6-K 1 a2042188z6-k.txt FORM 6-K (40F) FORM 6-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Report of Foreign Private Issuer Pursuant to Rule 13a - 16 or 15d - 16 of the Securities Exchange Act of 1934 For the month of: March 2001 Commission File Number: 1-12384 SUNCOR ENERGY INC. (Name of registrant) 112 FOURTH AVENUE S.W. P.O. BOX 38 CALGARY, ALBERTA, CANADA, T2P 2V5 Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F: Form 20-F Form 40-F X ------- ------- Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the SEC pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934: Yes No X ------- ------- If "Yes" is marked, indicate the number assigned to the registrant in connection with Rule 12g3-2(b): N/A EXHIBIT INDEX
EXHIBIT DESCRIPTION OF EXHIBIT ------- ---------------------- EXHIBIT 1 Reconciliation to U.S. GAAP EXHIBIT 2 Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2000 EXHIBIT 3 Management's Discussion and Analysis for the fiscal year ended December 31, 2000, dated February 28, 2001 EXHIBIT 4 Excerpt from page 78 of Suncor Energy Inc.'s 2000 Annual Report to Shareholders EXHIBIT 5 Consent of PricewaterhouseCoopers LLP EXHIBIT 6 Consent of Gilbert Laustsen Jung Associates Ltd.
SUNCOR ENERGY INC. ANNUAL INFORMATION FORM FEBRUARY 28, 2001 ANNUAL INFORMATION FORM TABLE OF CONTENTS GLOSSARY OF TERMS..........................................................................iii CONVERSION TABLE...........................................................................vii CURRENCY...................................................................................vii FORWARD LOOKING STATEMENTS................................................................viii CORPORATE STRUCTURE..........................................................................9 Incorporation of the Issuer.............................................................9 Subsidiaries of Suncor..................................................................9 GENERAL DEVELOPMENT OF THE BUSINESS..........................................................9 Three-Year Highlights..................................................................10 NARRATIVE DESCRIPTION OF THE BUSINESS.......................................................13 OIL SANDS................................................................................13 Operations.............................................................................13 Leasehold Interests and Royalties......................................................14 Estimated Synthetic Crude Oil Reserves.................................................16 Reserves Reconciliation................................................................17 Revenues from Synthetic Crude Oil and Diesel...........................................17 Capital Expenditures...................................................................18 Environmental Compliance...............................................................18 NATURAL GAS..............................................................................18 Reserves and Reserves Reconciliation...................................................19 Conventional Crude Oil.................................................................21 Before Royalties at....................................................................22 Natural Gas............................................................................24 Land Holdings..........................................................................24 Drilling...............................................................................25 Wells..................................................................................26 Sales and Sales Revenues...............................................................26 Production Costs.......................................................................27 Quarterly Volumes and Netback Analysis.................................................27 Marketing, Pipeline and Other Operations...............................................28 Capital and Exploration Expenditures...................................................28 Environmental Compliance...............................................................29 SUNOCO...................................................................................29 Refining...............................................................................29 Environmental Compliance...............................................................33 SUNCOR EMPLOYEES............................................................................33 RISK/SUCCESS FACTORS........................................................................34 SELECTED CONSOLIDATED FINANCIAL INFORMATION.................................................39 Selected Consolidated Financial Information............................................39 Dividend Policy and Record.............................................................39 Future Commitments to Buy, Sell, Exchange or Transport Crude Oil And Natural Gas.......40 MANAGEMENT'S DISCUSSION AND ANALYSIS........................................................41 MARKET FOR THE SECURITIES OF THE ISSUER.....................................................41 DIRECTORS AND OFFICERS......................................................................41 ADDITIONAL INFORMATION......................................................................45
ii GLOSSARY OF TERMS INDUSTRY TERMS BITUMEN/HEAVY OIL A naturally occurring viscous tar-like mixture, mainly of hydrocarbons heavier than pentane, that may contain sulphur compounds and that in its naturally occurring viscous state is not recoverable at a commercial rate through a well, without using enhanced recovery methods; and that when extracted can be upgraded into crude oil and other petroleum products. CAPACITY Maximum output that can be achieved from a facility in ideal operating conditions. COAL BED METHANE Natural gas produced from wells drilled into a coal formation. Also called coal seam methane. CONVENTIONAL CRUDE OIL Crude oil produced through wells by standard industry recovery methods for the production of Crude Oil. CONVENTIONAL NATURAL GAS Natural gas produced from all geological strata, excluding coal bed methane. CRUDE OIL Unrefined liquid hydrocarbons, excluding natural gas liquids. DOWNSTREAM This business segment manufactures, distributes and markets refined products from crude oil. DRY HOLE/WELL An exploration or development well determined, on an economic basis, to be incapable of producing hydrocarbons that will be plugged, abandoned and reclaimed. GROSS PRODUCTION/RESERVES Suncor's interest before deducting Crown royalties, freehold and overriding royalty interests. GROSS WELLS/LAND HOLDINGS Total number of wells or acres, as the case may be, in which Suncor has an interest. HEAVY FUEL OIL Residue from refining of conventional crude oil that remains after lighter products such as gasoline, petrochemicals and heating oils have been extracted. iii IN-SITU OIL In-situ or "in place" refers to methods of extracting heavy crude oil from deep deposits of oil sands with minimal disturbance of the ground cover. NATURAL GAS Hydrocarbons which at atmospheric conditions of temperature and pressure are in a gaseous phase. NATURAL GAS LIQUIDS Those hydrocarbon products recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butanes and pentanes plus, or a combination thereof. NET PRODUCTION/RESERVES Suncor's interest in total production or total reserves, as the case may be, after deducting Crown royalties and freehold and overriding royalty interests. NET WELLS/LAND HOLDINGS Suncor's interest in the gross number of wells or gross number of acres, as the case may be, after deducting interests of third parties. OVERBURDEN Material overlying oil sands that must be removed before mining. Consists of muskeg, glacial deposits and sand. PROBABLE RESERVES With reference to conventional crude oil and natural gas, those reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future. PROVED RESERVES With reference to conventional crude oil and natural gas, those reserves estimated as recoverable under current technology and existing economic conditions, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir. iv PROVED AND PROBABLE OIL SANDS RESERVES Annual estimates made by Suncor of recoverable synthetic crude oil associated with Suncor's surface mineable oil sands leases. The estimates are allocated between proven and probable categories based upon criteria agreed to by management and reviewed by independent consultants. The proved reserves are considered to be conservative estimates in which there are a high degree of confidence. Probable reserves incorporate portions of the mine that have a lower drilling density. There is least a 50% chance the proved plus probable reserve estimates will be exceeded. The bitumen estimates are converted to synthetic crude estimates on the basis of yields currently being obtained. RESERVOIR Body of porous rock containing an accumulation of water, crude oil or natural gas. SOUR CRUDE OIL Crude oil produced by Oil Sands that requires only partial upgrading and contains a higher sulphur content than sweet crude oil. SWEET SYNTHETIC CRUDE OIL Crude oil produced by Oil Sands consisting of a blend of hydrocarbons resulting from thermal cracking and purifying of bitumen. SYNTHETIC CRUDE OIL Upgraded or partially upgraded crude oil recovered from oil sands including surface mineable oil sands leases and in-situ heavy oil leases. UNDEVELOPED OIL AND NATURAL GAS LANDS Suncor's undivided percentage interest in lands on which no producing or commercially producible well has been drilled. UPSTREAM This business segment includes acquisition, exploration, development, production and marketing of crude oil, natural gas, and natural gas liquids; and for greater clarity includes the production of synthetic crude oil and other oil products from oil sands. UTILIZATION The average use of capacity taking into consideration unplanned outages and unscheduled maintenance. WELLS DEVELOPMENT WELL A crude oil or natural gas well in a reservoir known to be productive and expected to produce in future. v DRILLED WELL A well which has been drilled and has a defined status e.g. gas well, shut-in well, producing oil well, producing gas well, suspended well or dry and abandoned well. EXPLORATORY WELL A well drilled in unproved or semi-proved territory with the intention to discover commercial reservoirs or deposits of crude oil and/or natural gas. ACCOUNTING TERMS BARREL OF OIL EQUIVALENT (BOE) Converts natural gas to crude oil on the approximate long-term economic equivalent basis that 10,000 cubic feet of natural gas equals one barrel of crude oil. DEVELOPMENT COSTS Includes all costs associated with moving reserves from other classes such as "proved undeveloped" and "probable" to the "proved developed" class. FINDING COSTS Includes the cost of and investment in undeveloped land, geological and geophysical activities, exploratory drilling and direct administrative costs necessary to discover crude oil and natural gas reserves. INTEREST COVERAGE -- CASH FLOW BASIS Cash provided from operating activities before interest expense and income tax payments, divided by the aggregate of interest expense and interest capitalized. LIFTING COSTS Includes all expenses related to the operation and maintenance of producing or producible wells, natural gas plants and gathering systems. MMCF/E Converts crude oil to natural gas on the approximate long-term economic equivalent basis that one barrel of crude oil equals 10,000 cubic feet natural gas. NET DEBT Long-term borrowings (including the current portion) plus short-term borrowings, less cash and cash equivalents. OPERATING WORKING CAPITAL Current assets (excluding cash and cash equivalents), less current liabilities (excluding borrowings). vi RETURN ON AVERAGE CAPITAL EMPLOYED Earnings before long-term interest expense as a percentage of average capital employed. Average capital employed is the total of shareholders' equity and debt (short-term borrowings and current and long-term borrowings), less the book value of significant capital projects in process at the beginning and end of the year, divided by two. RETURN ON AVERAGE SHAREHOLDERS' EQUITY Earnings as a percentage of average shareholders' equity. Average shareholders' equity is the aggregate of total shareholders' equity at the beginning and end of the year, divided by two. CONVERSION TABLE 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. vii FORWARD LOOKING STATEMENTS This Annual Information Form contains certain forward-looking statements, which are based on Suncor's current expectations, estimates, projections and assumptions and were made by Suncor in light of its experience and its perception of historical trends. All statements that address expectations or projections about the future, including statements about Suncor's strategy for growth, expected expenditures, commodity prices, costs, schedules and production volumes, operating or financial results, are forward looking statements. Some of the forward looking statements may be identified by words like "expects," "anticipates," "plans," "intends," "believes," "projects," "indicates," "could", "vision", "goal", "objective" and similar expressions. These statements are not guarantees of future performance and involve a number of risks, uncertainties and assumptions. Suncor's business is subject to risks and uncertainties, some of which are similar to other oil and gas companies and some of which are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward looking statements as a result of known and unknown risks, uncertainties and other factors. The risks, uncertainties and other factors that could influence actual results include: changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor's products; fluctuations in commodity prices; fluctuations in currency exchange rates; Suncor's ability to respond to changing markets; the ability of Suncor to receive timely regulatory approvals; the successful and timely implementation of its growth projects including Project Millennium; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development projects; Suncor's ability to comply with current and future environmental laws; the accuracy of Suncor's production estimates and production levels and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venturers; competitive actions of other companies, including increased competition from other oil and gas companies or from companies which provide alternative sources of energy; the uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; actions by governmental authorities including increasing taxes, changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. Many of these risk factors are discussed in further detail throughout this Annual Information Form and in Management's Discussion and Analysis for the year ended December 31, 2000 and dated February 28, 2001, incorporated by reference herein. Readers are also referred to the risk factors described in other documents Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the Company by contacting the Secretary at 403-269-8709. viii CORPORATE STRUCTURE INCORPORATION OF THE ISSUER Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the CANADA BUSINESS CORPORATIONS ACT on August 22, 1979 of Sun Oil Company Limited, incorporated in 1923, and Great Canadian Oil Sands Limited, incorporated in 1953. On January 1, 1989, Suncor amalgamated with a wholly-owned subsidiary under the CANADA BUSINESS CORPORATIONS ACT. In September 1995, Suncor's articles were amended to change the location of its registered office from Toronto, Ontario, to Calgary, Alberta. In April 1997, Suncor's articles were amended to divide its issued and outstanding shares on a two-for-one basis, and to change the Company's name to Suncor Energy Inc. In May 2000, Suncor's articles were again amended to divide its issued and outstanding shares on a two-for-one basis. Suncor's registered and principal office is located at 112 - 4th Avenue, S.W. Calgary, Alberta, T2P 2V5. In this Annual Information Form, references to "Suncor" or the "Company" include Suncor Energy Inc., its subsidiaries and joint venture investments unless the context otherwise requires. SUBSIDIARIES OF SUNCOR Suncor Energy Inc. has two principal subsidiaries. Sunoco Inc. is an Ontario corporation that is wholly-owned by Suncor and is incorporated under the laws of Ontario. Sunoco refines and markets petroleum products and petrochemicals directly and indirectly through subsidiaries and joint ventures. In this Annual Information Form, references to "Sunoco" mean Sunoco Inc., its subsidiaries and joint venture investments, unless the context otherwise requires. Sunoco is unrelated to Sunoco, Inc. (formerly known as Sun Company, Inc.) that has offices in Pennsylvania. Suncor Energy Marketing Inc., wholly-owned by Sunoco, is incorporated under the laws of Alberta. Suncor Energy Marketing Inc. manages Company and third party Alberta-based pipeline operations, and markets, mainly to customers in Canada and the United States, certain crude oil and diesel fuel products and byproducts such as petroleum coke, sulphur and gypsum produced by Suncor's Oil Sands and Natural Gas (NG) business units as well as other third party products. Suncor Energy Marketing Inc. also has a petrochemicals marketing division that principally manages its participation in a petrochemical products joint venture partnership. GENERAL DEVELOPMENT OF THE BUSINESS OVERVIEW Suncor is a Canada-based integrated energy company. Suncor explores for, acquires, produces, and markets crude oil and natural gas, refines crude oil, and markets petroleum and petrochemical products. Suncor has three principal operating business units. OIL SANDS, based near Fort McMurray, Alberta, produces sweet and sour crude oil, diesel fuel and various custom blends and markets these products in Canada and the United States. NATURAL GAS (formerly Exploration and Production), based in Calgary, Alberta, explores for, acquires, develops, produces and markets natural gas throughout North America. Since November 1, 1998, Suncor Energy Marketing Inc. has marketed the crude oil, diesel products and other byproducts produced by Suncor's Oil Sands and Natural Gas business units. Since January 1, 2000, it has also managed the Company's, and certain third party, Alberta-based pipeline operations. Sunoco, headquartered in Toronto, Ontario, refines crude oil, markets a broad range of petroleum products, mostly in Ontario, and markets petrochemical products in the United States and Europe. In 1997, Sunoco started an energy marketing business and began marketing natural gas to residential and 9 commercial customers in Ontario. Suncor is currently commissioning an oil shale demonstration project known as the Stuart Oil Shale Project, in Gladstone, Queensland, Australia. In 2000, Suncor produced approximately 121,100 barrels per day of crude oil and natural gas liquids (approximately 6% of Canada's crude oil production) and 200 million cubic feet per day of natural gas. In 1999, the most recent period with published results, Suncor was the second largest crude oil and natural gas liquids producer and in the top quartile of natural gas producers in Canada. In 2000, Suncor sold approximately 92,000 barrels (14,600 m3) per day of refined products, mainly in Ontario but also in the United States and Europe. Suncor's refined product sales in Ontario represented approximately 17% of Ontario's total refined product sales in 2000. THREE-YEAR HIGHLIGHTS OIL SANDS In July 1997, Suncor announced plans to expand the production capacity of its Oil Sands plant, near Ft. McMurray, Alberta, including plans for a project ("Project Millennium") designed to double Oil Sands' production capacity from 1997 levels. Project Millennium involves an expanded mine, additional mining equipment, increased energy services support and twinning of the bitumen extraction and upgrading processes. Detailed engineering studies that followed the original announcement in 1997 resulted in a Project Millennium plan designed to increase total production capacity at Oil Sands to 225,000 barrels per day by 2002. Project Millennium was approved in 1999 by both Suncor's Board of Directors and the Alberta Energy & Utilities Board. In February 1999, Suncor announced the integrated project team of Canada-based companies, including Suncor, that would undertake the engineering, procurement, construction, commissioning and start-up of Project Millennium. Project Millennium construction began in April 1999. In the first quarter of 2000, Suncor announced Project Millennium costs could be as high as $2.45 billion, up from the original estimate of $2 billion. In October of 2000, a thorough analysis was completed on Suncor's Project Millennium that resulted in a revised capital cost estimate of $2.8 billion. The current capital cost estimate of $2.8 billion is attributed to rising labour, fabrication and material costs, and a $150 million change in the project's scope. The additional capital costs are expected to be financed by internally generated cash flow and additional borrowing. At the end of 2000 all Project Millennium engineering was completed and in aggregate the project was 70% complete. In March 1999, Suncor and TransAlta Energy Corporation ("TransAlta") announced TransAlta's plans to build, own and operate a $315 million co-generation facility at Suncor's Oil Sands site. This facility is expected to meet a portion of Oil Sands' electricity and steam requirements and to supply electricity to the Alberta power grid. The new TransAlta facility is being built in phases and is expected to generate 360 megawatts of electricity when fully operational in 2001. The first phase, consisting of two gas turbines producing 220 megawatts of electricity, became operational in 2000. Commissioning of other co-generation equipment continued throughout 2000 and the entire complex is expected to be fully commissioned in 2001. In October 1999, TransAlta also assumed the role of operator of Suncor's existing energy services plant. In early 2000, Suncor announced a plan to further expand its oil sands facilities beyond the Project Millennium expansion currently in process, with a proposed investment of $750 million in the first stage of an in-situ project and further expansion of the Oil Sands plant. Under current planning assumptions, the commercial scale in-situ portion of the project (referred to as the "Firebag In-situ Oil Sands Project") is targeted to add approximately 35,000 barrels of bitumen per day in 2005. The Firebag In-situ Oil Sands Project is intended to be integrated with Suncor's open pit mining operation. To process the additional bitumen, Suncor plans to add a vacuum tower complex designed to increase the Oil Sands plant upgrading capacity to a targeted 260,000 barrels per day in 2005. Work to finalize cost estimates is 10 underway. These plans are subject to Board of Directors and provincial regulatory approvals. Suncor submitted regulatory approval applications for the Firebag In-situ Oil Sands Project in 2000, and expects a regulatory decision in 2001. Subject to these approvals, construction of the Firebag In-Situ Oil Sands Project and the vacuum tower complex addition is scheduled to begin in late 2001, with start-up in late 2003 and commissioning in 2004 - 2005. The Company's long-term vision is to produce 140,000 barrels of bitumen per day from the Firebag project by the end of this decade, and to increase total production at its Oil Sands facilities, by a combination of oil sands mining and in-situ development, to approximately 400,000 to 450,000 barrels of crude oil a day in 2008. Any plans toward realizing this long-term vision would be subject to Board of Directors and regulatory approvals. NATURAL GAS In April 2000, Suncor's Board of Directors approved a repositioning of the Exploration and Production business and renamed it Natural Gas (NG) to reflect the sharpened focus on natural gas production to meet growing demand, both internally and externally. The repositioning plans called for a reduction in annual expenses in the NG business by $18 to $20 million by the end of 2001. During 2000, NG reduced annualized costs by approximately $15 million, approximately 80% of its target. Consolidation of the asset base, organizational restructuring and a reduction in the NG workforce of about 70 positions contributed to the reduced operating costs. The NG business has established a goal of achieving a sustainable 10% return on capital employed by 2004 at natural gas prices in the range of $3.00 to $3.50 per thousand cubic feet (mid-cycle prices). SUNOCO In 1997, Sunoco entered the natural gas marketing business in Ontario. In 1999, as part of its goal to broaden its energy offerings, Sunoco expanded the number of dealer members in the Home Energy Dealer Network to 29 dealers. In 2000 it was decided to exit the heating, ventilation and air conditioning market and shut down its Home Energy Dealer Network. This decision does not affect Sunoco's interests in the natural gas marketing business. Costs associated with the shut down were not significant. During 1998, TransAlta announced plans to build a co-generation facility in Sarnia, Ontario. Sunoco continues to evaluate its participation in this project. Any such participation would be subject to enabling rules and regulations arising from the Ontario government's electricity deregulation process. These include acceptable tariff structures currently under a rate hearing by the Ontario Energy Board. Due to the length of the deregulation process, start-up of the project is now estimated for mid-2002, as opposed to the 1998 estimate of completion in 2001. If the project proceeds, it is expected to supply some of Sarnia's power-consuming industries, including Sunoco's Sarnia refinery, with lower-cost power and steam. Negotiations continue with TransAlta to purchase steam and electricity from the project. In 2000, to reduce exposure to energy cost increases expected when the electricity market deregulates, Sunoco's Sarnia refinery negotiated a fixed-rate supply contract to lock-in costs on a portion of its electricity requirements for three years. The contract commences on the date when electricity deregulation begins and provides that, if this does not occur prior to a specific outside date, the contract would terminate unless renegotiated. Under this contract Sunoco is not prevented from reselling the purchased electricity and as such Sunoco would have the ability to sell into the marketplace any electricity surplus to its needs. 11 OTHER In the first quarter of 1998, Suncor arranged syndicated credit facilities totaling $1.296 billion to be used for general corporate purposes. These borrowings were arranged in anticipation of the Company's planned multi-billion dollar capital expenditure program during the 1999 - 2001 period, primarily relating to Project Millennium. The facilities are unsecured and rank equally with other unsecured and unsubordinated indebtedness of Suncor. During 1999, the Company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of U.S.$162.5 million of 9.125% preferred securities, the proceeds of which totaled Canadian $507 million after issue costs of $17 million ($10 million after income tax credits of $7 million). The preferred securities are unsecured junior subordinated debt of the Company, due in 2048 and redeemable at the Company's option on or after March 15, 2004. See "Dividend Policy and Record." During 2000, the Company put in place a borrowing facility for $500 million that is fully revolving for 364 days and expires in 2001. In June 1997, Sunoco Inc. and Australian joint venture participants, Southern Pacific Petroleum NL (SPP) and Central Pacific Minerals NL (CPM) announced the first stage of the Stuart Oil Shale Project in Gladstone, Queensland, Australia where the Company and the two Australian co-owners are currently testing the commercial viability of producing crude oil from oil shale. The first phase is designed as a 4,500-barrel per day demonstration plant. Suncor Energy (Management) Pty Ltd., a subsidiary of Sunoco, is the operator of the demonstration plant. Construction is now complete and commissioning of the first stage of the Stuart Oil Shale Project commenced in 1999. Operational issues have been experienced during commissioning of the Stuart Oil Shale Project, including issues relating to plant reliability, noise, odours and the discovery of low levels of dioxin and other emissions. In the third quarter of 2000, Suncor announced plans to spend up to $22 million to address these issues. Suncor recorded an after-tax write-down of $80 million on the project in 2000, reflecting increased costs and delayed oil production. All future expenditures on the Stuart Oil Shale Project are being expensed until operational issues and concerns about environmental and social impacts are addressed. Suncor intends to resolve operating issues at the plant before making any decisions regarding the project's next stage of development. To the end of December 2000, Suncor's investment in the first stage of the project, excluding $4 million invested by Suncor in partially paid SPP/CPM shares (See Note 2 to Suncor's consolidated financial statements for information about these shares), has been approximately $270 million, higher than the original estimate of $210 million due to the issues and delays experienced to date. A portion of the financing for the project, $73 million at the end of 2000, has been funded through project financing from SPP and CPM. The success of the Stuart Oil Shale Project is subject to uncertainty because of the developmental nature of the project and the inherent risks associated with the use of new technology. If the project does not proceed, the remaining associated costs and obligations on the balance sheet would be eliminated. The impact on future earnings, should this occur, is currently estimated not to be significant. If the first stage of the project proves successful, the next stages have the potential to increase production to 85,000 barrels per day within 10 years. Sunoco and SPP/CPM would ultimately have a 50/50 interest in the project. In September 1999, Dow Jones announced Suncor was to be included in the newly formed Dow Jones Sustainability Index, which is the world's first global equity index, tracking the performance of the 200 leading sustainability-driven companies in 68 industry groups in 22 countries. Suncor continued to be part of the Sustainability Index in 2000. Suncor announced in 2000 plans to invest at least $100 million over the next five years to pursue alternative and renewable energy opportunities. For further information on the status of the ongoing projects referred to above, including Project Millennium, and other highlights of 2000, reference is made to "Outlook" and other sections of Suncor's Management's Discussion and Analysis for the year ended December 31, 2000 and dated February 28, 12 2001 ("MD&A"), which MD&A is incorporated by reference herein. NARRATIVE DESCRIPTION OF THE BUSINESS OIL SANDS Suncor produces a variety of refinery feedstocks and diesel fuel by mining the Athabasca oil sands in northeastern Alberta and upgrading the bitumen extracted at its plant near Fort McMurray, Alberta. The Oil Sands operations, accounting for over 95% of Suncor's conventional and synthetic crude oil production in 2000, represents a significant portion of Suncor's asset base, cash flow and earnings. OPERATIONS Suncor's integrated Oil Sands business involves four operations: a mining operation using trucks and shovels to mine the oil sand; extraction which involves extracting the bitumen from the oil sands; a heavy oil upgrading process, where bitumen is converted into crude products; and an energy services plant (operated by TransAlta), which provides the site with steam and electric power. The first step of the open pit mining operation is the removal of overburden with trucks and shovels to access the oil sands - a mixture of sand, clay, and bitumen. The oil sands ore is transported to one of four sizing plants by a fleet of trucks. The ore is dumped into sizers where it is crushed and then transported to the extraction plant. On the west bank of the Athabasca River, the ore is transported by a conveyor system which stretches approximately three miles. On the east bank, a slurry of partially processed ore from the Mine Expansion is transported by a hydrotransport system to the extraction plant on the west side of the river. Bitumen is extracted from the oil sands with a hot water process. After the final removal of impurities and minerals, naphtha is added as diluent to facilitate transportation to the upgrading plant. After transfer to the upgrading plant, the diluted bitumen is separated into naphtha and bitumen. The naphtha is recycled to be used again as diluent and the bitumen is upgraded through a coking and distillation process. The upgraded product, referred to as sour crude oil, is either sold directly to customers or is further upgraded into sweet crude oil by removing the sulphur and nitrogen using a hydrogen treating process. Three separate streams of refined crude oil are blended together according to customer specifications. Suncor Energy Marketing Inc. ships these product blends by pipeline for sale and distribution to Suncor's Sarnia, Ontario refinery, as well as other customers in Canada and the United States. Oil Sands entered into a transportation service agreement with a subsidiary of Enbridge Inc. ("Enbridge") for a term that commenced in 1999 and extends to 2028, for pipeline capacity that allows for the initial shipment of 60,000 and increasing to 170,000 barrels per day of sour crude oil and bitumen from Fort McMurray, Alberta to Hardisty, Alberta. As the initial shipper on the pipeline, Suncor's annual tolls payable under the agreement are subject to annual adjustments. The pipeline is operated by Suncor Energy Marketing Inc. The pipeline is expected to meet Suncor's anticipated crude oil shipping requirements for the foreseeable future. The Oil Sands operation meets most of its current energy needs from an existing energy services plant which uses primarily petroleum coke, a by-product of the coking process, as fuel. The operation also consumes natural gas. The natural gas used includes volumes produced by Suncor, as well as natural gas purchased from others. TransAlta commenced operation of this facility in October 1999. The Project Millennium expansion energy requirements are to be met by the existing energy services plant, and Suncor's portion of the output from a new TransAlta owned and operated onsite cogeneration facility. In 1998, Suncor entered into an agreement with Nova Pipeline Ventures Limited Partnership, now known as TransCanada Pipeline Ventures Limited Partnership ("TCPV"), to provide Suncor with firm capacity on a new natural gas pipeline to be constructed by TCPV. This pipeline came into service in 1999. 13 In 1998, Suncor's Mine Expansion on the east side of the Athabasca River began operations. The project included a mine site facilities complex, a 250 tonne capacity bridge over the Athabasca River, and a new ore preparation process. The new ore preparation process utilizes crushers, slurry preparation equipment, and hydrotransport pumps to deliver an oil sand slurry across the Athabasca River through hydro-transport pipelines to the existing extraction plant. The oil sands plant is susceptible to loss of production due to the interdependence of its component systems. In 1999 two unplanned outages of the 5C9 diluent recovery unit lasted a total of 16 days and resulted in approximately 1.8 million barrels of lost production. These outages were precipitated by a change in feedstock resulting from the operation of a new vacuum tower. Parts of the 5C9 unit that failed were redesigned during the second outage in September, with the objective of improving reliability and helping to achieve targeted production rates. Suncor plans to shut down the same unit for routine maintenance before mid-year, 2001, for approximately eight days. There will be no production from the oil sands plant while this maintenance work takes place. Suncor's 130,000 barrels per day average production target for 2001 includes the estimated impact of this maintenance work on production. Project Millennium will involve the duplication of some facilities, thereby reducing the potential for a total loss of production. Severe climatic conditions at Oil Sands can cause reduced production and in some situations result in higher costs. In December 2000, three weeks of prolonged cold weather reduced production. Over the past several years, backup components and systems have been introduced in critical areas to improve reliability. In addition to ongoing preventive maintenance programs, full plant maintenance shutdowns are completed approximately every four years. The next complete shutdown is scheduled for 2002 when the original facilities (excluding the assets associated with Project Millennium) will undergo scheduled maintenance shutdown work. In addition to complete shutdowns, partial shutdowns in the upgrader are undertaken periodically. During these partial shutdown maintenance periods, work can be done while the rest of the plant continues to operate. This reduces both the cost and scope of shutdowns and allows for continued production of sour crude oil during the shutdown period. LEASEHOLD INTERESTS AND ROYALTIES In 1997, regulatory approval was obtained to allow Suncor to mine additional leases on its existing mine site (the "Mine Expansion"). Mining activity on the Mine Expansion, located east of the Athabasca River and south of the Steepbank River, commenced during the third quarter of 1998. 14 Set out in the table below is a summary of Suncor's oil sands leasehold interests as of December 31, 2000.
