Enbridge
Annual Report 2002

Plain-text annual report

Enduring Values, Sustainable Growth 2 0 0 2 A n n u a l R e p o r t Highlights 01 Letter to Shareholders 02 An Enbridge Profile 05 Management , s Discussion and Analysis 14 Financial Statements and Notes 39 Supplementary Information 70 Shareholder, Investor and Corporate Information 73 When used in this annual report, the words “anticipate”, “expect”, “project”, “believe”, “estimate”, “forecast” and similar expressions are intended to identify forward looking statements, which include statements relating to pending and proposed projects. Such statements are subject to certain risks, uncertainties and assumptions pertaining to operating performance, regulatory parameters, weather and economic conditions and, in the case of pending and proposed projects, risks relating to design and construction, regulatory processes, obtaining financing and performance of other parties, including partners, contractors and suppliers. * “At Enbridge, we pride ourselves on our consistent, predictable and sustainable growth. We also pride ourselves on our corporate values: it has been Enbridge’s adherence to its principles and culture that has enabled the Company to succeed in spite of the crisis of confidence that has engulfed markets for over a year. Of course, values are embodied in people, not structures. And that is why we have focused on the people of Enbridge in this year’s annual report. It is our employees, our senior management team and our Board of Directors who live our values, and in so doing continue to grow Enbridge and add value for our shareholders.” Patrick D. Daniel. President & Chief Executive Officer The photographs on the front cover represent the diversity of the people of Enbridge. Most are employees, representing all business units, all job levels, all major geographic areas of operation. Others are key stakeholders — customers, neighbours and shareholders. Collectively, they are “Enbridge”. * ENBRIDGE, the ENBRIDGE LOGO and the ENBRIDGE ENERGY SPIRAL are trademarks or registered trademarks of Enbridge Inc. in Canada and other countries. H I G H L I G H T S H i g h l i g h t s Dividends Per Common Share (dollars per share) Earnings Per Common Share (dollars per share) 0 0 0 . 1 0 0 0 . 1 0 0 0 . 1 5 1 0 . 1 0 6 0 . 1 0 2 1 . 1 5 9 1 . 1 0 7 2 . 1 0 0 4 . 1 0 2 5 . 1 5 1 . 1 5 4 . 1 8 5 . 1 6 6 . 1 1 9 . 1 4 5 . 2 1 9 . 2 0 6 . 3 5 1 0 . 1 5 4 5 . 0 93 94 95 96 97 98 99 00 01 02 93 94 95 96 97 98 99 00 01 02 Financial (millions of Canadian dollars, except per share amounts) Earnings Applicable to Common Shareholders Continuing Operations Discontinued Operations Per Common Share Amounts Earnings — Continuing Operations Earnings — Discontinued Operations Dividends Common Share Dividends Paid Return on Average Common Shareholders’ Equity Debt to Debt Plus Shareholders’ Equity at Year End Operating Energy Transportation 1 Deliveries (thousands of barrels per day) Barrel miles (billions) Average haul (miles) Energy Distribution 2 Volume of gas distributed (billion cubic feet) Number of active customers (thousands) Degree day deficiency 3 (degrees Celsius) Actual Forecast based on normal weather 1 2002 334.2 242.3 576.5 2.09 1.51 3.60 1.52 251.1 19.9% 64.4% 2002 2,088 705 925 410 1,623 3,362 3,700 2001 413.2 45.3 458.5 2.63 0.28 2.91 1.40 227.5 18.6% 72.9% 2001 2,109 695 903 427 1,571 3,766 3,816 2000 357.7 34.6 392.3 2.32 0.22 2.54 1.27 202.1 18.6% 69.4% 2000 2,072 735 972 421 1,520 3,569 3,929 1 Energy Transportation operating highlights include the statistics of the Lakehead System and wholly-owned liquid pipeline operations. 2 Highlights of Energy Distribution reflect the results of Enbridge Gas Distribution and other gas distribution operations on a quarter lag basis for the years ended September 30, 2002, 2001 and 2000. Energy Distribution volumes and the number of active customers are derived from the aggregate system supply and direct purchase gas supply arrangements. 3 Degree day deficiency is a measure of coldness. It is calculated by accumulating for each day in the period the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Toronto area. E N B R I D G E I N C . L e t t e r t o S h a r e h o l d e r s L E T T E R T O S H A R E H O L D E R S Enbridge has come through the most turbulent year in the history of the pipeline and utility sector in a very strong position relative to our North American peer group. Although our total return to shareholders over the year was only 1.5%, compared to our ten-year average of more than 15%, we did very well relative to an 11% decline in the value of stocks listed on the Toronto Stock Exchange, a 20% decline in the New York Stock Exchange Composite Index, and a 33% decline in the U.S. pipeline index. Our relative strength came from an unwavering vision, a focus on asset management, and low-risk projects. Where the companies in our sector sought higher risk businesses such as commodity marketing and trading to meet growth targets, Enbridge did not. We stuck to our core competencies of liquids pipelining, gas distribution and gas pipelining, which continue to provide high single digit growth in earnings per share. As a result of excellent future earnings potential from these businesses, we remain committed to the strategy that has made us one of North America’s leading energy delivery companies. We strive to be the best in this sector, as measured 2 by total shareholder return and return on equity over a sustained period. In 2002, not only did we grow our earnings to a record level of $576.5 million, an 8% increase in adjusted earnings per share, we also reduced debt substantially. Our consolidated debt-to-equity leverage has gone from approximately 72% to 64% and will be further reduced in 2003. We achieved the debt reduction through strong cash flow from operations, sale of non-core assets including our Energy Services business and Cornwall Electric, and new equity issuances. Our confidence in the future growth of the Company is exemplified by our excellent 10-year track record of dividend growth. In January 2002 we increased the dividend by 8.6%, and in January 2003 another 9% to $0.415 per common share per quarter. Over the past year we have made significant progress in each of our five major growth platforms. Firstly, we continued the expansion of our crude oil pipeline system by embarking on Phase III of our Terrace project which is on schedule and on budget to add about 10% to our delivery capacity of 1.7 million barrels per day in 2003. This new capacity will serve Alberta’s oil sands, where billions of dollars will be spent over the next decade to produce crude oil for U.S. and Canadian markets. Security of supply issues in the U.S. resulting from disruptions in supply from Venezuela and the Middle East will increase demand for reliable Canadian crude. Our pipeline system carries about 65% of the crude from the oil sands through the world’s longest crude oil pipeline. We also are very well positioned through our Norman Wells pipeline in the North to participate in and benefit from any liquids production associated with the huge gas reserves of the Mackenzie Delta. E N B R I D G E I N C . L e t t e r t o S h a r e h o l d e r s Our second growth platform — natural gas distribution — also is experiencing consistently strong expansion. We have added more than 50,000 new customers every year for the past six years, making Enbridge Gas Distribution one of North America’s fastest growing utilities. Rapid growth in the metropolitan Toronto area is forecast to continue for several years. Thirdly, our natural gas pipelining business was expanded significantly in 2002 as we increased our ownership position in the Alliance Pipeline from approximately 21% to over 37%. Alliance and Vector Pipeline supply key markets in Eastern Canada and the U.S. Midwest, and are well positioned to benefit from future natural gas production from northern gas in Prudhoe Bay and the Mackenzie Delta. Our extensive northern operating experience also should enable us to be of service to gas producer customers in the North. With our strong core businesses, excellent growth potential and corporate values, we are very well positioned to continue to provide excellent returns to you, the Enbridge shareholder. 3 Enbridge’s fourth growth platform is our master limited partnership, Enbridge Energy Partners, L.P. (EEP) which holds not only the U.S. portion of our crude oil pipeline, but now also the gas pipeline and midstream assets formerly owned by Enbridge Midcoast Energy. EEP’s future will be driven by increasing crude oil volumes from the oil sands as well as its interstate gas pipelines, end-user pipelines, gas gathering systems and processing plants. In addition to organic volume growth, EEP will seek small to medium-sized “bolt-on” asset acquisitions in our areas of influence — the Gulf Coast and Midwest regions of the U.S. Enbridge’s international operations have become our fifth growth platform and have provided consistent, reliable earnings from equity investments in Colombia and Spain. We are very cautious and disciplined in seeking international projects, and are not embarrassed at having made only two significant investments in the past ten years. Our expertise and niche as one of the world’s largest independent crude oil pipeline companies makes Enbridge a very favourable business partner. Our technology consulting company and fee-based operations provide a low-cost way of evaluating new prospective projects. We will continue our focus on energy delivery assets, which provide low-risk investments with consistent returns. Over 95% of our operating income currently comes from such operations. In addition to continued expansions and extensions to our core businesses, we intend to grow along the value chain by adding terminalling, E N B R I D G E I N C . L e t t e r t o S h a r e h o l d e r s storage, and feeder systems. As our North American footprint expands, we reduce the risk to shareholders by broadening the geographic areas in which we are involved and increasing the number of production basins and energy markets we serve. We continue to focus on operating efficiencies to provide the lowest possible tolls to our customers — our gas distribution company has the lowest operating cost per unit of throughput of any in North America, and our crude oil pipeline is among the very lowest in the world in terms of tolls per barrel mile. Through modest investments in renewable energy and by reducing our direct greenhouse gas emissions to levels below our 1990 levels, we will help meet the global challenge of climate change. We also will continue to work for more effective engagement of the consuming public in the climate change solution. The past accomplishments of Enbridge and our confidence in our future are largely attributable to our talented employee base of approximately 4,000 people. We hire as much on values as on skills. Never has that been more important than it was in 2002. We thank our employees for maintaining a culture and set of values that is critical to sustaining confidence in Enbridge and its operations. 4 With our strong core businesses, excellent growth potential and corporate values, we are very well positioned to continue to provide excellent returns to you, the Enbridge shareholder. We also wish to thank two individuals who have served Enbridge so long and so well. Brian F. MacNeill, who retired in December 2000 after almost a decade as Chief Executive Officer of the Company, has decided not to stand for re-election to the Enbridge Board. Derek P. Truswell, Group Vice President & Chief Financial Officer of Enbridge, is retiring effective April 1, 2003, after more than 34 years with the Company. Both of them will be missed for their leadership, counsel and many contributions to Enbridge’s success. On behalf of the Board of Directors: Donald J. Taylor Patrick D. Daniel Chair of the Board of Directors President & Chief Executive Officer March 4, 2003 E N B R I D G E I N C . P r o f i l e Enbridge is . . . a leading North American energy delivery company an experienced and knowledgeable asset manager a company with a reputation for excellent growth prospects and a low-risk profile a company with a track record of adding value for its shareholders Enbridge Inc. conducts its business through a number of distinct business units, focused on the Company’s core businesses — crude oil and liquids pipelines, natural gas pipelines, and natural gas distribution. 5 7 The Company is active internationally, but the bulk of its assets are in Canada and the United States. ENBRIDGE: ❚ has its head office in Calgary, Alberta, and employs approximately 4,000 people primarily in Canada and the United States. In 2002, Enbridge: ❚ delivered approximately 2.1 million barrels In North America, Enbridge owns, operates or has interests in: approximately 21 000 kilometres (13,000 miles) of crude oil mainline and feeder pipelines, approximately 15 500 km (9,600 miles) of natural gas transmission and gathering pipelines, and of crude oil and liquids per day, and approximately 30 000 km (18,600 miles) of mains ❚ distributed approximately 410 billion cubic for transportation and distribution of natural gas. feet of natural gas during the year. E N B R I D G E I N C . ❚ ❚ ❚ ❚ ❚ ❚ ❚ ❚ P r o f i l e E N E R G Y T R A N S P O R T A T I O N N O R T H E N E R G Y T R A N S P O R T A T I O N S O U T H “ Unprecedented growth in oil sands production is driving a wide “ We are focused on long-term growth through expanding 6 variety of opportunities for us. Our recent mainline expansions existing liquids and natural gas systems and acquiring will fill, requiring further capacity increases. In the oil sands mature energy transportation assets. There are numerous region, we’ll add additional pipeline capacity, tankage, laterals potential acquisition opportunities available in the and cavern storage. To capture the full production potential, United States, and the Partnership provides a competitive we will extend the reach of our mainline system to access cost-of-capital vehicle for participation in this active energy new markets for Canadian crude.” infrastructure market.” J. Richard Bird Dan C. Tutcher Group Vice President, Transportation North Group Vice President, Transportation South Energy Transportation North includes Enbridge Energy Transportation South is responsible for Pipelines, which owns and operates the Canadian the Company’s energy delivery businesses in the portion of the Enbridge crude oil mainline and United States. Enbridge holds an effective 14.1% operates the Lakehead and North Dakota systems interest in Enbridge Energy Partners, L.P., which in the United States. Energy Transportation North owns energy transportation and midstream systems also is responsible for Enbridge’s interests in the including overland transportation and pipeline Alliance and Vector natural gas pipelines, and the gathering, transmission, processing and treating midstream natural gas business in Western Canada. businesses in the upper Midwest, Midcontinent and Gulf Coast areas. E N B R I D G E I N C . E N E R G Y D I S T R I B U T I O N I N T E R N A T I O N A L P r o f i l e “ Enbridge has delivered natural gas to communities in “ Enbridge’s existing international investments are located in Ontario for more than 150 years. Our role in the Ontario Western Europe and Latin America. In addition to these regions, 7 market has changed, but our commitment to service a we are open to evaluation of high-potential investments or steadily expanding franchise area remains the same. operating opportunities that arise elsewhere. We maintain a We will continue to deliver a safe, reliable supply of disciplined focus on equity, operating and technology projects natural gas to all of our customers.” that build upon our core expertise, and continue to develop Stephen J.J. Letwin strong affiliation relationships with our partners.” Group Vice President, Distribution & Services Mel F. Belich Group Vice President, International The core of Enbridge’s Energy Distribution business Enbridge’s international activities, including CLH segment is Enbridge Gas Distribution, which delivers in Spain and OCENSA in Colombia, are developed natural gas to more than 1.6 million customers in and co-ordinated by wholly-owned Enbridge Ontario, Quebec and part of New York State. International Inc. The International Group is Enbridge is also involved in the gas distribution supported by other units within the Enbridge group business through its interest in Noverco Inc. and of companies, including Enbridge Technology Inc., is developing a natural gas distribution network which is engaged in technical advisory services, in the Province of New Brunswick through contract operations, product sales and training Enbridge Gas New Brunswick. services which are provided to pipeline and natural gas distribution industries globally. E N B R I D G E I N C . P r o f i l e E N E R G Y T R A N S P O R T A T I O N N O R T H Norman Wells Zama Edmonton Hardisty Kerrobert Fort McMurray Regina Cromer Gretna Montreal Westover Sarnia Toronto Buffalo Fort St. John Edmonton Chicago Dawn Liquids Pipelines ❚ Enbridge Pipelines Inc. ❚ Enbridge Pipelines (NW) Inc. ❚ Enbridge Pipelines (Athabasca) Inc. ❚ Enbridge Pipelines (Saskatchewan) Inc. Natural Gas Pipelines ❚ Alliance Pipeline Limited Partnership (37.1%) ❚ Vector Pipeline Limited Partnership (45%) Other ❚ AltaGas Services Inc. (40.3%) 8 E N E R G Y T R A N S P O R T A T I O N S O U T H Gretna Clearbrook Superior Casper Salt Lake City Lockport Mokena Lewiston Sarnia Bay City Chicago Toledo Patoka Houston Enbridge Energy Partners, L.P. (14.1%) Lakehead System ❚ North Dakota System ❚ Midcontinent and Gulf Coast Systems ❚ Enbridge Pipelines (Toledo) Inc. ❚ Mustang Pipe Line Partners (30%) ❚ Chicap Pipe Line Company (22.8%) Frontier Pipeline Company (77.8%) E N B R I D G E I N C . ❚ ❚ E N E R G Y D I S T R I B U T I O N I N T E R N A T I O N A L P r o f i l e Ottawa Toronto Montreal Vermont Coveñas Bogota C O L O M B I A Jose Terminal Cusiana/ Cupiagua ❚ Enbridge Gas Distribution Inc. Gazifère Inc. — an Enbridge Company Niagara Gas Transmission Limited — an Enbridge Company St. Lawrence Gas Company, Inc. — an Enbridge Company ❚ Noverco Inc. (32%), which owns: Gaz Métropolitain and Company, Limited Partnership (77%), which owns: Vermont Gas Systems, Inc. (100%) TQM Pipeline and Company, Limited Partnership (50%) ❚ Enbridge Gas New Brunswick Limited Partnership (63%) ❚ Aux Sable Liquids Products Inc. (30.9%) S P A I N Madrid Barcelona 9 Enbridge International Inc. ❚ Oleoducto Central S.A. — OCENSA (24.7%) ❚ Compañia Logistica de Hidrocarburos CLH, S.A. (25%) Enbridge Technology Inc. (global contracts) S U S T A I N A B L E A N D O T H E R B U S I N E S S D E V E L O P M E N T O P P O R T U N I T I E S ❚ SunBridge Wind Power Project (50%) Global Thermoelectric Inc. (strategic alliance) Inuvik Gas Ltd. (33.3%) Tidal Energy Marketing Inc. (50%) NetThruPut Inc. (52%) ❚ Proposed Northern Natural Gas Pipelines E N B R I D G E I N C . Prudhoe Bay Norman Wells Whitehorse Inuvik Fort Simpson Fort St. John Gull Lake ❚ P r o f i l e P L A N N I N G & D E V E L O P M E N T “ Our goal is to continue to position Enbridge for profitable growth. Our strategic planning process identifies those opportunities we can reasonably pursue over the next five years. And for the longer term, we are positioning Enbridge to participate in frontier energy development, emerging energy technologies, and sustainable development projects.” Stephen J. Wuori Group Vice President, Planning & Development 10 Climate Change In December 2002, Canada ratified the Kyoto Protocol, a 1997 treaty designed to reduce greenhouse gas emissions to 6% below 1990 levels. Enbridge is currently assessing and evaluating the federal government’s approach to implementation. Until these plans become certain, the Company will not be able to quantify the impact, if any, on its operations. From a supply perspective, however, we are encouraged by recent producer reactions, particularly their commitment to sustained oil sands development. Enbridge believes that climate change is a global issue that needs to be addressed today and into the future. As a leader in the energy sector, Enbridge will work to ensure that its activities are part of the solution to the climate change challenge. In November 2002, Enbridge President & Chief Executive Officer Pat Daniel delivered a presentation as part of the University of Calgary’s Kyoto Forum entitled Kyoto: A Call to Engage Canadians. The following are excerpts: ❚ “At Enbridge ... we are committed to taking actions to reduce greenhouse gas emissions throughout the company and its subsidiaries, and we have been a willing and active participant in the Climate Change Voluntary Challenge and Registry.” ❚ “Enbridge has set targets to reduce direct emissions from operations in Canada, and we are aggressively pursuing energy efficiencies that will reduce our consumption of electricity, a source of indirect greenhouse gas emissions.” ❚ “We can’t succeed without the people of Canada, who make the choices every day about energy consumption and about goods and services that drive energy demand and energy production.” ❚ “Worldwide, our societies demonstrate an increasing appetite for energy, and the issue of emissions reductions cannot be resolved successfully without the engagement of citizens as consumers of energy products and services. We must do this in new ways that promote public awareness — encourage the efficient use of energy — and support the development of alternative forms of energy.” E N B R I D G E I N C . C O R P O R A T E R E S O U R C E S P r o f i l e “ One of the many resources we employ at Enbridge for managing risk throughout the enterprise is a committed, hard-working and ethical work force. We have that from the Board level on down, and we maintain and strengthen that resource with clearly articulated corporate values and a Company-wide code of business conduct.” Bonnie D. DuPont Group Vice President, Corporate Resources Corporate Governance Enbridge considers the diverse nature of its mixture of corporate governance “best practices” to be a strength. Over the course of the past five years, the evolution of Enbridge’s corporate governance policies and practices has resulted in numerous accomplishments that we have shared with others who have indicated that they consider us to be leaders in this field. In 2002, Enbridge was recognized for its commitment to corporate governance when it was ranked fourth best in Canadian Business magazine’s listing of the Best & Worst Boards in Canada. The Board of Directors of Enbridge functions independent of management and is accountable to shareholders. The Board has delegated to the Governance Committee the role of overseeing corporate governance generally, and Enbridge has demonstrated vision and a comprehensive approach to governance through the integration of empowerment and accountability involving all employees up to the Board of Directors and ultimately to shareholders. 11 Enterprise-wide risk assessment and mitigation are management tools which keep Enbridge accountable to shareholders and responsible to our social environment. Enbridge uses a Corporate Risk Assessment process to identify operational risks throughout the organization. This, in turn, leads to an enterprise-wide risk mitigation strategy. The risk assessment is presented annually to the Audit, Finance & Risk Committee, which is separate from the Governance Committee. Strong financial results and operational accomplishments are the measurable evidence of these stewardship strengths. Additional information about Enbridge’s corporate governance practices is available in the Company’s Management Information Circular. E N B R I D G E I N C . P r o f i l e CORPORATE SOCIAL RESPONSIBILITY — ENBRIDGE IN THE COMMUNITY At Enbridge, we are committed to excellence in implementing standards that not only comply with legislated requirements but also respond to the social, economic and environmental needs of the communities where we operate, our customers, shareholders, governments and the public. Social responsibility — the safety of our employees and the public; a clean and healthy environment; and strong, vibrant communities — is one of our core values. We are committed to sustaining these essential values through socially responsible operations and involvement in our communities. Employees, senior management and our Board of Directors are all guided by the Company’s Statement on Business Conduct. Adherence to this code of conduct, which incorporates the internationally recognized Voluntary Principles on Security and Human Rights, is a condition of employment, and at home and abroad, this document outlines the expected standards of behaviour and ethics in all our business endeavours. COMMUNITY INVESTMENT In 2002, Enbridge invested $3 million in communities. Our goal is to foster long-term relationships, encourage community-mindedness and involvement by employees, and help create vibrant, healthy places for people to live. Investing in Health and Social Services For the fourth consecutive year, Enbridge employees across Canada and the United States raised more than $1 million for United Way campaigns and was recognized in Canada as a Thanks A Million corporate donor. Additionally, as the title sponsor of the Enbridge CN Tower Stair Climb, the Company helped garner the support of 10,000 climbers to raise $830,000 for the United Way of Greater Toronto. 12 The country’s health system is a top public policy issue for Canadians, and Enbridge Gas Distribution supports a variety of health-related organizations including the Ottawa Regional Cancer Centre, St. Elizabeth Health Care, Princess Margaret Hospital and the Rouge Valley Health System. Enbridge also supports youth volunteerism and leadership at The Hospital for Sick Children in Toronto. In 2002, Enbridge continued to provide funding to Health Smart Solutions, which raises money for hospitals in the Alberta Capital Region. The Company contributed to the Stanton Regional Hospital Foundation in the Northwest Territories; the Lambton Hospitals Foundation in Sarnia, Ontario; and the Northern Lights Health Region in Fort McMurray, Alberta. Enbridge also contributed to That All May Read, a nationwide CNIB program that provides play-back equipment to children and adults with vision loss, and provided support for Discovery House, a shelter for victims of family violence in Calgary. Enbridge youth-oriented programs included a new partnership in 2002 with Ottawa’s Christie Lake Kids, and ongoing support for Eva’s Initiatives to help Toronto’s homeless youth. Investing in Education In Calgary, Enbridge supported the annual Word on the Street program and Calgary Reads, which drew attention to literacy issues. In Ontario, Enbridge provided funding to the Barrie Literacy Council to help increase its volunteer base. Enbridge supports the Student Mentoring Program, created six years ago to help students in the Inuvialuit Settlement Region in the N.W.T. continue their studies so they can become scientists and resource managers to ensure the effective management of fish and marine mammals so important to the region. E N B R I D G E I N C . P r o f i l e Investing in the Environment In Ontario, Enbridge Gas Distrbution continued to provide aggressive demand-side management (DSM) programs that encourage and enable customers to use natural gas more efficiently. As part of this program, Enbridge offers rebates on the purchase of energy- saving heating equipment in homes, identifies solutions for plant operations and promotes energy- efficient design in the building industry. Since 1995, DSM programs have resulted in “avoided” emissions of approximately 900,000 tonnes of CO 2. Enbridge continued to support the City of Toronto’s annual Smog Summit and Pollution Probe’s Clean Air Campaign, to improve air quality through public education, advertising, advocacy and special events. Enbridge also invested in WindShare, which is building two wind turbines on the Toronto waterfront. In 2002, funding was provided through the Enbridge Environmental Initiatives Program to 34 community projects along the Enbridge Pipelines right-of-way. Projects included planting trees and shrubs to provide wildlife habitat and beautify parkland, and purchasing environmental education software for a library in Hardisty, Alberta. In Alberta, Enbridge entered into three-year partnerships with FEESA, An Environmental Education Society, to bring a climate change curriculum to schools along the pipeline right-of-way, and the Pembina Institute for Appropriate Development to develop an online climate change educational program. Investing in Leadership Development Enbridge continued to provide funding and voluntary participation in the development of community leadership programs in Calgary, Edmonton, Regina, Ottawa and Fredericton. Enbridge also funded and participated in the 2002 Toronto City Summit, which brought together more than 150 leaders from various community sectors, Social Vision Statement “We’re Enbridge. In partnership with our communities, we deliver more than energy; we deliver on our commitment to enhance the quality of life in our communities by supporting programs in health, education, social services and the environment. Together with our employees we have the energy to make a difference.” 13 including all three levels of government, to discuss issues and identify solutions to chart the city’s future. Volunteerism at Enbridge Over the past year, Enbridge has supported various volunteer resource programs across Canada, including Edmonton’s Stollery Children’s Hospital Foundation, and the Enbridge Volunteers in Partnership (VIP) Centre in York Region north of Toronto. In Calgary, Enbridge’s VIP employee initiative continued to support high-risk families facing homelessness. And in Edmonton, employees and their families contributed more than 13,000 volunteer hours to the community. Community Safety and Emergency Response In the United States, Enbridge Energy Partners developed a 911 Fund to honor the heroes and victims of the September 11, 2001, tragedy. The 911 Fund provides grants to first responder organizations — fire departments, emergency medical services, police and sheriff’s departments located in the U.S. In Canada, volunteer fire departments in a number of communities received Enbridge funding. Enbridge also supported the County of Strathcona Fallen Fire Fighters Memorial Fund and the Ontario Fire Marshal’s Team Up for Fire Safety campaign. Supporting Vibrant Communities Enbridge Gas Distribution’s involvement in the communities it serves helps create a long-term positive relationship with customers and municipalities. In 2002, the Company supported more than 400 events that provided opportunities to deliver safety and energy- efficiency information to more than 1.6 million people. E N B R I D G E I N C . M D & A M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S Earnings Applicable to Common Shareholders (millions of dollars) Return on Average Common Shareholders’ Equity (%) 8 . 0 8 6 . 3 4 4 . 0 3 1 3 . 0 8 1 3 . 7 1 2 9 . 0 4 2 9 . 7 8 2 3 . 2 9 3 5 . 8 5 4 5 . 6 7 5 7 . 7 1 5 . 9 2 . 3 1 0 . 5 1 2 . 4 1 8 . 3 1 3 . 4 1 6 . 8 1 6 . 8 1 9 . 9 1 93 94 95 96 97 98 99 00 01 02 93 94 95 96 97 98 99 00 01 02 14 C O N S O L I D A T E D R E S U L T S FINANCIAL HIGHLIGHTS (millions of Canadian dollars, except per share amounts) Earnings Applicable to Common Shareholders Energy Transportation North Energy Transportation South Energy Distribution International Corporate Earnings from continuing operations Discontinued operations Earnings Per Share Earnings — Continuing operations Earnings — Discontinued operations Dividends Per Share Common Share Dividends 2002 2001 2000 236.2 (41.4) 113.8 68.0 (42.4) 334.2 242.3 576.5 2.09 1.51 3.60 1.52 205.1 46.4 181.8 35.6 (55.7) 413.2 45.3 458.5 2.63 0.28 2.91 1.40 192.6 23.3 203.2 26.4 (87.8) 357.7 34.6 392.3 2.32 0.22 2.54 1.27 251.1 227.5 202.1 E N B R I D G E I N C . M D & A “ Enbridge had another very successful year in 2002. Adjusted earnings per share growth of 8% was in our target range. We significantly delevered the balance sheet, strengthening our financial position. Our plans include further debt reductions in 2003. From a financial perspective, we are well-positioned to execute our strategy going forward. From a shareholder perspective, we were able to increase the dividend paid to shareholders by 8.6% in 2002 and increased it again by 9% for 2003.” Derek P. Truswell Group Vice President & Chief Financial Officer Earnings applicable to common shareholders (earnings) for the year ended December 31, 2002 were $576.5 million, or $3.60 per common share, compared with $458.5 million, or $2.91 per common share, in 2001. Liquids pipelines and international operations contributed to the growth in earnings, along with higher equity earnings from Enbridge Energy Partners, L.P. (EEP). These increases were offset in part by lower earnings from Enbridge Gas Distribution (Enbridge Gas) due to warmer weather in 2002 than in 2001. Earnings for 2002 also included an after-tax gain of $240.0 million from the sale of the Energy Services business and an after-tax loss of $82.2 million on assets sold to EEP, included in Energy Transportation South. Prior year’s earnings included the benefit of $58.5 million related to income tax rate reductions. As shown below, after adjusting for significant one-time gains or losses and the impact of weather, earnings for the year ended December 31, 2002 were $428.4 million, compared with $387.8 million for 2001. 15 (millions of Canadian dollars, except per share amounts) Earnings applicable to common shareholders Gain on sale of Energy Services business Loss on sale of Enbridge Midcoast Energy assets Gain on sale of securities Weather Dilution gains Tax rate reductions Other Adjusted earnings Adjusted earnings per share Adjusted diluted earnings per share 2002 576.5 (240.0) 82.2 (17.8) 29.3 (6.1) (1.4) 5.7 428.4 $2.67 $2.64 2001 458.5 – – – (5.0) (15.2) (58.5) 8.0 387.8 $2.47 $2.44 2000 392.3 – – – 22.1 – (94.9) 15.6 335.1 $2.17 $2.16 E N B R I D G E I N C . M D & A Enbridge had several significant achievements during the year. ❚ The acquisition of a 25% interest in Compañia Logistica de Hidrocarburos CLH, S.A. (CLH) was completed in the first quarter. CLH is Spain’s largest refined products transportation and storage business. In May, Enbridge sold its Energy Services business for cash proceeds of $1 billion. ❚ The Company closed the sale of the United States assets of Enbridge Midcoast Energy to EEP for consideration of US$820 million. Concurrent with the sale, Enbridge Energy Management, L.L.C. (EEM) completed an initial public offering of shares, the proceeds of which were used to purchase i-units in EEP. The Company’s interests in EEP and EEM collectively are referred to as the Partnership. Bitumen production from MacKay River was connected to the Athabasca System in 2002. In the fourth quarter, the Company increased its ownership interest in Alliance to 37.1% through the purchase of a 9.6% interest from The Williams Companies Inc. (Williams) and a 6.1% interest from El Paso Corporation (El Paso). Enbridge will acquire an additional 1.1% interest in Alliance from El Paso at the end of the first quarter of 2003. As part of the El Paso transaction, Enbridge’s interest in the Aux Sable natural gas processing facility increased to approximately 30.9%. 16 Earnings from continuing operations for the year ended December 31, 2002 were $334.2 million, or $2.09 per share, compared with $413.2 million, or $2.63 per share, in 2001. Growth in earnings from the liquids pipelines and international operations, as well as higher earnings from the Partnership were more than offset by the loss on sale of the United States assets of Enbridge Midcoast Energy, warmer weather than 2001, and the positive impact on earnings of income tax rate reductions in 2001. For the year ended December 31, 2001, earnings from continuing operations were $413.2 million, or $2.63 per share, compared with $357.7 million, or $2.32 per share, in 2000. The higher earnings reflect improved operating results from Enbridge Gas and the Enbridge System. The acquisition of Midcoast Energy Resources, Inc. also contributed to higher earnings. In addition, the Company realized dilution gains from the issuance of units by EEP and improved results from corporate activities. These increases were partially offset by higher financing costs, a reduced contribution from Vector, a higher loss from Aux Sable, and income tax rate reductions that had a smaller positive impact on earnings in 2001 than 2000. Dividends paid on common shares increased in each of the last three years from growth in the dividend per share and a higher number of outstanding common shares. The quarterly dividend per share increased to $0.38 in the first quarter of 2002 from $0.35 per share established in the first quarter of 2001. In the second quarter of 2000 the quarterly dividend was raised to $0.3225. This represents increases of 8.6%, 8.5% and 6.6%, respectively, and reflects the sustained growth in earnings over the period. In 2002, the Company changed its financial reporting segments to conform with changes in senior management responsibilities. The gas services business and the investment in Aux Sable are included in Energy Distribution. All financial information has been restated to reflect the new segments. E N B R I D G E I N C . ❚ ❚ M D & A C O R P O R A T E S T R A T E G Y Enbridge’s resources are focused on three broad strategic thrusts and three areas of increased emphasis. The major strategies are to: enhance profitability through adoption and maintenance of incentive-based rate mechanisms to maximize benefits for customers and shareholders; expand and extend the core liquids and gas distribution businesses through greenfield development or acquisitions; and ❚ develop or acquire businesses that are complementary to the core businesses. Strategic emphasis is placed on increasing the Company’s North American footprint, increasing the scale of operations and developing and applying new technologies. Enbridge’s proposed actions with respect to these strategies are described in the “Outlook” for each business unit. The achievement of the Company’s major strategies is dependent on successful mitigation of business risks, discussed in each of the business segments. Enbridge believes it has identified and mitigated the risks, to the extent practical. Enbridge remained on track with the implementation of its strategy in 2002 and is committed to identifying and implementing the actions required to create value and sustainable growth. E N E R G Y T R A N S P O R T A T I O N N O R T H 17 FINANCIAL RESULTS (millions of Canadian dollars) Enbridge System Athabasca System NW System Saskatchewan System Alliance Pipeline Vector Pipeline Other 2002 123.7 41.2 9.5 6.4 40.7 7.1 7.6 236.2 2001 111.1 29.9 9.5 5.9 37.6 3.9 7.2 205.1 2000 98.3 27.7 10.7 9.5 28.4 11.2 6.8 192.6 BUSINESS ACTIVITIES Energy Transportation North activities include the liquids pipelines operations in Canada and the Company’s equity interests in gas transmission pipelines and AltaGas, a company engaged in natural gas gathering and processing. The mainline pipeline, comprised of the Enbridge System and the Lakehead System (the portion of the mainline pipeline in the United States operated by Enbridge and owned by EEP), is the world’s longest crude oil pipeline system and is the primary transporter of crude oil from Western Canada to the United States. It is the only pipeline that transports crude oil from western to eastern Canada and serves all of the major refining centres in the Province of Ontario, as well as the Midwest region of the United States. Additional tankage and facilities were constructed at the Athabasca terminal in Fort McMurray. E N B R I D G E I N C . ❚ ❚ M D & A Enbridge also owns the Athabasca System, the NW System and the Saskatchewan System. The Athabasca System is a 545-kilometre (339-mile) pipeline that transports synthetic and heavy oils from north of Fort McMurray in northern Alberta to the pipeline hub at Hardisty, Alberta. The Athabasca System also includes the MacKay River and Christina Lake lateral feeder lines and tankage facilities. The NW System transports crude oil from Norman Wells, in the Northwest Territories, to Zama, Alberta. The Saskatchewan System consists of approximately 322 kilometres (200 miles) of trunk line and 1,920 kilometres (1,193 miles) of pipeline on three separate gathering systems in the provinces of Saskatchewan and Manitoba. Natural gas transmission pipeline activities include equity investments in the Alliance and Vector pipelines. Enbridge owns a 37.1% interest in Alliance, a 3,000-kilometre (1,800-mile) pipeline that commenced operations in December 2000 and transports liquids-rich natural gas from Fort St. John, British Columbia to Chicago, Illinois. The Company provides operating services to and holds a 45% investment in Vector, which transports natural gas from Chicago to Dawn, Ontario. Vector also commenced operations in December 2000. Alliance and Vector have the capacity to deliver 1.55 billion cubic feet per day (bcfd) and 1.0 bcfd, respectively. RESULTS OF OPERATIONS Earnings from Energy Transportation North were $236.2 million for the year ended December 31, 2002, an increase of $31.1 million from 2001. The higher earnings were due to expansions of the Enbridge and Athabasca Systems. Higher earnings from the Enbridge System were due to the request from shippers in mid-2001 to construct Phase III of the Terrace expansion which resulted in incremental earnings and to Phase II of the Terrace expansion which was placed into service in early 2002. These increases were partially offset by an adjustment to the power allowance credit due to shippers as a result of Terrace operating at less than capacity. The Athabasca System generated higher earnings due to the construction of new laterals and tankage, which commenced operations in the second half of 2002. 18 Earnings were $205.1 million for the year ended December 31, 2001, compared with $192.6 million for 2000. The higher earnings were due to increased contributions from the Enbridge System, Alliance and the Athabasca System, partially offset by lower earnings from Vector. Liquids Pipelines Enbridge System In 2002, Enbridge System earnings were $12.6 million higher than last year primarily due to higher earnings from the Terrace expansion as Phase II was placed in service in early 2002 and Phase III was triggered in mid-2001. The increase in Terrace earnings was partially offset by an adjustment to the power allowance credit due to shippers as a result of Terrace operating at less than capacity. Earnings from the Enbridge System increased to $111.1 million in 2001 from $98.3 million in 2000. The increase was mainly due to the triggering of Phase III of the Terrace Expansion in mid-2001. In the third quarter, the Company recorded a charge for an adjustment to oil inventory due to shippers of approximately $3 million, after tax. This was the result of refinements in the oil loss estimation process, as well as improvements in the accuracy of measuring oil losses as new software applications were developed. 1 Deliveries (thousands of barrels per day) 4 2 0 , 2 2 4 9 , 1 2 7 0 , 2 9 0 1 , 2 8 8 0 , 2 98 99 00 01 02 1 Includes deliveries by the 14.1% owned Lakehead System E N B R I D G E I N C . M D & A Tolls on the Enbridge System are governed by the provisions of the Incentive Tolling Settlement (ITS). The ITS, which has been approved by the National Energy Board (NEB), has a five-year term which expires on December 31, 2004. Under the ITS, tolls are determined based on a starting revenue requirement which is adjusted each year for 75% of the change in the Gross Domestic Product Implicit Price Index. The ITS allows the Company and its customers to share in cost savings, protects Enbridge from fluctuations in volumes and incorporates additional incentive mechanisms for electric power cost savings. Since electricity is used to power the pumping stations, power costs are a significant expense. The Company is allowed to earn a separate return on facilities expansions or additions that qualify as non-routine adjustments. The Enbridge System begins at Edmonton and, together with the Lakehead System, comprises the world’s longest crude oil and liquids pipeline system. Since the inception of incentive tolling arrangements in 1995, through the cost performance sharing mechanism of the ITS, after-tax benefits of $79.7 million have been shared approximately 54% and 46% by Enbridge and its customers, respectively. Customers also have realized an additional after-tax benefit of $5.0 million through the power guarantee mechanism of the ITS. The renewal of the ITS in 2000 resulted in a reduction of $16.0 million to the starting point revenue, providing customers with annual on-going savings of $9.0 million, after tax. Enbridge benefited by an increase of $7.6 million in the threshold earnings level from which future sharing is measured. Athabasca System In 2002, earnings on the Athabasca System were $11.3 million higher than 2001, primarily due to the construction of additional tankage at Fort McMurray in 2001, and the construction and completion in 2002 of the MacKay River and Christina Lake lateral lines and two additional tanks at the Athabasca terminal. With the addition of third party volumes, operational control of the Athabasca System was transferred to Enbridge from the major shipper in October 2002. 19 In 2001, the construction of additional tankage and terminal facilities at the Athabasca terminal in Fort McMurray increased the investment base resulting in higher earnings than in 2000. The Company has a long-term contract with the major shipper on the Athabasca System. The shipper has committed annual volumes at specified tolls over a 30-year term. The contract terms provide for tolls that are similar to those that would result under traditional cost-of-service rate-making. The contract terms also provide for a return, based on the contract volumes, that approximates the NEB’s multi-pipeline rate of return on common equity in effect at the time of entering into the agreement. Additional third party volumes improve Enbridge’s return beyond this level. Earnings are recognized on a cost-of-service basis and any difference between the cost-of-service revenue and cash tolls is recognized in the period. The deferred amounts will be collected over the term of the contract. NW System Earnings in the last three years from the NW System have been consistent and reflect the negative effect of declining rate base, offset by cost savings that generate incentive earnings. Earnings are based on an agreement with the primary shipper and are a product of a deemed common equity ratio of 55% and the NEB multi-pipeline rate of return on common equity, plus any incentive cost savings. Saskatchewan System Earnings have been relatively constant in 2002 and 2001. Earnings in 2000 reflect the positive impact of income tax rate reductions. E N B R I D G E I N C . M D & A Gas Transmission Pipelines Alliance The increase in equity earnings of $3.1 million from Alliance in 2002, compared with 2001, was due to the acquisitions of the Williams and El Paso interests in the fourth quarter of 2002. In 2001, equity earnings from Alliance of $37.6 million improved by $9.2 million when compared with 2000. Higher earnings resulted from a higher rate base in 2001 since construction costs were being incurred until the pipeline was placed into service in December 2000. Earnings in 2000 represent allowance for equity funds during construction (AEDC). Enbridge provides operating services to and owns 45% of the Vector Pipeline, which transports natural gas from Chicago, Illinois, to Dawn, Ontario. Vector The contribution from Vector was $3.2 million higher in 2002, compared with 2001, due to a one-time adjustment to depreciation expense, reflecting a revision to depreciation rates to be consistent with the rates approved by the Federal Energy Regulatory Commission (FERC). In addition, an adjustment was booked in 2001 to reverse earnings that were overaccrued in 2000. In 2001, Vector earnings of $3.9 million were $7.3 million less than 2000. Earnings were impacted negatively by capacity constraints in 2001, as well as higher depreciation and interest expense. In 2000, Vector was under construction and earnings represented AEDC. 20 OUTLOOK Liquids Pipelines Enbridge System The NEB approved the facilities application for construction of Phase III of the Terrace Expansion Project in Canada in April 2002. Phase III involves construction of 176 kilometres (110 miles) of 914-millimetre (36-inch) pipeline on the Lakehead System between Clearbrook, Minnesota and Superior, Wisconsin and pumping additions in both Canada and the United States. Phase III will increase capacity by approximately 140,000 barrels per day. Shippers have requested that Phase III be in service in 2003. Phase II, placed in service in 2002, and Phase III were requested by shippers to handle anticipated increases in oil sands volumes in the next few years. Volumes transported are expected to increase in 2003 due to increased production from the oil sands region of Alberta. Fluctuations in volumes do not impact the majority of net earnings from the Enbridge System due to provisions in the ITS. The request to build Terrace Phase III demonstrates producers’ confidence that more capacity out of the Western Canadian Sedimentary Basin (WCSB) will be needed in the medium term. The ITS allows Enbridge and its customers to share in cost savings achieved by the Company. To ensure continued savings for customers and increased returns for shareholders, the Company will continue to focus on operational excellence. Enbridge Athabasca System The Enbridge Athabasca System is the only liquids pipeline directly linking both the Athabasca and Cold Lake oil sands deposits with the pipeline transportation hub at Hardisty, Alberta. With a design capacity of 570,000 barrels per day, the pipeline is well positioned to carry more of the region’s oil sands and heavy oil production in the future. E N B R I D G E I N C . M D & A Earnings from the Athabasca System are expected to increase in 2003 as a result of full year operations of the MacKay River and Christina Lake facilities. In addition, the Company expects that a new diesel-loading facility, to supply the regional market of the major shipper, will be in service by the spring of 2003. The Company has entered into a limited partnership with an industry partner to develop underground cavern facilities to provide crude oil storage services. The facilities are located near the Enbridge System main pipeline terminal at Hardisty. The partnership will provide petroleum storage services to shippers at Hardisty that previously were unavailable. The existing storage capacity of approximately three million barrels has been contracted to a shipper for a five-year term. Construction commenced in the fourth quarter of 2002, with completion expected in the fourth quarter of 2003. Supply Liquids supply from the WCSB is expected to increase during the next 10 years. Although supply of conventional light crude is forecast to continue to decline, significantly higher bitumen and upgraded synthetic production is expected from the Alberta oil sands region. Heavy crude production, which must be diluted with condensate, or heated or upgraded before it can be transported, may be constrained after 2006 without additional use of synthetic crude as diluent. Conventional oil reserves in Western Canada increased in 2001 to 5.2 billion barrels. Approximately 50% of production was replaced. Reserves from the oil sands stood at 6.7 billion barrels from developed, currently producing projects or projects on which substantial investment is being made. It is estimated that there are 315 billion barrels of bitumen ultimately recoverable in the Alberta oil sands, using existing technology. To date, approximately two billion barrels have been produced.1 21 Capital Expenditures Energy Transportation North expects to spend approximately $155 million in 2003 for capital expenditures, the majority of which relates to the Terrace Phase III expansion, the cavern storage project and core maintenance. Gas Transmission Pipelines Earnings from Alliance should increase in 2003 as a result of Enbridge’s higher ownership interest. Vector’s earnings are expected to decrease as a one-time adjustment to depreciation expense increased earnings in 2002. Vector’s earnings will continue to be negatively impacted over the short-term by higher interest expense. There is no near- term requirement for further capital investment in either pipeline. In the third quarter, Enbridge purchased Williams’ 9.6% and El Paso’s 6.1% interests in Alliance. The acquisition from El Paso also includes its 9.5% interest in Aux Sable and Alliance Canada Marketing, which are part of Energy Distribution. Enbridge did not assume either company’s direct merchant capacity commitments on the pipeline. These purchases increase the Company’s ownership interest in Alliance to 37.1% and were made at a cost of approximately $300 million. Supply and Demand for Natural Gas 1 Natural gas reserves in the WCSB increased 0.6% in 2001 to 59.8 trillion cubic feet. In 2001, approximately 106% of natural gas production was replaced. Demand for natural gas in North America is forecast to remain constant over the next five years and grow at 2% per year thereafter. Most of this growth will be for electricity generation requirements. 1 Source: CAPP Statistical Handbook — November 2002 Enbridge increased its ownership in the Alliance natural gas pipeline to 37.1% as of year end. E N B R I D G E I N C . M D & A BUSINESS RISKS Liquids Pipelines Supply and Demand The operation of the Company’s liquids pipelines are dependent upon the supply of and demand for crude oil and other liquid hydrocarbons from Western Canada. Supply, in turn, is dependent upon a number of variables, including the availability and cost of capital for oil sands projects and the price of crude oil. Drilling activity during the last three years has not been as strong as expected. The request by producers to build Phase III of Terrace, adding additional pipeline capacity, indicates that producers expect that volumes will increase in the future. Production from the oil sands of northern Alberta is expected to continue to increase, requiring additional infrastructure. Historically, refiners in the U.S. Midwest have utilized large volumes of Western Canadian light crude versus other imported crude. Line 9 transports offshore crude to Ontario and is owned by Enbridge. Volumes on Line 9 have displaced some Canadian and U.S. domestic deliveries in the Ontario market, requiring an increase in deliveries to the U.S. Midwest, which has limits on the volume of Canadian crude which can be readily absorbed. In December 2002, Canada ratified the Kyoto Protocol, a 1997 treaty designed to reduce greenhouse gas emissions to 6% below 1990 levels. Enbridge is assessing and evaluating the federal government’s approach to implementation. Until these plans become certain, the Company will not be able to quantify the impact, if any, on its operations. The Company is encouraged by recent producer reactions to Kyoto, particularly their commitment to oil sands development, which support the outlook for the sustainability of supply for the liquids pipelines. 22 Regulation Earnings from the Enbridge System and other liquids pipelines are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings from these operations. The NEB prescribes a benchmark multi-pipeline rate of return on common equity. To the extent the NEB rate of return fluctuates, a portion of the earnings of the Enbridge System changes. The Company believes that regulatory risk has been reduced through the negotiation of long-term agreements, such as the ITS, with its customers. Competition The Enbridge System transported approximately 65% of total Western Canadian crude oil production in 2002 and provides about 75% of capacity for the transportation of Western Canadian crude oil out of Canada. Competition among common carrier pipelines is based primarily upon the cost of transportation, access to supply and proximity to customers. Trans Mountain Pipe Line, Express Pipeline, and other common carriers, can be used by producers to ship Western Canadian crude oil to refineries in either Canada or the United States. Although the Company does not compete directly in the regions served by these other pipelines, producers can elect to have their crude oil refined elsewhere than delivery points on the Enbridge System. The Company believes that its liquids pipelines are serving larger markets and provide attractive options to producers in the WCSB, due to its competitive tolls. The Company also offers shorter transit times from the WCSB to the U.S Midwest. Increased competition could arise from new feeder systems servicing the same geographic regions as the Company’s feeder pipelines. Unused capacity on the Athabasca System should be more competitive than a new pipeline. However, competition to provide transportation service directly from the Alberta oil sands to Edmonton has increased. E N B R I D G E I N C . M D & A Environment and Safety Enbridge is committed to the protection of the health and safety of employees and the general public and to sound environmental stewardship. The Company believes that prevention of accidents and injuries and protection of the environment benefits everyone and delivers increased value to shareholders, customers and employees. Every five years, Energy Transportation North conducts a review of its environmental management system. The system reflects industry best practices and is aligned with the ISO 14001 standard for environmental management systems. Pipeline leaks are an inherent risk of operations. The Company has an extensive program to manage system integrity, which includes the development and use of predictive and detective in-line inspection tools. Maintenance, excavation and repair programs are directed to the areas of greatest benefit and pipe is replaced or repaired as required. Gas Transmission Pipelines Alliance and Vector Alliance and Vector are regulated federally and are subject to regulatory risk. The Company believes that this risk has been mitigated through the execution of long-term contracts with customers. Currently, pipeline capacity out of the WCSB exceeds supply. Alliance has been unaffected but Vector has not fully contracted its capacity. E N E R G Y T R A N S P O R T A T I O N S O U T H FINANCIAL RESULTS (millions of Canadian dollars) Enbridge Energy Partners Enbridge Midcoast Energy Loss on sale of Enbridge Midcoast Energy assets Feeder Pipelines Dilution gains Other 23 2002 19.5 7.3 (82.2) 8.1 6.1 (0.2) (41.4) 2001 12.5 9.5 – 9.2 15.2 – 46.4 2000 16.3 – – 7.2 – (0.2) 23.3 BUSINESS ACTIVITIES Energy Transportation South includes the Company’s ownership interests in the operations of EEP. Enbridge is the general partner and operates the assets of EEP. Activities also include owning and operating feeder pipelines in the United States. In October 2002, Enbridge sold the United States assets of Enbridge Midcoast Energy to EEP. Therefore, at year-end, this segment is comprised primarily of the Company’s ownership interests in the Partnership. From May 2001 until October 2002, Enbridge owned 100% of Enbridge Midcoast Energy. The results of operations of Enbridge Midcoast Energy, in the table above, relate to the period when the assets were wholly-owned. Enbridge has an effective 14.1% ownership interest (2001 — 13.6%, 2000 — 15.3%) in the Partnership. This ownership interest represents the Company’s direct investment in EEP of 10.6% and an indirect investment of 3.5% through the Company’s 17.2% ownership interest in EEM. EEP owns the Lakehead System, a feeder pipeline in North Dakota, the Enbridge Midcoast Energy assets and natural gas gathering and processing assets in east Texas (East Texas System). Enbridge Energy Partners owns and operates a number of natural gas gathering and processing facilities in Texas. E N B R I D G E I N C . M D & A 24 RESULTS OF OPERATIONS Results for the year ended December 31, 2002 were a loss of $41.4 million, compared with earnings of $46.4 million for 2001. The 2002 results include an after-tax loss of $82.2 million on the sale of the Enbridge Midcoast Energy assets. Excluding this loss, earnings for 2002 were $5.6 million lower than 2001. Increased earnings from the Partnership, resulting from the acquisitions of the North Dakota and East Texas Systems and the Enbridge Midcoast Energy assets, were more than offset by lower earnings from Enbridge Midcoast Energy prior to the sale and higher dilution gains in 2001. Enbridge Midcoast Energy earnings reflected improved operating performance from the assets, more than offset by adjustments related to 2001 that were recorded in 2002, and working capital and other closing adjustments identified prior to the disposition. The prior year included dilution gains of $15.2 million, compared with $6.1 million in 2002, reflecting two unit issuances by EEP in 2001, compared with one in 2002. The Lakehead crude oil pipeline is owned by Enbridge Energy Partners and operated by Enbridge Pipelines. In 2001, earnings from Energy Transportation South increased by $23.1 million to $46.4 million. The acquisition of Enbridge Midcoast Energy in May 2001 and dilution gains on the Company’s investment in EEP were the major contributors to the increase. Earnings from the Partnership were lower in 2001 due to reduced throughput, an adjustment to oil inventory due to shippers and one-time costs associated with relocating the Partnership’s office to Houston. In October 2002, the Company closed the sale of the United States assets of Enbridge Midcoast Energy to EEP for consideration of US$820.0 million, including cash and the assumption of debt. Concurrent with the sale transaction, EEM, a subsidiary of Enbridge, completed an initial public offering of 9,000,000 shares representing limited liability company interests with limited voting rights. The net proceeds from the offering were used to purchase i-units, a new class of limited partnership interests, from EEP. The proceeds from the i-units were used to finance a portion of the acquisition cost of the assets. In connection with the offering, Enbridge purchased 17.2% of the EEM shares, increasing its effective ownership in the Partnership to 14.1% from 12.9%. EEM has no assets or operations other than those related to the interest in EEP and, by agreement, will manage the business and affairs of EEP. Enbridge Energy Partners Equity earnings in the Partnership improved in 2002 due to higher incentive earnings earned by Enbridge as the general partner, improved results from the Lakehead System, and a higher ownership interest in the fourth quarter. The acquisitions of the North Dakota and East Texas Systems contributed a full year’s earnings in 2002 and the acquisition of the Enbridge Midcoast Energy assets increased earnings in the fourth quarter. The decreased contribution from the Partnership in 2001 compared with 2000 resulted from reduced throughput, an adjustment to oil inventory due to shippers, as well as one-time costs associated with relocating the Partnership’s office to Houston. In December 2001, EEP completed the acquisition of the East Texas System for US$230 million. The acquisition of the East Texas System represented the Partnership’s entry into the natural gas transportation business. E N B R I D G E I N C . M D & A Enbridge Midcoast Energy Enbridge Midcoast Energy was sold to EEP in October 2002. Enbridge purchased Midcoast Energy Resources, Inc. in May 2001 for cash consideration of $561.8 million and the assumption of long-term debt. Earnings from Enbridge Midcoast Energy in 2002 were $7.3 million, a decrease of $2.2 million from the prior year. While 2002 reflects improved operating performance, this was more than offset by adjustments related to 2001 that were recorded in 2002 and working capital and other closing adjustments identified prior to the disposition. Earnings for 2002 are for the period prior to the October 2002 disposition. Earnings for 2001 represent earnings from the May 2001 date of acquisition. In March 2002, the Company closed the acquisition of natural gas gathering and processing facilities in northeast Texas for approximately $290 million. Also, in October 2001, Enbridge announced the purchase of natural gas gathering, treating and transmission assets in south Texas for US$50 million. The Company closed a portion of the acquisition for US$9 million and EEP now holds an option to purchase the remaining assets. These assets were included with Enbridge Midcoast Energy and were part of the October 2002 sale to EEP. OUTLOOK Enbridge Energy Partners Earnings for the Partnership are expected to increase in 2003, reflecting higher transportation volumes on the Lakehead System and improved performance from the East Texas System. In addition, a full year’s contribution from the Enbridge Midcoast Energy assets is expected to increase earnings. Earnings from the Lakehead System and certain of the gas gathering assets are volume-sensitive and expected increases in volumes should have a positive impact on the Partnership’s earnings. The growth in the asset base and expected increase in earnings should result in higher incentive distributions to the Company. 25 The Terrace Phase III expansion, currently under way, offers opportunities to increase volumes transported on the Lakehead System as crude oil supply from Western Canada increases due to oil sands development. Phase III is designed primarily to increase capacity between Clearbrook, Minnesota and Superior, Wisconsin by approximately 140,000 barrels per day. The estimated cost of this project to EEP is approximately $312 million and is planned to be in service in 2003. Capital Expenditures In 2003, the Company plans to spend $17 million related to additional investments in EEP and EEM. BUSINESS RISKS Virtually all of the Company’s operations in Energy Transportation South are carried out through the Partnership. The business risks are mitigated by the size of the Company’s investment in the Partnership. Supply and Demand The Lakehead System is dependent upon the level of supply of and demand for crude oil and other liquid hydrocarbons from Western Canada. A decreased supply of crude oil impacts deliveries with a corresponding impact on earnings. Certain of the Partnership’s natural gas gathering assets are subject to changes in supply and demand for natural gas, natural gas liquids and related products. Commodity prices impact the willingness of natural gas producers to invest in additional infrastructure to produce natural gas. Construction continued in the United States on the Terrace Phase III expansion, expected to be in service in 2003. E N B R I D G E I N C . M D & A Regulation The interstate and intrastate gas pipelines are subject to regulation by FERC or state regulators. Gas gathering currently is not subject to active regulation. Several of the Partnership’s assets are regulated by FERC and their revenues could decrease if tariff rates were protested. Kansas Pipeline Company (KPC) has recently lowered its rates in compliance with a FERC order. Enbridge has agreed to reimburse EEP for a shortfall in revenue approximating US$2 million for the next two years. The rates are subject to a rehearing by FERC. Certain states in the U.S. may initiate rate regulatory oversight of intrastate gas pipelines. If this regulation occurs, it may reduce the revenues and earnings of the Partnership. Several of the Partnership’s pipeline systems transport commodities that are hazardous if released from the pipeline system. These assets are subject to strict regulation and could be shut down or required to operate at reduced operating pressures that likely would reduce earnings. Market Price Risk The Partnership’s business is subject to commodity price risk for natural gas costs and natural gas liquids. Historically, these risks have been managed by using derivative finacial instruments, fixing the prices of natural gas and natural gas liquids. 26 E N E R G Y D I S T R I B U T I O N FINANCIAL RESULTS (millions of Canadian dollars) Enbridge Gas Distribution Enbridge Commercial Services Noverco Enbridge Gas New Brunswick Gas Services Aux Sable Other 2002 85.3 10.7 20.6 3.6 (7.8) (3.1) 4.5 113.8 2001 156.1 14.3 16.3 2.3 (5.3) (6.2) 4.3 181.8 2000 147.6 18.4 31.4 3.4 (8.8) (3.3) 14.5 203.2 BUSINESS ACTIVITIES Energy Distribution includes the gas distribution operations of Enbridge Gas, Enbridge Commercial Services, which owns the Company’s investment in CustomerWorks LP, the Company’s investment in Noverco, and other gas distribution activities in smaller franchise areas. This segment also includes the gas services business, which manages the Company’s merchant capacity commitments on Alliance and Vector, and the equity investment in Aux Sable. Enbridge Gas is Canada’s largest natural gas distribution company and has been in operation for more than 150 years. It serves over 1.6 million customers in central and eastern Ontario, southwestern Quebec and parts of northern New York State. Its operations in Ontario are regulated by the Ontario Energy Board (OEB). Enbridge Commercial Services commenced operations on January 1, 2000 to provide information technology, fleet services, call management centre, customer care and billing services to Enbridge Gas, the Energy Services business and others. In 2001, Enbridge and BC Gas Inc. formed CustomerWorks LP to provide service covering the entire meter-to-cash process, including many of the services provided by Enbridge Commercial Services. Operations commenced on January 1, 2002. CustomerWorks LP provided services to more than 3.5 million customers of the BC Gas utility and Enbridge’s gas distribution business. In August 2002, CustomerWorks LP outsourced the provision of its customer care services to a new entity owned and operated by Accenture Inc. E N B R I D G E I N C . M D & A Enbridge owns an equity interest in Noverco through ownership of common shares and a cost investment through ownership of preference shares. Noverco is a holding company that owns a 77% interest in Gaz Métropolitain, a gas distribution company operating in the province of Quebec and the state of Vermont, which has a 50% interest in TQM Pipeline, a pipeline transporting natural gas in Quebec. The Company owns 63% of and operates Enbridge Gas New Brunswick (EGNB), the natural gas distribution franchise in the Province of New Brunswick. EGNB constructed a new distribution system and has approximately 1,600 customers. Over 200 kilometres (124 miles) of distribution main have been installed with the capability of attaching 6,000 customers. EGNB is regulated by the New Brunswick Board of Commissioners of Public Utilities. RESULTS OF OPERATIONS Earnings were $113.8 million for the year ended December 31, 2002, compared with $181.8 million in 2001. Lower earnings in 2002 were attributable to warmer weather experienced in the Enbridge Gas franchise area in 2002 and a lower contribution from Enbridge Commercial Services, partially offset by improved earnings from Noverco. Earnings for 2001 included the positive impact of income tax rate reductions of $45.0 million. Earnings from Energy Distribution were $181.8 million for the year ended December 31, 2001, compared with $203.2 million in 2000. The results reflect strong operating performance from Enbridge Gas, more than offset by a smaller positive impact of tax rate reductions in 2001 than in 2000. Earnings from Noverco were lower in 2001 due to the positive effect of tax rate reductions on earnings in 2000. Enbridge Gas Earnings from Enbridge Gas decreased by $70.8 million in 2002 from 2001. The decrease was due to significantly lower gas distribution margins, caused by lower distribution volume resulting from warmer weather. Had Enbridge Gas experienced normal weather in its franchise area, earnings would have been higher by $29.3 million. 27 Energy Distribution Degree Day Deficiency (degrees Celcius) Energy Distribution Volume of Gas Distributed (billions of cubic feet) Energy Distribution Number of Active Customers (thousands) 6 6 7 , 3 9 6 5 , 0 3 6 4 , 3 0 6 0 , 4 9 2 9 , 3 6 1 8 , 3 2 6 3 , 3 0 0 7 , 3 2 5 3 , 3 9 7 0 , 4 7 9 3 2 0 4 1 2 4 7 2 4 0 1 4 4 1 4 , 1 6 6 4 , 1 0 2 5 , 1 1 7 5 , 1 3 2 6 , 1 98 99 00 01 02 98 99 00 01 02 98 99 00 01 02 Forecast Actual E N B R I D G E I N C . M D & A 28 Normal weather is the weather forecast by Enbridge Gas, in the Toronto area, including the impacts of both the long run and short run actual historical weather experience, more heavily weighted on the short run experience. The effect of weather is measured by degree-day deficiency and is calculated by accumulating, from October 1, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. This non-GAAP measure is unique to the Company and, due to differing franchise areas, is unlikely to be directly comparable to the impact of weather-normalized earnings that may be reported by other companies. The weather-normalized adjustment is consistent with the manner in which degree days are calculated for regulatory purposes. Enbridge Gas Distribution, Canada’s largest natural gas company, added 52,000 customers in 2002. Earnings in 2001 of $156.1 million were higher than 2000 by $8.5 million. Although weather for 2001 was slightly warmer in the franchise area, it was colder during the winter months when distribution margins are higher, resulting in higher earnings of approximately $5.0 million. Operating earnings also increased due to growth in the customer base and lower unaccounted for gas, which is the difference between distribution volume entering the system and the volume delivered to customers. The weather was 5% colder compared with 2000 and was slightly warmer than normal. In the rate-making process, the OEB approves revenue rates that are designed to recover the cost of providing service and to provide a return on equity. Rates are set on a forecast basis. The cost of providing service includes the cost of gas commodity purchases and transportation costs, operation and maintenance costs, depreciation, income taxes, and the cost of capital used to finance all assets used in gas distribution, storage and transmission. The cost of capital, which is expressed as an allowed rate of return on rate base, is designed principally to meet the cost of interest on long and short-term debt, satisfy the dividend requirements of preferred shareholders, and provide a return on investment on common equity. It is the responsibility of Enbridge Gas to demonstrate to the OEB the prudency of the costs it has incurred or the activities it has undertaken. Enbridge Gas does not profit from the sale of the natural gas commodity. Enbridge Gas continued to operate under a targeted Performance-Based Regulation plan (PBR plan), which expired at the end of fiscal 2002. The PBR plan used a formula to calculate the level of operation and maintenance costs recoverable in rates. The formula included escalation factors for customer growth and inflation; these were offset by an annual productivity credit of 1.1%. The PBR plan also allowed for the recovery, subject to OEB approval, of factors impacting operation and maintenance costs that are outside of management’s control. During the PBR plan period, Enbridge Gas retained the savings it achieved as operation and maintenance expenses were lower than those calculated under the formula. The allowed rate of return on common equity for Enbridge Gas is based on the yield on Canadian government long-term bonds. For 2002, the allowed rate of return was 9.66% (2001 — 9.54%, 2000 — 9.73%) on a deemed common equity ratio of 35%. Over the last three years, Enbridge Gas added 157,000 customers, including approximately 52,000 customers in 2002. This growth was attributable to the continued preference for natural gas among homeowners and builders due to the price advantage and environmental benefits over other forms of energy. The new residential housing market was strong in 2002 and 2001 and, through marketing programs, builders have continued to choose natural gas for new housing construction. E N B R I D G E I N C . M D & A Enbridge Commercial Services The contribution from Enbridge Commercial Services (ECS) was $10.7 million for the year ended December 31, 2002, a decrease of $3.6 million compared with the prior year. The decrease is due to the positive impact of tax rate reductions in 2001 and the transfer of the remaining ECS operations into Enbridge Gas in the fourth quarter. Lower earnings from ECS in 2001, compared with 2000, reflect the transfer of the merchandise finance plan to the Energy Services business effective January 1, 2001. The merchandise finance plan business is included as a component of discontinued operations. Noverco The contribution from Noverco was $20.6 million in 2002, compared with $16.3 million in 2001. The increase is due to lower financing costs and higher incentive earnings. Equity earnings from Noverco in 2001 were lower than 2000, mainly due to the positive impact of tax rate reductions in 2000. Variations from normal weather do not affect Noverco’s earnings as the utility is not exposed to weather risk. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preference share investment, which is based on the yield of 10-year Government of Canada bonds plus 4.45%. The weighted average dividend yield on the preference shares, which is reset annually, was approximately 10% for each of the last three years. Enbridge Gas New Brunswick Earnings from Enbridge Gas New Brunswick improved in 2002 as a result of a full year of operations. Customer attachment to the new facilities continued to be slower than expected largely due to the shortage of skilled workers to install heating, ventilation and air conditioning equipment. This has resulted in an increase in the regulatory receivable used during the development period to defer annual shortfalls between EGNB’s revenues and cost of service. This deferral is anticipated to be significantly higher than expected at the project’s commencement. The recovery of this deferral will be determined by the regulator at the end of the development period. Earnings in 2001 were slightly lower than 2000. Construction of new natural gas distribution facilities commenced in the third quarter of 2000. Customer attachment to the new facilities has been slower than expected, resulting in lower earnings in 2001. Earnings in 2000 consisted mainly of AEDC. Gas Services Gas Services experienced a loss of $7.8 million for the year ended December 31, 2002, compared with a loss of $5.3 million in 2001. The loss increased in 2002 because of reduced basis differentials between Alberta and Chicago and between Chicago and Dawn, Ontario. The basis differential is the cost of transportation between natural gas hubs and determines the revenue which can be obtained from transportation capacity. The loss in 2001 was attributable to losses on the Company’s Alliance and Vector merchant capacity, also from the narrowing of the basis differential. 29 Enbridge Gas New Brunswick continued to expand its distribution system and add new customers. E N B R I D G E I N C . M D & A Aux Sable Enbridge owns a 30.9% interest in the Aux Sable facilities, which process natural gas delivered through Alliance. As the gas transported by Alliance is liquids-rich, it must be processed prior to delivery to other systems. Aux Sable commenced operations in December 2000 and has the capacity to process up to 1.6 bcfd of natural gas. In 2002, the loss from Aux Sable was $3.1 million, an improvement of $3.1 million from the loss of $6.2 million incurred for the year ended December 31, 2001. The improvement is due to improved margins between the prices of natural gas liquids and natural gas in 2002. In 2001, Aux Sable generated a loss of $6.2 million due to the unfavourable spread between gas liquids and natural gas prices during the first half of the year. The facilities operated at a break-even level during the last half of 2001. Enbridge Gas Distribution is developing, in consultation with stakeholders, an incentive regulation plan. OUTLOOK 30 Enbridge Gas 2003 Rate Application Enbridge Gas has filed its 2003 rate application with the OEB, requesting an order to approve rates for the sale, distribution, transmission and storage of gas, which reflected a gross revenue deficiency, or proposed increase in revenue rates, of $101.7 million. Of this amount, approximately $9.0 million is associated with changes to the distribution volume forecast, gas in storage inventory valuation and cost of capital (including the application of the OEB-approved rate of return on common equity formula), offset somewhat by a decline in federal taxation rates. A further $43.8 million of the increase arises from a requested increase in operating and maintenance expense recovery and $13.0 million from the proposed mechanism for recovery of the regulatory receivable related to the unbundling of the Energy Services business. The remainder relates to variances in all other items requested for recovery in the application. The 2003 rate application is a traditional cost-of-service application as the PBR plan ended in 2002. It is expected that the application will be heard by the OEB in early 2003 and a decision is anticipated in the third quarter of 2003. The 2003 rate application includes a request to review and revise the current formula used to calculate the rate of return on common equity. It is anticipated that this request will be heard in a separate phase of the 2003 rate hearing and, as such, the increase to a proposed rate of return of 11.5% versus the 9.95% produced by the current formula has not been incorporated into the calculation of the $101.7 million deficiency. The increase in the requested rate of return reflects the Company’s need to compete for investment dollars in the North American marketplace. Regulatory Receivable In a prior rate case, the OEB approved the recovery of $50.0 million of future income taxes related to the water heater rental business that was transferred to the Energy Service business in 1999. As part of its 2002 rate case, the Company applied for a mechanism to recover a portion of the $50.0 million. This aspect of the Company’s application was deferred and the regulatory process is under way. E N B R I D G E I N C . M D & A Incentive Regulation Plan The trend in North America is toward incentive, or performance-based, regulation. Enbridge Gas has completed its three-year, OEB-approved targeted PBR plan. The OEB expects Enbridge Gas to develop, in consultation with stakeholders, an appropriate incentive regulation plan. Enbridge Gas has provided a proposal for an incentive regulation plan to stakeholders for the purposes of discussion. For fiscal 2003, Enbridge Gas has filed a cost-of- service rate application with the OEB, which would be used to establish the base year rates for the incentive regulation term. The proposal suggests that rates be adjusted annually by a consumer price index and that utility earnings above or below the OEB-approved return on common equity be shared equally between ratepayers and Enbridge. Enbridge Gas has proposed that certain costs, such as gas commodity costs and capital expenditures for the safe operation and maintenance of the distribution system, should be passed through to ratepayers outside of the calculated rates. Enbridge Gas is holding discussions currently with stakeholders, the outcome of which may result in changes to the proposal. The plan will be presented to the OEB following the establishment of base rates for 2003. 2002 Rates Decision The OEB approved the 2002 revenue requirement and final rates in August 2002. In December 2002, the OEB released its decision with respect to several policy issues stemming from the 2002 rate case. The OEB’s decision included concerns and questions about the Company’s business operations in regards to outsourcing agreements, including the pipeline transportation contract with Alliance, as well as the agreements with Enbridge and its affiliates. As Enbridge Gas does not accept some aspects of the decision, it has filed a notice of motion, requesting the OEB to review its decision on Alliance and affiliate outsourcing, or in the alternative in this latter matter, to conduct a generic hearing on rules for affiliate outsourcing. Enbridge Gas also has filed an appeal to the Divisional Courts on matters arising from what Enbridge Gas believes to be errors in law in the decision. Direct Purchase Deregulation of the natural gas industry has introduced many changes to the natural gas distribution business, one of which occurred in the gas marketing segment of the industry. Prior to the advent of deregulation in 1985, Enbridge Gas supplied natural gas to 100% of its customer base. In 2002, 759,000 customers purchased their supply of gas from sources other than the utility (2001 — 695,000, 2000 — 602,000). Earnings are not impacted by the customers’ choice of gas commodity supplier, provided any migration is accurately forecast in advance and incorporated in the volume underlying the rate application. Enbridge Gas intends to continue to provide customers the option of purchasing their natural gas directly from the utility. 31 Enbridge Gas New Brunswick Customer attachment to the EGNB system has been slower than expected. EGNB plans to increase the attachment rate by becoming actively involved in the sale of the natural gas commodity and the sale, installation and service of natural gas equipment to the residential and small commercial markets. This “bundled” approach currently is not permitted under provincial legislation. The Company believes that the government of New Brunswick will be receptive to its plans. CAPITAL EXPENDITURES Capital expenditures for the Energy Distribution business are expected to be approximately $322 million. The majority of the expenditures relate to expansion of and core maintenance on the Enbridge Gas distribution system. In addition, expansion of the Enbridge Gas New Brunswick distribution system will continue. E N B R I D G E I N C . Enbridge has a more than 150-year history of safely providing gas to customers in Ontario. M D & A BUSINESS RISKS Enbridge Gas The business risks inherent in the natural gas distribution industry impact the ability of Enbridge Gas to realize the revenue level required to generate the allowed return on equity. These business risks include timely and adequate rate relief, accuracy in forecasting distribution volume and, most importantly, achieving the forecast natural gas distribution volume. With the ongoing changes in the electricity industry, Enbridge Gas may face an emerging risk of increased competition in the energy market. The regulatory process in North America has been evolving in recent years towards incentive or performance-based regulation and away from traditional As a distributor of natural gas, Enbridge provides service to more than 1.6 million residential, commercial and industrial customers. 32 cost-of-service regulation. Since the PBR plan only applied to operation and maintenance expenses, it did not materially change existing business risks. It is Enbridge Gas’ intention to introduce a comprehensive form of incentive regulation for 2004. It is anticipated that this form of regulation will provide greater opportunity to earn in excess of the allowed rate of return, but, as a result, may impact business risk. Volume Risks Since customers are billed on a volumetric basis, the ability to collect the total revenue requirement (the cost of providing service) depends upon achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather; economic conditions; pricing of competitive energy sources; and the number of customers. Sales and transportation of gas for customers in the residential and commercial sectors account for approximately 74% of total distribution volume. Weather during the year, measured in degree-days, has a significant impact on distribution volume as a major portion of the gas distributed to these two markets is used ultimately for space heating. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions are important to all market sectors as continued expansion adds to the total consumption of natural gas. Even in those circumstances where Enbridge Gas attains its total forecast distribution volume, it may not earn the approved return on equity due to other forecast variables. The mix of sales and transportation of gas for customers and the mix between the higher margin residential and commercial sectors and lower margin industrial sector could impact results. The timing of gas sales is also a factor, as the winter season has higher rates than the summer season. During 2002, Enbridge Gas received approval from the OEB to defer the difference between forecast and actual unaccounted for gas. Unaccounted for gas is the difference between volume entering the distribution system and that delivered to customers, determined based on meter readings. The difference is deferred as a receivable from or payable to ratepayers until the OEB approves its disposition. E N B R I D G E I N C . M D & A Rate Relief Enbridge Gas does not profit from the sale of the natural gas commodity nor is it at risk for the difference between the actual cost of gas purchased and the price approved by the OEB. This difference is deferred as a receivable from or payable to ratepayers until the OEB approves its disposition. Enbridge Gas monitors the balance and its potential impact on ratepayers and will request interim rate relief that will allow it to recover or refund the gas commodity cost differential. Rate relief can also be sought for other significant unbudgeted amounts, allowing Enbridge Gas to recover the costs of providing and maintaining the quality of its service while achieving the allowed rate of return on rate base. Enbridge Gas implemented a quarterly rate adjustment mechanism starting in 2002. This allows for the quarterly adjustment of rates to reflect changes in natural gas commodity prices. Adjustments are subject to approval by the OEB. Forecasting Accuracy Forecasting accuracy is a risk since rate applications are made or rates are established in advance based on anticipated distribution volume by class of customer. Forecasts are also made for the future cost of capital including the forecast yield rate for long-term Government of Canada Bonds used in the determination of the return on equity. Consequently, reliability of the forecasting process should ensure that any changes in cost of service, regardless of whether they are caused by inflation or by level of business activity, would be recovered in new rates approved for that year based on the anticipated distribution volume. Gas Services Earnings from Gas Services are dependent upon the basis (location) differentials between Alberta and Chicago and between Chicago and Dawn. To the extent that the difference in the price of natural gas in the various locations is not greater than the cost of transportation between Alberta and Chicago or Dawn, earnings will be negatively affected. 33 Aux Sable Earnings from Aux Sable will continue to be exposed to the effect of unfavourable spreads between the sale prices of natural gas liquids and the purchase price of replacement natural gas. Equity earnings would be negatively impacted by a decrease in the spread and positively impacted by an increase in the spread. I N T E R N A T I O N A L FINANCIAL RESULTS (millions of Canadian dollars) OCENSA/CITCOL CLH Jose Terminal Consulting, business development costs and other 2002 35.3 33.3 3.2 (3.8) 68.0 2001 35.1 – 5.9 (5.4) 35.6 2000 30.3 – 1.5 (5.4) 26.4 BUSINESS ACTIVITIES International includes earnings from the investments in OCENSA, a crude oil pipeline in Colombia, and CLH, Spain’s largest refined products transportation and storage business. Earnings also include fees earned as operator of the Jose Terminal in Venezuela and from technology and consulting services provided by Enbridge Technology Inc. E N B R I D G E I N C . M D & A In the first quarter of 2002, the purchase of a 25% interest in CLH, for approximately $430 million was completed. Enbridge has a role in management of CLH through Board representation and the appointment of management positions. RESULTS OF OPERATIONS Earnings increased by $32.4 million to $68.0 million in 2002. The acquisition of CLH in the first quarter of 2002 represented the growth in International. Earnings from other operations approximated 2001. CLH is Spain’s largest refined products transportation and storage business. Earnings in 2001 increased by $9.2 million to $35.6 million. The increase was partially due to the additional OCENSA ownership interest acquired in the third quarter of 2000. In addition, higher fees were earned to operate the Jose Terminal, resulting from the new long-term operating contract finalized in the second quarter of 2001. OUTLOOK The International business will continue to focus on select countries in key regions based on global trends in supply and demand. In addition, opportunistic acquisitions will be assessed based on risk/reward. The technology and consulting business is expected to provide support in connection with identification and development of equity participation projects. 34 The Jose Terminal long-term operating agreement has been in a force majeure situation since December 2002 as a result of the political uncertainty in Venezuela. The Venezuelan military and the Ministry of Energy and Mines are currently in control of the terminal facilities. Discussions are continuing with PDVSA, the national oil company, to return the operating company, in which Enbridge holds a 45% interest, to its role under the operating agreement. In the event the operating role is not re-established, the contract provides for certain payments to the operator. Historically, International has focussed on “grass roots” infrastructure projects. Increased international asset rationalization, the changing corporate strategies of multinationals, and the privatization of energy transportation activities in focus regions should continue to present investment and acquisition opportunities. Opportunities will be evaluated against the Company’s established investment criteria. Latin America and Western Europe are key regions of interest. Enbridge plans for the International segment to contribute approximately 15% of earnings over the long-term. BUSINESS RISKS The International business is subject to risks related to political and economic instability, currency volatility, market volatility, government regulations, foreign investment rules, security of assets, and environmental considerations. The Company assesses and monitors international regions and specific countries on an ongoing basis for changes in these risks. Risks are mitigated by a combination of Enbridge’s contractual arrangements, operation of the assets, regular analysis of country risk, and foreign currency hedging and insurance programs. C O R P O R A T E (millions of Canadian dollars) Corporate Financing Other 2002 (64.9) 22.5 (42.4) 2001 (70.4) 14.7 (55.7) 2000 (59.0) (28.8) (87.8) The Corporate segment includes new business development activities and corporate financing costs. E N B R I D G E I N C . M D & A Corporate costs amounted to $42.4 million in 2002, a decrease of $13.3 million from 2001. In 2002, Corporate included an after-tax gain on the sale of securities of $17.8 million and lower financing costs. Preferred securities distributions increased in 2002 due to the new issue in February 2002. In addition, corporate activities contributed less in 2002 than in 2001 and business development activities were increased in 2002. Corporate costs totalled $55.7 million in 2001, compared with $87.8 million in 2000. Higher financing costs associated with investments made late in 2000 and the acquisition of Enbridge Midcoast Energy in May 2001 were incurred during the year. These costs are not allocated to the business operations. Corporate activities also generated improved results in 2001. In 2000, the Company recorded a loss on foreign exchange contracts of $15.6 million, after tax, and income tax expense related to tax rate reductions. In December 2000, the federal government substantively enacted a 6% reduction in corporate tax rates. As a result, certain of the Company’s anticipated U.S. dollar cash flows became overhedged for accounting purposes. The derivative financial instruments were valued at market prices and a loss of $15.6 million was charged to income in 2000. The forward foreign exchange contracts subsequently were designated as a hedge of certain of the Company’s equity net investments in the United States in the third quarter of 2001. D I S C O N T I N U E D O P E R A T I O N S In January 2002, the Company announced the sale of the retail and commercial energy services business, including the water heater rental program, to focus on its core activities of energy transportation and distribution. The sale, for proceeds of $1 billion, was completed in the second quarter of 2002. This business included: the water heater rental program; retail appliance, fireplace and water heater sales and service; and mass market commercial plumbing, heating, ventilation and air conditioning, appliance repair and electrician contractor services in Canada and the United States. 35 Earnings from discontinued operations for the year ended December 31, 2002 were $242.3 million, compared with $45.3 million for 2001. The 2002 results included a gain on sale of $240.0 million. Earnings in 2001 included a full year’s results of operations and $14.3 million related to the positive effect of income tax rate reductions. Earnings from discontinued operations were $45.3 million in 2001, compared with earnings of $34.6 million in 2000. The increase is attributable to growth in the business, particularly the water heater rental program. C R I T I C A L A C C O U N T I N G P O L I C I E S RATE REGULATION The Company follows generally accepted accounting principles, which may differ for regulated operations from those otherwise expected in non-regulated businesses. These differences occur when the regulatory agencies render their decisions on rate applications and generally involve the timing of revenue and expense recognition to ensure that the actions of the regulator, which create assets and liabilities, have been reflected in the financial statements. The accounting for these items is based on an expectation of the future actions of the regulator. For example, the Company does not record future income taxes related to its regulated operations as the taxes payable method is prescribed by the regulator for rate-making purposes and there is reasonable expectation that all such future income taxes will be recovered in rates when they become payable. Similarly, the deferral of differences between amounts included in rates and actual experience for specified expenses is based on the expectation that the regulator will approve the refund to or recovery from ratepayers of the deferred balance, normally in the following year. E N B R I D G E I N C . M D & A 36 If the regulator’s future actions are different from the Company’s expectations, the timing and amount of the recovery of liabilities or refund of assets, recorded or unrecorded, could be significantly different from that reflected in the financial statements. L I Q U I D I T Y A N D C A P I T A L R E S O U R C E S The Company’s cash generated from operations, commercial paper issuances, available capacity under credit facilities and access to capital markets in Canada and the United States for the issue of long-term debt, equity, or other securities are expected to be sufficient to satisfy liquidity requirements. Enbridge reduced its debt to equity ratio to 64.4% as of year end. One of the Company’s objectives in 2002 was to reduce its debt to equity ratio and, therefore, strengthen its balance sheet. This objective was achieved. The debt to equity ratio, including short-term borrowings, at December 31, 2002, was 64.4%, compared with 72.9% at the end of 2001. The reduced leverage was primarily a result of the proceeds received on the sales of the Energy Services business and the Enbridge Midcoast Energy assets. The most significant transaction affecting both investing and financing activities in 2002 was the sale of the Enbridge Midcoast Energy assets for US$820 million. The Company received cash proceeds of $529.3 million. The remaining consideration was in the form of assumed debt owing to the Company. Concurrent with the sale transaction, EEM completed a public offering of 9,000,000 shares, including 1,550,000 shares purchased by Enbridge. The net proceeds of $421.9 million were used to purchase i-units in EEP. The statement of cash flows includes the proceeds of EEM’s issuance of shares and investment in EEP, because EEM is a subsidiary of the Company. The 82.8% interest in EEM not held by Enbridge is displayed as non-controlling interests on the consolidated statement of financial position. The Company’s consolidated leverage is expected to improve further through reductions in the assumed affiliated debt as EEP secures additional financing. OPERATING ACTIVITIES Cash provided by operating activities before changes in operating assets and liabilities and cash from discontinued operations was $732.7 million for the year ended December 31, 2002, compared with $735.7 million and $599.8 million for 2001 and 2000, respectively. In 2002, cash from operations is consistent with the prior year. Earnings from continuing operations were lower but include higher non-cash charges which increased cash from operations. The non-cash charges include the loss on sale of the Enbridge Midcoast Energy assets and higher future income tax expense. The increase in cash from operations in 2001 was attributable to higher earnings and a decreased level of non-cash credits. The lower non-cash credits reflected smaller future income tax recoveries resulting from tax rate reductions and increased cash distributions from Alliance and Vector consistent with operations commencing in late 2000. The decreased funding requirements for operating assets and liabilities in 2002 was due to lower gas in storage and decreased accounts receivable, commensurate with the lower cost of gas in 2002. In 2001 and 2000, working capital funding was required to fund an increase in gas in storage that resulted from the higher commodity cost for natural gas. The higher cost of gas also increased accounts receivable balances in the gas distribution business. E N B R I D G E I N C . M D & A Since the Company’s pension plans are adequately funded, no additional funding above usual levels is anticipated for 2003. INVESTING ACTIVITIES Cash used in investing activities for the year ended December 31, 2002 was $251.7 million, compared with $1,621.7 million in 2001 and $949.8 million in 2000. During 2002, the Company completed the acquisition of the Northeast Texas assets, included in the asset sale to EEP, acquired a 25% equity investment in CLH and increased its equity ownership of Alliance. These items, in addition to capital expenditures in Energy Transportation North and Energy Distribution, represent the majority of the cash used for investing purposes and more than offset the cash inflows from the sales of the Enbridge Midcoast Energy assets and the Energy Services business. Capital expenditures in Energy Transportation North primarily related to construction of new facilities on the Athabasca System. Energy Distribution capital expenditures included capital maintenance and expansion of the gas distribution system. Cash provided from investing activities includes proceeds from the sale of marketable securities and partial repayment by EEP of short-term loans required to finance acquisitions. Activity in 2001 was the result of acquisitions, including Midcoast Energy Resources, a greater interest in Frontier Pipeline, and gathering assets in South Texas, as well as a short-term loan to EEP to bridge finance an acquisition. There were increased additions to property, plant and equipment during 2001, which included the construction of Terrace Phase II and the Athabasca System facilities expansion, capital maintenance and expansion of the gas distribution business, and the capital program of Enbridge Midcoast Energy subsequent to acquisition. These were offset, in part, by significantly reduced long-term investment activity, as Alliance and Vector construction was completed in late 2000. 37 FINANCING ACTIVITIES Over the three-year period, the Company’s financing requirements have reflected its growth and investment strategies. The decision to finance with debt or equity is based on the capital structure for each business and the overall capitalization of the consolidated enterprise. Certain of the regulated pipeline and gas distribution businesses issue long-term debt to finance capital expenditures. This external financing may be supplemented by debt or equity injections from the parent company. Debt, and equity when required, has been issued to finance business acquisitions, investments in subsidiaries and long-term investments. Funds for debt retirements are generated through cash provided from operating activities, as well as through the issue of replacement debt. In 2002, cash used for financing activities to reduce short-term debt was partially offset by cash received from the issue of additional common shares and preferred securities. These activities were consistent with the goal of improving the Company’s debt to equity ratio and financing the growth in the business. Proceeds from the issuance of shares by EEM were used to invest in i-units of EEP, as described above. In 2001, cash provided from financing activities was greater than 2000 to support the increased levels of investing activity, primarily through acquisition, and higher capital expenditures. Investing activity was financed primarily with short-term variable rate debt on an interim basis. The Company expects to further improve its consolidated leverage in 2003. E N B R I D G E I N C . M D & A 38 Capital Expenditures, Investments and Acquisitions (millions of dollars) 5 . 5 4 6 , 1 2 . 1 4 1 , 1 2 . 4 2 3 , 1 9 . 1 0 3 , 2 7 . 5 3 9 98 99 00 01 02 R I S K M A N A G E M E N T OPERATING RISK As Enbridge continues to diversify its energy transportation and distribution businesses in North America and internationally, the risk profile of the Company will change. Entry into non-regulated businesses imposes greater economic exposure and requires more “at risk” capital. The Company’s expectation of higher returns from these businesses justifies the level of risk. In addition, these operating risks are actively managed through insurance and other programs. MARKET RISK Earnings and cash flows are subject to volatility stemming from movements in the Canadian dollar exchange rate relative to other currencies and interest rates. The Company has adopted an earnings at risk methodology to measure its exposure to market risk. To manage market risk, Enbridge uses derivative financial instruments to create offsetting positions to specific exposures. The Company has established risk management policies, approved by the Board of Directors, covering the use of derivative financial instruments for hedging purposes. Ongoing monitoring and senior management reporting procedures are in place. Derivative financial instruments are not used to create speculative positions. The financial instruments used and outstanding are described in Note 12 to the consolidated financial statements. Foreign Exchange Risk The Company has a hedging program to eliminate 80% to 100% of the long-term exposure related to its foreign currency denominated cash flows. The Company also hedges certain of its foreign currency denominated net equity investments. The redemption of the investment in OCENSA also is hedged. Interest Rate Risk Enbridge is exposed to interest rate fluctuations on variable rate debt and floating to fixed swaps are used to manage this exposure. The Company monitors its levels of fixed and variable rate debt instruments and, from time to time, fixed to floating swaps are used to help maintain balances of each commensurate with the Company’s financing strategies. The Company also enters into interest rate derivatives to hedge a portion of the interest cost of future debt issues related to specific capital projects. Commodity Price Risk The Company uses over-the-counter natural gas price swaps, futures, options and collars to manage physical exposures that arise from the merchant capacity commitments on Alliance and Vector. For the period that the Enbridge Midcoast Energy assets were owned, the Company was exposed to the margin between the price of natural gas and natural gas liquids. Enbridge used over-the-counter commodity derivatives to fix the selling price of the natural gas liquids and the cost of purchasing natural gas to establish the margins. The derivative financial instruments used to manage this exposure were transferred to EEP as part of the sale transaction. Natural Gas Supply Management Customers of Enbridge Gas are exposed to changes in the price of the natural gas commodity. A portion of the future natural gas supply requirements is hedged using natural gas swaps and options that manage the price of natural gas, as allowed by the OEB. Since the cost of the natural gas commodity is paid by customers, this risk mitigation strategy is for the account of the customers. The OEB monitors the policies, procedures and results of this hedging program. Quarterly Financial Information Selected financial information for the eight most recently completed quarters is shown on page 70. E N B R I D G E I N C . M A N A G E M E N T ’ S R E P O R T M a n a g e m e n t ’ s R e p o r t To the Shareholders of Enbridge Inc. Management is responsible for the accompanying consolidated financial statements and all other information in this Annual Report. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and necessarily include amounts that reflect management’s judgement and best estimates. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements. Management has established systems of internal control that provide reasonable assurance that assets are safeguarded from loss or unauthorized use and produce reliable accounting records for the preparation of financial information. The internal control system includes an internal audit function and an established code of business conduct. The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit, Finance & Risk Committee of the Board, composed of directors who are not officers or employees of the Company, has a specific responsibility for ensuring that management fulfills its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management, internal auditors and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit, Finance & Risk Committee reports its findings to the Board for its consideration in approving the consolidated financial statements for issuance to the shareholders. PricewaterhouseCoopers LLP, appointed by the shareholders as the Company’s independent auditors, conducts an examination of the consolidated financial statements in accordance with Canadian generally accepted auditing standards. 39 Patrick D. Daniel President & Chief Executive Officer January 27, 2003 D.P. Truswell Group Vice President & Chief Financial Officer E N B R I D G E I N C . A u d i t o r s ’ R e p o r t A U D I T O R S ’ R E P O R T To the Shareholders of Enbridge Inc. We have audited the consolidated statements of financial position of Enbridge Inc. as at December 31, 2002 and 2001 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 2002. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2002 and 2001 and the results of its operations and cash flows for each of the years in the three year period ended December 31, 2002 in accordance with Canadian generally accepted accounting principles. 40 Calgary, Alberta, Canada January 27, 2003 Chartered Accountants 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 is a change in accounting principles that has a material effect on the comparability of the Corporation’s financial statements, such as the changes in stock-based compensation and accounting for goodwill described in Note 1 to the consolidated financial statements. Our report to the shareholders dated January 27, 2003 is expressed in accordance with Canadian reporting standards which do 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. Calgary, Alberta, Canada January 27, 2003 Chartered Accountants E N B R I D G E I N C . C O N S O L I D A T E D S T A T E M E N T S O F E A R N I N G S C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s (millions of Canadian dollars, except per share amounts) Year ended December 31, Revenues Gas sales Transportation Energy services Expenses Gas costs Operating and administrative Depreciation Loss on sale of Enbridge Midcoast Energy assets Operating Income Investment and Other Income (Note 15) Interest Expense (Note 8) Income Taxes (Note 13) Earnings From Continuing Operations Earnings From Discontinued Operations (Note 5) Earnings Preferred Security Distributions (Note 9) Preferred Share Dividends (Note 10) Earnings Applicable to Common Shareholders Earnings Applicable to Common Shareholders Continuing Operations Discontinued Operations Earnings Per Common Share (Note 10) Continuing Operations Discontinued Operations Diluted Earnings Per Common Share (Note 10) Continuing Operations Discontinued Operations C O N S O L I D A T E D S T A T E M E N T S O F R E T A I N E D E A R N I N G S (millions of Canadian dollars, except per share amounts) Year ended December 31, Retained Earnings at Beginning of Year Earnings Applicable to Common Shareholders Effect of Change in Accounting for Income Taxes Effect of Change in Accounting for Stock-Based Compensation Preferred Securities Issue Costs Common Share Dividends Retained Earnings at End of Year Dividends Paid Per Common Share 2002 812.3 576.5 – (5.4) (4.2) (251.1) 1,128.1 1.52 2001 581.3 458.5 – – – (227.5) 812.3 1.40 The accompanying notes to the consolidated financial statements are an integral part of these statements. E N B R I D G E I N C . 2002 2001 2000 2,987.7 1,296.6 263.2 4,547.5 2,578.0 834.1 403.9 122.7 3,938.7 608.8 283.1 (422.0) 469.9 (102.1) 367.8 242.3 610.1 (26.7) (6.9) 576.5 334.2 242.3 576.5 2.09 1.51 3.60 2.06 1.50 3.56 2,675.3 1,177.6 228.0 4,080.9 1,407.0 1,035.2 128.4 2,570.6 958.8 613.0 387.5 – 1,959.3 611.3 2,202.8 739.1 392.5 – 3,334.4 746.5 194.9171.5 (437.1)(389.2) 504.3 (66.7)(13.7) 437.6 45.334.6 482.9 (17.5)(15.3) (6.9)(6.9) 458.5392.3 413.2 45.3 458.5 2.63 0.28 2.91 2.60 0.28 2.88 41 393.6 379.9 414.5 357.7 34.6 392.3 2.32 0.22 2.54 2.31 0.22 2.53 2000 503.1 392.3 (112.0) – – (202.1) 581.3 1.27 C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S (millions of Canadian dollars) Year ended December 31, Cash Provided By Operating Activities Earnings from continuing operations Charges/(credits) not affecting cash Depreciation Equity earnings less than/(in excess of) cash distributions Gain on reduction of ownership interest (Note 7) Loss on foreign exchange contracts Gain on sale of securities Loss on sale of Enbridge Midcoast Energy assets (Note 3) Future income taxes Other Changes in operating assets and liabilities (Note 16) Cash provided by operating activities of discontinued operations 42 Investing Activities Acquisitions Long-term investments Additions to property, plant and equipment Sale of Energy Services business (Note 5) Sale of Enbridge Midcoast Energy assets (Note 3) Sale of other assets Sale of securities Repayments by/(loans to) affiliate Changes in construction payable Other Financing Activities Net change in short-term borrowings and short-term debt Long-term debt issues Long-term debt repayments Non-controlling interests Preferred securities issued Common shares issued Enbridge Energy Management shares issued (Note 7) Preferred security distributions Preferred share dividends Common share dividends Increase/(Decrease) in Cash Cash at Beginning of Year Cash at End of Year The accompanying notes to the consolidated financial statements are an integral part of these statements. E N B R I D G E I N C . 2002 2001 2000 367.8 437.6 379.9 403.9 (44.6) (10.0) – (21.4) 122.7 (64.7) (21.0) 151.6 26.3 910.6 (289.3) (1,282.7) (729.9) 993.3 529.3 73.8 110.5 358.1 (14.8) – (251.7) (1,180.9) 247.4 (382.7) 0.2 193.5 293.1 421.9 (26.7) (6.9) (251.1) (692.2) (33.3) 74.0 40.7 392.5 1.2 (23.4)– – – – 3.4 (75.6) (323.1)(515.4) 1.9 414.5 (599.1) (41.8) (683.3) – – – – (280.6) (14.0) (2.9) (1,621.7) 1,521.4 905.6 (979.6) (4.1) – 23.3 – (17.5) (6.9) (227.5) 1,214.7 7.5 66.5 74.0 387.5 (52.0) 24.5 – – (117.1) (23.0) 179.1 263.5 (16.5) (554.9) (364.3) – – – – – (5.7) (8.4) (949.8) (105.2) 965.4 (133.3) 21.2 – 175.4 – (15.3) (6.9) (202.1) 699.2 12.9 53.6 66.5 C O N S O L I D A T E D S T A T E M E N T S O F F I N A N C I A L P O S I T I O N C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s (millions of Canadian dollars) December 31, Assets Current Assets Cash Accounts receivable and other Gas in storage Current assets of discontinued operations (Note 5) Current assets held for sale (Note 3) Property, Plant and Equipment, net (Note 6) Long-Term Investments (Note 7) Receivable from Affiliate (Note 3) Deferred Amounts Future Income Taxes (Note 13) Long-Term Assets of Discontinued Operations (Note 5) Long-Term Assets Held for Sale (Note 3) Liabilities and Shareholders’ Equity Current Liabilities Short-term borrowings Accounts payable and other Interest payable Current maturities and short-term debt (Note 8) Current liabilities of discontinued operations (Note 5) Current liabilities held for sale (Note 3) Long-Term Debt (Note 8) Future Income Taxes (Note 13) Non-Controlling Interests (Note 7) Long-Term Liabilities of Discontinued Operations (Note 5) Shareholders’ Equity Share capital Preferred securities (Note 9) Preferred shares (Note 10) Common shares (Note 10) Retained earnings Foreign currency translation adjustment Reciprocal shareholding (Note 7) Commitments and Contingencies (Note 18) 2002 2001 40.7 817.5 583.8 – – 1,442.0 6,947.6 3,371.5 701.5 315.8 209.0 – – 12,987.4 247.5 714.1 102.6 652.3 – – 1,716.5 6,040.3 837.4 560.8 – 9,155.0 533.7 125.0 2,169.0 1,128.1 12.3 (135.7) 3,832.4 74.0 1,270.2 665.6 123.0 148.9 2,281.7 6,817.5 1,772.8 – 329.7 142.0 750.0 1,034.0 13,127.7 410.9 679.9 100.2 1,819.7 73.8 125.3 3,209.8 5,913.3 722.8 131.1 118.6 10,095.6 339.7 125.0 1,875.9 812.3 7.4 (128.2) 3,032.1 12,987.4 13,127.7 43 The accompanying notes to the consolidated financial statements are an integral part of these statements. Approved by the Board: Donald J. Taylor Chair Robert W. Martin Director E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s N O T E S T O T H E C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Enbridge Inc. (Enbridge or the Company) is a leader in the transportation and distribution of energy. Enbridge conducts its business through four operating segments: Energy Transportation North, Energy Transportation South, Energy Distribution, and International. These operating segments are strategic business units established by senior management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation decisions and to assess operational performance. Energy Transportation North Energy Transportation North includes the operation of a common carrier pipeline and feeder pipelines which transport crude oil and other liquid hydrocarbons, equity investments in natural gas transmission pipelines and an equity investment in a company engaged in natural gas gathering and processing. Energy Transportation South Energy Transportation South consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP) and Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership). The Partnership transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines, and transports, gathers, processes and markets natural gas and natural gas liquids. The Company owned 100% of the assets of Enbridge Midcoast Energy from May 2001 until October 2002, when they were sold to EEP. The business activities of Energy Transportation South are carried out in the United States. 44 Energy Distribution The Energy Distribution business consists of gas utility operations which serve residential, commercial, industrial and transportation customers, primarily in central and eastern Ontario. This business also includes natural gas distribution activities in Quebec, New Brunswick and New York State, as well as gas services operations, including the equity investment in Aux Sable. International The Company’s International business invests in energy transportation and related energy projects outside of Canada and the United States. This business also provides consulting and training services related to proprietary pipeline operating technologies and natural gas distribution. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements of the Company are prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP). These accounting principles are different in some respects from United States generally accepted accounting principles (U.S. GAAP) and the significant differences that impact the Company’s financial statements are described in Note 19. Amounts are stated in Canadian dollars unless otherwise noted. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the financial statements. Actual results could differ from those estimates. Basis of Presentation The consolidated financial statements include the accounts of Enbridge Inc., its subsidiaries and its proportionate share of the accounts of joint ventures. Investments in entities which are not subsidiaries or joint ventures, but over which the Company exercises significant influence, are accounted for using the equity method. Other investments are accounted for at cost. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s The Company’s Energy Distribution business is conducted primarily through a wholly owned subsidiary, Enbridge Gas Distribution Inc. (Enbridge Gas), formerly The Consumers’ Gas Company Ltd. The fiscal year-end of Enbridge Gas is September 30 and its results are consolidated on a one quarter lag basis, which reflects the results of Enbridge Gas operations in accordance with its regulatory, tax and operating cycles. Accordingly, references to "December 31" mean the financial position of Enbridge Gas as at September 30 and references to the "year ended December 31" mean the results of Enbridge Gas for the year ended September 30. Regulation The Company’s Energy Transportation and Energy Distribution activities are subject to regulation by various authorities, including the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters such as construction, rates and underlying accounting practices, and ratemaking agreements with customers. In order to recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under generally accepted accounting principles. Revenue Recognition Revenues are recorded when products have been delivered or services have been performed. Certain of the Energy Transportation and Energy Distribution operations are subject to regulation and, accordingly, there are circumstances where revenues recognized do not match the cash tolls or the billed amounts. For rate-regulated operations, revenue is recognized in a manner that is consistent with the underlying rate design as mandated by the regulatory authority. Certain other operations recognize revenue under the terms of enforceable, committed long-term delivery contracts. Income Taxes The regulated activities of the Company recover income tax expense based on the taxes payable method when prescribed by regulators for ratemaking purposes or when stipulated in ratemaking agreements. Therefore, rates do not include the recovery of future income taxes related to temporary differences. Consequently, the taxes payable method is followed for accounting purposes as there is reasonable expectation that all future income taxes will be recovered in rates when they become payable. For all other operations, the liability method of accounting for income taxes is followed. Future income tax assets and liabilities are determined based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Future income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. Effective January 1, 2000, the Company adopted new recommendations for accounting for income taxes. Adoption of the recommendations resulted in a charge to retained earnings of $112.0 million, of which $76.1 million related to rental assets of Enbridge Gas no longer regulated by the OEB, $22.4 million related to the tax effect of differences between the carrying amounts of investments and their respective tax bases, and the remaining $13.5 million related to other non-regulated assets. Foreign Currency Translation The functional currency of the Company’s foreign operations, except for certain financing and investing operations, is the U.S. dollar. These operations are self-sustaining and translated into Canadian dollars using the current rate method. Gains and losses resulting from these translation adjustments are included as a separate component of shareholders’ equity. E N B R I D G E I N C . 45 C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s The Company’s foreign financing and investing operations are integrated with those of the parent company and are translated into Canadian dollars using the temporal method. Gains and losses resulting from these translation adjustments are included in earnings. Cash Cash includes short-term and demand deposits with a term to maturity of three months or less and are recorded at cost. Gas in Storage Natural gas in storage is recorded in inventory at prices approved by the OEB in the determination of customer sales rates. The actual price of gas purchased may differ from the OEB-approved price and includes the effect of natural gas price risk management activities. The difference between the approved price and the actual cost of the gas purchased is deferred for future disposition by the OEB. Property, Plant and Equipment Expenditures for system expansion and major renewals and betterments are capitalized; maintenance and repair costs are expensed as incurred. Regulated operations capitalize an allowance for interest during construction and, if approved, an allowance for equity funds used during construction, at rates authorized by the regulatory authorities. Depreciation Depreciation of property, plant and equipment generally is provided on a straight-line basis over the estimated service lives of the assets. 46 Future Removal and Site Restoration Costs Future removal and site restoration costs for the Energy Transportation operations are not determinable and will be recognized when approved for recovery in tolls by the regulators. Accordingly, no provision has been made for these costs as there is reasonable expectation that they will be recovered through future tolls when they become payable. Depreciation expense for Energy Distribution operations includes a provision for future removal and site restoration costs at rates approved by the regulator. Actual costs incurred are charged to accumulated depreciation. Goodwill Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. Effective January 1, 2002, the Company adopted the new standard of the Canadian Institute of Chartered Accountants (CICA) related to goodwill and other intangible assets. Under the new standard, goodwill is not amortized but is tested for impairment at least annually and written down to fair value if the criteria for impairment are met. The standard is being applied prospectively. Goodwill arising from the acquisition of Midcoast Energy Resources, Inc. in May 2001 (sold to EEP in October 2002), was amortized on a straight-line basis over 30 years prior to the adoption of the new standard. Results of operations for the year ended December 31, 2001 included goodwill amortization of $7.2 million. This amortization reduced both earnings per common share and diluted earnings per common share by $0.05 for the year ended December 31, 2001. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Derivative Financial Instruments Gains and losses on financial instruments used to hedge the Company’s net investment in foreign operations are included in the foreign currency translation adjustment in shareholders’ equity. Amounts received or paid related to derivative financial instruments used to hedge the currency risk of cash flows from foreign currency denominated transactions are recognized concurrently with the hedged cash flows. Amounts received or paid related to derivative financial instruments used to hedge the price of energy commodities are recognized as part of the cost of the underlying physical purchases. For other derivative financial instruments used for hedging purposes, amounts received or paid, including any gains and losses realized upon settlement, are recognized over the term of the hedged item. The Company applies settlement accounting to derivative financial instruments. Under this method, gains and losses on derivative instruments that qualify for hedge accounting are not recorded until they are realized. The notional amounts are not recorded in the financial statements as they do not represent amounts exchanged by the counterparties. Post-Employment Benefits The Company maintains both defined benefit and defined contribution pension plans. Pension costs and obligations for the defined benefit pension plans are determined using the projected benefit method and are charged to earnings as services are rendered, except for the regulated operations of the Energy Distribution segment where contributions made to the plan are expensed as paid, consistent with the recovery of such costs in rates. For the defined contribution plans, contributions made by the Company are expensed. The Company also provides post-employment benefits other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependants. The cost of such benefits is accrued during the years employees render service, except for the regulated operations of the Energy Distribution segment where the cost of providing these benefits is expensed as paid, consistent with the recovery of such costs in rates. Stock-Based Compensation Effective January 1, 2002, the Company adopted the new CICA standard for stock-based compensation. Awards not required to be expensed under the new standard, such as stock options, are accounted for as capital transactions when the options are exercised. The standard requires retroactive application for certain other stock compensation awards as a charge to opening retained earnings without restatement of prior periods. Outstanding stock appreciation rights, which expire in 2003 and 2004, resulted in a charge to opening retained earnings, on adoption, of $5.4 million. Comparative Amounts Certain comparative amounts have been restated to conform with the current year’s financial statement presentation. Change in Accounting Policy In September 2002, the CICA announced the deferral of the effective date of the accounting guideline on Hedging Relationships to fiscal years beginning on or after July 1, 2003. In addition, in December 2002, the CICA approved an exposure draft to amend the guideline. As a result, the Company is deferring adoption of the new guideline. 47 E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 2. SEGMENTED INFORMATION Year ended December 31, 2002 (millions of dollars) Revenues Gas costs Operating and administrative Depreciation Loss on sale of Enbridge Midcoast Energy assets Operating income/(loss) Investment and other income Interest and preferred equity charges Income taxes Earnings/(loss) from North 742.7 – (263.6) (143.2) – 335.9 82.7 (99.8) (82.6) Energy Transportation Energy South Distribution International Corporate 1 Consolidated 27.2 4,547.5 (2,578.0) – (834.1) (19.0) (403.9) (2.9) 2,506.6 (1,526.6) (404.3) (229.9) 6.8 – (16.5) (3.1) 1,264.2 (1,051.4) (130.7) (24.8) (122.7) (65.4) 44.2 (28.1) 7.9 – 345.8 19.9 (161.1) (90.8) – 5.3 64.0 (1.6) 0.3 – (12.8) 72.3 (165.0) 63.1 continuing operations 236.2 (41.4) 113.8 68.0 (42.4) Earnings from discontinued operations Earnings applicable to common shareholders 48 Year ended December 31, 2001 Energy Transportation Energy (122.7) 608.8 283.1 (455.6) (102.1) 334.2 242.3 576.5 (millions of dollars) Revenues Gas costs Operating and administrative Depreciation Operating income/(loss) Investment and other income/(expense) Interest and preferred equity charges Income taxes Earnings/(loss) from North 695.6 – (242.6) (134.9) 318.1 69.6 (104.0) (78.6) South Distribution International Corporate1 Consolidated 30.8 708.8 4,080.9 (2,202.8) – (558.9) (739.1) (19.0) (71.3) (392.5) (2.5) (29.2) 746.5 9.3 49.4 194.9 27.0 53.0 (461.5) (0.1) (28.3) (66.7) (0.6) (27.7) 2,638.3 (1,643.9) (385.1) (222.1) 387.2 (0.2) (161.7) (43.5) 7.4 – (21.1) (3.8) (17.5) 45.5 (167.4) 83.7 continuing operations 205.1 46.4 181.8 35.6 (55.7) Earnings from discontinued operations Earnings applicable to common shareholders 413.2 45.3 458.5 E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Energy Transportation Energy North 699.5 – (243.9) (156.3) 299.3 55.3 (106.4) (55.6) South Distribution International Corporate 1 Consolidated 2,570.6 22.2 30.1 (958.8) – – (613.0) (17.8) (18.5) (387.5) (0.7) (7.5) 611.3 3.7 4.1 171.5 22.6 35.3 (411.4) – (1.9) (13.7) 0.1 (14.2) 1,812.4 (958.8) (307.8) (214.3) 331.5 50.8 (166.1) (13.0) 6.4 – (25.0) (8.7) (27.3) 7.5 (137.0) 69.0 Year ended December 31, 2000 (millions of dollars) Revenues Gas costs Operating and administrative Depreciation Operating income/(loss) Investment and other income Interest and preferred equity charges Income taxes Earnings/(loss) from continuing operations 192.6 23.3 203.2 26.4 (87.8) Earnings from discontinued operations Earnings applicable to common shareholders 357.7 34.6 392.3 1 Corporate includes new business development activities and investing and financing activities, including general corporate investments and financing costs not allocated to the business segments. 2 The measurement basis for preparation of segmented information is consistent with the significant accounting policies described in Note 1. 3 Segmented information was restated to reflect changes in the internal organization of the Company in the fourth quarter of 2002. Total Assets (millions of dollars) December 31, Energy Transportation North Energy Transportation South 1 Energy Distribution International Corporate Discontinued Operations 49 2002 4,621.3 1,151.1 5,275.8 830.7 1,108.5 12,987.4 – 12,987.4 2001 4,244.2 1,544.9 5,401.8 294.3 769.5 12,254.7 873.0 13,127.7 1 Includes goodwill of $330.4 million in 2001 related to the acquisition of Enbridge Midcoast Energy, sold in the fourth quarter of 2002, as described in Note 3. Additions to Property, Plant and Equipment (millions of dollars) Year ended December 31, Energy Transportation North Energy Transportation South Energy Distribution International and Corporate Discontinued Operations 2002 257.4 128.9 313.2 7.5 707.0 22.9 729.9 2001 216.1 85.9 302.6 35.2 639.8 43.5 683.3 2000 85.9 0.6 255.4 2.0 343.9 20.4 364.3 E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 2. SEGMENTED INFORMATION (continued) Geographic Information Revenues (millions of dollars) Year ended December 31, Canada United States Other Revenues are attributed to countries based on the country of origin of the product or services sold. Property, Plant and Equipment (millions of dollars) December 31, Canada United States Other 2002 3,102.3 1,418.0 27.2 4,547.5 2001 3,317.7 736.8 26.4 4,080.9 2002 6,733.6 204.8 9.2 6,947.6 2000 2,511.1 41.8 17.7 2,570.6 2001 6,630.4 176.9 10.2 6,817.5 50 3. SALE OF ENBRIDGE MIDCOAST ENERGY ASSETS In October 2002, the Company closed the sale of the United States assets of Enbridge Midcoast Energy to EEP, including the Northeast Texas assets described in Note 4, for proceeds of US$820.0 million. The Company received cash proceeds of approximately US$339.0 million and the remaining consideration, in the form of assumed affiliate debt, will be settled when EEP secures additional financing. The Company continues to exercise significant influence over the assets sold and, for the period that the assets were held for sale, results of operations were not segregated from continuing operations. For the year ended December 31, 2002, excluding the loss on sale of $82.2 million after tax, the assets generated after-tax earnings of $7.3 million. 4. ACQUISITIONS Northeast Texas In March 2002, the Company acquired natural gas gathering and processing facilities in Northeast Texas for cash consideration of $289.3 million. These assets are included in the sale described in Note 3. The results of operations have been included in the consolidated statement of earnings for the period of ownership. (millions of dollars) Fair Value of Assets Acquired Property, plant and equipment Goodwill Working capital deficiency Purchase Price Cash Transaction costs E N B R I D G E I N C . 242.3 56.2 (9.2) 289.3 288.2 1.1 289.3 C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Midcoast Energy Resources, Inc. On May 11, 2001, the Company acquired all the outstanding shares of Midcoast Energy Resources, Inc., a Houston-based energy company, for cash consideration of $561.8 million and the assumption of long-term debt. This business is included in the sale described in Note 3. The acquisition was accounted for using the purchase method and the results of operations have been included in the consolidated statements of earnings from the date of acquisition until they were sold in October 2002. (millions of dollars) Fair Value of Assets Acquired Property, plant and equipment Working capital deficiency Goodwill Future income taxes Other non-current assets Purchase Price Cash Long-term debt assumed Transaction costs 677.3 (37.2) 328.9 (39.0) 37.8 967.8 554.5 406.0 7.3 967.8 51 Frontier Pipeline Company The Company acquired an additional 34.0% interest in Frontier Pipeline Company for $46.0 million in December 2001, increasing the Company’s ownership to 77.8%. The purchase price was allocated primarily to property, plant and equipment. 5. DISCONTINUED OPERATIONS The sale of the Company’s operations that provide energy products and services to retail and commercial customers, including the water heater rental program, closed in May 2002. Selected financial information related to discontinued operations is as follows. Earnings (millions of dollars) Year ended December 31, Net gain on disposition, net of tax Earnings Earnings from discontinued operations Selected Earnings Information (millions of dollars) Year ended December 31, Revenues Income tax expense/(recovery) Allocated interest expense 2002 240.0 2.3 242.3 2002 181.9 34.6 12.1 2001 – 45.3 45.3 2001 463.0 2.5 35.4 2000 – 34.6 34.6 2000 388.5 (15.6) 38.5 E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 6. PROPERTY, PLANT AND EQUIPMENT (millions of dollars) December 31, 2002 Energy Transportation North Energy Transportation South Energy Distribution Other Weighted Average Depreciation Rate 3.3% 4.1% 3.6% 6.6% (millions of dollars) December 31, 2001 Energy Transportation North Energy Transportation South Energy Distribution Other Weighted Average Depreciation Rate 2.5% 3.9% 3.2% 6.1% 7. LONG-TERM INVESTMENTS (millions of dollars) December 31, Equity Investments Energy Transportation North 52 Alliance Pipeline Vector Pipeline AltaGas Services Energy Transportation South The Partnership Chicap Pipeline Energy Distribution Noverco Aux Sable International Compañía Logistica de Hidrocarburos (CLH) Other Cost Investments Energy Distribution Noverco International OCENSA Pipeline Global Thermoelectric E N B R I D G E I N C . Accumulated Cost Depreciation 1,657.9 99.7 822.3 21.1 2,601.0 4,526.2 262.0 4,687.4 73.0 9,548.6 Accumulated Cost Depreciation 1,516.8 90.0 706.7 12.5 2,326.0 4,260.1 266.9 4,542.2 74.3 9,143.5 Net 2,868.3 162.3 3,865.1 51.9 6,947.6 Net 2,743.3 176.9 3,835.5 61.8 6,817.5 Ownership Interest 2002 2001 37.1% 45.0% 40.3% 14.1% 22.8% 32.1% 30.9% 25.0% 678.6 474.8 204.2 1,357.6 376.6 472.9 181.1 1,030.6 815.5 32.4 847.9 28.9 135.0 163.9 541.2 31.2 93.5 31.7 125.2 33.9 124.6 158.5 – 28.8 181.4 181.4 223.3 25.0 3,371.5 223.3 25.0 1,772.8 C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Equity investments include $551.9 million (2001 — $208.1 million) representing the unamortized excess of the purchase price over the underlying net book value of the investee’s assets at the date of purchase. The excess has been allocated to property, plant and equipment on the basis of estimated fair values and is amortized over the economic life of the assets. In October 2002, EEM, a partially-owned subsidiary, completed an initial public offering of 9,000,000 limited liability shares. The proceeds from the offering were used to purchase i-units, a new class of limited partnership interests from EEP. The Company purchased 17.2% of the EEM shares, increasing its total net investment in the Partnership to 14.1% from 12.9%. Although 82.8% of EEM is widely held, the Company has voting control of EEM. The Company’s statement of financial position includes 100% of EEM’s investment in EEP which totals $529.9 million. The Company’s net investment in the Partnership, after deducting the non-controlling interest of $438.8 million, is $376.7 million. In 2002 and prior to the formation of EEM, EEP completed a public issue of partnership units. As the Company elected not to participate in this offering, its effective interest in EEP was reduced to 12.9% from 13.6%. This resulted in recognition of a dilution gain of $10.0 million, before tax. In 2001, EEP completed two public issues of partnership units, in which the Company elected not to participate. As a result of these offerings, the Company’s effective ownership interest in EEP was reduced to 13.6% from 15.3%, resulting in recognition of dilution gains of $23.4 million, before tax. In 2002, the Company invested $294.7 million in Alliance and $20.6 million in Aux Sable, increasing the Company’s ownership interests from 21.4% to 37.1% and 21.4% to 30.9%, respectively. The purchase price included $7.1 million representing the excess of the purchase price over the underlying net book value of the assets. The excess has been allocated to property, plant and equipment and is being amortized over the economic life of the assets. 53 In 2002, the Company invested $430.8 million in CLH, a refined products transportation and storage company in Spain. The Company’s 25% interest is accounted for by the equity method. Contingent consideration of up to 90 million Euros ($149.1 million) will become payable over the next four years if certain minimum annual volume targets are met. The purchase price included $340.9 million representing the excess of the purchase price over the underlying net book value of the assets. The excess has been allocated to property, plant and equipment and is being amortized over the economic life of the assets. Noverco holds an approximate 10% reciprocal shareholding in the Company. As a result, the Company has a pro-rata interest of 3.2% in its own shares (2001 — 3.2%). Both the equity investment in Noverco Inc. and shareholders’ equity have been reduced by the reciprocal shareholding of $135.7 million (2001 — $128.2 million). Income from Equity Investments (millions of dollars) Year ended December 31, Energy Transportation North Energy Transportation South Energy Distribution International 2002 78.6 41.9 (3.7) 34.1 150.9 2001 65.6 32.0 (17.9) 0.3 80.0 2000 54.2 37.7 7.5 – 99.4 Consolidated retained earnings at December 31, 2002 includes undistributed earnings from equity investments of $155.7 million (2001 — $104.1 million). E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 8. DEBT (millions of dollars) December 31, Energy Transportation North Debentures Medium-term notes Other 1 Energy Transportation South Senior term notes 2 (US$275.0 million) Variable rate credit facility 3 Energy Distribution Debentures Medium-term notes 4 Other Corporate Medium-term notes Variable rate credit facility Preferred securities (Note 9) Other 5 Total Debt Weighted Average Interest Rate 9.07% 6.66% 8.08% 11.00% 5.86% 6.14% 7.79% 54 Current maturities of long-term debt Other short-term debt Current Maturities and Short-Term Debt Long-Term Debt 1 Primarily commercial paper borrowings. 2 The principal amount is recorded at the swapped rate. 3 Includes US$160.0 million (2001 — US$300.0 million). 4 Includes $100.0 million floating rate note swapped to 3.03%. 5 Primarily commercial paper borrowings. Includes US$582.5 million (2001 — US$470.2 million). Maturity 2008-2024 2005-2029 2005-2007 2003 2004-2024 2003-2028 2004-2032 2005 2048-2051 2002 300.0 622.5 58.8 397.8 252.7 635.0 1,105.0 9.0 1,788.7 400.0 16.3 1,106.8 6,692.6 225.0 427.3 652.3 6,040.3 2001 300.0 622.3 150.1 397.8 477.8 635.0 1,105.0 9.5 1,927.9 400.0 10.3 1,697.3 7,733.0 325.0 1,494.7 1,819.7 5,913.3 Short-term debt in the amount of $1,000.0 million (2000 — $840.0 million) is supported by the availability of long-term committed credit facilities and has been classified as long-term debt. Long-term debt maturities for the years ending December 31, 2003 through 2007 are $225.0 million, $450.0 million, $928.6 million, $440.0 million and $369.3 million, respectively. Short-term Borrowings Short-term borrowings, which primarily finance gas in storage and other working capital items, are comprised of commercial paper with maturities of less than one year. Of these borrowings, $100 million (2001 — $200.0 million) was swapped to a weighted average fixed interest rate of 2.6% (2001 — 5.7%). E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Weighted Average Effective Rate1 2002 2001 Notional Amounts 6.04% 7.40% – – 2.30% – 25.4 25.4 US$275.0 – US$275.0 US$140.0 – 400.0 – 40.0 400.0 150.0 2002 392.9 29.0 9.6 (9.5) 422.0 2001 345.0 85.8 12.2 (5.9) 437.1 2000 375.2 1.5 18.5 (6.0) 389.2 55 Interest Rate Management (millions of dollars) December 31, Energy Transportation North Commercial paper Energy Transportation South Senior term notes 2 Variable rate credit facilities Corporate Medium-term notes Variable rate debt Commercial paper 1 Reflects the effective rate after giving effect to floating to fixed swap agreements. 2 Subject to a cross-currency swap. Interest Expense (millions of dollars) Year ended December 31, Long-term debt Commercial paper and other short-term debt Short-term borrowings Capitalized In 2002, total interest paid was $429.3 million (2001 — $452.2 million; 2000 — $372.0 million). Credit Facilities (millions of dollars) December 31, 2002 Energy Transportation North Energy Transportation South (US$300.0 million) Energy Distribution Corporate Committed Uncommitted – – 5.5 – 5.5 150.0 473.9 659.0 1,900.0 3,182.9 Drawdowns – 252.7 14.5 400.0 667.2 Committed facilities carry a weighted average standby fee of 0.097% per annum on the unutilized portion. The committed facilities for Energy Transportation North, Energy Transportation South and Energy Distribution expire in 2003 and are extendible annually subject to the approval of the lenders. The committed facilities for Corporate expire in 2003, 2005 and 2007 and are extendible annually thereafter subject to the approval of the lenders. Drawdowns under all of these facilities bear interest at prevailing market rates. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 9. PREFERRED SECURITIES In 2002, the Company completed a public offering of 7.8% Preferred Securities for $200.0 million. Net proceeds were $193.5 million. The Company also has outstanding $175.0 million of 7.6% and $175.0 million of 8.0% Preferred Securities. The Preferred Securities may be redeemed at the Company’s option, in whole or in part, after the fifth anniversary of each issue. The Company has the right to defer, subject to certain conditions, payments of distributions on the securities for up to 20 consecutive quarterly periods. Since deferred and regular distributions may be settled through the issuance of common shares at the Company’s option, the Preferred Securities are classified into their respective debt and equity components. The equity component of the Preferred Securities is $533.7 million at December 31, 2002 (2001 — $339.7 million). 