON EXEMPTIVE RELIEF
Suncor is reporting its reserves data in accordance with, and is relying on, the terms of the following MRRS Decision Document: In the Matter of the Securities Legislation of Alberta, British Columbia, Saskatchewan, Manitoba, Ontario, Quebec, Nova Scotia, Newfoundland and Labrador, Yukon, Northwest Territories and Nunavut AND In the Matter of The Mutual Reliance Review System for Exemptive Relief Applications AND In the Matter of Suncor Energy Inc., December 22, 2003 (the “Decision Document”).
Suncor’s reserves data consists of the following:
• net proved working interest oil and gas reserve quantities relating to oil and gas operations, other than mining, estimated as at December 31, 2003 using constant prices and costs, and the related standardized measure; and
• gross proved and probable working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at December 31, 2003.
Suncor’s estimates of reserves and related standardized measure of discounted future net cash flows (the “standardized measure”) were evaluated or reviewed in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) modified to the extent necessary to reflect the terminology and standards of US disclosure requirements, including:
• the information required by the United States Financial Accounting Standards Board, including Financial Accounting Standard No. 69;
• the information required by SEC Industry Guide 2 Disclosure of Oil and Gas Operations, as amended from time to time; and
• certain other information required in accordance with US disclosure practices.
If Suncor had been reporting its’ reserves data in accordance with National Instrument 51-101 and had not been relying on the terms of the Decision Document, it would have been required to report gross and net reserves data consisting of the following:
• proved working interest oil and gas reserve quantities relating to oil and gas operations using constant prices and costs and related net present value of future net revenue, discounted at 10%; and
• proved and probable working interest oil and gas reserve quantities relating to oil and gas operations using forecast prices and costs and related net present value of future net revenue, discounted at 5%, 10%, 15% and 20%.
45
ADDITIONAL INFORMATION
Copies of the documents set out below may be obtained by any person upon request to the Secretary of the Company at 112 - 4 Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, or by e-mail request to info@suncor.com.
(i) The current Suncor Annual Information Form together with any pertinent information incorporated by reference therein;
(ii) The current Suncor comparative financial statements for the most recently completed financial year and the report of the auditors relating thereon, 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.
Copies of such documents will be made available without charge at any time when Suncor’s securities are in the course of distribution pursuant to a short form prospectus. At any other time Suncor reserves the right to impose a reasonable charge for requests by persons other than security holders. Such documents are available electronically on Suncor’s web site at www.suncor.com.
Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of Suncor’s securities, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in Suncor’s most recent management proxy circular for its most recent annual meeting of its shareholders that involved the election of directors. Additional financial information is provided in Suncor’s 2003 Consolidated Financial Statements.
Further information about Suncor, filed with Canadian securities commissions and the United States Securities and Exchange Commission (SEC), including periodic quarterly and annual reports and the Annual Information (AIF/40-F) is available online at www.sedar.com and www.sec.gov.
46
FORM
51-101F3
REPORT OF
MANAGEMENT
AND DIRECTORS
ON RESERVES DATA AND OTHER INFORMATION
This is the form referred to in item 3 of section 2.1 of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), as amended pursuant to the MRRS Decision Document dated December 22, 2003, In the Matter of Suncor Energy Inc. (the “Decision Document”).
Terms to which a meaning is ascribed in the Decision Document have the same meaning in this form.
Management of Suncor Energy Inc. (the “Company”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas and surface mineable oil sands activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:
(a) proved working interest oil and gas reserve quantities relating to oil and gas operations, other than mining, estimated as at December 31, 2003 using constant prices and costs, and the related standardized measure; and
(b) proved and probable working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at December 31, 2003.
Gilbert Laustsen Jung Associates Ltd., independent qualified reserves evaluators, have evaluated the Company’s reserves data. The report of the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.
The Audit Committee of the board of directors of the Company has
(a) reviewed the Company’s procedures for providing information to the independent qualified reserves evaluators;
(b) met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and
(c) reviewed the reserves data with management and the independent qualified reserves evaluators.
The Audit Committee of the board of directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas and surface mineable oil sands activities and has reviewed that information with management. The board of directors has, on the recommendation of the Audit Committee, approved
(a) the content and filing with securities regulatory authorities of the reserves data and other oil and gas and surface mineable oil sands information;
1
(b) the filing of the report of the independent qualified reserves evaluators on the reserves data; and
(c) the content and filing of this report.
2
Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
|
"RICHARD L. GEORGE" |
|
|
RICHARD L. GEORGE |
|
|
President and Chief Executive Officer |
|
|
|
|
|
|
|
|
"J. KENNETH ALLEY" |
|
|
J. KENNETH ALLEY |
|
|
Senior Vice President and Chief Financial Officer |
|
|
|
|
|
|
|
|
"JOHN T. FERGUSON" |
|
|
JOHN T. FERGUSON |
|
|
Director |
|
|
|
|
|
|
|
|
"JR SHAW" |
|
|
JR SHAW |
|
|
Chairman of the Board of Directors |
|
|
|
|
|
|
|
|
February 26, 2004 |
|
3
|
|
|
Gilbert
Laustsen Jung |
February 26, 2004
Suncor Energy Inc.
P.O. Box 38
112 – 4th Avenue S.W.