NUMBER OF GROSS ACRES PERCENTAGE OF REFERRED (NET ACRES IF SYNTHETIC CRUDE DESCRIPTION LEGAL DESCRIPTION TO AS APPLICABLE) OIL PROVED RESERVES ------------------------ ---------------------- ------------ --------------- -------------------- Mine Expansion: Leases 7280100T25 25 17,664 Mine Expansion 7279080T19 19 18,760 Leases and Fee 7597030T11 97 2,483 Lots represent 95% 7280060T23 36,900 7498050014 240 Fee Lots(1) 1 N/A 1,894 (1) 3 N/A 1,967 (1) 4 N/A 1,886 (1) Original Mine 7387060T04 86 4,500 Original Mine Leases 7279120092 17 1,600 Leases represent 5.1% Firebag(2) 7285100T85 85 39,500 (1) Firebag(2) Various(3) Various 266,440 (1) Cheecham(2) 7280100T27 27 49,900 (1) (24,450)
Notes: (1) No proved reserves are attributable to these leases. (2) Leases are principally in-situ. (3) Suncor holds a beneficial interest in 13 leases totaling 266,440 gross and net acres. The Government of Alberta is entitled to royalties under Leases 17, 19, 25, 86 and 97 and fee lots one, three and four at rates which the Government establishes from time to time. Under the Alberta Suncor Crown Royalty Agreement, Crown royalties are 25% of revenues less allowable costs (including capital expenditures), subject to a minimum payment of 5% of gross revenues. In 2000, Suncor made Crown royalty payments based upon the 5% minimum royalty. Suncor transitioned to a generic Oil Sands royalty agreement with the Alberta government in 1999 that provides Suncor with additional allowable cost deductions to a maximum of $158 million per year for 10 years (related to Suncor's original investment in the Oil Sands facility). In 2001, the minimum royalty rate will change to 1% of gross revenues. Suncor currently expects to pay Crown royalties at the minimum 1% rate until 2008, based on assumptions relating to future crude oil prices, production levels, operating costs and capital expenditures. 15 Union Pacific Resources Inc. (a successor to Norcen Energy Resources Limited) has a gross overriding royalty on Lease 86 pursuant to an agreement dated March 1, 1989 (the "Union Pacific Royalty"). The Union Pacific Royalty is based on a graduated scale dependent on the synthetic crude oil price expressed as a percentage of gross revenue from production of the lease. As of December 31, 2000, under the Union Pacific Royalty, no payment is required if synthetic crude prices are below $19.70 per barrel. Payment of 1.5% of gross revenue is required if the synthetic crude price ranges from $19.70 to $20.69 per barrel. For every $1.00 per barrel increase in the price of synthetic crude in the range of $20.70 to $25.69 per barrel, the percentage rate of the royalty increases by 0.5%. For every $1.00 per barrel increase in the price of synthetic crude in the range of $25.70 to $36.69 per barrel, the percentage rate of the royalty increases by a further 0.25% until a maximum royalty of 7% is reached. All synthetic crude prices are calculated on a monthly average basis and the crude price break points are adjusted annually on March 1 of each year by a contractually determined inflation component. Mining is currently expected to be completed on the Union Pacific lease in the 2001/2002 time period. Petro-Canada has a royalty on Lease 19 pursuant to an agreement dated October 6, 1992. The royalty is calculated as 1.5% of net sale proceeds. Net sale proceeds is calculated based upon a formula by which the sale proceeds for the period exceeds the sum of allowed deductions for the period. The Crown royalty regime that will be applicable to the Firebag and Cheecham in-situ leases has not been determined at this time. ESTIMATED SYNTHETIC CRUDE OIL RESERVES Suncor estimates that Leases 86 and 17 (the original leases), and the Mine Expansion leases, on a combined basis, contain proved plus probable reserves of synthetic crude oil totaling 2.5 billion barrels, with 422 million barrels classified as proved. These estimates are before deduction of Crown and applicable royalties on the leases. Under the Crown Royalty Agreement the Crown royalty is dependent on deemed net revenues (Revenue-Cost, or R-C); therefore, the calculation of net reserves would vary depending upon production rates, prices and operating and capital costs. The reserve estimates are based upon a detailed geological assessment including drilling density and laboratory tests and also consider current production capacity and upgrading yields, current mine plans, operating life and regulatory constraints. Based on these factors, additional reserves may be identified when more work on the mine is completed. The current proved plus probable reserve estimate is based on the mine plan approved by the Alberta Energy and Utilities Board. Suncor engaged Gilbert Laustsen Jung Associates Ltd. ("GLJ"), independent petroleum consultants, to audit Suncor's estimate of proved and probable reserves of synthetic crude oil as of December 31, 2000. In their opinion dated January 15, 2001, GLJ state that they believe that there is at least a 90% confidence that the current proved, and 50% confidence that the current proved plus probable, reserve estimates will be exceeded. Their opinion is qualified to the extent that it assumes Suncor will comply with any amendments that may be made to regulatory approvals. Planned future improvements in the extraction (bitumen production) and upgrading processes have not been considered in their report. On-site fuel consumption has been deducted. The independent GLJ audit does not take into account the economic aspects of future reserves. 16 RESERVES RECONCILIATION The following table sets out a reconciliation of Suncor's proved and probable reserves of synthetic crude oil from December 31, 1999 to December 31, 2000.
PROVED RESERVES PROBABLE RESERVES TOTAL --------------- --------------------- ----- (MILLIONS OF BARRELS) December 31, 1999.................. 476 2,028 2,504 Revisions(1)....................... (13) 6 (7) Additions.......................... 0 0 0 Production......................... (41) - (41) --- ----- ----- December 31, 2000.................. 422 2,034 2,456
Note: (1) Substantially all of the proved reserve revisions relate to proved bitumen drilling activity and revisions to the pit design based upon both geotechnical and economic data related to the Mine Expansion leases. REVENUES FROM SYNTHETIC CRUDE OIL AND DIESEL Although revenues after royalties, per barrel, are higher for synthetic crude oil than for conventional crude oil, operating costs to produce synthetic crude oil are higher than lifting and administrative costs to produce conventional crude oil from the Western Canada Sedimentary Basin. While there is no finding cost associated with synthetic crude oil, mine development and expansion of production can entail significant outlays of funds. The costs associated with synthetic crude oil production are largely fixed for the same reason and, as a result, operating costs per unit are largely dependent on levels of production. Since the early 1990's, cost reduction efforts, and higher production levels, have been successful in reducing unit costs. Aside from onsite fuel use, all of Oil Sands production is sold to Suncor Energy Marketing Inc., a wholly owned subsidiary of Sunoco, which then markets the production. In 1997, Suncor and Shell Canada ("Shell") renewed a purchase agreement whereby Shell agreed to purchase and receive approximately 95,000 cubic metres (approximately 600,000 barrels) of sweet synthetic crude oil per month. The original term of the agreement was to December 31, 1997, with 60-day evergreen terms thereafter. The price received is based on a formula involving postings for sweet crude oil. In 1997 Suncor entered into a long-term agreement with Koch Oil Co. Ltd. ("Koch") to supply Koch with up to 30,000 barrels per day (approximately 26% of Suncor's average 2000 total production) of sour crude from Suncor's Oil Sands operation. Suncor began shipping the crude to Koch's refinery in Minnesota under this long-term agreement effective January 1, 1999. The initial term of the agreement extends to January 1, 2009, with month to month evergreen terms thereafter, subject to termination after January 1, 2004, on twenty-four months' notice. In 2000, Suncor announced a long term sales agreement with Consumers Co-operative Refineries Limited ("CCRL") under which Suncor expects to begin supplying CCRL with 20,000 barrels per day of sour crude oil production from its Project Millennium expansion facilities by late 2002. Prices for sour crude oil under these agreements are set at agreed differentials to market benchmarks. There were two customers in 2000, Koch and Shell, that each represented 10% or more of Suncor's consolidated revenues in 2000. Shell was the only such customer in 1999. A portion of Oil Sands production is used in connection with Suncor's Sarnia refining operations. During 2000, the Sarnia refinery processed approximately 25% (1999 -- 26%) of Oil Sands crude oil 17 production. The following table sets forth the average sales price received per barrel of synthetic crude oil from Oil Sands on a quarterly basis for the years 2000 and 1999, after the impact of hedging activities.