10. SHARE CAPITAL The authorized share capital of the Company consists of an unlimited number of common shares with no par value and an unlimited number of preferred shares. Common Shares (millions of dollars; number of common shares in millions) December 31, 56 Balance at beginning of year Dividend Reinvestment and Share Purchase Plan Issued to Noverco Public issue Other Balance at end of year 2002 2001 2000 Number of Shares 162.9 0.2 0.5 5.0 1.1 169.7 Amount 1,875.9 8.3 23.1 225.4 36.3 2,169.0 Number of Shares 161.8 0.2 – – 0.9 162.9 Amount 1,852.6 7.2 – – 16.1 1,875.9 Number of Shares 156.3 0.2 0.6 4.5 0.2 161.8 Amount 1,677.2 7.2 19.7 143.9 4.6 1,852.6 Preferred Shares The 5,000,000 5.5% Cumulative Redeemable Preferred Shares, Series A are entitled to fixed, cumulative, preferential dividends of $1.375 per share per year, payable quarterly. On or after December 31, 2003, the Company may, at its option, redeem all or a portion of the outstanding preferred shares for $26.00 per share if redeemed on or prior to December 1, 2004; $25.75 if redeemed on or prior to December 1, 2005; $25.50 if redeemed on or prior to December 1, 2006; $25.25 if redeemed on or prior to December 1, 2007; and $25.00 if redeemed thereafter, in each case with all accrued and unpaid dividends to the redemption date. Earnings Per Common Share Earnings per common share is calculated by dividing earnings applicable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of shares outstanding has been reduced by the Company’s pro-rata weighted average interest in its own common shares of 5.3 million shares (2001 — 5.2 million shares), resulting from the investment in Noverco. The treasury stock method, used for calculating diluted earnings per share, uses an adjusted weighted average number of common shares outstanding which reflects the exercise of stock options. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s (number of common shares in millions) December 31, Weighted average shares outstanding Effect of dilutive securities Stock options Diluted weighted average shares outstanding 2002 160.3 1.7 162.0 2001 157.3 1.5 158.8 2000 154.5 0.8 155.3 Dividend Reinvestment and Share Purchase Plan Under the plan, registered shareholders may reinvest dividends in common shares of the Company or make optional cash payments to purchase additional common shares, in either case free of brokerage or other charges. Shareholder Rights Plan The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Rights issued under the plan become exercisable when a person, and any related parties, acquires or announces the intention to acquire 20% or more of the Company’s outstanding common shares without complying with certain provisions set out in the plan or without approval of the Board of Directors of the Company. Should such an acquisition or announcement occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase common shares of the Company at a 50% discount to the market price at that time. 11. STOCK OPTION PLAN The Company’s Incentive Stock Option Plan (1999) includes fixed stock options and performance-based stock options. A maximum of 12 million common shares is reserved for issuance under the plan. 57 Fixed Stock Options Full-time, key employees are granted options to purchase common shares that are exercisable at the market price of common shares at the date the options are granted. Generally, options vest in equal annual installments over a four-year period and expire ten years after the issue date. Outstanding stock options expire over a period ending no later than September 16, 2012. Outstanding Options (options in thousands; exercise price in dollars) December 31, Options at beginning of year Options granted Options exercised Options cancelled or expired Options at end of year Options vested 2002 2001 2000 Weighted Average Exercise Price 29.06 43.80 26.31 37.59 32.16 Number 5,120 1,024 (1,003) (99) 5,042 2,639 Weighted Average Exercise Price 26.76 30.11 19.27 34.47 29.06 Number 4,112 2,024 (843) (173) 5,120 2,853 Weighted Average Exercise Price 26.63 26.74 19.85 31.17 26.76 Number 3,116 1,360 (179) (185) 4,112 1,757 E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 11. STOCK OPTION PLAN (continued) Option Characteristics (options in thousands; exercise price in dollars) December 31, 2002 Exercise Price Range 12.44-19.99 20.00-29.99 30.00-39.99 40.00-47.71 Number Options Outstanding Weighted Average Remaining (000’s) Life (years) 1.84 6.29 6.95 9.09 532 1,445 2,027 1,038 5,042 Weighted Average Exercise Price 16.74 25.81 35.61 42.14 Options Vested Weighted Average Exercise Price 16.74 25.21 34.47 40.10 Number (000’s) 532 867 1,229 11 2,639 Performance-Based Options The Plan provides for the grant of performance-based options to executive officers. Vesting is based on the performance of the Company’s common share price. New performance-based options were granted in 2002. The options vest in equal annual installments over a five-year period and become exercisable, as to 50% of the grant, when the market price of a common share exceeds $61.00 per share for 20 consecutive trading days during the five-year period ended September 16, 2007. If the share price exceeds $71.00 for 20 consecutive trading days prior to September 16, 2007, the remaining options will become exercisable. The performance-based options expire on September 16, 2007 if the share price target is not reached but extend to September 16, 2010 for options that become exercisable. 58 (options in thousands; exercise price in dollars) December 31, Options at beginning of year Options granted Options exercised Options cancelled Options at end of year Options vested 2002 2001 2000 Weighted Average Exercise Price 32.03 46.30 31.66 – 37.73 32.10 Number 1,479 810 (244) – 2,045 1,235 Weighted Average Exercise Price 31.60 41.13 – 31.35 32.03 31.31 Number 1,480 65 – (66) 1,479 740 Weighted Average Exercise Price 31.60 – – – 31.60 – Number 1,480 – – – 1,480 – E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Pro Forma Compensation Expense If the Company had used the fair-value based method to account for fixed stock options and performance-based options, earnings and earnings per share would have been as follows. (millions of dollars) Year ended December 31, Earnings applicable to common shareholders from continuing operations As reported Stock-based compensation expense Pro forma Earnings applicable to common shareholders As reported Stock-based compensation expense Pro forma Earnings per common share from continuing operations As reported Pro forma Earnings per common share As reported Pro forma 2002 334.2 2.9 331.3 576.5 2.9 573.6 2.09 2.07 3.60 3.58 59 1 Pro forma earnings and earnings per share do not reflect options granted prior to January 1, 2002, the date of adoption of the standard on stock-based compensation. 2 The Black-Scholes model was used to calculate the fair value of the fixed stock options. Significant assumptions include a risk-free interest rate of 5.33%, expected volatility of 25%, an expected life of 10 years and an expected dividend yield of 3.51%. The weighted average grant-date fair value was $11.42 for the fixed stock options granted during the year ended December 31, 2002. 3 A barrier valuation model was used to calculate the fair value of the performance-based options. Significant assumptions include a risk-free interest rate of 4.20%, expected volatility of 24%, an expected life of 8 years and an expected dividend yield of 3.46%. The weighted average grant-date fair value was $7.65 for performance-based options granted during the year ended December 31, 2002. 12. FINANCIAL INSTRUMENTS Derivative Financial Instruments Used for Risk Management The Company is exposed to movements in foreign currency exchange rates, interest rates and the price of energy commodities, primarily natural gas. In order to manage these exposures for both shareholders and ratepayers, the Company utilizes derivative financial instruments to create offsetting positions to specific exposures. These instruments are not used for speculative purposes. Derivative financial instruments involve credit and market risks. Credit risk arises from the possibility that a counterparty will default on its contractual obligations and is limited to those contracts where the Company would incur a loss in replacing the instrument. The Company minimizes credit risk by entering into risk management transactions only with institutions that possess investment grade credit ratings or with approved forms of collateral. For transactions with terms greater than five years, the Company may also retain the right to require a counterparty, that would otherwise meet the Company’s credit criteria, to provide collateral. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 12. FINANCIAL INSTRUMENTS (continued) Foreign Exchange The Company has an exposure to foreign currency exchange rates, primarily because of its U.S. dollar denominated investments and its Euro investment in CLH where both carrying values and earnings are subject to foreign exchange risk. The Company utilizes par forward contracts and cross currency swaps to manage a portion of the foreign exchange exposure. In addition, cross currency swaps have been entered into to hedge the Company’s exposure on its U.S. dollar denominated senior term notes. Interest Costs The Company enters into forward interest rate agreements, swaps and collars to swap floating rate debt to fixed and hedge against the effect of future interest rate movements on its variable rate debt. The Company monitors its debt portfolio mix of fixed and variable rate instruments and has entered into fixed to floating interest rate swaps, with notional amounts of $300 million, to manage the balance of fixed and floating rate debt. Energy Commodity Costs As a result of the sale of the assets of Enbridge Midcoast Energy, the Company’s commodity price risk exposure arising from holding inventory and purchase and sale commitments has been reduced. The Company continues to use over-the-counter natural gas price swaps, futures, options and collars to manage physical exposures that arise in the management of merchant capacity commitments to the Alliance and Vector pipelines. 60 Natural Gas Supply Management The Company hedges a portion of the cost of future natural gas supply requirements of Enbridge Gas, as allowed by the regulator. Amounts paid or received under the hedge agreements are recognized as part of the cost of the natural gas purchases and are recovered through the ratemaking process. At December 31, 2002, the Company had entered into natural gas price swaps and options to manage the price for approximately 4.3%, or 5.9 billion cubic feet, of its forecast fiscal 2003 system gas supply. Fair Values The fair values of derivatives have been estimated using year-end market information. These fair values approximate the amount that the Company would receive or pay to terminate the contracts. (millions of dollars) December 31, Foreign exchange U.S. cross currency swaps Euro cross currency swaps Forwards (cumulative 2002 Notional Fair Value Principal Receivable/ 2001 Notional Fair Value Principal Receivable/ or Quantity (Payable) Maturity or Quantity (Payable) Maturity 535.8 371.1 24.9 (54.4) 2005-2022 2003 535.8 – 26.3 – 2005-2022 – exchange amounts) 1,993.0 (244.6) 2003-2022 2,130.1 (165.9) 2002-2022 Energy Commodities Natural gas (bcf) Natural gas supply management (bcf) Interest rates Interest rate swaps Forward interest rate swaps 35.3 5.9 934.1 – (1.5) 2003-2004 (0.2) 2003 0.6 – 2003-2029 – 74.4 36.0 955.4 600.0 (41.1) 2002-2006 (37.1) 2002 (12.7) 2002-2029 2002 (6.5) E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s In addition, the Company has forward foreign exchange contracts with a notional principal of Canadian $449 million, to exchange Canadian for U.S. dollars. The instruments expire in 2003, 2005 and 2007. The contracts are not effective hedges for accounting purposes but offset an exposure related to income taxes on foreign currency gains or losses on Canadian dollar debt of a U.S. subsidiary. These instruments are recorded at fair value and have a fair value receivable of $36.9 million as at December 31, 2002 (2001 — $23.9 million). As the Company has not settled any hedging instruments in advance of the hedged transactions, there were no deferred gains or losses for any of the Company’s hedges of anticipated transactions at December 31, 2002 and 2001. A credit risk on derivative financial instruments amounted to $105.3 million at December 31, 2002 with no significant concentration with any single counterparty. Fair Values of Other Financial Instruments The fair value of financial instruments, other than derivatives, represents the amounts that would have been received from or paid to counterparties, calculated at the reporting date, to settle these instruments. The carrying amount of all financial instruments classified as current approximates fair value because of the short maturities of these instruments. The estimated fair values of all other financial instruments are based on quoted market prices or, in the absence of specific market prices, on quoted market prices for similar instruments and other valuation techniques. The carrying amounts of all financial instruments, except for debt, approximate fair value. The fair value of debt does not include the effects of hedging. Total Debt (millions of dollars) December 31, Energy Transportation North Energy Transportation South Energy Distribution Corporate 61 2002 2001 Carrying Amount 981.3 650.5 1,749.0 3,311.8 6,692.6 Fair Value 1,084.5 686.6 1,989.2 3,394.7 7,155.0 Carrying Amount 1,072.4 875.6 1,749.5 4,035.5 7,733.0 Fair Value 1,116.8 910.6 1,956.6 4,055.6 8,039.6 Trade Credit Risk Trade receivables related to Energy Transportation North consist primarily of amounts due from companies operating in the oil and gas industry and are collateralized by the crude oil and other products contained in the Company’s pipelines and storage facilities. Credit risk in the Energy Distribution segment is reduced by the large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. Included in accounts receivable is an allowance for doubtful accounts of $31.1 million at December 31, 2002 (2001 — $29.9 million). E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 13. INCOME TAXES Income Tax Rate Reconciliation (millions of dollars) Year ended December 31, Earnings before income taxes Combined statutory income tax rate Income taxes at statutory rate Increase/(decrease) resulting from: Tax rate reductions on future income tax balances Future income taxes related to regulated operations Non-taxable items, net Lower foreign tax rates Large Corporations Tax in excess of surtax Other Income Taxes Continuing operations Discontinued operations 2002 746.9 38.0% 283.8 8.1 (36.7) (99.5) (42.2) 16.9 6.3 136.7 102.1 34.6 136.7 2001 552.1 41.0% 226.3 (67.5) (35.7) (28.2) (36.8) 18.8 (7.7) 69.2 66.7 2.5 69.2 Effective income tax rate 18.3% 12.5% 62 2000 412.6 43.3% 178.8 (103.7) (40.9) (31.0) (21.0) 16.1 (0.2) (1.9) 13.7 (15.6) (1.9) – In 2002, income taxes paid amounted to $105.2 million (2001 — $110.5 million; 2000 — $114.7 million). Components of Future Income Taxes (millions of dollars) December 31, Future Income Tax Liabilities Differences in accounting and tax bases of property, plant and equipment Differences in accounting and tax bases of investments Other Future Income Tax Assets Loss carryforwards Other Total Net Future Income Tax Liability 2002 313.8 525.7 110.1 949.6 283.0 38.2 321.2 628.4 2001 403.5 267.6 154.5 825.6 232.1 12.7 244.8 580.8 Accumulated future income taxes related to rate-regulated operations which have not been recorded in the accounts amounted to $511.2 million at December 31, 2002 (2001 — $506.3 million). Had the liability method been prescribed by the regulatory authorities for ratemaking purposes, such amounts would have been recorded and recovered in revenues. At December 31, 2002, the Company has recognized the benefit of unused tax loss carryforwards of $822.4 million. Unused tax loss carryforwards expire as follows: 2003 — $1.6 million; 2004 — $5.8 million; 2005 — $33.8 million; 2006 — $129.1 million; 2007 — $182.3 million; 2008 — $69.2 million and 2009 and beyond — $400.6 million. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Geographic Components of Pretax Earnings and Income Taxes (millions of dollars) Year ended December 31, Earnings before income taxes Canada United States Other Continuing operations Discontinued operations Current income taxes Canada United States Other Continuing operations Discontinued operations Future income taxes Canada United States Other Continuing operations Discontinued operations Continuing operations Discontinued operations 2002 346.1 (5.0) 128.8 469.9 276.9 746.8 154.8 3.2 8.8 166.8 36.9 203.7 (54.5) (10.5) 0.3 (64.7) (2.3) (67.0) 102.1 34.6 136.7 2001 297.2 103.8 103.3 504.3 47.8 552.1 44.4 8.9 10.0 63.3 20.1 83.4 (9.0) 12.4 – 3.4 (17.6) (14.2) 66.7 2.5 69.2 2000 273.3 73.3 47.0 393.6 19.0 412.6 129.4 (4.5) 5.9 130.8 24.4 155.2 (112.4) (4.7) – (117.1) (39.9) (157.0) 13.7 (15.6) (1.9) 63 14. POST-EMPLOYMENT BENEFITS Pension Plans The Company has three pension plans which provide either defined benefit or defined contribution pension benefits or both for employees of the Company. The Energy Transportation North pension plan provides non- contributory defined pension and/or defined contribution benefits to employees. The Energy Transportation South pension plan provides either non-contributory defined benefit pension benefits or contributory defined contribution pension benefits. The Enbridge Gas pension plan provides contributory defined benefit pension and/or defined contribution benefits to the majority of its employees. Defined Benefit Plans Retirement benefits under defined benefit plans are based on employees’ years of service and remuneration. Contributions made by the Company are made in accordance with independent actuarial valuations and are invested primarily in publicly traded equity and fixed income securities. The most recent actuarial valuation was performed as of January 1, 2002. Pension costs under the defined benefit pension plans reflect management’s best estimates of the rate of return on pension plan assets, rate of salary increases and various other factors including mortality rates, terminations and retirement ages. Adjustments arising from plan amendments, actuarial gains and losses, and changes to assumptions are amortized over the expected average remaining service lives of the employees. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 14. POST-EMPLOYMENT BENEFITS (continued) Defined Contribution Plans Contributions are generally based on the employee’s age and/or years of service. For the Energy Transportation South pension plan, contributions to the defined contribution plans are also based on employee contributions. For defined contribution pension benefits, pension expense equals amounts required to be contributed by the Company. Post-employment Benefits Other than Pensions Post-employment benefits other than pensions (OPEB) include supplemental health, dental and life insurance coverage for qualifying retired employees. The following tables detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability using the accrual method. 64 (millions of dollars) Change in benefit obligation Benefit obligation, January 1 Service cost Interest cost Amendments Employee contributions Actuarial loss Benefits paid Divestitures Effect of exchange rate changes Benefit obligation, December 31 Fair value of plan assets Fair value of plan assets, January 1 Actual return on plan assets Employer’s contributions Employee contributions Benefits paid Other Divestitures Effect of exchange rate changes Fair value of plan assets, December 31 Asset/(Liability) Plan assets in excess/(deficiency) of projected benefit obligations Unrecognized prior service cost Unrecognized plan surplus Unrecognized net loss/(gain) Recorded asset/(liability) 2002 OPEB 2001 OPEB 2002 Pension Benefit 2001 Pension Benefit 132.3 4.2 8.8 – 0.3 31.4 (5.7) (10.6) (0.2) 160.5 29.6 3.0 8.5 0.3 (5.7) – – (0.2) 35.5 (125.0) 3.4 36.2 31.5 (53.9) 113.5 3.7 8.0 2.8 0.3 6.4 (4.7) – 2.3 132.3 23.8 2.3 6.4 0.3 (4.7) – – 1.5 29.6 (102.7) 3.6 46.3 2.8 (50.0) 742.7 18.7 45.9 0.7 0.1 8.5 (37.9) (67.8) (0.8) 710.1 1,076.7 (20.3) 19.7 0.1 (37.9) (2.3) (100.9) (2.0) 933.1 223.0 20.8 – 4.8 248.6 651.2 20.4 45.4 22.1 4.1 38.2 (44.0) – 5.3 742.7 1,218.8 (122.9) 9.4 4.1 (44.0) – – 11.3 1,076.7 334.0 25.6 – (119.7) 239.9 E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s Net Pension Plan and OPEB Costs (millions of dollars) Year ended December 31, Benefits earned during the year Interest cost on projected benefit obligations Expected return on plan assets Amortization and deferral of unrecognized amounts Amount credited to EEP Pension and OPEB expense/(credit) 2002 25.2 54.5 (75.3) 6.9 (1.7) 9.6 2001 26.3 55.2 (93.7) (6.8) 5.5 (13.5) 2000 23.0 51.1 (76.2) (8.9) 6.5 (4.5) The above tables reflect the funded status, recorded pension and OPEB assets and liabilities and pension and OPEB expense for all of the Company’s benefit plans on an accrual basis. However, in accordance with its ability to recover employee benefit costs on a pay-as-you-go basis for the regulated operations of Enbridge Gas, the Company records the cost of such benefits on a cash basis. Using the cash basis for the Enbridge Gas plans and the accrual method for other plans, the Company’s pension expense was $3.6 million (2001 — $4.0 million credit; 2000 — $2.7 million expense). The pension asset was $73.1 million (2001 — $64.8 million). The Company’s OPEB expense totalled $6.8 million (2001 — $5.9 million; 2000 — $5.6 million). The OPEB liability was $8.4 million (2001 — $6.8 million). The pension and OPEB assets and obligations for discontinued operations were included in the sale transaction. Economic Assumptions The assumptions made in the measurement of pension expense and the projected benefit obligation or asset of the pension plans and OPEB are as follows. 65 Year ended December 31, Discount rate Average rate of salary increases Average rate of return on pension plan assets Medical cost trend rate Dental cost trend rate 2002 OPEB 2001 OPEB 6.75-7.25% 7.0-7.5% 2000 OPEB 2001 2002 Pension Pension Benefits Benefits 7.0-7.5% 6.75-7.25% 6.75-7.5% 4.0% 4.0% 2000 Pension Benefits 7.0-7.5% 4.0% 4.5-14.0% 4.5-11.0% 4.5-6.0% 4.5-5.5% 4.5-6.8% 4.5-6.0% 3.90-8.0% 7.75-8.0% 7.75-8.0% A 1% change in the assumed medical and dental care trend rate would result in a change of $27.1 million in the accumulated post-employment benefit obligations and a change of $2.2 million in OPEB expense. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 15. INVESTMENT AND OTHER INCOME (millions of dollars) Year ended December 31, Equity investments Cost investments Investment income Allowance for equity funds used during construction Gain/(loss) on foreign currency contracts Gain on reduction of EEP ownership interest Gain on sale of marketable securities Other 16. CHANGES IN OPERATING ASSETS AND LIABILITIES (millions of dollars) Year ended December 31, Accounts receivable and other Gas in storage Deferred amounts Accounts payable and other Interest payable 66 2002 150.9 61.1 22.9 5.3 0.1 10.0 21.4 11.4 283.1 2002 75.0 76.0 72.4 (76.4) 4.6 151.6 2001 80.0 51.9 16.3 3.9 (1.7) 23.4 – 21.1 194.9 2001 (583.7) (145.8) (77.6) 493.1 (9.1) (323.1) 2000 99.4 44.4 14.7 2.7 (24.5) – – 34.8 171.5 2000 (65.3) (144.7) (195.8) (132.8) 23.2 (515.4) Changes in accounts payable exclude changes in construction payables which are investing activities. 17. RELATED PARTY TRANSACTIONS EEP does not have any employees and uses the services of the Company for managing and operating its business. These services, which are charged at cost in accordance with service agreements, amounted to $97.2 million (2001 — $56.2 million; 2000 — $46.7 million). 18. COMMITMENTS AND CONTINGENCIES Enbridge Gas The remediation of discontinued manufactured gas plant sites may result in future costs. The probable overall cost of remediation cannot be determined at this time due to uncertainty about the existence or extent of environmental risks, the complexity of laws and regulations, particularly with respect to sites decommissioned years ago and no longer owned by Enbridge Gas, and the selection of alternative remediation approaches. Although there are no known regulatory precedents in Canada, there are precedents in the United States for recovery in rates of costs of a similar nature. If Enbridge Gas must contribute to any remediation costs, it would be generally allowed to recover in rates those costs not recovered through insurance or by other means and believes that the ultimate outcome of these matters would not have a significant impact on its financial position. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s In October 2002, the Supreme Court of Canada granted an Application for Leave to Appeal to a customer who commenced an action against Enbridge Gas claiming that the OEB-approved late payment penalties charged to customers were contrary to Canadian federal law. The Court will hear the plaintiff’s appeal of the Ontario Court of Appeal’s decision, released in December 2001, to dismiss a Notice of Appeal filed by the plaintiff in April 2000. The Company believes it has sound defences to the plaintiff’s claim and it intends to vigorously defend the action. CAPLA Claim The Canadian Alliance of Pipeline Landowners’ Associations and two individual landowners have commenced an action, which they will be applying for certification as a class action, against the Company and TransCanada PipeLines Limited. The claim relates to restrictions in the National Energy Board Act on the landowners’ use of land within a 30-metre control zone on either side of the pipeline easements. The Company believes it has a sound defence and intends to vigorously defend the claim. Since the outcome is indeterminable, the Company has made no provision for any potential liability. Enbridge Energy Partners Enbridge Energy Company, Inc. (EEC), which holds a portion of the Company’s equity interest in EEP, has agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer of its pipeline operations to EEP in 1991. This indemnification does not apply to amounts that EEP would be able to recover in its tariff rates if not recovered through insurance, or to any liabilities relating to a change in laws after December 27, 1991. In addition, in the event of default, EEC, as the General Partner, is subject to recourse with respect to a portion of EEP’s long-term debt which amounts to US$279 million at December 31, 2002. 