Enbridge
Annual Report 1999

Plain-text annual report

T H E E N E R G Y B R I D G E 1999 ANNUAL REPORT 1 Highlights 2 Letter to Shareholders 8 Operations Review 14 Management’s Discussion and Analysis 31 Financial Statements and Notes 57 Supplementary Information 58 Five Year Consolidated Highlights 60 Shareholder and Investor Information B R I D G I N G T H E G A P Enbridge bridges the gap between energy supply and the customer, providing seamless service and delivery. Enbridge is also bridging the gap from the present to an innovative and exciting energy future. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids pipeline system. The Company also is involved in liquids marketing and international energy projects, and has a growing involvement in the natural gas transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company, which provides gas to 1.5 million customers in Ontario, Quebec and New York State. Enbridge is also involved in the distribution of electricity, and provides retail energy products and services to a growing number of Canadian and United States markets. The Company employs approximately 5,500 people, primarily in Canada, the United States and Latin America. Enbridge common shares trade on the Toronto Stock Exchange under the symbol “ENB”, and on The NASDAQ National Market in the United States under the symbol “ENBR”. Information about Enbridge is available on the World Wide Web at www.enbridge.com. Inuvik Norman Wells Zama Fort St. John Fort McMurray Edmonton Hardisty Casper Salt Lake City Ottawa Montreal Cornwall Toronto Dawn Chicago Toledo Patoka Liquids Pipelines Gas Pipelines Gas Distribution Electric Power Distribution Gas Gathering and Processing Coveñas Jose Terminal Cusiana/ Cupiagua Bogota Enbridge Inc. LIQUIDS PIPELINES (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) Enbridge Pipelines Inc. Enbridge Pipelines (NW) Inc. Enbridge Pipelines (Athabasca) Inc. Enbridge Pipelines (Saskatchewan) Inc. Enbridge Pipelines (North Dakota) Inc. Enbridge Pipelines (Toledo) Inc. Lakehead Pipe Line Partners, L.P. (15.3%) (cid:2) Mustang Pipe Line Partners (30%) Chicap Pipe Line Company (23%) (cid:2) Frontier Pipeline Company (44%) (cid:2) GAS DISTRIBUTION (cid:2) (cid:2) Enbridge Consumers Gas (cid:2) Gazifère Inc. – an Enbridge Company (cid:2) Niagara Gas Transmission Limited – an Enbridge Company (cid:2) St. Lawrence Gas Company, Inc. – an Enbridge Company Noverco Inc. (32%) (cid:2) Gaz Métropolitain and Company, Limited Partnership (77%) (cid:2) Vermont Gas Systems, Inc. (100%) (cid:2) TQM Pipeline and Company, Limited Partnership (50%) (cid:2) Enbridge Gas New Brunswick Inc. (63%) INTERNATIONAL Enbridge International Inc. (cid:2) Oleoducto Central S.A. (17.5%) (cid:2) Sociedad Williams Enbridge Compania (G.P.) (45%) Enbridge Technology Inc. GAS PIPELINES AND NEW BUSINESS DEVELOPMENT Alliance Pipeline Limited Partnership (21.4%) Vector Pipeline Limited Partnership (45%) AltaGas Services Inc. (40%) Inuvik Gas Ltd. (33 1/3%) Cornwall Electric – an Enbridge Company ENERGY SERVICES Enbridge Services Inc. Enbridge (Pennsylvania) Inc. Enbridge Petroleum Exchange Inc. Tidal Energy Marketing Inc. (50%) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) ALL SECTIONS OF A BRIDGE MUST BE INTEGRATED WITH AND REINFORCE ALL OTHER SECTIONS. AT ENBRIDGE, ALL BUSINESS SEGMENTS STRENGTHEN AND SUPPORT EACH OTHER. EACH SEGMENT MUST SUCCEED ON ITS OWN, BUT THE SUCCESS OF THE ENTERPRISE AS A WHOLE IS PARAMOUNT. E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Highlights FINANCIAL1 (Canadian dollars in millions, except per share amounts) Earnings applicable to common shareholders Cash provided from operating activities Dividends paid on common shares Per common share amounts 2 (dollars per share) Earnings Cash provided from operating activities Dividends Return on average common shareholders’ equity Debt to debt plus shareholders’ equity at year end OPERATING Liquids Pipelines 3 Deliveries (thousands of barrels per day) Barrel miles (billions) Average haul (miles) Gas Distribution 4 Gas distribution volumes (billions of cubic feet) Number of active customers 5 (thousands) Degree day deficiency 6 (degrees Celsius) Actual Forecast based on normal weather 1999 287.9 495.1 186.4 1.91 3.28 1.195 14.3% 67.4% 1998 240.9 312.4 168.3 1.66 2.15 1.120 13.8% 69.7% 1997 217.3 437.8 147.1 1.58 3.18 1.060 14.2% 67.7% 1999 1998 1997 2,023 696 946 402 1,466 3,460 4,060 2,136 771 989 397 1,414 3,352 4,079 2,083 771 1,014 428 1,362 4,011 4,003 1 Prior year amounts have been restated to conform to the segmentation and presentation adopted in 1999. 2 Prior year per common share amounts have been restated to give effect to the two for one stock split that occurred on May 10, 1999. 3 Liquids Pipelines operating highlights include the statistics of the 15.3% owned portion of the mainline system located in the United States. 4 Highlights of Gas Distribution reflect the results of Enbridge Consumers Gas (The Consumers’ Gas Company Ltd.) and other gas distribution assets on a quarter lag basis of consolidation. 5 The number of active customers at year end reflects 58,000 new connections made to the Gas Distribution system during 1999. 6 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. Earnings Per Common Share (dollars per share) 1 9 1 . 6 6 1 . 8 5 1 . 5 4 1 . 5 1 1 . 95 96 97 98 99 Dividends Per Common Share (dollars per share) 5 9 1 1 . 0 2 1 1 . 0 6 0 1 . 0 0 0 1 . 5 1 0 1 . 95 96 97 98 99 1 T H E E N E R G Y B R I D G E 1 9 9 9 : A T I M E L I N E F O R A C H I E V E M E N T January The SEP II mainline expansion program was completed, adding 100,000 barrels per day of capacity in Canada and 170,000 barrels per day into Chicago. The Enbridge Petroleum Exchange began operation of Canada’s first Internet-based crude oil exchange. Letter to Shareholders Enbridge made significant strides in 1999. Earnings reached record levels. Dividends again increased. And we attained a number of key operational objectives. The fundamentals of our business remain strong and we are well positioned to take advantage of our numerous long term growth opportunities. We will continue to pursue our strategies for profitable growth to generate superior value for our shareholders. Brian F. MacNeill President & Chief Executive Officer 1999: CONTINUING THE PATTERN OF PROFITABLE GROWTH Financial Highlights: “BRIDGES SPAN GAPS AND BRING PEOPLE TOGETHER. ENBRIDGE BRIDGES THE GAP BETWEEN ENERGY SUPPLY AND THE CUSTOMER, PROVIDING SEAMLESS SERVICE AND DELIVERY. ENBRIDGE IS ALSO BRIDGING THE GAP FROM THE PRESENT TO AN INNOVATIVE AND EXCITING ENERGY FUTURE.” Earnings applicable to common shareholders increased to a record $287.9 million, or $1.91 per share, in 1999, up from $240.9 million, or $1.66 per share, in 1998. Once again, we achieved our target of double-digit growth in earnings per share. Over the last four years, compound annual growth in earnings per common share amounted to 13.5%, and this was achieved despite the record warm winters in 1999 and 1998 that adversely affected Gas Distribution earnings by an estimated $71 million. Notwithstanding superior earnings growth, we continue to maintain the relatively low business risk profile of the Company. Earnings generated a 14.3% return on common shareholder equity, up from 13.8% in 1998 and in line with the five-year average of 14.1%. This result illustrates the profitability of our core businesses and new investments, and the essence of the value proposition we offer our shareholders — superior returns with relatively low risk. Enbridge has increased its quarterly dividends by an average of 5% each year since 1996, and in 1999 we increased the quarterly dividend to $0.3025 per common share. Annual increases are in line with the strong earnings and cash flow over the last five years, while the dividend payout ratio has declined, which is consistent with our growth profile. In 1999, we invested $1.2 billion in the business, which is down from the record $1.6 billion spent in 1998. Although profitable in their own right, these investments position Enbridge for future growth in earnings. This level of spending requires continuous access to capital markets, and in 1999 we raised approximately $1 billion in debt and equity, a clear indication of the confidence that the investment community places in the long term fundamentals of our business. Our financial position is strong. At year end, our book equity to total capitalization was 33%, in line with our target capital structure and an improve- ment over the 30% in 1998. In addition to internally generated funds, we also have access to some $2 billion in unutilized credit facilities to finance significant opportunities. Operating Highlights: In addition to our financial success, Enbridge achiev- ed a number of operational milestones in 1999. We strengthened the existing energy delivery busi- nesses and added to overall pipeline capacity through completion of a number of liquids pipeline expansions and extensions including the System Expansion Program Phase II (SEP II), Phase I of the Terrace expansion, the new Athabasca Pipeline and related tank terminal, the reversal of Line 9 to transport crude oil from Montreal to Sarnia, and extension of the United States system to deliver crude oil to a refinery in Toledo, Ohio. 2 March The Vector Pipeline received regulatory approval from the National Energy Board for the Canadian portion of the system in March. Final U.S. approval was received from the Federal Energy Regulatory Commission in May. In September, Westcoast Energy Inc. joined the project. Vector Pipeline, which is scheduled for first service in October 2000, will transport natural gas from Chicago to the Dawn, Ontario, hub. Enbridge announced a proposal for a new pipeline in the southern United States to transport crude oil from the eastern Gulf Coast to western Gulf Coast refineries. The project, which is currently seeking shipper commitments, is called the Alligator Pipeline. E N B R I D G E 1 9 9 9 A N N U A L R E P O R T April The Ontario Energy Board approved Performance Based Regulation (PBR) for Enbridge Consumers Gas for the years 2000 through 2002. PBR introduces an incentive mechanism to the traditional cost of service methodology, with shareholders and customers benefiting from cost reductions and productivity gains. We expanded the Enbridge Consumers Gas distri- bution network with the addition of 12 new communities and 58,000 new connections, and won the natural gas distribution franchise for the province of New Brunswick. We successfully negotiated a five-year extension to the Incentive Tolling Agreement for Enbridge Pipelines’ Canadian mainline liquids pipeline system, and received regulatory approval to imple- ment Performance Based Regulation for Enbridge Consumers Gas. We continued to develop a significant presence in the natural gas transmission business through involvement in the Alliance and Vector pipelines — both of which are on track for start up in October 2000 — and entered into the midstream gas busi- ness with a 40% investment in AltaGas Services Inc. We successfully negotiated an interim facilities operating contract in Venezuela which, coupled with several successful technology transfer contracts, helped to further increase International earnings through the year. We unbundled ancillary assets from the gas distri- bution utility, and completed the transition to a fully unregulated retail products and services business. We announced plans to establish a shared services business unit to provide information technology, billing and fleet management services to Enbridge’s growing portfolio of energy distribution and services businesses in Central and Atlantic Canada, and potentially to third party customers. We also celebrated our 50th anniversary. It was an opportunity to look back at what we were — a Western Canadian crude oil pipeline with one share- holder — compared with what we are today — a widely held, publicly traded, diversified, international leader in energy transportation and distribution. THE REASONS FOR OUR SUCCESS Clearly, 1999 was a successful year. But this success was really a continuation of the pattern of profitable growth we have established over the last five years. We believe this success stems from our focused approach to the business, how we develop and refine our strategies for growth, and how we measure performance. Approach To The Business: There are many things we do well at Enbridge, as do other companies. But there are also some things that we think set us apart: (cid:2) First and foremost, our emphasis is not on increas- ing the size of the Company. It is on adding economic value. We won’t grow for growth’s sake, and sometimes this means rejecting projects that don’t make the grade, or saying “no” to business opportunities that are fashionable at the moment but don’t fit with our philosophy or what our share- holders expect. (cid:2) Our approach is to develop our core businesses and then leverage these assets and our capabilities to expand to complementary businesses. Generally, any new business must be complementary to our existing core business platform. (cid:2) We develop our people so that we are well positioned for long term success. Our strength stems from our Board of Directors, a strong management team and our 5,500 employees. Employees participate in decision-making and share in the success, so our goals are aligned with those of our shareholders. (cid:2) We carefully evaluate business prospects to ensure they have the appropriate balance between risk and reward while still meeting our risk para- meters. We look to commercial terms and operational synergies to mitigate risks. 3 T H E E N E R G Y B R I D G E Enbridge shareholders approved a two-for-one stock split, increasing availability of common shares for purchase by the public and enhancing the liquidity and trading of the shares. May Construction of the Enbridge Pipelines (Athabasca) Inc. system, from the oil sands to Hardisty, Alberta, was completed by the beginning of April, and first oil was received at Hardisty in May. Line 9 began service with the pipeline operating with partially reversed flow, transporting crude oil from Montreal to Westover, Ontario. Full reversal from Montreal to Sarnia began in September. Enbridge announced plans to acquire an interest in AltaGas Services Inc. to establish a strategic alliance for midstream gas services — including gathering, processing, upstream storage and liquids extraction — for Canadian gas producers. As of September, Enbridge had acquired an interest of approximately 40%. (cid:2) Finally, we take a great deal of pride in achieving the targets we set for ourselves. It has been this success in meeting targets that has earned us the credibility we have with investors and other stakeholders. Developing And Refining Strategies: Planning is a continuous process, and at Enbridge we plan, re-tool the plan, and then we do still more planning. Our primary planning horizon is five years, but we also look farther out so we can identify and capitalize on underlying trends, both within and outside the industry. Our businesses are changing rapidly. We know that to succeed we need to anticipate our customers’ needs and be ready with new prod- ucts and services when they are needed. Or to use a hockey analogy, just like Wayne Gretzky, we understand the need to go where the puck will be, not where it is now. Our current strategic plan includes a Company-wide focus on enhancing the profitability of energy delivery operations by incorporating incentive provisions in rate-setting mechanisms for existing and new businesses, and then managing opera- tional performance to maximize the benefits to customers and shareholders. There are also a number of focused strate- gic thrusts for growth and development initiatives within or complementary to the Company’s two core businesses: (cid:2) Developing the Company’s strong base of existing delivery busi- nesses through expansion and geographic extension within North America, and through attractive international opportunities; (cid:2) Developing and acquiring field gathering, terminaling and marketing businesses that are complementary to the liquids pipeline business, and pursuing significant growth opportu- nities for natural gas pipeline and gas gathering, processing and marketing investments; (cid:2) Leveraging the position of Enbridge Consumers Gas to estab- lish a new source of growth from investment in and/or provision of services to electric power distribution systems; and (cid:2) Building a base for potential longer term growth through a measured entry into unregulated retail energy services using a transfer of competencies and assets previously developed within Enbridge Consumers Gas. Measuring Performance: We take a very critical look at how we are doing relative to our plans. Generally, we “stay the course” but refine our strate- gies and tactics as needed. We’re not afraid to make course corrections along the way, always keeping in mind our over-riding objective of providing superior returns for our shareholders. New opportunities must not only make sense as part of overall corporate performance, they must make sense on a stand-alone basis. Our goal is to make sure that our highly profitable core businesses do not subsidize less than optimal projects that don’t meet our strategic objectives. Once the project is complete and operational, we also look back to see if our assumptions were valid so we can improve on the decision-making process. In addition to traditional financial indicators such as earn- ings per share and return on equity, we use a variety of other indicators to prioritize and select new projects: (cid:2) Operational and technical performance, which includes stan- dards for environmental protection, health and safety; (cid:2) Economic value added, which we measure by comparing returns to our cost of capital; and (cid:2) Customer contact and services standards, an increasingly important factor which will determine success in a deregu- lated energy environment. LOOKING AHEAD The past year was pivotal in positioning Enbridge for contin- ued growth in the year 2000 and beyond. There is considerable upside for our liquids business. Although oil prices recovered in 1999, drilling levels and volume growth lagged the recovery. However, increased Western Canadian drilling and the numerous oil sands and heavy oil projects announced and under way in Alberta are expected to boost throughput to pre-1999 levels by year end 2000 with further increases thereafter. The investments we have made in additional pipeline capacity will enable us to adapt quickly to increasing supply from Western Canada, and reap the rewards. 4 Enbridge and the Canadian Association of Petroleum Producers announced extension for another five years of the Incentive Tolling Agreement, for the years 2000 through 2004, for the Canadian mainline liquids pipeline system. June Alliance Pipeline began construction in Canada and the United States. Alliance, in which Enbridge has a 21.4% interest, is scheduled to begin transporting natural gas from Western Canada to the Chicago area in October 2000. Initial capacity will be approximately 1.3 billion cubic feet per day. As of year end, 72% of mainline pipe had been installed. E N B R I D G E 1 9 9 9 A N N U A L R E P O R T September Enbridge Gas New Brunswick was awarded the gas distribution franchise for the province of New Brunswick. Enbridge has a 63% interest in the project which will involve investment of approx- imately $300 million over 20 years. Western Canada will continue to provide substantial volume growth, and the extension of our mainline incentive tolling agreement for another five years, from 2000 to 2004, will ensure that Enbridge and its customers continue to share in cost savings from efficient operation of the pipeline system. However, we are also diversifying our sources of liquids supply to other basins and we are making progress on this front. The growth in the gas distribution franchise continues to surpass our estimates. We expect to benefit from the record year of customer additions in 1999, a modest increase in allowed return on equity for 2000, and the return to more normal weather patterns. Our return on capital should also improve with the introduction of targeted Performance Based Regulation (PBR) for three years beginning in 2000. After that, comprehensive PBR is expected to provide further upside. The shared services model we adopted in 1999 will assist in maximizing use of resources and leveraging cost effi- ciencies and intellectual capital across operating units. Despite these efforts, the returns allowed by Canadian reg- ulators continue to be unsatisfactory. Under these conditions, a major challenge for Enbridge — and for all Canadian pipeline and utility companies — will be attracting new funds for our growth plans. To that end, we plan to work with our col- leagues, customers and provincial and federal regulators to address this. With the unbundling of ancillary assets from the gas distri- bution utility last October, we now have the critical mass to operate effectively and capitalize on deregulation of energy services. We will continue to assess opportunities to extend our reach and develop a wide product line. We will also con- tinue our measured approach to establish a sound base of profitable operations. We will continue to seek international investments. But we only pursue opportunities where we can leverage our capa- bilities and bring something other than financial resources to the table. In January 1999, we announced that we were acquiring a 45% interest in the recently completed Jose crude oil storage and marine terminal in Venezuela. Along with our partners, we have been successfully operating the facility since April. However, the issuance of a Venezuelan Minister- ial permit needed to close the transaction was delayed and we hope to close the transaction in the first half of 2000. In just a short time, Enbridge has become a major player in the natural gas transmission and midstream businesses. The Alliance and Vector pipeline projects and the acquisition of a 40% interest in AltaGas Services provide the foundation for future growth in natural gas infrastructure for Enbridge. We also have a number of other opportunities that provide us with further confidence that we can sustain the level of growth that our shareholders have become accustomed to. Our long term view of natural gas is very positive as strong United States demand will drive further infrastructure devel- opment to connect new basins such as the Alaska North Slope, and the Mackenzie Delta and the East Coast of Canada. Enbridge is well positioned to participate in north- ern gas development — we are the only Canadian operator with far northern facilities through both our Norman Wells liquids pipeline and our Inuvik gas pipeline and distribution system. We have been actively developing project design alternatives for consideration by resource owners, recogniz- ing that any such project will likely involve a consortium of producers and pipeline companies. Despite a slowdown in the privatization of Municipal Elec- tric Utilities in Ontario, we are excited about the prospects for energy convergence. Through Canada’s premier natural gas distribution company — Enbridge Consumers Gas — we are perhaps the best positioned to achieve synergies by sharing services between gas and electric distribution systems serving the same customer base. Finally, there are a number of acquisition opportunities we are pursuing to extend our core businesses. As an inde- pendent company with a long history of managing infrastructure assets, we have a natural advantage in acting as an aggre- gator of pipeline assets that become non-strategic to existing owners, including those we expect to be shed from the mega- mergers of large integrated oil companies. 5 T H E E N E R G Y B R I D G E October First commercial natural gas development north of Canada’s Arctic Circle became a reality with start-up of the Inuvik Gas Project to distribute natural gas to the town of Inuvik. Enbridge has a 33 1/3% interest. Unbundling took effect October 1, 1999, with Enbridge Consumers Gas remaining a regulated gas distribution company, and Enbridge Services becoming the provider of energy products and services in a non-regulated environment. The first phase of the Terrace Expansion on Enbridge’s mainline system was completed, adding 170,000 barrels per day of capacity for heavy and synthetic oils. Pipeline construction was completed in February, with facilities additions completed in the fall. SHARE PRICE AND DIVIDENDS Although Enbridge has provided superior returns to share- holders over the last five years, our share price performance in 1999 was disappointing. We believe that the decline we experienced in 1999 was not a reflection of a change in business fundamentals, but rather general market conditions. Although we don’t believe that the current price reflects full value for our shares, we will con- tinue to focus our attention on factors within our control and on delivering profitable growth for our shareholders. Cer- tainly senior management at Enbridge is convinced of the continued fundamental strength of the Company and of our prospects for growth — that is why senior management, and many others in the Company, have shown their commitment by continuing to acquire shares. Conditions in the equity markets and circumstances related to some of our peers also resulted in some erroneous con- cerns regarding the dividend. Since 1995, Enbridge has increased its quarterly dividend by an average of 5% each year. These increases were based entirely on the level and quality of earnings growth and not because of reduced opportuni- ties to reinvest capital at attractive rates of return. During this period, our payout has declined from 87% in 1995 to 63% last year, which provides substantial support for the current dividend. The Company has shown a commitment to further increase dividends for shareholders as the last four years have demonstrated. Based on our positive outlook for earnings growth, we see no reason why this trend should not continue. THE ENERGY BRIDGE Last year was our first full year operating as Enbridge, one Company with one name and one vision. We have had con- siderable success in establishing this new brand, and we are using the roots of our name — energy and bridge — as this year’s annual report theme. It’s appropriate because that is how we see ourselves — as a bridge to our various stakeholders. We are an energy bridge — the premier provider of energy delivery and services, to seamlessly link our customers to sources of supply. We are also a bridge from the financial capital invested by our share- holders to the physical infrastructure required to meet our customers’ energy needs and generate a return on investment. A key link in all of our bridges is, of course, our employees, and we thank them for their contributions during the past year. It was a year of change and new challenges for many, as we unbundled energy services and established the shared services organization. We appreciate the special effort and commitment that took. Special thanks, too, to all those employees who worked so hard to prepare for Year 2000, and the more than 600 employees who participated in the year end rollover to ensure a smooth, uneventful tran- sition to 2000. In 1999, we strengthened our bridges to and for our cus- tomers, our shareholders, and the communities where we operate. In 2000 and beyond, we will strengthen our exist- ing bridges and continue to establish new ones for the Enbridge of the future. On behalf of the Board of Directors: D.J. Taylor Chairman of the Board of Directors February 23, 2000 B.F. MacNeill President & Chief Executive Officer 6 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Answers to some frequently asked questions Why did Enbridge’s share price drop in 1999? Enbridge’s common share price declined from $35.25 to $28.65 in 1999. Since Enbridge pays a healthy dividend, the net decline in terms of total shareholder return (dividends plus change in share price) was 16%. Although we’re not satisfied with this result, Enbridge’s share price performed relatively well compared with our peers. We believe that the decline related to general market conditions rather than a change in investors’ views toward Enbridge. First, 1999 saw a steady and substantial rise in interest rates, and the increase continued into 2000. That’s not a good situation for stocks such as ours that are sensitive to interest rates. Generally, as interest rates rise, dividend paying stocks and interest bearing securities like bonds decline in price and the opposite occurs when interest rates decline. In addition, there was an unprecedented flow of funds from investors into other industries that benefit from strong economic conditions, such as the high-tech industry, and to participation in the demutualization of the insurance business in Canada. Despite the downturn, the fundamentals of our business remain strong and our outlook for growth continues to be positive. What is Enbridge’s position on dividends? Dividend policy is a matter for Enbridge’s Board of Directors, and subject to its ongoing review. In general, however, given that we are well positioned to continue the pattern of strong earnings established over the last five years, the Company expects dividend growth to continue. Are you still interested in electric power distribution? You had unbundling problems. Why, and when will the problem be fixed? The pace of privatization of Ontario’s Municipal Electric Utilities (MEUs) has been slower than expected. We are working with MEUs to pursue partnerships, shared services and other relationships, but we believe it will be several years before there are major investment opportunities. However, we continue to be encouraged by the prospects for convergence of energy sources. Enbridge is well positioned to achieve synergies by sharing services between gas and electric distribution systems serving the same customer base. We recently established a dedicated corporate entity that will provide common services to all Enbridge distribution and energy services companies in Central and Atlantic Canada. This entity will maximize resources and leverage cost synergies across all of our business units, and could potentially provide services for third party entities such as MEUs. Despite extensive planning and preparation for the transfer of non-regulated energy products and services from Enbridge Consumers Gas to Enbridge Services, we experienced some start-up problems. A combination of factors, including record numbers of customer telephone calls, resulted in delays in answering calls and in dispatching service personnel. As a result, we disappointed some long-time Enbridge customers, but we moved quickly to resolve the problems. We added personnel, phone lines and service capacity, and brought service levels back to Enbridge’s high standards. The support and trust of our customers is very important to Enbridge, and regaining their confidence has a high priority. Does Enbridge plan to make a large corporate acquisition? Our focus is on the substantial growth potential that exists within our core businesses. We believe that numerous opportunities exist for continued expansion of these core businesses, as we have demonstrated by our success in the past, as well as for selective small-scale acquisitions, joint ventures and investments. However, we also will continue to assess other investment opportunities that could make economic sense for us and for our shareholders. When used in this annual report, the words “believe,” “estimate,” “forecast,” “anticipate,” “expect,” “project” 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. 7 T H E E N E R G Y B R I D G E Patrick D. Daniel President & Chief Operating Officer, Energy Delivery “ENBRIDGE’S CORE ENERGY DELIVERY BUSINESSES CONTRIBUTE DIRECTLY TO GROWTH MOMENTUM. LAST YEAR WE BROUGHT ON STREAM OVER $1.5 BILLION OF NEW CRUDE OIL PIPELINE ASSETS TO SERVE OUR PRODUCING AND REFINING CUSTOMERS, AND $400 MILLION OF NEW GAS DISTRIBUTION FACILITIES IN ONTARIO TO SERVE 58,000 NEW CUSTOMERS. WE ALSO CONTINUED TO INCREASE INTERNATIONAL EARNINGS.” 8 The Athabasca Pipeline (above) was completed in 1999 as were the SEP II and Terrace Phase I (at right) expansions. Operations Review In 1999, Enbridge adopted a new business seg- mentation that better reflects how the business is managed. These segments include Liquids Pipelines, Gas Distribution, International, Gas Pipelines and New Business Development, and Energy Services. LIQUIDS PIPELINES The Liquids Pipelines segment is one of Enbridge’s two core businesses. Through subsidiaries such as Enbridge Pipelines Inc., Enbridge owns and operates the world’s longest crude oil and natural gas liquids pipeline system. The mainline pipeline consists of the wholly owned Enbridge System in Canada and the Lakehead System in the United States. Enbridge has a 15.3% interest in the Lakehead System. The combined system is the primary transporter of crude oil from Canada to the United States, and is the only pipeline that transports crude oil from Western Canada to Eastern Canada, serving all of the major refining centres in the province of Ontario as well as the Great Lakes region of the United States. In 1999, the system delivered an average of 2.0 million barrels per day, and as a result of recently completed expansion programs, has overall capacity of approximately 2.2 million barrels per day. The system consists of approximately 14 000 kilometres (8,700 miles) of mainline pipeline in Canada and in the United States. Highlights in 1999 included strengthening of the existing energy transportation business and addition to overall pipeline capacity through completion of a number of expansions and extensions including: (cid:2) The System Expansion Program Phase II which increased system capacity by 100,000 barrels per day in Canada and 170,000 barrels per day into Chicago. (cid:2) Terrace Expansion Phase I which added 170,000 barrels per day of capacity for heavy and synthetic oils. (cid:2) The Athabasca Pipeline which has a potential capac- ity of 570,000 barrels per day to transport synthetic and heavy oils from northern Alberta to the pipeline hub at Hardisty, Alberta. (cid:2) Line 9 which went into fully reversed flow in Sep- tember 1999, enabling shippers to deliver up to 240,000 barrels per day of offshore crude from Montreal to refineries in the Sarnia area. (cid:2) The Toledo Pipeline which connects the Lakehead system at Stockbridge, Michigan, to two refineries in the Toledo, Ohio, area, with capacity in excess of 80,000 barrels per day of heavy crude oil. In addition to these projects which were completed in 1999, Enbridge announced a proposal to con- struct a pipeline in the southern United States to transport offshore crude oil from the St. James, Louisiana, pipeline hub to Houston area refiners. Enbridge is discussing the proposal, called the Alli- gator Pipeline, with potential shippers and is seeking firm commitments before proceeding with a specific project application. Another significant achievement in 1999 was the successful negotiation of a five-year extension to the Incentive Tolling Agreement (ITA). Enbridge and the Canadian Association of Petroleum Producers announced extension of the ITA for the years 2000 through 2004 for the Canadian mainline liquids pipeline system. As of year end 1999, the first ITA had generated after tax savings of $66 million that were shared by Enbridge and its customers. The fundamentals of the extended agreement are con- sistent with the original agreement, and confirm that Enbridge and its customers will continue to share in savings from cost reductions and pro- ductivity gains. E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Norman Wells Zama Fort McMurray Edmonton Hardisty Casper Salt Lake City Montreal Toronto Chicago Toledo Patoka Liquids Pipelines Enbridge Pipelines Inc. and Lakehead Pipe Line Partners, L.P. Enbridge Pipelines (NW) Inc. Enbridge Pipelines (Saskatchewan) Inc. Enbridge Pipelines (North Dakota) Inc. Enbridge Pipelines (Athabasca) Inc. Enbridge Pipelines (Toledo) Inc. Mustang Pipe Line Partners Frontier Pipeline Company Chicap Pipe Line Company The Liquids Pipelines business segment also includes: (cid:2) Enbridge Pipelines (NW) Inc. which transports crude oil from Norman Wells, N.W.T., to Zama, Alberta. (cid:2) A number of feeder pipeline systems which deliver crude oil to the mainline system, including Enbridge Pipelines (Saskatchewan) and Enbridge Pipelines (North Dakota), formerly Producers and Portal pipelines, respectively. (cid:2) Investment in a number of strategic crude oil pipelines in the United States, including a 44% interest in the Frontier Pipeline; a 30% interest in Mustang Pipe Line Partners; and a 23% interest in the Chicap Pipe Line Company. GAS DISTRIBUTION Gas Distribution is Enbridge’s other core business. It includes Enbridge Consumers Gas, Canada’s largest natural gas distribution company; Enbridge’s inter- est in natural gas distribution in Quebec, through Noverco Inc.; and Enbridge Gas New Brunswick. Enbridge Consumers Gas: The Consumers’ Gas Company Ltd., which is wholly owned by Enbridge Inc. and which operates under the name Enbridge Consumers Gas, has been distributing natural gas to customers for more than 150 years. Together with its subsidiaries, Enbridge Consumers Gas delivered 402 billion cubic feet of natural gas in 1999 to approximately 1.5 million residential, commercial, industrial, and transportation service customers. Enbridge Consumers Gas serves customers in central and eastern Ontario. Its wholly owned subsidiary Gazifère Inc. serves southwestern Quebec, and St. Lawrence Gas Company, Inc. serves parts of north- ern New York State. Another subsidiary, Niagara Gas Transmission Limited, provides transmission services to Enbridge Consumers Gas, Gazifère and St. Lawrence Gas, and links southwestern Ontario storage facilities with pipelines in Michigan. In recent years, Enbridge Consumers Gas has shown sustained growth, adding more than 50,000 customers per year. In 1999, the distribution network expanded with a 7.3% increase in approved rate base reflecting the addition of 12 new communities and a record 58,000 new cus- tomers. The company also received regulatory approval to implement Performance Based Regu- lation, which is expected to benefit ratepayers through guaranteed productivity benefits and con- tinued delivery of high quality service, and also benefit Enbridge Consumers Gas. The Company will operate under a simplified regulatory process and reward shareholders when there are cost reductions and productivity gains. For years, Enbridge Consumers Gas operated as an integrated, regulated utility, delivering natural gas to customers, supplying heating and related appliances, and providing maintenance and other services. However, the growing shift towards energy deregulation has resulted in unbundling of ser- vices, which involves the removal of ancillary products and services from regulatory control, Stephen J. Wuori President, Enbridge Pipelines Inc. “THE LIQUIDS PIPELINES BUSINESS SEGMENT IS WELL POSITIONED TO DELIVER SOLID GROWTH. WE HAVE THE ABILITY TO TRANSPORT INCREASING VOLUMES OF CRUDE OIL TO KEY MARKETS, AND TO OFFER SUPERIOR TOLLS, TRANSIT TIMES AND OPERATING FLEXIBILITY TO OUR CUSTOMERS.” Rudy G. Riedl President, Enbridge Consumers Gas “IN 1999, ENBRIDGE CONSUMERS GAS RESTRUCTURED ITSELF TO BE BETTER PREPARED FOR MORE COMPETITION IN THE RAPIDLY CHANGING ENERGY MARKETPLACE. IN 2000, MANAGEMENT AND EMPLOYEES WILL FOCUS ON CONSOLIDATING OUR GAINS AND IMPROVING THE QUALITY OF SERVICE TO OUR CUSTOMERS.” 9 T H E E N E R G Y B R I D G E Mel F. Belich Senior Vice President, International Development & Corporate Law; Chairman, Enbridge International Inc. and Chairman, Enbridge Technology Inc. “ENBRIDGE INTERNATIONAL DEVELOPS AND MANAGES THE CORPORATION’S INTERNATIONAL ENERGY OPPORTUNITIES, INCLUDING THE CONSTRUCTION, OWNERSHIP AND OPERATION OF LIQUIDS AND NATURAL GAS PIPELINES, TERMINALS AND STORAGE SYSTEMS AROUND THE WORLD. ENBRIDGE TECHNOLOGY COMPLEMENTS THAT EFFORT BY PROVIDING SPECIALIZED CONSULTING AND TRAINING EXPERTISE ON A GLOBAL BASIS.” 10 Enbridge invested in AltaGas Services (at left), continued to add customers for Enbridge Consumers Gas (above), and operated Cornwall Electric (at right). thereby eliminating the regulatory constraints that hamper the market responsiveness and competi- tiveness of those businesses. As of October 1, 1999, a separate and unregulated affiliate called Enbridge Services Inc. began delivering the prod- ucts and services that Enbridge Consumers Gas had historically delivered. Enbridge Consumers Gas remains regulated, and will still be responsi- ble for the supply and distribution of natural gas to its customers. Noverco: Through its 32% interest in Noverco Inc., Enbridge participates in gas distribution and trans- mission in Quebec and the northeastern United States — Noverco has a 77% interest in Gaz Mét- ropolitain and Company, Limited Partnership. Gaz Métropolitain is Quebec’s major gas distributor. The only other distribution company in the province is Gazifère, which is an Enbridge company. Enbridge Gas New Brunswick: Enbridge is a 63% participant in Enbridge Gas New Brunswick, which was awarded the franchise for natural gas distrib- ution in New Brunswick in September 1999. Enbridge Gas New Brunswick anticipates investing approximately $300 million during the 20-year fran- chise period to distribute gas to up to 23 communities. Natural gas service to the first New Brunswick customers is planned to start in late 2000. The project is of strategic importance because it provides Enbridge with a presence in Atlantic Canada, which is becoming an important new energy region in North America. INTERNATIONAL Enbridge’s international objective is to supplement its North American business activities with invest- ments in attractive foreign projects that utilize the Company’s technical and operating expertise. An example is the company’s investment in the OCENSA pipeline in Colombia. OCENSA: The Oleoducto Central South America (OCENSA) crude oil pipeline was Enbridge’s first international venture, entered into in 1994. Enbridge has a 17.5% interest and acts as joint operator of the pipeline, tankage and marine loading system that transports 500,000 barrels per day of crude oil from the Cusiana and Cupiagua oilfields in the central interior of Colombia to the Port of Coveñas on the Caribbean coast. Enbridge earns a fixed rate of return on its OCENSA invest- ment, plus operating and incentive fees. Venezuela: In January 1999, Enbridge announced that it had entered into an agreement to operate and acquire, through a Venezuelan general partnership, a 45% interest in the Jose Crude Oil Storage and Ship Loading Terminal project in Venezuela. The ter- minal, a new facility located within the Jose Industrial Complex, a large petroleum and petrochemical facil- ity, handles crude oil from Eastern Venezuelan fields for loading onto tankers for export, and has initial throughput capacity of approximately 800,000 barrels per day. The partnership began operating the Jose facility in April 1999, and as of year end 1999, the acquisition was subject only to the receipt of gov- ernment permits. Technology: Enbridge Technology Inc. provides crude oil pipeline and natural gas distribution consulting and training services. A highlight in 1999 was the completion of a significant contract with PEMEX Refining, a subsidiary of the national oil company of Mexico, to provide conceptual design and advisory services on the modernization of its national crude oil and refined products pipeline system. Enbridge Technology provides consulting and training services around the world. Its global reach provides Enbridge with an entry into a variety of countries to review and investigate business opportunities, and offsets inter- national business development costs with earnings from consulting and technology projects. E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Inuvik Fort St. John Edmonton Ottawa Montreal Dawn Toronto Chicago Gas Distribution Enbridge Consumers Gas Noverco Inc. Enbridge Gas New Brunswick Inuvik Gas Project Gas Pipelines Alliance Pipeline Vector Pipeline Gas Gathering and Processing AltaGas Services Electric Power Distribution Cornwall Electric GAS PIPELINES AND NEW BUSINESS DEVELOPMENT In just a few short years, Enbridge has developed a significant presence in the natural gas trans- mission business, primarily through its investment in the Alliance and Vector pipelines. In 1999, Enbridge also entered the midstream gas business with a 40% investment in AltaGas Services Inc. Gas Pipelines: The Alliance Pipeline is a new gas transmission system being built from Fort St. John, British Columbia, to Chicago, Illinois. Enbridge has a 21.4% interest in the project. The pipeline began construction in the first quarter of 1999 and as of year end 1999 had completed 2 150 kilometres (1,336 miles), or 72% of the mainline. The line is scheduled to be in service in October 2000 and will have the capacity to deliver approximately 1.3 billion cubic feet per day. Enbridge is the sponsor of and has a 45% interest in the Vector Pipeline, which will transport natural gas from Chicago to Dawn, Ontario. At Chicago, Vector will connect with the Alliance Pipeline and other natural gas transmission systems, providing a transportation link for Western Canadian and U.S. sourced supplies. Vector construction began early in 2000, and the line is projected to be in service in October 2000. Initial capacity will be approxi- mately 1 billion cubic feet per day. Gas Gathering and Processing: Enbridge entered the midstream natural gas business in 1999 by acquir- ing a 40% interest in AltaGas Services Inc., a publicly traded, Alberta-based company that since 1994 has acquired or constructed over $390 million in natural gas assets. These assets include natural gas gathering and processing facilities, ethane and natural gas liquids extraction plant pro- cessing capacity, and ownership of AltaGas Utilities Inc., a natural gas distribution company serving over 90 Alberta communities. Enbridge’s investment in AltaGas represents the addition of an attractive new growth platform which is complementary to other Enbridge energy delivery businesses. Inuvik Gas Project: Enbridge owns a 33 1/3% inter- est in the Inuvik Gas Project, together with partners AltaGas Services (a 40% owned affiliate) and the Inuvialuit Petroleum Corporation. The project involves a 50 kilometre (30 mile) gas pipeline and a local distribution network to supply gas to the town of Inuvik in the N.W.T. Though small, the project is significant in that it involves the first commercialization of Mackenzie Delta natural gas reserves, and augments Enbridge’s experience with construction of pipelines in permafrost con- ditions. It also provides a successful model for cooperation with local interests in the development of northern energy delivery infrastructure. Electric Power Distribution: The 1998 acquisition of Cornwall Electric — an Enbridge Company, has pro- vided Enbridge with experience in the electric power business in anticipation of further Enbridge invest- ments in and partnerships with Ontario Municipal Electric Utilities. In addition, Enbridge has devel- oped a strategic alliance with Hydro-Québec, one of the principal shareholders of Noverco. This strate- gic alliance could provide significant competitive advantages with respect to future electric power dis- tribution and cogeneration opportunities. J. Richard Bird Senior Vice President, Corporate Planning & Development and President, Enbridge Consumers Energy Inc. “A WHOLE NEW INFRASTRUCTURE GROWTH SEGMENT HAS BEEN SUCCESSFULLY LAUNCHED ON THE STRENGTH OF TRANSFERABLE SKILLS AND SYNERGIES PROVIDED BY OUR CORE BUSINESSES. THIS SEGMENT, CONSISTING OF INVESTMENTS IN NATURAL GAS PIPELINES, GATHERING AND PROCESSING, AND ELECTRIC POWER DISTRIBUTION, IS ALREADY CONTRIBUTING 10% OF ENBRIDGE’S EARNINGS. STRONG POTENTIAL FOR FURTHER GROWTH EXISTS INCLUDING DEVELOPMENT OF ALASKA NORTH SLOPE, MACKENZIE DELTA AND EAST COAST GAS RESERVES; RATIONALIZATION OF THE WESTERN CANADA GATHERING AND PROCESSING INDUSTRY; AND RESTRUCTURING OF THE ONTARIO ELECTRIC INDUSTRY.” 11 T H E E N E R G Y B R I D G E Enbridge Services sells retail energy products (at left) and services appliances (above). Enbridge’s Pat Daniel launches Action By Canadians (at right) as Federal Environment and Natural Resources Ministers Anderson and Goodale listen. ENERGY SERVICES In 1997, using its extensive experience in Enbridge Consumers Gas as a base, Enbridge began to make a measured entry into the emerging world of deregulated and unbundled energy services in Canada and the United States. Effective October 1, 1999, ancillary assets from the gas distribution utility were transferred into a fully unregulated retail products and services business called Enbridge Services Inc. Enbridge Services began delivering, in the non-regulated home comfort marketplace, those products and services that Enbridge Con- sumers Gas had historically provided as part of its regulated operations. That includes operating the Enbridge Consumers Gas Appliance Stores, which now are known as Enbridge Home Services stores, and offering a complementary portfolio of retail energy products and services such as the sale and maintenance of heating and air condi- tioning appliances and equipment, hearth products, and financing for those appliances. In Canada, Enbridge Services operates outlets in Ontario and B.C. Retail energy service opportunities also have been identified in the United States, where governments are going through similar stages of energy deregulation and unbundling. Enbridge (Penn- sylvania) Inc. was established in 1998 to test the potential for developing a retail energy services busi- ness in the Philadelphia area as a first step to expanding into other United States markets. Stephen J.J. Letwin President & Chief Operating Officer, Energy Services “ENBRIDGE SERVICES ENTERED 2000 WELL POSITIONED TO GROW OUR UNREGULATED RETAIL ENERGY SERVICES BUSINESS. WE HAVE AN ENVIRONMENT, HEALTH AND SAFETY — AND THE CHALLENGE OF CLIMATE CHANGE EXCELLENT MANAGEMENT TEAM FOCUSED ON OPERATIONAL EXCELLENCE. WE HAVE SIGNIFICANT OPPORTUNITIES FOR GEOGRAPHIC EXPANSION AND INCREASED MARKET SHARE IN OUR CORE AREAS.” Enbridge’s commitment to health, safety and envi- ronmental stewardship extends from the Board of Directors to employees in the field. The Company uses a comprehensive system of policies, pro- grams and procedures to promote a safe work environment, identify and control hazards, and promote the safety of all personnel. Similarly, Enbridge management ensures the Company is operating in an environmentally respon- sible manner. In 1999, the Company continued to monitor and audit facilities, remediate sites, and integrate environmental planning into a variety of North American and International projects. nating role and is developing the foundation for the Company’s role in the climate change challenge. In 1999, Enbridge was instrumental in creating a nation-wide greenhouse gas emissions reduction program, Action By Canadians. The program pro- motes voluntary action by individual Canadians, and was launched by Pat Daniel, Enbridge Presi- dent & Chief Operating Officer, Energy Delivery, and Chairman of the Energy Council of Canada. The ABC program is a partnership with the Energy Council of Canada and its member organizations, 15 of which have provided funding for the program, and the Government of Canada. A key environmental focus in 1999 was climate change. The need to implement an effective corpo- rate framework to manage greenhouse gas emissions against a background of continuing policy uncertainty resulted in the establishment of the Enbridge Climate Change Task Force in the fall of 1999. The task force has a planning and coordi- Enbridge is also a participant in Canada’s Climate Change Voluntary Challenge and Registry (VCR). In 1999, Enbridge Consumers Gas and Enbridge Pipelines (Saskatchewan) received Gold Champion Reporting Level awards from the VCR, and Enbridge Pipelines received a Silver Champion Reporting Level award. 12 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Enbridge supports a variety of initiatives that strengthen the fabric of the communities where we operate. ENBRIDGE IN THE COMMUNITY Enbridge’s Community Investment Program reflects a core value — corporate social responsibility. We support organizations that require financial and human resources, knowledge and structural capac- ity that in turn will ultimately strengthen and sustain communities. The overall objective is to help build communities while supporting those in need. We focus our community investment on health and social services, education, environ- mental and civic initiatives. In 1999, Enbridge invested approximately $3.0 million while expanding our involvement in some very key community-building opportunities. Health and Social Services: A focus for Enbridge employees in 1999 was the emerging social issues around homelessness, child hunger, youth and domestic violence. Through our combined corporate and employee led donations and fundraising events, Enbridge raised approximately $1.6 million in Canada and another $120,000 in the United States for the United Way. Another key initiative was the Enbridge Festival of Trees, a Christmas part- nership with the Alberta Lung Association and Southern Alberta Children’s Hospital which raised over $200,000 for the Hospital. Enbridge Con- sumers Gas was one of the founding sponsors of Share the Warmth, a not-for-profit fund that assists low-income families, seniors, chronically ill and dis- abled persons who are unable to pay their energy bills. Last year, the Company assisted Share the Warmth to expand its services to all of the areas serviced by Enbridge Consumers Gas. Education: Support for education included the funding of major literacy-related programs to help raise community awareness of the issue and the need for this fundamental learning skill. Also, post- secondary scholarships in Corporate Environmental Management and Environmental Regulatory Studies were created to advance the exchange of knowl- edge between industry and students who represent future industry leadership. Environment: Since its inception in 1991, our highly acclaimed and effective Environmental Initiative Program (EIP) has contributed to over 200 innov- ative and collaborative community-based groups in communities along our pipeline system. Our EIP helps community groups implement their own envi- ronmental programs, and helps inform people of the importance of being engaged in conservation efforts. Specific projects included funding for an interpretive trail system in Norman Wells, N.W.T., and wetland conservation and rehabilitation pro- grams in Cornwall, Ontario. Civic: In Eastern Canada, the Enbridge Community Event Services Team continued to provide barbecue services, a popular hot air balloon program and special event services for a variety of community functions. In 1999, over 800 community events were supported, attracting over one million people. In Western Canada, Enbridge helped create a unique program called Leadership Calgary, with a compa- rable program in Edmonton and the potential for programs in Toronto and Ottawa. The program recruits and nurtures rising leaders from all sectors of the community, then helps develop civic leader- ship skills through workshops and practicums. Enbridge is committed to embracing and nurtur- ing the spirit of volunteerism with our employees and in our communities and supports a grassroots, employee-driven program called Volunteers In Part- nership. This community outreach program engages employees and their families in supporting chari- table organizations as volunteers with a wide range of community-building programs. Bonnie D. DuPont Senior Vice President, Human Resources & Public Affairs “A BRIDGE NEEDS STRONG FOUNDATIONS. ONE OF ENBRIDGE’S FOUNDATIONS IS OUR EMPLOYEES. ANOTHER IS THE SUPPORT OF THE PEOPLE AND COMMUNITIES IN AREAS WHERE THE COMPANY OPERATES.” 13 T H E E N E R G Y B R I D G E Management’s Discussion and Analysis Derek P. Truswell Senior Vice President & Chief Financial Officer OVERVIEW The following indicators illustrate Enbridge Inc.’s progress in achieving its growth objectives. Return on Average Common Shareholders’ Equity Earnings Applicable to Common Shareholders (millions of dollars) Earnings per Common Share (dollars per share) Dividends per Common Share (dollars per share) Total Assets (billions of dollars) Active Customers at Gas Utility (thousands) Liquids Deliveries (thousands of barrels per day) 1 Represents average ROE for five year period 1999 1998 1997 1996 14.3% 287.9 1.91 1.195 9.2 1,466 2,023 13.8% 240.9 1.66 1.120 8.3 1,414 2,136 14.2% 217.3 1.58 1.060 6.7 1,362 2,083 15.0% 180.3 1.45 1.015 5.8 1,307 1,970 Compound Annual Growth 1995 13.2% 130.4 1.15 1.000 5.2 1,264 1,754 14.1% 1 21.9% 13.5% 4.6% 15.3% 3.8% 3.6% (cid:2) Return on average common shareholders’ equity improved to 14.3% in 1999, well above average regulated rates of return in Canada. (cid:2) The Corporation’s total assets have grown by an average of 15% annually over the past four years while still main- taining a strong and improving return on common equity. (cid:2) Earnings applicable to common shareholders increased by $47 million, or 20%, over 1998 resulting in a compound earnings growth rate of almost 22% per annum over the last four years. This improvement was achieved despite the record warm winters experienced in the Corporation’s gas distribution franchise areas over the past two years which adversely affected earnings by $31 million in 1999 and $40 million in 1998. (cid:2) With earnings per common share of $1.91 in 1999, the Corporation has achieved its double digit growth objective since 1995. (cid:2) While increasing its quarterly dividend payments for the fourth consecutive year in 1999, the Corporation has reduced its dividend payout ratio to 63% from 87% in 1995, in line with its growth objectives. (cid:2) Despite the significant decrease in average crude oil prices in late 1998 and its impact on throughput levels during 1999, the Corporation’s liquids pipeline systems have recorded a 4% compound annual growth rate in throughput over the last four years. (cid:2) Similarly the Corporation’s gas distribution utility customer base in Ontario has maintained a growth rate of 4% per annum since 1995. (cid:2) Since the beginning of 1995, Enbridge has invested $5.2 billion in additions to property, plant and equipment, long term investments and acquisitions of subsidiaries and joint ventures. These investments have been facilitated by a continued access to capital markets. Over the last five years, Enbridge has raised $4.9 billion through debt and equity offerings in Canada and the United States. 14 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T “ENBRIDGE HAS TRANSFORMED FROM A RATE REGULATED BUSINESS INTO A DIVERSIFIED ENERGY DELIVERY AND SERVICE PROVIDER IN NORTH AMERICA AND INTERNATIONALLY, WHILE MAINTAINING ITS RELATIVELY LOW RISK PROFILE.” Earnings Applicable to Common Shareholders (millions of dollars) Return on Average Common Shareholders’ Equity (%) . 0 5 1 . 2 3 1 . 2 4 1 . 8 3 1 . 3 4 1 Financial Highlights (Canadian dollars in millions; except per share amounts) 1999 1998 1997 . 9 7 8 2 . 9 0 4 2 . 3 7 1 2 . 3 0 8 1 . 4 0 3 1 95 96 97 98 99 95 96 97 98 99 FINANCIAL HIGHLIGHTS The following should be read in conjunction with the Consoli- dated Financial Statements included in this report. The Consolidated Financial Statements have been prepared in accordance with Canadian Generally Accepted Accounting Prin- ciples (GAAP). The impacts of differences between Canadian and US GAAP are disclosed in Note 18 to the Consolidated Financial Statements. Earnings Applicable to Common Shareholders Liquids Pipelines Gas Distribution International Gas Pipelines and New Business Development Energy Services Corporate Preferred Securities Distributions Preferred Share Dividends Cash Provided from Operating Activities Common Share Dividends Per Share Amounts1 Earnings Dividends 165.3 99.2 28.7 143.2 100.2 24.3 108.4 132.1 16.1 31.2 (2.5) (22.1) (5.0) (6.9) 6.3 (6.2) (26.9) — — (2.4) (7.5) (29.4) — — 287.9 240.9 217.3 495.1 186.4 312.4 168.3 437.8 147.1 1.91 1.195 1.66 1.120 1.58 1.060 1 Per share amounts reflect amounts applicable to common shares only and prior year amounts have been restated to reflect the two for one stock split that occurred on May 10, 1999. 15 T H E E N E R G Y B R I D G E Earnings applicable to common shareholders increased $47.0 million over 1998. The improvement is principally the result of the expansion of the liquids mainline system, completion of the Athabasca pipeline project, increased investment in gas pipeline systems and fees earned from operating the Jose Ter- minal in Venezuela. These improvements were partially offset by higher financing costs to support the growth initiatives and the absence of an insurance settlement recorded in 1998. The Gas Distribution segment continued to be affected by warmer than normal weather, resulting in earnings consis- tent with the prior year. The improvement in 1998 earnings over 1997 was primarily a result of the pipeline system construction and expansions within the Liquids Pipelines, Gas Pipelines and International segments as well as a full year contribution from the strategic investment in Noverco Inc. and the settlement of an insurance claim outstanding since 1991. These gains were partially offset by warmer weather and a lower allowed rate of return within Gas Distribution operations. Increases in cash provided from operating activities are the product of improved pretax earnings and lower current income tax expense, the latter resulting from high tax deductions asso- ciated with recent capital additions. The funding of changes in operating assets and liabilities was not as substantial in 1999 as the previous year due to the lower level of acquisi- tions, asset additions and long term investments. Common share dividends paid over the last three years reflect both increases in the dividend rate and the number of common shares outstanding. As a result of sustained growth in earn- ings, quarterly dividends increased to $0.2725 per share in the third quarter of 1997, to $0.2875 per share in the third quarter of 1998 and to $0.3025 per share in the second quarter of 1999, representing increases of 5.8%, 5.5% and 5.2%, respectively. RESULTS OF OPERATIONS In 1999, Enbridge adopted a new business unit segmentation that reflects current management accountability for opera- tions. The operating segments shown below represent strategic business units that are established by senior man- agement of the Corporation to facilitate achievement of the Corporation’s long term growth objectives, to aid in resource allocation decisions and to assess divisional performance. These segments include Liquids Pipelines, Gas Distribution, International, Gas Pipelines and New Business Development, and Energy Services. The following discussion and analysis provides information on each business unit’s results on both a segmented and operating basis. The operating results are based upon those presented in Note 2 to the Consolidated Financial Statements. Liquids Pipelines The results of the Liquids Pipelines segment include contribu- tions from three primary North American liquid hydrocarbon pipeline systems: the Canadian portion of the main crude oil pipeline (Enbridge System), the 15.3% owned portion located in the United States (Lakehead System) held through a U.S. Master Limited Partnership (Partnership) and a wholly owned pipeline originating in the Northwest Territories (Enbridge (NW) System). The segment also includes the Corporation’s inter- ests in the wholly owned Enbridge (Athabasca) Pipeline and other feeder pipelines located in Canada and the United States. Segmented Results Liquids Pipelines (Canadian dollars in millions) Enbridge System Lakehead System Enbridge (NW) System Enbridge (Athabasca) System Feeder pipelines and other 1999 1998 1997 97.9 18.9 11.1 23.9 13.5 81.7 25.9 11.0 13.5 11.1 68.3 16.0 12.6 — 11.5 Earnings 165.3 143.2 108.4 Enbridge System The increase in Enbridge System earnings over the three year period is attributable to system expansions as well as sus- tained achievements under incentive tolling. The second phase of the System Expansion Program (SEP II) was com- pleted in early 1999, while major portions of the Terrace Expansion Project were put into service during 1999. The 1998 results included a $4 million gain on the resolution of an insurance claim. Under the Incentive Tolling Agreement (ITA) entered into in 1995, higher earnings are achieved by maximizing system utilization and increasing operating efficiency, unlike traditional cost based regulation where earnings are based on the level of capital investment. Under the agreement, earnings in excess of pre-determined thresholds are shared between the Corpo- ration and its customers. In 1999, after tax cost savings amounted to $17.7 million, providing a net benefit of $9.5 million to the Corporation (1998 – $9.0 million, 1997 – $9.3 million) and $8.2 million to industry (1998 – $7.7 million, 16 Incentive Tolling Agreement Cost Performance Savings (after tax, millions of dollars) . 7 7 1 . 3 7 1 . 7 6 1 1 Deliveries (thousands of barrels per day) 6 3 1 2 , 3 8 0 2 , 3 2 0 2 , 0 7 9 1 , 4 5 7 1 , 1 8 . 2 6 . 95 96 97 98 99 Shipper Share Enbridge Share 2.5 3.4 8.0 7.7 8.2 3.7 4.7 9.3 9.0 9.5 1995 1996 1997 1998 1999 Total 6.2 8.1 17.3 16.7 17.7 1997 – $8.0 million). Since inception of the ITA in 1995, after tax benefits of $66.0 million have been shared approximately 55% and 45% by the Corporation and industry, respectively. Low crude oil prices in late 1998 and early 1999 resulted in reduced throughput in 1999 on both the Canadian and U.S. systems, however, Enbridge System earnings were not mate- rially affected due to throughput protections incorporated in the ITA. Lakehead System The Lakehead System also experienced significant through- put reductions as a result of low crude prices. Crude oil deliveries averaged 1,369,000 barrels per day in 1999 down from the record 1,562,000 barrels in 1998, representing a 12% decline. Enbridge’s earnings were not materially affected due to its level of ownership in the Lakehead System. Partially offsetting the reduced equity income from the Part- nership were greater incentive allocations to Enbridge, as General Partner, due to achieving higher distribution levels to unitholders of the Partnership. In 1998, Lakehead System earnings included a $6 million gain related to the settlement of an outstanding insurance claim, which, coupled with higher incentive allocations resulted in earnings improvements over 1997. E N B R I D G E 1 9 9 9 A N N U A L R E P O R T By Product Type 1 Light Crude Oil Medium and Heavy Crude Oil Refined Products and Natural Gas Liquids By Destination 1 Prairies United States Eastern Canada 1999 1998 1,036 1,089 774 833 213 214 2,023 2,136 447 1,028 548 2,023 459 1,105 572 2,136 96 99 97 95 1 Includes deliveries by the 15.3% 98 owned Lakehead System Enbridge (NW) System Through an agreement with the main shipper on the system, Enbridge (NW) returns are the product of a deemed equity ratio of 55% and the National Energy Board (NEB) prescribed mul- tipipeline rate of return on equity. Over the last three years Enbridge (NW) System earnings have been affected by a declining rate base and reductions in the allowed rate of return on equity to 9.58% in 1999 from 10.21% in 1998 and 10.67% in 1997. Earnings have been modestly enhanced by incen- tive cost savings. Enbridge (Athabasca) System This system delivers synthetic crude oil from the oil sands near Fort McMurray, Alberta, to Hardisty, Alberta, where it joins into the Enbridge and other pipeline systems. Contributions from this system reflect the commencement of operations in April 1999 as well as the recording of Allowance for Equity Funds used During Construction (AEDC) in 1998 and early 1999. The primary shipper has entered into a long term contract with Enbridge, com- mitting annual volumes at specified tolls over a thirty year period. The result of these arrangements is similar in substance to a tra- ditional cost of service tolling methodology and yields a return equal to the NEB’s multipipeline rate in effect at the time of the agreement. Accordingly, Enbridge recognizes earnings from this system on a cost of service basis, with any difference between recorded revenue and actual cash tolls reflected as a deferred 17 T H E E N E R G Y B R I D G E transportation revenue charge. Any deferred amounts will be recovered over the remaining years of the contract. Feeder Pipelines and Other Earnings from the feeder pipeline systems which connect with the main pipeline system have remained stable over the three year period, despite a growing contribution from the 44% owned Frontier Pipeline which transports crude oil from Casper, Wyoming, to Salt Lake City, Utah. Operating Results Liquids Pipelines (Canadian dollars in millions) Operating Revenue Power Costs Operating and Administrative Expenses Depreciation Operating Income Investment and Other Income Interest Expense Earnings Before Income Taxes Income Taxes Earnings 1999 1998 1997 599.5 (67.5) (168.1) (115.5) 248.4 52.9 (88.4) 212.9 (47.6) 495.4 (82.3) (152.4) (87.0) 173.7 73.8 (62.0) 185.5 (42.3) 511.4 (83.3) (147.1) (85.8) 195.2 37.8 (66.6) 166.4 (58.0) 165.3 143.2 108.4 Operating revenue in 1999 increased over 1998 levels due to the full year operating impact of SEP II as well as the com- mencement of deliveries resulting from the completion of Phase I of the Terrace expansion, the second quarter rever- sal of Line 9 and commissioning of the Athabasca Pipeline. Although there was lower throughput through the mainline system during the year, revenues are effectively volume neutral in that under the ITA revenues associated with such volumet- ric shortfalls will be recovered in the following year through higher tolls. 1998 revenues were lower than 1997 due to the impact of prior years’ income tax recoveries refunded to the shippers through lower tolls. Also contributing to the decline in 1998 was a reduced rate of return and lower rate base on the Enbridge (NW) System. Despite pipeline expansions and project completions, more efficient power usage on the various lines as well as lower throughput in 1999 resulted in a reduction in power costs. Increases in other operating and administrative expenses, par- ticularly in 1999, are a result of higher activity levels associated with new pipelines, Year 2000 remediation costs and general inflation. Depreciation expense has also increased reflecting system expansions and additions. Investment and other income reflects AEDC as well as equity earnings from the Partnership and U.S. feeder pipelines. The higher level in 1998 is attributable to the level of construction activity and a pretax $16 million gain on the settlement of an insurance claim outstanding since 1991. Interest expense increased in 1999 as a result of the com- missioning of various pipeline expansions and additions. In 1998, during the construction phase, related interest expense was capitalized as part of the cost of construction. Income tax expense as a percentage of pretax earnings was 22.3%, 22.8%, and 34.9% for each of 1999, 1998 and 1997, respectively. Generally these rates are lower than the expected Canadian statutory rates as AEDC and equity earnings from investments are non taxable items. Additionally, the use of flow through tax accounting under which only current tax expense is recorded can result in lower effective tax rates, par- ticularly during periods of expansion when current tax deduction levels are high. Gas Distribution The Gas Distribution segment includes Enbridge Consumers Gas and related utilities as well as the Corporation’s 32% interest in Noverco acquired in mid 1997 and the new fran- chise awarded to Enbridge Gas New Brunswick in September 1999. The combined segmented and operating results for this division are shown below: Combined Segmented and Operating Results Gas Distribution (Canadian dollars in millions) Enbridge Consumers Gas and Related Utilities Gas Sales Gas Costs Gas Sales Margin Transportation Revenue Net Gas Distribution Revenue Other Revenue Net Revenue Operating and Administrative Expenses Depreciation Other Income Interest Expense Income Taxes Noverco Earnings 1999 1998 1997 1,368.5 1,411.5 1,763.4 (860.4) (1,035.9) (897.5) 471.0 224.7 695.7 272.8 968.5 (390.0) (238.1) 19.2 (184.4) (93.6) 81.6 17.6 99.2 551.1 130.5 681.6 242.1 923.7 (363.9) (215.0) 7.7 (176.5) (93.5) 82.5 17.7 727.5 25.9 753.4 210.9 964.3 (370.7) (185.8) 4.6 (164.1) (123.1) 125.2 6.9 100.2 132.1 18 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Enbridge Consumers Gas Approved Rate Base (millions of dollars) 3 8 2 3 , 9 5 0 3 , * 6 0 8 2 , 1 3 8 2 , 2 0 6 2 , Enbridge Consumers Gas Approved Return on Common Equity (%) 5 7 8 1 1 . . 5 1 1 . 3 0 1 3 7 9 . 1 5 9 . 97 96 00 98 * After unbundling of assets in 1999 99 96 97 98 99 00 Enbridge Consumers Gas Degree Day Deficiency (degrees Celsius) 9 0 2 4 , 8 5 0 4 , 1 1 0 4 , 3 0 0 4 , 9 7 0 4 , 2 5 3 3 , 0 6 0 4 , 0 6 4 3 , 96 97 Forecast 98 99 Actual Enbridge Consumers Gas Enbridge Consumers Gas is a rate of return regulated natural gas distribution utility serving approximately 1.5 million cus- tomers in central and eastern Ontario. The Ontario Energy Board (OEB) sets rates based upon a deemed capital struc- ture, an allowed rate of return on common equity, an approved rate base and costs expected to be incurred by the utility assuming normal weather. As customers are billed on an actual volume basis, the utility’s ability to recover the allowed rate of return depends upon achieving the forecast distribution volumes under “normal weather” conditions. Other differences in realized returns may result from variances between OEB approved and actual capital expenditures, operating expenses, interest expense, and income taxes. Enbridge Consumers Gas’ 1999 earnings were consistent with 1998, both years significantly below 1997 results. In the past two years the utility’s franchise area experienced significantly warmer than normal weather, resulting in lower than expected sendout volumes. Degree days 1, which represent a measure of coldness in the franchise area, were 3,460 in 1999, 15% lower than the expected 4,060. Similarly, in 1998, degree days were 3,352 or 18% lower than the expected 4,079. Actual degree days of 4,011 in 1997 approximated the normal expected level. 1 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. The Corporation estimates that the significantly warmer than normal weather resulted in a reduction of earnings of approx- imately $31 million in 1999 and $40 million in 1998. In response, in each year, the Corporation implemented a variety of cost reduction initiatives, operational efficiencies and other corporate actions across the Enbridge group of companies to mitigate a large portion of the warm weather impact on con- solidated results. Since 1998, the utility’s annual change in allowed rate of return has been based upon the forecast change in yield on Cana- dian Government long term bonds. Reflecting the general year over year reduction in Canadian interest rates in both 1998 and 1999, the allowed rate of return on common equity has also been in decline. For the 1999 fiscal year, Enbridge Con- sumers Gas’ allowed rate of return was 9.51% (1998 – 10.3%; 1997 – 11.5%) on a deemed 35% equity component of a rate base of $3,283 million (1998 – $3,059 million; 1997 – $2,831 million). The impact of these reductions in the allowed rate of return has partially been offset by rate base growth. The increase in rate base over the last three years reflects the continued popularity of natural gas among homeowners and builders, due to its relative price advantage and environmen- tal benefits over other forms of energy. Enbridge Consumers Gas has increased its active customer base by approximately 159,000 customers since the beginning of 1997, including approximately 52,000 in 1999. The actual number of new con- nections to the system in 1999 was approximately 58,000. 19 T H E E N E R G Y B R I D G E Combined Gas Utilities Volume of Gas Distributed (billions of cubic feet) 9 2 4 8 2 4 1 9 3 7 9 3 2 0 4 Combined Gas Utilities Number of Active Customers (thousands) 6 6 4 1 , 4 1 4 1 , 2 6 3 1 , 7 0 3 1 , 4 6 2 1 , 95 96 97 98 99 95 96 97 98 99 The impact of recent weather patterns has been reflected in net gas distribution revenue with 1999 showing a marginal improvement over 1998 due to slightly colder weather, but a significant decline from 1997’s normal weather. Gas sales rep- resent revenue earned for commodity cost and delivery directly to the customer. The decline in 1999 and 1998 is attributable to both lower volumes due to weather and a shift in customer demand for transportation service only. Partially offsetting these reductions were increasing gas prices, which are passed directly to customers. Transportation revenue represents amounts earned from third party marketers using the utility’s facilities to deliver direct-sell natural gas to customers. The shift between these types of services does not impact net gas distribution revenue as the difference equals the cost of gas purchased which is passed on to the customer. Combined gas sale and transportation service sendout volumes for the last three years amounted to 402 billion cubic feet (bcf), 397 bcf and 428 bcf in 1999, 1998 and 1997, respectively. The year over year increase in other revenue is due to con- tinued growth in ancillary programs (rentals, merchandising, extended service products, merchandise finance plan, natural gas vehicles, and agent billing collection). Operating and administrative expenses include costs for the utility and ancillary programs. The increase in 1999 is due to 20 higher costs associated with serving an expanding customer base, growth in the ancillary programs, branding costs and Year 2000 remediation costs, partly offset by continued cost reduction initiatives. The decrease in 1998 expenses com- pared with 1997 was mainly due to warmer weather, the introduction of cost recovery and reduction measures, pro- ductivity initiatives, and the absence of corporate reorganization costs incurred in 1997. Consistent with the growth in rate base and customer portfo- lio size, depreciation expense has increased each year since 1997. Additional borrowings required to finance the growing investment in property, plant and equipment have resulted in increasing interest expense. Income taxes, which are recorded on a flow through basis, have declined in the past two years essentially as a result of lower pretax earnings. Over the three year period the effective tax rate has remained comparable. Noverco Noverco Inc. is a holding company whose principal asset is a 77% interest in Gaz Métropolitain and Company, Limited Part- nership that is engaged in natural gas distribution in Quebec and Vermont. Variations from normal weather have no effect on Noverco’s earnings as the Quebec regulator holds utilities weather neutral. Equity earnings from Noverco reflect the Corporation’s 32% equity interest adjusted for the effect of Noverco’s 10% reci- procal shareholding in Enbridge and the amortization of the excess of the purchase price paid over the underlying net book value of the assets. However, a substantial portion of the earn- ings from Noverco comprises dividends from the Corporation’s $181.4 million investment in the preference shares of Noverco. These shares entitle the Corporation to a cumulative dividend based on the yield of 10 year Government of Canada bonds plus 4.45%. The weighted average yield on the prefer- ence shares, which is reset annually, was 10.0% and 10.6% for 1999 and 1998, respectively. International International earnings represent income from the Corpora- tion’s U.S. dollar denominated investment in the OCENSA Pipeline in Colombia which commenced operations in 1998 and fees earned as operator of the Jose Terminal in Venezuela. The Corporation also generates earnings from its international technology and consulting services. E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Segmented Results International (Canadian dollars in millions) OCENSA Pipeline Jose Terminal Enbridge Technology Business Development Costs Earnings 1999 1998 1997 24.0 6.3 0.8 (2.4) 28.7 24.8 — 2.4 (2.9) 24.3 18.5 — (0.1) (2.3) 16.1 Enbridge earns a pre-established fixed rate of return on its OCENSA investment and also acts as joint operator earning operating and incentive fees. The increase in earnings com- pared with 1997 reflects a higher average level of investment due to completion of construction. An agreement to acquire a 45% interest in the U.S. $385 million Jose Terminal in Venezuela, signed in early 1999 is pending receipt of final assent from the Venezuelan Govern- ment. For the intervening period, PDVSA Petroleos y Gas, S.A., the current owner of the Terminal, has engaged Enbridge and its partners to operate the Terminal. During 1999, Enbridge earned $6.3 million in net fees for operating the Terminal. The 1999 decline in earnings from Enbridge Technology rep- resents the completion of a consulting contract in Mexico. Operating Results International (Canadian dollars in millions) Operating Revenue Expenses Other Income Income Tax (Expense) Recovery Earnings 1999 1998 1997 24.0 (16.1) 23.6 (2.8) 16.0 (17.9) 26.3 (0.1) 6.6 (10.8) 19.4 0.9 28.7 24.3 16.1 Operating revenue is comprised primarily of consulting fees for the automation and modernization of the Mexican national crude oil and refined products pipeline system. This contract which com- menced in 1998 was completed in 1999. Revenues in 1999 also include fees derived as contract operator of the Jose Terminal. Operating costs, include the cost of providing consulting ser- vices in Mexico as well as new business development activities. Included in other income are returns on the investment in the OCENSA pipeline and certain related operating fees and incen- tive distributions. OCENSA returns are received on a net of tax basis, with no additional tax exigible at the Enbridge level. Income tax expenses in 1999 relate to Venezuelan taxes on fees earned from the Jose Terminal project. Gas Pipelines and New Business Development This segment’s results include equity income in respect of the Corporation’s ownership interests in the Alliance Pipeline Project (21.4%) and the Vector Pipeline Project (45%), both of which are currently under construction with anticipated com- missioning in late 2000. Alliance is a $5.0 billion project that will transport natural gas from Fort St. John, British Columbia, to Chicago, Illinois. Vector is a US $0.5 billion project that will transport natural gas between Chicago and Dawn, Ontario. The segment also includes the Corporation’s 40% equity inter- est in AltaGas Services Inc., which provides natural gas gathering, processing and related services as well as natural gas transmission and distribution in Alberta. Other new business initiatives include an electrical utility serving the community of Cornwall, Ontario, and the 33 1/3% owned Inuvik gas distribution utility located in Inuvik, N.W.T. Segmented Results Gas Pipelines and New Business Development (Canadian dollars in millions) Alliance Pipeline Project Vector Pipeline Project AltaGas Services Inc. Other New Business Initiatives and Development Costs Earnings 1999 1998 1997 27.7 5.5 2.0 (4.0) 31.2 8.6 1.4 — (3.7) 6.3 0.7 — — (3.1) (2.4) Increases in earnings of Alliance and Vector are in line with higher rate bases earning AEDC as construction progresses. Earnings from AltaGas represent equity income since the third quarter 1999 acquisition. Operating Results Gas Pipelines and New Business Development (Canadian dollars in millions) Operating Revenue Operating and Administrative Expenses Depreciation Other Income Interest Expense Income Tax Recovery Earnings 1999 1998 1997 54.8 (56.7) (5.1) 30.6 (0.3) 7.9 31.2 24.8 (28.9) (2.6) 7.4 0.6 5.0 6.3 1.2 (7.7) — 1.0 — 3.1 (2.4) 21 T H E E N E R G Y B R I D G E Operating revenue, operating and administrative expenses and depreciation expense are principally derived from Cornwall Elec- tric, purchased in mid 1998, and other small new business initiatives. Amounts in 1999 and 1998 have increased over prior years commensurate with the timing of the inclusion of these operations. Other income mainly represents equity earnings from the Alliance, Vector and AltaGas investments. Income tax recovery is principally related to initial operating losses on various new business initiatives. Energy Services The Energy Services segment primarily reflects the Corpora- tion’s initiative to provide integrated energy products and services to retail and commercial customers in Ontario, British Columbia and Philadelphia, Pennsylvania. Commenc- ing in the fourth quarter of 1999, the ancillary programs unbundled from Enbridge Consumers Gas have also been included in this segment. Operating Results Energy Services (Canadian dollars in millions) Operating Revenue Operating and Administrative Expenses Depreciation Interest Expense Income Tax Recovery Earnings 1999 1998 1997 143.4 (116.7) (21.7) (7.9) 0.4 21.4 (28.9) (1.5) (1.4) 4.2 0.6 (14.1) (0.1) — 6.1 (2.5) (6.2) (7.5) In accordance with determinations of the OEB, on October 1, 1999, the Corporation separated and removed (unbundled) ancil- lary business activities from the regulated operations of Enbridge Consumers Gas into a wholly owned subsidiary of Enbridge in the unregulated Energy Services segment. Major components of this transaction were the water heater and furnace rental program, merchandise financing operations, merchandise retail- ing and related services. These operations are now reported on a calendar year rather than the quarter lagged September 30 year end of Enbridge Consumers Gas. As a result, a one time additional quarter of earnings (approximately $7 million) was included in the transition year of 1999 for these operations. In anticipation of unbundling, the Ontario operations contin- ued the development of other retail and commercial service and product offerings. This was accomplished through the acquisition of four retail appliance stores and four service providers in late 1998 as well as the development of a south- ern Ontario franchise alliance of service providers under the Enbridge brand. Markets in which the acquired service providers operate include the sales, installation and support for heating, ventilation and air conditioning products, fireplaces, and appliances as well as plumbing and electrical services. Historically, these markets have been characterized by numerous small regional operators; however, in recent years several aggregators have been acquir- ing these operators to capitalize on synergies and brand loyalty. Despite the high competition for potential acquisitions in its fran- chise area, Enbridge believes it is prudent to take a measured approach and has consistently applied its economic criteria, which has resulted in slower than anticipated expansion of operations. Management believes that, in the longer term, this measured approach will translate into better economic returns. Corporate and Other The net cost for Corporate and Other items includes activi- ties such as general corporate investments and costs associated with financing non regulated activities. These costs can be summarized as follows: Corporate and Other (Canadian dollars in millions) Operating and Administrative Expenses Depreciation Investment and Other Income Interest Expense Loss Before Undernoted Income Tax Recovery Loss Preferred Securities Distributions Preferred Share Dividends 1999 1998 1997 (12.5) (3.1) 44.8 (99.5) (70.3) 48.2 (22.1) (5.0) (6.9) (5.5) (2.7) 23.5 (73.6) (58.3) 31.4 (26.9) — — (5.3) (2.2) 6.8 (45.4) (46.1) 16.7 (29.4) — — Net Cost (34.0) (26.9) (29.4) Operating and administrative expenses increased in 1999, reflecting centralization of certain business activities and general corporate costs such as branding the Enbridge name and Year 2000 remediation. The increase in investment and other income in 1999 reflects investment income from higher average cash balances and an $18.2 million ($11.5 million after tax) dilution gain realized from the Corporation’s investment in the U.S. pipeline operations. The 1998 investment and other income also included $13.5 million ($8.0 million after tax) of one time gains in 1998 associated with the sale of non strategic real estate and recoveries under a financing arrangement. In 1997, higher corporate provisions commensurate with the Corporation’s significant growth initia- tives effectively offset a dilution gain of $16.3 million recorded on the Corporation’s investment in the U.S. Partnership. 22 The substantial rise in interest expense over the last three years as well as preferred security distributions and preferred share dividends accrued in 1999 reflect the impact of financ- ing incurred to fund acquisitions and investments. Capital Expenditures, Investments and Acquisitions (millions of dollars) Income tax recoveries have increased over the three years in line with the higher level of interest expense and other costs. LIQUIDITY AND CAPITAL RESOURCES The Corporation’s cash generated from operations combined with continuous access to capital markets in Canada and the United States plus approximately $2.0 billion in unutilized credit facilities provide sufficient resources to finance growth opportunities, debt repayments and dividend distributions. (For a further description of the Corporation’s committed and uncommitted credit facilities, reference should be made to Note 10 to the Consolidated Financial Statements.) . 5 5 4 6 1 , . 8 9 8 0 1 , . 2 1 4 1 1 , 1999 1998 1997 97 98 99 Operating Activities Summary of Cash Flows (Canadian dollars in millions) Cash Provided from Operating Activities Earnings plus charges (credits) not affecting cash Changes in operating assets 626.9 490.4 486.9 and liabilities (131.8) (178.0) (49.1) Cash Used in Investing Activities Investments and acquisitions Capital expenditures Changes in construction payables and other Cash Provided from Financing Activities Debt issued (net) Non controlling interest preference shares Preferred securities Preferred shares Common shares Preferred share and security distributions Common share dividends 495.1 312.4 437.8 (257.1) (357.5) (783.7) (1,388.4) (438.4) (651.4) (64.5) 55.1 30.9 (1,205.7) (1,590.4) (1,058.9) 388.8 1,178.6 490.1 100.0 338.5 — 10.3 — — 123.3 218.0 — — — 315.6 (11.9) (186.4) — (168.3) — (147.1) 639.3 1,351.6 658.6 Increase (Decrease) in Cash (71.3) 73.6 37.5 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T By Business Segment Liquids Pipelines Gas Distribution Gas Pipelines Other 1999 380.7 365.4 341.8 53.3 1998 1,009.9 400.6 204.4 30.6 1997 221.6 748.8 38.8 80.6 1,141.2 1,645.5 1,089.8 Cash provided from operating activities increased in 1999 pri- marily as a result of the commencement of operations of SEP II, Terrace and Athabasca pipelines as well as lower current tax expense, the latter resulting from high tax deductions associated with recent capital additions. Funding requirements for operating assets and liabilities were lower in 1999 due to the reduced level of acquisitions, asset additions and long term investments. Investing Activities Cash used in investing activities in 1999 was $1.2 billion, 24% lower than 1998 but 14% over 1997. This reflects the Cor- poration’s strong growth in a changing North American energy delivery and services market. Expenditures related to system expansions in Liquids Pipelines and Gas Pipelines, combined with ongoing improvements and replacement of existing facilities in Gas Distribution, accounted for the large increase in the level of capital investments over the last three years. In 1999, the Liquids Pipelines segment incurred capital expenditures related to the construction of the Enbridge (Athabasca) Pipeline ($160.3 million), Phase I of the Terrace expansion ($119.4 million) and Line 9 Reversal ($18.0 million). In 1998, amounts were similarly spent on con- struction of Athabasca ($266.7 million), Terrace ($481.1 23 T H E E N E R G Y B R I D G E million) and the Canadian leg of SEP II ($58.8 million). Capital expenditures in 1997 primarily related to SEP II and the first phase of the System Expansion Program. Gas Distribution capital expenditures remained relatively constant over each of the three years averaging approximately $400 million per year, representing the continuous growth in the customer base. In 1999, other segments incurred a total of $43.8 million (1998 – $11.2 million; 1997 – $20.7 million) of capital expenditures, principally in relation to the expansion of Energy Services operations and infrastructure costs of new business activities such as Cornwall Electric. Expenditures on long term investments in 1999 reflected investments in Alliance Pipeline Project of $138.0 million (1998 – $105.4 million; 1997 – $30.5 million) and $24.6 million (1998 – $23.0 million) in the Vector Pipeline Project. During 1999, the Corporation acquired an approximate 40% interest in AltaGas for $163.8 million. In 1998 the Corpora- tion invested U.S.$2.5 million (1997 – U.S.$38.7 million) in the OCENSA Pipeline, acquired Cornwall Electric for $68 million and a 23% equity interest in the Chicap Pipe Line for $33.3 million. Included in 1997 long term investments was the purchase for $332.4 million of $181.4 million of Noverco’s preference shares and $151.0 million for 32% of its outstanding common shares. In related and subsequent transactions, the Corpo- ration has sold 15.5 million (after two for one split) of its common shares to Noverco for total proceeds of $380.4 million. As a result, Noverco’s common share interest in the Corporation was approximately 10% at December 31, 1999 and 1998 (1997 – 8%). The construction related liabilities, incurred during the signif- icant pipeline expansion period of 1997 through mid 1999, were reduced at the completion of expansions and additions accounting for the change in 1999. Financing Activities Over the three year period, the Corporation’s level of financing activities also reflected its growth and investment strategies. Funding sourced from debt or equity is determined primarily on the basis of the capital structure appropriate for each business. Certain of the Corporation’s regulated pipeline and gas distri- bution operations issue long term debt to finance capital additions, usually in the form of fixed rate debentures or medium term notes. This external financing may be supple- mented by debt or equity injections from the parent company. Debt related to non regulated activities issued at the corporate level has been incurred mainly to finance business acquisitions and investments in subsidiaries, and is supplemented with the issue of share capital. Funds for debt retirements are gener- ated through cash provided from operating activities, as well as through the issuance of replacement debt. In 1999, Liquids Pipelines issued $275 million of medium term notes (MTN) to finance system expansions and the repayment of $85 million of MTNs, $40 million of debentures and $48 million of variable rate financing. Gas Distribution replaced $53 million in MTNs and matured debentures, reduced its short term borrowings by $245 million, and redeemed $100 million in preference shares. The preference shares were replaced with the issuance of $100 million in new redeemable preference shares. As these shares are not redeemable at the option of the holder and only participate in the earnings of Enbridge Consumers Gas, they have been considered a non controlling (minority) interest ownership in the Consolidated Financial Statements. Also during 1999, the Corporation issued $200 million in MTNs and $497 million in variable rate financing (net) in order to finance non regulated and new corporate ventures. To opti- mize the Corporation’s cost of capital and diversify the mix of capital funding sources, the Corporation also issued $350 million in Preferred Securities. These Securities are unsecured junior subordinated instruments that may be redeemed at the Corporation’s option in whole or in part after five years. The Corporation has the right to defer, subject to certain condi- tions, distributions on the Securities for a period of up to 20 consecutive quarterly periods. Such deferred distribution amounts are payable in cash, or at the option of the Corpo- ration, from the proceeds on the sale of equity securities delivered to the trustee of the Securities. As such, under Cana- dian GAAP the securities are apportioned between their debt and equity elements in the statement of financial position, with the debt portion approximating the present value of the 49 year maturity amount. The Corporation has made cash pay- ments with respect to distributions since the date of issuance. In 1998, Liquids Pipelines issued $200 million of MTNs and $73 million of variable rate financing (net) to finance expan- sions of the pipeline system. Minor sinking fund repayments of $22 million were also made in the year. Gas Distribution replaced maturing long term obligations and sinking fund 24 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T payments of approximately $260 million and funded asset growth with the issuance of $595 million of MTNs. To fund Cor- porate investments, bridging of pipeline construction activities and the maturing of $125 million of long term obligations, the Corporation issued $400 million of MTNs and approxi- mately $326 million of variable rate financing (net). During 1997, Liquids Pipelines issued $50 million in MTNs and an additional $62 million in variable rate financing (net) to support capacity expansions of the pipeline system and meet debt maturity obligations of $21 million. Consistent with its large capital expenditure program and to replace matur- ing long term obligations of approximately $70 million, Gas Distribution issued $200 million of MTNs and effectively con- verted (through the use of long term interest rate swaps) approximately $100 million of short term borrowings into medium term debt maturing in 2002. Finally, to fund Corpo- rate investment activities, the Corporation issued $155 million of variable rate financing and $100 million of MTNs. As at December 31, 1999 (following a May 10, 1999 two for one stock split), the number of common shares outstanding had grown to 156.3 million shares from 135.0 million shares (after split) at the beginning of 1997. In addition to the common shares issued to Noverco in 1997 and 1998 ($380 million), Enbridge has raised approximately $296 million of equity in the three year period, including a $115 million public offering of treasury common shares in October 1998. Also included in this amount is a $125 million public offering of preferred shares made in December 1998, $7.1 million in common shares issued in conjunction with the AltaGas acquisition and contri- butions of $38.4 million from the Corporation’s Dividend Reinvestment and Share Purchase Plan. Common share dividends paid over the past three years have reflected a growing regular quarterly dividend on an increas- ing number of common shares. FINANCIAL RISK EXPOSURE AND MANAGEMENT Earnings, cash flow and customers’ rates are subject to volatil- ity stemming mainly from movements in the U.S./Canadian dollar exchange rate, the price of natural gas, and interest rates. In order to minimize these risks for both its ratepayers and shareholders, the Corporation utilizes a variety of hedging instruments to create an offsetting position to specific expo- sures. All of these instruments are employed in connection with an underlying asset, liability or anticipated transaction, and are not used for speculative purposes. In implementing its hedging programs, the Corporation has established formal analysis and execution procedures, which require the prior approval of either the Board of Directors or a committee of senior management. Ongoing monitoring and senior man- agement reporting procedures with respect to the hedging programs are in place. Foreign Exchange In 1997, the Corporation established a hedging program to eliminate 80% to 100% of the long term exposure relating to U.S. dollar denominated investments. At year end 1999, the Corporation had hedged future cash flows of approximately U.S.$39 million per annum (1998 – U.S.$39 million; 1997 – U.S.$30 million) as well as U.S.$100 million (1998 and 1997 – U.S.$100 million) on the redemption of the Corporation’s investment in Colombia, thereby mitigating potential currency exposures on anticipated cash flows from, and redemption of, these U.S. dollar investments. Natural Gas Prices As allowed under the regulatory framework governing the Cor- poration’s natural gas distribution operations, the Corporation hedges the cost of a portion of its future natural gas supply requirements. At December 31, 1999, approximately 10% of its forecast fiscal 2000 system gas supply requirements, or 18 billion cubic feet, was hedged. As the cost of natural gas ultimately flows through to customers in the form of regulated gas costs, the customer realizes the results of this risk miti- gation strategy. The OEB monitors the policies, procedures and results of this hedging program. Interest Costs To hedge against the effect of future interest rate movements on certain of its short term and long term borrowing require- ments, the Corporation enters into various interest related hedging instruments. As at December 31, 1999, the Corpora- tion had effectively fixed interest rates on $696.3 million of variable rate debt through floating to fixed interest rate swaps. In anticipation of future debt issuances related to specific com- mitted capital projects, the Corporation enters into financial contracts to hedge a portion of the interest cost associated with the anticipated issues. 25 T H E E N E R G Y B R I D G E A detailed description and analysis of these transactions, includ- ing the duration, carrying amounts and current valuations are included in Note 13 to the Consolidated Financial Statements. At December 31, 1999, no material credit risk exposure existed as the Corporation enters into off balance sheet risk management transactions only with creditworthy institutions that possess strong investment grade ratings or where such transactions are secured with approved forms of collateral. Additionally, as the Corporation did not settle hedging instru- ments in advance of the hedged transactions, there were no gains or losses deferred in relation to any of the Corporation’s off balance sheet hedges of anticipated transactions at December 31, 1999 and 1998. FUTURE PROSPECTS When used in this section, the words “believe”, “estimate”, “fore- cast”, “anticipate”, “expect”, “project” and similar expressions are intended to identify forward looking statements. Such state- ments are subject to certain risks, uncertainties and assumptions pertaining to operating performance, regulatory parameters, weather, economic conditions, etc. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. Enbridge expects continued earnings growth as a result of the full year impact of 1999 pipeline expansions, investments and acquisitions. These activities, along with the benefits of Per- formance Based Regulation (PBR) in Ontario, the extension of the Pipeline Incentive Tolling Agreement (ITA), and opportuni- ties provided by the unbundling transaction and related shared services concept in Eastern Canada, are expected to support earnings growth patterns experienced since 1995. The 1999 recovery of crude oil prices could accelerate pipeline expan- sion opportunities, further supporting earnings growth. However, the continuation of warmer than normal weather, as experienced by Enbridge Consumers Gas in the first fiscal 2000 quarter ended December 31, 1999, may impact Gas Distribution results negatively, partially offsetting the expected earnings growth discussed above. The ongoing transformation of the Corporation into a diversi- fied energy transporter and service provider in North America and internationally, and entry into more non regulated busi- nesses, is resulting in the risk profile of the Corporation changing modestly. Entry into non regulated businesses imposes greater economic exposure and requires more “at risk” capital to be spent. This is managed by detailed analy- sis and control processes with an expectation of higher returns from these businesses. Costs related to these new activities are deferred only if there is a reasonable certainty that the outcome of the project will benefit future periods. Otherwise, provisions are made against the project costs. In addition, pro- visions are made for potential liabilities, if any, resulting from claims against the Corporation arising in the normal course of business including contested income tax reassessments. In the opinion of management, exposures in excess of the pro- visions made, if any, would not have a material effect on the financial position of the Corporation. Commodity Price Risk Enbridge’s earnings are generally insulated from the impact of fluctuations in crude oil and natural gas prices. The Liquids Pipelines segment does not take ownership of the commodi- ties transported and crude oil prices do not impact transportation charges. A sustained increase or decline in crude oil prices does have an impact, however, on exploration and production activities in Western Canada, thereby ulti- mately affecting the throughput levels on the pipeline systems. With the downside volume protection available in Canada under the ITA and the Corporation’s level of ownership in the U.S. portion of the pipeline system, the Corporation’s sensi- tivity to short term fluctuations in crude oil prices is substantially reduced. Nevertheless, in the longer term, sus- tained improved oil prices could generate pipeline expansion opportunities. With the recent improvement in crude oil prices as well as a number of industry milestones reached with oil sands developments in the Province of Alberta, the outlook for future growth and expansion opportunities remains positive. Changes in gas prices do not have an effect on regulated Gas Distribution earnings as commodity cost of gas is flowed through to customers. Prolonged high gas prices, however, could affect the economics of gas usage by customers in com- parison with alternate energy sources. Despite the recent increases in the price of natural gas, the Corporation expects that natural gas will continue to hold a price advantage over electricity in its franchise area and maintain its competitive advantage against domestic fuel oil in the residential heating market. In 1999, natural gas enjoyed, on average, a price 26 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T advantage on an equivalent annual volume basis of over 50% against electricity and approximately 20% against domestic fuel oil. It is expected that the current price advantage of natural gas will continue in the foreseeable future. Addition- ally, increasing natural gas prices will create further expansion and investment opportunities for the Corporation in gas trans- mission growth initiatives. Regulatory Developments Liquids Pipelines In 1999, Enbridge and the Canadian Association of Petroleum Producers agreed to an extension of the 1995 ITA for the Canadian mainline liquids pipelines system. The new agree- ment extends the current arrangement for another five year term commencing in 2000. It preserves the significant exist- ing benefits achieved for shippers and shareholders, and includes new features which will provide additional benefits for each. The extended agreement provides added incentives to achieve further energy savings. It also provides a $90 million investment opportunity over the next three years at the same time that shippers gain a toll surcredit. This results from an agreement to refund deferred taxes previously collected by Enbridge prior to 1992 and used to fund expansion of the pipeline. Enbridge will add the investment to its mainline rate base and will earn a rate of return on the equity portion at the prescribed NEB multipipeline rate. Gas Distribution In December 1999, the OEB released its decision on Enbridge Consumers Gas’ year 2000 Rate Application. The decision included the approval of a rate of return of 9.73% (1999 – 9.51%) on a deemed 35% equity component of rate base of $2,806 million (1999 – $3,283 million or $2,720 million excluding the rental assets portion of the unbundled assets). In the spring of 1998, in response to the changes occurring in the industry, Enbridge Consumers Gas filed an application with the OEB to separate and remove the Merchandise Sales Program, Heating Parts Replacement Plan and the non regu- lated Merchandise Finance Program, as well as certain aspects of its non emergency service activities, from the existing oper- ations of the regulated utility. On March 31, 1999, the OEB released its decision with respect to terms and conditions under which these businesses and activities could be under- taken by the utility or transferred to another Enbridge affiliate. In the March 1999 decision, the OEB denied the full recov- ery of the unrecorded deferred income taxes of $168.0 million related to the rental assets. The OEB determined that $50 million of the unrecorded deferred tax liabilities may be recov- ered in future utility rates and a further $42 million in refunds from Revenue Canada relating to a change in its assessing practice can also be applied against the liability. Enbridge Con- sumers Gas has filed an application for judicial review asking the Divisional Court, Superior Court of Justice to set aside the OEB’s order and that the matter of the deferred taxes be referred back to the OEB for a rehearing. In the absence of a full recovery, the disallowed balance of $76 million will be charged to retained earnings upon the adoption of the new income tax accounting standard. On October 1, 1999, the Corporation transferred to the Energy Services segment, not only the businesses described above but the Rental Program assets as well. The net book and fair market values of the net assets transferred were approximately $737 million. Unbundling of these businesses will leave Enbridge Consumers Gas as a core distribution utility, ready to focus on operational excellence and able to generate efficiencies which will benefit both shareholder and ratepayers. The Energy Services segment will operate these businesses independently outside of regulation, which will allow these businesses to be run more efficiently. The over- riding rationale for unbundling is that the introduction of competitive markets will improve customer choice and provide a broader opportunity for business to develop in the province. Customers are expected to benefit from value enhancing services. Recent changes in regulation reflect a trend in Canada toward incentive or performance based regulation (PBR). In April 1999, the OEB accepted Enbridge Consumers Gas’ proposed targeted PBR plan for a three year term and has encouraged Enbridge Consumers Gas to develop, in consultation with stakeholders, an appropriate comprehensive PBR plan by the end of this term. It is the OEB’s desire that this plan be based upon either revenue cap or rate cap principles. A com- prehensive plan of this nature would permit the Company to set rates within certain limits and provide flexibility to adjust prices to stay within the cap. 27 T H E E N E R G Y B R I D G E Segmented Outlook Liquids Pipelines Enbridge expects continued earnings growth from its Liquids Pipelines segment in 2000 as a result of the full year impact of expansions as well as the gradual recovery of U.S. pipeline operations to more normalized throughput levels. Phase I of Terrace, Line 9 reversal and the Athabasca Pipeline should provide greater earnings impact in 2000 as each of these systems were only effective for part of 1999. The con- tinuation of cost savings and the benefits of incentive mechanisms under the extended ITA are also expected to make a positive contribution to this segment’s earnings. Gas Distribution The earnings of Enbridge Consumers Gas will be reduced in 2000 by the impact of the intersegment shift of the unbun- dled assets to the Energy Services division. However, the year 2000 utility earnings of Enbridge Consumers Gas will benefit from an otherwise higher rate base as well as an increased allowed rate of return. Furthermore, a return to normal weather patterns in the franchise area and the anticipated benefits to be realized under the new PBR enhance the earnings poten- tial of this segment. These anticipated improvements could be hampered by the continuation of warmer than normal weather experienced in the quarter ended December 31, 1999 which represents the first fiscal quarter of Enbridge Con- sumers Gas for the year 2000. The degree days in this quarter, although 3% colder than the same quarter last year, were approximately 10% lower than normal. The Corporation is unable to predict whether these weather patterns are indica- tive of the balance of fiscal 2000. In that customers are billed on a volume basis, the Corpora- tion’s ability to recover its total revenue requirement (i.e., the cost of providing service) depends on achieving the forecast distribution volumes established in the rate making process. Weather during the year has a significant impact on sales to and transportation of gas for customers in the higher margin residential and commercial markets (which account for approx- imately two-thirds of total distribution volumes) as the majority of gas distributed to these markets is ultimately used for space heating. Sales and transportation service to large volume commercial and industrial customers are more sus- ceptible to the prevailing economic conditions, including the price of competitive energy sources for those customers who have the ability to switch to alternate fuels. Customer addi- tions are important to all market sectors as expansion adds to the overall consumption of natural gas. Earnings from Noverco are primarily derived from Enbridge’s preferred share holdings that are anticipated to yield after tax returns of approximately 10%. Following the receipt of the natural gas distribution franchise rights within the Province of New Brunswick in 1999, the Cor- poration anticipates recording of AEDC amounts on ongoing construction costs. International Earnings contribution from this segment will remain sensi- tive to the timing of the completion of the acquisition of the 45% interest in the U.S.$385 million Venezuelan Jose Termi- nal. For the intervening period, Enbridge and its partners will continue operating the Terminal and earn operating fees. In the absence of a successful closing of the acquisition, the operating results of the International segment are expected to remain relatively consistent in 2000. Gas Pipelines and New Business Development Construction on the 21.4% owned Alliance Pipeline Project com- menced in 1999. The investment is accounted for using the equity method. The pipeline component, which represents approximately 88% of the expected capital costs, will contribute significant earnings through AEDC earned on the increased investment levels through to scheduled commissioning during the fourth quarter of 2000. Equity earnings during the fourth quarter and thereafter will reflect the pipeline’s contractually established rate of return of approximately 11%. The Natural Gas Liquids (NGLs) extraction plant component of the project will not contribute to earnings until start up in the fourth quarter of 2000. Based upon the current relationship between prices for natural gas and NGLs, the plant would generate very attrac- tive profit levels, but this relationship is not expected to remain as favorable in the future. Similarly, the Vector Pipeline Project commenced construction in January 2000 and anticipates operations to commence in late 2000. Again, increasing amounts of AEDC are expected to be booked in 2000 in concert with this increasing investment. The Alliance and Vector Pipelines have planned delivery capac- ities of 1.3 billion and 1.0 billion cubic feet per day, respectively. Enbridge has committed 105 million and 260 million cubic feet 28 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T per day of these capacities, respectively, of which a substan- tial portion will be utilized to satisfy Enbridge Consumers Gas’ delivery requirements. Over the next two to four years, the remaining capacities committed by Enbridge are expected to be fully contracted out. However, during the initial period the earnings from these projects may be reduced by toll discounts and/or partially utilized capacity. This segment’s earnings are also anticipated to benefit in 2000 from a full year earnings contribution from the 40% investment in AltaGas Services Inc. acquired during the third quarter of 1999. Energy Services With the October 1, 1999 transfer of the unbundled assets from the rate regulated operations of Enbridge Consumers Gas, this segment’s earnings are expected to increase sub- stantially in 2000. Based on current performance levels, the intersegment shift in earnings is expected to be approximately $30 million. The unbundled programs are now free to operate without reg- ulatory constraints on rates of return that are applicable to a gas distribution utility. To the extent that Energy Services can continue to grow this business on a cost efficient basis and utilize the existing market to further sell energy products and services, increases in earnings are expected over the next few years. A key to this growth will be the retention of existing and the capture of additional customers. System problems associated with the transfer of responsibilities from the utility to this divi- sion resulted in service disruptions. Although, these problems have been rectified and Enbridge does not believe that long term damage to its customer relationships has occurred, there does exist a high level of competition for customer loyalty. Consistent with this customer focus, Energy Services will be re-examining its market segments to ensure that it is provid- ing appropriate product offerings in its key target markets. Capital and Investment Expenditures The Corporation expects to incur capital and investment expen- ditures of $800–$900 million in 2000. Approximately, half of these expenditures will be incurred in its core operations par- ticularly for the expanding customer base in Ontario. With the exception of routine maintenance and enhancement programs for the Liquids Pipelines division, no major expansions are cur- rently anticipated. Nevertheless, the Corporation’s long term outlook for the second and third phases of the Terrace Expan- sion Program remains positive. The remainder of the anticipated expenditures will occur as the construction of Alliance and Vector Pipeline Projects continue. These anticipated levels of capital expenditures do not reflect any funds required for new acquisi- tions or joint venture investments. The Corporation’s cash generated from operations in combination with its ability to main- tain access to capital markets in Canada and the United States along with its substantial unutilized credit facilities will provide sufficient resources to finance the planned as well as any new growth opportunities. Year 2000 Issue The Corporation entered the new millennium with no signifi- cant Year 2000 related problems or service disruptions reported by its business units or affiliated companies in North America and internationally. The Corporation will continue mon- itoring its energy distribution and transmission systems as well as information technology and equipment for potential date sensitive issues in 2000. To the end of December 31, 1999, the Corporation had incurred $33 million of operating and $13 million of capital costs for Year 2000 remediation and business continuity initiatives. As a result of fewer than anticipated remediation issues, actual costs of the project have been substantially below budgeted costs of $60 million. In addition to having successfully rolled over the operations into the new millennium, management expects longer term bene- fits and efficiencies being realized from its Year 2000 Readiness Program. These benefits include substantial infor- mation technology upgrades and the elimination of redundant systems; completion of detailed and comprehensive listings of hardware and software systems; and, enhancement of the Cor- poration’s emergency response and disaster recovery plans. Sensitivities The following sensitivities are presented net of the effect of Enbridge’s hedging activities. The Corporation estimates that a 1% change in interest rates results in a $4 million change in earnings and cash flow from operations. As a result of the Corporation’s foreign exchange hedging program, there are no material sensitivities to exchange rate fluctuations. 29 T H E E N E R G Y B R I D G E By virtue of the regulatory environment in which the Gas Dis- tribution segment operates, the Corporation’s natural gas distribution operations have regulatory mechanisms in place which provide for recovery of any increase in the price of natural gas provided that gas procurement is undertaken on a prudent basis, which the Corporation believes it consistently does. Liquids Pipelines exposure to changes in crude oil and natural gas liquid prices is limited to system utilization impacts as the Corporation does not physically own the commodities it transports. Based upon results for the last two year period, a 20 degree day deficiency has correlated to approximately $1 million in earnings variance to the gas utility. However, due to the numer- ous variables that impact earnings on a go forward basis, this sensitivity may not be indicative of future impacts. Accounting Pronouncements Effective January 1, 2000, the Corporation is required to adopt two new Canadian accounting standards. The new CICA Section 3465 — Income Taxes requires a focus on future income tax assets and liabilities on a company’s balance sheet (liability method) as opposed to a focus on the deferred tax provision recorded in an entity’s income statement (deferral method). The accounting standard permits rate regulated operations an exemption from the application of the standard, meaning that a significant portion of the Corporation’s operations will not be required to adopt the new standard. These operations will remain on the flow through method of accounting, which reflects only actual income taxes payable as an expense. With respect to business acquisitions, the Standard requires tax effects of differences between the assigned and underlying tax values of the identifiable net assets acquired to be recorded as future income tax assets or liabilities and included in the allocation of the cost of the purchase. Additionally, the tax effects of dif- ferences between the carrying amount of an equity investment and its tax basis must be recorded as a future income tax asset or liability. Finally, Enbridge will also recognize the previously unrecorded income tax liabilities associated with unbundling and other deregulated assets. The combined impact of these items will be an estimated net charge to Retained Earnings of approximately $93 million effective January 1, 2000. The new CICA Section 3461 — Employee Future Benefits requires the Corporation to adopt an accrual method of accounting for all employee future benefits, including pensions and post employment medical and dental benefits. Given that the Liquids Pipelines division is already required by regulators to accrue for postretirement benefits in the United States and pension costs in both Canada and the United States, and due to the regulatory nature of Gas Distribution operations, the Corporation anticipates that the implementation of this Stan- dard will not have a material impact on its consolidated results of operations and financial position. 30 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Management’s Report 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 Corporation. The Audit, Finance & Risk Committee of the Board, composed of directors who are not officers or employees of the Corporation, 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 Corporation’s independent auditors, conducts an examination of the consolidated financial statements in accordance with Canadian generally accepted auditing standards. B.F. MacNeill President & Chief Executive Officer D.P. Truswell Senior Vice President & Chief Financial Officer Auditors’ Report To the Shareholders of Enbridge Inc. We have audited the consolidated statements of financial position of Enbridge Inc. as at December 31, 1999 and 1998 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 1999. 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 Corporation as at December 31, 1999 and 1998 and the results of its operations and cash flows for each of the years in the three year period ended December 31, 1999 in accordance with Canadian generally accepted accounting principles. Calgary, Alberta, Canada January 14, 2000 (PricewaterhouseCoopers LLP) Chartered Accountants 31 T H E E N E R G Y B R I D G E Consolidated Statement Of Earnings (Canadian dollars in millions, except per share amounts) Year ended December 31, 1999 1998 1997 Operating Revenue Gas sales Transportation Energy services and other Expenses Gas costs Operating and administrative Depreciation Operating Income Investment and Other Income (Note 3) Interest Expense (Note 4) Earnings Before Undernoted Income Taxes (Note 5) Earnings Preferred Security Distributions (Note 11) Preferred Share Dividends (Note 11) Earnings Applicable to Common Shareholders Earnings Per Common Share (Note 11) Consolidated Statement Of Retained Earnings (Canadian dollars in millions, except per share amounts) Year ended December 31, Retained Earnings at Beginning of Year Earnings Applicable to Common Shareholders Preferred Share and Preferred Security Issue Costs (Note 11) Common Share Dividends Retained Earnings at End of Year Dividends Per Common Share The accompanying notes to the consolidated financial statements are an integral part of these statements. 1,374.2 820.3 493.2 2,687.7 903.1 821.6 383.8 1,416.1 624.8 300.8 2,341.7 865.0 675.0 309.0 2,108.5 1,849.0 579.2 188.7 (380.6) 387.3 (87.5) 299.8 (5.0) (6.9) 287.9 1.91 492.7 156.4 (312.9) 336.2 (95.3) 240.9 – – 240.9 1.66 1,763.9 537.3 218.8 2,520.0 1,036.4 638.4 274.0 1,948.8 571.2 76.5 (276.1) 371.6 (154.3) 217.3 – – 217.3 1.58 1999 407.6 287.9 (6.0) (186.4) 503.1 1.195 1998 336.7 240.9 (1.7) (168.3) 407.6 1.120 1997 266.5 217.3 – (147.1) 336.7 1.060 32 Consolidated Statement Of Cash Flows (Canadian dollars in millions) Year ended December 31, Cash Provided from Operating Activities Earnings Charges (credits) not affecting cash: Depreciation Equity earnings in excess of cash distributions (Note 7) Gain on long term investment dilution (Note 7) Deferred income taxes (Note 5) Other Changes in operating assets and liabilities (Note 6) Investing Activities Long term investments (Note 7) Acquisition of subsidiaries (Note 8) Additions to property, plant and equipment Changes in construction payable (Note 6) Other Financing Activities Variable rate financing, net Fixed rate financing, net (Note 10) Non controlling interest preference shares (Note 10) Preferred securities (Note 11) Preferred shares (Note 11) Common shares (Note 11) Preferred security distributions (Note 11) Preferred share dividends (Note 11) 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 1 9 9 9 A N N U A L R E P O R T 1999 1998 1997 299.8 240.9 217.3 383.8 (29.7) (18.2) 5.5 (14.3) (131.8) 495.1 (340.8) (16.7) (783.7) (56.0) (8.5) 309.0 (13.8) (1.0) (26.1) (18.6) (178.0) 312.4 (181.0) (76.1) (1,388.4) 61.9 (6.8) 274.0 (9.2) (16.3) (0.1) 21.2 (49.1) 437.8 (434.8) (3.6) (651.4) 36.2 (5.3) (1,205.7) (1,590.4) (1,058.9) 204.3 184.5 100.0 338.5 – 10.3 (5.0) (6.9) (186.4) 639.3 (71.3) 124.9 53.6 349.0 829.6 – – 123.3 218.0 – – (168.3) 1,351.6 73.6 51.3 124.9 130.6 359.5 – – – 315.6 – – (147.1) 658.6 37.5 13.8 51.3 33 T H E E N E R G Y B R I D G E Consolidated Statement Of Financial Position (Canadian dollars in millions) December 31, Assets Current Assets Cash Accounts receivable and other Gas in storage Long Term Investments (Note 7) Deferred Charges and Other Property, Plant and Equipment, Net (Note 9) Liabilities and Shareholders’ Equity Current Liabilities Short term borrowings Accounts payable and other Interest payable Current portion of long term liabilities Long Term Debt (Note 10) Deferred Credits Deferred Income Taxes (Note 5) Non Controlling Interest Preference Shares (Note 10) Commitments and Contingencies (Note 16) Shareholders’ Equity Share capital (Note 11) Preferred securities Preferred shares Common shares Issued – 1999 – 156,308,000 (1998 – 155,710,000) Retained earnings Foreign currency translation adjustment Reciprocal shareholding (Note 7) The accompanying notes to the consolidated financial statements are an integral part of these statements. Approved by the Board: (D.J. Taylor) Director (F.W. Fitzpatrick) Director 34 1999 1998 53.6 678.5 375.1 1,107.2 1,051.6 278.7 6,770.7 9,208.2 155.4 494.6 86.1 174.4 910.5 5,284.8 157.8 254.5 100.0 124.9 611.3 357.8 1,094.0 676.9 212.1 6,364.2 8,347.2 400.4 540.9 87.9 257.5 1,286.7 4,502.3 230.4 266.4 – 6,707.6 6,285.8 341.1 125.0 – 125.0 1,677.2 503.1 (23.9) (121.9) 2,500.6 9,208.2 1,659.8 407.6 (9.1) (121.9) 2,061.4 8,347.2 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Notes To The 1999 Consolidated Financial Statements (Canadian dollars in millions, except per share amounts) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The Corporation’s primary business activities are the transportation and distribution of energy. These activities are conducted through the Corporation’s five operating segments: Liquids Pipelines, Gas Distribution, International, Gas Pipelines and New Business Development, and Energy Services. The consolidated financial statements of the Corporation are prepared in accordance with Canadian generally accepted accounting principles and conform in all material respects with the historical cost accounting standards of the International Accounting Standards Committee. 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, expenses and related disclosures. Actual results could differ from those estimates and assumptions; however, management believes that such differences would not be material. Basis of Presentation The consolidated financial statements include the accounts of the Corporation, its subsidiaries and the proportionate share of the accounts of its joint ventures. Investments in entities which are not subsidiaries or joint ventures, but over which the Corporation exercises significant influence, are accounted for using the equity method. Other investments are accounted for on the cost basis. The Corporation’s Gas Distribution business is conducted primarily through a wholly owned subsidiary, The Consumers’ Gas Company Ltd. (Enbridge Consumers Gas). The Corporation consolidates the September 30 fiscal year results of Enbridge Consumers Gas on a quarter lag basis, which reflects the results of Enbridge Consumers Gas operations in accordance with its regulatory, tax and operating cycles. Accordingly, references to “December 31” reflect the financial position of Enbridge Consumers Gas as at September 30, and references to the “year ended December 31” include the results of Enbridge Consumers Gas for its fiscal year ended September 30. Regulation The Corporation’s primary business activities are subject to regulation by various authorities, including the National Energy Board (NEB) for Canadian Liquids Pipelines and Gas Pipelines operations, the Federal Energy Regulatory Commission (FERC) for U.S. Liquids Pipelines and Gas Pipelines operations, and the Ontario Energy Board (OEB) for the Gas Distribution operations. These and other regulatory authorities exercise statutory authority over various matters such as construction, rates and underlying accounting practices, and ratemaking agreements with shippers. In order to achieve proper matching of revenues and expenses, the Corporation follows accounting practices prescribed by the regulators or stipulated in approved ratemaking agreements. Accordingly, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under generally accepted accounting principles applicable to non regulated operations. Foreign Currency Translation The functional currency of the Corporation’s foreign operations, except for certain financing and investing activities, is the U.S. dollar. These operations are self sustaining and translated into Canadian dollars using the current rate method. Assets and liabilities are translated into Canadian dollars at rates of exchange in effect at the date of the consolidated statement of financial position. Revenue and expense items are translated at exchange rates prevailing during the year. Gains and losses resulting from these translation adjustments are deferred as a separate component of shareholders’ equity until there is a realized reduction of the foreign investment. The functional currency of the Corporation’s foreign financing and investing operations is the Canadian dollar. These operations are integrated with those of the parent company and are translated into Canadian dollars using the temporal method. Monetary assets and liabilities are translated into Canadian dollars at rates of exchange in effect at the date of the consolidated statement of financial position. Non monetary assets and liabilities are translated at historical rates of exchange. Income and expense items are translated at exchange rates prevailing during the year, except for items relating to non monetary assets and liabilities which are translated at the applicable historical rates of exchange. Gains and losses resulting from these translation adjustments are included in earnings. 35 T H E E N E R G Y B R I D G E Revenue Recognition Revenues are recorded when products have been delivered or services have been performed. The gas and liquids transportation and gas distribution operations of the Corporation are subject to regulation by various authorities and, accordingly, there are circumstances where revenues recognized do not match the cash tolls or the billed amounts. In these situations, revenue is recognized in a manner that is consistent with the underlying rate design as mandated by the regulatory authority or under the terms of enforceable committed long term delivery contracts. Income Taxes The Corporation recovers income tax expense based on the taxes payable method when prescribed by the regulators for ratemaking purposes or when stipulated in ratemaking agreements. Under this method, no provision is made for income taxes deferred as a result of timing differences in the recognition of revenues and expenses for income tax and financial statement purposes. This method is followed for accounting purposes as there is reasonable expectation that all such taxes will be recovered through rates when they become payable. In all other instances, the tax allocation method of accounting is followed. Cash Cash includes short term and demand deposits which are valued at cost. The short term deposits are all highly marketable securities with a maturity of three months or less when purchased and are held to maturity. Gas in Storage Supplies of natural gas are recorded in inventory at prices as approved by the OEB in the determination of customer sales rates. The actual cost of gas purchased includes the effect of any 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 as approved by the OEB. Deferred Charges Deferred charges related to projects which may benefit future periods are capitalized and upon commercial viability are amortized over the useful life of the initiative, or expensed upon abandonment of the project. Deferred financing charges are amortized on the straight line basis over the life of the related debt. Unamortized financing charges related to refinanced debt, together with the costs of issuing replacement debt, are deferred and amortized over the life of the replacement issues. 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 follow the practice of capitalizing, at rates authorized by the regulatory authorities, an allowance for interest during construction. When prescribed by the regulator, liquids and gas transportation operations also capitalize an allowance for equity funds used during construction, at authorized rates. Contributions in aid of construction of gas distribution and electrical utility assets are deducted from the cost of acquiring property, plant and equipment, with subsequent depreciation calculated on the net cost. Depreciation Depreciation of property, plant and equipment is generally provided on the straight line basis over their estimated service lives. When property, plant and equipment are retired or otherwise disposed of, the cost less net proceeds is charged to accumulated depreciation. For unusual disposals, the gain or loss arising on disposition is included in earnings. A provision for Gas Distribution future removal and site restoration costs is recorded against and recovered through depreciation at rates approved by the OEB. Actual costs incurred are charged to accumulated depreciation. Similar costs are not recovered through tolls for liquids and gas transportation pipeline activities as regulatory approval has not been sought and the recovery method and timing have not been determined. No provision has been made for future pipeline removal and site restoration costs since it is expected that these costs will be recovered through pipeline tolls. Off Balance Sheet Financial Instruments Gains and losses on financial instruments used to hedge the Corporation’s investments in self sustaining foreign operations are deferred and included in the cumulative translation adjustment. Amounts received or paid under financial instruments used to hedge cash flows from U.S. dollar denominated operations are recognized concurrently with the hedged cash flows. Amounts received or paid under financial instruments used to hedge purchases of natural gas are 36 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T recognized as part of the cost of the underlying physical purchases. For other off balance sheet financial instruments, amounts received or paid, including deferred gains and losses realized upon settlement, are recognized over the life of the underlying hedged items. Postretirement Benefits The Corporation 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 in the Gas Distribution segment where contributions made to the plan are expensed as pension costs, consistent with its ratemaking process. For the defined contribution plan, contributions made by the Corporation are expensed as pension costs. The Corporation also provides postretirement benefits other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependants. For Canadian operations, these costs are charged to earnings as incurred. For U.S. operations, the cost of such benefits is accrued during the years the employees render service. Comparative Amounts Comparative amounts are reclassified to conform with the current year’s financial statement presentation. 2. SEGMENTED INFORMATION The operating segments shown below represent strategic business units which are established by senior management of the Corporation to facilitate the achievement of the Corporation’s long term growth objectives, to aid in resource allocation decisions and to assess operational performance. In all material respects, the measurement basis for preparation of segmented information is consistent with the significant accounting policies outlined in Note 1. Liquids Pipelines The Corporation’s main crude oil pipeline system is the primary transporter of Western Canadian crude oil production. The system extends across the Canadian prairies to the major refining centres in the Great Lakes region of the United States and continues into Ontario and Quebec. The Canadian portion of the system is owned and operated by a wholly owned subsidiary; the U.S. portion is operated and 15.3% owned by a wholly owned U.S. subsidiary through a Master Limited Partnership. The Corporation also owns feeder pipeline systems in North America through wholly owned subsidiaries. As well, this segment reflects the operations of Enbridge (Athabasca) System which delivers synthetic crude oil from the oil sands near Fort McMurray, Alberta, to Hardisty, Alberta. Gas Distribution The Gas Distribution segment consists largely of gas utility operations which serve 1.5 million residential, commercial, industrial and other customers, primarily in central and eastern Ontario. Contributions from the Corporation’s strategic investment in Noverco Inc. (Note 7) are also included. International This segment reflects the Corporation’s long term investment in a crude oil pipeline in Colombia for which the Corporation also acts as an operator. The segment also includes operating fees earned from the operation of the Jose Terminal in Venezuela. Gas Pipelines and New Business Development The Corporation’s investment in two natural gas transmission lines, Alliance Pipeline (21.4% owned), and Vector Pipelines (45% owned and to be operated) are included in this segment, as are revenues and expenses associated with electricity distribution and the Corporation’s 40% equity interest in AltaGas Services Inc. The segment also includes costs of investigation, evaluation and development of new business development projects which are not included in the core business of the other segments. Energy Services This segment includes the results of the Corporation’s retail appliance, fireplace and water heater operations as well as mass market and commercial plumbing, heating, ventilation and air conditioning, appliance repair and electrician contractor services which operate in both Canada and the United States. Petroleum marketing and related services are also included in this segment. 37 T H E E N E R G Y B R I D G E Operating Segments Year ended December 31, 1999 Operating Revenue Gas sales Transportation Energy services and other Expenses Gas costs Operating and administrative Depreciation Operating Income (Loss) Investment and Other Income Interest Expense Earnings (Loss) Before Income Taxes Income Taxes Earnings (Loss) Additions to Property, Plant and Equipment Year ended December 31, 1998 Operating Revenue Gas sales Transportation Energy services and other Expenses Gas costs Operating and administrative Depreciation Operating Income (Loss) Investment and Other Income Interest Expense Earnings (Loss) Before Income Taxes Income Taxes Earnings (Loss) Additions to Property, Plant and Equipment Liquids Pipelines Gas Distribution1 International Gas Pipelines Energy Services1 Corporate2 Consolidated — 595.6 3.9 599.5 — 235.6 115.5 351.1 248.4 52.9 (88.4) 212.9 (47.6) 165.3 376.9 1,368.5 224.7 272.8 1,866.0 897.5 390.0 238.1 1,525.6 340.4 36.8 (184.4) 192.8 (93.6) 99.2 363.0 — — 24.0 24.0 — 15.7 0.3 16.0 8.0 23.6 (0.1) 31.5 (2.8) 28.7 0.1 — 494.3 1.1 495.4 — 234.7 87.0 321.7 173.7 73.8 (62.0) 185.5 (42.3) 143.2 976.6 1,411.5 130.5 242.1 1,784.1 860.4 363.9 215.0 1,439.3 344.8 25.4 (176.5) 193.7 (93.5) 100.2 400.6 — — 16.0 16.0 — 17.7 0.2 17.9 (1.9) 26.3 — 24.4 (0.1) 24.3 0.4 — — 54.8 54.8 — 56.7 5.1 61.8 (7.0) 30.6 (0.3) 23.3 7.9 31.2 7.2 643.7 545.8 5.7 — 137.7 143.4 5.6 111.1 21.7 138.4 5.0 — (7.9) (2.9) 0.4 (2.5) 35.2 908.1 — — — — — — 12.5 3.1 15.6 (15.6) 44.8 (99.5) (70.3) 48.2 (22.1) 1.3 1,374.2 820.3 493.2 2,687.7 903.1 821.6 383.8 2,108.5 579.2 188.7 (380.6) 387.3 (87.5) 299.8 783.7 139.4 9,208.2 11.9 710.0 — — 24.8 24.8 — 28.9 2.6 31.5 (6.7) 7.4 0.6 1.3 5.0 6.3 1.1 278.9 181.6 4.6 — 16.8 21.4 4.6 24.3 1.5 30.4 (9.0) — (1.4) (10.4) 4.2 (6.2) 6.1 85.5 — — — — — — 5.5 2.7 8.2 (8.2) 23.5 (73.6) (58.3) 31.4 (26.9) 1,416.1 624.8 300.8 2,341.7 865.0 675.0 309.0 1,849.0 492.7 156.4 (312.9) 336.2 (95.3) 240.9 3.6 1,388.4 146.8 8,347.2 11.3 335.3 Total Assets 3,172.3 4,133.2 211.5 Investments Accounted for by the Equity Method 125.5 26.8 — Liquids Pipelines Gas Distribution International Gas Pipelines Energy Services Corporate2 Consolidated Total Assets 2,908.0 4,736.0 192.0 Investments Accounted for by the Equity Method 115.4 27.0 — 38 Operating Segments (continued) Year ended December 31, 1997 Operating Revenue Gas sales Transportation Energy services and other Expenses Gas costs Operating and administrative Depreciation Operating Income (Loss) Investment and Other Income Interest Expense Earnings (Loss) Before Income Taxes Income Taxes Earnings (Loss) Additions to Property, Plant and Equipment E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Liquids Pipelines Gas Distribution International Gas Pipelines Energy Services Corporate 2 Consolidated — 511.4 — 511.4 — 230.4 85.8 316.2 195.2 37.8 (66.6) 166.4 (58.0) 108.4 214.3 1,763.4 25.9 210.9 2,000.2 1,035.9 370.7 185.8 1,592.4 407.8 11.5 (164.1) 255.2 (123.1) 132.1 416.4 — — 6.6 6.6 — 10.7 0.1 10.8 (4.2) 19.4 — 15.2 0.9 16.1 — — — 1.2 1.2 — 7.7 — 7.7 (6.5) 1.0 — (5.5) 3.1 (2.4) 0.5 53.1 34.0 0.5 — 0.1 0.6 0.5 13.6 0.1 14.2 (13.6) — — (13.6) 6.1 (7.5) — 8.3 — — — — — — 5.3 2.2 7.5 (7.5) 6.8 (45.4) (46.1) 16.7 (29.4) 20.2 1,763.9 537.3 218.8 2,520.0 1,036.4 638.4 274.0 1,948.8 571.2 76.5 (276.1) 371.6 (154.3) 217.3 651.4 138.3 6,672.2 12.2 174.2 Total Assets 1,887.4 4,414.7 170.4 Investments Accounted for by the Equity Method 69.2 58.8 — 1 2 On October 1, 1999, the Corporation separated and removed (“unbundled”) the ancillary business activities from the regulated operations of Enbridge Consumers Gas to the unregulated Energy Services segment. This intersegment transaction comprised the transfer of the water heater and furnace rental program, merchandise retailing and financing operations and other related services including the transfer of associated assets for $737 million. The segmentation for 1999 reflects the results of operations of the unbundled activities for the period October 1, 1999 to December 31, 1999 and the associated assets in the Energy Services segment. With the exception of a reduction in the total assets of the Gas Distribution segment to account for the intersegment transfer of assets, the results of operations of the Gas Distribution segment reflects a full year contribution from the ancillary business activities for the year ended September 30, 1999 under the quarter lag basis of consolidation. Corporate reflects non operating investing and financing activities including general corporate investments and costs associated with financing non regulated activities. Geographic Segments There are no material operating revenues earned or capital assets owned outside of Canada which are consolidated with the results of the Corporation. Foreign earnings are primarily derived from investments accounted for using the equity or cost methods. 3. INVESTMENT AND OTHER INCOME Year ended December 31, Long term investments (Note 7) Short term investments Allowance for equity funds used during construction Gain on sale of non strategic real estate Gain on settlement of defeased debt (Note 7) Settlement of outstanding insurance claim Other 1999 139.6 11.9 9.9 — — — 27.3 188.7 1998 92.5 4.2 18.1 7.4 6.1 16.0 12.1 156.4 1997 74.5 — 3.2 — — — (1.2) 76.5 39 T H E E N E R G Y B R I D G E 4. INTEREST EXPENSE Year ended December 31, Long term debt Short term borrowings Capitalized 1999 382.8 14.9 (17.1) 380.6 1998 322.2 14.5 (23.8) 312.9 1997 275.3 9.8 (9.0) 276.1 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 with a weighted average interest rate (including the effect of hedging instruments) of 4.9% at December 31, 1999 (1998 – 5.4%; 1997 – 4.2%). In 1999, total interest paid was $399.5 million (1998 – $319.7 million; 1997 – $267.7 million). 5. INCOME TAXES The geographic components of pretax earnings and income taxes were as follows: Year ended December 31, Earnings before income taxes Canada United States Other Current income taxes Canada United States Other Deferred income taxes Canada United States Income taxes Deferred income taxes have arisen as a result of the following items: Year ended December 31, Recognition of tax losses available for carryforward Timing of recognition of regulatory deferral accounts Transfer of U.S. pipeline business to Master Limited Partnership Other 1999 1998 1997 236.5 102.7 48.1 387.3 62.3 13.5 6.2 82.0 (3.4) 8.9 5.5 87.5 1999 (39.8) 44.7 6.0 (5.4) 5.5 212.6 88.2 35.4 336.2 89.4 29.8 2.2 121.4 (24.4) (1.7) (26.1) 95.3 1998 (14.5) (14.2) (2.7) 5.3 (26.1) 279.2 69.9 22.5 371.6 134.9 18.1 1.4 154.4 (5.0) 4.9 (0.1) 154.3 1997 — — 2.3 (2.4) (0.1) Accumulated deferred income taxes which have not been recorded in the accounts amounted to $743.3 million at December 31, 1999 (1998 – $679.9 million). Had the deferred method of tax allocation been prescribed by the regulatory authorities for ratemaking purposes, such amounts would have been recorded and recovered in rates to date. In October 1998, Revenue Canada changed its assessing practice relating to natural gas utilities with respect to the treatment for tax purposes of certain capitalized expenditures. Effective for 1997 and subsequent taxation years, these expenditures can now be expensed for tax purposes. Contingent upon OEB approval, the Corporation will refund the higher 40 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T taxes included in rate and revenue structures in 1999, 1998 and 1997 for non rental related operations of $14.1 million (1998 – $10.1 million). Lower taxes payable relating to rental operations for 1999, 1998 and 1997 of $42.3 million (1998 – $32.0 million) were determined by the OEB in 1999 to be available to offset the Corporation’s liabilities on the currently unrecorded deferred income taxes associated with the rental program. As at December 31, 1999, these amounts are included in deferred credits. Prior to 1992, the Corporation’s main Canadian crude oil pipeline system had collected through tolls $114.1 million which had been recorded as deferred income taxes. Consistent with a mandate from its regulator and an agreement with the Canadian Association of Petroleum Producers to repay these funds to its customers, the Corporation has reclassified these deferred income taxes to deferred credits as a liability to shippers on its statement of financial position, to reflect the planned repayment. A corresponding increase has been reflected in the amount of unrecorded deferred income taxes. Prior years’ comparative amounts have been restated to conform with the current year’s financial statement presentation. During 1999, $17.3 million of such funds were repaid to the shippers through lower tolls and $54.1 million has been included in the current portion of long term liabilities. The income tax provision differs from the amount that would have been expected using the combined Canadian federal and provincial statutory income tax rate. The difference results from the items shown in the following table: Year ended December 31, Earnings before income taxes Statutory income tax rate Income taxes at statutory rate Increase (decrease) resulting from: Non provision of deferred income taxes on regulated operations Non taxable items, net Lower effective foreign tax rates Income taxes recoverable relating to prior years Large Corporations Tax in excess of surtax Other Income taxes Effective income tax rate 1999 387.3 44.6% 172.7 (37.1) (48.7) (16.0) 1.6 14.4 0.6 87.5 1998 336.2 44.6% 150.0 (18.6) (2.9) (27.1) (17.3) 10.1 1.1 95.3 22.6% 28.4% In 1999, income taxes paid amounted to $79.6 million (1998 – $163.5 million; 1997 – $172.1 million). 6. CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, Accounts receivable and other Gas in storage Deferred charges and other Accounts payable and other Interest payable Current portion of long term liabilities Deferred credits 1999 (67.2) (17.3) (38.6) 9.7 (1.8) 54.1 (70.7) (131.8) 1998 (174.7) (47.9) (9.4) (14.3) 17.0 — 51.3 (178.0) 1997 371.6 44.6% 165.7 (20.2) 15.0 (17.5) — 7.5 3.8 154.3 41.5% 1997 (75.5) (30.8) (5.0) 56.7 (8.2) — 13.7 (49.1) Changes in accounts payable shown above exclude changes in construction payable which relate to investing activities. 41 T H E E N E R G Y B R I D G E 7. LONG TERM INVESTMENTS December 31, Noverco Inc. Preference shares Common shares Reciprocal shareholding Alliance Pipeline Project AltaGas Services Inc. Colombia Pipeline U.S. Master Limited Partnership Vector Pipeline Project Other 1999 1998 181.4 148.7 (121.9) 208.2 306.5 165.6 160.2 82.9 59.4 68.8 1,051.6 181.4 148.9 (121.9) 208.4 146.2 — 160.2 68.3 29.3 64.5 676.9 Noverco Inc. On August 27, 1997, the Corporation purchased Noverco preference shares for $181.4 million and 32% of Noverco’s common shares for $151.0 million. Noverco is a holding company which has, as its principal asset, a 77% interest (1998 – 80%) in Gaz Métropolitain and Company, Limited Partnership, which is engaged in natural gas distribution in Quebec and Vermont, and which also holds a 50% interest in TQM Pipeline and Company, Limited Partnership, which owns and operates a pipeline transporting natural gas in Quebec. This acquisition was financed by a combination of debt ($45.3 million) and 12.0 million common shares of Enbridge issued to Noverco in a separate transaction ($287.1 million). Noverco also acquired a warrant to purchase from the Corporation 3.0 million additional common shares on June 30, 1998 at a price of $25.50 per share. On June 30, 1998, the warrant was exercised and on November 13, 1998, was settled for proceeds of $76.5 million. Consequently, Noverco’s common share interest in the Corporation increased to approximately 10% from 8%. Additionally, on November 13, 1998, in conjunction with a separate public offering, 500,000 common shares were issued to Noverco at a price of $33.525 per share, maintaining Noverco’s reciprocal shareholding interest in Enbridge at 10%. As a result of the reciprocal shareholdings, the Corporation has a pro rata interest of 3.2% in its own shares (1998 – 3.2%). Accordingly, both the investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $121.9 million (1998 – $121.9 million). The investment in common shares of Noverco is accounted for on the equity basis while the investment in preference shares is accounted for at cost. The investment in the common shares of Noverco includes $122.6 million (1998 – $129.3 million) representing the unamortized excess of the purchase price over the net book value of those shares at the date of acquisition. For equity accounting purposes, the excess was allocated to property, plant and equipment, on the basis of estimated fair values, and is being amortized over the economic life of such assets. The preference shares, which are non voting and redeemable on July 2, 2031, entitle the Corporation to a cumulative dividend based on the yield of 10 year Government of Canada bonds plus 4.45%. In 1999, earnings from Noverco amounted to $17.6 million (1998 – $17.7 million; 1997 – $6.9 million). At December 31, 1999, the carrying value of the investment in Noverco common shares included unremitted equity earnings of $7.1 million (1998 – $0.5 million). Alliance Pipeline Project The Corporation holds a 21.4% equity interest in the Alliance Pipeline Partnership. The Partnership is presently constructing a natural gas pipeline from Fort St. John, British Columbia, to Chicago, Illinois, which is anticipated to be in service late in 2000. The Alliance Pipeline has a planned delivery capacity of 1.3 billion cubic feet per day of which 105 million cubic feet has been committed by the Corporation. From time to time, the Corporation is required to provide further funds upon call of the Partnership. During 1999, the Corporation invested $138.0 million in the project (1998 – $105.4 million; 1997 – $30.5 million) and recorded $22.3 million (1998 – $6.5 million; 1997 – $1.0 million) of equity earnings. At December 31, 1999, the carrying value of the investment in the Partnership included unremitted equity earnings of $29.8 million (1998 – $7.5 million). 42 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T AltaGas Services Inc. On September 30, 1999, the Corporation purchased non voting participating preference shares of AltaGas Services Inc. for $90.0 million and 7.3 million of AltaGas’ common shares for $73.8 million. On an aggregate basis the participating and common shares represent an approximate 40% interest in AltaGas. AltaGas is a holding company which, through its wholly owned subsidiaries, provides natural gas gathering, processing, and related services as well as natural gas transmission and distribution to end users in Alberta and Saskatchewan. This acquisition was financed by a combination of cash ($156.7 million) and 217,330 common shares of Enbridge ($7.1 million). The investment in participating and common shares of AltaGas is accounted for on the equity basis. The participating shares fully participate in the earnings of AltaGas and are convertible into common shares on a one to one basis at the option of Enbridge. Should Enbridge not convert these shares into common shares by September 30, 2004, then AltaGas will be required to convert all participating shares prior to September 30, 2009, based on a ratio of $10 divided by the current market value of an AltaGas common share. The investment in the common shares of AltaGas includes $39.2 million representing the unamortized excess of the purchase price over the net book value of those shares at the date of acquisition. For equity accounting purposes, the excess was allocated to property, plant and equipment, on the basis of estimated fair values, and is being amortized over the economic life of such assets. In 1999, earnings from AltaGas amounted to $2.0 million. At December 31, 1999, the carrying value of the investment in AltaGas participating and common shares included unremitted equity earnings of $2.0 million. Colombia Pipeline Pursuant to an agreement with a consortium of crude oil producers/shippers, the Corporation has made a long term investment in a pipeline in Colombia. From time to time, the Corporation was required to provide funds upon the call of the parties to the agreement. During 1999, the Corporation did not make additional investments in the pipeline as the Corporation had no remaining commitment to provide further funds. During 1998, the Corporation contributed U.S. $2.5 million (1997 – U.S. $38.7 million). Under a separate agreement, the Corporation acts as one of the operators of the pipeline and earns operating fees. The Corporation earns a fixed rate of return on its investment and has no residual interest in the assets of the pipeline. Accordingly, the investment is accounted for on the cost basis. The investment is to be redeemed in equal payments over a ten year period. Subject to certain conditions, redemption may commence in 2003 but, in any event, no later than 2012. Earnings amounted to $24.0 million in 1999 reflecting the fixed rate of return on the investment as well as the operating and incentive fees (1998 – $24.8 million; 1997 – $18.5 million). U.S. Master Limited Partnership The portion of the main liquids pipeline system located in the United States is owned by Lakehead Pipe Line Partners, L.P., a U.S. Master Limited Partnership. The Corporation’s wholly owned U.S. subsidiary, Lakehead Pipe Line Company, Inc. (Lakehead), holds an equity interest of approximately 15.3% in the Partnership, and manages and operates the U.S. pipeline business as the General Partner. The Corporation’s interest in the net income of the Partnership, adjusted for the allocation of depreciation on an historical cost basis for assets contributed on formation of the Partnership, and including incentive distributions amounted to $31.6 million (1998 – $33.7 million; 1997 – $26.4 million). In 1999, the Corporation received cash distributions of $35.0 million from the Partnership (1998 – $31.8 million; 1997 – $21.8 million). The carrying value of the Corporation’s investment in the Partnership includes unremitted equity earnings of $12.0 million (1998 – $15.4 million). In 1999 and 1997, the Partnership completed public issues of additional Partnership Units. As the Corporation elected not to participate in these offerings its effective equity interest in the Partnership was reduced to 15.3% from 16.6% in 1999 and to 16.6% from 18.0% in 1997. The proceeds received by the Partnership were allocated among the capital accounts of the unitholders based upon the increase in Partnership net assets attributable to each interest as a result of the issue. The Corporation’s pro rata share of Partnership net assets increased by $18.2 million and $16.3 million, which were recognized in earnings in 1999 and 1997, respectively. Financing of the Partnership was previously facilitated through Lakehead Services, Limited Partnership. The Corporation owns a 99% limited partner interest in the Services Partnership and the Partnership holds a 1% general partner interest. At December 31, 1997, the Services Partnership had borrowings of U.S. $52 million under a Revolving Credit 43 T H E E N E R G Y B R I D G E Facility Agreement. In conjunction with its borrowings under this facility, the Services Partnership irrevocably placed U.S. government securities in a trust to be used solely for satisfying scheduled payments of both interest and principal on these borrowings. This transaction was recognized as an in substance defeasance and the debt was considered to be extinguished. In 1998, as a result of the cessation of financing activities of the Services Partnership and the corresponding release of trust assets in excess of defeased debt requirements, the Corporation recovered $6.1 million which were recognized in earnings. Vector Pipeline Project The Corporation holds a 45% interest in the Vector Pipeline Partnership and is the operator of the project. The Partnership is constructing a natural gas transmission line between Chicago, Illinois, and Dawn, Ontario, for a cost of approximately U.S.$504 million. The Vector Pipeline has a planned delivery capacity of 1 billion cubic feet per day of which 260 million cubic feet has been committed by the Corporation. From time to time during construction, the Corporation is required to provide further funds upon call of the Partnership. During 1999, the Corporation invested $24.6 million in the project (1998 – $23.0 million) and recorded $5.5 million (1998 – $1.4 million) of equity earnings. At December 31, 1999, the carrying value of the investment in the Partnership included unremitted equity earnings of $6.9 million (1998 – $1.4 million). Other Other investments include the Corporation’s 23% equity investment in the Chicap Pipe Line acquired in September 1998 for $33.3 million and a 44% equity investment in the Frontier Pipeline. The Chicap Pipe Line transports crude oil between refining centres of Patoka and Chicago, Illinois. The Frontier Pipeline transports crude oil from Casper, Wyoming, to Salt Lake City, Utah. During 1999, the Corporation recorded $11.2 million (1998 – $5.8 million; 1997 – $4.7 million) in equity earnings from these investments. At December 31, 1999, the carrying value of these investments included unremitted equity earnings of $4.8 million (1998 – $3.5 million). 8. ACQUISITION OF SUBSIDIARIES Cornwall Electric On July 31, 1998, the Corporation acquired all of the outstanding shares of Cornwall Street Railway Light & Power Company Limited for cash consideration of $68.0 million. Cornwall Electric provides electrical power to the residents of Cornwall, Ontario, and surrounding areas. This investment, which was accounted for using the purchase method, exceeded the book value of the assets by $27.0 million. This excess was allocated to property, plant and equipment, on the basis of estimated fair values and is being amortized over the economic life of such assets. 9. PROPERTY, PLANT AND EQUIPMENT, NET December 31, 1999 Liquids Pipelines Gas Distribution Gas Pipelines Energy Services Other December 31, 1998 Liquids Pipelines Gas Distribution Gas Pipelines Energy Services Other Weighted Average Depreciation Rate 2.6% 2.7% 4.0% 4.5% 10.2% Weighted Average Depreciation Rate 2.9% 2.6% 4.0% 5.3% 10.3% Cost 4,082.9 3,583.0 107.3 912.0 26.9 8,712.1 Cost 3,715.9 4,218.5 103.0 10.2 23.6 8,071.2 Accumulated Depreciation 1,247.1 353.1 40.8 294.8 5.6 1,941.4 Accumulated Depreciation 1,144.0 521.0 37.1 2.0 2.9 1,707.0 Net 2,835.8 3,229.9 66.5 617.2 21.3 6,770.7 Net 2,571.9 3,697.5 65.9 8.2 20.7 6,364.2 The average depreciation rate for the Gas Distribution segment, after inclusion of a provision for future removal and site restoration costs, is 5.0% (1998 – 5.0%). 