---------------------------------------------------------------------------------------------------------------------- 2000 1999 ---------------------------------------------------------------------------------------------------------------------- $/bbl 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q ----- ----- ----- ----- ----- ----- ----- ----- ----- Average sales price 31.33 32.39 31.12 31.84 28.77 24.24 21.57 20.00 ----------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES Capital spending information for Oil Sands is set out in the table under the caption "Capital and Exploration Investing Expenditures" in the Corporate section of the MD&A. ENVIRONMENTAL COMPLIANCE For a description of the impact of environmental protection requirements on Oil Sands, refer to the "Government Regulation" section of this Annual Information Form. NATURAL GAS Suncor's Natural Gas business, based in Calgary, Alberta, explores for, develops, produces and markets natural gas and natural gas liquids from the Western Canada Sedimentary Basin. In April 2000, Suncor's Board of Directors approved a repositioning of the Exploration and Production business, and renamed it Natural Gas to reflect a sharpened focus on natural gas production. The repositioning entailed a workforce reduction of 70 positions, the consolidation of production in three core natural gas areas, and a restructuring of business processes to support the new focus. During 2000, NG sharpened its natural gas focus in Western Canada by concentrating on natural gas prospects and selling most of its conventional crude oil properties. Exiting 2000, natural gas and natural gas liquids accounted for approximately 92% of the NG business unit's production. NG also sold its Burnt Lake property, a project to evaluate steam assisted gravity drainage technology in the production of heavy oil, which had commenced production in 1997 (see the "Conventional Crude Oil" section of this Annual Information Form). Suncor's exploration program is focused on multiple geological zones in three core asset areas: Northern (northeast British Columbia and northwest Alberta), Foothills (western Alberta and portions of northeast British Columbia) and Central Alberta. Suncor drills primarily medium to high-risk wells focusing on prospects that can be connected to existing infrastructure. An in-house natural gas marketing group sells Suncor's proprietary natural gas and natural gas acquired from other producers. During 1997 Suncor entered into a five-year agreement with Enron Capital and Trade Resources Canada Corp. ("ECT") for ECT to provide operational and administrative services to Suncor related to its natural gas portfolio. 18 RESERVES AND RESERVES RECONCILIATION GLJ reported January 26, 2001, on Suncor's estimated proved and probable reserves of natural gas, natural gas liquids and crude oil (other than synthetic crude oil), as of December 31, 2000. Information with respect to these reserves is set out in the tables below and in the tables under the headings "Conventional Crude Oil" and "Natural Gas" (the "Reserves Tables"). GLJ's determination of Suncor's estimated proved and probable recoverable reserves are based on constant year end prices and costs determined as of the dates indicated with no escalation into the future. The accuracy of any reserve estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates presented are considered reasonable, the estimates should be viewed with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. In the Reserves Tables: (1) Proved reserves are considered recoverable under current technology and existing economic conditions, from reservoirs that are evaluated on known drilling, geological, geophysical and engineering data. (2) Proved developed reserves are on production, or reserves that could be recovered from existing wells or facilities, if the Company placed them on production. (3) Probable reserves are those reserves which the analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where analysis suggest the likelihood of their existence and future recovery. Probable reserves to be obtained by the application of enhanced recovery processes will be the increased recovery, over and above that estimated in the proved category, that can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future. A 50% risk factor has been utilized in arriving at probable reserves. (4) Gross reserves represent the aggregate of Suncor's working interest in reserves including the royalty interest of governments and others in such reserves and Suncor's royalty interest in reserves of others. Net reserves are gross reserves less that royalty interest share of others including governments. Royalties can vary depending upon selling prices, production volumes, and timing of initial production and changes in legislation. Net reserves have been calculated, following generally accepted guidelines, on the basis of prices and the royalty structure in effect at year-end and anticipated production rates. Such estimates by their very nature are inexact and subject to constant revision. 19 The following tables set out a reconciliation of NG's estimated proved reserves from December 31, 1999 to December 31, 2000. ESTIMATED PROVED RESERVES RECONCILIATION(1)
GROSS NET --------------------------------- --------------------------------- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS ------------------- ------------ ------------------- ------------ (MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF BARRELS) CUBIC FEET) BARRELS) CUBIC FEET) December 31, 1999............................... 51(2) 1,013 41 764 Revisions of previous estimates................. (3) (52) (6) (81) Purchases of minerals in place.................. - 9 - 7 Extension and discoveries....................... 1 39 1 28 Production...................................... (3) (73) (2) (52) Sales of minerals in place...................... (30) (139) (23) (99) ---- ----- ---- ---- December 31, 2000............................... 16(2) 797 11 567 ==== ===== ==== ====
Notes: (1) Sales of minerals in place includes 3.5 million barrels related to Suncor's Burnt Lake heavy oil extraction pilot project. (2) Includes 9.2 million barrels of natural gas liquids as at December 31, 2000 (15.8 million barrels as at December 31, 1999). Estimated proved reserves are comprised of developed and undeveloped reserves. The following tables show the breakdown between these categories. ESTIMATED PROVED DEVELOPED RESERVES RECONCILIATION (1)
GROSS NET --------------------------------- --------------------------------- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS ------------------- ------------ ------------------- ------------ (MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF BARRELS) CUBIC FEET) BARRELS) CUBIC FEET) December 31, 1999............................... 38 627 30 471 Revisions of previous estimates................. (3) (10) (5) (31) Purchases of minerals in place.................. - 6 - 5 Extension and discoveries....................... 1 69 1 49 Production...................................... (3) (73) (2) (52) Sales of minerals in place...................... (20) (46) (15) (33) ---- ----- ---- ---- December 31, 2000............................... 13 573 9 409 ==== ===== ==== ====
Note: (1) Sales of minerals in place includes 2.5 million barrels of crude oil related to Suncor's Burnt Lake heavy oil extraction pilot project 20 ESTIMATED PROVED UNDEVELOPED RESERVES RECONCILIATION (1)
GROSS NET --------------------------------- --------------------------------- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS ------------------- ------------ ------------------- ------------ (MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF BARRELS) CUBIC FEET) BARRELS) CUBIC FEET) December 31, 1999............................... 13 386 11 293 Revisions of previous estimates................. - (42) (1) (50) Purchases of minerals in place.................. - 3 - 2 Extension and discoveries....................... - (30) - (21) Sales of minerals in place...................... (10) (93) (8) (66) ---- ----- ---- ---- December 31, 2000............................... 3 224 2 158 ==== ===== ==== ====
Note: (1) Sales of minerals in place includes 1.1 million barrels of crude oil related to Suncor's Burnt Lake heavy oil extraction pilot project. The following tables set out a reconciliation of NG's estimated probable reserves from December 31, 1999 to December 31, 2000. ESTIMATED PROBABLE RESERVES RECONCILIATION (1)
GROSS NET --------------------------------- --------------------------------- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS ------------------- ------------ ------------------- ------------ (MILLIONS OF (BILLIONS OF (MILLIONS OF (BILLIONS OF BARRELS) CUBIC FEET) BARRELS) CUBIC FEET) December 31, 1999............................... 20 428 15 322 Revisions of previous estimates................. (2) (69) (2) (63) Purchases of minerals in place.................. - 5 - 4 Extension and discoveries....................... - 2 - 1 Sales of minerals in place...................... (11) (62) (8) (47) ---- ----- ---- ---- December 31, 2000............................... 7 304 5 217 ==== ===== ==== ====
Note: (1) Sales of minerals in place includes 0.5 million barrels related to Suncor's Burnt Lake heavy oil extraction pilot project. CONVENTIONAL CRUDE OIL The following table shows estimates of NG's proved crude oil reserves before royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation") and Suncor's average daily production of crude oil before royalties, in Alberta, British Columbia and Saskatchewan, represented by the conventional fields identified in this table. 21
PROVED RESERVES 2000 AVERAGE BEFORE ROYALTIES AT DAILY PRODUCTION DECEMBER 31, 2000(1) BEFORE ROYALTIES(3) --------------------- ---------------------- (MILLIONS OF (BARRELS OF FIELDS BARRELS) % OIL PER DAY) % ------------------------------ ------------ --- ------------ --- Simonette....................................... 3.3 53 910 22 Blueberry....................................... 2.0 31 390 9 McKinley........................................ 0.3 5 100 2 Bonanza......................................... 0.2 3 80 2 Rosevear........................................ 0.1 2 45 1 Divested Properties............................. 0 0 2,650 63 Other(2)........................................ 0.3 6 40 1 --- --- ----- --- Total -- gross................................... 6.2 100 4,215 100 === === ===== ===
Notes: (1) The reserves and production in this table do not include natural gas liquids. (2) Includes fields in which Suncor holds overriding royalty interests. (3) Production in 2001 will be materially different from 2000 due to strategic divestments. Most of the large conventional oil fields in the western provinces have been in production for a number of years and the rate of production in these fields is subject to natural decline. In some cases, additional amounts of crude oil can be recovered by using various methods of enhanced crude oil recovery, infill drilling and production optimization techniques. At the end of 2000, approximately 75% of Suncor's proved conventional oil reserves were under enhanced oil recovery programs. Suncor's NG business unit had a 79% working interest in a heavy oil extraction pilot project at Burnt Lake, Alberta. This interest was sold in 2000. 22 NATURAL GAS LIQUIDS The following table shows estimates of NG's proved natural gas liquids reserves before royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation") and Suncor's average daily production of natural gas liquids before royalties, in Alberta, British Columbia and Saskatchewan, represented by the conventional fields identified in this table.
PROVED RESERVES 2000 AVERAGE BEFORE ROYALTIES AT DAILY PRODUCTION DECEMBER 31, 2000 BEFORE ROYALTIES --------------------- ---------------------- (MILLIONS OF (BARRELS OF FIELDS BARRELS) % OIL PER DAY) % ------------------------------ ------------ --- ------------ --- Simonette....................................... 2.4 26 592 20 Grande Prairie 1.5 15 206 7 Knopcik......................................... 1.4 14 448 15 Pine Creek...................................... 0.7 8 235 8 Glacier......................................... 0.7 7 96 3 Stolberg 0.5 6 40 1 Blueberry 0.5 6 131 4 Rosevear 0.4 4 147 5 George 0.2 2 309 10 Blackstone 0.1 1 48 2 Hinton 0.1 1 95 3 Mountain Park 0.1 1 19 1 Divested Properties............................. 0 0 125 4 Other(1)........................................ 0.8 9 501 17 --- --- ----- --- Total -- gross.................................. 9.4 100 2,992 100 === === ===== ===
Note: (1) Includes fields in which Suncor holds overriding royalty interests. 23 Natural Gas The following table shows estimates of NG's proved natural gas reserves, before royalties, as prepared by GLJ (see "Reserves and Reserves Reconciliation") and Suncor's average daily production of natural gas before royalties, in Alberta and British Columbia, represented by the major natural gas fields identified in the table.
PROVED RESERVES 2000 AVERAGE BEFORE ROYALTIES AT DAILY PRODUCTION DECEMBER 31, 2000 BEFORE ROYALTIES --------------------- ---------------------- (MILLIONS OF (BILLIONS OF CUBIC FEET FIELDS CUBIC FEET) % PER DAY) % ------------------------------ ------------ --- ------------ --- Stolberg........................................ 207 26 17 8 Blackstone/Brown Creek.......................... 92 12 15 8 Grande Prairie area............................. 61 8 9 5 Mountain Park................................... 54 7 11 5 Glacier......................................... 51 6 10 5 Knopcik area.................................... 50 6 18 9 Rosevear........................................ 49 6 27 13 Simonette....................................... 48 6 11 5 Blueberry....................................... 43 5 11 5 Sinclair........................................ 22 3 7 4 Pine Creek...................................... 17 2 6 3 Cutbank......................................... 15 2 9 5 Divested Properties............................. 0 0 12 6 Other(1)........................................ 88 11 37 19 --- --- --- --- Total -- Gross.................................. 797 100 200 100 === === === ===
Note: (1) Includes fields in which Suncor holds overriding royalty interests. LAND HOLDINGS The following table sets out the undeveloped and developed lands in which the NG business unit held crude oil and natural gas interests at the end of 2000. Undeveloped lands are lands within their primary term upon which no well has been drilled. Developed lands are lands past their primary term or upon which a well has been drilled. The petroleum and natural gas interests include Suncor's undivided percentage interest in leases, licenses, reservations, permits or exploration agreements (collectively the "Agreements"). In general, Agreements confer upon the lessee the right to explore for and remove crude oil and natural gas from the lands, with the lessee paying exploration, development costs, operating costs, abandonment and reclamation costs, subject to paying rentals, taxes and royalties. Interests in Agreements (excluding freehold agreements) are acquired from the federal or provincial governments through competitive bidding or by undertaking work commitments, or by joint venture agreements with industry companies. 24
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL ACRES ----------------------------- ------------------------------ ----------------------------- GROSS ACRES(1) NET ACRES(1) GROSS ACRES(1) NET ACRES(1) GROSS ACRES(1) NET ACRES(1) -------------- ------------ -------------- ------------ -------------- ------------ (THOUSANDS) CANADA CONVENTIONAL Alberta.................... 318 204 738 547 1,056 751 British Columbia........... 111 47 329 247 440 294 Saskatchewan............... 0 0 - - 0 0 --- --- ----- ----- ----- ----- Total Conventional......... 429 251 1,067 794 1,496 1,045 --- --- ----- ----- ----- ----- NON-CONVENTIONAL Alberta.................... 15 4 294 257 309 261 Frontier................... 7 3 535 70 542 73 Total Non-Conventional..... 22 7 829 327 851 334 --- --- ----- ----- ----- ----- UNITED STATES Coal Bed Methane........... - - 18 18 18 18 --- --- ----- ----- ----- ----- AUSTRALIA Coal Bed Methane........... - - 1,280 1,100 1,280 1,100 === === ===== ===== ===== ===== Total Landholdings 451 258 3,194 2,239 3,645 2,497 === === ===== ===== ===== =====
Note: (1) "Gross Acres" means all of the acres in which Suncor has either an entire or undivided percentage interest in. "Net Acres" represents the acres remaining after deducting the undivided percentage interests of others from the gross acres. DRILLING The following table sets forth the gross and net exploratory and development wells, all in Western Canada, which were completed, capped or abandoned in which Suncor participated during the years indicated.
YEAR ENDED DECEMBER 31, ------------------------------------------------- 2000 1999 ------------------ -------------------- GROSS NET GROSS NET ----- --- ----- --- Exploratory Wells Crude oil..................................... 0 0 1 1 Gas........................................... 3 1 6 5 Dry........................................... 17 15 17 13 -- -- -- -- Total Exploratory Wells......................... 20 16 24 19 -- -- -- -- Development Wells Crude oil..................................... 5 2 14 2 Gas........................................... 23 14 9 4 Dry........................................... 4 3 3 1 -- -- -- -- Total Development Wells ........................ 32 19 26 7 -- -- -- -- Total........................................... 52 35 50 26 == == == ==
Not included are wells completed by other companies under farmout agreements relating to lands in which Suncor has an undivided percentage interest, since Suncor did not incur cash expenditures in connection with such wells. In addition to the above wells, Suncor had interests in four gross (two net) exploratory wells in progress at the end of 2000. Also, Suncor had an interest in one gross (one net) coal bed methane well in Alberta. Suncor continues to hold interests in frontier properties (Arctic and Northwest Territories) including 28 long-term "significant discovery licences". 25 WELLS The following table summarizes the wells in which the NG business unit has a working interest or a royalty interest as at December 31, 2000.
PRODUCING NON-PRODUCING WELLS(1)(2) WELLS(1)(3) ------------------ -------------------- GROSS NET GROSS NET ----- --- ----- --- CONVENTIONAL CRUDE OIL WELLS Alberta..................................................... 48 32 22 18 British Columbia............................................ 23 11 6 3 NWT......................................................... - - - - --- --- --- -- Total Conventional Crude Oil Wells............................ 71 43 28 21 --- --- --- -- CONVENTIONAL NATURAL GAS WELLS Alberta..................................................... 45 135 51 27 British Columbia............................................ 45 22 20 13 NWT - 0 2 2 --- --- --- -- TOTAL CONVENTIONAL NATURAL GAS WELLS.......................... 290 157 73 42 --- --- --- -- NON-CONVENTIONAL HEAVY CRUDE OIL Alberta..................................................... 0 0 10 8 --- --- --- -- COAL BED METHANE Alberta..................................................... 0 0 1 1 --- --- --- -- TOTAL WELLS................................................... 361 200 112 72 === === === ==
Notes: (1) Gross wells represent the number of wells in which NG has a working interest and net wells represent NG's aggregate working interest share in such wells. (2) Producing wells are wells producing hydrocarbons or having the potential to produce, excluding shut-in wells. As at December 31, 2000 Suncor has interests in four oil fields and 28 gas fields. (3) Non-Producing Wells represent management's estimate of shut-in wells that could be capable of economic production but were not on production as at December 31, 2000. SALES AND SALES REVENUES The following table shows the breakdown of NG's sources of revenues.
YEAR ENDED GROSS REVENUES(1) DECEMBER 31, ------------------ 2000 1999 ---- ---- ($ MILLIONS) Crude oil and natural gas liquids............................. 77 100 Natural gas................................................... 344 198 Pipeline...................................................... 6 5 Other......................................................... 1 3 --- --- Total......................................................... 428 306 === ===
Note: (1) Includes intersegment revenues. 26 PRODUCTION COSTS The following shows production (lifting) costs in connection with NG's crude oil and natural gas operations for the years indicated.
YEAR ENDED PRODUCTION (LIFTING) COSTS DECEMBER 31, ------------------ 2000 1999 ---- ---- ($ PER BOE OF GROSS PRODUCTION) Average production (lifting) cost of conventional crude oil and gas(1).................. 4.62 4.40
Note: (1) Production (lifting) costs include all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems. It does not include an estimate for future reclamation costs. QUARTERLY VOLUMES AND NETBACK ANALYSIS The following table shows, for natural gas, conventional crude oil and natural gas liquids, for the quarters indicated, Suncor's production volumes, pricing, royalties, operating expenses and netbacks.
2000 1999 ---------------------------------------------------- --------------------------------------------------- 4Q 3Q 2Q 1Q TOTAL 4Q 3Q 2Q 1Q TOTAL -------- -------- ------- ------- -------- ------- ------ ------- ------- --------- NATURAL GAS Production Volume (mmcf/day) 183 200 195 222 200 219 231 225 229 226 -------- -------- ------- ------- -------- ------- ------ ------- ------- --------- Price / mcf 8.02 4.63 3.70 2.96 4.72 2.96 2.48 2.15 2.18 2.44 Royalties / mcf (2.14) (1.09) (0.85) (0.61) (1.17) (0.72) (0.37) (0.23) (0.28) (0.40) Operating Expenses / mcf (0.95) (0.68) (0.77) (0.66) (0.76) (0.68) (0.77) (0.58) (0.61) (0.66) -------- -------- ------- ------- -------- ------- ------ ------- ------- --------- Netback / mcf 4.93 2.86 2.08 1.69 2.79 1.56 1.34 1.34 1.29 1.38 ======== ======== ======= ======= ======== ======= ====== ======= ======= ========= CONVENTIONAL CRUDE OIL Production Volume (kbbls/day) 1.6 3.6 3.5 8.1 4.2 7.9 8.4 9.7 10.8 9.2 -------- -------- ------- ------- -------- ------- ------ ------- ------- --------- Price / bbl 36.01 33.09 30.04 26.30 29.50 25.21 20.55 20.48 18.48 20.94 Royalties / bbl (11.52) (9.70) (8.29) (8.31) (9.46) (7.00) (5.54) (3.81) (2.29) (4.66) Operating Expenses / bbl (9.47) (6.79) (7.65) (6.62) (7.63) (6.76) (7.69) (5.83) (6.07) (6.59) -------- -------- ------- ------- -------- ------- ------ ------- ------- --------- Netback / bbl 15.02 16.60 14.10 11.37 12.41 11.45 7.32 10.84 10.12 9.69 ======== ======== ======= ======= ======== ======= ====== ======= ======= ========= NATURAL GAS LIQUIDS Production Volume (kbbls/day) 2.5 2.8 3.1 3.5 3.0 4.0 4.1 4.1 4.7 4.2 -------- -------- ------- ------- -------- ------- ------ ------- ------- --------- Price / bbl 43.00 39.56 32.80 33.16 36.66 27.12 22.81 16.70 11.88 19.32 Royalties / bbl (12.62) (11.50) (9.55) (9.25) (10.73) (7.44) (5.89) (4.96) (3.40) (5.42) Operating Expenses / bbl (9.47) (6.79) (7.65) (6.62) (7.63) (6.76) (7.69) (5.83) (6.07) (6.59) -------- -------- ------- ------- -------- ------- ------ ------- ------- --------- Netback / bbl 20.91 21.27 15.60 17.29 18.30 12.92 9.23 5.91 2.41 7.31 ======== ======== ======= ======= ======== ======= ====== ======= ======= =========
27 MARKETING, PIPELINE AND OTHER OPERATIONS Suncor operates gas processing plants at South and North Rosevear, Pine Creek, Boundary Lake South, Progress, and Simonette with a total design capacity of approximately 243 million cubic feet per day. Suncor's interest in these gas processing plants is approximately 166 million cubic feet per day. Suncor also has varying working interests in natural gas processing plants operated by other companies. Approximately 70% of Suncor's natural gas production is marketed under direct sales arrangements to customers in Alberta, eastern Canada, and the U.S. midwest and west coast. This includes a significant volume of natural gas consumed in Suncor's Oil Sands plant at Fort McMurray and in its Sarnia refinery. NG contracts for the supply of natural gas to each of these facilities. Natural gas consumption at the Oil Sands plant in 2000 was 24 million cubic feet per day and is anticipated to range from 50 - 100 million cubic feet per day during Project Millennium commissioning in 2001. Natural gas consumption at the Sarnia refinery in 2000 was 21 million cubic feet per day. Contracts for these direct sales arrangements are of varied terms, with a majority having terms of one year or less, and incorporate pricing which is either fixed over the term of the contract or determined on a monthly basis in relation to a specified market reference price. Under these contracts, NG is responsible for transportation arrangements to the point of sale. Sales to the U.S. are made under a variety of arrangements with differing transportation and pricing terms. Approximately 30% of Suncor's natural gas production is sold under existing contracts to aggregators ("system sales"). Proceeds received by producers under these sales arrangements are determined on a netback basis, whereby each producer receives revenue equal to its proportionate share of sales less regulated transportation charges and a marketing fee. Most of NG's system sales volumes are contracted to TransCanada Gas Services and Pan-Alberta Gas Ltd. These companies resell this natural gas primarily to eastern Canadian and midwest and eastern U.S. markets. To ensure ongoing direct sales access to U.S. markets, NG has entered into long-term gas pipeline transportation contracts. Suncor currently has 14 million cubic feet per day of firm capacity on the Northern Border Pipeline to the U.S. midwest, that expires October 31, 2003. Suncor also has firm capacity of 40 million cubic feet per day on the Pacific Gas Transmission ("PGT") pipeline to the California border extending to the year 2023. Suncor's crude oil production is used in its refining operations, exchanged for other crude oil with Canadian or U.S. refiners, or sold to Canadian and U.S. purchasers. Sales are generally made under spot contracts or under contracts that are terminable on relatively short notice. Suncor's conventional crude oil production is shipped on pipelines operated by independent pipeline companies. NG currently has no pipeline commitments related to the shipment of crude oil. The Suncor-owned Albersun pipeline, operated by Suncor Energy Marketing Inc., was constructed in 1968 to transport natural gas to the Oil Sands plant. It extends approximately 180 miles south of the plant and connects with the TCPL Alberta intraprovincial pipeline system. The Albersun pipeline has the capacity to move in excess of 100 million cubic feet per day of natural gas. Suncor arranges for natural gas supply and controls most of the natural gas on the system under delivery based contracts. The pipeline moves natural gas both north and south for Suncor and other shippers. In 2000, throughput on Albersun pipeline was 68 million cubic feet per day and revenues were approximately $6 million. CAPITAL AND EXPLORATION EXPENDITURES Capital and exploration spending information for Suncor's NG business unit is set out in the table under the caption "Capital and Exploration Investing Expenditures" in the Corporate section of MD&A. 28 ENVIRONMENTAL COMPLIANCE For a description of the impact of environmental protection requirements on NG, refer to the information under the headings, "Risk/Success Factors Affecting Performance" in the Natural Gas Section of the MD&A, and also to the "Government Regulation" section of this Annual Information Form. SUNOCO Suncor conducts its refining and retail marketing of petroleum products and petrochemicals through its principal subsidiary, Sunoco Inc., and its subsidiaries and joint ventures. Sunoco's operations are carried out by three divisions: Refining (including wholesale), Retail Marketing, and Integrated Energy Solutions. REFINING SARNIA REFINERY. Located in Sarnia, Ontario, the Sunoco refinery has an economic refining capacity of 70,000 barrels of crude oil per day and average 2000 refining sales of approximately 92,200 barrels per day. This complex refinery has the flexibility to produce a high proportion of transportation fuels and value-added petrochemicals. The configuration of the refinery permits the processing of a high percentage of sweet synthetic crude oil, in addition to conventional sweet and sour crudes. The competitive advantage of processing sweet synthetic crude oil is that it is low in sulphur and heavy petroleum products (less valuable products) yielding a more valuable product mix. The refinery has cracking capacity of 40,200 barrels per day from a Houdry catalytic cracker and a hydrocracker. Approximately 40% of the cracking capacity at the refinery is attributable to the Houdry catalytic cracker, which was built in the early 1950s and uses an older cracking technology. In 2000, some additional maintenance costs were incurred as the result of unplanned outages. The next major maintenance on the Houdry catalytic cracker is expected in 2001. The hydrocracker, which is capable of processing approximately 23,300 barrels per day, adds flexibility by producing premium distillate and napthas. An alkylation unit, capable of processing 5,400 barrels per day, complements a petrochemical plant for flexibility in gasoline, octane and petrochemical production. The addition of a jet fuel tower in 1993 and a low sulphur diesel tower in 1995 further added to the refinery's ability and flexibility to produce premium-valued transportation fuels. As a result of this configuration, the refinery has flexibility to vary its gasoline/distillate ratio. In 2000 a solvents unit was added. With a capacity of 3,100 barrels per day, the unit produces two streams of chemical products, A-100 and A-150, which were not previously produced at the Sarnia refinery. These chemical products are of a higher value than the streams they replaced, broadening Sunoco's chemical product slate and expanding the Company's customer base to include paint and chemical manufacturers. The total chemicals output of the Sarnia refinery increased in 2000 as a result of the addition of the new unit. 29 The following chart sets out the average daily crude input, average refinery utilization rate, and cracking capacity utilization of the Sarnia refinery over the last two years:
2000 1999 ------ ------ Crude input -- barrels per day...................................... 68,900 66,500 Average utilization rate (%)(1)..................................... 98 95 Average cracking capacity utilization (%)(2)........................ 91 96
Notes: (1) Based upon crude unit processing capacity and input to crude units. (2) Based upon rated throughput capacity and input to units. During 2000, the Sarnia refinery completed a planned 32-day turnaround on the hydrocracker. The work was completed on time and on budget. Several unplanned outages were also experienced during 2000. In the next regular turnaround in 2001, specific maintenance work to address the operational issues will be integrated into the plan. SOURCES OF FEEDSTOCK. Sunoco's refining operation uses both synthetic and conventional crude oil. In 2000, 64% of the crude oil refined at the Sarnia refinery was synthetic crude oil, compared with 65% in 1999, the remainder being conventional crude oil and condensate. Of the synthetic crude oil refined, approximately 56% in 2000 was from Suncor's Oil Sands plant production compared to 63% in 1999, with the balance purchased from others under month to month contracts. In the event of a significant disruption in the supply of synthetic crude oil from either Suncor's Oil Sands business unit or the other suppliers of synthetic crude oil, additional sweet or sour conventional crude oil would be processed. Conventional crude oil refined by Sunoco comes mainly from western Canada, supplemented from time to time with crude oil from the United States and other foreign sources purchased or obtained in exchange for Canadian crude. Crude oil from other countries can be delivered to Sarnia via pipeline from the United States Gulf Coast and from the east coast, via the Interprovincial Pipeline from Sarnia to Montreal (Line 9), which began shipping in an east-west direction in October 1999. Sunoco has not committed to firm pipeline capacity on either of these lines. The market for crude oil generally is conducted on a spot basis or under contracts terminable by short notice. Production of transportation fuels is enhanced through a buy/sell agreement with Nova Chemicals (Canada) Ltd., a petrochemical refinery in which feedstocks more suitable for gasoline blending are taken by Sunoco in exchange for feedstocks more suitable for petrochemical cracking. Reciprocal product buy/sell and exchange agreements are also used with other refiners to minimize transportation costs, balance product availability in particular locations, and enhance refinery utilization. These agreements are entered into from time to time, and renewed as necessary. On occasion, Sunoco purchases refined products to supplement its own refinery production. Since late 1997, Sunoco has been marketing ethanol-enhanced gasolines through all of its Sunoco branded service stations. In order to secure supply, Sunoco signed an exclusive 10-year ethanol fuel supply agreement with Commercial Alcohols Inc., which constructed a 150 million litre per year capacity ethanol plant near Chatham, Ontario. The agreement with Commercial Alcohols Inc. terminates in 2007. By the end of 2000, Sunoco's ethanol enhanced gasolines were also being sold through most of the joint-venture operated retail service stations. PRINCIPAL PRODUCTS. The refinery produces transportation fuels, heating fuels, heavy fuel oils, and petrochemicals and liquefied petroleum gases. Sunoco's petrochemical facilities, with a design capacity of 13,100 barrels per day (approximately 2,090 cubic metres), produce benzene, toluene and mixed xylenes and recover orthoxylene from mixed xylenes, as well as petrochemicals A-100 and A-150. 30 Noted below is information on Sunoco's daily sales volumes for the last two years.
DAILY SALES VOLUMES 2000 1999 ------------------- ------ ------ (THOUSANDS OF CUBIC METRES PER DAY) Transportation fuels Gasoline -- retail (1)............................................. 4.2 4.1 -- other.................................................. 4.0 3.7 Jet fuel........................................................... 1.1 1.1 Other.............................................................. 3.1 2.7 ---- ---- 12.4 11.6 ---- ---- Petrochemicals..................................................... 0.6 0.7 Heating fuels...................................................... 0.4 0.4 Heavy fuel oils.................................................... 0.6 0.5 Other.............................................................. 0.6 0.6 ---- ---- Total.............................................................. 14.6 13.8 ==== ====
Note: (1) Excludes sales through joint ventures. Sales of gasolines and other transportation fuels represented 69% of Sunoco's consolidated sales and other operating revenues in 2000 compared to 62% in 1999. TRANSPORTATION AND DISTRIBUTION. A variety of transportation modes are used to deliver products to markets, including pipeline, water, rail and road. Sunoco owns and operates petroleum transportation, terminal and dock facilities in support of its refining and marketing activities. Such assets include storage facilities and bulk distribution plants in Ontario and a 55% interest in the Sun-Canadian Pipe Line, a refined products pipeline between Sarnia and Toronto. The major mode of transportation for gasolines, diesel, jet fuel and heating fuels from the Sarnia refinery to its core markets in Ontario is the refined products pipeline owned and operated by Sun-Canadian Pipe Line Company Limited. The pipeline serves terminal facilities in London, Hamilton and Toronto, and has a capacity of 126,000 (20,000 m(3)) barrels per day of which 84% was utilized in 2000 and 83% was utilized in 1999. Ownership of the pipeline company is divided between Suncor with a 55% interest, and another integrated refiner with a 45% interest. The pipeline operates as a private facility for its owners. Sunoco also has direct pipeline access to petroleum markets in the Great Lakes region of the United States by way of connection to a pipeline system at Sarnia operated by a U.S. based refiner. This link to the United States allows Sunoco to quickly move products to market or obtain feedstocks or products when market conditions are favourable in the Michigan and Ohio markets. Sunoco believes that its own facilities and those under long-term contractual arrangements with other parties will provide a sufficient level of storage for its current and foreseeable needs. PRINCIPAL MARKETS. Sunoco markets transportation fuels (gasoline, diesel, propane and jet fuel), heating fuels, liquefied petroleum gases, residual fuel oil and asphalt feedstock to its retail marketing business and industrial, commercial and wholesale customers and refiners, primarily in Ontario. In Quebec, Sunoco supplies its industrial and commercial customers through long-term arrangements with other regional refiners or through Group Petrolier Norcan Inc., a 25% Suncor-owned fuels terminal and product supply business in Montreal, Quebec. In addition, at the end of 2000, Sunoco markets diesel through eleven branded Fleet Fuel Cardlock sites. Sunoco also markets toluene, mixed xylenes, orthoxylene and petrochemicals, primarily in Canada and the United States, through Sun Petrochemicals Company. Suncor Energy Marketing Inc. 31 has a 50% interest in Sun Petrochemicals Company, a petrochemical marketing joint venture established in 1992 with a subsidiary of a U.S. refiner, to market products from a Toledo, Ohio refinery owned by the joint venture partner, and Sunoco's Sarnia refinery. Under this arrangement, petrochemicals used to manufacture plastics, rubber, synthetic fibres, industrial solvents and agricultural products, and as gasoline octane enhancers, are marketed. All Sunoco's benzene production is sold directly to other petrochemical manufacturers in Sarnia, and sales of other petrochemical products are made mostly in North America. Approximately 84% of Sunoco's total gasoline volumes are sold through the retail marketing channels referred to under the heading "Retail Distribution Channels" below. The remainder is sold through wholesale, commercial and industrial accounts in Ontario and Quebec which sell transportation fuels (including gasoline, diesel and jet fuels) and heating oil. Sunoco's share of total refined product sales in its primary market of Ontario is approximately 17% (1999 - approximately 16%). Sales of transportation fuels accounted for over 85% of Sunoco's total volumes in 2000. Petrochemicals sales represented over 3% of total volumes, and the remaining volumes were comprised of other refined products such as heating fuels, heavy oils, and liquefied petroleum gases which were sold to various industrial users and resellers. RETAIL MARKETING RETAIL DISTRIBUTION CHANNELS. Sunoco's retail marketing division consists of three distinct distribution channels o 301 Sunoco retail service stations, o 154 Pioneer-operated retail service stations (Pioneer Group Inc. is an independent retailer with which Sunoco has a 50% joint venture partnership), and o 54 UPI-operated service stations and a network of bulk distribution facilities for rural and farm fuels (UPI Inc. is a 50% joint venture company owned by Sunoco and GROWMARK Inc., a U.S. midwest agricultural supply and grain marketing cooperative). Volumes to the Pioneer and UPI joint ventures are supplied under exclusive supply agreements. The agreement with UPI expires in 2002, after which Sunoco will continue to be the exclusive supplier of refined products as long as it remains a shareholder. Sunoco plans to maintain its relationship with this joint venture. The Pioneer agreement expires in 2003 and it will be automatically renewed thereafter for one-year terms until terminated upon twelve months prior written notice. No notice has been given. INTEGRATED ENERGY SOLUTIONS In 1997, Sunoco entered the residential and commercial natural gas marketing business in Ontario. This initiative was considered to be the first step to broaden Sunoco's energy offering. Sunoco now serves more than 130,000 residential and commercial customer accounts in Ontario. Despite a small percentage of the customer contracts still tied to utility-regulated rates, which have lagged behind the rising market prices, over 95% of Sunoco's customer contracts have been converted to fixed-price sales contracts. These are matched with fixed-price supply arrangements to mitigate risk exposure to market volatility and to yield a positive margin in 2001. CAPITAL EXPENDITURES Capital spending information for Sunoco is set out in the table under the caption, "Capital and Exploration Investing Expenditures" in the Corporate section of the MD&A. 32 ENVIRONMENTAL COMPLIANCE For a description of the impact of environmental protection requirements on Sunoco, refer to "Environmental Performance" and "Risk/Success Factors Affecting Performance" in the Sunoco section of MD&A, and also to the "Government Regulation" section of this Annual Information Form. SUNCOR EMPLOYEES The following table shows the distribution of employees among Suncor's three business units, its corporate office and the Stuart Oil Shale Project for the past two years.
YEAR ENDED DECEMBER 31, ------------------- 2000 1999 ----- ----- Oil Sands........................................................... 2,057 1,741 Natural Gas......................................................... 182 314 Sunoco(1)........................................................... 590 591 Stuart Project...................................................... 77 68 Corporate(2)........................................................ 137 82 ----- ----- Total............................................................... 3,043 2,796 ===== =====
Notes: (1) Excludes joint venture employees. (2) Reflects inclusion of Calgary-based employees providing technical support to the Firebag In-Situ Project, as well as some information technology employees who were previously counted within the individual business units. In addition to Suncor employees, independent contractors supply a range of services to the Company. The Communications, Energy and Paperworkers Union Local 707 represents approximately 1,250 Oil Sands employees. The current collective agreement expires on May 1, 2001. Management believes Suncor's positive working relationship will continue and that a new agreement should be reached without work interruptions. Employee associations represent approximately 170 Sunoco Sarnia refinery and Sun-Canadian Pipe Line Company employees. In September 1999, Sunoco signed a new two-year agreement with the employee associations, which will be renegotiated in 2001. Sunoco management believes Sunoco's positive working relationship will continue and a new agreement should be reached. Relations with these associations have been constructive for many years. 33 RISK/SUCCESS FACTORS VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES. Suncor's future financial performance is closely linked to oil prices, and to a lesser extent natural gas prices. The price of these commodities can be influenced by global and regional supply and demand factors. Worldwide economic growth, political developments, compliance or non-compliance with quotas imposed upon members of the Organization of Petroleum Exporting Countries and weather can affect world oil supply and demand. Natural gas prices realized by Suncor are affected primarily by North American supply and demand and by prices of alternate sources of energy. All of these factors are beyond Suncor's control and can result in a high degree of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials between heavy and light grades of crude oil. Oil and natural gas prices have fluctuated widely in recent years and Suncor expects continued volatility and uncertainty in crude oil and natural gas prices. A prolonged period of low crude oil prices could affect the value of Suncor's crude oil and gas properties and the level of spending on development projects, and could result in curtailment in production at some properties, and accordingly could have an adverse impact on Suncor's financial condition and liquidity and results of operations. Suncor cannot control the factors that influence supply and demand or the prices of crude oil or natural gas. Suncor cannot control the prices of crude oil or natural gas, or currency exchange rates. However, the Company has a hedging program that fixes the price of crude oil and natural gas and the associated exchange for a percentage of Suncor's total production volume. Suncor's objective is to lock in prices on a portion of its future production today to reduce exposure to market volatility and ensure the Company's ability to finance growth. If an operational upset occurred that reduced or eliminated crude oil and/or natural gas production for a period of time, Suncor would be required to continue to make payments under its hedging program if the actual price was higher than the price hedged. For particulars of Suncor's hedging position as of year-end 2000, see note 18 of Suncor's consolidated financial statements. Suncor conducts an assessment of the carrying value of its assets to the extent required by Canadian GAAP. If crude oil and natural gas prices decline, the carrying value of Suncor's assets could be subject to downward revisions, and Suncor's earnings could be adversely affected. In 2000, Suncor wrote down the carrying value of its investment in the Stuart Oil Shale Project. In addition, as result of a decision to dispose of properties that were no longer viewed as core or strategic to ongoing plans of Suncor's Natural Gas business, the carrying values of these properties were written down to their net estimated recoverable amount and a provision for estimated restructuring costs was recorded. RISK FACTORS RELATED TO PROJECT MILLENNIUM. The present capital cost estimate for completion of Project Millennium is $2.8 billion, up from original estimates. There are certain risks associated with the Project Millennium schedule, resources (including securing materials, skilled labour and equipment) and cost, including the risk that current cost estimates will be exceeded. At this stage of the project, the main risks to Project Millennium execution include the potential for reduced productivity and increased costs that can be associated with weather, or unforeseen disruptions in the supply of labour. While Project Millennium design mainly utilizes established technologies, the commissioning of all the new units and the integration of the new facilities with the existing asset base could cause delays in achieving the expected production capacity of 225,000 barrels per day by 2002. Suncor believes that the planned increases in Oil Sands production present issues that require prudent risk management, including, but not limited to: Suncor's ability to finance Oil Sands growth if commodity prices were to stay at low levels for an extended period; the impact of new entrants to the oil sands business which could take the form of competition for skilled people, increased demands on the Fort McMurray, Alberta infrastructure (for example, housing, roads and schools), or price competition for products sold into the marketplace; the potential ceiling on the demand for synthetic crude oil; and the impact of changing standards for government regulation and public expectations in relation to the impact of oil sands development on the environment. 34 INCREASED DEPENDENCE ON OIL SANDS BUSINESS. The Company's significant capital commitment to complete Project Millennium may require it to forego investment opportunities in other segments of its operations. Equally significant capital commitments may be required and made in future toward achievement of Suncor's long term vision for its Oil Sands operations. In addition, completion of Project Millennium, and any such future projects to increase production capacity at Oil Sands, will substantially increase the Company's dependence on the Oil Sands segment of its business. When Project Millennium is completed, for example, the Oil Sands business could account for 90% of Suncor's upstream production in 2002 compared to 70% in 1998. To mitigate this, twinning of the extraction and upgrading processes after completion of Project Millennium will reduce the impact of disruption in operations. COMPETITION. The petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of crude oil and gas interests, and the refining, distribution and marketing of petroleum products and chemicals. Suncor competes in virtually every aspect of its business with other energy companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. Suncor offers custom blends of synthetic crude oil to meet specific customer demands. Suncor believes that the competition for its custom blended synthetic crude oil production is Canadian conventional and synthetic sweet and sour crude oil. A number of other companies have indicated they are planning to enter the oil sands business and begin production of synthetic crude oil, or expand existing operations. Expansion of existing operations and development of new projects could materially increase the supply of synthetic crude oil and other competing crude oil products in the marketplace. Depending on the levels of future demand, increased supplies could have a negative impact on prices. If all announced competing projects were to be built, they could quadruple production of bitumen and upgraded synthetic crude oil to more than two million barrels (320,000 cubic metres) per day. In the western Canadian diesel market demand and supply can fluctuate. Currently there is excess supply of diesel fuel and Suncor expects the market could be impacted by this excess supply and have a negative impact on margins. Margins for diesel are typically higher than the margins for synthetic and conventional crude oil. The above noted expansion plans of Suncor's competitors could also result in an increase in the supply of diesel and further weakening of margins. Over the past five years the industry-wide oversupply of refined petroleum products and the overabundance of retail outlets have kept pressure on downstream margins. Management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. In addition, as Suncor's downstream business unit, Sunoco, participates in new product markets, such as natural gas and potentially electricity, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations. NEED TO REPLACE CONVENTIONAL NATURAL GAS RESERVES. The future natural gas reserves and production of the Company's NG business unit and, therefore, NG's cash flow from such production are highly dependent on its success in discovering or acquiring additional reserves and exploiting its current reserve base. Without natural gas reserve additions through exploration and development or acquisition activities, NG's conventional natural gas reserves and production will decline over time as reserves are depleted. For example, in 2000, Suncor's natural gas average reservoir decline rates were in the 28% range, consistent with industry experience. Decline rates will vary with the nature of the reservoir, life-cycle of the well, and other factors. Therefore past decline rates are not necessarily indicative of future performance. Exploring for, developing and acquiring reserves is highly capital intensive. To the extent cash flow from operations is insufficient to generate sufficient capital and external sources of capital become limited or unavailable, NG's ability to make the necessary capital investments to maintain and expand its conventional natural gas reserves could be impaired. In addition, NG's long term performance is dependent on its ability to consistently and competitively find and develop low cost, high-quality reserves that can be economically brought on stream. Market demand for land and services can also increase or decrease finding and development costs. There can be no assurance that Suncor will be able to find and develop or acquire additional reserves to replace production at acceptable costs. 