Enbridge Annual Report 2002

FY2002 Annual Report · Enbridge

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Enduring Values, Sustainable Growth

2 0 0 2 A n n u a l R e p o r t

Highlights 01 Letter to Shareholders 02 An Enbridge Profile 05 Management

s Discussion and Analysis 14

Financial Statements and Notes 39 Supplementary Information 70 Shareholder, Investor and Corporate Information 73

When used in this annual report, the words “anticipate”, “expect”, “project”, “believe”, “estimate”, “forecast” and similar expressions are intended to identify
forward looking statements, which include statements relating to pending and proposed projects. Such statements are subject to certain risks, uncertainties and
assumptions pertaining to operating performance, regulatory parameters, weather and economic conditions and, in the case of pending and proposed projects, risks
relating to design and construction, regulatory processes, obtaining financing and performance of other parties, including partners, contractors and suppliers.

“At Enbridge, we pride ourselves on our consistent, predictable and sustainable growth. We also pride ourselves

on our corporate values: it has been Enbridge’s adherence to its principles and culture that has enabled the

Company to succeed in spite of the crisis of confidence that has engulfed markets for over a year. Of course,

values are embodied in people, not structures. And that is why we have focused on the people of Enbridge in this

year’s annual report. It is our employees, our senior management team and our Board of Directors who live our

values, and in so doing continue to grow Enbridge and add value for our shareholders.”

Patrick D. Daniel. President & Chief Executive Officer

The photographs on the front
cover represent the diversity of
the people of Enbridge. Most
are employees, representing all
business units, all job levels,
all major geographic areas
of operation. Others are key
stakeholders — customers,
neighbours and shareholders.
Collectively, they are “Enbridge”.

* ENBRIDGE, the ENBRIDGE LOGO and the ENBRIDGE ENERGY SPIRAL are trademarks

or registered trademarks of Enbridge Inc. in Canada and other countries.

H I G H L I G H T S

H i g h l

i g h t s

Dividends Per Common Share
(dollars per share)

Earnings Per Common Share
(dollars per share)

0
0
0
.
1

5
1
0
.
1

0
6
0
.
1

0
2
1
.
1

5
9
1
.
1

0
7
2
.
1

0
0
4
.
1

0
2
5
.
1

5
1
.
1

5
4
.
1

8
5
.
1

6
6
.
1

1
9
.
1

4
5
.
2

1
9
.
2

0
6
.
3

5
1
0
.
1

5
4
5
.
0

Financial (millions of Canadian dollars, except per share amounts)
Earnings Applicable to Common Shareholders

Continuing Operations
Discontinued Operations

Per Common Share Amounts

Earnings — Continuing Operations
Earnings — Discontinued Operations

Dividends

Common Share Dividends Paid
Return on Average Common Shareholders’ Equity
Debt to Debt Plus Shareholders’ Equity at Year End

Operating
Energy Transportation 1

Deliveries (thousands of barrels per day)
Barrel miles (billions)
Average haul (miles)

Energy Distribution 2

Volume of gas distributed (billion cubic feet)
Number of active customers (thousands)
Degree day deficiency 3 (degrees Celsius)

Actual
Forecast based on normal weather

2002

334.2
242.3
576.5

2.09
1.51
3.60
1.52
251.1
19.9%
64.4%

2002

2,088
705
925

410
1,623

3,362
3,700

2001

413.2
45.3
458.5

2.63
0.28
2.91
1.40
227.5
18.6%
72.9%

2001

2,109
695
903

427
1,571

3,766
3,816

2000

357.7
34.6
392.3

2.32
0.22
2.54
1.27
202.1
18.6%
69.4%

2000

2,072
735
972

421
1,520

3,569
3,929

1 Energy Transportation operating highlights include the statistics of the Lakehead System and wholly-owned liquid pipeline operations.
2 Highlights of Energy Distribution reflect the results of Enbridge Gas Distribution and other gas distribution operations on a quarter lag basis for the years
ended September 30, 2002, 2001 and 2000. Energy Distribution volumes and the number of active customers are derived from the aggregate system supply
and direct purchase gas supply arrangements.

3 Degree day deficiency is a measure of coldness. It is calculated by accumulating for each day in the period the total number of degrees each day by which

the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Toronto area.

E N B R I D G E

I N C .

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t e r

t o S h a r e h o l d e r s

L E T T E R T O S H A R E H O L D E R S

Enbridge has come through the most turbulent year in the history of the pipeline and utility sector in a very

strong position relative to our North American peer group. Although our total return to shareholders over the

year was only 1.5%, compared to our ten-year average of more than 15%, we did very well relative to an 11%

decline in the value of stocks listed on the Toronto Stock Exchange, a 20% decline in the New York Stock

Exchange Composite Index, and a 33% decline in the U.S. pipeline index.

Our relative strength came from an unwavering vision, a focus on asset management, and low-risk projects.

Where the companies in our sector sought higher risk businesses such as commodity marketing and trading

to meet growth targets, Enbridge did not. We stuck to our core competencies of liquids pipelining, gas distribution

and gas pipelining, which continue to provide high single digit growth in earnings per share. As a result of

excellent future earnings potential from these businesses, we remain committed to the strategy that has made us

one of North America’s leading energy delivery companies. We strive to be the best in this sector, as measured

by total shareholder return and return on equity over a sustained period.

In 2002, not only did we grow our earnings to a record level of $576.5 million, an 8% increase in adjusted

earnings per share, we also reduced debt substantially. Our consolidated debt-to-equity leverage has gone from

approximately 72% to 64% and will be further reduced in 2003. We achieved the debt reduction through strong

cash flow from operations, sale of non-core assets including our Energy Services business and Cornwall

Electric, and new equity issuances.

Our confidence in the future growth of the Company is exemplified by our excellent 10-year track record

of dividend growth. In January 2002 we increased the dividend by 8.6%, and in January 2003 another 9%

to $0.415 per common share per quarter.

Over the past year we have made significant progress in each of our five major growth platforms.

Firstly, we continued the expansion of our crude oil pipeline system by embarking on Phase III of our Terrace

project which is on schedule and on budget to add about 10% to our delivery capacity of 1.7 million barrels per

day in 2003. This new capacity will serve Alberta’s oil sands, where billions of dollars will be spent over the

next decade to produce crude oil for U.S. and Canadian markets. Security of supply issues in the U.S. resulting

from disruptions in supply from Venezuela and the Middle East will increase demand for reliable Canadian

crude. Our pipeline system carries about 65% of the crude from the oil sands through the world’s longest crude

oil pipeline. We also are very well positioned through our Norman Wells pipeline in the North to participate in

and benefit from any liquids production associated with the huge gas reserves of the Mackenzie Delta.

E N B R I D G E

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t o S h a r e h o l d e r s

Our second growth platform — natural gas distribution — also is experiencing consistently strong expansion.

We have added more than 50,000 new customers every year for the past six years, making Enbridge Gas

Distribution one of North America’s fastest growing utilities. Rapid growth in the metropolitan Toronto area

is forecast to continue for several years.

Thirdly, our natural gas pipelining business was expanded significantly in 2002 as we increased our ownership

position in the Alliance Pipeline from approximately 21% to over 37%. Alliance and Vector Pipeline supply

key markets in Eastern Canada and the U.S. Midwest, and are well positioned to benefit from future natural gas

production from northern gas in Prudhoe Bay and the Mackenzie Delta. Our extensive northern operating

experience also should enable us to be of service to gas producer customers in the North.

With our strong core businesses, excellent growth potential

and corporate values, we are very well positioned to continue to provide

excellent returns to you, the Enbridge shareholder.

Enbridge’s fourth growth platform is our master limited partnership, Enbridge Energy Partners, L.P. (EEP)

which holds not only the U.S. portion of our crude oil pipeline, but now also the gas pipeline and midstream

assets formerly owned by Enbridge Midcoast Energy. EEP’s future will be driven by increasing crude oil

volumes from the oil sands as well as its interstate gas pipelines, end-user pipelines, gas gathering systems and

processing plants. In addition to organic volume growth, EEP will seek small to medium-sized “bolt-on” asset

acquisitions in our areas of influence — the Gulf Coast and Midwest regions of the U.S.

Enbridge’s international operations have become our fifth growth platform and have provided consistent, reliable

earnings from equity investments in Colombia and Spain. We are very cautious and disciplined in seeking

international projects, and are not embarrassed at having made only two significant investments in the past ten

years. Our expertise and niche as one of the world’s largest independent crude oil pipeline companies makes

Enbridge a very favourable business partner. Our technology consulting company and fee-based operations

provide a low-cost way of evaluating new prospective projects.

We will continue our focus on energy delivery assets, which provide low-risk investments with consistent returns.

Over 95% of our operating income currently comes from such operations. In addition to continued expansions

and extensions to our core businesses, we intend to grow along the value chain by adding terminalling,

E N B R I D G E

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storage, and feeder systems. As our North American footprint expands, we reduce the risk to shareholders by

broadening the geographic areas in which we are involved and increasing the number of production basins

and energy markets we serve.

We continue to focus on operating efficiencies to provide the lowest possible tolls to our customers — our gas

distribution company has the lowest operating cost per unit of throughput of any in North America, and our

crude oil pipeline is among the very lowest in the world in terms of tolls per barrel mile.

Through modest investments in renewable energy and by reducing our direct greenhouse gas emissions to levels

below our 1990 levels, we will help meet the global challenge of climate change. We also will continue to work

for more effective engagement of the consuming public in the climate change solution.

The past accomplishments of Enbridge and our confidence in our future are largely attributable to our talented

employee base of approximately 4,000 people. We hire as much on values as on skills. Never has that been more

important than it was in 2002. We thank our employees for maintaining a culture and set of values that is critical

to sustaining confidence in Enbridge and its operations.

With our strong core businesses, excellent growth potential and corporate values, we are very well positioned

to continue to provide excellent returns to you, the Enbridge shareholder.

We also wish to thank two individuals who have served Enbridge so long and so well. Brian F. MacNeill, who

retired in December 2000 after almost a decade as Chief Executive Officer of the Company, has decided not to

stand for re-election to the Enbridge Board. Derek P. Truswell, Group Vice President & Chief Financial Officer

of Enbridge, is retiring effective April 1, 2003, after more than 34 years with the Company. Both of them will

be missed for their leadership, counsel and many contributions to Enbridge’s success.

On behalf of the Board of Directors:

Donald J. Taylor

Patrick D. Daniel

Chair of the Board of Directors

President & Chief Executive Officer

March 4, 2003

E N B R I D G E

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Enbridge is . . .

a leading North American energy delivery company

an experienced and knowledgeable asset manager

a company with a reputation for excellent growth prospects and a low-risk profile

a company with a track record of adding value for its shareholders

Enbridge Inc. conducts its business through a number of distinct business units, focused on the Company’s

core businesses — crude oil and liquids pipelines, natural gas pipelines, and natural gas distribution.

5
7

The Company is active internationally, but the bulk of its assets are in Canada and the United States.

ENBRIDGE:
❚ has its head office in Calgary, Alberta, and

employs approximately 4,000 people primarily

in Canada and the United States.

In 2002, Enbridge:
❚ delivered approximately 2.1 million barrels

In North America, Enbridge owns, operates or has

interests in:

approximately 21 000 kilometres (13,000 miles)

of crude oil mainline and feeder pipelines,

approximately 15 500 km (9,600 miles) of natural

gas transmission and gathering pipelines, and

of crude oil and liquids per day, and

approximately 30 000 km (18,600 miles) of mains

❚ distributed approximately 410 billion cubic

for transportation and distribution of natural gas.

feet of natural gas during the year.

E N B R I D G E

I N C .

❚
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❚
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❚
❚
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E N E R G Y
T R A N S P O R T A T I O N N O R T H

E N E R G Y
T R A N S P O R T A T I O N S O U T H

“ Unprecedented growth in oil sands production is driving a wide

“ We are focused on long-term growth through expanding

variety of opportunities for us. Our recent mainline expansions

existing liquids and natural gas systems and acquiring

will fill, requiring further capacity increases. In the oil sands

mature energy transportation assets. There are numerous

region, we’ll add additional pipeline capacity, tankage, laterals

potential acquisition opportunities available in the

and cavern storage. To capture the full production potential,

United States, and the Partnership provides a competitive

we will extend the reach of our mainline system to access

cost-of-capital vehicle for participation in this active energy

new markets for Canadian crude.”

infrastructure market.”

J. Richard Bird

Dan C. Tutcher

Group Vice President, Transportation North

Group Vice President, Transportation South

Energy Transportation North includes Enbridge

Energy Transportation South is responsible for

Pipelines, which owns and operates the Canadian

the Company’s energy delivery businesses in the

portion of the Enbridge crude oil mainline and

United States. Enbridge holds an effective 14.1%

operates the Lakehead and North Dakota systems

interest in Enbridge Energy Partners, L.P., which

in the United States. Energy Transportation North

owns energy transportation and midstream systems

also is responsible for Enbridge’s interests in the

including overland transportation and pipeline

Alliance and Vector natural gas pipelines, and the

gathering, transmission, processing and treating

midstream natural gas business in Western Canada.

businesses in the upper Midwest, Midcontinent

and Gulf Coast areas.

E N B R I D G E

I N C .

E N E R G Y D I S T R I B U T I O N

I N T E R N A T I O N A L

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“ Enbridge has delivered natural gas to communities in

“ Enbridge’s existing international investments are located in

Ontario for more than 150 years. Our role in the Ontario

Western Europe and Latin America. In addition to these regions,

market has changed, but our commitment to service a

we are open to evaluation of high-potential investments or

steadily expanding franchise area remains the same.

operating opportunities that arise elsewhere. We maintain a

We will continue to deliver a safe, reliable supply of

disciplined focus on equity, operating and technology projects

natural gas to all of our customers.”

that build upon our core expertise, and continue to develop

Stephen J.J. Letwin

strong affiliation relationships with our partners.”

Group Vice President, Distribution & Services

Mel F. Belich

Group Vice President, International

The core of Enbridge’s Energy Distribution business

Enbridge’s international activities, including CLH

segment is Enbridge Gas Distribution, which delivers

in Spain and OCENSA in Colombia, are developed

natural gas to more than 1.6 million customers in

and co-ordinated by wholly-owned Enbridge

Ontario, Quebec and part of New York State.

International Inc. The International Group is

Enbridge is also involved in the gas distribution

supported by other units within the Enbridge group

business through its interest in Noverco Inc. and

of companies, including Enbridge Technology Inc.,

is developing a natural gas distribution network

which is engaged in technical advisory services,

in the Province of New Brunswick through

contract operations, product sales and training

Enbridge Gas New Brunswick.

services which are provided to pipeline and

natural gas distribution industries globally.

E N B R I D G E

I N C .

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E N E R G Y
T R A N S P O R T A T I O N N O R T H

Norman
Wells

Zama

Edmonton

Hardisty

Kerrobert

Fort
McMurray

Regina

Cromer

Gretna

Montreal

Westover

Sarnia

Toronto
Buffalo

Fort
St. John

Edmonton

Chicago

Dawn

Liquids Pipelines
❚ Enbridge Pipelines Inc.
❚ Enbridge Pipelines (NW) Inc.
❚ Enbridge Pipelines (Athabasca) Inc.
❚ Enbridge Pipelines (Saskatchewan) Inc.

Natural Gas Pipelines
❚ Alliance Pipeline Limited Partnership (37.1%)
❚ Vector Pipeline Limited Partnership (45%)
Other
❚ AltaGas Services Inc. (40.3%)

E N E R G Y
T R A N S P O R T A T I O N S O U T H

Gretna

Clearbrook

Superior

Casper

Salt Lake City

Lockport
Mokena

Lewiston

Sarnia

Bay
City

Chicago

Toledo

Patoka

Houston

Enbridge Energy Partners, L.P. (14.1%)

Lakehead System
❚ North Dakota System
❚ Midcontinent and Gulf Coast Systems

❚ Enbridge Pipelines (Toledo) Inc.
❚ Mustang Pipe Line Partners (30%)
❚ Chicap Pipe Line Company (22.8%)
Frontier Pipeline Company (77.8%)

E N B R I D G E

I N C .

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❚
E N E R G Y D I S T R I B U T I O N

I N T E R N A T I O N A L

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Ottawa

Toronto

Montreal

Vermont

Coveñas

Bogota
C O L O M B I A

Jose
Terminal

Cusiana/
Cupiagua

❚ Enbridge Gas Distribution Inc.

Gazifère Inc. — an Enbridge Company
Niagara Gas Transmission Limited — an Enbridge Company
St. Lawrence Gas Company, Inc. — an Enbridge Company

❚ Noverco Inc. (32%), which owns:

Gaz Métropolitain and Company, Limited Partnership (77%),
which owns:

Vermont Gas Systems, Inc. (100%)
TQM Pipeline and Company, Limited Partnership (50%)

❚ Enbridge Gas New Brunswick Limited Partnership (63%)
❚ Aux Sable Liquids Products Inc. (30.9%)

S P A I N

Madrid

Barcelona

Enbridge International Inc.

❚ Oleoducto Central S.A. — OCENSA (24.7%)
❚ Compañia Logistica de Hidrocarburos CLH, S.A. (25%)

Enbridge Technology Inc. (global contracts)

S U S T A I N A B L E A N D O T H E R
B U S I N E S S D E V E L O P M E N T
O P P O R T U N I T I E S

❚ SunBridge Wind Power Project (50%)

Global Thermoelectric Inc. (strategic alliance)
Inuvik Gas Ltd. (33.3%)
Tidal Energy Marketing Inc. (50%)
NetThruPut Inc. (52%)

❚ Proposed Northern Natural Gas Pipelines

E N B R I D G E

I N C .

Prudhoe
Bay

Norman
Wells

Whitehorse

Inuvik

Fort
Simpson

Fort
St. John

Gull Lake

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P L A N N I N G & D E V E L O P M E N T

“ Our goal is to continue to position Enbridge for profitable

growth. Our strategic planning process identifies those

opportunities we can reasonably pursue over the next

five years. And for the longer term, we are positioning

Enbridge to participate in frontier energy development,

emerging energy technologies, and sustainable

development projects.”

Stephen J. Wuori

Group Vice President, Planning & Development

Climate Change
In December 2002, Canada ratified the Kyoto Protocol,
a 1997 treaty designed to reduce greenhouse gas
emissions to 6% below 1990 levels. Enbridge is
currently assessing and evaluating the federal
government’s approach to implementation. Until these
plans become certain, the Company will not be able
to quantify the impact, if any, on its operations. From
a supply perspective, however, we are encouraged
by recent producer reactions, particularly their
commitment to sustained oil sands development.

Enbridge believes that climate change is a global issue
that needs to be addressed today and into the future.
As a leader in the energy sector, Enbridge will work
to ensure that its activities are part of the solution to
the climate change challenge.

In November 2002, Enbridge President & Chief
Executive Officer Pat Daniel delivered a presentation
as part of the University of Calgary’s Kyoto Forum
entitled Kyoto: A Call to Engage Canadians.
The following are excerpts:

❚ “At Enbridge ... we are committed to taking actions
to reduce greenhouse gas emissions throughout the
company and its subsidiaries, and we have been a
willing and active participant in the Climate Change
Voluntary Challenge and Registry.”

❚ “Enbridge has set targets to reduce direct emissions
from operations in Canada, and we are aggressively
pursuing energy efficiencies that will reduce our
consumption of electricity, a source of indirect
greenhouse gas emissions.”

❚ “We can’t succeed without the people of Canada,
who make the choices every day about energy
consumption and about goods and services that
drive energy demand and energy production.”

❚ “Worldwide, our societies demonstrate an

increasing appetite for energy, and the issue
of emissions reductions cannot be resolved
successfully without the engagement of citizens
as consumers of energy products and services.
We must do this in new ways that promote
public awareness — encourage the efficient
use of energy — and support the development
of alternative forms of energy.”

E N B R I D G E

I N C .

C O R P O R A T E R E S O U R C E S

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“ One of the many resources we employ at Enbridge for

managing risk throughout the enterprise is a committed,

hard-working and ethical work force. We have that from

the Board level on down, and we maintain and strengthen

that resource with clearly articulated corporate values

and a Company-wide code of business conduct.”

Bonnie D. DuPont

Group Vice President, Corporate Resources

Corporate Governance
Enbridge considers the diverse nature of its mixture of
corporate governance “best practices” to be a strength.
Over the course of the past five years, the evolution of
Enbridge’s corporate governance policies and practices
has resulted in numerous accomplishments that we
have shared with others who have indicated that
they consider us to be leaders in this field.

In 2002, Enbridge was recognized for its commitment
to corporate governance when it was ranked fourth
best in Canadian Business magazine’s listing of the
Best & Worst Boards in Canada.

The Board of Directors of Enbridge functions
independent of management and is accountable
to shareholders. The Board has delegated to the
Governance Committee the role of overseeing
corporate governance generally, and Enbridge has
demonstrated vision and a comprehensive approach
to governance through the integration of empowerment
and accountability involving all employees up to the
Board of Directors and ultimately to shareholders.

Enterprise-wide risk assessment and mitigation are
management tools which keep Enbridge accountable
to shareholders and responsible to our social
environment. Enbridge uses a Corporate Risk
Assessment process to identify operational risks
throughout the organization. This, in turn, leads
to an enterprise-wide risk mitigation strategy. The
risk assessment is presented annually to the Audit,
Finance & Risk Committee, which is separate from
the Governance Committee. Strong financial results
and operational accomplishments are the measurable
evidence of these stewardship strengths.

Additional information about Enbridge’s corporate
governance practices is available in the Company’s
Management Information Circular.

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CORPORATE SOCIAL RESPONSIBILITY — ENBRIDGE IN THE COMMUNITY

At Enbridge, we are committed to excellence in implementing standards that not only comply with legislated
requirements but also respond to the social, economic and environmental needs of the communities where we
operate, our customers, shareholders, governments and the public. Social responsibility — the safety of
our employees and the public; a clean and healthy environment; and strong, vibrant communities — is one
of our core values. We are committed to sustaining these essential values through socially responsible
operations and involvement in our communities.

Employees, senior management and our Board of Directors are all guided by the Company’s Statement on
Business Conduct. Adherence to this code of conduct, which incorporates the internationally recognized
Voluntary Principles on Security and Human Rights, is a condition of employment, and at home and abroad,
this document outlines the expected standards of behaviour and ethics in all our business endeavours.

COMMUNITY INVESTMENT

In 2002, Enbridge invested $3 million in communities.
Our goal is to foster long-term relationships, encourage
community-mindedness and involvement by employees,
and help create vibrant, healthy places for people to live.

Investing in Health and Social Services
For the fourth consecutive year, Enbridge employees
across Canada and the United States raised more
than $1 million for United Way campaigns and
was recognized in Canada as a Thanks A Million
corporate donor. Additionally, as the title sponsor
of the Enbridge CN Tower Stair Climb, the Company
helped garner the support of 10,000 climbers
to raise $830,000 for the United Way
of Greater Toronto.

The country’s health system is
a top public policy issue for
Canadians, and Enbridge Gas
Distribution supports a
variety of health-related
organizations including
the Ottawa Regional
Cancer Centre, St.
Elizabeth Health Care,
Princess Margaret Hospital
and the Rouge Valley Health
System. Enbridge also supports
youth volunteerism and
leadership at The Hospital for
Sick Children in Toronto.

In 2002, Enbridge continued to
provide funding to Health Smart
Solutions, which raises money for
hospitals in the Alberta Capital

Region. The Company contributed to the Stanton
Regional Hospital Foundation in the Northwest
Territories; the Lambton Hospitals Foundation in
Sarnia, Ontario; and the Northern Lights Health
Region in Fort McMurray, Alberta.

Enbridge also contributed to That All May Read,
a nationwide CNIB program that provides play-back
equipment to children and adults with vision loss, and
provided support for Discovery House, a shelter for
victims of family violence in Calgary.

Enbridge youth-oriented programs included a new
partnership in 2002 with Ottawa’s Christie Lake Kids,
and ongoing support for Eva’s Initiatives to help
Toronto’s homeless youth.

Investing in Education

In Calgary, Enbridge supported
the annual Word on the Street
program and Calgary Reads,
which drew attention to
literacy issues. In Ontario,
Enbridge provided funding
to the Barrie Literacy
Council to help increase
its volunteer base.

Enbridge supports the Student
Mentoring Program, created six
years ago to help students in the
Inuvialuit Settlement Region in
the N.W.T. continue their studies
so they can become scientists and
resource managers to ensure the
effective management of fish and
marine mammals so important
to the region.

E N B R I D G E

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Investing in the Environment
In Ontario, Enbridge Gas Distrbution continued to
provide aggressive demand-side management (DSM)
programs that encourage and enable customers to use
natural gas more efficiently. As part of this program,
Enbridge offers rebates on the purchase of energy-
saving heating equipment in homes, identifies
solutions for plant operations and promotes energy-
efficient design in the building industry. Since 1995,
DSM programs have resulted in “avoided” emissions
of approximately 900,000 tonnes of CO 2.

Enbridge continued to support the City of Toronto’s
annual Smog Summit and Pollution Probe’s Clean Air
Campaign, to improve air quality through public
education, advertising, advocacy and special events.
Enbridge also invested in WindShare, which is
building two wind turbines on the Toronto waterfront.

In 2002, funding was provided through the Enbridge
Environmental Initiatives Program to 34 community
projects along the Enbridge Pipelines right-of-way.
Projects included planting trees and shrubs to provide
wildlife habitat and beautify parkland, and purchasing
environmental education software for a library in
Hardisty, Alberta.

In Alberta, Enbridge entered into three-year partnerships
with FEESA, An Environmental Education Society,
to bring a climate change curriculum to schools
along the pipeline right-of-way, and the Pembina
Institute for Appropriate Development to develop
an online climate change educational program.

Investing in Leadership Development
Enbridge continued to provide funding and voluntary
participation in the development of community
leadership programs in Calgary, Edmonton, Regina,
Ottawa and Fredericton.

Enbridge also funded and participated in the 2002
Toronto City Summit, which brought together more
than 150 leaders from various community sectors,

Social Vision Statement
“We’re Enbridge. In partnership with our communities,
we deliver more than energy; we deliver on our
commitment to enhance the quality of life in our
communities by supporting programs in health,
education, social services and the environment.
Together with our employees we have the
energy to make a difference.”

including all three levels of government, to discuss
issues and identify solutions to chart the city’s future.

Volunteerism at Enbridge
Over the past year, Enbridge has supported various
volunteer resource programs across Canada, including
Edmonton’s Stollery Children’s Hospital Foundation,
and the Enbridge Volunteers in Partnership (VIP)
Centre in York Region north of Toronto.

In Calgary, Enbridge’s VIP employee initiative
continued to support high-risk families facing
homelessness. And in Edmonton, employees and
their families contributed more than 13,000
volunteer hours to the community.

Community Safety and Emergency Response
In the United States, Enbridge Energy Partners
developed a 911 Fund to honor the heroes and victims
of the September 11, 2001, tragedy. The 911 Fund
provides grants to first responder organizations — fire
departments, emergency medical services, police and
sheriff’s departments located in the U.S. In Canada,
volunteer fire departments in a number of communities
received Enbridge funding. Enbridge also supported
the County of Strathcona Fallen Fire Fighters
Memorial Fund and the Ontario Fire Marshal’s
Team Up for Fire Safety campaign.

Supporting Vibrant Communities
Enbridge Gas Distribution’s involvement in the
communities it serves helps create a long-term positive
relationship with customers and municipalities. In 2002,
the Company supported more than 400 events that
provided opportunities to deliver safety and energy-
efficiency information to more than 1.6 million people.

E N B R I D G E

I N C .

M D & A

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S

Earnings Applicable
to Common Shareholders
(millions of dollars)

Return on Average
Common Shareholders’ Equity
(%)

8
.
0
8

6
.
3
4

4
.
0
3
1

3
.
0
8
1

3
.
7
1
2

9
.
0
4
2

9
.
7
8
2

3
.
2
9
3

5
.
8
5
4

5
.
6
7
5

7
.
7
1

5
.
9

2
.
3
1

0
.
5
1

2
.
4
1

8
.
3
1

3
.
4
1

6
.
8
1

9
.
9
1

C O N S O L I D A T E D R E S U L T S

FINANCIAL HIGHLIGHTS

(millions of Canadian dollars, except per share amounts)
Earnings Applicable to Common Shareholders

Energy Transportation North
Energy Transportation South
Energy Distribution
International
Corporate
Earnings from continuing operations
Discontinued operations

Earnings Per Share

Earnings — Continuing operations
Earnings — Discontinued operations

Dividends Per Share

Common Share Dividends

2002

2001

2000

236.2
(41.4)
113.8
68.0
(42.4)
334.2
242.3

576.5

2.09
1.51

3.60

1.52

205.1
46.4
181.8
35.6
(55.7)
413.2
45.3

458.5

2.63
0.28

2.91

1.40

192.6
23.3
203.2
26.4
(87.8)
357.7
34.6

392.3

2.32
0.22

2.54

1.27

251.1

227.5

202.1

E N B R I D G E

I N C .

M D & A

“ Enbridge had another very successful year in 2002. Adjusted

earnings per share growth of 8% was in our target range.

We significantly delevered the balance sheet, strengthening our

financial position. Our plans include further debt reductions

in 2003. From a financial perspective, we are well-positioned

to execute our strategy going forward. From a shareholder

perspective, we were able to increase the dividend paid to

shareholders by 8.6% in 2002 and increased it again by

9% for 2003.”

Derek P. Truswell

Group Vice President & Chief Financial Officer

Earnings applicable to common shareholders (earnings) for the year ended December 31, 2002 were $576.5 million,
or $3.60 per common share, compared with $458.5 million, or $2.91 per common share, in 2001. Liquids pipelines
and international operations contributed to the growth in earnings, along with higher equity earnings from Enbridge
Energy Partners, L.P. (EEP). These increases were offset in part by lower earnings from Enbridge Gas Distribution
(Enbridge Gas) due to warmer weather in 2002 than in 2001. Earnings for 2002 also included an after-tax gain
of $240.0 million from the sale of the Energy Services business and an after-tax loss of $82.2 million on assets
sold to EEP, included in Energy Transportation South. Prior year’s earnings included the benefit of $58.5 million
related to income tax rate reductions.

As shown below, after adjusting for significant one-time gains or losses and the impact of weather, earnings for
the year ended December 31, 2002 were $428.4 million, compared with $387.8 million for 2001.

(millions of Canadian dollars, except per share amounts)
Earnings applicable to common shareholders
Gain on sale of Energy Services business
Loss on sale of Enbridge Midcoast Energy assets
Gain on sale of securities
Weather
Dilution gains
Tax rate reductions
Other

Adjusted earnings

Adjusted earnings per share

Adjusted diluted earnings per share

2002
576.5
(240.0)
82.2
(17.8)
29.3
(6.1)
(1.4)
5.7

428.4

$2.67

$2.64

2001
458.5
–
–
–
(5.0)
(15.2)
(58.5)
8.0

387.8

$2.47

$2.44

2000
392.3
–
–
–
22.1
–
(94.9)
15.6

335.1

$2.17

$2.16

E N B R I D G E

I N C .

M D & A

Enbridge had several significant achievements during the year.

❚ The acquisition of a 25% interest in Compañia Logistica de Hidrocarburos

CLH, S.A. (CLH) was completed in the first quarter. CLH is Spain’s largest
refined products transportation and storage business.

In May, Enbridge sold its Energy Services business for cash proceeds of
$1 billion.

❚ The Company closed the sale of the United States assets of Enbridge Midcoast
Energy to EEP for consideration of US$820 million. Concurrent with the
sale, Enbridge Energy Management, L.L.C. (EEM) completed an initial
public offering of shares, the proceeds of which were used to purchase
i-units in EEP. The Company’s interests in EEP and EEM collectively are
referred to as the Partnership.

Bitumen production from MacKay River
was connected to the Athabasca System
in 2002.

In the fourth quarter, the Company increased its ownership interest in Alliance to 37.1% through the purchase
of a 9.6% interest from The Williams Companies Inc. (Williams) and a 6.1% interest from El Paso Corporation
(El Paso). Enbridge will acquire an additional 1.1% interest in Alliance from El Paso at the end of the first
quarter of 2003. As part of the El Paso transaction, Enbridge’s interest in the Aux Sable natural gas processing
facility increased to approximately 30.9%.

Earnings from continuing operations for the year ended December 31, 2002 were $334.2 million, or $2.09 per
share, compared with $413.2 million, or $2.63 per share, in 2001. Growth in earnings from the liquids pipelines
and international operations, as well as higher earnings from the Partnership were more than offset by the loss on
sale of the United States assets of Enbridge Midcoast Energy, warmer weather than 2001, and the positive impact
on earnings of income tax rate reductions in 2001.

For the year ended December 31, 2001, earnings from continuing operations were $413.2 million, or $2.63 per
share, compared with $357.7 million, or $2.32 per share, in 2000. The higher earnings reflect improved operating
results from Enbridge Gas and the Enbridge System. The acquisition of Midcoast Energy Resources, Inc. also
contributed to higher earnings. In addition, the Company realized dilution gains from the issuance of units by EEP
and improved results from corporate activities. These increases were partially offset by higher financing costs, a
reduced contribution from Vector, a higher loss from Aux Sable, and income tax rate reductions that had a smaller
positive impact on earnings in 2001 than 2000.

Dividends paid on common shares increased in each of the last three years from growth in the dividend per share
and a higher number of outstanding common shares. The quarterly dividend per share increased to $0.38 in the
first quarter of 2002 from $0.35 per share established in the first quarter of 2001. In the second quarter of 2000
the quarterly dividend was raised to $0.3225. This represents increases of 8.6%, 8.5% and 6.6%, respectively,
and reflects the sustained growth in earnings over the period.

In 2002, the Company changed its financial reporting segments to conform with changes in senior management
responsibilities. The gas services business and the investment in Aux Sable are included in Energy Distribution.
All financial information has been restated to reflect the new segments.

E N B R I D G E

I N C .

❚
❚
M D & A

C O R P O R A T E S T R A T E G Y

Enbridge’s resources are focused on three broad strategic thrusts and three areas of increased emphasis.
The major strategies are to:

enhance profitability through adoption and maintenance of incentive-based rate mechanisms to maximize benefits
for customers and shareholders;

expand and extend the core liquids and gas distribution businesses through greenfield development or
acquisitions; and

❚ develop or acquire businesses that are complementary to the core businesses.

Strategic emphasis is placed on increasing the Company’s North American footprint, increasing the scale of
operations and developing and applying new technologies. Enbridge’s proposed actions with respect to these
strategies are described in the “Outlook” for each business unit.

The achievement of the Company’s major strategies is dependent on successful mitigation of business risks,
discussed in each of the business segments. Enbridge believes it has identified and mitigated the risks, to the
extent practical.

Enbridge remained on track with the implementation of its strategy in 2002 and is committed to identifying and
implementing the actions required to create value and sustainable growth.

E N E R G Y T R A N S P O R T A T I O N N O R T H

FINANCIAL RESULTS

(millions of Canadian dollars)
Enbridge System
Athabasca System
NW System
Saskatchewan System
Alliance Pipeline
Vector Pipeline
Other

2002
123.7
41.2
9.5
6.4
40.7
7.1
7.6
236.2

2001
111.1
29.9
9.5
5.9
37.6
3.9
7.2
205.1

2000
98.3
27.7
10.7
9.5
28.4
11.2
6.8
192.6

BUSINESS ACTIVITIES
Energy Transportation North activities include the liquids pipelines operations in
Canada and the Company’s equity interests in gas transmission pipelines and
AltaGas, a company engaged in natural gas gathering and processing.

The mainline pipeline, comprised of the Enbridge System and the Lakehead
System (the portion of the mainline pipeline in the United States operated by
Enbridge and owned by EEP), is the world’s longest crude oil pipeline system and
is the primary transporter of crude oil from Western Canada to the United States.
It is the only pipeline that transports crude oil from western to eastern Canada
and serves all of the major refining centres in the Province of Ontario, as well
as the Midwest region of the United States.

Additional tankage and facilities were
constructed at the Athabasca terminal
in Fort McMurray.

E N B R I D G E

I N C .

❚
❚
M D & A

Enbridge also owns the Athabasca System, the NW System and the Saskatchewan System. The Athabasca System
is a 545-kilometre (339-mile) pipeline that transports synthetic and heavy oils from north of Fort McMurray in
northern Alberta to the pipeline hub at Hardisty, Alberta. The Athabasca System also includes the MacKay River
and Christina Lake lateral feeder lines and tankage facilities. The NW System transports crude oil from Norman
Wells, in the Northwest Territories, to Zama, Alberta. The Saskatchewan System consists of approximately 322
kilometres (200 miles) of trunk line and 1,920 kilometres (1,193 miles) of pipeline on three separate gathering
systems in the provinces of Saskatchewan and Manitoba.

Natural gas transmission pipeline activities include equity investments in the Alliance and Vector pipelines.
Enbridge owns a 37.1% interest in Alliance, a 3,000-kilometre (1,800-mile) pipeline that commenced operations
in December 2000 and transports liquids-rich natural gas from Fort St. John, British Columbia to Chicago,
Illinois. The Company provides operating services to and holds a 45% investment in Vector, which transports
natural gas from Chicago to Dawn, Ontario. Vector also commenced operations in December 2000. Alliance
and Vector have the capacity to deliver 1.55 billion cubic feet per day (bcfd) and 1.0 bcfd, respectively.

RESULTS OF OPERATIONS
Earnings from Energy Transportation North were $236.2 million for the year ended December 31, 2002, an
increase of $31.1 million from 2001. The higher earnings were due to expansions of the Enbridge and Athabasca
Systems. Higher earnings from the Enbridge System were due to the request from shippers in mid-2001 to
construct Phase III of the Terrace expansion which resulted in incremental earnings and to Phase II of the Terrace
expansion which was placed into service in early 2002. These increases were partially offset by an adjustment to
the power allowance credit due to shippers as a result of Terrace operating at less than capacity. The Athabasca
System generated higher earnings due to the construction of new laterals and tankage, which commenced
operations in the second half of 2002.

Earnings were $205.1 million for the year ended December 31, 2001, compared
with $192.6 million for 2000. The higher earnings were due to increased contributions
from the Enbridge System, Alliance and the Athabasca System, partially offset by
lower earnings from Vector.

Liquids Pipelines
Enbridge System
In 2002, Enbridge System earnings were $12.6 million higher than last year primarily
due to higher earnings from the Terrace expansion as Phase II was placed in service
in early 2002 and Phase III was triggered in mid-2001. The increase in Terrace
earnings was partially offset by an adjustment to the power allowance credit due to
shippers as a result of Terrace operating at less than capacity.

Earnings from the Enbridge System increased to $111.1 million in 2001 from
$98.3 million in 2000. The increase was mainly due to the triggering of Phase III
of the Terrace Expansion in mid-2001. In the third quarter, the Company recorded
a charge for an adjustment to oil inventory due to shippers of approximately
$3 million, after tax. This was the result of refinements in the oil loss estimation
process, as well as improvements in the accuracy of measuring oil losses as new
software applications were developed.

Deliveries
(thousands of barrels per day)

4
2
0
,
2

2
4
9
,
1

2
7
0
,
2

9
0
1
,
2

8
8
0
,
2

98 99

1 Includes deliveries
by the 14.1% owned
Lakehead System

E N B R I D G E

I N C .

M D & A

Tolls on the Enbridge System are governed by the provisions of the Incentive
Tolling Settlement (ITS). The ITS, which has been approved by the National
Energy Board (NEB), has a five-year term which expires on December 31, 2004.
Under the ITS, tolls are determined based on a starting revenue requirement
which is adjusted each year for 75% of the change in the Gross Domestic Product
Implicit Price Index. The ITS allows the Company and its customers to share in
cost savings, protects Enbridge from fluctuations in volumes and incorporates
additional incentive mechanisms for electric power cost savings. Since electricity
is used to power the pumping stations, power costs are a significant expense.
The Company is allowed to earn a separate return on facilities expansions or
additions that qualify as non-routine adjustments.

The Enbridge System begins at Edmonton and,
together with the Lakehead System, comprises
the world’s longest crude oil and liquids
pipeline system.

Since the inception of incentive tolling arrangements in 1995, through the cost performance sharing mechanism
of the ITS, after-tax benefits of $79.7 million have been shared approximately 54% and 46% by Enbridge and its
customers, respectively. Customers also have realized an additional after-tax benefit of $5.0 million through the
power guarantee mechanism of the ITS. The renewal of the ITS in 2000 resulted in a reduction of $16.0 million
to the starting point revenue, providing customers with annual on-going savings of $9.0 million, after tax. Enbridge
benefited by an increase of $7.6 million in the threshold earnings level from which future sharing is measured.

Athabasca System
In 2002, earnings on the Athabasca System were $11.3 million higher than 2001, primarily due to the construction
of additional tankage at Fort McMurray in 2001, and the construction and completion in 2002 of the MacKay
River and Christina Lake lateral lines and two additional tanks at the Athabasca terminal. With the addition of
third party volumes, operational control of the Athabasca System was transferred to Enbridge from the major
shipper in October 2002.

In 2001, the construction of additional tankage and terminal facilities at the Athabasca terminal in Fort McMurray
increased the investment base resulting in higher earnings than in 2000.

The Company has a long-term contract with the major shipper on the Athabasca System. The shipper has committed
annual volumes at specified tolls over a 30-year term. The contract terms provide for tolls that are similar to those
that would result under traditional cost-of-service rate-making. The contract terms also provide for a return, based
on the contract volumes, that approximates the NEB’s multi-pipeline rate of return on common equity in effect at
the time of entering into the agreement. Additional third party volumes improve Enbridge’s return beyond this
level. Earnings are recognized on a cost-of-service basis and any difference between the cost-of-service revenue
and cash tolls is recognized in the period. The deferred amounts will be collected over the term of the contract.

NW System
Earnings in the last three years from the NW System have been consistent and reflect the negative effect of declining
rate base, offset by cost savings that generate incentive earnings. Earnings are based on an agreement with the
primary shipper and are a product of a deemed common equity ratio of 55% and the NEB multi-pipeline rate of
return on common equity, plus any incentive cost savings.

Saskatchewan System
Earnings have been relatively constant in 2002 and 2001. Earnings in 2000 reflect the positive impact of income
tax rate reductions.

E N B R I D G E

I N C .

M D & A

Gas Transmission Pipelines
Alliance
The increase in equity earnings of $3.1 million from Alliance in 2002, compared
with 2001, was due to the acquisitions of the Williams and El Paso interests in
the fourth quarter of 2002. In 2001, equity earnings from Alliance of $37.6 million
improved by $9.2 million when compared with 2000. Higher earnings resulted
from a higher rate base in 2001 since construction costs were being incurred until
the pipeline was placed into service in December 2000. Earnings in 2000
represent allowance for equity funds during construction (AEDC).

Enbridge provides operating services to
and owns 45% of the Vector Pipeline, which
transports natural gas from Chicago,
Illinois, to Dawn, Ontario.

Vector
The contribution from Vector was $3.2 million higher in 2002, compared with
2001, due to a one-time adjustment to depreciation expense, reflecting a revision to depreciation rates to be
consistent with the rates approved by the Federal Energy Regulatory Commission (FERC). In addition, an
adjustment was booked in 2001 to reverse earnings that were overaccrued in 2000. In 2001, Vector earnings
of $3.9 million were $7.3 million less than 2000. Earnings were impacted negatively by capacity constraints
in 2001, as well as higher depreciation and interest expense. In 2000, Vector was under construction and
earnings represented AEDC.

OUTLOOK

Liquids Pipelines
Enbridge System
The NEB approved the facilities application for construction of Phase III of the Terrace Expansion Project
in Canada in April 2002. Phase III involves construction of 176 kilometres (110 miles) of 914-millimetre
(36-inch) pipeline on the Lakehead System between Clearbrook, Minnesota and Superior, Wisconsin and pumping
additions in both Canada and the United States. Phase III will increase capacity by approximately 140,000 barrels
per day. Shippers have requested that Phase III be in service in 2003. Phase II, placed in service in 2002, and
Phase III were requested by shippers to handle anticipated increases in oil sands volumes in the next few years.

Volumes transported are expected to increase in 2003 due to increased production from the oil sands region of
Alberta. Fluctuations in volumes do not impact the majority of net earnings from the Enbridge System due to
provisions in the ITS. The request to build Terrace Phase III demonstrates producers’ confidence that more
capacity out of the Western Canadian Sedimentary Basin (WCSB) will be needed in the medium term.

The ITS allows Enbridge and its customers to share in cost savings achieved by the Company. To ensure
continued savings for customers and increased returns for shareholders, the Company will continue to focus
on operational excellence.

Enbridge Athabasca System
The Enbridge Athabasca System is the only liquids pipeline directly linking both the Athabasca and Cold Lake
oil sands deposits with the pipeline transportation hub at Hardisty, Alberta. With a design capacity of 570,000
barrels per day, the pipeline is well positioned to carry more of the region’s oil sands and heavy oil production
in the future.

E N B R I D G E

I N C .

M D & A

Earnings from the Athabasca System are expected to increase in 2003 as a result of full year operations of the
MacKay River and Christina Lake facilities. In addition, the Company expects that a new diesel-loading facility,
to supply the regional market of the major shipper, will be in service by the spring of 2003.

The Company has entered into a limited partnership with an industry partner to develop underground cavern
facilities to provide crude oil storage services. The facilities are located near the Enbridge System main pipeline
terminal at Hardisty. The partnership will provide petroleum storage services to shippers at Hardisty that previously
were unavailable. The existing storage capacity of approximately three million barrels has been contracted to a
shipper for a five-year term. Construction commenced in the fourth quarter of 2002, with completion expected
in the fourth quarter of 2003.

Supply
Liquids supply from the WCSB is expected to increase during the next 10 years. Although supply of conventional
light crude is forecast to continue to decline, significantly higher bitumen and upgraded synthetic production
is expected from the Alberta oil sands region. Heavy crude production, which must be diluted with condensate,
or heated or upgraded before it can be transported, may be constrained after 2006 without additional use
of synthetic crude as diluent.

Conventional oil reserves in Western Canada increased in 2001 to 5.2 billion barrels. Approximately 50% of
production was replaced. Reserves from the oil sands stood at 6.7 billion barrels from developed, currently
producing projects or projects on which substantial investment is being made. It is estimated that there are 315
billion barrels of bitumen ultimately recoverable in the Alberta oil sands, using existing technology. To date,
approximately two billion barrels have been produced.1

Capital Expenditures
Energy Transportation North expects to spend approximately $155 million in 2003 for capital expenditures, the
majority of which relates to the Terrace Phase III expansion, the cavern storage project and core maintenance.

Gas Transmission Pipelines
Earnings from Alliance should increase in 2003 as a result of Enbridge’s higher ownership interest. Vector’s earnings
are expected to decrease as a one-time adjustment to depreciation expense increased earnings in 2002. Vector’s
earnings will continue to be negatively impacted over the short-term by higher interest expense. There is no near-
term requirement for further capital investment in either pipeline.

In the third quarter, Enbridge purchased Williams’ 9.6% and El Paso’s 6.1% interests in Alliance. The acquisition
from El Paso also includes its 9.5% interest in Aux Sable and Alliance Canada Marketing, which are part of
Energy Distribution. Enbridge did not assume either company’s direct merchant
capacity commitments on the pipeline. These purchases increase the Company’s
ownership interest in Alliance to 37.1% and were made at a cost of
approximately $300 million.

Supply and Demand for Natural Gas 1
Natural gas reserves in the WCSB increased 0.6% in 2001 to 59.8 trillion cubic
feet. In 2001, approximately 106% of natural gas production was replaced.
Demand for natural gas in North America is forecast to remain constant over
the next five years and grow at 2% per year thereafter. Most of this growth
will be for electricity generation requirements.

1 Source: CAPP Statistical Handbook — November 2002

Enbridge increased its ownership in the
Alliance natural gas pipeline to 37.1%
as of year end.

E N B R I D G E

I N C .

M D & A

BUSINESS RISKS

Liquids Pipelines
Supply and Demand
The operation of the Company’s liquids pipelines are dependent upon the supply
of and demand for crude oil and other liquid hydrocarbons from Western Canada.
Supply, in turn, is dependent upon a number of variables, including the availability
and cost of capital for oil sands projects and the price of crude oil. Drilling
activity during the last three years has not been as strong as expected. The
request by producers to build Phase III of Terrace, adding additional pipeline
capacity, indicates that producers expect that volumes will increase in the future.

Production from the oil sands of northern
Alberta is expected to continue to increase,
requiring additional infrastructure.

Historically, refiners in the U.S. Midwest have utilized large volumes of
Western Canadian light crude versus other imported crude. Line 9 transports offshore crude to Ontario and
is owned by Enbridge. Volumes on Line 9 have displaced some Canadian and U.S. domestic deliveries in
the Ontario market, requiring an increase in deliveries to the U.S. Midwest, which has limits on the volume
of Canadian crude which can be readily absorbed.

In December 2002, Canada ratified the Kyoto Protocol, a 1997 treaty designed to reduce greenhouse
gas emissions to 6% below 1990 levels. Enbridge is assessing and evaluating the federal government’s approach
to implementation. Until these plans become certain, the Company will not be able to quantify the impact, if
any, on its operations. The Company is encouraged by recent producer reactions to Kyoto, particularly their
commitment to oil sands development, which support the outlook for the sustainability of supply for the
liquids pipelines.

Regulation
Earnings from the Enbridge System and other liquids pipelines are subject to the actions of various regulators,
including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings from these
operations. The NEB prescribes a benchmark multi-pipeline rate of return on common equity. To the extent the NEB
rate of return fluctuates, a portion of the earnings of the Enbridge System changes. The Company believes that
regulatory risk has been reduced through the negotiation of long-term agreements, such as the ITS, with its customers.

Competition
The Enbridge System transported approximately 65% of total Western Canadian crude oil production in 2002 and
provides about 75% of capacity for the transportation of Western Canadian crude oil out of Canada. Competition
among common carrier pipelines is based primarily upon the cost of transportation, access to supply and
proximity to customers. Trans Mountain Pipe Line, Express Pipeline, and other common carriers, can be used by
producers to ship Western Canadian crude oil to refineries in either Canada or the United States. Although the
Company does not compete directly in the regions served by these other pipelines, producers can elect to have
their crude oil refined elsewhere than delivery points on the Enbridge System. The Company believes that
its liquids pipelines are serving larger markets and provide attractive options to producers in the WCSB, due
to its competitive tolls. The Company also offers shorter transit times from the WCSB to the U.S Midwest.

Increased competition could arise from new feeder systems servicing the same geographic regions as the
Company’s feeder pipelines. Unused capacity on the Athabasca System should be more competitive than
a new pipeline. However, competition to provide transportation service directly from the Alberta oil sands
to Edmonton has increased.

E N B R I D G E

I N C .

M D & A

Environment and Safety
Enbridge is committed to the protection of the health and safety of employees and the general public and to
sound environmental stewardship. The Company believes that prevention of accidents and injuries and protection
of the environment benefits everyone and delivers increased value to shareholders, customers and employees.
Every five years, Energy Transportation North conducts a review of its environmental management system.
The system reflects industry best practices and is aligned with the ISO 14001 standard for environmental
management systems.

Pipeline leaks are an inherent risk of operations. The Company has an extensive program to manage system integrity,
which includes the development and use of predictive and detective in-line inspection tools. Maintenance,
excavation and repair programs are directed to the areas of greatest benefit and pipe is replaced or repaired as required.

Gas Transmission Pipelines
Alliance and Vector
Alliance and Vector are regulated federally and are subject to regulatory risk. The Company believes that this
risk has been mitigated through the execution of long-term contracts with customers. Currently, pipeline capacity
out of the WCSB exceeds supply. Alliance has been unaffected but Vector has not fully contracted its capacity.

E N E R G Y T R A N S P O R T A T I O N S O U T H

FINANCIAL RESULTS

(millions of Canadian dollars)
Enbridge Energy Partners
Enbridge Midcoast Energy
Loss on sale of Enbridge Midcoast Energy assets
Feeder Pipelines
Dilution gains
Other

2002
19.5
7.3
(82.2)
8.1
6.1
(0.2)
(41.4)

2001
12.5
9.5
–
9.2
15.2
–
46.4

2000
16.3
–
–
7.2
–
(0.2)
23.3

BUSINESS ACTIVITIES
Energy Transportation South includes the Company’s ownership interests in the operations of EEP. Enbridge is
the general partner and operates the assets of EEP. Activities also include owning and operating feeder pipelines
in the United States.

In October 2002, Enbridge sold the United States assets of Enbridge Midcoast Energy to EEP. Therefore,
at year-end, this segment is comprised primarily of the Company’s ownership
interests in the Partnership. From May 2001 until October 2002, Enbridge
owned 100% of Enbridge Midcoast Energy. The results of operations of
Enbridge Midcoast Energy, in the table above, relate to the period when the
assets were wholly-owned.

Enbridge has an effective 14.1% ownership interest (2001 — 13.6%, 2000 — 15.3%)
in the Partnership. This ownership interest represents the Company’s direct
investment in EEP of 10.6% and an indirect investment of 3.5% through the
Company’s 17.2% ownership interest in EEM. EEP owns the Lakehead System,
a feeder pipeline in North Dakota, the Enbridge Midcoast Energy assets and
natural gas gathering and processing assets in east Texas (East Texas System).

Enbridge Energy Partners owns and operates
a number of natural gas gathering and
processing facilities in Texas.

E N B R I D G E

I N C .

M D & A

RESULTS OF OPERATIONS
Results for the year ended December 31, 2002 were a loss of $41.4 million,
compared with earnings of $46.4 million for 2001. The 2002 results include an
after-tax loss of $82.2 million on the sale of the Enbridge Midcoast Energy
assets. Excluding this loss, earnings for 2002 were $5.6 million lower than 2001.
Increased earnings from the Partnership, resulting from the acquisitions of the
North Dakota and East Texas Systems and the Enbridge Midcoast Energy assets,
were more than offset by lower earnings from Enbridge Midcoast Energy prior
to the sale and higher dilution gains in 2001. Enbridge Midcoast Energy earnings
reflected improved operating performance from the assets, more than offset by
adjustments related to 2001 that were recorded in 2002, and working capital and
other closing adjustments identified prior to the disposition. The prior year
included dilution gains of $15.2 million, compared with $6.1 million in 2002, reflecting two unit issuances by
EEP in 2001, compared with one in 2002.

The Lakehead crude oil pipeline is owned
by Enbridge Energy Partners and operated
by Enbridge Pipelines.

In 2001, earnings from Energy Transportation South increased by $23.1 million to $46.4 million. The acquisition
of Enbridge Midcoast Energy in May 2001 and dilution gains on the Company’s investment in EEP were the
major contributors to the increase. Earnings from the Partnership were lower in 2001 due to reduced throughput,
an adjustment to oil inventory due to shippers and one-time costs associated with relocating the Partnership’s
office to Houston.

In October 2002, the Company closed the sale of the United States assets of Enbridge Midcoast Energy to EEP
for consideration of US$820.0 million, including cash and the assumption of debt. Concurrent with the sale
transaction, EEM, a subsidiary of Enbridge, completed an initial public offering of 9,000,000 shares representing
limited liability company interests with limited voting rights. The net proceeds from the offering were used to
purchase i-units, a new class of limited partnership interests, from EEP. The proceeds from the i-units were used
to finance a portion of the acquisition cost of the assets. In connection with the offering, Enbridge purchased 17.2%
of the EEM shares, increasing its effective ownership in the Partnership to 14.1% from 12.9%. EEM has no assets
or operations other than those related to the interest in EEP and, by agreement, will manage the business and
affairs of EEP.

Enbridge Energy Partners
Equity earnings in the Partnership improved in 2002 due to higher incentive earnings earned by Enbridge as
the general partner, improved results from the Lakehead System, and a higher ownership interest in the fourth
quarter. The acquisitions of the North Dakota and East Texas Systems contributed a full year’s earnings in
2002 and the acquisition of the Enbridge Midcoast Energy assets increased earnings in the fourth quarter.

The decreased contribution from the Partnership in 2001 compared with 2000 resulted from reduced throughput,
an adjustment to oil inventory due to shippers, as well as one-time costs associated with relocating the
Partnership’s office to Houston.

In December 2001, EEP completed the acquisition of the East Texas System for US$230 million.
The acquisition of the East Texas System represented the Partnership’s entry into the natural gas
transportation business.

E N B R I D G E

I N C .

M D & A

Enbridge Midcoast Energy
Enbridge Midcoast Energy was sold to EEP in October 2002. Enbridge purchased Midcoast Energy Resources,
Inc. in May 2001 for cash consideration of $561.8 million and the assumption of long-term debt. Earnings from
Enbridge Midcoast Energy in 2002 were $7.3 million, a decrease of $2.2 million from the prior year. While 2002
reflects improved operating performance, this was more than offset by adjustments related to 2001 that were
recorded in 2002 and working capital and other closing adjustments identified prior to the disposition. Earnings
for 2002 are for the period prior to the October 2002 disposition. Earnings for 2001 represent earnings from
the May 2001 date of acquisition.

In March 2002, the Company closed the acquisition of natural gas gathering and processing facilities in northeast
Texas for approximately $290 million. Also, in October 2001, Enbridge announced the purchase of natural
gas gathering, treating and transmission assets in south Texas for US$50 million. The Company closed a portion
of the acquisition for US$9 million and EEP now holds an option to purchase the remaining assets. These
assets were included with Enbridge Midcoast Energy and were part of the October 2002 sale to EEP.