44 10. DEBT Long Term Debt December 31, Regulated Operations Liquids Pipelines Debentures 1 Medium term notes Variable rate Gas Distribution Debentures Medium term notes Other 2 Preference shares Total regulated operations Non Regulated Operations Debentures 3 Medium term notes Variable rate Total non regulated operations Total long term debt Current portion of long term debt Long term debt E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Weighted Average Interest Rate Maturity 1999 1998 9.1% 6.5% 5.1% 10.9% 6.5% 7.1% 2000–2024 2001–2029 2000–2024 2000–2028 9.4% 5.8% 5.4% 2000–2048 2002–2028 411.6 702.0 23.5 430.9 511.7 96.8 1,137.1 1,039.4 717.4 1,115.0 109.5 — 1,941.9 3,079.0 237.0 694.3 1,379.8 2,311.1 5,390.1 (105.3) 5,284.8 724.9 1,161.0 108.8 100.0 2,094.7 3,134.1 228.1 499.4 882.7 1,610.2 4,744.3 (242.0) 4,502.3 1 2 3 Includes $14.5 million of debentures (1998 – $54.1 million) secured by a first mortgage on specific pipeline properties and the assignment of the benefits of a shipping agreement. Primarily comprised of commercial paper borrowings effectively converted into long term debt maturing in 2002 through the use of long term interest rate swaps. Includes U.S. $130.0 million 9.4% debentures issued in 1995 which were effectively converted into Canadian $178.1 million at an effective interest rate of 8.8% reflecting the use of a cross currency swap and the amortization of both debenture purchase warrant proceeds totaling $13.3 million and hedging costs over the life of the primary instrument. The amounts of long term debt maturities and sinking fund requirements for the years ending December 31, 2000 through 2004, in millions, are $105.3, $430.2, $315.3, $140.3 and $164.6, respectively. Fixed rate long term debt retirements in 1999 totalled $183.1 million (1998 – $360.8 million; 1997 – $94.2 million). Preference Shares of Gas Distribution Segment The Cumulative Redeemable Retractable Preference Shares of Enbridge Consumers Gas (Group 2 $1.6125 Series C – 2,000,000 shares, $50.0 million; Group 3 $1.43 Series C – 2,000,000 shares, $50.0 million) were redeemed in 1999, both at $25 per share. Dividends on these shares for the year ended December 31, 1999, amounted to $2.5 million and are included in interest expense (1998 – $6.1 million; 1997 – $6.1 million). Credit Facilities At December 31, 1999, the Corporation’s credit facilities in the amount of $2,707.6 million comprised the following: Liquids Pipelines Gas Distribution Other Committed Uncommitted Drawdowns 150.0 300.3 1,950.0 2,400.3 — 307.3 — 307.3 — 14.4 650.0 664.4 Committed facilities carry a weighted average standby fee of 0.087% per annum on the unutilized portion. The committed facilities for the Liquids Pipelines and Gas Distribution segments expire in 2000 and are extendible annually subject to the approval of the lenders. The committed facility for corporate purposes expires in 2004. Drawdowns under these facilities bear interest at prevailing market rates. 45 T H E E N E R G Y B R I D G E Non Controlling Interest Preference Shares On July 5, 1999, Enbridge Consumers Gas issued 4,000,000 Cumulative Redeemable Convertible Preference Shares for $100 million which bear dividends at 4.67% until July 1, 2002 after which the annual dividend will float in relation to prime rate. At this date and every five years thereafter, the holder may convert these shares into a different preference share bearing a fixed coupon rate based upon Canadian treasury bill yields. Also on and after July 1, 2002, Enbridge Consumers Gas has the option to redeem the shares for $25.50 if the shares are publicly listed or $25 if they are not, together with accrued and unpaid dividends in each case. As the holder of the share does not control cash redemption rights and only participates in the earnings of Enbridge Consumers Gas these shares have been considered as a non controlling interest. 11. SHARE CAPITAL The authorized share capital of the Corporation consists of an unlimited number of common and preferred shares. Common Shares 1999 1998 1997 (number of common shares in thousands) Balance at beginning of year Dividend Reinvestment and Share Purchase Plan Investment by Noverco (Note 7) Shares issued for investment in AltaGas (Note 7) Public issue Other Balance at end of year Number 155,710 200 — 217 — 181 156,308 Amount 1,659.8 6.6 — 7.1 — 3.7 1,677.2 Number 148,328 178 3,500 — 3,500 204 155,710 Amount 1,441.8 5.6 93.3 — 114.5 4.6 1,659.8 Number 134,980 1,222 12,000 — — 126 148,328 Amount 1,126.2 26.2 287.1 — — 2.3 1,441.8 Preferred Shares On December 1, 1998, the Corporation completed a public offering of 5,000,000 5.5% Cumulative Redeemable Preferred Shares, Series A, for cash proceeds of $125.0 million less related issue costs. The preferred shares are entitled to fixed cumulative preferential dividends of $1.375 per share per year, payable quarterly. On or after December 31, 2003, the Corporation 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 at $25.00 per share if redeemed thereafter, in each case with all accrued and unpaid dividends to the redemption date. The after tax issue costs of these shares totalling $1.7 million have been charged to retained earnings. Preferred Securities On July 8, and October 21, 1999, the Corporation completed public offerings of Preferred Securities which are unsecured junior subordinated instruments that mature in 2048 and may be redeemed at the Corporation’s option in whole or in part after the fifth anniversary of each issue. The Corporation has the right to defer, subject to certain conditions, payments of distributions on the securities for a period of up to 20 consecutive quarterly periods. Such deferred distribution amounts are payable in cash, or at the option of the Corporation, from the proceeds on the sale of equity securities delivered to the trustee of the securities. Accordingly, the securities are classified into their debt and equity components as shown below: Date of Issue July 8, 1999 October 21, 1999 Number of Securities 7 million 7 million Redeemable Face Value 175.0 175.0 Maturity Date June 30, 2048 September 30, 2048 Debt 4.9 4.0 Equity 170.1 171.0 Distributions on these securities are payable at an annual rate of 7.6% for the July issue and 8.0% for the October issue. These distributions are deductible for tax purposes by the Corporation and the after tax amount of the distributions is charged to earnings applicable to common shareholders. The after tax issue costs of these securities totalling $6.0 million have been charged to retained earnings. 46 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Earnings Per Common Share Earnings per common share are computed on the weighted average number of common shares outstanding of 150,995,000, 145,448,000 and 137,808,000 in 1999, 1998 and 1997, respectively. The prior years have been restated to reflect a two for one common share split on May 10, 1999. On a full year basis, there were no materially dilutive instruments outstanding during each of the years in the three year period ended December 31, 1999. The weighted average number of shares outstanding have been reduced by the Corporation’s pro rata interest in its own common shares resulting from the investment in Noverco (Note 7). For the purposes of the calculation, earnings have been reduced by the preferred security distributions and preferred share dividends. Dividend Reinvestment and Share Purchase Plan The Corporation has a Dividend Reinvestment and Share Purchase Plan. Under the Plan, registered shareholders may reinvest dividends in common shares of the Corporation, or make optional cash payments to purchase additional common shares, in either case free of brokerage or other charges. Shareholder Rights Plan The Corporation has a Shareholder Rights Plan designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Corporation. Rights issued under the Plan become exercisable when a person, and any related parties, acquires or announces its intention to acquire 20% or more of the Corporation’s outstanding common shares without complying with certain provisions set out in the Plan, or without approval of the Board of Directors of the Corporation. 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 Corporation at a 50% discount to the market price at that time. 12. STOCK OPTION PLAN The Corporation’s Incentive Stock Option Plan (1999) is comprised of fixed stock options and performance based stock options. A maximum of 12 million common shares are reserved for issuance under the various alternatives covered by the Plan. The details for the options outstanding have been restated to retroactively reflect the two for one common share split on May 10, 1999. Fixed Stock Options and Stock Appreciation Rights Full time key employees are granted options to purchase unissued common shares, exercisable at the market price of common shares at the date the options are granted. Generally, options vest in equal annual instalments over a four year period and expire after ten years from the original issue date. Stock Appreciation Rights (SARs) may be granted in connection with the grant of fixed stock options in an amount not exceeding the number of shares to which the options relate. SARs are exercisable at such times and such amounts as the underlying options, and entitle the holders to surrender the underlying and unexercised options in exchange for the amount by which the market price of the common shares covered by the options exceeds the option exercise price. No further SARs have been granted since November 3, 1994. The previous plans also allowed the Corporation to provide for option holders Restricted Stock Units (RSUs) equivalent to the amount of dividends that would have been received on the number of common shares subject to unexercised options. No further RSUs have been allowed since July 10, 1997. A summary of the status of the Corporation’s fixed stock options is presented below: (options in thousands; exercise prices in dollars) Number of shares under option at beginning of year Options granted Options exercised Options cancelled or expired Number of shares under option at end of year 1 1999 Weighted Average Exercise Price Number 2,415 888 (115) (72) 3,116 23.33 34.45 15.35 30.25 26.63 1998 Weighted Average Exercise Price 18.45 33.11 15.02 22.22 23.33 Number 1,874 811 (128) (142) 2,415 1997 Weighted Average Exercise Price 15.15 24.38 12.84 16.92 18.45 Number 1,384 644 (128) (26) 1,874 1 At December 31, 1999, there remained 376,000 and 656,000 unexercised stock options which had the SAR and RSU features, respectively. 47 T H E E N E R G Y B R I D G E The options outstanding at the end of 1999 had the following characteristics: (options in thousands; exercise prices in dollars) Exercise Price Range 11.43 to 20.00 20.01 to 30.00 30.01 to 35.50 Number Outstanding Weighted Average Exercise Price Number Available for Exercise Weighted Average Exercise Price 951 522 1,643 15.45 24.36 33.82 917 311 193 15.29 24.43 33.10 Outstanding stock options will expire over a period ending no later than August 17, 2009. Performance Based Stock Options The Plan provides for the granting of performance based options to executive management with vesting based upon the performance of the Corporation’s common stock price. The options become exercisable, as to 50% of the grant, when the market price of a common share exceeds $40.00 per share for 20 consecutive trading days during the period January 20, 1998 to December 31, 2002. If the share price exceeds $45.00 during the same period the grant is fully exercisable. A summary of the status of the Corporation’s performance based options is presented below: (options in thousands; exercise prices in dollars) Number of shares under option at beginning of year Options granted Options cancelled Number of shares under option at end of year 1999 Weighted Average Exercise Price 31.40 33.88 31.35 31.60 Number 1,420 120 (60) 1,480 1998 Weighted Average Exercise Price 31.39 31.35 31.40 Number — 1,620 (200) 1,420 The performance based options expire on January 1, 2003 but will extend to January 20, 2006 if the options become exercisable before December 31, 2002. None of the performance based options have met the vesting conditions at December 31, 1999. 13. FINANCIAL INSTRUMENTS Fair Value of Financial Instruments The fair value of financial instruments represent an approximation of amounts that would have been received from or paid to counterparties, calculated at the reporting date, to settle these instruments prior to maturity. At December 31, 1999, the Corporation had no intention of settling any instruments prior to maturity. Carrying amounts of financial instruments represent amounts recorded in the consolidated statement of financial position. With the exception of the items listed below, the estimated fair values of all financial instruments approximate the carrying amounts. December 31, Long term debt Regulated operations Non regulated operations 1999 1998 Carrying Amount 3,079.0 2,311.1 Fair Value 3,351.5 2,286.5 Carrying Amount 3,134.1 1,610.2 Fair Value 3,616.0 1,642.7 The following methods and assumptions were used to estimate the fair value of each class of financial instruments at December 31, 1999 and 1998: (cid:2) (cid:2) (cid:2) The fair value of long term debt is based on quoted market prices at year end or based on the discounted future cash flows of each debt issue at current interest rates for remaining average terms to maturity. Due to the regulatory nature of business operations, the Corporation has the ability to recover related interest on debt at existing rates. The carrying amount of the Corporation’s long term investment in the Colombia Pipeline Project approximates fair value as the contractual rate of return represents current market rates for investments with similar terms and conditions. The carrying amounts of all financial instruments classified as current approximate fair value because of the short maturities of these instruments. 48 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Risk Management By virtue of its business operations, the Corporation is exposed to movements in the U.S./Canadian dollar exchange rate, the price of natural gas and interest rates. In order to minimize these exposures for both its ratepayers and shareholders, the Corporation utilizes a variety of hedging instruments to create an offsetting position to specific exposures. These instruments are employed in connection with an underlying asset, liability or anticipated transaction, and are not used for speculative purposes. By entering into these hedging instruments, the Corporation agrees to exchange with counterparties the difference between fixed and variable amounts, calculated by reference to specific foreign exchange rates, interest rates, or natural gas price indices based on a notional principal amount or notional quantity of natural gas. The notional amounts are not recorded in the financial statements as they do not represent amounts exchanged by the counterparties. The Corporation enters into off balance sheet risk management transactions only with creditworthy institutions that possess strong investment grade credit ratings or where such transactions are secured with approved forms of collateral. For transactions with terms of greater than five years, the Corporation may also retain the right to require a counterparty (who would otherwise meet the Corporation’s credit criteria) to provide collateral within a specified time frame. As at December 31, 1999, no material credit exposure existed as the Corporation was not party to any off balance sheet instruments in a significant receivable position. Foreign Exchange The Corporation has an exposure to the U.S./Canadian dollar exchange rate primarily through its investments in U.S. dollar denominated operations. The Corporation has established a hedging program to eliminate a portion of that long term exposure. At December 31, 1999, the Corporation had entered into par forward and cross currency swaps to hedge U.S. dollar denominated cash flows of approximately U.S. $39 million per annum (1998 – U.S. $39 million; 1997 – U.S. $30 million) as well as the redemption of the U.S. dollar denominated investment in the Colombia pipeline project of U.S. $100 million (1998 – $100 million), thereby mitigating potential currency exposures on the anticipated cash flows from, and redemption of, these U.S. dollar investments. In addition, forward foreign exchange contracts, including cross currency swaps, have been entered into to hedge the Corporation’s exposure on its U.S. dollar denominated debt and to match the effect of translating Canadian dollar denominated monetary financing held by an integrated U.S. subsidiary. Natural Gas Prices The Corporation also uses natural gas price swaps, options and collars to manage exposure to natural gas prices which, under the majority of system supply gas contracts, are indexed to U.S. dollar denominated natural gas futures contracts plus a basis differential or to Alberta based gas price indices. As allowed under the regulatory framework governing the Corporation’s Gas Distribution operations, the Corporation hedges the cost of a portion of future natural gas supply requirements. Amounts paid or received under this risk mitigation strategy are recognized as part of the cost of the underlying natural gas purchases which is recovered through the rate making process. The OEB continues to monitor the implementation and results of the Corporation’s natural gas hedging program. At December 31, 1999, the Corporation had entered into natural gas price swaps and options to effectively manage the price for approximately 10.3%, or 18.2 billion cubic feet, of its forecast fiscal 2000 system gas supply. During the year ended December 31, 1999, the Corporation hedged 37.7%, or 62.0 billion cubic feet, of its system gas supply (1998 – 34%, or 53.4 billion cubic feet; 1997 – 36%, or 65.7 billion cubic feet). Interest Costs To hedge against the effect of future interest rate movements on its short to long term borrowing requirements, the Corporation enters into forward interest rate agreements, swaps and collars. In anticipation of future debt issuances related to specific committed capital projects, the Corporation enters into financial contracts to hedge a portion of the interest cost associated with the anticipated issues. Fair Value of Off Balance Sheet Financial Instruments The fair value of off balance sheet financial instruments reflects the estimated amounts that the Corporation would receive or pay to terminate the contracts at the year end date. This fair value represents the difference between the present value of estimated future receipts and future payments under the terms of each instrument which is estimated by obtaining quoted market prices or by using pricing models widely used in financial markets. These fair value amounts should not be viewed in isolation, but rather in relation to the fair values of the underlying hedged transactions and the overall reduction in the Corporation’s exposure to adverse fluctuations in foreign exchange rates, natural gas prices and interest rates. At December 31, 1999, the Corporation had no intention of settling any instruments prior to maturity. 49 T H E E N E R G Y B R I D G E At year end, the Corporation was party to the following off balance sheet financial instruments: December 31, Foreign exchange Cross currency swaps Forwards (cumulative exchange amounts) Natural gas prices (billion cubic feet) Interest rates Interest rate swaps Bond forwards Notional Principal or Quantity 316.2 1,832.3 18.2 696.3 — 1999 Fair Value Payable/ (Receivable) (3.4) 14.4 (0.3) (1.3) — Maturity 2001–2022 2000–2022 2000 2000–2029 Notional Principal or Quantity 316.2 1,891.2 31.1 271.0 153.0 1998 Fair Value Payable/ (Receivable) Maturity 2.6 89.2 (3.5) 2001–2022 1999–2022 1999 6.9 8.5 1999–2002 1999 As the Corporation did not settle hedging instruments in advance of the hedged transactions, there were no gains or losses deferred in relation to any of the Corporation’s off balance sheet hedges of anticipated transactions at December 31, 1999 and 1998. Trade Credit Risk Trade receivables relating to Liquids Pipelines 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 Corporation’s pipeline and storage facilities. The Corporation holds adequate insurance on this crude oil and other products. Credit risk with respect to trade receivables of the remaining operating segments is reduced by the large and diversified customer base, and, for rate regulated operations, the ability to recover an estimate for doubtful accounts through the ratemaking process. The allowance for doubtful accounts amounted to $16.4 million at December 31, 1999 (1998 – $16.3 million). 14. POSTRETIREMENT BENEFITS Pension Plans The Corporation has three pension plans which provide either defined benefit or defined contribution pension benefits or both for the employees of the Corporation. The Liquids Pipelines pension plan in Canada provides non contributory defined benefit pension and/or defined contribution benefits to Canadian employees. The Liquids Pipelines pension plan in the United States provides non contributory defined benefit pension benefits to U.S. employees. The Enbridge Consumers Gas pension plan provides contributory defined benefit pension benefits to employees of the Gas Distribution and Energy Services segments. Defined Benefit Retirement benefits under defined benefit plans are based on the employees’ years of service and remuneration. Contributions made by the Corporation are 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, 1999. Pension costs under the defined benefit pension plan 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, experience gains and losses, and changes to assumptions are amortized over the expected average remaining service lives of the employees. Consistent with its ratemaking process, Enbridge Consumers Gas records as pension expense the contributions deemed sufficient by actuaries to fully fund the plans over an acceptable time frame. Defined Contribution Defined contribution pension benefits cover all employees hired by the Liquids Pipelines segment in Canada after January 1, 1997 as well as its existing employees who elected to leave the defined benefit plan on a prospective basis. Contributions are based on each employee’s age and years of service. For defined contribution pension benefits, pension expense equals amounts contributed by the Corporation. 50 The status of the Corporation’s pension plans was as follows: December 31, Pension plan assets at market values: Liquids Pipelines Canada United States Enbridge Consumers Gas Projected benefit obligations: Liquids Pipelines Canada United States Enbridge Consumers Gas E N B R I D G E 1 9 9 9 A N N U A L R E P O R T 1999 1998 191.3 174.0 668.7 1,034.0 155.4 74.4 404.2 634.0 169.8 161.9 564.6 896.3 124.9 98.3 411.5 634.7 The Corporation’s pension expense totaled $9.4 million (1998 – $5.0 million; 1997 – $9.2 million) and the deferred pension asset was $21.3 million (1998 – $16.7 million). Postretirement Benefits Other than Pensions Postretirement benefits other than pensions include supplemental health, dental and life insurance coverage for qualifying retired employees. The cost of providing these benefits amounted to $2.0 million (1998 – $2.6 million; 1997 – $1.7 million). 15. RELATED PARTY TRANSACTIONS The U.S. Master Limited Partnership, which does not have any employees, uses the services of the Corporation for managing and operating the U.S. pipeline business. These services, which are charged at cost in accordance with service agreements, amounted to $50.9 million (1998 – $51.7 million; 1997 – $46.0 million). Accounts receivable include $2.5 million due from the Partnership (1998 – $3.8 million). The Partnership had entered into an easement agreement with Enbridge Holdings (Mustang) Inc. (“Enbridge Mustang”), a wholly owned subsidiary of the Corporation. Enbridge Mustang acquired certain real property for the purposes of granting pipeline easements to the Partnership for construction of a new pipeline, completed during 1998, by the Partnership from Superior, Wisconsin, to Chicago, Illinois. In order to provide for these real property acquisitions by Enbridge Mustang, the Partnership had made non interest bearing cash advances to Enbridge Mustang. As Enbridge Mustang disposes of the real property, the advances are repaid. Under the terms of the agreement, the Partnership reimburses Enbridge Mustang for the net cost of acquiring, holding and disposing of the real property. The advances amounted to $11.0 million at December 31, 1999 (1998 – $49.4 million). Lakehead is authorized by its Board of Directors to provide loans to the Partnership, on an uncommitted basis, in an amount not to exceed U.S. $200 million. In late March 1999, the Partnership borrowed U.S. $25.0 million from Lakehead at an interest rate of 7.75%. This loan was repaid in early April 1999. In late September 1998, the Partnership borrowed U.S. $37.0 million from Lakehead at an interest rate of 8.75%. This loan was repaid in early October 1998. 16. COMMITMENTS AND CONTINGENCIES Jose Crude Oil Storage and Ship Loading Terminal In 1999, the Corporation entered into an agreement to acquire, through a Venezuelan general partnership, a 45% interest in the U.S.$385 million Jose Crude Oil Storage and Ship Loading Terminal in Venezuela from PDVSA Petroleos y Gas, S.A., a subsidiary of Petroleos de Venezuela, S.A. The project entails the acquisition and operation of existing onshore and offshore terminaling facilities within the Jose Industrial Complex (“Terminal”), a large petroleum and petrochemical complex. The Terminal handles crude oil from eastern Venezuelan fields for loading onto tankers for export, with throughput capacity of approximately 800,000 barrels per day. The Venezuelan Partnership has not received the final assent from the Venezuelan Government to complete the acquisition. During the intervening period, PDVSA has engaged the Partnership to operate the Terminal on its behalf. During 1999, the Corporation earned $6.3 million in fees for operating the Terminal. 51 T H E E N E R G Y B R I D G E Enbridge Consumers Gas Enbridge Consumers Gas is aware that the remediation of discontinued manufactured gas plant sites may become an issue in the future. The probable overall cost of remediation measures 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 Consumers 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 of costs of a similar nature in rates. Enbridge Consumers Gas expects that, if it is found that it 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. In April 1994, an action was commenced against Enbridge Consumers Gas by a customer alleging that the OEB approved late payment penalties charged to customers were contrary to Canadian federal law and seeking certification of the action as a class action. The claim sought $112 million in restitutionary payments and other relief not calculated or quantified in the claim on behalf of all people who were customers of Enbridge Consumers Gas who had paid or been charged such penalties since April 1981. The class action was not certified by the Court although the Class Proceedings Committee, established under the Ontario Class Proceedings Act, 1992 (the “92 Act”) decided that it would fund the action. In February 1995, Mr. Justice Winkler, of the Ontario Court of Justice, General Division, issued a judgement in favour of Enbridge Consumers Gas dismissing the class action lawsuit. He concluded that the late payment charge is not interest payable on a credit transaction, but was an incentive to customers to pay their bills by a certain date. He held that Section 347 of the Criminal Code (Canada), which deals with interest on credit transactions, did not apply. In March 1995, the plaintiff’s solicitors filed notice of an appeal of the decision of the trial judge. In September 1996, the Court of Appeal heard and dismissed the appeal. The plaintiff was granted leave to appeal to the Supreme Court of Canada from the decision of the Court of Appeal and the appeal was heard in March 1998. On October 30, 1998, the Supreme Court allowed the appeal and set aside the trial court’s summary judgement dismissing the action. The Supreme Court rejected the argument of Enbridge Consumers Gas with respect to Section 347 and remitted the matter back to the trial court for determination of all other issues including the other defenses raised in pleadings but not yet heard in court and for proceedings in accordance with the 1992 Act. Enbridge Consumers Gas intends to defend the action before the Ontario Court. Further motions for summary judgement and related matters have been brought by both the plaintiff and Enbridge Consumers Gas to be heard by the Ontario Court commencing March 20, 2000. U.S. Master Limited Partnership Lakehead has agreed to indemnify the Partnership from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer of its pipeline operations to the Partnership in 1991. This indemnification does not apply to amounts that the Partnership 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, Lakehead, as the General Partner, is subject to recourse with respect to a portion of the Partnership’s long term debt which amounted to U.S. $585 million at December 31, 1999. Corporate Provisions have been made for potential liabilities, if any, resulting from claims against the Corporation arising in the normal course of business. Furthermore, in the case of income tax reassessments, where deemed appropriate, advance tax payments are made to forestall non deductible interest potentially resulting from the outcome of contested reassessments. Such payments are reflected in receivables in the statement of financial position. The ultimate outcome of these claims cannot be determined at this time. However, in the opinion of management, liabilities in excess of the provisions made, if any, would not be material. Year 2000 The Year 2000 Issue arises because many computerized systems use two digits rather than four to identify a year. Date sensitive systems may recognize the year 2000 as 1900 or some other date, resulting in errors when information using year 2000 dates is processed. To the reporting date, the Year 2000 Issue has not had a negative impact on the Corporation’s ability to conduct normal business operations, nor to the knowledge of the Corporation has had a significant effect on the operations of its customers, suppliers or other third parties providing critical services. 52 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T 17. SUBSEQUENT EVENT There are currently unrecorded deferred income taxes, related to the rental assets, in the amount of approximately $168 million. Enbridge Consumers Gas applied to the OEB for full recovery of these taxes in future gas distribution rates, as ratepayers had benefited from the tax deductions in prior years by means of lower gas distribution rates. In March 1999, the OEB released its decision and determined that $50 million of the projected amount may be recovered in future utility rates, and a further $42 million in refunds from Revenue Canada relating to a change in its assessing practice can be used to offset this deferred tax liability, leaving $76 million in future income tax liabilities to be borne by the shareholder. In October 1999, Enbridge Consumers Gas filed an Application for Judicial Review asking the Divisional Court, Superior Court of Justice to set aside the OEB’s order, and that the matter of the deferred taxes be referred back to the OEB for a rehearing. The Application also seeks a declaration that Enbridge as the common shareholder of Enbridge Consumers Gas is not responsible for deferred taxes and that Enbridge Consumers Gas be provided a full and fair opportunity to be heard with respect to any considerations which may have led, or may lead, to the conclusion that deferred taxes are the responsibility of the shareholder. The decision of the Divisional Court, Superior Court of Justice on whether to hear the appeal will be issued in due course. On October 1, 1999, immediately prior to the transfer of the rental assets to the Energy Services segment, Enbridge Consumers Gas adopted the new CICA Handbook recommendations with respect to income taxes which are effective January 1, 2000. Under the quarter lag basis of consolidation, the timing of this adoption coincides with the required adoption by the Corporation. As a result of adopting this new accounting standard and recording the $168 million of deferred income taxes associated with the rental assets, the Corporation will record a charge to retained earnings in the amount of $76 million, as well as a regulatory asset of $50 million, reflecting the future recovery from ratepayers, and will recharacterize $42 million in deferred credits as future income taxes payable. 18. UNITED STATES ACCOUNTING PRINCIPLES As a registrant with the United States Securities and Exchange Commission, the Corporation is required to reconcile its financial results for significant differences between generally accepted accounting principles in Canada (Canadian GAAP) and those accepted in the United States (U.S. GAAP). Although the accounting bodies of the two countries are moving towards harmonization of accounting principles, current differences with U.S. GAAP result in variations in reported earnings as well as differences in presentation and disclosure. The following information describes the effect of differences between Canadian and U.S. GAAP on the Corporation’s consolidated financial statements: Earnings and Comprehensive Income Year ended December 31, Earnings under Canadian GAAP Deferred income taxes Preferred securities distributions Earnings under U.S. GAAP Foreign currency translation adjustment Comprehensive income Financial Position December 31, Accounts receivable and other Long term investments Deferred charges and other Property, plant and equipment, net Accounts payable and other Long term debt Deferred credits Deferred income taxes Preferred securities Retained earnings Foreign currency translation adjustment (debit) 1999 299.8 — (5.0) 294.8 (14.8) 280.0 1998 240.9 — — 240.9 (22.0) 218.9 1999 1998 Canada 678.5 1,051.6 278.7 6,770.7 494.6 5,284.8 157.8 254.5 341.1 503.1 (23.9) U.S. 646.0 1,084.0 1,699.2 7,178.2 464.2 5,625.9 162.3 2,108.3 — 481.1 (1.9) Canada 611.3 676.9 212.1 6,364.2 540.9 4,502.3 230.4 266.4 — 407.6 (9.1) 1997 217.3 (9.6) — 207.7 9.6 217.3 U.S. 735.5 710.1 1,463.6 6,764.2 509.4 4,502.3 302.4 2,034.8 — 385.6 12.9 53 T H E E N E R G Y B R I D G E Under U.S. GAAP, deferred income taxes of integrated foreign operations are considered monetary and translated at current exchange rates. Under Canadian GAAP, deferred income tax liabilities of integrated foreign operations are considered non monetary and translated at historical exchange rates. Under U.S. GAAP, the Corporation’s Preferred Securities and related distributions would be treated entirely as debt and interest expense, respectively. Under Canadian GAAP, where repayment of the indebtedness is payable in whole or in part through equity instruments the instrument is apportioned into debt and equity components. The fair value of the equity component, when classified as long term debt under U.S. GAAP, is $326.8 million at December 31, 1999. Under U.S. GAAP, deferred income tax liabilities are recorded for regulated operations which follow the taxes payable method. As these deferred income taxes are recoverable through future revenues, a corresponding deferred asset is also recorded. These assets and liabilities reflect changes in enacted income tax rates. U.S. GAAP requires that the cost of postretirement benefits be determined using the accrual method. The application of the accrual method of accounting for pension and other postretirement benefits for regulated operations has no effect on earnings as any difference from the allowed method of recovery is recognized as a deferred asset or credit and would be recovered or refunded, respectively, through the regulatory process. The cost of these benefits as they relate to non regulated operations would not have a material effect on earnings. For business acquisitions, the purchase price allocation reflects the recognition of additional deferred income tax liabilities on the excess of the purchase prices over the net book value of assets acquired and liabilities assumed. A corresponding increase to property, plant and equipment acquired is also recognized. In addition, a portion of the purchase price is allocated to the unrecognized excess of pension plan assets over the projected benefit obligations at the date of acquisition. However, an offsetting deferred liability, reflecting the expected future refund of such excess through the regulatory process, is also recognized. Under U.S. GAAP, the Corporation’s investments in joint ventures are accounted for using either the equity or the cost method instead of proportionate consolidation. Basic and fully diluted earnings per share applicable to common shareholders under U.S. GAAP for the year ended December 31, 1999 were $1.91 (1998 – $1.66; 1997 – $1.51). At December 31, 1999, accumulated other comprehensive income consisted solely of an accumulated foreign currency translation adjustment of $(1.9) million (1998 – $12.9 million). In addition to the above, included in the 1998 current portion of long term liabilities in the Statement of Financial Position under Canadian GAAP is $100 million of Cumulative Redeemable Retractable Preference Shares of Enbridge Consumers Gas which were redeemed in fiscal 1999. Under U.S. GAAP, these shares would be accounted for as non controlling (minority) interest. The following additional disclosures are required under U.S. GAAP: Deferred Income Taxes Deferred income taxes have arisen as a result of the following items: December 31, Differences between capital cost allowance and depreciation: Property, plant and equipment Long term investment Recognition of taxes on: Acquisition purchase price excess Incremental revenue required for recovery of unrecorded taxes Transfer of U.S. pipeline business to Master Limited Partnership Other Deferred income taxes Pension Plans Disclosures required under U.S. GAAP for pension plans are as follows: Change in Pension Benefit Obligations December 31, Pension benefit obligations at beginning of year Service cost Interest cost Amendments Pension plan participants’ contributions Actuarial (gain) loss Benefits paid Effect of exchange rate changes Pension benefit obligations at end of year 1999 1998 765.3 25.6 431.1 598.4 216.4 71.5 781.7 25.9 425.3 531.6 222.2 48.1 2,108.3 2,034.8 1999 634.7 19.5 41.8 — 5.6 (32.5) (30.8) (4.3) 634.0 1998 578.9 17.6 41.1 1.7 5.7 8.2 (25.2) 6.7 634.7 54 Change in Pension Plan Assets December 31, Fair value of pension plan assets at beginning of year Actual return on plan assets Employer’s contributions Pension plan participants’ contributions Benefits paid Other Effect of exchange rate changes Fair value of pension plan assets at end of year Net Pension Asset December 31, Pension plan assets in excess of projected benefit obligations Unrecognized prior service cost Unrecognized pension plan surplus Unrecognized net gain Net pension asset under U.S. GAAP Pension Cost 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 the Partnership Pension (credit) expense under U.S. GAAP E N B R I D G E 1 9 9 9 A N N U A L R E P O R T 1999 896.3 146.9 7.5 5.6 (30.8) 17.5 (9.0) 1,034.0 1999 400.0 7.2 (2.2) (231.3) 173.7 1998 17.6 41.1 (54.1) (5.2) 3.3 2.7 1998 900.7 7.6 4.0 5.7 (25.2) (7.4) 10.9 896.3 1998 261.6 8.9 (3.0) (114.1) 153.4 1997 14.5 40.4 (54.7) (4.2) 0.7 (3.3) 1999 21.0 41.8 (65.6) (6.8) 6.1 (3.5) Economic Assumptions The most significant economic assumptions made in the measurement of the pension costs and the projected benefit obligations of the pension plans were as follows: Year ended December 31, 1999 1998 1997 Discount rate Average rate of salary increases Average rate of return on pension plan assets 6.3–7.5% 4.0–4.5% 7.5–8.0% 6.3–8.5% 4.5–5.5% 7.5–8.5% 6.5–8.5% 4.8–5.5% 8.0–8.5% Postretirement Benefits Other Than Pensions Postretirement benefits other than pensions include supplemental health, dental and life insurance coverage for retired employees. U.S. GAAP requires the accrual, during the years the employees render service, of the expected cost of providing these benefits to employees, their beneficiaries and qualified dependants. Postretirement Benefit Obligations Based on actuarial valuations dated January 1, 1999, the status of the Corporation’s postretirement benefit plans was as follows: Change in Postretirement Benefit Obligations December 31, 1999 1998 Postretirement obligations at beginning of year Service cost Interest cost Benefit plan participants’ contributions Actuarial loss Benefits paid Effect of exchange rate changes Postretirement benefit obligations at end of year 112.0 3.9 7.7 0.3 0.2 (3.0) (1.7) 119.4 85.7 3.2 7.1 0.2 17.0 (3.6) 2.4 112.0 55 T H E E N E R G Y B R I D G E Change in Postretirement Benefit Plan Assets December 31, Fair value of postretirement benefit plan assets at beginning of year Actual return on plan assets Employer’s contributions Benefit plan participants’ contributions Benefits paid Effect of exchange rate changes Fair value of postretirement benefit plan assets at end of year Net Postretirement Benefit Obligations December 31, Accumulated postretirement benefit obligations in excess of plan assets Unrecognized prior service cost Unrecognized net transition obligation Unrecognized net loss Net postretirement benefit obligations under U.S. GAAP Postretirement Benefit Cost Year ended December 31, Service cost Interest cost Expected return on plan assets Amortization and deferral of unrecognized amounts Amount charged to the Partnership Postretirement benefit cost under U.S. GAAP 1999 1998 18.4 0.3 5.0 0.3 (3.0) (1.0) 20.0 1999 99.4 (7.8) (41.7) (10.4) 39.5 13.0 2.3 5.3 0.2 (3.6) 1.2 18.4 1998 93.6 (8.4) (45.8) (10.6) 28.8 1999 3.9 7.7 (0.8) 4.6 (3.1) 12.3 1998 1997 3.2 7.1 (0.8) 4.2 (3.1) 10.6 2.5 6.7 (0.5) 3.6 (2.7) 9.6 Economic Assumptions The most significant economic assumptions made in the measurement of the postretirement benefit costs and the projected benefit obligations were as follows: Year ended December 31, 1998 1997 1999 Discount rate Medical cost trend rate Dental cost trend rate 6.5–7.5% 4.5–6.8% 4.5–6.0% 6.5–8.5% 4.5–7.0% 4.5–6.0% 6.5–7.3% 4.5–7.0% 6.0% A 1% change in the assumed medical and dental care trend rate would result in a $17.1 million change in the accumulated postretirement benefit obligations and a $2.7 million change in postretirement benefit costs. Stock Option Plan The Corporation provides stock based compensation in the form of stock options to full time key employees. At the time of grant, the exercise price is equal to the market price and accordingly, no compensation expense is recognized under the Corporation’s accounting policies. Under U.S. GAAP, a compensation cost is measured at the grant date in accordance with a fair value based method utilizing an option pricing model. Companies electing not to recognize the compensation cost determined under the fair value based method must make pro forma disclosure of net income and net income per share as if that method of accounting had been applied. Had the Corporation applied the fair value based method, the adjustment to earnings and earnings per share would not have been material. Accounting for Derivative Instruments and Hedging Activities On June 30, 1998, the Financial Accounting Standards Board (FASB) issued FAS 133 Accounting for Derivative Instruments and Hedging Activities effective January 1, 2000. On June 23, 1999, the FASB issued FAS 137 which deferred the effective date of FAS 133 by one year. The new standard has not been adopted by the Corporation as at December 31, 1999 and the impact on the consolidated financial statements has not been determined. 56 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Supplementary Information (unaudited) SELECTED QUARTERLY FINANCIAL DATA1 (Canadian dollars in millions, except per share amounts) 1999 Quarters Operating revenue Operating income Earnings applicable to common shareholders Earnings per common share Dividends per common share 1998 Quarters Operating revenue Operating income Earnings applicable to common shareholders Earnings per common share Dividends per common share QUARTERLY SHARE TRADING INFORMATION 1 The Toronto and Montreal Stock Exchanges 1999 Quarters (Canadian dollars) First 588.4 121.7 69.8 0.47 0.2875 First 628.1 139.5 62.2 0.43 0.2725 High Low Close Volume (thousands) 1998 Quarters (Canadian dollars) High Low Close Volume (thousands) The NASDAQ National Market 1999 Quarters (U.S. dollars) High Low Close Volume (thousands) 1998 Quarters (U.S. dollars) High Low Close Volume (thousands) Second 1,049.9 283.6 178.4 1.18 0.3025 Second 894.4 256.6 147.6 1.02 0.2725 First 36.33 33.25 33.43 12,576 First 33.75 30.25 31.83 17,256 First 24.13 22.31 22.38 147 First 23.50 21.32 22.32 228 Third 552.2 105.1 36.5 0.24 0.3025 Third 466.0 90.8 38.8 0.27 0.2875 Second 35.00 31.50 33.75 14,106 Second 33.33 30.00 33.13 18,648 Second 24.88 21.38 23.00 181 Second 22.63 20.82 22.63 158 Fourth 497.2 68.8 3.2 0.02 0.3025 Fourth 353.2 5.8 (7.7) (0.06) 0.2875 Third 33.95 29.80 31.75 12,385 Third 34.88 28.95 32.03 14,732 Third 23.69 20.50 21.63 184 Third 23.63 18.75 20.94 150 Total 2,687.7 579.2 287.9 1.91 1.1950 Total 2,341.7 492.7 240.9 1.66 1.1200 Fourth 32.00 28.60 28.65 12,716 Fourth 35.70 31.00 35.25 10,888 Fourth 21.75 19.25 20.13 83 Fourth 23.03 20.13 22.97 102 1 Comparative amounts have been restated to reflect the split of common shares on a two for one basis on May 10, 1999. 57 T H E E N E R G Y B R I D G E Five Year Consolidated Highlights FINANCIAL AND OPERATING INFORMATION 1 (Canadian dollars in millions, except per share amounts) Segmented Earnings Liquids Pipelines Gas Distribution 2 International Gas Pipelines and New Business Development Energy Services Corporate and Other Earnings Applicable to Common Shareholders Cash Flow Data Cash provided from operating activities Capital expenditures Dividends paid on common shares Operating Data Liquids Pipelines 3 Deliveries (thousands of barrels per day) Barrel miles (billions) Average haul (miles) Gas Distribution Distribution volume (billion cubic feet) Number of active customers (thousands) Degree day deficiency 4 (degrees Celsius) Actual Forecast based on normal weather 1999 165.3 99.2 28.7 31.2 (2.5) (34.0) 287.9 1998 143.2 100.2 24.3 6.3 (6.2) (26.9) 240.9 495.1 783.7 186.4 312.4 1,388.4 168.3 2,023 696 946 402 1,466 3,460 4,060 2,136 771 989 397 1,414 3,352 4,079 1997 108.4 132.1 16.1 (2.4) (7.5) (29.4) 217.3 437.8 651.4 147.1 2,083 771 1,014 428 1,362 4,011 4,003 1996 92.6 111.8 4.8 – – (28.9) 180.3 479.6 560.5 125.9 1,970 768 1,069 429 1,307 4,209 4,058 1995 80.2 75.5 1.6 – – (26.9) 130.4 415.4 428.7 116.3 1,754 771 1,204 391 1,264 3,748 3,955 1 2 3 4 Certain comparative amounts have been reclassified to conform with the current year’s basis of presentation. The highlights of the Gas Distribution activities reflect the results of Enbridge Consumers Gas and other gas distribution assets on a quarter lag basis of consolidation. Liquids Pipelines operating highlights include the statistics of the 15.3% owned portion of the mainline system located in the United States. 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. 58 E N B R I D G E 1 9 9 9 A N N U A L R E P O R T Five Year Consolidated Highlights SHAREHOLDER AND INVESTOR INFORMATION 1 (per share amounts in Canadian dollars) Average common shares outstanding weighted monthly during the year (thousands) Number of registered common shareholders at year end 150,995 8,877 145,448 9,207 137,808 10,036 124,330 10,060 113,582 8,824 1999 1998 1997 1996 1995 Common Share Trading (TSE and ME) High Low Close Volume (millions) Per Common Share Data Earnings applicable to common shareholders Cash provided from operating activities Dividends on common shares Financial Ratios Return on average common 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 36.33 28.60 28.65 51.8 1.91 3.28 1.195 14.3% 6.6% 67.4% 63.7% 2.0x 62.6% 35.70 28.95 35.25 61.5 1.66 2.15 1.120 13.8% 6.6% 69.7% 64.8% 2.0x 67.7% 32.85 19.53 32.70 55.3 1.58 3.18 1.060 14.2% 7.0% 67.7% 62.5% 2.4x 67.3% 21.00 15.88 19.98 52.2 1.45 3.86 1.015 15.0% 7.6% 68.4% 62.5% 2.3x 70.0% 16.50 13.44 15.94 54.1 1.15 3.66 1.000 13.2% 7.0% 69.1% 62.7% 1.8x 87.0% 1 2 3 4 5 6 Comparative amounts have been restated to reflect the split of common shares on a two for one basis on May 10, 1999 and current year classifications. Earnings applicable to common shareholders divided by average common equity (weighted monthly during the year). Sum of earnings, minority 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 (minority) interest, deferred income taxes, deferred credits, and total debt (excluding short term borrowings which finance gas in storage). Total long term debt (including current portion) divided by the sum of total long term debt, shareholders’ equity and non controlling (minority) interest. Sum of earnings before income taxes, minority interest and interest expense, divided by interest expense. Dividends per common share divided by earnings per share applicable to common shareholders. 59 T H E E N E R G Y B R I D G E Shareholder and Investor Information Common and Preferred Shares Debentures Annual Meeting The Common Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange under the ticker symbol “ENB” and in the United States on The NASDAQ National Market under “ENBR”. The Preferred Shares, Series A, of Enbridge Inc. trade in Canada on the Toronto Stock Exchange under the symbol “ENB.PR.A”. Registrar and Transfer Agent in Canada CIBC Mellon Trust Company 320 Bay Street, ground floor Toronto, Ontario M5H 4A6 Telephone: (416) 643-5000 Toll free: (800) 387-0825 Internet: www.cibcmellon.ca CIBC Mellon Trust Company also has offices in Halifax, Montreal, Winnipeg, Calgary, Regina and Vancouver. Co-Registrar and Co-Transfer Agent in the United States ChaseMellon Shareholder Services L.L.C. 120 Broadway, 13th floor New York, NY, 10271 U.S.A. Attention: Stock Transfer Toll free: (800) 526-0801 Preferred Securities Enbridge Preferred Securities, Series B and C, trade in Canada on the Toronto Stock Exchange under the ticker symbols “ENB.PR.B” and “ENB.PR.C”, respectively. The registrar and transfer agent is Montreal Trust Company. The registrar and trustee for Enbridge Deben- tures is Montreal Trust Company — Montreal, Toronto, Winnipeg, Edmonton and Vancouver. The Annual Meeting of Shareholders will be held at the Palliser Hotel, Calgary, Alberta, Canada, at 1:30 p.m. on Thursday, April 27, 2000. Auditors Form 40-F PricewaterhouseCoopers LLP Shareholder Inquiries If you have inquiries regarding the following: (cid:2) Dividend Reinvestment and Share Purchase Plan (cid:2) change of address (cid:2) share transfer (cid:2) lost certificates (cid:2) dividends (cid:2) duplicate mailings Please contact the registrar and transfer agent — CIBC Mellon Trust Company in Canada or ChaseMellon in the United States. Other Investor Inquiries If you have inquiries regarding the following: (cid:2) additional financial or statistical information (cid:2) industry and company developments (cid:2) latest news releases or investor presentations Please contact Enbridge Investor Relations or visit Enbridge’s web site at www.enbridge.com. Investor Relations Director, Investor Relations Enbridge Inc. 2900, 421 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 4K9 Toll free: (800) 481-2804 Facsimile: (403) 231-5989 The Corporation files annually with the Securi- ties 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 Corporation. Dividend Reinvestment and Share Purchase Plan, and Dividend Direct Deposit Enbridge Inc. offers a Dividend Reinvestment and Share Purchase Plan that enables share- holders 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 at any of the locations listed above. Registered Office Enbridge Inc. 2900, 421 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 4K9 Telephone: (403) 231-3900 Facsimile: (403) 231-3920 Internet: www.enbridge.com Le présent document est disponible en français. 2000 Dividend Information for Common Shares and Preferred Shares, Series A Record date Payment date Common Share Dividend Reinvestment Plan (DRIP) enrolment cut-off date Common Share Purchase Plan cut-off date for DRIP (cheques can be post-dated to the payment date) 1st Q Feb. 11 March 1 Feb. 4 Feb. 23 2nd Q May 12 June 1 May 5 May 25 3rd Q Aug. 11 Sept. 1 Aug. 3 Aug. 25 4th Q Nov. 17 Dec. 1 Nov. 10 Nov. 24 60 Corporate Information BOARD OF DIRECTORS James J. Blanchard Senior Partner Verner, Liipfert, Bernhard, McPherson & Hand, Attorneys Beverly Hills, Michigan J. Lorne Braithwaite President and Chief Executive Officer Cambridge Shopping Centres Limited Thornhill, Ontario André Caillé President and Chief Executive Officer Hydro-Québec, Montreal, Quebec E. Susan Evans Company Director Calgary, Alberta William R. Fatt Chairman and Chief Executive Officer Fairmont Hotels & Resorts, Toronto, Ontario F. William Fitzpatrick Company Director Paradise Valley, Arizona Richard L. George President and Chief Executive Officer Suncor Energy Inc., Calgary, Alberta Louis D. Hyndman Senior Partner, Field Atkinson Perraton, Barristers & Solicitors, Edmonton, Alberta Brian F. MacNeill President & Chief Executive Officer Enbridge Inc., Calgary, Alberta Robert W. Martin Company Director, Toronto, Ontario Donald J. Taylor Chairman, Enbridge Inc., Jacksons Point, Ontario E N B R I D G E 1 9 9 9 A N N U A L R E P O R T SENIOR MANAGEMENT Brian F. MacNeill President & Chief Executive Officer Mel F. Belich Senior Vice President, International Development & Corporate Law; Chairman, Enbridge International Inc. J. Richard Bird Senior Vice President, Corporate Planning & Development and President, Enbridge Consumers Energy Inc. Patrick D. Daniel President & Chief Operating Officer, Energy Delivery Bonnie D. DuPont Senior Vice President, Human Resources & Public Affairs Stephen J.J. Letwin President & Chief Operating Officer, Energy Services Rudy G. Riedl President, Enbridge Consumers Gas Derek P. Truswell Senior Vice President & Chief Financial Officer Stephen J. Wuori President, Enbridge Pipelines Inc. Happy Birthday Enbridge Enbridge Inc. celebrated its 50th anniversary in 1999 — the company that became Enbridge in 1998 began life when it was incorporated as Interprovincial Pipe Line in April 1949. Employees organized over 40 events in centres in North and South America. Celebrations ranged from community events to dinners, and from golf tournaments to the ’50s-style family picnic shown here for over 600 Edmonton area employees, annuitants and their families. Federal Justice Minister and Edmonton MP Anne McLellan was one of the guests. Designed and Produced by Rivard Communications Inc., Calgary Printed by Ronalds Printing, Calgary w w w . e n b r i d g e . c o m Enbridge common shares trade on the Toronto Stock Exchange in Canada under the symbol “ENB” and on The NASDAQ National Market in the United States under the symbol “ENBR.” For more information contact: Enbridge Inc. 2900 Canada Trust Tower 421 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 4K9 Telephone: (403) 231-3900 Fax: (403) 231-3920 

Continue reading text version or see original annual report in PDF format above