35 OPERATING HAZARDS AND OTHER UNCERTAINTIES. Each of Suncor's three principal business units, Oil Sands, NG and Sunoco, require high levels of investment and have particular economic risks and opportunities. Generally, Suncor's operations are subject to hazards and risks such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts and oil spills, any of which can cause personal injury, damage to property, equipment and the environment, as well as interrupt operations. In addition, all of Suncor's operations are subject to all of the risks normally incident to the transportation, processing and storing of crude oil, natural gas and other related products. At Oil Sands, mining oil sand, extracting bitumen from the oil sand, and upgrading bitumen into synthetic crude oil and other products, involve particular risks and uncertainties. The Oil Sands plant located near Fort McMurray in northern Alberta is susceptible to loss of production, slowdowns, or restrictions on its ability to produce higher value products due to the interdependence of its component systems. Severe climatic conditions at Oil Sands can cause reduced production and in some situations result in higher costs. During December 2000, for example, three weeks of prolonged cold weather conditions impacted productivity and costs. While there is no finding cost associated with synthetic crude oil, mine development and expansion of production can entail significant capital outlays. The costs associated with synthetic crude oil production at Oil Sands are largely fixed and, as a result, operating costs per unit are largely dependent on levels of production. Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Certain aboriginal peoples have filed a claim against the government of Canada, certain governmental entities and the Regional Municipality of Wood Buffalo (which includes the city of Fort McMurray, Alberta), claiming, among other things, a declaration that the plaintiffs have aboriginal title to large areas of lands surrounding Fort McMurray, including the lands on which Oil Sands and most of the other oil sand operations in Alberta are situated. To Suncor's knowledge the aboriginal peoples have made no claims against Suncor and Suncor is unable to assess the effect, if any, the claim would have on its Oil Sands operations. In Suncor's NG business unit, the risks and uncertainties associated with the exploration for, and the development, production, transportation and storage of crude oil, natural gas and natural gas liquids should not be underestimated or viewed as predictable. NG's operations are subject to all of the risks normally incident to drilling for natural gas wells, the operation and development of such properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution, and other environmental risks. Suncor's downstream business unit, Sunoco, is subject to all of the risks normally incident to the operation of a refinery, terminals and other distribution facilities, as well as service stations, including loss of product or slowdowns due to equipment failures or other accidents. Although Suncor maintains a risk management program, including an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable. Losses resulting from the occurrence of these risks could have a material adverse impact on Suncor. Under the Company's business interruption insurance coverage, the company would bear the first $70 million of any loss arising from a future insured incident at its Oil Sands operations. In addition, there are risks associated with growth projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies, such as the Stuart Oil Shale Project, cannot be assured. There are also inherent risks, including political and foreign exchange risk, in investing in business ventures internationally. To date, other than the Stuart Oil Shale Project, Suncor has not made material international investments. However, export sales in 2000 represented 14% of Suncor's 2000 consolidated revenue (1999 - 10%). 36 INTEREST RATE RISK. Suncor is exposed to fluctuations in short-term Canadian interest rates as a result of the use of floating rate debt. Suncor maintains a substantial portion of its debt capacity in revolving, floating rate bank facilities and commercial paper, with the remainder issued in fixed rate borrowings. To minimize its exposure to interest rate fluctuations, Suncor occasionally enters into interest rate swap agreements and exchange contracts to effectively fix the interest rate on floating rate debt. EXCHANGE RATE FLUCTUATIONS. Suncor's consolidated financial statements are presented in Canadian dollars. Results of operations are affected by the exchange rates between the Canadian dollar and the U.S. dollar. These exchange rates have varied substantially in the last five years. A substantial portion of Suncor's revenue is received by reference to U.S. dollar denominated prices. Oil prices are generally set in U.S. dollars, while Suncor's sales of refined products are primarily in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollar may therefore give rise to foreign currency exposure, either favorable or unfavorable, creating another element of uncertainty. In the future, the strength of the Canadian dollar relative to foreign currencies could create additional uncertainties for Suncor as it pursues its international growth plans. ENVIRONMENTAL RISKS. Environmental legislation affects nearly all aspects of Suncor's operations. These regulatory regimes are laws of general application that apply to Suncor in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require Suncor to obtain operating licenses and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum productions and petrochemicals. Environmental assessments are required before initiating most new major projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, Suncor expects further changes will likely be required to preserve and protect the environment and quality of life. Some of the issues under discussion include: possible cumulative impacts of oil sands development in the Athabasca region; reducing or stabilizing various emissions, including greenhouse gases; land reclamation and restoration; Great Lakes water quality; and reformulated gasoline to support lower vehicle emissions. Changes in environmental legislation could have a potentially adverse effect on Suncor from the standpoint of product demand, product reformulation and quality, and methods of production and distribution. For example, requirements for cleaner-burning fuels could cause additional costs, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on Suncor. Management anticipates capital expenditures and operating expenses will increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties, liability for clean up costs and damages and the loss of important permits. Suncor is required to and has posted annually with Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced ($13 million as at December 31, 2000) as security for the estimated cost of its reclamation activity on Leases 86 and 17, and the Steepbank Mine. For Project Millennium, Suncor has posted an irrevocable letter of credit equal to approximately $26 million, representing security for the estimated cost of reclamation activities relating to Project Millennium up to the end of January 2001. UNCERTAINTY OF RESERVE ESTIMATES. The reserve data for Suncor's Oil Sands and NG business units, included in Suncor's Annual Information Form, represent estimates only. There are numerous uncertainties inherent in estimating quantities of these proved reserves, including many factors beyond the control of Suncor. In general, estimates of economically recoverable reserves are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effect of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. The accuracy of any reserve estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. In the Oil Sands business unit, reserve estimates are based upon a geological assessment, including drilling and laboratory tests, and also consider current production capacity and upgrading yields, current mine plans, operating life and 37 regulatory constraints. In the NG business unit, reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. For these reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, and in NG the classification of such reserves based on risk of recovery prepared by different engineers or by the same engineers at different times, may vary substantially. At Oil Sands, the independent audit does not take into account the economic aspects of future reserves. Suncor's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. RISKS SPECIFICALLY RESPECTING SUNOCO. Sunoco's operations are sensitive to wholesale and retail margins for its refined products, including gasoline. Margin volatility is influenced by overall marketplace competitiveness, weather, the cost of crude oil (See "Volatility of Crude Oil and Natural Gas Prices.") and fluctuations in supply and demand for refined products. Sunoco expects that margin volatility and overall marketplace competitiveness will continue. In 1998, the Canadian government passed legislation limiting sulphur levels in gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. The Canadian refining industry faces significant capital spending to construct sulphur removal facilities to meet these requirements. No regulations have been tabled at this time with respect to sulphur levels in diesel, although Suncor expects limits that will be less than its current capabilities. Actual capital spending required for Sunoco to meet the announced and anticipated new standards for both gasoline and diesel is subject to the findings of a strategic assessment underway at Sunoco. Decisions relative to gasoline will be finalized and a detailed implementation plan will be completed in 2001. The cost to comply with the anticipated sulphur in diesel limits could be significant but are not expected to place the Company at a competitive disadvantage. LABOUR RELATIONS. Suncor's hourly employees at its Oil Sands facility near Fort McMurray and its Sarnia refinery are represented by a labor union and an employee association, respectively. Suncor's collective agreement with the Communications, Energy and Paperworkers Union Local 707 at Oil Sands expires on May 1, 2001. Suncor believes that the current positive working relationship will continue and that a new agreement should be reached without work interruptions, although no assurance can be given in this regard. Other building trades labour agreements expire on April 30, 2001. While Suncor is not a direct party to these agreements they impact Suncor as these trades supply labour for much of Project Millennium. Project Millennium management has developed a working relationship with the trade unions and believes a satisfactory resolution will be reached that will not impede progress on the project. Any work interruptions could materially and adversely affect Suncor's business and financial position. GOVERNMENTAL REGULATION. The oil and gas industry in Canada, including the oil sands industry, operates under federal, provincial and municipal legislation, regulation and intervention by governments in such matters as land tenure, prices, royalties, production rates, environmental protection controls, income, the exportation of crude oil, natural gas and other products, as well as other matters. This industry is also subject to regulation and intervention by governments in such matters as the awarding or acquisition of exploration and production, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights. Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain regulatory approvals. The regulatory approval process can involve stakeholder consultation, environmental impact assessments and public hearings, among other things. In addition, regulatory approvals may be subject to conditions including security deposit obligations and other commitments. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays and abandonment or restructuring of projects and increased costs, all of which could negatively affect future earnings and cash flow. Such regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas, increase Suncor's costs and have a material adverse impact. 38 SELECTED CONSOLIDATED FINANCIAL INFORMATION SELECTED CONSOLIDATED FINANCIAL INFORMATION The following selected consolidated financial information for each of the years in the three-year period ended December 31, 2000 is derived from Suncor's consolidated financial statements. The consolidated financial statements for each of the years in the three-year period ended December 31, 2000 have been audited by PricewaterhouseCoopers LLP (formerly Coopers & Lybrand), Chartered Accountants. Suncor's 2000 audited consolidated financial statements include the audit report of PricewaterhouseCoopers LLP for each of the years in the three-year period ended December 31, 2000. The information set forth below should be read in conjunction with the MD&A and Suncor's consolidated comparative financial statements and related notes.
YEAR ENDED DECEMBER 31,(1) ---------------------------- 2000 1999 1998 ----- ----- ----- ($ MILLIONS EXCEPT PER SHARE AMOUNTS) Revenues......................................... 3,388 2,387 2,070 Net earnings..................................... 377 186 178 Per common share(1) (undiluted).................. 1.58 0.74 0.81 Per common share(1) (diluted).................... 1.57 0.73 0.80 Cash flow provided from operations............... 958 591 580 Per common share(1).............................. 4.11 2.51 2.64 Capital and exploration expenditures............. 1,998 1,350 936
AS AT DECEMBER 31, ---------------------------- 2000 1999 1998 ----- ----- ----- ($ MILLION) Total assets..................................... 6,833 5,176 4,104 Long-term borrowings(2).......................... 2,193 1,307 1,299 Common shareholders' equity(3)................... 1,958 1,594 1,499
Notes: (1) Per share amounts for all years reflect a two-for-one share split in 2000 and payments on the preferred securities issued in 1999. (2) Includes current portion. (3) Excludes Preferred Securities issued in 1999. See Dividend Policy and Record. DIVIDEND POLICY AND RECORD Suncor's Board of Directors has established a policy of paying dividends on a quarterly basis. This policy will be reviewed from time to time in light of Suncor's financial position, its financing requirements for growth, its cash flow and other factors considered relevant by Suncor's Board of Directors. A dividend of $0.085 per common share for the first quarter of 2001 has been declared, payable on March 26, 2001 to shareholders of record on March 15, 2001. During 1999, the Company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of US$162.5 million of 9.125% preferred securities, the proceeds of which totalled Canadian $507 million after issue costs of $17 million ($10 million after income tax credits of $7 million). The preferred securities are unsecured junior subordinated debt of the Company, due in 2048 and redeemable at the Company's option on or after March 15, 2004. Subject to certain conditions, the Company has the right to defer payment of interest on the securities for up to 20 consecutive quarterly 39 periods. Deferred interest and principal amounts are payable in cash, or, at the option of the Company, from the proceeds on the sale of equity securities of the Company delivered to the trustee of the preferred securities. For accounting purposes, the preferred securities are classified as share capital in the consolidated balance sheet and the interest distributions thereon, net of income taxes, are classified as dividends. Proceeds from the offerings were used to repay commercial paper borrowings. The following table sets forth the per share amount of dividends paid by Suncor during the last three years.
YEAR ENDED DECEMBER 31, ----------------------------- 2000 1999 1998 ------ ------ ------ Common Shares Cash dividends(1)................................ $ 0.34 $ 0.34 $ 0.34 Preferred Securities Cash interest distributions...................... $ 0.21 $ 0.17 -- Dividends paid in common shares.................. -- -- --
Note: (1) Per share amounts for all years reflect a two-for-one share split in 2000. FUTURE COMMITMENTS TO BUY, SELL, EXCHANGE OR TRANSPORT CRUDE OIL AND NATURAL GAS In order to ensure continued availability of, and access to, transportation facilities for the crude oil and natural gas products of its Oil Sands and Natural Gas business units, the Company has entered into long term contracts for pipeline capacity on various third party systems. The Company's Oil Sands business unit has entered into a long-term commitment with Enbridge for the transportation of sour crude oil and bitumen from Suncor's oil sands plant near Ft. McMurray, Alberta, to Hardisty, Alberta. Particulars of that commitment are described under the heading "Operations" in the "Oil Sands" section of this Annual Information Form. Natural gas pipeline commitments are described in the following table:
-------------------------------------------------------------------------------------------------------------- AGGREGATE NATURE OF COMMITMENTS TERM VOLUME PRICE/COST PRICE PER UNIT -------------------------------------------------------------------------------------------------------------- ($ MILLIONS) Natural gas pipeline commitments: -------------------------------------------------------------------------------------------------------------- Nova 1998-2008 ** 19 $0.17 per MCF -------------------------------------------------------------------------------------------------------------- Westcoast Energy 1996-2001 27 mmcf/day 2 $0.23 per MCF -------------------------------------------------------------------------------------------------------------- Foothills 1997-2003 16 mmcf/day 1 $0.08 per MCF -------------------------------------------------------------------------------------------------------------- Northern Border 1997-2003 14 mmcf/day 8 $0.52 per MCF -------------------------------------------------------------------------------------------------------------- Alberta Natural Gas 1991-2008 41 mmcf/day 9 $0.07 per MCF -------------------------------------------------------------------------------------------------------------- Pacific Gas Transmission 1995-2023 40 mmcf/day 166 $0.49 per MCF --------------------------------------------------------------------------------------------------------------
The Company's Natural Gas business has entered into numerous natural gas purchase and sale commitments, aggregating 71 mmcf/day and 220 mmcf/d, respectively. Purchase commitment terms vary from one to three years and pricing varies, representing a combination of fixed and index-based pricing. Sales commitments consist of both short- and long- term contracts ranging from one to eight years duration, with varying pricing generally based on a combination of fixed and index-based terms. Oil Sands has also entered into long-term contracts to sell crude oil products to customers, some of which are described under the heading, "Revenues from Synthetic Crude Oil and Diesel", in the "Oil Sands" section of this Annual Information Form. In addition, the Company enters into crude oil and 40 foreign currency swap and option contract to protect its future Canadian dollar earnings and cash flows from the potential adverse impact of low petroleum prices and an unfavourable U.S./Canadian dollar exchange rates. For further particulars of these hedging arrangements, see the information under the heading "Hedging", under "Risk/Success Factors Affecting Performance" in the "Corporate" section of the Company's MD&A, incorporated by reference herein, and note 18 to Suncor's 2000 consolidated financial statements, which note is incorporated by reference herein. Also see note 15 to Suncor's 2000 consolidated financial statements, which note is incorporated by reference herein, for a further description of the Company's operating commitments for 2001 and subsequent years. MANAGEMENT'S DISCUSSION AND ANALYSIS Suncor's Management's Discussion and Analysis, dated February 28, 2001, is incorporated by reference into and forms an integral part of this Annual Information Form, and should be read in conjunction with the consolidated comparative financial statements and the notes thereto. MARKET FOR THE SECURITIES OF THE ISSUER The common shares of Suncor are listed on The Toronto Stock Exchange in Canada, and on the New York Stock Exchange in the United States. To the best of management's knowledge, approximately 40% of Suncor's common shares are beneficially held by residents of the United States. Suncor's 9.05% preferred securities are listed on The Toronto Stock Exchange in Canada, and Suncor's 9.125% preferred securities are listed on the New York Stock Exchange in the United States. DIRECTORS AND OFFICERS As of the date hereof, Suncor's Board of Directors is comprised of twelve directors. The term of office of each director is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed. The Board of Directors is required to have, and has, an Audit Committee. The Board of Directors also has a Board Policy, Strategy Review and Governance Committee, a Human Resources and Compensation Committee, and an Environment, Health and Safety Committee. The following table sets out certain information with respect to Suncor's directors.
VOTING SECURITIES OF PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY OR EMPLOYMENT, AND OWNED OR OVER WHICH MAJOR POSITIONS AND CONTROL OR DIRECTION NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2001(1) ---------------------------- -------------------- ---------------------- ------------------------ Mel Benson(2) April 19, 2000 to Management Services 1,000 Common Shares Calgary, Alberta Present Consultant 365 Deferred Share Units(3) 41 VOTING SECURITIES OF PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY OR EMPLOYMENT, AND OWNED OR OVER WHICH MAJOR POSITIONS AND CONTROL OR DIRECTION NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2001(1) ---------------------------- -------------------- ---------------------- ------------------------ Brian A. Canfield(2)(4) November 10, 1995 Chairman 8,052 Common Shares Point Roberts, Washington to Present TELUS Corporation(a telecommunications 2,669 Deferred Share company) Units(3) Bryan P. Davies(5) January 28, 1991 Senior Vice 6,200 Common Shares Etobicoke, Ontario to April 23, 1996 President, Regulatory Affairs, 364 Deferred Share April 19, 2000 to Royal Bank of Canada Units(3) Present (a chartered banking institution) John T. Ferguson(5)(6) November 10, 1995 Chairman, Princeton 8,310 Common Shares Edmonton, Alberta to Present Developments Ltd. (a real estate 1,323 Deferred Share development Units(3) company), Chairman and Director, TransAlta Corporation (an electric utility company) Richard L. George(6) February 1, 1991 President and Chief 94,262 Common Shares Calgary, Alberta to Present Executive Officer, Suncor Energy Inc.(7) Poul Hansen(2)(5) April 23, 1996 to Chairman and General 6,826 Common Shares Vancouver, British Columbia Present Manager, Sperling Hansen Associates Inc. (an environmental engineering consulting company) John R. Huff(4)(6) January 30, 1998 Chairman and Chief 10,273 Common Shares Houston, Texas to Present Executive Officer, Oceaneering 2,811 Deferred Share International, Inc. Units(3) (an oilfield services company) Michael M. Koerner(4)(6)(8) May 31, 1977 to President, Canada 8,000 Common Shares Toronto, Ontario January 27, 1994 Overseas Investments Limited (a venture 3,197 Deferred Share October 1, 1995 to capital investment Units(3) Present management company) 42 VOTING SECURITIES OF PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY OR EMPLOYMENT, AND OWNED OR OVER WHICH MAJOR POSITIONS AND CONTROL OR DIRECTION NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2001(1) ---------------------------- -------------------- ---------------------- ------------------------ Robert W. Korthals(2)(5)(9) April 23, 1996 to Corporate Director 8,000 Common Shares Toronto, Ontario Present 1,854 Deferred Share Units (3) M. Ann McCaig(2)(5) October 1, 1995 to President, VPI 5,120 Common Shares Calgary, Alberta Present Investments Ltd. (a private investment 3,065 Deferred Share holding company) Units(3) JR Shaw(5)(6) January 30, 1998 Executive Chairman 37,000 Common Shares Calgary, Alberta to Present of the Board, Shaw Communications Inc. 2,862 Deferred Share (a diversified Units(3) communications company) W. Robert Wyman(4)(6) November 25, 1987 Chairman of the 32,400 Common Shares West Vancouver, British to Present Board of Directors Columbia of Suncor Energy Inc. 4,106 Deferred Share Units(3)
Notes: (1) The information relating to holdings of Common Shares, not being within the knowledge of Suncor, has been furnished by the respective nominees individually. Where a nominee holds a fractional Common Share, the holdings reported have been rounded down to the nearest whole Common Share. Certain of the Common Shares held by Mr. George and Mr. Hansen are held jointly with their respective spouses. The number of Common Shares held by Mr. George includes 82,486 Common Shares over which he exercises control or direction but which are beneficially owned by members of his family. 400 Common Shares held by Mr. Benson are beneficially owned by his spouse, but he exercises control or direction over such shares. (2) Member of the Environment, Health and Safety Committee. (3) Deferred Share Units (DSU's) are not securities but are included for informational purposes as they represent an economic interest based on Common Shares of the Company. (4) Member of the Human Resources and Compensation Committee. (5) Member of the Audit Committee. (6) Member of the Board Policy, Strategy Review and Governance Committee. (7) Mr. George is also the President and a director of Sunoco Inc., Suncor's refining and marketing subsidiary, and Suncor Energy Marketing Inc., Suncor's crude oil marketing subsidiary. 43 (8) Mr. Koerner, Suncor's longest serving director, will retire from Suncor's Board of Directors at the expiry of his current term of office on April 18, 2001. (9) In 1998, Mr. Korthals was a director of Anvil Range Mining Corporation, which sought protection under the Companies Creditors Arrangement Act (Canada). Each of the directors named above has been engaged in the principal occupation indicated above for the past five years, except for: Mr. Benson, who from 1996 to 2000 was the Senior Operations Advisor, African Development, Exxon Co. International; Mr. Canfield, who in 1998 was Chairman, BC TELECOM Inc. and BC TEL, and who from 1993 to 1997 was Chief Executive Officer and Chairman, BC TELECOM Inc. and BC TEL; Mr. Davies, who in 1999 and prior thereto was Senior Vice President, Corporate Affairs, Royal Bank of Canada; Mr. Ferguson, who from 1996 to 1998 was also Chief Executive Officer, Princeton Developments Ltd., in addition to his current position as Chairman, Princeton Developments Ltd.; Mr. Huff, who in 1998 and prior thereto was also President, Oceaneering International, Inc., in addition to his current position as Chairman and Chief Executive Officer, Oceaneering International, Inc.; Mr. Shaw, who in 1998 and prior thereto was Chairman and Chief Executive Officer of Shaw Communications Inc.; and Mr. Wyman, who in 1999 and prior thereto was Vice Chairman of the Board of Directors of Fletcher Challenge Canada Limited. The following are officers of the Corporation. Except where otherwise indicated, the persons named in the table below held the offices set out opposite their respective names as at December 31, 2000 and as of the date hereof.
NAME AND MUNICIPALITY OF RESIDENCE OFFICE(1) ---------------------------------- --------- W. ROBERT WYMAN................................ Chairman of the Board West Vancouver, British Columbia RICHARD L. GEORGE.............................. President and Chief Executive Officer Calgary, Alberta M.M. (MIKE) ASHAR.............................. Executive Vice President, Oil Sands Fort McMurray, Albertas DAVID W. BYLER................................. Executive Vice President, Natural Gas M.D. of Rockyview, Alberta MICHAEL W. O'BRIEN............................. Executive Vice President, Corporate Development and Canmore, Alberta Chief Financial Officer THOMAS L. RYLEY................................ Executive Vice President, Sunoco Toronto, Ontario BARRY D. STEWART............................... Executive Vice President, In-situ and International Oil Calgary, Alberta TERRENCE J. HOPWOOD............................ Vice.President, General Counsel and Secretary Calgary, Alberta SUE LEE........................................ Senior Vice President, Human Resources and Calgary, Alberta Communications J. KENNETH ALLEY............................... Vice.President, Finance Calgary, Alberta JANICE B. ODEGAARD............................. Assistant Secretary Calgary, Alberta
44 Note: (1) The principal occupation of each officer is the specified office with Suncor, with the exception of Ms. Odegaard, who is also Corporate Director, Legal Affairs, of Suncor. All of the foregoing officers of the Company have, for the past five years, been actively engaged as executives or employees of Suncor or its affiliates, except Mr. Wyman, who is a non-executive Chairman of Suncor. The percentage of Common Shares of Suncor owned beneficially, directly or indirectly, or over which control or direction is exercised by Suncor's directors and senior officers, as a group, is less than 1%. ADDITIONAL INFORMATION Copies of the documents set out below may be obtained without charge by any person upon request to the Secretary, Suncor Energy Inc., Box 38, 112 - 4 Avenue S.W., Calgary, Alberta, T2P 2V5, telephone 403-269-8709: (i) The current Suncor Annual Information Form together with any pertinent information incorporated by reference therein; (ii) The current Suncor comparative financial statements for the most recently completed financial year and the report of the auditors relating thereto, together with any subsequent interim financial statements; (iii) Suncor's management proxy circular in respect of its most recent annual meeting of shareholders that involved the election of directors; and (iv) Any other documents incorporated by reference into Suncor's most recent preliminary short form prospectus or short form prospectus if securities of Suncor are in the course of distribution pursuant to such documents. Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Suncor's securities, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in Suncor's most recent management proxy circular for its most recent annual meeting of its shareholders that involved the election of directors. Additional financial information is provided in Suncor's comparative financial statements for its most recently completed financial year. 45