Calgary, AB T2P 2V5
|
To: |
|
The Board of Directors of Suncor Energy Inc. |
|
|
|
|
|
Re: |
|
Form 51-101F2, as modified in accordance with exemptions from National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) contained in the MRRS Decision Document dated December 22, 2003, In the Matter of Suncor Energy Inc. (the “Decision Document”) |
We are providing this report in accordance with the terms of the Decision Document and any capitalized terms, not otherwise defined in this report, shall have the same meaning as set out in the Decision Document.
We have evaluated the Company’s reserves data as at December 31, 2003. The reserves data consist of the following:
(a) |
|
proved working interest oil and gas reserve quantities relating to oil and gas operations, other than mining, estimated as at December 31, 2003 using constant prices and costs, and the related standardized measure; and |
(b) |
|
proved and probable working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at December 31, 2003 |
The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
We evaluated or reviewed the Company’s estimates of reserves and related future net revenue (or, where applicable, related standardized measure of discounted future net cash flows (the standardized measure)) in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) modified to the extent necessary to reflect the terminology and standards of the US Disclosure Requirements.
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook, as modified to the extent necessary to reflect the terminology and standards of the US Disclosure Requirements.
The following table sets forth the estimated standardized measure of future cash flows (before deducting income taxes) attributed to proved oil and gas reserve quantities not related to mining operations, estimated using constant prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended, December 31, 2003:
1
|
|
|
Standardized
Measure of Future Cash Flows for |
|
|||||||||
|
Preparation Date of Report |
|
Location
of |
|
Evaluated |
|
Reviewed |
|
Total |
|
|||
|
February 20, 2004 |
|
Canada |
|
$ |
2,533 million |
|
$ |
84 million |
|
$ |
2,617 million |
|
|
|
|
|
|
(97 |
)% |
(3 |
)% |
(100 |
)% |
|||
In addition, all proved plus probable company gross reserves have been evaluated for Suncor’s oilsands mining properties located in Canada and all reserves and resources have been evaluated or reviewed for all of Suncor’s oil and gas plus mining operations.
In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, as modified or amended as set out above. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
We have no responsibility to update our reports evaluating reserves data of the Company by us for the year ended December 31, 2003 for events and circumstances occurring after the preparation dates of our reports.
Reserves are estimates only, and not exact quantities. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
Executed as to our report referred to above:
|
GILBERT LAUSTSEN JUNG ASSOCIATES LTD., |
||
|
Calgary, Alberta, Canada |
||
|
|
||
|
|
||
|
Per: |
ORIGINALLY SIGNED BY |
|
|
|
||
|
Dana B. Laustsen, P. Eng. |
||
|
Executive Vice-President |
||
2
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. Undertaking
Suncor Energy Inc. (the “Registrant”) undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the staff of the Securities and Exchange Commission (“SEC”), and to furnish promptly, when requested to do so by the SEC staff, information relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises, or transactions in said securities.
B. Consent to Service of Process
The Registrant has filed previously with the SEC a Form F-3 in connection with the Common Shares.
DISCLOSURE CONTROLS AND PROCEDURES
See Exhibits 6 and 7 hereof.
AUDIT COMMITTEE FINANCIAL EXPERT
See page 7 of Appendix A of Exhibit 3.
CODE OF ETHICS
See pages 25 and 26 of Exhibit 3.
FEES PAID TO PRINCIPAL ACCOUNTANT
See page 27 of Exhibit 3.
AUDIT COMMITTEE PRE-APPROVAL POLICIES
See page 45 of Registrant’s AIF.
APPROVAL OF NON-AUDIT SERVICES
See page 45 of Registrant's AIF.
OFF-BALANCE SHEET ARRANGEMENTS
See pages 21 and 22 of Exhibit 2.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
See page 21 of Exhibit 2.
IDENTIFICATION OF THE AUDIT COMMITTEE
See page 3 of Exhibit 3.
SIGNATURES
Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.
|
|
|
|
SUNCOR ENERGY INC. |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DATE: |
April 13, 2004 |
|
PER: |
“RICHARD L. GEORGE” |
|
|
|
|
|
|
RICHARD L. GEORGE |
|
|
|
|
|
|
President and Chief Executive Officer |
|
EXHIBIT INDEX
|
Exhibit No. |
|
Description |
|
|
|
|
|
1 |
|
Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2003, including reconciliation to U.S. GAAP (Note 19) |
|
|
|
|
|
2 |
|
Management’s Discussion and Analysis for the fiscal year ended December 31, 2003, dated February 26, 2004 |
|
|
|
|
|
3 |
|
Pages 3, 25 to 27 and Appendix A inclusive of Suncor Energy Inc.’s Management Proxy Circular dated March 8, 2004 |
|
|
|
|
|
4 |
|
Consent of PricewaterhouseCoopers LLP |
|
|
|
|
|
5 |
|
Consent of Gilbert Laustsen Jung Associates Ltd. |
|
|
|
|
|
6 |
|
Certificate of President and Chief Executive Officer Pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e) |
|
|
|
|
|
7 |
|
Certificate of Senior Vice President and Chief Financial Officer Pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e) |
|
|
|
|
|
8 |
|
Certificate of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
|
|
9 |
|
Certificate of the Senior Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |