-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, VRgzGGEZV3tZ0qEmvQKseXmFKvOGI9qRj9wJ8kslXPq6FvEwqhkxdhqVbNbELaZu Y3HFTwVcZsMxmQnroBgCIw== 0000912057-01-506966.txt : 20010410 0000912057-01-506966.hdr.sgml : 20010410 ACCESSION NUMBER: 0000912057-01-506966 CONFORMED SUBMISSION TYPE: 6-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20010319 FILED AS OF DATE: 20010404 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SUNCOR ENERGY INC CENTRAL INDEX KEY: 0000311337 STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911] IRS NUMBER: 000000000 STATE OF INCORPORATION: A0 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 6-K SEC ACT: SEC FILE NUMBER: 001-12384 FILM NUMBER: 1595523 BUSINESS ADDRESS: STREET 1: 112 4TH AVENUE SW PO BOX 38 STREET 2: CALGARY ALBERTA CITY: CANADA T2P 2V5 STATE: A0 BUSINESS PHONE: 4032698100 MAIL ADDRESS: STREET 1: 112 FOURTH AVE SW BOX 38 STREET 2: CALGARY ALBERTA CITY: CANADA T2P 2V5 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 EX-1 2 a2042188zex-1.txt EXHIBIT 1 EXHIBIT 1 SUNCOR ENERGY INC. 2000 RECONCILIATION OF RESULTS FROM CANADIAN GAAP TO U.S. GAAP (ALL FIGURES ARE IN CANADIAN DOLLARS) CANADIAN AND UNITED STATES ACCOUNTING PRINCIPLES The consolidated financial statements of Suncor Energy Inc. have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The adjustments under U.S. GAAP result in changes to the Consolidated Statements of Earnings and Consolidated Balance Sheets of the company as follows:
- ------------------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------- (Canadian $ millions) CDN US CDN US CDN US - ------------------------------------------------------------------------------------------------------------------------------- REVENUES Sales & other operating revenues (1) 3,385 3,481 2,383 2,448 2,068 2,107 Interest 3 3 4 4 2 2 - ------------------------------------------------------------------------------------------------------------------------------- 3,388 3,484 2,387 2,452 2,070 2,109 - ------------------------------------------------------------------------------------------------------------------------------- EXPENSES Purchases of crude oil and products 807 807 519 519 366 366 Operating, selling and general (1) (2) (3) 918 1,036 774 791 698 785 Exploration 53 53 40 40 40 40 Royalties 199 199 99 99 78 78 Taxes other than income taxes 361 361 334 334 325 325 Depreciation, depletion & amortization (4) 365 372 318 318 264 264 Gain on disposal of assets (148) (148) (34) (34) (6) (6) Write down of oil shale assets (5) 125 244 - - - - Restructuring 65 65 - - - - Start-up expenses - Project Millennium (6) 15 14 - 1 - - Start-up expenses - Other (6) - (13) - 31 - - Interest (4) 8 40 26 59 24 24 - ------------------------------------------------------------------------------------------------------------------------------- 2,768 3,030 2,076 2,158 1,789 1,876 - ------------------------------------------------------------------------------------------------------------------------------- EARNINGS BEFORE INCOME TAXES 620 454 311 294 281 233 - ------------------------------------------------------------------------------------------------------------------------------- PROVISION FOR INCOME TAXES Current Income taxes on earnings 45 45 29 29 (3) (3) Income tax refund - - - - (16) (16) - ------------------------------------------------------------------------------------------------------------------------------- 45 45 45 29 (19) (19) - ------------------------------------------------------------------------------------------------------------------------------- Future Income taxes on earnings (2) (4) (5) (6) (7) 198 138 96 87 117 98 Income tax refund - - - - 5 5 - ------------------------------------------------------------------------------------------------------------------------------- 198 138 96 87 122 103 - ------------------------------------------------------------------------------------------------------------------------------- 243 183 125 116 103 84 - ------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS 377 271 186 178 178 149 Dividends on preferred securities (4) (26) - (22) - - - - ------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS 351 271 164 178 178 149 Other comprehensive income, net of tax Minimum pension liability (8) N/A (2) N/A 6 N/A (6) - ------------------------------------------------------------------------------------------------------------------------------- COMPREHENSIVE INCOME N/A 269 N/A 184 N/A 143 - ------------------------------------------------------------------------------------------------------------------------------- PER COMMON SHARE NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS Basic 1.58 1.22 0.74 0.81 0.81 0.68 Diluted 1.57 1.21 0.73 0.80 0.80 0.67 - -------------------------------------------------------------------------------------------------------------------------------
* Per share calculations, for both current and prior years, reflect a two-for-one split of the company' common shares during 1998 and 2000. 2
AS AT as at DECEMBER 31, 2000 December 31, 1999 (CANADIAN $ MILLIONS) (Canadian $ millions) AS U.S. As U.S. REPORTED GAAP reported GAAP ---------- ---------- ---------- ---------- Current assets (8) 665 666 457 457 Capital assets, net (4) (5) (6) 5,883 5,768 4,528 4,503 Deferred charges and other (4) 166 173 191 205 Future income taxes (4) (6) (7) (8) 119 125 - - ---------- ---------- ---------- ---------- Total assets 6,833 6,732 5,176 5,165 ========== ========== ========== ========== Current liabilities 837 837 710 710 Long-term borrowings (4) 2,192 2,716 1,306 1,830 Accrued liabilities and other (3) (8) 252 277 236 236 Future income taxes (5) (7) 1,080 1,042 816 736 Equity: Share capital and retained earnings (4) 2,472 1,862 2,108 1,653 Accumulated other comprehensive Income (8) N/A (2) N/A - ---------- ---------- ---------- ---------- 2,472 1,860 2,108 1,653 ========== ========== ========== ========== Total liabilities and shareholders' equity 6,833 6,732 5,176 5,165 ========== ========== ========== ==========
(1) Under U.S. GAAP (EITF 00 - 10, "Accounting for Shipping and Handling Fees and Costs"), amounts billed to customers for shipping and handling costs should be classified as revenues, and shipping and handling costs incurred that relate to amounts billed to customers should be classified as expenses in the earnings statement. The company's accounting policy is to classify shipping and handling costs incurred that relate to amounts billed to customers as follows: o As "Operating, selling and general" for downstream refining and marketing operations; and o Deducted from "Sales and other operating revenues" for upstream operations. The company's accounting policy is acceptable under Canadian GAAP, which does not specifically address accounting for shipping and handling costs. The impact of EITF 00 - 10, which is one of reclassification only and does not affect net earnings, is to increase 2000 "Sales and other operating revenues" and "Operating, selling and general" expenses by $96 million (1999 - $65 million; 1998 - $39 million). 3 (2) The company is a party to certain off-balance-sheet derivative financial instruments, such as crude oil, natural gas and foreign currency swap contracts, in respect of future firmly committed and anticipated sales transactions. Under Canadian GAAP, foreign currency swap contracts qualify, and are accounted for, as hedges of these future transactions. Under U.S. GAAP, foreign currency swap contracts used to hedge foreign currency exposure to anticipated, but not firmly committed, transactions cannot be accounted for as hedges under SFAS No. 52, "Foreign Currency Translation". Accordingly, for reporting under U.S. GAAP, gains or losses resulting from changes in the market value of foreign currency swap contracts related to these anticipated transactions are recognized in earnings when those changes in market value occur. At December 31, 2000, there were no foreign currency swap contracts outstanding to hedge foreign currency exposure to anticipated transactions and, therefore, no impact on net earnings. As at December 31, 1999, the market value of such contracts was nil therefore, the loss recognized in 1998 was reversed. This 1998 loss reversal resulted in an increase in 1999 net earnings of $29 million after future income taxes of $19 million (1998 - net earnings decreased by $29 million after future income tax recoveries of $19 million). (3) Under U.S. GAAP (APB 25, "Accounting for Stock Issued to Employees"), compensation expense is also recorded, over the same vesting period, for the portion of these awards payable in common shares. The impact of this GAAP difference is to decrease 2000 net earnings by $22 million (1999 and 1998 - $ nil). Since the common shares awarded under these plans are to be issued from treasury, the income tax impact on the company is nil. STOCK-BASED COMPENSATION The company applies APB Opinion 25 in accounting for common share options granted to non-employee directors and certain executives. Accordingly, no compensation cost has been recognized in the consolidated statements of earnings. Had compensation cost been determined on the basis of fair values in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation", 2000 net earnings would have been lower by $7 million ($0.03 per common share), 1999 net earnings would have been lower by $5 million ($0.02 per common share) and 1998 net earnings would have been lower by $3 million ($0.03 per common share). (4) Under Canadian GAAP, the preferred securities issued in 1999 are classified as share capital in the consolidated balance sheets and the interest distributions thereon, net of income taxes, are accounted for as dividends in the consolidated statements of changes in shareholders' equity. Under US GAAP, the preferred securities are classified as long-term borrowings in the consolidated balance sheets and the interest distributions thereon and the related income tax impact are accounted for in the consolidated statements of earnings. Under Canadian GAAP, issue costs of the preferred securities, net of the related income tax credits, are charged against share capital. Under US GAAP, issue costs are deferred on the consolidated balance sheets and amortized to earnings over the term of the related long-term borrowings. 4 This difference in classification decreased 2000 net earnings by $31 million after income tax recoveries of $23 million (1999 net earnings decreased $20 million after income tax recoveries of $17 million). However, the interest distributions on the preferred securities above are eligible for interest capitalization under U.S. GAAP, resulting in an increase in 2000 net earnings of $9 million after future income taxes of $6 million (1999 net earnings increased $2 million after future income taxes of $2 million). These preferred securities, which are publicly traded, had a fair value, based on quoted market prices, of $544 million at December 31, 2000 (1999 - $492 million). Under Canadian GAAP, the 2000 interest distributions of $47 million (1999 - $37 million) on the preferred securities are classified as financing activities in the consolidated statements of cash flows. Under U.S. GAAP (SFAS No.95, "Statement of Cash Flows"), the interest distributions and the amortization of issue costs of $7 million are classified as operating activities. (5) In 2000, the company recorded an impairment write down of the carrying value of the Stuart oil shale project to its net recoverable amount, which under Canadian GAAP is its estimated future cash flow from use together with its residual value, calculated on an undiscounted basis. Under U.S. GAAP (SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"), an impairment loss is measured based on the fair value of the asset, which in the case of the oil shale project is its estimated net cash flows, but calculated on a discounted basis. The impact of this GAAP difference is to decrease 2000 net earnings by $64 million, after income tax recoveries of $55 million. (6) Under U.S. GAAP (AICPA Statement of Position 98-5, "Reporting the Costs of Start-Up Activities"), all costs relating to start-up activities are expensed as incurred. Under Canadian GAAP, certain costs relating to the company's start-up activities are initially capitalized and then amortized over the estimated useful lives of the related assets. Under Canadian GAAP in 2000: o Certain costs associated with the Stuart oil shale project that were previously capitalized were written down. Under U.S. GAAP, these start-up costs were expensed in 1999. These differences increased 2000 net earnings by $8 million after related income taxes of $6 million (1999 decreased net earnings by $12 million after related income tax credits of $8 million). (7) In December 2000, the Canadian Federal Department of Finance released draft legislation that merged federal budget proposals announced earlier in the year. Under Canadian GAAP, the budget proposals are considered substantially enacted. Accordingly, future income tax assets and liabilities have been measured taking into account the reduction in tax rates presented in the draft legislation. Under US GAAP, in accordance with SFAS 109 "Accounting for Income Taxes", changes in tax rates and tax laws on temporary differences are only after they have been signed into law. 5 The impact of this GAAP difference was to decrease 2000 net earnings by $6 million (1999 and 1998 - nil). At December 31, 2000, future income taxes, under Canadian and U.S. GAAP, are comprised of the following:
AS REPORTED U.S. GAAP ($ millions) CURRENT NON-CURRENT CURRENT NON-CURRENT ------------ ------------ ------------ ------------ Future income tax assets: Employee future benefits 2 39 2 41 Reclamation and environmental remediation costs 9 23 9 24 Royalties - 43 - 43 Employee incentive plans - 4 - 10 Inventories 20 - 21 - Other 14 10 14 - ------------ ------------ ------------ ------------ 45 119 46 125 ============ ============ ============ ============ Future income tax liabilities Depreciation - 1,038 - 992 Overburden removal costs - 23 - 23 Maintenance shutdown costs - 12 - 12 Other 9 7 9 15 ============ ============ ============ ============ 9 1,080 9 1,042 ============ ============ ============ ============
(8) Under U.S. GAAP (SFAS No.87, "Employers' Accounting for Pensions"), recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is greater than accrued pension costs otherwise recorded. No such adjustment is required under Canadian GAAP. Recording the additional minimum liability affects the consolidated balance sheet only and has no impact on net earnings or cash flows. An intangible asset equal to the amount of any unamortized liabilities arising from plan amendments is recognized. Any excess of the additional minimum liability over the amount recognized as an intangible asset is recorded as a separate component of equity (net of any related income tax recoveries), and is included as a component of comprehensive income under SFAS No. 130, "Reporting Comprehensive Income". At December 31, 2000, an additional minimum pension liability of $3 million and other comprehensive income of $2 million, net of income tax recoveries of $1 million, was recognized. At December 31, 2000, unamortized liabilities arising from plan amendments were nil. At December 31, 1999, the accumulated benefit obligation did not exceed the fair value of plan assets and accrued pension costs otherwise recorded. Accordingly, as at December 31, 1999 the additional minimum pension liability and related intangible asset recognized at 6 December 31, 1998 was adjusted to nil, and other comprehensive income of $6 million, net of income taxes of $4 million, was recognized. EMPLOYEE FUTURE BENEFITS Effective January 1, 2000, the company adopted new Canadian accounting recommendations with respect to accounting for the costs of employee future benefits. The new recommendations were applied in a manner that produced recognized and unrecognized amounts for all of its benefit plans the same as those determined by the application of U.S. GAAP (SFAS No. 87, "Employers Accounting for Pensions; SFAS No. 106, "Employers' Accounting for Post-Retirement Benefits Other than Pensions" and SFAS No. 112, "Accounting for Post-Employment Benefits"). For Canadian reporting, the new recommendations were adopted retroactively and financial statements of prior periods were restated to give effect to them. Accordingly, for U.S. reporting, comparative figures have also been restated to reflect the fact that GAAP differences previously reported no longer apply. RECENTLY ISSUED ACCOUNTING STANDARDS DERIVATIVE FINANCIAL INSTRUMENTS Effective January 1, 2001, the company will adopt SFAS 133 Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding normal purchase and sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income (OCI) and are recognized in the income statement when the hedged item is realized. Ineffective portions of changes in the fair value and the cash flow hedges are recognized in earnings, immediately. The adoption of SFAS 133 is expected to result in a decrease in OCI of $173 million, net of future income tax recoveries of $87 million and an increase in 2001 U.S. GAAP earnings of $47 million net of future income taxes of $28 million. Assets are expected to increase by $89 million and liabilities are expected to increase by $274 million as a result of recording all derivative instruments on the consolidated Balance Sheet at fair value. Implementation of this accounting standard will not affect the company's cash flow or liquidity. OIL AND GAS DATA The following data supplements oil and gas disclosure in the company's Annual Report, and is provided in accordance with the provision of the United States Financial Accounting Standards Board's Statement No. 69. This statement requires disclosure about conventional oil and gas activities only, and therefore the company's oil sands activities are excluded. 7 COSTS INCURRED
COSTS INCURRED FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Property acquisition costs Proved properties.............................................. 5 - - Unproved properties............................................ 10 48 24 Exploration costs................................................ 40 64 92 Development costs................................................ 69 70 123 --- --- --- 124 182 239 === === ===
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers.................................. 139 97 80 Transfers to other operations.................................... 183 153 167 ---- ---- ---- 322 250 247 ---- ---- ---- Expenses Production costs................................................. 47 63 64 Depreciation, depletion and amortization......................... 68 76 74 Exploration...................................................... 63 52 50 Gain on disposal of assets....................................... (147) (36) (4) Restructuring costs.............................................. 65 - - ---- ---- ---- Other related costs.............................................. 25 21 18 ---- ---- ---- 121 176 202 ---- ---- ---- Operating profit before income taxes............................... 201 74 45 Related income taxes............................................... (103) (33) (21) ---- ---- ---- Results of operations from Natural Gas............................. 98 41 24 ==== ==== ====
The information noted above does not totally agree to the segmented information on page 48 of the company's annual report due to different classification of revenues and expenses,
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers................................... 139 97 80 Transfers to other operations..................................... 183 153 167 ---- ---- ---- 322 250 247 ---- ---- ---- Expenses Production costs.................................................. 47 63 64 Depreciation, depletion and amortization.......................... 68 76 74 Exploration....................................................... 63 52 50 Gain on disposal of assets........................................ (147) (36) (4) Restructuring costs............................................... 65 - - ---- ---- ---- Other related costs............................................... 25 21 18 ---- ---- ---- 121 176 202 ---- ---- ---- Operating profit before income taxes................................ 201 74 45 Related income taxes................................................ (103) (33) (21) ---- ---- ---- Results of operations from Natural Gas.............................. 98 41 24 ==== ==== ====
8
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers.................................. 139 97 80 Transfers to other operations.................................... 183 153 167 ---- ---- ---- 322 250 247 ---- ---- ---- Expenses Production costs................................................. 47 63 64 Depreciation, depletion and amortization......................... 68 76 74 Exploration...................................................... 63 52 50 Gain on disposal of assets....................................... (147) (36) (4) Restructuring costs.............................................. 65 - - ---- ---- ---- Other related costs.............................................. 25 21 18 ---- ---- ---- 121 176 202 ---- ---- ---- Operating profit before income taxes............................... 201 74 45 Related income taxes............................................... (103) (33) (21) ---- ---- ---- Results of operations from Natural Gas............................. 98 41 24 ==== ==== ====
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES In computing the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes, assumptions other than those mandated by SFAS No. 69 could produce substantially different results. The Company cautions against viewing this information as a forecast of future economic conditions or revenues. Figures are based on year-end commodity prices. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and taking into account the future periods in which they are expected to be developed and produced based on year-end economic conditions. The estimated future production is priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and determinable price escalations provided by contract. At December 31, 2000, no such contractual arrangements existed. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. In addition, the Company has also deducted certain other estimated costs deemed necessary to derive the estimated pretax future net cash flows from the proved reserves including direct general and administrative costs of exploration and production operations and reclamation and environmental remediation costs. Deducting future income tax expenses then reduces the estimated pretax future net cash flows further. Such income taxes are determined by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax cash flows relating to the Company's proved oil and gas reserves less the tax basis of the properties involved. At December 31, 2000, there were no legislated future tax rate changes. The future income tax expenses give effect to permanent differences and tax credits and allowances relating to the company's proved oil and gas reserves. The resultant future net cash flows are reduced to present value amounts by applying the SFAS No. 69 mandated 10% discount factor. The result is referred to as "Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes". 9
2000 1999 1998 ------ ------ ------ ($ MILLIONS) Future cash inflows..................................................... 8,176 3,272 3,382 Future production and development costs................................. (633) (1,053) (1,183) Other related future costs.............................................. (175) (133) (139) Future income tax expenses.............................................. (3,426) (789) (637) ------ ------ ------ Future net cash flows................................................... 3,942 1,297 1,423 Discount at 10%......................................................... (2,009) (548) (626) ------ ------ ------ Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes............................................................ 1,933 749 797 ====== ====== ======
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES
2000 1999 1998 ------ ------ ------ ($ MILLIONS) Balance, beginning of year.............................................. 749 797 678 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas net of related costs............... (275) (192) (187) Revisions to estimates of proved reserves: Prices............................................................. 3,886 458 69 Development costs.................................................. (3) (68) (75) Production costs................................................... 55 (25) (26) Quantities......................................................... (363) (175) (19) Other.............................................................. (237) (81) (6) Extensions, discoveries, and improved recovery less related costs..... 177 46 168 Development costs incurred during the period.......................... 69 70 123 Purchases of reserves in place........................................ 41 - - Sales of reserves in place............................................ (989) (130) (13) Accretion of discount................................................. 115 113 100 Income taxes.......................................................... (1,292) (64) (15) ------ ------ ------ Balance, end of year.................................................... 1,933 749 797 ====== ====== ======
10 EX-2 3 a2042188zex-2.txt EXHIBIT 2 EXHIBIT 2 MANAGEMENT'S STATEMENT ON FINANCIAL REPORTING - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ The financial statements on pages 56 to 77 which consolidate the financial results of Suncor Energy Inc., its subsidiaries and joint ventures, and all information in this annual report, are the responsibility of management. The financial statements have been prepared in accordance with Canadian generally accepted accounting principles. They include some amounts which are based on estimates and judgments relating to matters not concluded by year-end. Financial information presented elsewhere in this annual report is consistent with that in the financial statements. In management's opinion the financial statements have been properly prepared within reasonable limits of materiality and within the framework of the accounting policies summarized on pages 56 to 58 In meeting its responsibilities for the integrity of the financial statements, management maintains a system of internal controls and an internal audit program. Management also administers a program of proper business conduct compliance. PricewaterhouseCoopers LLP, the company's independent auditors, have audited the accompanying financial statements. Their report accompanies this statement. The Audit Committee of the Board of Directors, composed of six independent directors, meets regularly with management, the internal auditors and PricewaterhouseCoopers LLP to review their activities and to discuss auditing, management information systems, internal control, accounting policy and financial reporting matters. The Audit Committee also meets quarterly to review interim financial statements prior to their release. The internal auditors and PricewaterhouseCoopers LLP have unrestricted access to the Company, the Audit Committee and the Board of Directors. The Audit Committee reviews the financial statements and Management's Discussion and Analysis and recommends their approval to the Board of Directors. /s/ Richard L. George /s/ Michael W. O'Brien - --------------------- ------------------------------ RICHARD L. GEORGE MICHAEL W. O'BRIEN President and Executive Vice President Chief Executive Officer and Chief Financial Officer January 18, 2001 54 SUNCOR ENERGY INC. 2000 ANNUAL REPORT AUDITORS' REPORT - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ To the Shareholders of Suncor Energy Inc: We have audited the consolidated balance sheets of Suncor Energy Inc. as at December 31, 2000, 1999 and 1998 and the consolidated statements of earnings, cash flows and changes in shareholders' equity for each of the years then ended. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in Canada. Those standards require that we plan and perform an audit to obtain reasonable assurance that the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2000, 1999 and 1998 and the results of its operations and cash flows for each of the years then ended in accordance with accounting principles generally accepted in Canada. /s/ PriceWaterhouseCoopers LLP - ------------------------------ PRICEWATERHOUSECOOPERS LLP Chartered Accountants Calgary, Alberta January 18, 2001 SUNCOR ENERGY INC. 2000 ANNUAL REPORT 55 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Suncor Energy Inc. is an integrated Canadian energy company, whose three operating segments are Oil Sands, Natural Gas and Sunoco. Oil Sands includes the production of light sweet and light sour crude oil, diesel fuel and various custom blends from oil sands mined in the Athabasca region of northeastern Alberta, and the marketing of these products in Canada and the United States. Natural Gas includes the exploration, acquisition, development, production and transportation of natural gas and crude oil in Canada and the marketing of natural gas and crude oil in Canada and the United States. Sunoco includes the manufacture, transportation and marketing of petroleum and petrochemical products, primarily in Ontario and Quebec, and the marketing of natural gas in Ontario. Petrochemical products are also sold in the United States and Europe. The company's oil shale project in Queensland, Australia, is currently being treated as a Corporate project for segmented reporting purposes. The significant accounting policies of the company are summarized below: (a) PRINCIPLES OF CONSOLIDATION AND THE PREPARATION OF FINANCIAL STATEMENTS These consolidated financial statements are prepared and reported in Canadian dollars in accordance with Canadian generally accepted accounting principles (GAAP), which differ in some respects from GAAP in the United States. The significant differences in GAAP, as applicable to these consolidated financial statements and notes, are described in the company's Form 40-F report, which is filed with the United States Securities and Exchange Commission and is available on request. The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company's proportionate share of the assets, liabilities, revenues, expenses and cash flows of its joint ventures. The timely preparation of financial statements requires that management make estimates and assumptions, and use judgment, regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. (b) CASH EQUIVALENTS AND INVESTMENTS The company considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents consist primarily of term deposits and certificates of deposit. Investments with maturities from greater than three months to one year are classified as short-term investments, while those with maturities in excess of one year are classified as long-term investments. Cash equivalents and short-term investments are stated at cost, which approximates market value. (c) REVENUES The company deems production from its oil sands plant, excluding diesel sales and synthetic crude oil sales under long-term agreements, as well as its conventional crude oil production to be used first for internal refinery consumption. The company also deems a portion of its natural gas production to be sold to Sunoco for resale to its natural gas customers. Therefore, on consolidation, revenues from these deemed sales are eliminated from sales and other operating revenues and purchases of crude oil and products. The company also uses a portion of its natural gas production for internal consumption at its oil sands plant and refinery. On consolidation, revenues from these sales are eliminated from sales and other operating revenues and operating, selling and general expenses. Revenues associated with sales of crude oil, natural gas, petroleum and petrochemical products and all other items not eliminated on consolidation are recorded when title passes to the customer. Revenues from natural gas production from properties in which the company has an interest with other producers are recognized on the basis of the company's net working interest. (d) CAPITAL ASSETS COST Capital assets are recorded at cost. The company follows the successful efforts method of accounting for its crude oil and natural gas operations. Under the successful efforts method, acquisition costs of proved and unproved properties are capitalized. Costs of unproved properties are transferred to proved properties when proved reserves are confirmed. Exploration costs, including geological and geophysical costs, are expensed as incurred. Exploratory drilling costs are capitalized initially. If it is determined that the well does not contain proved reserves, the capitalized exploratory drilling costs are charged to expense, as dry hole costs, at that time. The related land costs are expensed through the amortization of unproved properties as covered under the Natural Gas section of the following policy. Development costs, which include the costs of wellhead equipment, development drilling costs, gas plants and handling facilities, applicable geological and geophysical costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface are expensed as operating costs. 56 SUNCOR ENERGY INC. 2000 ANNUAL REPORT SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INTEREST CAPITALIZATION Interest costs relating to major capital projects and to the portion of non-producing oil and gas properties expected to become producing are capitalized as part of the cost of such capital assets. Capitalization of interest ceases when the capital asset is substantially complete and ready for productive use. LEASES Leases entered into by the company as lessee that transfer substantially all the benefits and risks of ownership to the lessee are recorded as capital leases and classified as capital assets and long-term borrowings. All other leases are classified as operating leases under which leasing costs are expenses in the period in which they are incurred. Gains and losses on the sale and leaseback of assets recorded as capital leases are deferred and amortized to earnings in proportion to the amortization of leased assets. DEPRECIATION, DEPLETION AND AMORTIZATION OIL SANDS: Capital assets are depreciated over their useful lives on a straight-line basis, except for original lease acquisition costs and related mine assets, which are depreciated over the life of proved reserves on a unit of production basis. The company is depreciating capital assets as follows: (i) mobile equipment over three to 20 years; (ii) mine equipment and acquisition costs of original leases #86 and #17 over approximately 17 million barrels of proved reserves; (iii) plant and other capital assets, including new leases, primarily over 10 to 40 years. NATURAL GAS: Unproved properties whose acquisition costs are individually significant are evaluated for impairment by management. Impairment of unproved properties whose acquisition costs are not individually significant is provided for through amortization of the portion not expected to become producing, based on historical experience, over the average projected holding period. Acquisition costs of proved properties are depleted using the unit of production method based on proved reserves. Capitalized exploratory drilling costs and development costs are depleted on the basis of proved developed reserves. For purposes of the depletion calculation, production and reserves volumes for oil and natural gas are converted to a common unit of measure on the basis of their approximate relative energy content. Gas plants, support facilities and equipment are depreciated on a straight-line basis over their useful lives, which average 12 years. SUNOCO: Depreciation of capital assets is on a straight-line basis over their useful lives. The refinery and additions thereto are depreciated over an average of 30 years, service stations and related equipment over an average of 20 years and other facilities and equipment over three to 25 years. RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS Reclamation and environmental remediation costs for identified sites are estimated and charged against earnings when there exists a regulatory or statutory requirement or contractual agreement, or when management has made a decision to decommission or restore a site, providing that assessments indicate that such costs are probable and reasonably estimable. Estimated reclamation costs in the company's upstream operations are accrued on the unit of production basis. Estimated environmental remediation costs, which are predominantly in the company's downstream operation, are accrued for those sites where assessments indicate that such work is required. Costs are accrued based upon currently known information, estimated timing of remedial actions, and existing regulatory requirements and technology. Changes in these factors may result in material changes to estimated costs, which will be recognized prospectively when known. IMPAIRMENT Capital assets are reviewed for impairment whenever events or conditions indicate that their net carrying amount, less related provisions for reclamation and environmental remediation costs and future income taxes, may not be recoverable from estimated future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, then a write-down to the estimated net recoverable amount is made, with a charge to earnings. DISPOSALS Gains or losses on disposals of capital assets are generally recognized in earnings. For oil and gas capital assets, gains or losses are recognized in earnings for significant disposals or disposal of an entire property. However, the acquisition cost of an unproved property surrendered or abandoned which is not individually significant or a partial abandonment of a proved property is charged to accumulated depreciation, depletion or amortization, as appropriate. (e) DEFERRED CHARGES Overburden removal costs incurred to expose oil sands and oil shale for mining, including depreciation on overburden removal equipment where applicable, are deferred. These costs are amortized based on the amount of oil sands and oil shale mined in the year, the ratio of total overburden to be removed to total reserves of oil sands and oil shale to be mined and the removal cost, determined on a last-in, first-out (LIFO) basis, per unit of overburden. The cost of major maintenance shutdowns is deferred and amortized on a straight-line basis over the period to the next shutdown which varies from two to seven years. Normal maintenance and repair costs are charged to expense as incurred. Oil sands preproduction costs are amortized on a unit of production basis over the life of proved producing reserves. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 57 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (f) EMPLOYEE FUTURE BENEFITS The company has employee future benefit programs as follows: - - a defined benefit pension plan and a defined contribution pension plan providing retirement benefits for its eligible employees, and supplementary defined benefit pension plans providing additional retirement benefits for its executives - - other post-retirement benefits, including certain health care and life insurance benefits, for its retired employees and eligible surviving dependants - - post-employment benefits providing certain benefits to former or inactive employees and eligible surviving dependants, after employment but before retirement under specified circumstances. The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management's best estimates of demographic and financial assumptions, and such cost is accrued ratably from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is a market rate of interest. Company contributions to the defined contribution plan are expensed as incurred. (g) INVENTORIES Inventories of crude oil and refined products are valued at the lower of cost using the last-in, first-out (LIFO) method and net realizable value. Materials and supplies are valued at the lower of average cost and net realizable value. (h) DERIVATIVE FINANCIAL INSTRUMENTS The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of market prices for its petroleum and natural gas products and to protect its Canadian dollar income and cash flows against adverse foreign currency exchange movements. The company also periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to interest rate fluctuations. The company does not use derivative financial instruments involving multipliers or leverage. These derivative contracts are initiated within the guidelines of the company's risk management policies, which require stringent authorities for approval and commitment of contracts, designation of the contracts by management as hedges of the related transactions, and monitoring of the effectiveness of such contracts in reducing the related risks. Contract maturities are consistent with the settlement dates of the related hedged transactions. Derivative contracts accounted for as hedges are not recognized in the consolidated balance sheets. Gains or losses on these contracts are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized. Gains or losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur. (i) FOREIGN CURRENCY TRANSLATION Monetary assets and liabilities in foreign currencies are translated to Canadian dollars at rates of exchange in effect at the end of the period. Other assets and related depreciation, depletion and amortization, other liabilities, revenues and expenses are translated at rates of exchange in effect at the respective transaction dates. The resulting exchange gains and losses are included in earnings, except for unrealized exchange gains and losses arising on translation of long-term liabilities with fixed or ascertainable lives. These gains and losses are deferred and amortized over the remaining terms of the liabilities. The company's oil shale project in Australia is integrated with the company's other activities and is translated in the manner described above. (j) STOCK-BASED COMPENSATION PLANS Under the company's share option programs, common share options are granted to executives, certain employees and non-employee directors. The company does not recognize compensation expense on the issuance of common share options under these programs because the exercise price of the share options is equal to the market value of the common shares at the date of grant. The company also has long-term employee incentive plans which provide awards to certain executives based on the market price of the company's common shares and to all other employees based on the market price of the company's common shares and the achievement of certain performance measurement criteria relating to the company's business segments. These awards vest on April 1, 2002 and are payable at that time, generally in equal amounts of cash and common shares of the company. The estimated costs of the cash portion of these awards, based on share price and expected performance achievement, are recorded as compensation expense over the vesting period. Under the company's directors' compensation plan, non-employee directors of the company may elect to receive half or all of their annual remuneration as directors in common share equivalents. The estimated costs of directors' compensation in the form of these common share equivalents, based on share price, are recorded as compensation expense annually. 58 SUNCOR ENERGY INC. 2000 ANNUAL REPORT CONSOLIDATED FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF EARNINGS
for the years ended December 31 - ----------------------------------------------------------------------------------- ($ millions) 2000 1999 1998 - ----------------------------------------------------------------------------------- REVENUES Sales and other operating revenues (notes 5 and 7) 3 385 2 383 2 068 Interest 3 4 2 - ----------------------------------------------------------------------------------- 3 388 2 387 2 070 - ----------------------------------------------------------------------------------- EXPENSES Purchases of crude oil and products 807 519 366 Operating, selling and general (note 13) 918 774 698 Exploration (note 5) 53 40 40 Royalties (note 4) 199 99 78 Taxes other than income taxes (note 5) 361 334 325 Depreciation, depletion and amortization 365 318 264 Gain on disposal of assets (148) (34) (6) Write-down of oil shale assets (note 2) 125 -- -- Restructuring (note 3) 65 -- -- Start-up expenses - Project Millennium (note 9) 15 -- -- Interest (note 5) 8 26 24 - ----------------------------------------------------------------------------------- 2 768 2 076 1 789 - ----------------------------------------------------------------------------------- EARNINGS BEFORE INCOME TAXES 620 311 281 - ----------------------------------------------------------------------------------- PROVISION FOR INCOME TAXES (note 6) Current Income taxes on earnings 45 29 (3) Income tax refund -- -- (16) - ----------------------------------------------------------------------------------- 45 29 (19) - ----------------------------------------------------------------------------------- Future Income taxes on earnings 198 96 117 Income tax refund -- -- 5 - ----------------------------------------------------------------------------------- 198 96 122 - ----------------------------------------------------------------------------------- 243 125 103 - ----------------------------------------------------------------------------------- NET EARNINGS 377 186 178 Dividends on preferred securities (note 16) (26) (22) -- - ----------------------------------------------------------------------------------- Net earnings attributable to common shareholders 351 164 178 - ----------------------------------------------------------------------------------- PER COMMON SHARE (dollars) (note 17) Net earnings attributable to common shareholders - - basic 1.58 0.74 0.81 - - diluted 1.57 0.73 0.80 - ----------------------------------------------------------------------------------- Cash dividends 0.34 0.34 0.34 - -----------------------------------------------------------------------------------
See accompanying summary of accounting policies and notes. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 59 CONSOLIDATED FINANCIAL STATEMENTS CONSOLIDATED BALANCE SHEETS
as at December 31 - ------------------------------------------------------------------------------------ ($ millions) 2000 1999 1998 - ------------------------------------------------------------------------------------ ASSETS CURRENT ASSETS Cash and cash equivalents 21 5 26 Accounts receivable (notes 5 and 7) 407 277 190 Current income taxes -- -- 10 Future income taxes (note 6) 45 14 -- Inventories (note 8) 192 161 175 - ------------------------------------------------------------------------------------ Total current assets 665 457 401 Capital assets, net (note 9) 5 883 4 528 3 504 Deferred charges and other (note 10) 166 191 199 Future income taxes (note 6) 119 -- -- - ------------------------------------------------------------------------------------ Total assets 6 833 5 176 4 104 - ------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Short-term borrowings 64 32 16 Accounts payable 424 277 125 Accrued liabilities (notes 13 and 14) 285 339 169 Income taxes payable 15 15 -- Future income taxes (note 6) 9 -- -- Taxes other than income taxes 39 46 59 Current portion of long-term borrowings (note 11) 1 1 1 - ------------------------------------------------------------------------------------ Total current liabilities 837 710 370 - ------------------------------------------------------------------------------------ Long-term borrowings (notes 11 and 12) 2 192 1 306 1 298 Accrued liabilities and other (notes 13 and 14) 252 236 194 Future income taxes (note 6) 1 080 816 743 Commitments and contingencies (note 15) SHAREHOLDERS' EQUITY Preferred securities (note 16) 514 514 -- Share capital (note 17) 537 524 518 Retained earnings 1 421 1 070 981 - ------------------------------------------------------------------------------------ Total shareholders' equity 2 472 2 108 1 499 - ------------------------------------------------------------------------------------ Total liabilities and shareholders' equity 6 833 5 176 4 104 - ------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------
See accompanying summary of accounting policies and notes. Approved on behalf of the Board: /s/ R.L. George /s/ R.W. Korthals - -------------------- ----------------------- R.L. George, Director R.W. Korthals, Director 60 SUNCOR ENERGY INC. 2000 ANNUAL REPORT CONSOLIDATED FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31 - ------------------------------------------------------------------------------------------------ ($ millions) 2000 1999 1998 - ------------------------------------------------------------------------------------------------ OPERATING ACTIVITIES Cash flow provided from operations (1), (2) 958 591 580 Decrease (increase) in operating working capital Accounts receivable (note 5) (130) (101) 77 Inventories (31) 14 (16) Accounts payable and accrued liabilities 93 322 (114) Taxes payable 18 12 (14) - ------------------------------------------------------------------------------------------------ Cash provided from operating activities 908 838 513 - ------------------------------------------------------------------------------------------------ CASH USED IN INVESTING ACTIVITIES (2) (1 607) (1 290) (937) - ------------------------------------------------------------------------------------------------ NET CASH DEFICIENCY BEFORE FINANCING ACTIVITIES (699) (452) (424) - ------------------------------------------------------------------------------------------------ FINANCING ACTIVITIES Increase (decrease) in short-term borrowings 32 16 (20) Issuance of preferred securities (note 16) -- 507 -- Stuart Oil Shale Project borrowings -- 11 49 Repayment of commercial paper borrowings (note 16) -- (507) -- Repayment of 12% debentures, Series A -- -- (55) Net increase in other long-term borrowings 792 510 533 Issuance of common shares under stock option plan (note 17) 9 6 5 Dividends paid on preferred securities (3) (note 16) (47) (37) -- Dividends paid on common shares (71) (75) (75) - ------------------------------------------------------------------------------------------------ Cash provided from financing activities 715 431 437 - ------------------------------------------------------------------------------------------------ INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 16 (21) 13 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 5 26 13 - ------------------------------------------------------------------------------------------------ CASH AND CASH EQUIVALENTS AT END OF YEAR 21 5 26 - ------------------------------------------------------------------------------------------------ PER COMMON SHARE (dollars) (note 17) (1) Cash flow provided from operations 4.32 2.68 2.64 (3) Dividends paid on preferred securities (pre-tax) 0.21 0.17 -- - ------------------------------------------------------------------------------------------------ Cash flow provided from operations after deducting dividends paid on preferred securities 4.11 2.51 2.64 - ------------------------------------------------------------------------------------------------ (2) See Schedules of Segmented Data on pages 64 and 65 - ------------------------------------------------------------------------------------------------
See accompanying summary of accounting policies and notes. CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
- ------------------------------------------------------------------------------------------------ Preferred Share Retained ($ millions) Securities Capital Earnings - ------------------------------------------------------------------------------------------------ AT DECEMBER 31, 1997 -- 513 878 Net earnings -- -- 178 Dividends paid on common shares -- -- (75) Issued for cash under stock option plan -- 4 -- Issued under dividend reinvestment plan -- 1 -- - ------------------------------------------------------------------------------------------------ AT DECEMBER 31, 1998 -- 518 981 Net earnings -- -- 186 Dividends paid on preferred securities -- -- (22) Dividends paid on common shares -- -- (75) Issuance of preferred securities (note 16) 514 -- -- Issued for cash under stock option plan -- 6 -- - ------------------------------------------------------------------------------------------------ AT DECEMBER 31, 1999 514 524 1 070 Net earnings -- -- 377 Dividends paid on preferred securities -- -- (26) Dividends paid on common shares -- -- (71) Issued for cash under stock option plan -- 9 -- Issued under dividend reinvestment plan -- 4 (4) Income taxes - impact of new standard (note 1) -- -- 75 - ------------------------------------------------------------------------------------------------ AT DECEMBER 31, 2000 514 537 1 421 - ------------------------------------------------------------------------------------------------
See accompanying summary of accounting policies and notes. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 61 CONSOLIDATED FINANCIAL STATEMENTS SCHEDULES OF SEGMENTED DATA*
for the years ended December 31 - ------------------------------------------------------------------------------------------------------------------------------ Oil Sands Natural Gas Sunoco ($ millions) 2000 1999 1998 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------ EARNINGS REVENUES** Sales and other operating revenues 544 461 421 237 143 114 2 604 1 779 1 533 Intersegment revenues*** 792 428 347 191 163 176 -- -- -- Interest -- -- -- -- -- -- -- -- -- - ------------------------------------------------------------------------------------------------------------------------------ 1 336 889 768 428 306 290 2 604 1 779 1 533 - ------------------------------------------------------------------------------------------------------------------------------ EXPENSES Purchases of crude oil and products 3 6 10 -- -- -- 1 783 1 090 845 Operating, selling and general 467 369 341 74 88 86 310 270 263 Exploration -- -- -- 53 40 40 -- -- -- Royalties 98 51 43 101 48 35 -- -- -- Taxes other than income taxes 12 9 7 3 5 5 345 320 313 Depreciation, depletion and amortization 232 177 128 78 87 84 54 53 51 (Gain) loss on disposal of assets -- 2 (1) (147) (36) (5) (1) -- -- Write-down of oil shale assets -- -- -- -- -- -- -- -- -- Restructuring -- -- -- 65 -- -- -- -- -- Start-up expenses - Project Millennium 15 -- -- -- -- -- -- -- -- Interest -- -- -- -- -- -- -- -- -- - ------------------------------------------------------------------------------------------------------------------------------ 827 614 528 227 232 245 2 491 1 733 1 472 - ------------------------------------------------------------------------------------------------------------------------------ EARNINGS (LOSS) BEFORE INCOME TAXES 509 275 240 201 74 45 113 46 61 Income taxes (194) (108) (95) (103) (33) (21) (32) (19) (24) - ------------------------------------------------------------------------------------------------------------------------------ NET EARNINGS (LOSS) 315 167 145 98 41 24 81 27 37 - ------------------------------------------------------------------------------------------------------------------------------ As at December 31 TOTAL ASSETS 5 079 3 178 2 081 762 962 943 911 849 874 - ------------------------------------------------------------------------------------------------------------------------------ CAPITAL EMPLOYED**** 1 412 1 352 1 242 412 727 772 386 405 499 - ------------------------------------------------------------------------------------------------------------------------------ RETURN ON AVERAGE CAPITAL EMPLOYED (%)**** 22.8 12.9 16.3 17.2 5.5 3.3 20.5 6.0 7.4 - ------------------------------------------------------------------------------------------------------------------------------ RETURN ON AVERAGE CAPITAL EMPLOYED (%)***** 10.6 9.2 11.6 17.2 5.5 3.3 20.5 6.0 7.4 - ------------------------------------------------------------------------------------------------------------------------------
* The company currently has no foreign geographic segments. See note 5 for information on export sales. Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies. ** Two customers in the Oil Sands segment in 2000 represented 10% or more ($493 million and $355 million) of the company's 2000 consolidated revenues (1999 - one customer represented 10% or more ($281 million); 1998 none). *** Intersegment revenues are recorded at prevailing fair market prices and accounted for as if the sales were to third parties. **** Capital Employed - the total of shareholders' equity and debt (short-term borrowings and current and long-term portions of long-term borrowings), less capitalized costs related to major projects in progress. Long-term borrowings are recorded mainly in the Corporate segment. ***** If capital employed were to include capitalized costs related to major projects in progress, the return on average capital employed would be as stated on this line. See accompanying summary of accounting policies and notes. 62 SUNCOR ENERGY INC. 2000 ANNUAL REPORT CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------------------------------------------------------------ Corporate and eliminations Total ($ millions) 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------------------------ EARNINGS REVENUES** Sales and other operating revenues -- -- -- 3 385 2 383 2 068 Intersegment revenues*** (983) (591) (523) -- -- -- Interest 3 4 2 3 4 2 - ------------------------------------------------------------------------------------------------ (980) (587) (521) 3 388 2 387 2 070 - ------------------------------------------------------------------------------------------------ EXPENSES Purchases of crude oil and products (979) (577) (489) 807 519 366 Operating, selling and general 67 47 8 918 774 698 Exploration -- -- -- 53 40 40 Royalties -- -- -- 199 99 78 Taxes other than income taxes 1 -- -- 361 334 325 Depreciation, depletion and amortization 1 1 1 365 318 264 (Gain) loss on disposal of assets -- -- -- (148) (34) (6) Write-down of oil shale assets 125 -- -- 125 -- -- Restructuring -- -- -- 65 -- -- Start-up expenses - Project Millennium -- -- -- 15 -- -- Interest 8 26 24 8 26 24 - ------------------------------------------------------------------------------------------------ (777) (503) (456) 2 768 2 076 1 789 - ------------------------------------------------------------------------------------------------ EARNINGS (LOSS) BEFORE INCOME TAXES (203) (84) (65) 620 311 281 Income taxes 86 35 37 (243) (125) (103) - ------------------------------------------------------------------------------------------------ NET EARNINGS (LOSS) (117) (49) (28) 377 186 178 - ------------------------------------------------------------------------------------------------ As at December 31 TOTAL ASSETS 81 187 206 6 833 5 176 4 104 - ------------------------------------------------------------------------------------------------ CAPITAL EMPLOYED**** 22 (121) (72) 2 232 2 363 2 441 - ------------------------------------------------------------------------------------------------ RETURN ON AVERAGE CAPITAL EMPLOYED (%)**** 16.6 8.3 9.5 - ------------------------------------------------------------------------------------------------ RETURN ON AVERAGE CAPITAL EMPLOYED (%)***** -- -- -- 9.3 6.4 7.6 - ------------------------------------------------------------------------------------------------
SUNCOR ENERGY INC. 2000 ANNUAL REPORT 63 CONSOLIDATED FINANCIAL STATEMENTS SCHEDULES OF SEGMENTED DATA*
for the years ended December 31 - -------------------------------------------------------------------------------------------------------------------------------- Oil Sands Natural Gas Sunoco ($ millions) 2000 1999 1998 2000 1999 1998 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------------------- CASH FLOW BEFORE FINANCING ACTIVITIES CASH PROVIDED FROM (USED IN) OPERATING ACTIVITIES: Cash flow provided from (used in) operations Net earnings (loss) 315 167 145 98 41 24 81 27 37 Exploration expenses Cash -- -- -- 12 12 16 -- -- -- Dry hole costs -- -- -- 41 28 24 -- -- -- Non-cash items included in earnings Depreciation, depletion and amortization 232 177 128 78 87 84 54 53 51 Future income taxes 189 102 76 101 31 14 (16) (33) 13 Current income tax provision allocated to Corporate 5 6 19 2 2 7 48 52 11 (Gain) loss on disposal of assets -- 2 (1) (147) (36) (5) (1) -- -- Write-down of oil shale assets -- -- -- -- -- -- -- -- -- Restructuring -- -- -- 56 -- -- -- -- -- Other (12) -- (4) (4) 6 3 6 3 1 Overburden removal outlays (48) (53) (46) -- -- -- -- -- -- Overburden removal outlays - Project Millennium (27) -- -- -- -- -- -- -- -- Increase (decrease) in deferred credits and other 1 4 3 1 1 -- 2 1 (1) - -------------------------------------------------------------------------------------------------------------------------------- Total cash flow provided from (used in) operations 655 405 320 238 172 167 174 103 112 Decrease (increase) in operating working capital (169) 83 (8) 27 27 (13) 40 69 7 - -------------------------------------------------------------------------------------------------------------------------------- Total cash provided from (used in) operating activities 486 488 312 265 199 154 214 172 119 - -------------------------------------------------------------------------------------------------------------------------------- CASH PROVIDED FROM (USED IN) INVESTING ACTIVITIES: Capital and exploration expenditures (1 808) (1 057) (507) (127) (200) (242) (45) (42) (60) Deferred maintenance shutdown expenditures (3) (22) (7) (1) -- (1) (9) -- (2) Deferred outlays and other investments (5) (7) (1) -- -- 1 (7) (2) (3) Proceeds from disposals 101 1 1 314 90 9 2 1 1 - -------------------------------------------------------------------------------------------------------------------------------- Total cash provided from (used in) investing activities (1 715) (1 085) (514) 186 (110) (233) (59) (43) (64) - -------------------------------------------------------------------------------------------------------------------------------- NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES (1 229) (597) (202) 451 89 (79) 155 129 55 - --------------------------------------------------------------------------------------------------------------------------------
* The company currently has no foreign geographic segments. See note 5 for information on export sales. Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies. See accompanying summary of accounting policies and notes. 64 SUNCOR ENERGY INC. 2000 ANNUAL REPORT CONSOLIDATED FINANCIAL STATEMENTS
- ---------------------------------------------------------------------------------------------------- Corporate and eliminations Total ($ millions) 2000 1999 1998 2000 1999 1998 - ---------------------------------------------------------------------------------------------------- CASH FLOW BEFORE FINANCING ACTIVITIES CASH PROVIDED FROM (USED IN) OPERATING ACTIVITIES: Cash flow provided from (used in) operations Net earnings (loss) (117) (49) (28) 377 186 178 Exploration expenses Cash -- -- -- 12 12 16 Dry hole costs -- -- -- 41 28 24 Non-cash items included in earnings Depreciation, depletion and amortization 1 1 1 365 318 264 Future income taxes (76) (4) 19 198 96 122 Current income tax provision allocated to Corporate (55) (60) (37) -- -- -- (Gain) loss on disposal of assets -- -- -- (148) (34) (6) Write-down of oil shale assets 125 -- -- 125 -- -- Restructuring -- -- -- 56 -- -- Other (7) 4 3 (17) 13 3 Overburden removal outlays -- -- -- (48) (53) (46) Overburden removal outlays - Project Millennium -- -- -- (27) -- -- Increase (decrease) in deferred credits and other 20 19 23 24 25 25 - ---------------------------------------------------------------------------------------------------- Total cash flow provided from (used in) operations (109) (89) (19) 958 591 580 Decrease (increase) in operating working capital 52 68 (53) (50) 247 (67) - ---------------------------------------------------------------------------------------------------- Total cash provided from (used in) operating activities (57) (21) (72) 908 838 513 - ---------------------------------------------------------------------------------------------------- CASH PROVIDED FROM (USED IN) INVESTING ACTIVITIES: Capital and exploration expenditures (18) (51) (127) (1 998) (1 350) (936) Deferred maintenance shutdown expenditures -- -- -- (13) (22) (10) Deferred outlays and other investments (1) (1) 1 (13) (10) (2) Proceeds from disposals -- -- -- 417 92 11 - ---------------------------------------------------------------------------------------------------- Total cash provided from (used in) investing activities (19) (52) (126) (1 607) (1 290) (937) - ---------------------------------------------------------------------------------------------------- NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES (76) (73) (198) (699) (452) (424) - ----------------------------------------------------------------------------------------------------
SUNCOR ENERGY INC. 2000 ANNUAL REPORT 65 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. CHANGES IN ACCOUNTING POLICIES Effective January 1, 2000, the company adopted new recommendations issued by the Accounting Standards Board of the Canadian Institute of Chartered Accountants with respect to accounting for the costs of employee future benefits; accounting for income taxes; and, the computation, presentation and disclosure of earnings per share. EMPLOYEE FUTURE BENEFITS: The new recommendations on accounting for the costs of employee future benefits, which will not affect the company's cash flows or liquidity, have been adopted retroactively and financial statements of all prior periods presented for comparative purposes have been restated to give effect to them. Accordingly, at January 1, 2000, retained earnings were decreased by $34 million, accrued liabilities and other were increased by $57 million and future income taxes were decreased by $23 million. The impact of the new recommendations for the year ended December 31, 2000 was to increase operating, selling and general expenses by $14 million (1999 - $24 million; 1998 - $16 million) and decrease net earnings by $8 million (1999 - $14 million; 1998 - $10 million). FUTURE INCOME TAXES: The new recommendations on accounting for income taxes, which will not affect the company's cash flows or liquidity, have been adopted retroactively as an adjustment to opening retained earnings to reflect the cumulative effect of the change on prior periods. The financial statements of prior periods presented for comparative purposes have not been restated. Accordingly, at January 1, 2000, retained earnings were increased and future income taxes were decreased by $75 million. The impact of the new recommendations for the year ended December 31, 2000 was to increase net earnings by $23 million. EARNINGS PER SHARE: The new recommendations on earnings per share, which bring Canadian accounting requirements in line with U.S. and international standards, require use of the treasury stock method to determine the dilutive effect of warrants, options and equivalents. Previously, the company used the current imputed earnings approach to determine the dilutive effect. The new recommendations have been adopted retroactively and earnings per share figures of all prior periods presented for comparative purposes have been restated to give effect to them. This change in accounting policy had no effect on basic earnings per share and no material effect on diluted earnings per share for the years ended December 31, 2000, 1999 and 1998. 2. OIL SHALE PROJECT In the third quarter of 2000, the company reviewed the carrying value of the company's costs associated with the Stuart Oil Shale Project as a result of operational issues, increased costs and delayed oil production. Based upon management's current operating assumptions and best estimates of the most probable set of economic conditions associated with the development of the project, the carrying value of the assets exceeded the net future cash flows from the project. As a result, the company recorded a write-down of the carrying value of the project of $125 million. The impact of this write-down was to decrease net earnings by $80 million. As at December 31, 2000, the company's records included the following significant amounts related to the oil shale project: Net capital assets of $134 million, after the above write-down. Investments in partly paid Restricted Class Shares of the Australian joint venture participants in the Stuart Oil Shale Project, Central Pacific Minerals NL (CPM) and Southern Pacific Petroleum NL (SPP), totalling $4 million. These shares convey to the company a right, but not an obligation, to fully pay for additional Restricted Class Shares of CPM and SPP, respectively, for an additional investment of approximately $57 million. Ownership of these shares would represent approximately a 14% interest in CPM and SPP as at December 31, 2000. The Restricted Class Shares would automatically convert to an equal number of common shares in June 2004, or earlier in certain circumstances. The market value of these common shares at December 31, 2000, based on quoted market prices, was approximately $144 million (1999 - $222 million; 1998 - $157 million). It is uncertain, however, whether the quoted market price would be fully realized upon any future sale of these shares. Long-term borrowings of $73 million and accrued interest of $16 million. Principal and interest repayable from project net cash flows. The success of the Stuart Oil Shale Project is subject to uncertainty. If the project is unsuccessful, the above amounts would be eliminated. The impact on future earnings, should this occur, is currently estimated to not be significant. 3. RESTRUCTURING CHARGE In 2000, the carrying value of certain assets of the company's Natural Gas business were written down to their net estimated recoverable amount and a provision for estimated restructuring costs was recorded, as follows: 66 SUNCOR ENERGY INC. 2000 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------- ($ millions) - --------------------------------------------- Non-cash charges: Impairment of non-core proved properties 21 Impairment of non-core unproved properties 18 Write-down of capitalized development costs on proved properties 17 Cash charges: Employee terminations 6 Consultants and other 3 - --------------------------------------------- 65 - --------------------------------------------- - ---------------------------------------------
The impact of these charges is to decrease net earnings by $30 million. At December 31, 2000, current liabilities include $2 million related to termination and other costs to be paid in 2001. 4. ROYALTIES
- ------------------------------------------------------------------------------ 2000 1999 1998 ($ millions) Crown Other Total Crown Other Total Crown Other Total - ------------------------------------------------------------------------------ Oil Sands 87 11 98 48 3 51 35 8 43 Natural Gas 90 11 101 40 8 48 28 7 35 - ------------------------------------------------------------------------------ Total 177 22 199 88 11 99 63 15 78 - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------
Alberta Crown royalties totalling $8 million (1999 - $7 million; 1998 - $5 million) were paid in kind, and are not shown in the company's revenues and expenses. 5. SUPPLEMENTAL INFORMATION
- ---------------------------------------------------------------------------- ($ millions) 2000 1999 1998 - ---------------------------------------------------------------------------- Export sales (1) 478 233 231 - ---------------------------------------------------------------------------- Exploration expenses Geological and geophysical 10 10 14 Other 2 2 2 - ---------------------------------------------------------------------------- Cash costs 12 12 16 Dry hole costs 41 28 24 - ---------------------------------------------------------------------------- Cash and dry hole costs (2) 53 40 40 Leasehold impairment (3) 10 12 10 - ---------------------------------------------------------------------------- 63 52 50 - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- Taxes other than income taxes Excise taxes (4) 336 311 305 Production, property and other taxes 25 23 20 - ---------------------------------------------------------------------------- 361 334 325 - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- Interest expense Long-term interest cost 112 71 67 Less interest capitalized (104) (45) (43) - ---------------------------------------------------------------------------- 8 26 24 - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- Cash interest payments 104 63 64 - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- Allowance for doubtful accounts 3 3 3 - ---------------------------------------------------------------------------- - ----------------------------------------------------------------------------
In 2000, the company had in place a securitization program to sell, on an ongoing basis, up to $122 million of accounts receivable (1999 - $83 million) on a limited recourse basis, to a third party. As at December 31, 2000, $122 million (1999 - $83 million) in accounts receivable had been sold under the program. On December 31, 1998, the company sold, on a limited recourse basis, approximately $50 million in accounts receivable to third parties. The company believes it has no significant exposure to credit loss under the recourse provisions. (1) Sales of crude oil, natural gas and refined products to customers in the United States and petrochemicals in Europe. (2) Exploration expenses in the Consolidated Statements of Earnings. (3) Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings. (4) Excise taxes are also included in sales and other operating revenues in the Consolidated Statements of Earnings. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 67 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. INCOME TAXES THE ASSETS AND LIABILITIES SHOWN ON SUNCOR'S BALANCE SHEETS ARE CALCULATED USING ACCOUNTING RULES KNOWN AS GENERALLY ACCEPTED ACCOUNTING PRINCIPLES. SUNCOR'S INCOME TAXES ARE CALCULATED ACCORDING TO GOVERNMENT TAX LAWS AND REGULATIONS, WHICH COULD RESULT IN DIFFERENT VALUES FOR SOME ASSETS AND LIABILITIES FOR INCOME TAX PURPOSES. THESE DIFFERENCES ARE KNOWN AS TEMPORARY DIFFERENCES, BECAUSE EVENTUALLY THESE DIFFERENCES WILL REVERSE. THE AMOUNT SHOWN ON THE BALANCE SHEETS AS FUTURE INCOME TAXES REPRESENTS NON-DISCOUNTED INCOME TAXES THAT WILL EVENTUALLY BE PAYABLE OR RECOVERABLE IN FUTURE YEARS WHEN THESE TEMPORARY DIFFERENCES DO REVERSE. SEE BELOW FOR MORE TECHNICAL DETAILS AND NUMBERS. The provision for income taxes reflects an effective tax rate which differs from the statutory tax rate. A reconciliation of the two rates and the dollar effect is as follows:
- ------------------------------------------------------------------------------------------------- 2000 1999 1998 ($ millions) AMOUNT % Amount % Amount % - ------------------------------------------------------------------------------------------------- Federal tax rate 236 38 118 38 107 38 Provincial abatement (62) (10) (31) (10) (28) (10) Federal surtax 7 1 3 1 3 1 Provincial tax rates 96 16 48 16 46 16 - ------------------------------------------------------------------------------------------------- STATUTORY TAX AND RATE 277 45 138 45 128 45 Add (deduct) the tax effect of: Crown royalties (see note 4) 83 13 44 13 31 11 Resource allowance (101) (17) (56) (17) (49) (16) Large corporations tax 10 2 10 3 9 3 Income tax refund* -- -- -- -- (11) (4) Tax rate changes on future income taxes (13) (2) -- -- -- -- Attributed Canadian royalty income (13) (2) -- -- -- -- Other -- -- (11) (4) (5) (2) - ------------------------------------------------------------------------------------------------- INCOME TAXES AND EFFECTIVE RATE 243 39 125 40 103 37 - ------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------
2000 income tax payments totalled $22 million (1999 - payments of $5 million; 1998 - net refund of $19 million). * During 1998, settlements were reached with Canada Customs and Revenue Agency (formerly Revenue Canada) on a number of taxation issues resulting in refunds totalling $34 million, $11 million of which were reflected in 1997 net earnings ($0.05 per common share). The impact of the refund in 1998 is to increase net earnings by $11 million ($0.05 per common share) reflecting a reduction of prior years income taxes of $5 million and taxable interest of $6 million (after a provision for income taxes of $5 million). At December 31, 2000, future income taxes are comprised of the following:
- --------------------------------------------------------- ($ millions) Current Non-current - --------------------------------------------------------- Future income tax assets: Employee future benefits 2 39 Reclamation and environmental remediation costs 9 23 Royalties -- 43 Employee incentive plans -- 10 Inventories 20 -- Other 14 4 - --------------------------------------------------------- 45 119 - --------------------------------------------------------- - --------------------------------------------------------- Future income tax liabilities: Depreciation -- 1 038 Overburden removal costs -- 23 Maintenance shutdown costs -- 12 Other 9 7 - --------------------------------------------------------- 9 1 080 - --------------------------------------------------------- - ---------------------------------------------------------
7. RELATED PARTY TRANSACTIONS The following table summarizes the company's related party transactions for the year and balances at the end of the year. These transactions are in the normal course of operations and have been carried out on the same terms as would apply with unrelated parties.
- ----------------------------------------------------------------- ($ millions) 2000 1999 1998 - ----------------------------------------------------------------- Revenues Sales to Sunoco joint ventures: Refined products 600 395 309 Petrochemicals 128 108 85 - ----------------------------------------------------------------- At the end of the year, amounts due from related parties are as follows: Sunoco joint ventures 58 45 41 - -----------------------------------------------------------------
68 SUNCOR ENERGY INC. 2000 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Sales to and balances with Sunoco joint ventures are exchange amounts established and agreed to by the related parties, before application of the proportionate consolidation method of accounting. The company has exclusive supply agreements with two Sunoco joint ventures for the sale of refined products. One agreement expires in 2002, after which the company will continue to be the exclusive supplier of refined products as long as it remains a shareholder. The company plans to maintain its relationship with this joint venture. The other agreement expires in 2003 and will be automatically renewed thereafter for one-year terms until terminated upon twelve months' prior written notice. No notice has been given by either party. The company also has a non-exclusive supply agreement with a Sunoco joint venture for the sale of petrochemicals. The agreement is automatically renewed on an annual basis until it is terminated by either party upon twelve months' written notice. No notice has been given by either party. 8. INVENTORIES
- ------------------------------------------------------------- ($ millions) 2000 1999 1998 - ------------------------------------------------------------- Crude Oil 83 47 58 Refined products 55 67 62 Materials and supplies 54 47 55 - ------------------------------------------------------------- Total 192 161 175 - ------------------------------------------------------------- - -------------------------------------------------------------
The replacement cost at December 31, 2000, of all inventories valued at LIFO exceeded their carrying value by $61 million (1999 - $37 million; 1998 - -nil). In 2000, the company sold inventories produced in prior years whose LIFO costs were lower than current crude oil and operating costs. The impact of this reduction in inventory was to decrease expenses by $8 million and increase net earnings by $5 million. 9. CAPITAL ASSETS
- ----------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 ACCUM. Accum. Accum. ($ millions) COST PROVISION Cost Provision Cost Provision - ----------------------------------------------------------------------------------------------------------------------- Oil Sands Plant 1 814 496 1 770 487 1 548 449 Mine and mobile equipment 918 313 850 243 828 191 Capitalized energy services asset lease 101 2 -- -- -- -- Capitalized aircraft lease 8 -- -- -- -- -- Project Millennium* - in-service 102 6 -- -- -- -- - in-progress 2 434 -- 905 -- 99 -- - ----------------------------------------------------------------------------------------------------------------------- 5 377 817 3 525 730 2 475 640 - ----------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------- Natural Gas Proved properties (note 3) 877 366 1 190 487 1 242 506 Unproved properties (note 3) 125 56 344 171 288 169 Pipeline 20 17 22 18 22 18 Other support facilities and equipment 13 6 19 12 18 10 - ----------------------------------------------------------------------------------------------------------------------- 1 035 445 1 575 688 1 570 703 - ----------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------- Sunoco Refinery 745 367 740 350 724 327 Marketing and transportation 405 187 380 165 362 148 - ----------------------------------------------------------------------------------------------------------------------- 1 150 554 1 120 515 1 086 475 - ----------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------- Corporate Stuart Oil Shale Project (note 2) 134 -- 237 -- 187 -- Other 6 3 7 3 6 2 - ----------------------------------------------------------------------------------------------------------------------- 140 3 244 3 193 2 - ----------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------- 7 702 1 819 6 464 1 936 5 324 1 820 - ----------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------- Net capital assets 5 883 4 528 3 504 - ----------------------------------------------------------------------------------------------------------------------- - -----------------------------------------------------------------------------------------------------------------------
Interest capitalized during 2000 totalled $104 million (1999 - $45 million; 1998 - $43 million). Capitalized costs related to the in-progress phase of Project Millennium and the Stuart Oil Shale Project are not being amortized. Depreciation will begin when the facilities are substantially complete and ready for commercial production to commence. * Start-up costs incurred in the commissioning of Project Millennium have been expensed. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 69 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. DEFERRED CHARGES AND OTHER
- --------------------------------------------------------------------------------- ($ millions) 2000 1999 1998 - --------------------------------------------------------------------------------- Oil sands overburden removal costs (see below) 76 85 95 Deferred maintenance shutdown costs 35 45 44 Investments 8 8 8 Other 47 53 52 - --------------------------------------------------------------------------------- 166 191 199 - --------------------------------------------------------------------------------- - --------------------------------------------------------------------------------- Oil sands overburden removal costs Balance - beginning of year 85 95 86 Outlays during year 75 53 46 Depreciation on equipment during year 8 6 2 - --------------------------------------------------------------------------------- 168 154 134 Amortization during year (92) (69) (39) - --------------------------------------------------------------------------------- Balance - end of year 76 85 95 - --------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------
11. LONG-TERM BORROWINGS
- ------------------------------------------------------------------------------------------------- ($ millions) 2000 1999 1998 - ------------------------------------------------------------------------------------------------- FIXED RATE BORROWINGS Medium Term Notes, maturing in 2007. Interest payable semi-annually 400 400 400 7.4% Debentures, Series C, maturing in 2004. Interest payable semi-annually* 125 125 125 Borrowings under or with support of lines of credit converted to fixed rate obligations by interest rate swap transactions, maturing in 2003. Interest payable quarterly at rates averaging 5.6%** 110 110 110 Stuart Oil Shale Project borrowings with interest at 7.75% (note 2) 73 82 71 Sunoco joint venture borrowings with interest at rates averaging 7.7% at December 31, 2000 (1999 - 7.6%; 1998 - 7.1%) 4 5 5 - ------------------------------------------------------------------------------------------------- 712 722 711 Capital leases*** 109 -- -- Less current portion of fixed rate long-term borrowings 1 1 1 - ------------------------------------------------------------------------------------------------- 820 721 710 - ------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------- VARIABLE RATE BORROWINGS**** Borrowings with interest at variable rates averaging 6.0% at December 31, 2000 (1999 - 5.2%; 1998 - 5.3%) under or with support of lines of credit 1 372 585 588 - ------------------------------------------------------------------------------------------------- TOTAL LONG-TERM BORROWINGS 2 192 1 306 1 298 - ------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------
* During 1996, the company entered into a cross-currency interest rate swap transaction to convert its 7.4% Debentures to a 6.2% fixed interest rate U.S. dollar obligation of approximately $91 million. Later in 1996, the company entered into another cross-currency interest rate swap transaction to convert the U.S. $91 million obligation back to a fixed rate Canadian $125 million obligation. Both contracts will remain in place for the term of the debenture. The net effect of the two swap transactions is to reduce the effective interest rate on the debentures from 7.3% (7.4% coupon rate) to 5.5%. The principal obligation remains unchanged. ** During 1998, the company entered into interest rate swap transactions to convert $50 million and $60 million of variable rate borrowings to fixed interest rate obligations at 5.5% and 5.7%, respectively. 70 SUNCOR ENERGY INC. 2000 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS *** Obligations under capital leases are as follows:
- --------------------------------------------------------------- ($ millions) - --------------------------------------------------------------- Energy services assets lease with interest at 6.82% maturing in 2004 101 Aircraft lease with interest at prime plus 0.5% maturing in 2008 8 - --------------------------------------------------------------- 109 - --------------------------------------------------------------- - ---------------------------------------------------------------
Future minimum amounts payable under these capital leases are as follows:
- --------------------------------------------------------------- ($ millions) - --------------------------------------------------------------- 2001 8 2002 8 2003 8 2004 108 2005 1 Later years 6 - --------------------------------------------------------------- Total minimum lease payments 139 Less amount representing imputed interest (30) - --------------------------------------------------------------- Present value of obligation under capital leases 109 - --------------------------------------------------------------- - ---------------------------------------------------------------
**** During 1999, the company entered into a cross-currency interest rate swap transaction to convert U.S. $183 million of variable rate borrowings with interest based on 90-day LIBOR to Canadian $278 million with interest based on 90-day bankers' acceptances. LONG-TERM BORROWINGS
- ------------------------------------------- (percentages) 2000 1999 1998 - ------------------------------------------- Variable rate 63 45 45 Fixed rate 37 55 55
Principal repayments of long-term borrowings other than obligations under capital leases in each of the next five years are as follows:
- --------------------------------------------------------------- ($ millions) - --------------------------------------------------------------- 2001 1 2002 1 2003 2 2004 1 608 2005 -- - ---------------------------------------------------------------
12. LINES OF CREDIT At December 31, 2000, the company had available $2 411 million in credit and term loan facilities, of which $917 million had been drawn, as follows: A facility for $600 million, which is fully revolving for 364 days, has a term period of three years and expires in 2004. A facility for $500 million, which is fully revolving for 364 days and expires in 2001. A facility for U.S. $183 million (Cdn $278 million), which is non-revolving, has been fully drawn and expires in 2004. A facility for $1 018 million, which is fully revolving for six years and expires in 2004. Uncommitted facilities totalling $15 million, which can be terminated at any time at the option of the lenders. The company is also authorized, supported by unutilized credit and term loan facilities, to issue commercial paper to a maximum of $600 million having a term not to exceed 364 days. At December 31, 2000, the company had $565 million in commercial paper outstanding. These credit facilities are subject to commitment fees, the amounts of which are not significant. 13. ACCRUED LIABILITIES AND OTHER
- ------------------------------------------------------- ($ millions) 2000 1999 1998 - ------------------------------------------------------- Reclamation & environmental remediation costs (a) 70 86 87 Pension costs (see note 14) 95 96 83 Other (b) 87 54 24 - ------------------------------------------------------- Total 252 236 194 - ------------------------------------------------------- - -------------------------------------------------------
(a) RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS Total accrued reclamation and environmental remediation costs also include $27 million in current liabilities (1999 - $13 million; 1998 - $14 million). Payments during 2000 totalled $15 million (1999 - $13 million; 1998 - $11 million). The estimate of remaining reclamation costs for the company's oil sands operation is $525 million for its current mining operation and its Project Millennium. Factors such as inflation and changes in technology and proved reserves may materially change the cost estimate. The Natural Gas segment's reclamation and environmental remediation cost estimate decreased in 2000 from $57 million to $32 million, reflecting the divestment of properties (see note 3). A total of $26 million has been accrued to December 31, 2000. The remaining $6 million will be accrued over future years on a unit of production basis. (b) EMPLOYEE AND DIRECTOR INCENTIVE PLANS Compensation expense recorded under the company's long-term employee incentive plans was $32 million (1999 - $26 million; 1998 - $4 million). Compensation expense is an estimated amount, based on the market price of the company's common shares and expected performance achievement, and is therefore subject to measurement uncertainty and volatility. Compensation expense in the form of common share equivalents under the directors' compensation plan is not significant. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 71 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. EMPLOYEE FUTURE BENEFITS WHEN EMPLOYEES WORK FOR SUNCOR, THEY ARE ELIGIBLE TO RECEIVE PENSION, HEALTH CARE AND INSURANCE BENEFITS WHEN THEY RETIRE. THIS BENEFIT OBLIGATION OR COMMITMENT THAT SUNCOR HAS TO EMPLOYEES AND RETIREES AT DECEMBER 31, 2000 WAS $483 MILLION. AS REQUIRED BY GOVERNMENT REGULATIONS AND PLAN PERFORMANCE, SUNCOR SETS ASIDE FUNDS, WHICH ARE IN THE CUSTODY OF AN INDEPENDENT TRUSTEE, TO MEET THESE OBLIGATIONS. AT THE END OF DECEMBER 2000, PLAN ASSETS TO MEET THE BENEFIT OBLIGATION WERE $322 MILLION. THE EXCESS OF THE BENEFIT OBLIGATION OVER PLAN ASSETS OF $161 MILLION REPRESENTS THE NET UNFUNDED OBLIGATION. SEE BELOW FOR THE TECHNICAL DETAILS AND NUMBERS. DEFINED BENEFIT PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS The company's defined benefit pension plans provide a pension benefit at retirement based upon years of service and final average earnings. The defined benefit pension plans consist of a funded plan which covers most employees, and unfunded supplementary benefit plans which provide supplemental retirement benefits to executives. Under the funded plan, the company makes contributions to an independent trustee to cover pension payment obligations to retired employees. The trustee acts as the depository for contributions, the disbursing agent and custodian of the pension plan's assets. These assets are managed by a pension fund investment committee, on behalf of the beneficiaries, which retains independent managers and advisers. The company's other post-retirement benefits program, which is unfunded, includes certain health care and life insurance benefits provided to retired employees and eligible surviving dependants. Retirees share in the cost of providing these benefits. Company contributions to the funded pension plan, the present value of pension and other post-retirement benefit obligations and periodic benefit costs are determined by an independent actuary in accordance with regulatory requirements, based on management's best estimate of actuarial assumptions. ASSUMPTIONS AND ESTIMATES
- --------------------------------------------------------------------------- Other post- Pension benefits retirement benefits (percentages) 2000 1999 1998 2000 1999 1998 - --------------------------------------------------------------------------- Discount rate 7.00 7.25 6.00 7.00 7.25 6.00 Expected return on plan assets 7.25 7.25 8.00 -- -- -- Rate of compensation increase 4.25 4.25 4.50 4.25 4.25 4.50
The following table presents information about the funded status of the plans and obligations recognized in the consolidated balance sheets at December 31:
- ----------------------------------------------------------------------------------------------------------- Other Pension benefits post-retirement benefits 2000 1999 1998 2000 1999 1998 - ----------------------------------------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year 364 403 334 69 72 64 Service costs 12 15 11 3 4 2 Interest costs 26 24 23 5 4 5 Plan participants' contribution 3 2 2 -- -- -- Amendments -- -- -- -- (8) 3 Actuarial (gain) loss 23 (61) 51 4 (1) -- Benefits paid (24) (19) (18) (2) (2) (2) - ----------------------------------------------------------------------------------------------------------- Benefit obligation at end of year 404 364 403 79 69 72 - ----------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS* Fair value of plan assets at beginning of year 316 278 250 -- -- -- Actual return on plan assets 15 39 28 -- -- -- Employer contribution 12 16 16 -- -- -- Plan participants' contribution 3 2 2 -- -- -- Benefits paid (24) (19) (18) -- -- -- - ----------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of year 322 316 278 -- -- -- - ----------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------- Net unfunded obligation (82) (48) (125) (79) (69) (72) Items not yet recognized in earnings: Unamortized transitional asset (8) (16) (24) -- -- -- Unamortized net actuarial loss 45 18 108 13 11 21 - ----------------------------------------------------------------------------------------------------------- Accrued benefit liability* (45) (46) (41) (66) (58) (51) - ----------------------------------------------------------------------------------------------------------- * Current portion (15) (8) (8) (2) (2) (2) - ----------------------------------------------------------------------------------------------------------- Long-term portion (30) (38) (33) (64) (56) (49) - ----------------------------------------------------------------------------------------------------------- (45) (46) (41) (66) (58) (51) - ----------------------------------------------------------------------------------------------------------- - -----------------------------------------------------------------------------------------------------------
* Assets in the employees' pension plan consist of marketable equity securities, government and corporate bonds and short-term notes. Pension plan assets are not the company's assets and therefore are not included in the consolidated balance sheets. 72 SUNCOR ENERGY INC. 2000 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The above benefit obligation at year-end includes funded and unfunded plans, as follows:
- ------------------------------------------------------------------------------------------------------------------- Pension benefits Other post-retirement benefits 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------- Funded plan 334 309 332 -- -- -- Unfunded plans 70 55 71 79 69 72 - ------------------------------------------------------------------------------------------------------------------- Benefit obligation at end of year 404 364 403 79 69 72 - ------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------
The unamortized asset determined at January 1, 1987, the transition date, is being amortized on a straight-line basis over 15 years to 2001. The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 13 years for pension benefits (1999 and 1998 - 13 years), and over the expected average future service life to full eligibility age of 11 years for post-retirement benefits. The components of net periodic benefit cost are as follows:
- ------------------------------------------------------------------------------------------------------------------- Pension benefits Other post-retirement benefits 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------- Service costs 12 15 11 3 4 2 Interest costs 26 24 23 5 4 5 Expected return on plan assets (22) (22) (20) -- -- -- Amortization of transitional asset (8) (8) (8) -- -- -- Amortization of net actuarial loss 6 12 9 1 1 1 - ------------------------------------------------------------------------------------------------------------------- Net periodic benefit cost 14 21 15 9 9 8 - ------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------
In order to measure the expected cost of other post-retirement benefits, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease gradually each year to a rate of 5% for 2010 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for other post-retirement benefit obligations. A 1% change in assumed health care cost trend rates would have the following effects:
- ------------------------------------------------------------- 1% 1% ($ millions) increase decrease - ------------------------------------------------------------- Effect on total of service and interest cost components of net periodic post-retirement health care benefit cost 2 (1) - ------------------------------------------------------------- Effect on the health care component of the accumulated post-retirement benefit obligation 13 (10) - -------------------------------------------------------------
DEFINED CONTRIBUTION PENSION PLAN The company has a defined contribution plan, under which both the company and employees make contributions. Company contributions, which totalled $4 million (1999 - $4 million; 1998 - $3 million), are based on employees' earnings and contributions. 15. COMMITMENTS AND CONTINGENCIES (a) OPERATING COMMITMENTS In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company enters into non-cancellable operating leases for service stations, office space and other property and equipment, as well as transportation service agreements for pipeline capacity and an energy services agreement. Under contracts existing at December 31, 2000, future minimum amounts payable under these leases and agreements are as follows:
- -------------------------------------------------------- Pipeline capacity Operating ($ millions) and energy services* leases - -------------------------------------------------------- 2001 101 43 2002 116 25 2003 115 19 2004 115 16 2005 123 15 Later years 3 159 70 - -------------------------------------------------------- 3 729 188 - -------------------------------------------------------- - --------------------------------------------------------
* Includes annual tolls payable under a transportation service agreement with a major pipeline company to use a portion of its pipeline capacity and tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The agreement commenced in 1999 and extends to 2028. As the initial shipper on the pipeline, Suncor's annual tolls payable under the agreement could be subject to annual adjustments. A major energy company is in the process of building a cogeneration facility at the oil sands site with expected completion during the first quarter of 2001. Under long-term energy agreements, Suncor has a commitment to obtain a portion of the power and all of the steam generated by this facility to meet the energy needs of its oil sands operation. Effective October 1999, this company also commenced managing the operations of Suncor's existing energy services facility. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 73 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (b) CAPITAL EXPENDITURE COMMITMENTS AND CONTINGENCIES At December 31, 2000, the company had outstanding commitments of $193 million for capital expenditures on Project Millennium. (c) CONTINGENCIES The company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated reclamation and environmental remediation costs. These costs are accrued at the company's natural gas and oil sands operations on the unit of production basis. Estimated environmental remediation costs at service stations are also accrued upon completion of site investigations. These costs are reduced by any estimated gains likely to be realized on a sale of these sites. Any changes in these estimates will affect future earnings. Under the company's business interruption insurance coverage, the company would bear the first $70 million of any loss arising from a future insured incident at its oil sands operations. The company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and to be funded mainly from the company's cash provided from operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any one quarter or year. The company believes that any liabilities that might arise pertaining to such matters would not be expected to have a material effect on the company's consolidated financial position. 16. PREFERRED SECURITIES During 1999, the company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of U.S.$163 million of 9.125% preferred securities, the proceeds of which totalled Canadian $507 million after issue costs of $17 million ($10 million after tax). The preferred securities are unsecured junior subordinated debentures, due in 2048 and redeemable at the company's option on or after March 15, 2004. Subject to certain conditions, the company has the right to defer payment of interest on the securities for up to 20 consecutive quarterly periods. Deferred interest and principal amounts are payable in cash, or, at the option of the company, from the proceeds on the sale of equity securities of the company delivered to the trustee of the preferred securities. Accordingly, the preferred securities are classified as share capital in the consolidated balance sheet and the interest distributions thereon, net of income taxes, are classified as dividends. Proceeds from the offerings were used to repay commercial paper borrowings. 17. SHARE CAPITAL (a) AUTHORIZED: COMMON SHARES The company is authorized to issue an unlimited number of common shares without nominal or par value. PREFERRED SHARES The company is authorized to issue an unlimited number of preferred shares without nominal or par value in series. (b) ISSUED: The number of common shares and common share options outstanding, common share prices and per share calculations, for both current and prior periods, reflect a two-for-one split of the company's common shares during 2000.
- ------------------------------------------------------------ Common Shares ($ millions) Number Amount - ------------------------------------------------------------ Balance as at December 31, 1997 219 813 266 513 Issued for cash under stock option plan 594 930 4 Issued under dividend reinvestment plan 25 460 1 - ------------------------------------------------------------ Balance as at December 31, 1998 220 433 656 518 Issued for cash under stock option plan 587 850 6 Issued under dividend reinvestment plan 10 732 -- - ------------------------------------------------------------ Balance as at December 31, 1999 221 032 238 524 Issued for cash under stock option plan 738 176 9 Issued under dividend reinvestment plan 130 165 4 - ------------------------------------------------------------ Balance as at December 31, 2000 221 900 579 537 - ------------------------------------------------------------ - ------------------------------------------------------------
74 SUNCOR ENERGY INC. 2000 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS COMMON SHARE OPTIONS (i) EXECUTIVE STOCK PLAN Under this program, the company has granted common share options to non-employee directors and certain executives of the company and its subsidiaries. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted to non-employee directors are exercisable immediately. Options granted to employees are exercisable as follows: one-third after one year, the second third after two years and the final third after three years of the grant date. No option may be exercisable more than 10 years after the grant date. (ii) EMPLOYEE STOCK OPTION PROGRAM Under this program, the company has granted 1 067 290 share options to certain executives and senior employees. The exercise price for these grants was equal to or greater than the market value of the common shares at the grant date. Options vest and are exercisable on April 1, 2002, one-half at that time and the other half based on achievement of certain performance measurement criteria. The following tables cover common share options granted by the company:
- ----------------------------------------------------------------------------------------- Exercise price per share Weighted (dollars) Number Range Average - ----------------------------------------------------------------------------------------- Outstanding, December 31, 1997 5 196 582 4.75-26.08 14.27 Granted 893 036 24.55-26.38 24.66 Exercised (594 978) 4.75-15.69 7.25 Cancelled (97 402) 10.55-26.08 21.38 - ----------------------------------------------------------------------------------------- Outstanding, December 31, 1998 5 397 238 4.75-26.38 16.64 Granted 1 090 456 20.25-30.18 20.70 Exercised (583 040) 4.75-24.55 9.76 Cancelled (46 668) 15.54-26.08 25.73 - ----------------------------------------------------------------------------------------- Outstanding, December 31, 1999 5 857 986 4.75-30.18 18.01 Granted 950 016 26.08-38.55 31.29 Exercised (737 202) 4.75-24.55 12.57 Cancelled (209 925) 20.25-33.03 26.03 - ----------------------------------------------------------------------------------------- OUTSTANDING, DECEMBER 31, 2000 5 860 875 4.75-38.55 20.55 - ----------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------- Exercisable, December 31 1998 2 266 874 4.75-26.08 10.44 - ----------------------------------------------------------------------------------------- 1999 2 609 816 4.75-26.98 12.89 - ----------------------------------------------------------------------------------------- 2000 3 067 594 4.75-31.98 15.42 - -----------------------------------------------------------------------------------------
AVAILABLE FOR GRANT, DECEMBER 31
- ---------------------------------------------------------------- (number of common shares) 2000 1999 1998 - ---------------------------------------------------------------- 6 336 377 7 076 468 8 120 258 - ----------------------------------------------------------------
The following table is an analysis of outstanding and exercisable common share options as at December 31, 2000:
- ------------------------------------------------------------------------------------------------------------------------- OUTSTANDING EXERCISABLE Weighted Weighted Weighted Average Remaining Average Exercise Average Exercise Exercise Price Number Contractual Life Price Per Share Number Price Per Share - ------------------------------------------------------------------------------------------------------------------------- 4.75-10.44 572 148 3 7.91 572 148 7.91 10.55-15.69 1 595 815 5 13.43 1 595 815 13.43 20.25-24.85 1 695 992 7 22.15 800 230 22.96 26.08-26.98 1 094 290 6 26.11 41 334 26.96 28.12-38.55 902 630 9 31.45 58 067 31.94 - ------------------------------------------------------------------------------------------------------------------------- Total 5 860 875 6 20.55 3 067 594 15.42 - ------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------
SUNCOR ENERGY INC. 2000 ANNUAL REPORT 75 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (iii) FAIR VALUE OF OPTIONS GRANTED The weighted average fair value of common share options granted in 2000 is $7.12 per share (1999 - $7.01 per share; 1998 - $9.05 per share). The fair value of common share options granted is estimated as at the grant date using the Black-Scholes option-pricing model, using the following assumptions:
- --------------------------------------------------------- 2000 1999 1998 - --------------------------------------------------------- Dividend $0.34/ $0.34/ $0.34/ SHARE share share Risk-free interest rate 6.45% 4.89% 5.31% Expected life 7 YEARS 7 years 7 years Expected volatility 37% 32% 32% - ---------------------------------------------------------
18. FINANCIAL INSTRUMENTS (a) BALANCE SHEET FINANCIAL INSTRUMENTS The company's financial instruments recognized in the consolidated balance sheets consist of cash and cash equivalents, accounts receivable, derivative contracts not accounted for as hedges, investment in CPM and SPP, substantially all current liabilities, except for income taxes payable and future income taxes, and long-term borrowings. The estimated fair values of recognized financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The fair values of cash and cash equivalents, accounts receivable and current liabilities approximate their carrying amounts due to the short-term maturity of these instruments. At December 31, 2000, the company had outstanding crude oil and U.S. dollar swap contracts maturing in July 2004, fixing the purchase price of 2 130 000 barrels of crude oil at Cdn$49 million. These derivative contracts, which have not been accounted for as hedges, had a fair value and carrying value of $10 million at December 31, 2000 (1999 -$(2) million; 1998 - $nil). The fair value of the company's investment in the shares of CPM and SPP is not determinable. Information about the terms, conditions and characteristics of this investment is presented in note 2. The following table summarizes estimated fair value information about the company's long-term borrowings at December 31:
- ------------------------------------------------------------------------------------------------------------- 2000 1999 1998 CARRYING FAIR Carrying Fair Carrying Fair ($ millions) AMOUNT VALUE Amount Value Amount Value - ------------------------------------------------------------------------------------------------------------- Long-term borrowings - fixed rate 525 528 525 516 525 548 - variable rate 1 482 1 482 695 695 698 698 - Sunoco joint ventures 3 3 4 4 4 4 - Stuart Oil Shale Project 73 73 82 82 71 71 - capital leases 109 109 -- -- -- -- - -------------------------------------------------------------------------------------------------------------
The fair value of the company's fixed rate long-term borrowings, which are publicly traded, is based on quoted market prices. The fair value of the company's variable rate long-term borrowings, capital leases, proportionate share of the long-term borrowings of its Sunoco joint ventures, and the Stuart Oil Shale Project borrowings approximates the carrying amount. (b) UNRECOGNIZED DERIVATIVE FINANCIAL INSTRUMENTS The company is also a party to certain derivative financial instruments which are not recognized in the consolidated balance sheets, as follows: REVENUE AND MARGIN HEDGES The company enters into crude oil and foreign currency swap and option contracts to protect its future Canadian dollar earnings and cash flows from the potential adverse impact of low petroleum prices and an unfavourable U.S./Canadian dollar exchange rate. These contracts reduce fluctuations in sales revenues by locking in fixed prices, or a range of fixed prices, and exchange rates on the portion of its crude oil sales covered by the contracts. The company also enters into crude oil and heating oil swap contracts to lock in fixed margins on the portion of refined product sales covered by the contracts. While these contracts reduce the risk of exposure to adverse changes in commodity prices and exchange rates, they also reduce the potential benefit of favourable changes in commodity prices and exchange rates. The contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company's sales revenues or crude oil purchase costs. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions. 76 SUNCOR ENERGY INC. 2000 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Contracts outstanding at December 31 were as follows: CONTRACT AMOUNTS
- ---------------------------------------------------------------------------------------------------------------------------- Average price* Revenue hedged ($ millions except for average price) Quantity Cdn$ Cdn$ Hedge Period - ---------------------------------------------------------------------------------------------------------------------------- REVENUE HEDGES AS AT DECEMBER 31, 2000 Crude oil swaps and options* 42 710 BBL/DAY 28 436 2001 4 790 BBL/DAY 20 (a) 35 (a) 2001 10 000 BBL/DAY 26-32 (a) 95-117 (a) 2001 41 000 BBL/DAY 28 426 2002 7 000 BBL/DAY 22-26 (a) 56-66 (a) 2002 - ---------------------------------------------------------------------------------------------------------------------------- AS AT DECEMBER 31, 1999 Crude oil swaps* 52 655 bbl/day 26 503 2000 9 845 bbl/day 19 (a) 67 (a) 2000 35 000 bbl/day 26 327 2001 4 000 bbl/day 26 38 2002 U.S. dollar swaps U.S.$81 1.41 114 2001 U.S.$289 1.41 408 2002 - ---------------------------------------------------------------------------------------------------------------------------- AS AT DECEMBER 31, 1998 Crude oil swaps* 23 700 bbl/day 28 242 1999 6 000 bbl/day 28 61 2000 U.S. dollar swaps U.S.$115 1.39 160 1999 U.S.$274 1.39 381 2000 U.S.$312 1.41 440 2001 U.S.$314 1.42 446 2002 - ----------------------------------------------------------------------------------------------------------------------------
* Average price for crude oil swaps is WTI per barrel at Cushing, Oklahoma. (a) Average price and revenue hedged is in U.S. dollars
- ---------------------------------------------------------------------------------------------------------------------------- Average margin Margin hedged ($ millions except for average price) Quantity U.S.$/bbl U.S.$ Hedge period - ---------------------------------------------------------------------------------------------------------------------------- MARGIN HEDGES Refined product sale and crude purchase swaps 6 575 bbl/day 5 12 2001 - ----------------------------------------------------------------------------------------------------------------------------
INTEREST RATE HEDGES The company enters into interest rate and cross-currency interest rate swap contracts as part of its risk management strategy to minimize exposure to interest rate fluctuations. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the company and a financial institution. The cross-currency swap contracts involve an exchange of Canadian dollar interest payments and U.S. dollar interest payments between the company and a financial institution, and an exchange of Canadian and U.S. dollar principal amounts at the maturity date of the underlying borrowing to which the swaps relate. The swap transactions are completely independent from and have no direct effect on the relationship between the company and its lenders. The differentials on the exchange of periodic interest payments are recognized in the accounts as an adjustment to interest expense. The notional amounts of interest rate and cross-currency interest rate swap contracts outstanding at December 31, 2000 are detailed in note 11, Long-Term Borrowings. FAIR VALUE OF UNRECOGNIZED DERIVATIVE FINANCIAL INSTRUMENTS The fair value of these hedging derivative financial instruments is the estimated amount, based on brokers' quotes, that the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:
- -------------------------------------------------------------- ($ millions) 2000 1999 1998 - -------------------------------------------------------------- Revenue hedge swaps and options (247) (136) 77 Margin hedge swaps (11) -- -- U.S. dollar swaps -- (1) (108) Interest rate and cross- currency interest rate swaps 5 -- 10 - -------------------------------------------------------------- (253) (137) (21) - -------------------------------------------------------------- - --------------------------------------------------------------
COUNTERPARTY CREDIT RISK The company may be exposed to certain losses in the event that counterparties to the derivative financial instruments are unable to meet the terms of the contracts. The company's exposure is generally limited to those counterparties holding derivative contracts with positive fair values at the reporting date. The company minimizes this risk by entering into agreements only with highly rated financial institutions, and through regular management review of potential exposure to, and credit ratings of, such financial institutions. At December 31, 2000, the company had exposure to credit risk with counterparties as follows:
- ------------------------------------------- ($ millions) 2000 - ------------------------------------------- Derivative contracts not accounted for as hedges 8 Unrecognized derivative contracts -- - ------------------------------------------- 8 - ------------------------------------------- - -------------------------------------------
SUNCOR ENERGY INC. 2000 ANNUAL REPORT 77 EX-3 4 a2042188zex-3.txt EXHIBIT 3 EXHIBIT 3 MANAGEMENT'S DISCUSSION AND ANALYSIS HEDGING Companies use derivatives to hedge or counteract possible fluctuations in the price of commodities or interest rates. This permits mitigation of price or interest rate risk due to market fluctuations. OVERVIEW*** Suncor Energy Inc. is a Canadian company comprised of three operating businesses: an oil sands operation (Oil Sands); a natural gas business (Natural Gas - NG, formerly the Exploration and Production business); and a refining and marketing operation (Sunoco). Suncor markets its crude oil production, diesel fuel and byproducts through its wholly owned subsidiary Suncor Energy Marketing Inc. Suncor's corporate centre is located in Calgary, Alberta, Canada. Suncor is currently commissioning an oil shale demonstration project known as the Stuart Oil Shale Project. 2000 EARNINGS INCREASED 103% Net earnings for the year increased to $377 million, from $186 million in 1999. Cash flow from operations was $958 million, compared with $591 million in 1999. During the year, several transactions impacted net earnings and cash flow from operations that were not viewed as ongoing operational earnings and cash flow. These transactions included Suncor's write-down of the carrying value of the Stuart Oil Shale Project, restructuring costs and divestment gains in NG and Project Millennium start-up costs. Refer to Notes 2 and 3 in Suncor's Consolidated Financial Statements for further information. Operational earnings in 2000 increased to $427 million from $167 million in 1999. Operational cash flow from operations was over $1 billion, representing the eighth consecutive year of cash flow growth. Operational cash flow in 1999 was $591 million. The non-operational transactions are explained in the Notes to the Consolidated Financial Statements. See the tables below for the components of net earnings and cash flow from operations.
NET EARNINGS COMPONENTS - ---------------------------------------------------------------------------------------------- ($ millions after income taxes) 2000 1999 1998 - ---------------------------------------------------------------------------------------------- Operational earnings 427 167 175 NATURAL GAS Asset divestments 69 19 3 Restructuring (30) -- -- STUART OIL SHALE PROJECT Partial asset write-down (80) -- -- OIL SANDS Start-up expenses - Project Millennium (9) -- -- - ---------------------------------------------------------------------------------------------- Net earnings 377 186 178 - ---------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS COMPONENTS - ---------------------------------------------------------------------------------------------- ($ millions) 2000 1999 1998 - ---------------------------------------------------------------------------------------------- Operational cash flow 1,009 591 580 NATURAL GAS Restructuring costs (9) -- -- OIL SANDS Start-up expenses & overburden removal - Project Millennium (42) -- -- - ---------------------------------------------------------------------------------------------- Cash flow from operations 958 591 580 - ---------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------
Quarterly Data: For information related to quarterly sales, net income and net income per share for the years 2000 and 1999 refer to page 78 of the 2000 annual report and the section "Financial Data". 28 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS The $260 million increase in consolidated operational earnings in 2000 compared to 1999 resulted primarily from higher commodity prices and record Oil Sands sales volumes. Other factors that increased earnings include improved refining margins and volumes, reduced income tax rates and higher Australian/Canadian foreign exchange rate gains. These positive factors were partially offset by higher HEDGING losses and operating expenses, lower natural gas volumes, Stuart Oil Shale Project costs and reduced retail gasoline margins. Operational cash flow in 2000 increased over 1999 primarily due to the same factors that increased earnings.
CONSOLIDATED FINANCIAL RESULTS - --------------------------------------------------------------------------------------------- ($ millions) 2000 1999 1998 - --------------------------------------------------------------------------------------------- Net earnings 377 186 178 Cash flow provided from operations 958 591 580 Investing activities 1,607 1,290 937 Dividends - common shares 75 75 75 - preferred securities 47 37 0 Long-term borrowings 2,192 1,306 1,298 - ---------------------------------------------------------------------------------------------
RELATIVE SEGMENT CONTRIBUTION - --------------------------------------------------------------------------------------------- (before the impact of corporate and elimination adjustments, expressed as %) 2000 1999 1998 - --------------------------------------------------------------------------------------------- NET EARNINGS Oil Sands 64 71 70 Natural Gas 20 17 12 Sunoco 16 12 18 CASH FLOW PROVIDED FROM OPERATIONS Oil Sands 62 60 53 Natural Gas 22 25 28 Sunoco 16 15 19 CAPITAL EMPLOYED Oil Sands 64 55 49 Natural Gas 19 29 31 Sunoco 17 16 20 - ---------------------------------------------------------------------------------------------
INDUSTRY INDICATORS - ----------------------------------------------------------------------------------------------------- (average of the year unless otherwise noted) 2000 1999 1998 - ----------------------------------------------------------------------------------------------------- West Texas Intermediate (WTI) crude oil U.S.$/barrel at Cushing 30.25 19.30 14.40 Canadian 0.3% par crude Cdn$/barrel at Edmonton 44.56 27.50 20.45 Light/heavy crude oil differential U.S.$/barrel - WTI @ Cushing/Bow River @ Hardisty 6.84 3.42 4.54 Natural gas U.S.$/thousand cubic feet at Henry Hub 3.90 2.27 2.14 Natural gas (Alberta spot) Cdn$/thousand cubic feet at Empress 5.08 3.00 2.25 Natural gas exports to the U.S. trillions of cubic feet 3.5* 3.4 3.1 New York Harbour 3-2-1 crack U.S.$/barrel** 5.45 2.47 2.85 Refined product demand (Ontario) percentage change over prior year 2.0* 3.8 2.6 Exchange rate: Cdn$:U.S.$ 0.67 0.67 0.67 Exchange rate: Cdn$:Australian$ 1.16 1.04 1.07 - -----------------------------------------------------------------------------------------------------
* Estimate ** New York Harbour 3-2-1 crack is an industry indicator measuring the margin on a barrel of oil for gasoline and distillate. It is calculated by taking 2 times the New York Harbour gasoline margin plus 1 times the New York Harbour distillate margin and dividing by 3. *** The tables and charts in this document form an integral part of Management's Discussion and Analysis and should be referred to when reading the narrative. References to Suncor or the Company include Suncor Energy Inc. and its subsidiaries and investment in joint ventures, unless otherwise stated. Management's Discussion and Analysis contains certain forward-looking statements that are based on Suncor's current expectations, estimates, projections and assumptions and were made by the Company in light of its experience and its perception of historical trends. All statements that address expectations or projections about the future, including statements about Suncor's strategy for growth, 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 exchange rates; Suncor's ability to respond to changing markets; the ability of Suncor to receive timely regulatory approvals; the successful implementation of its growth projects, including Project Millennium; the integrity and reliability of Suncor's capital assets; the cumulative impact of the resource development projects; Suncor's ability to comply with current and future environmental laws; the accuracy of Suncor's production estimates and production levels and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venturers; competitive actions of other companies, including increased competition from other oil and gas companies or from companies which provide alternative sources of energy; the uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; actions by governmental authorities including increasing taxes, changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor;and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. Many of these risk factors are discussed in further detail throughout this Management's Discussion and Analysis and in the Company's Annual Information Form on file with the Alberta Securities Commission and certain other securities regulatory authorities. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the Company. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 29 MANAGEMENT'S DISCUSSION AND ANALYSIS Oil Sands BITUMEN A thick, sticky form of crude oil. At room temperature, bitumen is like cold molasses. It must be heated or diluted before it will flow into a well or through a pipeline. - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ OVERVIEW Suncor has more than 30 years' experience in mining and upgrading oil sands to produce crude oil on a commercial basis, more experience than any other company in the world. Suncor uses the following proven technology and processes to produce oil from its leases in the Athabasca oil sands, near Fort McMurray, Alberta: - - Giant trucks and shovels mine the bitumen-laden oil sands. - - The BITUMEN is separated from the oil sands in the extraction process. It can then be sold directly to customers or upgraded into a variety of refinery feedstocks, including sweet and sour crude oil products and diesel fuel. The resulting products can be blended to customer specifications and sent by pipeline to markets in Canada and the United States. The Oil Sands business also has an on-site energy plant, operated and partially owned by TransAlta Energy Corporation (TransAlta). The energy plant generates steam and electricity using natural gas and petroleum coke, a byproduct of the upgrading process. In 1999, Suncor received government approval to proceed with Project Millennium, Suncor's oil sands expansion project. By the end of 2000, all engineering and 70% of the total project was completed. Commissioning is expected to begin in the second half of 2001, with full production capacity of 225,000 barrels per day targeted by 2002. Total Oil Sands production in 2000 averaged 113,900 barrels per day. RESULTS OF OPERATIONS AND INVESTING ACTIVITIES 2000 VS. 1999 OIL SANDS - SUMMARY OF RESULTS
- ----------------------------------------------------------------- ($ millions unless otherwise noted) 2000 1999 1998 - ----------------------------------------------------------------- Revenue 1 336 889 768 Production (thousands of barrels per day) 113.9 105.6 93.6 Average sales price ($ per barrel) 31.67 23.84 22.18 Earnings 315 167 145 Cash provided from operations 655 405 320 Total assets 5 079 3 178 2 081 Investing activities 1 715 1 085 514 ROCE (%) 22.8 12.9 16.3 - -----------------------------------------------------------------
EARNINGS ANALYSIS RECORD PRODUCTION AND INCREASED SELLING PRICES CONTRIBUTE TO INCREASED EARNINGS Oil Sands earned $315 million in 2000 compared with $167 million in 1999, representing an 88% increase in earnings. Higher earnings were mainly attributable to record Oil Sands production volumes and an increase in crude oil prices. The benchmark WTI crude price increased by 57% over 1999 levels. These favourable factors were partially offset by higher hedging losses, increases in cash and non-cash expenses and lower sour crude oil prices due to widening of the light/heavy crude oil differential. Sour crude oil sales represented about 35% of sales volumes in 2000. Start-up expenses on Project Millennium, totalling $9 million (after tax) also reduced earnings in 2000. The combined impact of pricing factors increased earnings in 2000 by $212 million from 1999 levels. 30 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS [GRAPHIC OF NORTH AMERICA HIGHLIGHTING ALBERTA CITIES] [PHOTOGRAPGH OF MIKE ASHAR] The year 2001 is a turning point for Oil Sands. We look forward to steady base plant operations and bringing Millennium operations up to a production capacity of 225,000 barrels per day by 2002. MIKE ASHAR Executive Vice President, Oil Sands - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- OIL SANDS PRODUCTION INCREASES 8%, SALES VOLUMES UP 13% Oil Sands increased production in 2000 for the eighth consecutive year to an average of 113,900 barrels per day, from 105,600 barrels per day in 1999. This was due to increased mining from the Steepbank Mine and enhancements to base plant operations. Three weeks of prolonged cold weather in December impacted fourth-quarter production which averaged 110,000 barrels per day. The 5C9 fractionating tower is scheduled to be shut down for maintenance before mid-2001 for approximately eight days, resulting in no oil production during this period. Suncor's 130,000 barrels per day average production target for 2001 includes the estimated impact of this maintenance work and its impact on production. Higher production increased sales volumes to a record 115,600 barrels per day in 2000, up from 102,200 barrels per day in 1999. This volume increase resulted in a year-over-year earnings improvement of $80 million. As sales exceeded production in 2000, inventory levels in 2000 declined.
BRIDGE ANALYSIS OF EARNINGS (CDN$ MILLIONS) - -------------------------------- 1999 - -------------------------------- Total 167 - -------------------------------- - -------------------------------- 2000 Volume 80 Oil Price 212 Royalties (29) Cash Expenses (69) Non-cash Expenses (37) Earnings Before the Following 324 Project Millennium Start-up (9) - -------------------------------- Total 315 - -------------------------------- - --------------------------------
Record sales volume and increased crude price, partially offset by higher expenses and increased hedging losses, resulted in an 88% earnings improvement. ROYALTIES Crown royalties payable by Suncor to the Government of Alberta increased 81% from $48 million in 1999 to $87 million in 2000 as a result of higher sales volumes and prices. The higher Crown royalties were partly offset by a $8 million decrease in royalties paid to Union Pacific (Union Resources Inc. now owned by Anadarko Petroleum Corporation) because Suncor mined fewer barrels in 2000 from the lease on which Union has a royalty interest. Mining is currently expected to be completed on the Union lease in the 2001/2002 time period. The combined impact of the above factors was a net increase in total royalties expensed, which reduced earnings by $29 million after tax. Crown royalties in effect for Suncor's existing Oil Sands operations require payments to the Government of Alberta of 25% of revenues less allowable costs (including capital expenditures), subject to a minimum payment of 5% of gross revenues. In 2000, Suncor made Crown royalty payments based on the 5% minimum royalty. Suncor
BRIDGE ANALYSIS OF NET CASH DEFICIENCY (CDN$ MILLIONS) - ------------------------------------------- 1999 - ------------------------------------------- Total (597) - ------------------------------------------- - ------------------------------------------- 2000 Operations 292 Working Capital (252) Investing Activities (630) Cash Flow Before the Following (1 187) Project Millenium (42) - ------------------------------------------- Total (1 229) - ------------------------------------------- - -------------------------------------------
Capital spending on Project Millenium reached its peak in 2000, which is reflected in increased investing activities and working capital increase due to increased inventory value and lower payables at the end of the year. This was only partly offset by impoved cash flow operations. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 31 MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS OVERBURDEN MAINTENANCE SHUTDOWN Material lying on top of the oil sands Preventative maintenance activities that must be removed before mining. that involve shutting down major Consists of muskeg, glacial deposits parts of, or an entire facility. and sand. 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. This is based on assumptions relating to future oil prices, production levels, operating costs and capital expenditures. EXPENSES INCREASED Expenses in 2000 increased by 35% over 1999 levels. The increase in expenses reduced Oil Sands earnings by approximately $115 million after tax. Cash expenses increased, resulting in a $69 million reduction in earnings. This was largely a result of increased sales levels and higher energy costs. Ore quality variability encountered during the year also contributed to the increase in costs, as operations were modified to minimize the impact. Ore quality can be expected to vary from time to time as different parts of an ore body are mined. Suncor will continue to assess ore quality for its impact on operations and costs. In addition, there were higher maintenance and operating costs relating to concurrently mining leases on both sides of the Athabasca River. Mining operations on the original leases west of the Athabasca River are expected to be shut down in 2001/2002, thereby eliminating these inefficiencies. In addition to factors related to the current operations, cash expenses increased due to Project Millennium start-up costs of $9 million after tax.
- ---------------------------------------------------------------------------------- CASH AND TOTAL OPERATING COSTS (CDN$ PER BARREL) 1996 1997 1998 1999 2000 - ---------------------------------------------------------------------------------- Cash Operating Cost 12.40 13.25 11.75 11.70 12.55 Start-up Expenditures Project Millennium -- -- -- -- 1.00 Total Cash Cost 12.40 13.25 11.75 11.70 13.55 Non-cash Cost 2.40 2.55 2.25 3.35 3.70 - ---------------------------------------------------------------------------------- Total 14.80 15.80 14.00 15.05 17.25 - ---------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------
Cash operating costs increased, reflecting higher operating and maintenance costs. Non-cash costs are up as a result of the higher asset base associated with the increased production and the acceleration of depreciation costs associated with the original leases. Non-cash charges (depreciation, depletion and amortization) increased by $55 million due to: - - mine plan changes that increased OVERBURDEN amortization charges by $11 million, - - increased overburden amortization charges of $13 million due to the increase in production volumes, - - a higher depreciation expense of $18 million due to capital additions that increased production, - - higher depreciation of $11 million associated with the closing of the original leases earlier than anticipated, due to a 20 million barrel reduction in reserves recognized in 1999, and - - higher turnaround amortization charges of $2 million as a result of planned MAINTENANCE SHUTDOWN work in 1999. The $55 million increase in non-cash charges reduced earnings by $37 million. PER BARREL OPERATING COSTS INCREASED Cash operating costs increased to $13.55 per barrel in 2000, including $1 per barrel related to Project Millennium start-up and overburden expenditures. This compares to $11.70 in 1999. Excluding the Project Millennium component, the increase of $0.85 per barrel is due to costs associated with higher energy expenses and variable ore quality. The negative impact of these cost factors was partially offset by higher volumes. Total operating costs per barrel in 2000 were $17.25 compared with $15.05 per barrel in 1999. Higher total operating costs were due to the same factors that affected cash operating costs, as well as increased amortization and depreciation expenses. 32 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS WORKING CAPITAL * This section contains forward- The excess of current assets (excluding looking information. Also refer cash) over current liabilities. The excess to the Overview *** on page 29 measures the ability of a business to of this report. finance current operations; for example, whether debt will need to be incurred to fund growth activities.
- ---------------------------------------------------------------------------------- OPERATING MARGINS (CDN$ PER BARREL) 1996 1997 1998 1999 2000 - ---------------------------------------------------------------------------------- Selling Price 26.84 26.36 22.18 23.84 31.67 Cash Margin 11.75 12.05 9.25 10.75 15.80-16.80 - ----------------------------------------------------------------------------------
The increase in margin in 2000 reflects a 57% increase in crude oil price realizations and higher cash operating costs. The margin improvement was reduced by losses associated with Suncor's hedging program that reduced the margin by $7.55 per barrel. The variation in cash margin shows the margin with and without the effect of start-up expenses for Project Millennium incurred in 2000 only. Without start-up expenses, the cash margin was $16.80, and with those expenses it was $15.80. SELLING PRICE - The average price from the sale of crude oil, including the impact of hedging activities. CASH MARGIN - The difference between the selling price received for products sold and cash operating cost per barrel plus royalties per barrel. CASH MARGIN INCREASED 47% TO $15.80 PER BARREL IN 2000 Oil Sands' cash operating margin was $15.80 in 2000 compared with $10.75 per barrel in 1999. The following factors influenced cash margins during the year: - - higher crude prices (before hedging) had a favourable impact of $15.40 per barrel, - - hedging losses had an unfavourable net impact of $7.55 per barrel, - - cash operating costs had an unfavourable impact of $0.85 per barrel, - - Millennium start-up and overburden removal costs had an unfavourable impact of $1 per barrel, and - - higher royalties had an unfavourable impact of approximately $0.95 per barrel. NET CASH DEFICI ENCY ANALYSIS Cash flow provided from operations was $655 million in 2000 compared with $405 million in 1999. An increase of $292 million was primarily due to improved earnings. These earnings were partially offset by Project Millennium's $42 million start-up and overburden removal costs. Oil Sands had an increase in WORKING CAPITAL of $252 million relative to 1999. The increase was primarily due to increased inventory value and lower accounts payable and accruals that reflected lower Project Millennium activity at the end of 2000. Payables were lower because major components of the project were received and paid for by the end of 2000. These factors were partly offset by lower trade receivables in 2000 compared with 1999, primarily due to the sale of $11 million of receivables. Investing activities at Oil Sands increased by $630 million to $1.7 billion in 2000 from $1.1 billion in 1999. The increase was primarily due to $1.6 billion in spending on Project Millennium (including capitalized interest of $90 million). These combined factors resulted in an increase in net cash deficiency from $597 million in 1999 to $1.229 billion in 2000. OUTLOOK* PROJECT MILLENNIUM Suncor's $2.8 billion Project Millennium is designed to further increase Oil Sands production capacity, improve operational reliability and reduce operating costs. Project Millennium is designed to increase production capacity to 225,000 barrels per day by 2002. Suncor's production goal for 2002 is estimated at an average of 210,000 barrels per day due to planned maintenance shutdown work that year. In 2000, Suncor announced a long-term sales agreement with Consumers' Co-operative Refineries Limited (CCRL). Suncor expects to begin supplying CCRL with 20,000 barrels per day of sour crude oil production from its Millennium expansion facilities by late 2002. Project Millennium calls for an expanded mine, additional mining equipment, increased energy services support and twinning of the bitumen extraction and upgrading processes. The twinning of these facilities is expected to allow some level of cash flow to continue during scheduled plant maintenance work by allowing a portion of the operations to continue production while maintenance work elsewhere at the plant is carried out. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 33 MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS PROVEN AND PROBABLE RESERVES Annual estimates are made by Suncor of recoverable bitumen reserves associated with Company surface mineable oil sands leases. The estimates are allocated between proven and probable categories based upon criteria agreed to by management and reviewed by independent consultants. The proven reserves are considered to be conservative estimates in which there is a very high degree of confidence. Probable reserves incorporate portions of the mine that have a lower drilling density and are expected to be recovered under current approvals for a period in excess of 30 years, if further expansions do not occur. There is at least a 50 per cent chance that the proven plus probable reserve estimates will be exceeded. The bitumen estimates are converted to synthetic crude estimates on the basis of yields currently being obtained. Assuming estimated economies of scale and reliability improvements are achieved, management believes Oil Sands could reduce its cash operating costs from its 2000 level of $12.55 per barrel (excluding Project Millennium costs) to the $8.50 to $9.50 per barrel range in 2002. These estimates were developed in 1998 based on an assumed natural gas price of approximately $2.30 per thousand cubic feet (mcf), and other assumptions relating to key variables, including the targeted level of oil production. Accordingly, these estimates are subject to change and their achievement cannot be assured. For example, these estimates do not include the impact of maintenance activities now scheduled for 2002, or changes in natural gas prices which potentially impact cash operating costs by approximately $0.50 per barrel for every $1 per mcf variance from the $2.30 per mcf assumption. Oil Sands has PROVEN AND PROBABLE RESERVES of 422 million barrels and 2.034 billion barrels respectively on the leases it currently has regulatory approval to mine. Management believes these reserves are sufficient to support Project Millennium's planned production target of 225,000 barrels per day for a period in excess of 30 years. These reserve totals do not include the Firebag in-situ heavy oil leases described below or other oil sands leases that Suncor owns because regulatory approval to proceed with recovery from these leases must be obtained before reserves are recognized. Additional reserves would only be recognized as Suncor completes further drilling and analysis on these leases and receives approval to proceed with the Firebag Project from the Board of Directors and regulatory authorities. REVISED COST ESTIMATE FOR PROJECT MILLENNIUM In October 2000, a thorough analysis was completed on Suncor's Project Millennium that resulted in a revised capital cost estimate of $2.8 billion. In the first quarter of 2000, Suncor had estimated project costs could be as high as $2.45 billion, up from the original estimate of $2 billion. The capital cost estimate increased to $2.8 billion as a result of higher labour, fabrication and material costs and a $150 million change in the project's scope. The additional capital costs are expected to be financed through internally generated cash flow and additional borrowing. Management believes that despite the added costs, Project Millennium is able to yield economic returns in excess of its 11% cost of capital if the benchmark WTI price averages U.S.$15 per barrel (and escalated at 2% per year). At year-end, the project was 70% complete with engineering finished and all significant materials purchased. The focus for 2001 is to complete construction and begin commissioning in the second half of 2001. Full production capacity of 225,000 barrels per day is targeted by 2002. RISK FACTORS RELATED TO PROJECT MILLENNIUM At this stage, 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 and integration of the new facilities with the existing asset base could cause delays in achieving the targeted production capacity of 225,000 barrels per day by 2002. BEYOND PROJECT MILLENNIUM 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 Firebag IN-SITU Oil Sands Project and further Oil Sands plant expansion. The commercial-scale Firebag Project is targeted to add approximately 35,000 barrels of bitumen per day in 2005. To process the additional bitumen, Suncor plans to add a vacuum tower complex to increase Oil Sands upgrading capacity to 260,000 barrels of oil per day in 2005. These plans are subject to Board of Directors and provincial regulatory approvals. Suncor submitted regulatory approval applications for the Firebag Project in 2000, and expects a regulatory decision in 2001. Subject to these approvals, construction of facilities for the first stage is scheduled to begin in the second half of 2001, with start-up in late 2003 and commissioning in 2004-2005. 34 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - OIL SANDS IN-SITU In-situ or "in place" refers to methods of extracting heavy oil from deep deposits of oil sands with minimal disturbance of the ground cover. CO-GENERATION The simultaneous production of electricity and steam from one energy source, e.g. natural gas. The Company's long-term vision is to ultimately 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, through a combination of oil sands mining and in-situ development, to approximately 400,000 to 450,000 barrels of oil a day in 2008. Any such plans toward realizing this long-term vision would be subject to Board of Directors and regulatory approvals. LEVERAGING ALLIANCES TO SUPPORT OIL SANDS EXPANSION In March 1999, Suncor signed an agreement with TransAlta to build, own and operate a CO-GENERATION facility at Oil Sands with a portion of its output to help meet Suncor's long-term electricity and steam needs. This facility commenced operations early in 2001. TransAlta also assumed responsibility for operating Suncor's existing utility plant at Oil Sands on October 1, 1999. In Spring 2000, Suncor and Williams Energy Canada, Inc. (Williams) began construction of the Hydrocarbon Liquids Conservation Project. This project is designed to extract and separate natural gas liquids and olefins from "off-gas," a byproduct of the Oil Sands upgrading process. The recovered liquids and olefins will be transported in batches via Suncor's Oil Sands pipeline to Williams' Redwater, Alberta facility for further processing. Management believes the project will help reduce sulphur dioxide emissions at Oil Sands and provide additional revenue for Suncor. RISK/SUCCESS FACTORS AFFECTING OVERALL PERFORMANCE The profitability of Suncor's Oil Sands business is influenced by world crude oil price levels that are difficult to predict and impossible to control. In addition, the light/heavy oil differential can have an impact on earnings. In 2000, this differential widened resulting in reduced earnings. Management believes the differential will trend toward more historical ranges in 2001 if the demand for heavy oil increases as anticipated. Unplanned production or operational outages and slowdowns, particularly those that are weather-related, can be expected from time to time. Suncor's relationship with its employees and provincial building trade unions is important to its future success because work disruptions have the potential to adversely affect Oil Sands operations and growth projects. Suncor's collective agreement with the Communications, Energy and Paperworkers Union Local 707 expires on May 1, 2001. Management believes its positive working relationship will continue and that a new agreement should be reached without work interruptions. Labour agreements with other building trades expire on April 30, 2001. While Suncor is not a direct party to these agreements, they impact the Company 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 and progress on the project will not be impeded. Also refer to "Environmental Regulation, Risk/Success Factors" in the Corporate section of this MD&A. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 35 MANAGEMENT'S DISCUSSION AND ANALYSIS NATURAL GAS - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- OVERVIEW Suncor's Natural Gas (NG) business, based in Calgary, Alberta, explores for, develops, produces and markets natural gas and natural gas liquids from the Western Canada Sedimentary Basin. In addition to conventional production, NG is acquiring land to explore for, develop and produce coal bed methane, and is developing new service offerings to the resource sector. To date, the coal bed methane business and service offerings have not engaged in any material operations and have not earned any revenues. STRATEGIC FOCUS In the first quarter of 2000, a study was initiated to examine ways to improve financial and operating performance and to identify profitable growth areas for Exploration and Production (E&P), the Company's conventional oil and natural gas business. The information from the study was used to create the E&P long-term strategy that repositioned the business with a focus on natural gas and natural gas liquids, and renamed it Natural Gas (NG). NG has a goal to achieve at least 10% return on capital within five years (at mid-cycle commodity prices in the U.S. $3 - U.S. $3.50/mcf price range). The strategy for improving profitability is built on a much sharper focus on natural gas, building more competitive operating areas, improving base business efficiency and creating new services for the resource sector. Specific strategies implemented as a result of this repositioning have had a significant impact on financial and operating results for 2000. A portfolio optimization program was initiated in 1997 to improve the quality of the conventional asset base and net cash position through the sale of non-strategic properties. Divestments associated with the optimization were accelerated in 2000 to sharpen NG's focus on natural gas. Divestment of non-core assets contributed $314 million in 2000 to net cash surplus, an increase of $224 million over 1999 contributions and $64 million over the Company's target of $250 million. Property dispositions represented production of 10,000 barrels of oil equivalent per day (BOE/d) (100 million cubic feet equivalent per day (mmcfe/d)) at the time of the sale, including 7,000 BOE/d of crude oil and bitumen. As a result, NG's annual average production for 2000 declined to 27,200 BOE/d or 272 mmcfe/d. Production came principally from three key asset areas in western Alberta and northeastern British Columbia. Natural gas and natural gas liquids accounted for approximately 92% of production volume at the end of 2000. RESULTS OF OPERATIONS/ INVESTING/EXPLORATION ACTIVITIES 2000 VS. 1999
NATURAL GAS - SUMMARY OF RESULTS - ------------------------------------------------------------------- ($ millions unless otherwise noted) 2000 1999 1998 - ------------------------------------------------------------------- Revenue 428 306 290 Conventional production (thousands BOE/d) 27.2 36.0 41.0 Average sales price (including impact of hedging) Natural gas ($/thousand cubic feet) 4.72 2.44 1.95 Crude oil ($/barrel) 29.50 20.94 20.14 Operational earnings 59 22 21 Net earnings 98 41 24 Cash flow provided from operations 238 172 167 Total assets 762 962 943 Capital and exploration expenditures 127 200 242 Return on capital employed (%) 17.2 5.5 3.3 - -------------------------------------------------------------------
36 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - NATURAL GAS [GRAPHIC OF NORTH AMERICA HIGHLIGHTING ALBERTA CITIES] We have made significant progress in our strategy to sharpen our focus on natural gas and reduce our costs. We'll continue to look for profitable opportunities for growth. [PHOTOGRAPH OF DAVE BYLER] DAVE BYLER Executive Vice President, Natural Gas - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- EARNINGS ANALYSIS EARNINGS INCREASED BY 139% ON ASSET DIVESTMENT GAINS AND STRONGER COMMODITY PRICES Net earnings were up more than 139% over 1999 levels to $98 million, primarily due to divestment gains and stronger natural gas prices. Operational earnings, which exclude the impact of asset divestments and restructuring charges, increased by $37 million to $59 million in 2000 from $22 million in 1999. This was primarily due to higher commodity prices and was partially offset by lower production volumes and higher exploration and royalty expenses. Cash flow from operations rose to $238 million from $172 million in 1999, again mainly due to higher natural gas prices. NATURAL GAS PRICES INCREASED 93% In 2000, NG's price averaged $4.72 per thousand cubic feet (mcf) of natural gas, compared with $2.44 per mcf in 1999.
- -------------------------------- BRIDGE ANALYSIS OF EARNINGS (CDN$ MILLIONS) - -------------------------------- 1999 - -------------------------------- Total 41 - -------------------------------- - -------------------------------- 2000 Price 94 Volume (35) Royalties (28) Expenses 6 Earnings Before the Following 78 Divestment Gains 50 Restructuring Costs (30) - -------------------------------- Total 98 - -------------------------------- - --------------------------------
Higher commodity prices and divestment gains more than offset the decline in production from divestments and restructuring costs. Increased prices in 2000 were a result of increased demand and improved access to U.S. markets coupled with a relatively flat natural gas supply in North America. While crude oil made up only 15% of NG's production in 2000, crude prices were also higher, averaging $29.50 per barrel (after hedging losses), compared to $20.94 per barrel (after hedging losses) in 1999. The combined impact of the above pricing factors increased earnings by $94 million. PRODUCTION DECLINED 24% FROM 1999 LEVELS NG's natural gas and liquids volumes declined to an average of 27,200 BOE/d (272 mmcfe/d) in 2000, from an average of 36,000 BOE/d in 1999. The main reasons for production declines were asset divestments associated with portfolio optimization during 1999 and 2000 (representing annual production of 1,500 and 5,500 BOE/d respectively) and natural reservoir declines. The decrease in volumes reduced earnings by $35 million compared to 1999.
- -------------------------------- BRIDGE ANALYSIS OF NET CASH SURPLUS (CDN$ MILLIONS) - -------------------------------- 1999 - -------------------------------- Total 89 - -------------------------------- - -------------------------------- 2000 - -------------------------------- Operations 66 Capital and Exploration Expenditures 72 Divestment Proceeds 224 - -------------------------------- Total 451 - -------------------------------- - --------------------------------
Year-over-year improvement of $362 million in NG's net cash flow was the result of lower capital and exploration spending, proceeds from property dispositions and higher operating cash flow due to higher commodity prices. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 37 MANAGEMENT'S DISCUSSION AND ANALYSIS - NATURAL GAS * This section contains forward- RESTRUCTURING CHARGES looking information. Also refer to See note 3 to the Consolidated the Overview *** on page 29 of Financial Statements. this report. ROYALTIES INCREASED WITH HIGHER COMMODITY PRICES Royalties increased to $11 per BOE ($1.10 per mcfe) in 2000, from $4.26 per BOE ($0.43 per mcfe) in 1999 due mainly to the increase in commodity prices. The increase in royalties reduced earnings by $28 million. TOTAL EXPENSES REDUCED FROM 1999 LEVELS Total expenses, excluding royalties and RESTRUCTURING CHARGES, were reduced by $12 million in 2000 from 1999 levels. This reflected divestment activity in 1999 and 2000. Lower non-cash expenses and lower operating expenses were partially offset by higher exploration expenses. Non-cash expenses (depreciation, depletion and amortization) decreased by $9 million as a result of asset divestments. Operating expenses were reduced by $14 million compared to 1999 levels, due to asset divestments and improved base business efficiency. Exploration expenses were up $13 million in 2000 over 1999 due primarily to an increase in dry hole costs. Combined, the above factors increased earnings by $6 million year-over-year. ASSET DIVESTMENT GAINS Completion of NG's portfolio optimization program in 2000 yielded after-tax gains of $69 million, $50 million higher than the gains reported in 1999. RESTRUCTURING CHARGES As a result of restructuring, charges of $65 million were recorded in the year. Earnings were reduced by $30 million. NET CASH SURPLUS ANALYSIS NG had a net cash surplus of $451 million in 2000, an improvement of $362 million compared to the net cash surplus of $89 million in 1999. This improvement was due to an increase in divestment proceeds of $224 million, a reduction in capital and exploration investing activities of $72 million and an improvement in cash from operating activities of $66 million.
- --------------------------------------------------------------------- TOTAL PROVED RESERVES (MILLIONS OF BARRELS OF OIL EQUIVALENT) 1996 1997 1998 1999 2000 - --------------------------------------------------------------------- Natural Gas 99 109 120 101 80 Liquids 65 70 69 51 16 - --------------------------------------------------------------------- Total 164 179 189 152 96 - --------------------------------------------------------------------- - ---------------------------------------------------------------------
During 2000, Natural Gas focused on rationalizing its asset base, primarily through the sale of oil properties, and bringing proven undeveloped reserves into production. CAPITAL AND EXPLORATION INVESTING ANALYSIS In 2000, NG's capital expenditures were $127 million, $73 million less than in 1999. This resulted from less exploration drilling, no heavy oil expenditures and lower gas plant, facility and well equipment expenditures. Divestment proceeds increased $224 million as a result of completing the strategic divestment program. The positive cash flow from net investing activities was part of NG's cash flow management program to support other Suncor growth initiatives. During 2000, Natural Gas focused on rationalizing its asset base and bringing proven undeveloped reserves into production. This increased the five-year finding and development costs (excluding acquisitions) to $11 per BOE, for the five-year period ended 2000, from $8.25 per BOE, for the five-year period ended 1999. During 2000, negative proven reserve revisions of eight million BOE (approximately 5.5% of reserves at the beginning of 2000) were recorded. This adjustment reflected a combination of lower than expected production and new information, which resulted in the downward revision. Future revisions - - positive or negative - are dependent upon such factors as actual production from reservoirs, operating costs, price assumptions and plans associated with the presence of infrastructure. These revisions were partially offset by reserve additions of five million BOE. OUTLOOK* Management expects the Company's natural gas strategy announced in April of 2000 will improve the bottom line of the Natural Gas business that is strategically important to Suncor. Natural gas production continues to benefit Suncor because it diversifies the Company's product portfolio and supplies a cleaner burning fuel, relative to crude oil, to meet growing market demand in North America. Natural gas production also provides a natural hedge against growing internal natural gas demands.
- --------------------------------------------------------------------- NATURAL GAS PRICING VS. INDUSTRY AVERAGE (CDN$/THOUSAND CUBIC FEET) 1996 1997 1998 1999 2000 - --------------------------------------------------------------------- Suncor Average Annual Price 1.50 1.93 1.95 2.44 4.72 Industry Average Reference Price 1.64 1.98 1.95 2.47 4.43 - ---------------------------------------------------------------------
NOTE: 2000 Industry average reference price is an estimate. 38 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - NATURAL GAS During 2000, NG reduced annualized costs by approximately $15 million, approximately 80% of its $18 million to $20 million target. Consolidation of the asset base, organizational restructuring and a reduction of about 70 positions in the NG workforce contributed to reduced operating costs. The remainder of the $18 million to $20 million annualized cost reduction target is expected to be achieved through active management of general and administrative costs. Plans to further improve efficiency and lower operating costs will focus on strategic partnerships, operating alliances and technology applications. Divestments associated with portfolio optimization generated $314 million for the Company in 2000. With this transition now complete, management expects any acquisitions and divestments of conventional assets that may occur in 2001 will further focus NG on growth and consolidation around its three core areas in western Alberta and northeastern British Columbia. COAL BED METHANE In 2000, NG continued to investigate coal bed methane (CBM) as a new natural gas source for the Company. Other companies have commercially viable CBM production in the United States. Suncor is currently examining the viability of CBM projects in the United States, Australia and Canada. At year-end, Suncor had no CBM operations, but did have property in Australia, the United States and Canada, and options with respect to property in the United States. In addition to its potential to add to Suncor's natural gas volumes, some methods of CBM production may have unique environmental benefits. Suncor is participating in research and development initiatives to investigate the potential of coal beds to sequester carbon dioxide (CO2), awaste greenhouse gas emission. In addition, CO2 pumped into the coal bed may provide an economic means of increasing production of natural gas from the coal.
- ----------------------------------------------------- 2000 SUNCOR NATURAL GAS MARKETS - ----------------------------------------------------- (mmcf/d) (%) System 59 30 Direct 141 70 - ----------------------------------------------------- Total 200 100 - ----------------------------------------------------- - -----------------------------------------------------
Natural Gas believes its gas portfolio is positioned to take advantage of improved pricing fundamentals. RISK/SUCCESS FACTORS AFFECTING PERFORMANCE The risks associated with Suncor's natural gas activities and commodity pricing should not be underestimated or viewed as predictable. Suncor expects that both natural gas and crude oil pricing will continue to be volatile due to the cyclical nature of supply and demand for these commodities. Management continues to believe the single most important factor that will influence Natural Gas' long-term performance is its ability to consistently and competitively find and develop reserves that can be brought on stream economically. Market demand for land and services can also increase or decrease operating costs. Management believes there are risks and uncertainties associated with obtaining regulatory approval for exploration and development activities. Working in other countries could increase these risks and add to costs or cause delays to these projects. The Company continues to work at reducing these risks through proactive consultation with stakeholders. Also refer to "Environmental Regulation Risk/Success Factors" in the Corporate section of this MD&A.
- ----------------------------------------------------- DIRECT PROPRIETARY GAS SALES - ----------------------------------------------------- (mmcf/d) (%) British Columbia 13 9 Midwest U.S. 15 11 Eastern Canada 26 19 California 40 28 Alberta 47 33 - ----------------------------------------------------- Total 141 100 - ----------------------------------------------------- - -----------------------------------------------------
- ----------------------------------------------------- SYSTEM PROPRIETARY GAS - ----------------------------------------------------- (mmcf/d) (%) TransCanada Gas Services 31 53 Pan Alberta 17 29 Canwest 2 3 Other 9 15 - ----------------------------------------------------- Total 59 100 - ----------------------------------------------------- - -----------------------------------------------------
SUNCOR ENERGY INC. 2000 ANNUAL REPORT 39 MANAGEMENT'S DISCUSSION AND ANALYSIS DISTILLATES Diesel, jet fuels and heating oils. Sunoco - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- OVERVIEW Sunoco Inc., Suncor's wholly owned subsidiary, operates a refining and marketing business in central Canada. Sunoco is strategically integrated with Suncor's upstream Oil Sands operations in western Canada. Its Sarnia Refinery effectively integrates Suncor's upstream and downstream businesses as part of the "value chain." The refinery has the capacity to refine 70,000 barrels of petroleum feedstocks from Oil Sands and other sources into gasoline, DISTILLATES and petrochemicals. Sunoco, in turn, benefits from having access to a reliable, long-term supply of Oil Sands feedstocks. This integration strengthens the Company as a whole. Sunoco markets 57% of the refinery's production through controlled distribution networks in Ontario that sell gasolines and diesel to retail customers. These are: - - 301 Sunoco retail service stations, - - 11 Sunoco-branded Fleet Fuel Cardlock sites, - - 154 Pioneer-operated retail service stations (Pioneer Group Inc. is an independent retailer with whom Sunoco has a 50% joint venture partnership), and - - 54 UPI-operated retail 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 Midwest U.S. agricultural supply and grain marketing co-operative.) Approximately 40% of Sunoco's refined products were sold to wholesale and industrial accounts in Ontario and Quebec. Jet fuels, diesel and gasolines comprised the highest volume of sales. The remaining 3% of Sunoco's total refined products sales were petrochemicals sold through Sun Petrochemicals Company, a 50% joint venture between Sunoco and a U.S. refinery. Sunoco's Integrated Energy Solutions business has been marketing natural gas in Ontario since 1997. Sunoco serves more than 130,000 commercial and residential customer accounts in Ontario. RESULTS OF OPERATIONS AND INVESTING ACTIVITIES 2000 VS. 1999 SUNOCO RESULTS SUMMARY
- ----------------------------------------------------------------- ($ millions unless otherwise noted) 2000 1999 1998 - ----------------------------------------------------------------- Revenue 2 604 1 779 1 533 Refined product sales (thousands of cubic metres) Sunoco retail gasoline 1 539 1 500 1 496 Total 5 360 5 080 5 037 Earnings (loss) breakdown: Refining/wholesale 66 10 22 Retail marketing 9 21 16 Energy marketing (7) (4) (1) Others (tax adjustments) 13 -- -- Total 81 27 37 Cash flow provided from operations 174 103 112 Investing activities 59 43 64 Net cash surplus 155 129 55 Return on capital employed (%) 20.5 6.0 7.4 - -----------------------------------------------------------------
40 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO [GRAPHIC OF NORTH AMERICA HIGHLIGHTING ONTARIO CITIES] [PHOTOGRAPGH OF TOM RYLEY] We continue to assess opportunities to expand Sunoco's customer offering in Ontario, and that includes marketing more environmentally focused fuels and possibly electricity. TOM RYLEY Executive Vice President, Sunoco - --------------------------------------------------------------------------------
- ----------------------------------------------------------- SUNOCO SALES BY CHANNEL (PERCENTAGE) - ----------------------------------------------------------- Sunoco Retail Service Stations, Cardlock Sites, and Joint-Venture Operated Sites* 57 Wholesale/Industrial 40 Sun Petrochemicals Company 3 - -----------------------------------------------------------
*Controlled distribution channel
BRIDGE ANALYSIS OF EARNINGS (CDN$ MILLIONS) - -------------------------------- 1999 - -------------------------------- Total 27 - -------------------------------- - -------------------------------- 2000 Margin 45 Volume 8 Ancillary Income 9 Joint Ventures 1 Integrated Energy Solutions (3) Expenses (19) Tax Rate Adjustment 13 - -------------------------------- Total 81 - -------------------------------- - --------------------------------
Higher refining margins and volumes were the key factors of improved operating earnings in 2000. Tax adjustments related to revaluation of future income tax balances further increased total earnings by $13 million. EARNINGS AND BUSINESS ANALYSIS OVERALL EARNINGS HIGHEST ON RECORD Sunoco's earnings rose to $81 million in 2000, compared with $27 million in 1999 - its best earnings on record. This improvement was mainly due to higher volumes and refining margins, but was partially offset by lower retail margins, higher expenses and losses in Integrated Energy Solutions. Reductions in income tax rates in 2000 increased earnings by a further $13 million due to the revaluation of future income tax balances. Return on capital employed rose to 20.5%, compared with 6% in 1999, due primarily to improved earnings.
BRIDGE ANALYSIS OF NET CASH DEFICIENCY (CDN$ MILLIONS) - ------------------------------------------- 1999 - ------------------------------------------- Total 129 - ------------------------------------------- - ------------------------------------------- 2000 Operations 71 Working Capital (29) Investing Activities (16) - ------------------------------------------- Total 155 - ------------------------------------------- - -------------------------------------------
Improvement in cash flow from operations was partially offset by a lower reduction in working capital compared to 1999. Total capital spending was higher than 1999 due to planned maintenance work completed at the Sarnia Refinery. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 41 MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO REFINING EARNINGS UP $56 MILLION OVER LAST YEAR Earnings from refining activities increased to $66 million in 2000 compared with $10 million in 1999. Sales of refined products averaged 92,200 barrels per day (bpd), compared with 86,800 bpd in 1999. The higher refining earnings were largely a result of an increase in refining margins to 5.9 cents per litre (cpl) compared with 4 cpl in 1999, due to tight international supply and demand for gasoline and distillates. This factor alone increased year-over-year earnings by $47 million. Higher wholesale gasoline and distillate sales volumes increased refining earnings by $6 million over 1999. Improved performance in joint venture investments also increased earnings by $2 million over last year, due primarily to improved margins. Refining earnings were further improved as a result of a $5 million benefit from selling lower cost inventory as described in Note 8 to the Consolidated Financial Statements. During the year, the Sarnia Refinery completed a planned turnaround on time and within budget. However, several unplanned outages at the refinery during the year tightened the product supply and required additional purchases to meet customer demand. Total expenses increased by $7 million over 1999. This was due to higher natural gas and steam costs, and higher freight costs due to operational outages. The increase in expenses was partially offset by a $3 million mark-to-market gain on the forward purchase of crude oil. Sunoco cardlock diesel sales volumes doubled in 2000 due to marketing initiatives and an expansion of the diesel cardlock network. At the end of the year, Sunoco signed a joint venture agreement with Fifth Wheel Corporation, a major truck stop operator, which will provide Sunoco with another controlled distribution channel for distillates sales.
- ---------------------------------------------------------------------------------- MARGIN (CDN CENTS PER LITRE) 1996 1997 1998 1999 2000 - ---------------------------------------------------------------------------------- Sunoco-based Retail Gasoline Margin 5.7 6.8 7.0 7.4 6.6 Refining Margin 4.4 4.6 4.1 4.0 5.9 - ----------------------------------------------------------------------------------
Refining margins improved from last year due to the tight supply situation North America experienced during the year. Retail margins declined, on the other hand, as the rapidly rising costs of crude oil could not be fully recovered. REDUCED MARGINS IMPACT RETAIL MARKETING PROFITABILITY Earnings from retail marketing declined to $9 million in 2000 compared with $21 million in 1999. Total retail volumes at Sunoco retail service stations grew more than 2% in 2000, increasing earnings by $2 million over 1999. However, retail gasoline margins from the Sunoco branded network decreased $7 million from 1999 (6.6 cpl in 2000 compared with 7.4 cpl in 1999). Margins were negatively impacted because the rapidly increasing crude costs could not be fully recovered. Similarly, joint venture profitability declined $1 million from prior year, although total sales volumes improved by more than 5% over 1999. Sales of premium products, such as Ultra 94, also declined due to the significant crude oil-driven increase in retail prices during the year. In 2000, a new retailer agreement with different cost and revenue allocations was implemented, contributing to a $15 million increase in total expenses over 1999. This increase was partially offset by a corresponding increase of $9 million in ancillary income and royalties under the new arrangement. The net increase of $6 million was due mostly to commencement of a pilot internet marketing site and higher costs associated with customer loyalty programs and bank credit cards. These cost increases resulted from higher retail prices. Average throughput at Sunoco-branded sites grew 4% in 2000, to 5.3 million litres per site from 5.1 million litres per site in 1999. The increased efficiency reflects improvement in retail volumes resulting from marketing initiatives. Sunoco's customer loyalty program with the Canadian Automobile Association's (CAA) Ontario clubs has continued to gain popularity since its introduction in 1998. In 2000, Sunoco encouraged an additional 15% of CAA members to use their cards to earn savings on CAA membership when purchasing Sunoco products and services. Sunoco now serves more than 66% of the 1.8 million CAA members in Ontario. 42 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO * This section contains forward- looking information. Also refer to the Overview *** on page 29 of this report.
- ------------------------------------------------------------------------------------------ SUNOCO-BRANDED RETAIL NETWORK EFFICIENCY* (MILLIONS OF LITRES PER SITE) 1996 1997 1998 1999 2000 - ------------------------------------------------------------------------------------------ Throughput 4.2 4.3 5.0 5.1 5.3 Number of Sites 333 332 310 305 301 - ------------------------------------------------------------------------------------------
Site throughput continued to improve, reflecting higher volumes that resulted from marketing initiatives such as the loyalty program with the Canadian Automobile Association (CAA). * THROUGHPUT PER SITE - Millions of litres per site based on the average number of sites at the beginning and end of the year. SITES - Number at year-end, excluding joint venture owned sites. Sunoco launched a branded Affinity Card Program in July to further strengthen customer loyalty. This program offers discounts to natural gas customers to encourage retail product purchases. Sunoco's joint venture investment, Pioneer Petroleums, was named a winner of "Canada's 50 Best Managed Private Companies Program" for 2000, sponsored by Arthur Andersen, CIBC and the NATIONAL POST. INTEGRATED ENERGY SOLUTIONS LOSES $7 MILLION Integrated Energy Solutions (IES), Sunoco's retail natural gas marketing division, lost $7 million in 2000 compared with a loss of $4 million in 1999. The rapid increase in natural gas prices during 2000 was a major factor, since some of Sunoco's customer contracts were tied to regulated rates that lagged the rising market prices. Over 95% of these agreements have now been restructured to match fixed price sales contracts with fixed price supply, and yield a positive margin in 2001. IES exited the heating, ventilation and air conditioning market in 2000, and closed its Home Energy Dealer Network. These decisions do not affect Sunoco's interests in the natural gas marketing business. Costs associated with the shutdown were not material to Sunoco's overall earnings. NET CASH SURPLUS ANALYSIS Net cash flow increased to $155 million in 2000 compared with $129 million in 1999. Cash flow from operations increased to $174 million compared with $103 million in 1999. This was primarily a result of the higher earnings from the refining operations, which were partially offset by lower retail earnings. Working capital decreased by $40 million in 2000, down $29 million compared with a $69 million decrease in 1999. The decline was due to a $25 million unfavourable change in current assets, due mostly to higher trade receivables reflecting the increased sales volumes and higher product prices, and lower reduction in inventory compared with 1999. Net change in cur rent liabilities was $4 million lower than 1999, resulting from the increased costs of feedstocks purchased. Capital spending increased to $59 million versus $43 million in 1999, primarily due to a major hydrocracker maintenance shutdown at the Sarnia Refinery. OUTLOOK* Sunoco has identified five focus areas: - - Maximize refinery competitiveness, - - Increase business integration, - - Continue to grow core business, - - Capitalize on long-term growth opportunities, and - - Continue to improve environmental performance. MAXIMIZING REFINERY COMPETITIVENESS Sunoco's goal is to achieve levels of profitability and efficiency at the Sarnia Refinery by 2002 to position it in the top one-third of North American refineries of similar size and complexity. A three-year organizational realignment to reduce refining costs is expected to be completed in 2001. Plans are in place to improve energy efficiency and enhance systems processes. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 43 MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO ANCILLARY INCOME Income earned from such activities as car washes, sale of fast foods and confectionary items. To reduce exposure to energy cost increases expected when the electricity market deregulates, the refinery negotiated a fixed rate supply contract to lock in the cost of a portion of its electricity for three years from the date that electricity deregulation begins. In addition, negotiations continue with TransAlta Energy Corporation to purchase steam and electricity from the Sarnia Regional Co-generation Project that is expected to commence at the end of 2002. INCREASED BUSINESS INTEGRATION Sunoco restructured in 2000 to increase operating efficiencies. The changes are designed to enable Sunoco to better execute its business strategies by providing greater focus on Sunoco-wide performance. No significant changes have been made to Sunoco's business strategies. The reorganization reduces the number of business units from three to two, called Rack-Back and Rack-Forward. Sunoco will base its financial reporting on this structure starting January 1, 2001. Under the new structure, Rack Forward will include retail operations, wholesale and commercial sales, natural gas marketing, and the UPI and Pioneer joint venture investments. Rack Back will include refining operations and sales to the refinery's largest industrial and reseller customers, including Sun Petrochemicals Company. CONTINUED CORE BUSINESS GROWTH Rack-Forward will continue to focus on marketing Sunoco-branded products, managing retail assets, wholesale and commercial sales, joint venture investments, UPI and Pioneer, and natural gas retail sales. Plans are in place to: - - Integrate marketing strategies across all sales channels to increase effectiveness and reduce costs, - - Implement initiatives to increase sales of premium products, such as Gold Diesel, and to reposition and regain sales volumes of Ultra 94, - - Grow non-fuel revenues (ANCILLARY INCOME) in a capital-effective manner through value-added strategic alliances, and - - Continue to develop strategies to increase distillates sales. Rack-Back is responsible for the procurement and manufacturing of a cost-competitive and reliable supply of petroleum and other energy products. In addition, Rack-Back is responsible for managing sales and distribution to the refinery's largest industrial and reseller customers. Rack Back will also focus on: - - Creating strategies to reduce product costs, optimize production and improve supply-chain and energy-cost management for long-term growth and competitiveness, - - Positioning Sunoco to meet legislated limits on sulphur content in gasoline and diesel, which will be phased in between 2002-2005, and - - Developing economic options to reduce air emissions at the Sarnia Refinery to help meet Suncor's vision of long-term sustainability. CAPITALIZE ON LONG-TERM GROWTH OPPORTUNITIES Sunoco continues to assess the potential to market electricity in Ontario subsequent to the pending deregulation of electricity services. In conjunction with Suncor's Alternative and Renewable Energy business development group, Sunoco will continue to explore additional energy opportunities in its markets. To further integrate Suncor's upstream and downstream businesses, Sunoco continues to assess new marketing and refining investment opportunities to grow the future value of Suncor and to capture the greatest long-term value from the increasing production from Oil Sands. 44 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - SUNOCO CONTINUE TO IMPROVE ENVIRONMENTAL PERFORMANCE Sunoco continues to focus on environmental issues facing Ontario and Canada and to develop more environmentally responsible products. For example, in an effort to reduce carbon monoxide and carbon dioxide emissions, the Sunoco-branded retail network introduced ethanol-enhanced gasoline in late 1997. In 2000, Pioneer Petroleums, Sunoco's joint venture partner, expanded the market share of ethanol-enhanced gasoline when it joined Sunoco and UPI stations in selling the product. Sunoco's certification to display Environment Canada's EcoLogo at its gasoline pumps and car washes demonstrates Sunoco's active commitment to offer products and services that meet the Canadian government's environmental labelling guidelines. Reducing smog is an important goal for Sunoco. Sunoco continues to participate in Ontario's Pilot Emission Reduction Project by using a gasoline additive that reduces nitrogen oxides (NOX) from tailpipe emissions. This generated a total of 825 tons of NOX credits for Sunoco in 2000 compared with 275 tons of NOX emission credits in 1999. The 1999 emission reduction credits were sold to Ontario Power Generation Inc., and the proceeds were used to conduct a refinery-wide emission inventory assessment in 2000. To support Suncor's goal of meeting or exceeding national and international commitments on greenhouse gas emissions, Sunoco is developing a plan in 2001 to reduce emissions at the Sarnia Refinery by 25% from 1995 levels by 2005. In 2000, Sunoco worked with Conestoga-Rovers and Associates to pursue opportunities to produce energy from Ontario landfills. Methane gas from landfill sites has the potential to provide a reliable source of fuel for heating and generating electricity and carbon dioxide for possible commercial use. Landfill gas recovery also reduces greenhouse gas emissions and landfill odours. RISK/SUCCESS FACTORS AFFECTING PERFORMANCE While the downstream business environment improved in 2000 (as reflected in the overall performance), management expects fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. Management believes the margin and price volatility and the below average inventory levels in crude and refined products that North America experienced in 2000 will continue to impact the business environment in which Sunoco operates in 2001. As Sunoco enters new markets, such as electricity retailing, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations or risks inherent in entering new markets. The Canadian refining industry faces significant capital spending to construct sulphur removal facilities. This capital expenditure is required following the passage of legislation that limits sulphur levels in gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. Actual capital spending required to meet the new standard is subject to the findings of a strategic assessment that is under way. A detailed implementation plan will be completed in 2001. No regulations have been tabled at this time with respect to sulphur levels in diesel, although Suncor expects limits that will be lower than its current capabilities. The cost to comply with these anticipated sulphur in diesel limits could be significant but are not expected to place the Company at a competitive disadvantage. Also refer to "Environmental Regulation Risk/Success Factors" in the Corporate section of this MD&A. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 45 MANAGEMENT'S DISCUSSION AND ANALYSIS CORPORATE SALE LONG-TERM EMPLOYEE INCENTIVE PLAN See note 5 to the Consolidated See note 13 (b) to the Consolidated Financial Statements. Financial Statements. LINES OF CREDIT See note 12 the the Consolidated Financial Statements. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- OVERVIEW Suncor's corporate centre fulfills a number of roles that include supporting the Company's business units and Board of Directors. Corporate centre personnel are accountable for functions such as legal, taxation, risk management, company-wide human resource programs, treasury, corporate finance, alternative and renewable energy investment assessments, planning and business development, corporate communications and regulatory reporting at the corporate level. RESULTS OF OPERATIONS AND INVESTING ACTIVITIES 2000 VS. 1999 EXPENSES INCREASED Corporate expenses increased to $117 million in 2000 from $49 million in 1999. The primary reasons for the $68 million increase were an $80 million write-down of the carrying value of Suncor's investment in the Stuart Oil Shale Project in Australia and the expensing of additional costs of $12 million on the Stuart Project. These were partially offset by a foreign exchange gain of $11 million as the Australian dollar weakened against the Canadian dollar. Higher corporate expenses were partially offset by a lower interest expense of $10 million and a reduction in other expenses of $3 million. The reduction in interest expense is due to higher capitalization of interest expenses associated with Project Millennium capital spending. The corporate centre had a net cash deficiency of $76 million in 2000, largely unchanged compared to the net cash deficiency of $73 million in 1999. CONSOLIDATED BALANCE SHEET ANALYSIS Higher commodity and refined petroleum product prices and higher sales volumes at the end of 2000 compared to the end of 1999 increased accounts receivable by $165 million. This increase was partially offset by the SALE of $35 million in accounts receivable. An inventory increase of $31 million represents an increase in upstream inventory levels to reflect crude oil sales in transit at year-end. It is expected there will be a reduction in the inventory level in the first quarter of 2001. Net capital assets increased by $1.4 billion in 2000. Capital assets increased by $1.7 billion due to Suncor's Project Millennium. These increases were partially offset by the sale in 2000 of Natural Gas capital assets with a net book value of $167 million and a $56 million write-down of capital assets in the Natural Gas business due to the change in strategy. There was also a before-tax write-down of $125 million in the carrying value of the Stuart Oil Shale Project asset. Trade payables and accrued liabilities were $709 million at the end of 2000, $93 million higher than at the end of 1999. With the majority of material purchases now completed on Project Millennium, the project liabilities decreased by $86 million from year-end 1999. More than offsetting this decrease were higher liabilities associated with buying crude oil, feedstocks and refined products from third parties. A portion of the refined product purchases were required in the downstream business due to several unplanned outages at the Sarnia Refinery. Other factors that increased year-end payables and accrued liabilities were higher royalties, resulting from higher commodity prices, and an increase in reclamation activities in all three operating businesses. Excluding cash, short-term borrowings and the current portion of long-term borrowings, Suncor had a working capital deficiency of $128 million at the end of 2000 compared to a deficiency of $225 million at the end of 1999. This $97 million improvement primarily reflected the impact of higher commodity prices. Suncor had in place $1.5 billion in unused LINES OF CREDIT to cover working capital deficiencies. With Project Millennium targeted to be in operation at the end of 2001, the working capital position is expected to improve, with the additional revenue resulting from the anticipated higher production levels. 46 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE [GRAPHIC OF NORTH AMERICA HIGHLIGHTING ALBERTA CITIES] Corporate Office employees are charged with supporting the goals of each of Suncor's businesses and developing strategic growth plans for the Company that ensure growth occurs in a sustainable manner and maximum shareholder value is created and optimized. [PHOTOGRAPH OF MIKE O'BRIEN] MIKE O'BRIEN Executive Vice President, Corporate Development and Chief Financial Officer - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- For a description of future income tax assets and liabilities on the balance sheet refer to Note 6 in the Consolidated Financial Statements. These balances are expected to fluctuate based upon future earnings and capital expenditure levels. They could also fluctuate if government tax laws and regulations change. CONSOLIDATED EARNINGS ANALYSIS Sales and other operating revenues increased to $3,385 million in 2000, up from $2,383 million in 1999. The impact of higher commodity prices, both in the upstream and downstream businesses, increased revenues by $928 million. There were two factors that partially offset the benefit of the higher prices and are reflected in the $928 million figure. One is the impact of hedging activity in 2000, which reduced year-over-year revenues by $336 million. The second factor that reduced revenues in 2000 was lower prices from sour crude oil sales due to widening of the light/heavy crude oil differential. Management believes the differential in 2001 will return to levels within a more historical range as demand is expected to increase, but the timing is difficult to predict because the determining factors are beyond Suncor's control. While crude oil sales volumes increased due to record Oil Sands sales levels, a decrease in conventional liquids and natural gas volumes resulted in a net $42 million negative impact on revenue. Downstream sales volumes increased 6%, adding $98 million to consolidated revenues. Additional ancillary income of $18 million was also recorded in the year. The impact of higher feedstock and refined product prices in 2000 impacted Suncor's downstream business, which purchased both feedstocks and refined products. In 2000, a planned 32-day maintenance shutdown of the hydrocracker unit that produces transportation fuels, and operating difficulties in the fourth quarter, necessitated the purchase of additional finished product to meet customers' requirements. These factors increased costs for the year by $288 million. Operating, selling and general expenses increased by $144 million, to $918 million in 2000 from $774 million in 1999. Higher operating costs in all operations represented $147 million of the year-over-year increase. The higher operating costs were due mainly to higher Oil Sands volumes, variable ore quality, higher energy costs, higher reclamation expense activities and higher maintenance costs at both Oil Sands and the Sarnia Refinery. The higher maintenance costs reflected a three-week period of extremely cold weather at Oil Sands and problems with major units at the Sarnia Refinery during the fourth quarter. Increased operating costs were also due to higher expenditures in Sunoco's branded marketing operations. These included costs associated with increasing ancillary revenue, higher advertising expenses, as well as increased bank credit card costs due to the impact of higher crude oil prices that were reflected in higher selling prices and higher volumes. In addition, expenses also increased by $8 million due to a higher provision for LONG-TERM EMPLOYEE INCENTIVE PLAN costs in 2000. Costs associated with the Stuart Oil Shale Project were expensed after the asset write-down in the third quarter. This treatment resulted in $19 million in Stuart Project costs being expensed in 2000. Partially offsetting these increases was a foreign exchange gain of $11 million due to the weakening of the Australian dollar against the Canadian dollar related to the Stuart Project loan obligations. Volume-related expenses in NG were $19 million lower because volumes decreased due to property divestments. Exploration expenses increased by $13 million in 2000 to $53 million, primarily as a result of higher dry hole costs. Royalty expenses increased by $100 million in 2000 to $199 million. The increase was primarily due to higher commodity prices which were partially offset by the lower volumes resulting from divestments by the NG business. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 47 MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE * This section contains forward- FUTURE INCOME TAXES looking information. Also refer See Note 6 to the Consolidated to the Overview *** on page 29 Financial Statements. of this report. Taxes, other than income taxes, increased by $27 million primarily due to higher sales volumes of taxable products (mainly transportation fuels) in the downstream business. Depreciation, depletion and amortization (DD&A) increased by $47 million to $365 million in 2000 over 1999. An increase of $55 million was recorded in the Oil Sands business as explained on page 32 under the Oil Sands section (Expenses Increased). DD&A was reduced by $8 million primarily due to the lower asset base in the NG business after it divested nearly 30% of proven reserves held at the beginning of the year. While interest costs increased in 2000 to $112 million from $71 million in 1999, net interest expense charged to the income statement in 2000 decreased to $8 million from $26 million in 1999. This reflected the high level of investment in Project Millennium and the resulting interest capitalization associated with this project. Interest costs associated with the Stuart Oil Shale Project have been charged to the income statement in the second half of 2000 with the decision to write down a portion of the carrying value of the project at the end of the second quarter. With Project Millennium expected to begin commercial operations by 2002, interest charges now being capitalized will be expensed, thereby reducing future earnings. Suncor's effective tax rate in both 2000 and 1999 was approximately 40%. The adoption in 2000 of the new standard for FUTURE INCOME TAXES resulted in the recognition of a $13 million reduction on the balance sheet and a corresponding increase in net earnings due to the revaluation of future income tax balances. This change was due to a reduction in the income tax rates by federal and provincial governments. These reductions only applied to Suncor's downstream business (Sunoco). Under the previous accounting standard, such adjustments would not have been made. As well, there was the recognition of a provincial benefit of $13 million due to provincial Crown royalties being in excess of the federal resource allowance deduction. This benefit was a result of the high commodity prices that increased Crown royalties and a high level of tax depreciation due to the high investing expenditures. Suncor believes the effective tax rate in 2001 will be approximately 40%. OUTLOOK* In 2001, Suncor priorities include: EXPAND OIL SANDS PRODUCTION AND INCREASE INTEGRATION In 2001, Suncor's priority is to commission Project Millennium, a $2.8 billion project that is expected to increase Oil Sands' production capacity to 225,000 barrels per day by 2002. By increasing production capacity and improving efficiencies, Project Millennium is expected to reduce Oil Sands' unit cash costs. Suncor's next stage of expansion is expected to progress in 2001 as the Firebag In-situ Oil Sands Project proceeds through the regulatory approval process. This commercial-scale in-situ project is targeted to add approximately 35,000 barrels of bitumen per day in 2005. To process the additional bitumen, Suncor plans to add a vacuum tower complex to increase the Oil Sands upgrading capacity to 260,000 barrels of oil per day in 2005. These plans are subject to Board of Directors and regulatory approvals. The Company's long-term vision is to ultimately increase total production at its Oil Sands facilities through a combination of oil sands mining and in-situ development to approximately 400,000 to 450,000 barrels of oil per day in 2008. Any such plans toward realizing this long-term vision would be subject to Board of Directors and regulatory approvals. Suncor's Oil Sands expansion will be supported by the continuing effort to further integrate the Company to capture more of the value between our upstream production and the end consumer. Suncor continues to evaluate several approaches to secure markets and transportation for its increasing Oil Sands production including the possible acquisition or joint venture of a refinery. In addition, the Company will continue efforts to enter into long-term sales agreements with other refiners in both Canada and the United States. FOCUS ON BASE BUSINESS EXCELLENCE Although the Oil Sands expansion is a critical part of Suncor's growth strategy, the Company realizes that properly managing its base business is important to achieving strong financial returns. Safe and efficient operations reduce the risk of production loss, environmental liability and the higher costs incurred in conducting unscheduled maintenance. In 2001, all of Suncor's businesses will continue to make base business excellence a priority and will focus on improving operational reliability. A key focus for the future will be to apply technological advancements that increase the efficiency of each business, reduce costs and improve 48 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE DUAL TRAINS The creation of parallel processes for the existing extraction and upgrading facilities along with additional mining equipment and increased energy services support. environmental performance. Suncor's goal is to be one of the lowest-cost oil producers in North America and a top quartile competitor in each of its businesses. INCREASE EMPHASIS ON SUSTAINABILITY As the Company expands its hydrocarbon-based businesses with the accompanying increases in greenhouse gas emissions, management believes Suncor also needs to work concurrently toward the development of alternative and renewable sources of energy. Alternative energy sources have the potential for lower environmental impacts as well as creating additional business investment opportunities. Early in 2000, Suncor announced plans to invest $100 million in alternative and renewable energy projects over a five-year period. During 2000, many opportunities were investigated and evaluated and Suncor expects that its plans to establish renewable energy businesses in the areas of wind, solar, run-of-river hydro, biomass and landfill gas, will result in investment decisions in 2001. Suncor's effort to reduce greenhouse gas emissions will also be reflected in its pursuit of greater energy efficiency as an investment in the future viability of the business that could yield cost savings and improve competitive, as well as environmental, performance. Suncor's goal is to meet or exceed relevant national and international commitments to limit greenhouse gases in the atmosphere. In the context of current Canadian commitments, this involves lowering net greenhouse gas emissions to 6% below 1990 levels by 2010; an ambitious target given the Company's vision to produce 400,000 to 450,000 barrels of oil per day by 2008. Achievement of this commitment requires access to the flexibility mechanisms in the Kyoto Protocol, and the implementation of a meaningful credit for early action program in Canada. LONG-TERM CORPORATE DEVELOPMENT Suncor will continue to emphasize development of long-term strategic plans aimed at growing its current businesses and identifying ways to broaden the scope of the products and services the Company provides. As the Company moves forward it will work to introduce new strategies and technologies into its business model that will strengthen its economic performance and enhance shareholder value while also furthering its commitment to sustainable development and growth. In 2001, Suncor will continue to examine development opportunities in surface mineable oil deposits. The Company is currently testing the commercial viability of producing oil from oil shale with the Stuart Oil Shale Project in Australia and has also assessed potential oil shale deposits in a number of other locations. Suncor is operating the Stuart Oil Shale Project, which is a joint venture with Southern Pacific Petroleum NL/Central Pacific Minerals NL (SPP/CPM). During 2000, Suncor experienced operational issues with the first phase of the Stuart Oil Shale Project including the discovery of low levels of dioxin in plant emissions. The next stage of this project's commercial development has been put on hold until these issues and concerns about environmental and social impacts are addressed. RISK/SUCCESS FACTORS AFFECTING PERFORMANCE OIL SANDS When Project Millennium is completed, an even greater portion of Suncor's financial performance is expected to be dependent on the performance of its Oil Sands operations. The Oil Sands business could account for 90% of Suncor's upstream production in 2002 compared to 70% in 1998. Assuming estimated economies of scale and reliability improvements are achieved, management believes its per barrel cash operating costs will decrease from 2000 levels in 2002 largely as a result of increased production associated with Project Millennium. See the Outlook section under "Oil Sands" for a more detailed discussion. Suncor believes the planned increases in Oil Sands production present strategic advantages, as well as issues that require prudent risk management. The strategic advantages of Oil Sands growth include: - - Economies of scale associated with higher levels of production from the existing Oil Sands infrastructure, - - DUAL TRAINS in the extraction and upgrading processes provide flexibility to schedule periodic plant maintenance while continuing to generate production, - - The ability to leverage demonstrated operational experience and technologies, and - - Production growth without the exploration risk associated with conventional oil and gas operations. The issues Suncor must manage include, but are not limited to: - - Suncor's ability to finance Oil Sands growth in a volatile commodity pricing environment. (Also refer to the section on Liquidity and Capital Resources.) SUNCOR ENERGY INC. 2000 ANNUAL REPORT 49 MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE - - Competition from new entrants in the oil sands business. This could take the form of competition for skilled people, increased demands on the Fort McMurray infrastructure (housing, roads, schools, etc.), or higher prices for the products and services required to operate and maintain the plant. Suncor has addressed these issues by developing a comprehensive recruitment strategy, working with the community to determine infrastructure needs, designing Oil Sands' expansion to reduce unit costs, capitalizing on technology advancements and seeking strategic alliances with service providers. - - Potential changes in the demand for refinery feedstocks and diesel. Suncor believes it can reduce the impact of this issue by entering into long-term supply agreements with major customers, expanding its customer base and offering customized blends of refinery feedstocks to meet customers' specifications. - - Preservation and protection of the environment. (See Environmental Regulation Risk/Success Factors on page 51.) COMMODITY PRICES Suncor's future financial performance remains closely linked to hydrocarbon commodity prices, which can be influenced by a number of factors including global and regional supply and demand factors, worldwide political events and the weather. These factors, amongst others, can result in a high degree of price volatility as illustrated over the last three years when the monthly average price for the benchmark WTI crude oil ranged from a low of U.S.$11.30 per barrel to a high in 2000 of U.S.$34.25 per barrel. Suncor has partially offset the impact of crude oil price volatility by pursuing economies of scale and improving reliability at Oil Sands over the past five years. Crude oil and natural gas prices are based on a U.S. dollar benchmark, which results in Suncor's earned prices being influenced by the Canadian/U.S. currency exchange rate. This creates another element of uncertainty. The continued weakness in the Canadian dollar versus the U.S. dollar for the last three years ($0.67 Cdn:U.S.$ compared to $0.72 in 1997) increased Suncor's revenues, as measured in Canadian dollars. In the future, the strength of the Canadian dollar relative to foreign currencies could create uncertainties for Suncor. For example, a one cent change in the Australian/Canadian exchange rate on the Stuart Oil Shale Project borrowings will impact Suncor's after-tax earnings by approximately $1 million. (See Note 2 to the Consolidated Financial Statements.)
- ------------------------------------------------------------------------------------- CRUDE OIL HEDGING PROGRAM (AT DECEMBER 31, 2000) 2001 2002 2003 2004 2005 - ------------------------------------------------------------------------------------- Barrels per day of Annual Crude Oil Hedged 57,500 48,000 0 0 0 Current Annual Limits (barrels) 57,500 63,000 63,000 67,500 70,000 Hedged Price - Cdn$ per barrel 28.69 29.04 -- -- -- - -------------------------------------------------------------------------------------
Suncor uses hedging as a risk management tool to reduce earnings and cash flow volatility. The annual limits may change, subject to Board approval, to reflect management's ongoing assessment of the risk it is willing to accept. The hedged price is a combination of the price for swaps and costless collars, and reflects the hedged foreign exchange rate and spot price, where appropriate. Refer to Note 18 in the Consolidated Financial Statements for additional information. HEDGING Suncor cannot control the prices of crude oil or natural gas, or currency exchange rates. However, the Company has a hedging program that fixes the prices of crude oil and natural gas and the associated foreign exchange, for a percentage of Suncor's total production volume. Suncor's risk management objective with the hedging program is to lock in prices on a portion of the Company's future production today, to reduce exposure to market volatility and ensure the Company's ability to finance its growth. The Board of Directors meets with management regularly to assess Suncor's hedging thresholds in light of its price forecast and cash requirements. To add more certainty to Suncor's ability to finance its 2000 and 2001 capital programs, the Board authorized hedging up to 50% of its crude oil volumes in 2000 and 2001 with the authorized limit returning to 30% in 2002, 2003 and 2004. For natural gas, the Board authorized a hedging program that allows up to 50% of Suncor's volume to be hedged in the current year and subsequent year, 30% for the third year, and 15% for the fourth year. See Note 18 to the Consolidated Financial Statements for details of Suncor's hedge position as of December 31, 2000. In 2000, crude oil, natural gas and currency exchange hedging activities decreased Suncor's earnings by $259 million. In 1999, hedging activities decreased earnings by $56 million. OTHER FACTORS Other critical factors affecting Suncor's financial results include volumes of refined product sales, margins on the sale of refined products, success of the exploration program, interest rates and the Company's ability to manage costs. Also refer to the note *** at the beginning of the MD&A, and to the Company's Annual Information Form, on file with securities regulators or available without charge from the Company. 50 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE SENSITIVITY ANALYSIS The following sensitivity analysis shows the main factors affecting Suncor's annual pretax cash flow from operations and after-tax earnings based on actual 2000 operations. The table illustrates the potential financial impact of these factors applied to Suncor's 2000 results. It should be noted that Natural Gas production in 2001 is expected to be lower than the 2000 average due to property divestments and natural reservoir declines. As well, with Project Millennium commissioning planned for the second half of 2001, Oil Sands production is expected to increase over 2000 levels. A change in any one factor could compound or offset other factors. Because this table does not incorporate potential cross-relationships, it would not necessarily accurately predict future results. SENSITIVITY ANALYSIS
- ------------------------------------------------------------------------------------------------------- Approximate change in Pre-tax cash flow After-tax ($ millions) 2000 Average Change from operations earnings - ------------------------------------------------------------------------------------------------------- Oil Sands Price of crude oil ($/barrel) 31.67 U.S.$1.00 26 15 Light/heavy differential ($/barrel) 9.38 U.S.$1.00 15 9 Sales (barrels/day) 115,600 1,000 12 7 Natural gas Price of natural gas ($/thousand cubic feet) 4.72 0.10 5 3 Production of natural gas (millions of cubic feet/day) 200 10 11 4 Sunoco Retail gasoline margin (cents/litre) 6.6 0.1 2 1 Refining/wholesale margin (cents/litre) 5.9 0.1 4 2 Consolidated Exchange rate: Cdn$:U.S.$ 0.67 0.01 13 7 Interest rate 6.0%* 1% 1 0 - -------------------------------------------------------------------------------------------------------
* Borrowings with interest at variable rates averaging 6.0% at December 31. ENVIRONMENTAL REGULATION RISK/SUCCESS FACTORS Environmental legislation affects nearly all aspects of Suncor's operations. These regulatory regimes are laws of general application that apply to Suncor in the same manner that they apply to other companies and enterprises in the energy industry. They require Suncor to obtain operating licences and to impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments are required before initiating most new projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, Suncor expects further changes will likely be required. Some of the issues under discussion include the possible cumulative impacts of oil sands development in the Athabasca region; the need to reduce or stabilize various emissions; issues relating to global climate change and greenhouse gas, including the potential impacts of government regulation as it relates to these issues; land reclamation and restoration; water quality; and reformulated gasoline to support lower vehicle emissions. Changes in regulation could have an adverse effect on Suncor from the standpoint of product demand, product formulation and quality, and methods of production and distribution and cost of operations. For example, cleaner-burning fuels may be mandated, causing additional costs that 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 the Company. 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. SUNCOR ENERGY INC. 2000 ANNUAL REPORT 51 MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE LIQUIDITY AND CAPITAL RESOURCES Suncor's growth initiatives have increased net debt to $2.2 billion at December 2000 from $1.3 billion at December 1999. Capital investment from 2001 to 2003, including spending for the completion of Project Millennium, is currently planned in the $2.5 billion to $3 billion range. This is similar to the three-year period from 2000-2002. In light of the revised Project Millennium capital cost estimate of $2.8 billion and the unpredictability of crude oil prices, Suncor has arranged an additional $500 million credit facility for one year. Suncor management believes its sufficient borrowing capacity and cash flow from operations will be sufficient to fund the completion of Project Millennium and ongoing operations and investing activities. Crude oil prices, and to a lesser degree natural gas prices, and capital investing plans are important components in determining Suncor's yearly earnings and cash flow and net debt levels. In 2000, as in 1999, crude oil prices experienced extremes that were unanticipated. In 1999, the benchmark WTI price reached a low in the U.S.$10 per barrel range and reached a high of U.S.$40 per barrel at one point in 2000. Suncor management does not believe crude oil prices will be sustained at the 2000 price level of an average U.S.$30 per barrel. In the preparation of its business plan for the next three years, Suncor has used a crude oil price assumption that is below the consensus of third party consultants. Suncor's business plans are based on assumptions that are generally at the conservative end of the range of such assumptions. Suncor's financing and capital spending plans are based upon the following planning assumptions:
- ------------------------------------------------------------------------ RATIO OF NET DEBT/CASH FLOW FROM OPERATIONS 1996 1997 1998 1999 2000 - ------------------------------------------------------------------------ Number of times 0.9 1.4 2.2 2.3 2.3 - ------------------------------------------------------------------------
Ratio could remain in the 2.0-2.5 times range depending upon commodity price assumptions and the timely completion and successful implementation of Project Millenium. With the higher forecasted spending associated with Project Millennium, Suncor believes the debt/cash flow ratio could climb from its 2000 year-end level of 2.3 times to a short-term peak in the 3.5 times range. This reflects Suncor's current planning assumptions, especially the WTI price assumption. Utilizing assumptions for WTI that would average approximately U.S.$25 per barrel and a Henry Hub natural gas price assumption of U.S.$6.10, this ratio would be expected to be in the 2.0 - 2.5 times range. This is subject to the timely completion and successful implementation of Project Millennium and contingent on the Company's financial assumptions. Management believes expected increases in cash flow will reduce the debt/cash flow ratio to Suncor's long-term goal of 1.5 - 2.0 times range by the year 2002. Based upon the prior year's capital investment levels and currently planned future investment levels, Suncor does not expect its upstream operations to be cash taxable until the middle of the current decade.
- ----------------------------------------------------------------------------------------------------------- 2000 Actual Current Plan Last Year's Plan - ----------------------------------------------------------------------------------------------------------- PLANNING ASSUMPTIONS Average for Average next Average next the year 3-year range 3-year range - ----------------------------------------------------------------------------------------------------------- Crude oil - WTI U.S.$ per barrel 30.25 18.00 - 19.00 17.50 - 18.00 Natural gas - U.S.$/thousand cubic feet @ Henry Hub 3.90 3.00 - 3.50 2.45 - 2.55 Exchange rate: Cdn$:U.S.$ 0.67 0.69 - 0.71 0.68 - 0.70 - -----------------------------------------------------------------------------------------------------------
Note: The foregoing are planning assumptions and are not estimates or predictions of actual future events or circumstances. 52 SUNCOR ENERGY INC. 2000 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS - CORPORATE OPERATING COMMITMENTS Throughout Suncor's more than 30-year involvement in its Oil Sands operations in northern Alberta, it has had to invest in assets and related services that in more developed geographic areas would be provided by third parties. These include assets such as crude oil and natural gas pipelines, electrical and steam generation facilities and accommodation for contract workers. Suncor believes organizations with the specific expertise associated with such assets can provide more cost-effective services. As part of the Oil Sands growth initiatives, the Company will look to exit such businesses and obtain services from third parties whenever feasible. One example is Suncor's long-term agreement with TransAlta Energy Corporation to have that company build, own and operate a co-generation facility at Oil Sands with a portion of its output to help meet Suncor's long-term electricity and steam needs. While these existing arrangements, and any new arrangements, will continue to result in long-term operating commitments, the Company believes this approach has the potential to reduce operating and administrative expenses. DIVIDENDS During 2000, Suncor's quarterly common share dividend was $0.085 per share, unchanged from 1999 (after taking into consideration the two-for-one share split in the second quarter of 2000). Dividend levels are reviewed quarterly in light of Suncor's growth-related initiatives, financial position, financing requirements, cash flow and other factors considered relevant by the Board of Directors.
CAPITAL AND EXPLORATION INVESTING EXPENDITURES - ----------------------------------------------------------------------------------------------------- ($ millions) 2001 Plan 2000 Actual 1999 Actual - ----------------------------------------------------------------------------------------------------- OIL SANDS (EXCLUDING PROJECT MILLENNIUM) Sustaining capital 107 6 28 Environmental 8 1 1 Heavy oil - Firebag In-situ Oil Sands Project 124 33 40 Strategic Production improvements 60 132 203 Expansion 6 Steepbank 0 5 13 - ----------------------------------------------------------------------------------------------------- Total 299 177 291 - ----------------------------------------------------------------------------------------------------- PROJECT MILLENNIUM 450 1 631 806 - ----------------------------------------------------------------------------------------------------- NATURAL GAS Exploration 11 42 75 Development 60 65 75 Environmental 1 1 1 - ----------------------------------------------------------------------------------------------------- Subtotal finding and development capital 72 108 151 Coal bed methane 10 4 2 Other 18 15 7 - ----------------------------------------------------------------------------------------------------- Total 100 127 160 - ----------------------------------------------------------------------------------------------------- SUNOCO Refining and distribution 34 20 18 Retail marketing 24 21 19 Environmental 12 3 3 Other 3 1 2 - ----------------------------------------------------------------------------------------------------- Total 73 45 42 - ----------------------------------------------------------------------------------------------------- CORPORATE Stuart Oil Shale Project -- 18 51 Other -- -- -- Alternative and renewable energy 13 -- -- - ----------------------------------------------------------------------------------------------------- GRAND TOTAL 935 1 998 1 350 - ----------------------------------------------------------------------------------------------------- - -----------------------------------------------------------------------------------------------------
SUNCOR ENERGY INC. 2000 ANNUAL REPORT 53 EX-4 5 a2042188zex-4.txt EXHIBIT 4 EXHIBIT 4 QUARTERLY SUMMARY QUARTERLY SUMMARY (unaudited)
- ------------------------------------------------------------------------------------------------------------------------------ FINANCIAL DATA TOTAL TOTAL TOTAL FOR THE QUARTER ENDED YEAR FOR THE QUARTER ENDED YEAR FOR THE QUARTER ENDED YEAR MAR JUNE SEPT DEC MAR JUNE SEPT DEC MAR JUNE SEPT DEC ($ MILLIONS EXCEPT 31 30 30 31 31 30 30 31 31 30 30 31 per share amounts) 2000 2000 2000 2000 2000 1999 1999 1999 1999 1999 1998 1998 1998 1998 1998 - ------------------------------------------------------------------------------------------------------------------------------ REVENUES 779 820 862 927 3 388 469 564 639 715 2 387 543 498 531 498 2 070 - ------------------------------------------------------------------------------------------------------------------------------ NET EARNINGS (LOSS) Oil Sands 90 81 76 68 315 17 34 43 73 167 49 29 34 33 145 Natural Gas 8 16 43 31 98 3 13 20 5 41 3 4 7 10 24 Sunoco 19 20 19 23 81 5 3 12 7 27 7 16 7 7 37 Corporate and eliminations (12) (6) (88) (11) (117) (14) (17) (5) (13) (49) (12) (6) (1) (9) (28) - ------------------------------------------------------------------------------------------------------------------------------ 105 111 50 111 377 11 33 70 72 186 47 43 47 41 178 ============================================================================================================================== PER COMMON SHARE - net earnings attributable to common shareholders - basic 0.45 0.47 0.19 0.47 1.58 0.04 0.12 0.29 0.29 0.74 0.22 0.19 0.21 0.19 0.81 - diluted 0.45 0.47 0.19 0.46 1.57 0.04 0.12 0.29 0.28 0.73 0.22 0.19 0.21 0.18 0.80 ============================================================================================================================== - cash dividends 0.085 0.085 0.085 0.085 0.34 0.085 0.085 0.085 0.085 0.34 0.085 0.085 0.085 0.085 0.34 ============================================================================================================================== CASH FLOW PROVIDED FROM (USED IN) OPERATIONS Oil Sands 199 181 156 119 655 53 90 104 158 405 96 74 86 64 320 Natural Gas 48 42 64 84 238 42 43 39 48 172 39 36 42 50 167 Sunoco 46 38 49 41 174 23 17 37 26 103 24 39 26 23 112 Corporate and eliminations (24) (17) (40) (28) (109) (25) (21) (33) (10) (89) (15) (11) 16 (9) (19) - ------------------------------------------------------------------------------------------------------------------------------ 269 244 229 216 958 93 129 147 222 591 144 138 170 128 580 ==============================================================================================================================
EX-5 6 a2042188zex-5.txt EXHIBIT 5 EXHIBIT 5 [PRICEWATERHOUSECOOPERS LOGO] - -------------------------------------------------------------------------------- PRICEWATERHOUSECOOPERS LLP CHARTERED ACCOUNTANTS 425 1st Street SW Suite 1200 Calgary, Alberta Canada T2P 3V7 Telephone +1 (403) 509 7500 Facsimile +1 (403) 781-1825 Direct Fax (403) 781-1825 CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS We hereby consent to the incorporation, by reference, in the annual report of Suncor Energy Inc. on Form 40-F, of our report dated January 18, 2001 on our audits of the consolidated financial statements, including the additional information provided on Exhibit 1 to Form 40-F, as of December 31, 2000, 1999 and 1998. Chartered Accountants Calgary, Alberta February 28, 2001 COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have a material effect on the comparability of the company's financial statements, such as the changes described in Note 1 to the consolidated financial statements. Our report to the shareholders dated January 18, 2001 is expressed in accordance with Canadian reporting standards which to not require a reference to such a change in accounting principles in the auditors' report when the change is properly accounted for and adequately disclosed in the financial statements. "PRICEWATERHOUSECOOPERS LLP" Chartered Accountants January 18, 2001 AlmG:\AmacDona\RC\Suncor\Letters2001\Consent_Feb26 01 PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and other members of the worldwide PricewaterhouseCoopers organization. EX-6 7 a2042188zex-6.txt EXHIBIT 6 EXHIBIT 6 LETTER OF CONSENT TO: Suncor Energy Inc. The Securities and Exchange Commission The Securities Regulatory Authorities of each Province of Canada RE: SUNCOR ENERGY INC. We refer to the following reports prepared by Gilbert Laustsen Jung Associates Ltd.: o the letter reports dated January 15, 2001, as to the synthetic crude oil reserves effective December 31, 2000 associated with the Suncor Energy Inc. oil sands operations located near Fort McMurray, Alberta; o the Reserve Determination and Evaluation of the Canadian Oil and Gas Properties of Suncor Energy Inc. Natural Gas effective December 31, 2000, dated January 26, 2001; o the Suncor Energy Inc. Natural Gas Constant Price Analysis effective December 31, 2000, dated January 24, 2001; (collectively the "Reports") We hereby consent to the use of our name, reference to and excerpts from the said reports by Suncor Energy Inc. in its Annual Information Form for the 2000 fiscal year (AIF), and to the incorporation by reference of the AIF in the annual report of Suncor Energy Inc. on Form 40-F. We have read the AIF and have no reason to believe that there are any misrepresentations in the information contained in it that is derived from our Reports or that are within our knowledge as a result of the services which we performed in connection with the preparation of the Reports. Yours very truly, GILBERT LAUSTSEN JUNG ASSOCIATES LTD. "WAYNE CHOW" Wayne W. Chow, P. Eng. Vice-President Calgary, Alberta Date: February 28, 2001 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SUNCOR ENERGY INC. Date: March 23, 2001 BY: "MICHAEL W. O'BRIEN" ----------------------------------- MICHAEL W. O'BRIEN Executive Vice President, Corporate Development and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----