19. UNITED STATES ACCOUNTING PRINCIPLES These consolidated financial statements have been prepared in accordance with Canadian GAAP. The effects of significant differences between Canadian GAAP and U.S. GAAP for the Company are described below. 67 Earnings and Comprehensive Income (millions of dollars except per share amounts) Year ended December 31, Earnings under Canadian GAAP Preferred security distributions 1 Stock-based compensation 2 Tax effect of the above adjustment Future income tax recovery/(expense) 3 Earnings under U.S. GAAP Unrealized net gain/(loss) on cash flow hedges 5 Foreign currency translation adjustment 5 Comprehensive income Earnings per common share Diluted earnings per common share 2002 610.1 (26.7) (12.1) 4.9 – 576.2 19.5 (1.3) 594.4 3.55 3.51 2001 482.9 (17.5) (15.2) 6.1 92.8 549.1 (150.8) 15.1 413.4 3.45 3.41 2000 414.5 (15.3) – – (182.8) 216.4 – 16.2 232.6 1.36 1.35 E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s 19. UNITED STATES ACCOUNTING PRINCIPLES (continued) Financial Position (millions of dollars) December 31, Cash4 Accounts receivable and other 4 Property, plant and equipment 4 Accumulated depreciation 4 Long-term investments 4 Deferred amounts 3, 4 Short-term borrowings Accounts payable and other 4 Current maturities and short-term debt Long-term debt 1 Future income taxes 3, 5 Preferred securities 1 Retained earnings Additional paid in capital 2 Accumulated other comprehensive income/(loss) 5 2002 Canada United States 42.7 843.4 9,506.6 2,596.3 3,421.0 1,178.7 256.8 921.1 658.5 6,612.5 1,403.0 – 1,098.9 12.1 (103.2) 40.7 817.5 9,548.6 2,601.0 3,371.5 315.8 247.5 714.1 652.3 6,040.3 628.4 533.7 1,128.1 – 12.3 2001 Canada United States 71.3 1,313.5 9,116.0 2,323.1 1,801.6 1,342.8 410.9 923.4 1,819.7 6,293.2 1,499.7 – 781.2 15.2 (121.4) 74.0 1,270.2 9,143.5 2,326.0 1,772.8 329.7 410.9 679.9 1,819.7 5,913.3 580.8 339.7 812.3 – 7.4 68 1 Preferred Securities Under U.S. GAAP, the full amount of the Company’s Preferred Securities and related distributions would be recognized as debt and interest expense, respectively. The Preferred Securities have a fair market value of $565.0 million at December 31, 2002 (2001 — $345.5 million). 2 Stock-Based Compensation The Company accounts for stock-based compensation for U.S. GAAP purposes in accordance with APB 25, Accounting for Stock Issued to Employees, which requires the use of the intrinsic value-based method to measure compensation expense. Under Canadian GAAP, the Company’s performance-based options do not give rise to compensation expense. Under U.S. GAAP, the performance-based options which vested during 2002 gave rise to pre-tax compensation expense of $12.1 million (2001 — $6.9 million; 2000 — nil). Starting in 2002, the Company accounts for SARs in accordance with the new Canadian accounting standard for stock-based compensation which results in the same compensation expense as under U.S. GAAP. Under U.S. GAAP in 2001 and 2000, the Company’s stock appreciation rights (SARs) are accounted for using the intrinsic value method which resulted in pre-tax compensation expense of $8.3 million and nil, respectively. 3 Future Income Taxes Canadian GAAP requires that the effect of tax rate reductions are recognized when they are substantively enacted. Under U.S. GAAP, the effect of tax rate reductions cannot be recognized until enacted. In 2000, the Company recognized $92.8 million of earnings related to substantively enacted tax rate reductions that are recognized in 2001 under U.S. GAAP. In 2000, future income taxes of $76.5 million, related to the unbundling transaction and charged to retained earnings under Canadian GAAP as part of the adoption of the new income tax standard, are charged to earnings as a write-down of the regulatory asset under U.S. GAAP. Under U.S. GAAP, deferred income tax liabilities are recorded for rate-regulated operations which follow the taxes payable method for ratemaking purposes. As these deferred income taxes are expected to be recoverable in future revenues, a corresponding regulatory asset is also recorded. These assets and liabilities are adjusted to reflect changes in enacted income tax rates. The additional deferred income taxes under U.S. GAAP include the difference between capital cost allowance and depreciation of property, plant and equipment of $549.3 million (2001 — $574.4 million) and the incremental revenue required for the recovery of unrecorded taxes of $316.0 million (2001 — $370.5 million). 4 Accounting for Joint Ventures Under U.S. GAAP, the Company’s investments in joint ventures are accounted for using the equity method. 5 Accumulated Other Comprehensive Income At December 31, 2002, accumulated other comprehensive income consists of an accumulated foreign currency translation adjustment of $28.1 million (2001 — $29.4 million) and net unrealized losses of $131.3 million (2001 — $150.8 million) for derivative financial instruments. Supplemental Disclosure — Pro Forma Compensation Expense U.S. GAAP requires that, where the fair value based method is not used to measure compensation expense, pro forma earnings and earnings per share, calculated as if the fair value based method had been used, must be disclosed. In Canada, these requirements apply to options granted on or after January 1, 2002 and therefore, the Company’s Canadian GAAP disclosure does not include any options granted prior to that date. E N B R I D G E I N C . C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s (millions of dollars except per share amounts) Year ended December 31, Earnings under U.S. GAAP As reported Stock-based compensation expense Pro forma Earnings per common share As reported Stock-based compensation expense Pro forma Diluted earnings per common share As reported Stock-based compensation expense Pro forma 2002 576.2 7.3 568.9 3.55 0.05 3.50 3.51 0.04 3.47 2001 549.1 4.6 544.5 3.45 0.03 3.42 3.41 0.03 3.38 2000 216.4 2.6 213.8 1.36 0.02 1.34 1.35 0.02 1.33 The fair value of stock options was calculated in the same manner, using the same assumptions, as disclosed in Note 11 except that for Canadian GAAP, only awards granted since the adoption of the new CICA standard for stock-based compensation on January 1, 2002 are included. Assumptions used for U.S. GAAP comparative periods are as follows. Year ended December 31, Risk free interest rate Expected life (years) Expected volatility Expected quarterly dividends 69 2001 5.38% 10 25% $0.38 2000 5.41% 10 25% $0.35 The weighted average grant-date fair value of options granted during 2001 under the fixed option plan in 2001 and 2000 was $10.09 and $7.80, respectively. New Accounting Standards Accounting for Asset Retirement Obligations In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which is to be adopted for fiscal years beginning after June 15, 2002. This standard requires that legal obligations associated with the retirement of long-lived tangible assets be recognized at fair value when incurred. The Company will adopt the new standard effective January 1, 2003. Since the majority of the Company’s operations are rate-regulated, the new standard is not expected to have a material impact on earnings. A similar standard has been issued by the Canadian Institute of Chartered Accountants effective January 1, 2004. Accounting for Costs Associated with Exit or Disposal Activities In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for exit or disposal activities initiated on or after December 31, 2002. This standard replaces Emerging Issues Task Force Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity". The standard requires liabilities associated with exit or disposal activities to be recorded, at fair value, as they are incurred rather than on the adoption of a formal plan of disposal. Consolidation of Variable Interest Entities In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest Entities, which is to be adopted for interim periods commencing after July 15, 2003. The Company is assessing the impact of this standard, if any, on its financial statements. E N B R I D G E I N C . S u p p l e m e n t a r y I n f o r m a t i o n S U P P L E M E N T A R Y I N F O R M A T I O N ( u n a u d i t e d ) Selected Quarterly Financial Data (millions of dollars, except per share amounts) 2002 Operating revenue from continuing operations Operating income from continuing operations Margin Earnings applicable to common shareholders First 1,073.2 152.9 0.138 105.0 8.1 113.1 0.66 0.05 0.71 0.38 First 778.8 192.7 79.8 3.7 83.5 0.51 0.02 0.53 0.35 Continuing operations Discontinued operations Earnings per common share Continuing operations Discontinued operations Dividends per common share 2001 Operating revenue from continuing operations Operating income from continuing operations Earnings applicable to common shareholders Continuing operations Discontinued operations 70 Earnings per common share Continuing operations Discontinued operations Dividends per common share Quarterly Share Trading Information The Toronto Stock Exchange 2002 (dollars) High Low Close Volume (millions) 2001 (dollars) High Low Close Volume (millions) Second 1,645.8 336.4 0.203 199.1 234.2 433.3 1.26 1.48 2.74 0.38 Second 1,615.9 371.9 245.3 25.1 270.4 1.56 0.16 1.72 0.35 First 46.15 41.50 44.73 21.3 First 43.00 33.90 42.35 20.7 The New York Stock Exchange and the NASDAQ National Market 1 First 2002 (U.S. dollars) 27.57 High 24.20 Low 26.52 Close 0.6 Volume (millions) First 2001 (U.S. dollars) 28.63 High 22.25 Low 26.69 Close 0.2 Volume (millions) Third 1,171.0 30.8 0.026 (3.9) – (3.9) (0.03) – (0.03) 0.38 Third 974.7 92.4 58.4 6.4 64.8 0.37 0.04 0.41 0.35 Second 48.94 43.06 47.16 15.5 Second 42.50 35.55 41.19 17.7 Second 30.49 25.61 30.11 0.6 Second 27.20 23.00 27.14 0.3 Fourth 657.5 88.7 0.135 34.0 – 34.0 0.20 (0.02) 0.18 0.38 Fourth 711.5 89.5 29.7 10.1 39.8 0.19 0.06 0.25 0.35 Third 49.25 42.71 46.27 17.0 Third 43.24 39.02 42.55 13.3 Third 31.03 26.29 28.37 1.7 Third 27.50 25.50 26.94 0.5 Total 4,547.5 608.8 0.132 334.2 242.3 576.5 2.09 1.51 3.60 1.52 Total 4,080.9 746.5 413.2 45.3 458.5 2.63 0.28 2.91 1.40 Fourth 46.85 41.11 42.61 18.5 Fourth 45.55 40.89 43.40 16.0 Fourth 29.14 26.05 26.73 1.3 Fourth 28.77 26.05 27.22 0.7 1 Effective October 30, 2001, Enbridge Inc. began trading on the New York Stock Exchange and delisted from the NASDAQ. E N B R I D G E I N C . F I V E Y E A R C O N S O L I D A T E D H I G H L I G H T S S u p p l e m e n t a r y I n f o r m a t i o n Financial and Operating Information 1 (millions of dollars, except per share amounts) Earnings by Segment Energy Transportation North Energy Transportation South Energy Distribution 2 International Corporate Continuing operations Discontinued operations 3 Earnings applicable to common shareholders 2002 236.2 (41.4) 113.8 68.0 (42.4) 334.2 242.3 2001 205.1 46.4 181.8 35.6 (55.7) 413.2 45.3 2000 192.6 23.3 203.2 26.4 (87.8) 357.7 34.6 1999 172.5 39.1 95.2 28.7 (47.6) 287.9 – 1998 120.1 33.2 93.5 24.3 (30.2) 240.9 – 576.5 458.5 392.3 287.9 240.9 Cash Flow Data Cash provided from operating activities Expenditures on property, plant and equipment Dividends paid on common shares Operating Data Energy Transportation 4 Deliveries (thousands of barrels per day) Barrel miles (billions) Average haul (miles) Energy Distribution Distribution volume (billion cubic feet) Number of active customers (thousands) Degree day deficiency 5 (degrees Celsius) Actual Forecast based on normal weather 910.6 729.9 251.1 2,088 705 925 410 1,623 3,362 3,700 414.5 683.3 227.5 2,109 695 903 427 1,571 3,766 3,816 263.5 364.3 202.1 2,072 735 972 421 1,520 3,569 3,929 495.1 783.7 186.4 1,942 687 968 402 1,466 3,460 4,060 312.4 1,388.4 168.3 2,024 759 1,028 397 1,414 3,352 4,079 71 1 Certain comparative amounts have been reclassified to conform with the current year’s basis of presentation. 2 The highlights of the Energy Distribution activities reflect the results of Enbridge Gas Distribution and other gas distribution assets on a quarter lag basis of consolidation. 3 The results of discontinued operations cannot be disaggregated from continuing operations prior to 2000. 4 Energy Transportation operating highlights include the statistics of the 14.1% owned portion of the mainline system located in the United States. 5 Degree day deficiency is a measure of coldness. It is calculated by accumulating for each day in the fiscal period the total number of degrees by which the daily mean temperature fell below 18 degrees Celsius. The figures given are those accumulated in the Toronto area. E N B R I D G E I N C . S u p p l e m e n t a r y I n f o r m a t i o n F I V E Y E A R C O N S O L I D A T E D H I G H L I G H T S Shareholder and Investor Information (per share amounts in dollars) Average common shares outstanding weighted monthly during the year (thousands) Number of registered common shareholders 2002 2001 2000 1999 1998 160,310 157,297 154,469 150,995 145,448 at year end 7,406 7,832 8,265 8,877 9,207 Common Share Trading (TSE) 1 High Low Close Volume (millions) Per Common Share Data 1 Earnings applicable to common shareholders Continuing operations Discontinued operations Dividends paid on common shares Financial Ratios Return on average shareholders’ equity 2 Return on average capital employed 3 Debt to debt plus shareholders’ equity 4 Debt to total capital employed Earnings coverage of interest 5 Dividend payout ratio 6 49.25 41.11 42.61 72.3 2.09 1.51 3.60 1.520 19.9% 7.5% 64.4% 57.0% 2.7x 42.2% 45.55 33.90 43.40 67.6 2.63 0.28 2.91 1.400 18.6% 7.3% 72.9% 66.3% 2.2x 48.1% 44.00 23.00 43.70 68.2 2.32 0.22 2.54 1.270 18.6% 7.2% 69.4% 61.6% 2.0x 50.0% 36.33 28.60 28.65 51.8 1.91 – 1.91 1.195 14.3% 6.6% 68.9% 63.7% 2.0x 62.6% 35.70 28.95 35.25 61.5 1.66 – 1.66 1.120 13.8% 6.6% 71.4% 64.8% 2.0x 67.5% 1 Data for 2002, 2001 and 2000 are for the Toronto Stock Exchange only. Prior year data include the Toronto and Montreal stock exchanges. 2 Earnings applicable to common shareholders divided by average common equity (weighted monthly during the year). 3 Sum of earnings (including earnings from discontinued operations), non-controlling interest and after-tax interest expense divided by average capital employed (weighted monthly during the year). Capital employed is equal to the sum of shareholders’ equity, non-controlling interest, future income taxes, deferred credits, and total debt (excluding short-term borrowings which finance gas in storage). 4 Total debt (including short-term borrowings) divided by the sum of total debt and shareholders’ equity. 5 Sum of earnings before income taxes, non-controlling interest and interest expense, divided by interest expense. Includes earnings from discontinued operations. 6 Dividends per common share divided by total earnings per share applicable to common shareholders. 72 E N B R I D G E I N C . S h a r e h o l d e r a n d I n v e s t o r I n f o r m a t i o n S H A R E H O L D E R A N D I N V E S T O R I N F O R M A T I O N Common and Preferred Shares The Common Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange and in the United States on the New York Stock Exchange under the trading symbol “ENB”. The Preferred Shares, Series A, of Enbridge Inc. trade in Canada on the Toronto Stock Exchange under the trading symbol “ENB.PR.A”. Registrar and Transfer Agent in Canada CIBC Mellon Trust Company 199 Bay Street, Commerce Court West Securities Level Toronto, Ontario M5L 1G9 Telephone: (416) 643-5000 Toll free: (800) 387-0825 Internet: www.cibcmellon.com CIBC Mellon Trust Company also has offices in Halifax, Montreal, Winnipeg, Calgary, and Vancouver. Co-Registrar and Co-Transfer Agent in the United States Mellon Investor Services 85 Challenger Road Overpeck Centre Ridgefield Park, NJ, 07660 U.S.A. Toll free: (800) 526-0801 Preferred Securities Enbridge Preferred Securities, Series B, C and D trade in Canada on the Toronto Stock Exchange under the trading symbols “ENB.PR.B”, “ENB.PR.C” and “ENB.PR.D”, respectively. The registrar and transfer agent is Computershare Trust Company of Canada (formerly Montreal Trust Company). Debentures The registrar and trustee for Enbridge Debentures is Computershare Trust Company of Canada (formerly Montreal Trust Company) — Montreal, Toronto, Winnipeg, Edmonton and Vancouver. Auditors PricewaterhouseCoopers LLP Shareholder Inquiries If you have inquiries regarding the following: ❚ Dividend Reinvestment and Share Purchase Plan change of address share transfer lost certificates dividends duplicate mailings Please contact the registrar and transfer agent — CIBC Mellon Trust Company in Canada or Mellon Investor Services in the United States. Other Investor Inquiries If you have inquiries regarding the following: additional financial or statistical information industry and company developments latest news releases or investor presentations Please contact Enbridge Investor Relations or visit Enbridge’s web site at www.enbridge.com. Investor Relations Manager, Investor Relations Enbridge Inc. 3000, 425 - 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Toll free: (800) 481-2804 Annual and Special Meeting The Annual and Special Meeting of Shareholders will be held in the Crystal Ballroom at the Fairmont Palliser Hotel, Calgary, Alberta, at 1:30 p.m. MDT on Wednesday, May 7, 2003. Form 40-F The Company files annually with the Securities and Exchange Commission of the United States a report known as the Annual Report on Form 40-F. Copies of the Form 40-F are available, free of charge, upon written request to the Corporate Secretary of the Company. Dividend Reinvestment and Share Purchase Plan, and Dividend Direct Deposit Enbridge Inc. offers a Dividend Reinvestment and Share Purchase Plan that enables shareholders to reinvest their cash dividends in Common Shares and to make additional cash payments for purchases at the market price. The Company also offers Dividend Direct Deposit which enables shareholders to receive dividends by electronic fund transfer to the bank account of their choice in Canada. Details may be obtained from the Investor Information section of the Enbridge web site at www.enbridge.com, or by contacting CIBC Mellon Trust Company. Registered Office Enbridge Inc. 3000, 425 - 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Telephone: (403) 231-3900 Facsimile: (403) 231-3920 Internet: www.enbridge.com 2003 Dividend Information for Common Shares and Preferred Shares, Series A 1st Q Record date Payment date Common Share Dividend Reinvestment Plan (DRIP) enrolment cut-off date Share Purchase Plan cut-off date (cheques can be post-dated to the payment date) Feb. 14 March 1 Feb. 7 Feb. 21 2003 Interest Payment Information for Preferred Securities, Series B, C and D 1st Q Record date Payment date Le présent document est disponible en français. March 15 March 31 2nd Q May 21 June 1 May 14 May 26 2nd Q June 14 June 30 3rd Q Aug. 15 Sept. 1 Aug. 8 Aug. 25 3rd Q Sept. 13 Sept. 30 4th Q Nov. 14 Dec. 1 Nov. 6 Nov. 24 4th Q Dec. 13 Dec. 31 E N B R I D G E I N C . 73 ❚ ❚ ❚ ❚ ❚ ❚ ❚ ❚ C o r p o r a t e I n f o r m a t i o n C O R P O R A T E I N F O R M A T I O N BOARD OF DIRECTORS David A. Arledge Corporate Director Houston, Texas James J. Blanchard Senior Partner Piper Rudnick Washington, D.C. J. Lorne Braithwaite Corporate Director Toronto, Ontario Patrick D. Daniel President & Chief Executive Officer Enbridge Inc. Calgary, Alberta E. Susan Evans Corporate Director Calgary, Alberta William R. Fatt Chief Executive Officer Fairmont Hotels & Resorts Inc. Toronto, Ontario 74 Richard L. George President & Chief Executive Officer Suncor Energy Inc. Calgary, Alberta Michel Gourdeau President Hydro-Québec Oil & Gas Montreal, Québec Louis D. Hyndman Senior Partner Field Atkinson Perraton Edmonton, Alberta Brian F. MacNeill Chairman Petro-Canada Calgary, Alberta Robert W. Martin Corporate Director Toronto, Ontario George K. Petty Corporate Director San Luis Obispo, California Donald J. Taylor Chair Enbridge Inc. Jacksons Point, Ontario SENIOR MANAGEMENT: THE CORPORATE LEADERSHIP TEAM Patrick D. Daniel President & Chief Executive Officer Mel F. Belich Group Vice President, International J. Richard Bird Group Vice President, Transportation North Bonnie D. DuPont Group Vice President, Corporate Resources Stephen J.J. Letwin Group Vice President, Distribution & Services Derek P. Truswell Group Vice President & Chief Financial Officer Dan C. Tutcher Group Vice President, Transportation South Stephen J. Wuori Group Vice President, Planning & Development Environment, Health and Safety Prevention of accidents and injuries, and protection of the environment benefits everyone. That’s why environmental, health and safety performance is an integral part of Enbridge’s businesses, and objectives and performance targets are established, programs are implemented and results are monitored. The results are published in the Company’s Environment, Health and Safety Annual Report. You can obtain a copy of the most recent report by e-mailing webmaster@enbridge.com, or visiting the Enbridge website at www.enbridge.com. E N B R I D G E I N C . C H A N G E S T O S E N I O R M A N A G E M E N T I N 2 0 0 3 C o r p o r a t e I n f o r m a t i o n Continuity of its senior management team has been an Enbridge trademark. With the decision by Chief Financial Officer Derek Truswell to take early retirement, after more than 34 years of outstanding service to the organization, the Company took the opportunity to make a number of changes to its senior management team, while maintaining its existing strengths. Effective April 1, 2003, the following changes will take effect, to fill the position of CFO, refresh the organization, rebalance workloads and reinforce the Company’s commitment to succession management. The Company’s four core operating units will continue to be led by the same individuals, but a number of responsibilities have changed, and two new members have been added to the Corporate Leadership Team. Patrick D. Daniel: as President & Chief Executive Officer, Mr. Daniel continues to be responsible for all operations of the Company, and all Group Vice Presidents report to him. Mel F. Belich is appointed Group Vice President, International and Corporate Law, retaining responsibility for International consulting, development and operations, and adding the Corporate Law function. J. Richard Bird continues as Group Vice President, Transportation North, responsible for the operation and development of Enbridge’s crude oil pipeline businesses, as well as overseeing the Company’s interests in the Alliance and Vector natural gas pipelines. Bonnie D. DuPont continues as Group Vice President, Corporate Resources, responsible for Human Resources, Public & Government Affairs, Information Technology, Office Services and the Corporate Secretariat function. She adds responsibility for the coordination of the Environment, Health and Safety, and Corporate Security functions. Stephen J.J. Letwin is appointed Group Vice President, Gas Strategy & Corporate Development. He retains responsibility for Energy Distribution and adds Planning and Business Development functions. Jim Schultz is appointed Senior Vice President and continues as President, Enbridge Gas Distribution, responsible for the Company’s Eastern Canadian businesses. He reports to Mr. Letwin. Dan C. Tutcher continues as Group Vice President, Transportation South, responsible for the Company’s energy delivery businesses in the United States. Scott Wilson is appointed Senior Vice President, Finance, responsible for the Treasury, Controllers and Financial Services functions. He reports to Mr. Wuori. Stephen J. Wuori is appointed Group Vice President & Chief Financial Officer, responsible for all financial affairs of the Company. Designed and Produced by Rivard Communications Inc., Calgary. Printed by Quebecor World Calgary. Enbridge common shares trade on the Toronto Stock Exchange in Canada and on the New York Stock Exchange in the U.S. under the symbol “ENB”. Enbridge Inc. 3000, 425 - 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Telephone: (403) 231-3900 Fax: (403) 231-3920 w w w. e n b r i d g e . c o m g p 

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