OUTLOOK

Enbridge Energy Partners
Earnings for the Partnership are expected to increase in 2003, reflecting higher transportation volumes on the
Lakehead System and improved performance from the East Texas System. In addition, a full year’s contribution
from the Enbridge Midcoast Energy assets is expected to increase earnings. Earnings from the Lakehead System
and certain of the gas gathering assets are volume-sensitive and expected increases in volumes should have
a positive impact on the Partnership’s earnings. The growth in the asset base and expected increase in earnings
should result in higher incentive distributions to the Company.

The Terrace Phase III expansion, currently under way, offers opportunities to increase volumes transported on the
Lakehead System as crude oil supply from Western Canada increases due to oil sands development. Phase III is
designed primarily to increase capacity between Clearbrook, Minnesota and Superior, Wisconsin by approximately
140,000 barrels per day. The estimated cost of this project to EEP is approximately $312 million and is planned
to be in service in 2003.

Capital Expenditures
In 2003, the Company plans to spend $17 million related to additional investments in EEP and EEM.

BUSINESS RISKS
Virtually all of the Company’s operations in Energy Transportation South are carried out through the Partnership.
The business risks are mitigated by the size of the Company’s investment in
the Partnership.

Supply and Demand
The Lakehead System is dependent upon the level of supply of and demand for
crude oil and other liquid hydrocarbons from Western Canada. A decreased
supply of crude oil impacts deliveries with a corresponding impact on earnings.

Certain of the Partnership’s natural gas gathering assets are subject to changes
in supply and demand for natural gas, natural gas liquids and related products.
Commodity prices impact the willingness of natural gas producers to invest
in additional infrastructure to produce natural gas.

Construction continued in the United States
on the Terrace Phase III expansion, expected
to be in service in 2003.

E N B R I D G E

I N C .

M D & A

Regulation
The interstate and intrastate gas pipelines are subject to regulation by FERC or state regulators. Gas gathering
currently is not subject to active regulation. Several of the Partnership’s assets are regulated by FERC and their
revenues could decrease if tariff rates were protested. Kansas Pipeline Company (KPC) has recently lowered
its rates in compliance with a FERC order. Enbridge has agreed to reimburse EEP for a shortfall in revenue
approximating US$2 million for the next two years. The rates are subject to a rehearing by FERC. Certain states
in the U.S. may initiate rate regulatory oversight of intrastate gas pipelines. If this regulation occurs, it may reduce
the revenues and earnings of the Partnership.

Several of the Partnership’s pipeline systems transport commodities that are hazardous if released from the pipeline
system. These assets are subject to strict regulation and could be shut down or required to operate at reduced
operating pressures that likely would reduce earnings.

Market Price Risk
The Partnership’s business is subject to commodity price risk for natural gas costs and natural gas liquids.
Historically, these risks have been managed by using derivative finacial instruments, fixing the prices of natural
gas and natural gas liquids.

E N E R G Y D I S T R I B U T I O N

FINANCIAL RESULTS

(millions of Canadian dollars)
Enbridge Gas Distribution
Enbridge Commercial Services
Noverco
Enbridge Gas New Brunswick
Gas Services
Aux Sable
Other

2002
85.3
10.7
20.6
3.6
(7.8)
(3.1)
4.5
113.8

2001
156.1
14.3
16.3
2.3
(5.3)
(6.2)
4.3
181.8

2000
147.6
18.4
31.4
3.4
(8.8)
(3.3)
14.5
203.2

BUSINESS ACTIVITIES
Energy Distribution includes the gas distribution operations of Enbridge Gas, Enbridge Commercial Services,
which owns the Company’s investment in CustomerWorks LP, the Company’s investment in Noverco, and other
gas distribution activities in smaller franchise areas. This segment also includes the gas services business, which
manages the Company’s merchant capacity commitments on Alliance and Vector, and the equity investment in
Aux Sable.

Enbridge Gas is Canada’s largest natural gas distribution company and has been in operation for more than 150
years. It serves over 1.6 million customers in central and eastern Ontario, southwestern Quebec and parts of
northern New York State. Its operations in Ontario are regulated by the Ontario Energy Board (OEB).

Enbridge Commercial Services commenced operations on January 1, 2000 to provide information technology,
fleet services, call management centre, customer care and billing services to Enbridge Gas, the Energy Services
business and others. In 2001, Enbridge and BC Gas Inc. formed CustomerWorks LP to provide service covering
the entire meter-to-cash process, including many of the services provided by Enbridge Commercial Services.
Operations commenced on January 1, 2002. CustomerWorks LP provided services to more than 3.5 million
customers of the BC Gas utility and Enbridge’s gas distribution business. In August 2002, CustomerWorks LP
outsourced the provision of its customer care services to a new entity owned and operated by Accenture Inc.

E N B R I D G E

I N C .

M D & A

Enbridge owns an equity interest in Noverco through ownership of common shares and a cost investment through
ownership of preference shares. Noverco is a holding company that owns a 77% interest in Gaz Métropolitain,
a gas distribution company operating in the province of Quebec and the state of Vermont, which has a 50%
interest in TQM Pipeline, a pipeline transporting natural gas in Quebec.

The Company owns 63% of and operates Enbridge Gas New Brunswick (EGNB), the natural gas distribution
franchise in the Province of New Brunswick. EGNB constructed a new distribution system and has approximately
1,600 customers. Over 200 kilometres (124 miles) of distribution main have been installed with the capability of
attaching 6,000 customers. EGNB is regulated by the New Brunswick Board of Commissioners of Public Utilities.

RESULTS OF OPERATIONS
Earnings were $113.8 million for the year ended December 31, 2002, compared with $181.8 million in 2001.
Lower earnings in 2002 were attributable to warmer weather experienced in the Enbridge Gas franchise area in
2002 and a lower contribution from Enbridge Commercial Services, partially offset by improved earnings from
Noverco. Earnings for 2001 included the positive impact of income tax rate reductions of $45.0 million.

Earnings from Energy Distribution were $181.8 million for the year ended December 31, 2001, compared with
$203.2 million in 2000. The results reflect strong operating performance from Enbridge Gas, more than offset by
a smaller positive impact of tax rate reductions in 2001 than in 2000. Earnings from Noverco were lower in 2001
due to the positive effect of tax rate reductions on earnings in 2000.

Enbridge Gas
Earnings from Enbridge Gas decreased by $70.8 million in 2002 from 2001. The decrease was due to significantly
lower gas distribution margins, caused by lower distribution volume resulting from warmer weather. Had Enbridge
Gas experienced normal weather in its franchise area, earnings would have been higher by $29.3 million.

Energy Distribution
Degree Day Deficiency
(degrees Celcius)

Energy Distribution
Volume of Gas
Distributed
(billions of cubic feet)

Energy Distribution
Number of Active
Customers
(thousands)

6
6
7
,
3

9
6
5
,
0 3
6
4
,
3

0
6
0
,
4

9
2
9
,
3

6
1
8
,
3

2
6
3
,
3

0
0
7
,
3

2
5
3
,
3

9
7
0
,
4

7
9
3

2
0
4

1
2
4

7
2
4

0
1
4

4
1
4
,
1

6
6
4
,
1

0
2
5
,
1

1
7
5
,
1

3
2
6
,
1

98 99

Forecast

Actual

E N B R I D G E

I N C .

M D & A

Normal weather is the weather forecast by Enbridge Gas, in the Toronto area,
including the impacts of both the long run and short run actual historical weather
experience, more heavily weighted on the short run experience. The effect of
weather is measured by degree-day deficiency and is calculated by accumulating,
from October 1, the total number of degrees each day by which the daily mean
temperature falls below 18 degrees Celsius. This non-GAAP measure is unique
to the Company and, due to differing franchise areas, is unlikely to be directly
comparable to the impact of weather-normalized earnings that may be reported
by other companies. The weather-normalized adjustment is consistent with the
manner in which degree days are calculated for regulatory purposes.

Enbridge Gas Distribution, Canada’s largest
natural gas company, added 52,000
customers in 2002.

Earnings in 2001 of $156.1 million were higher than 2000 by $8.5 million.
Although weather for 2001 was slightly warmer in the franchise area, it was colder during the winter months
when distribution margins are higher, resulting in higher earnings of approximately $5.0 million. Operating earnings
also increased due to growth in the customer base and lower unaccounted for gas, which is the difference between
distribution volume entering the system and the volume delivered to customers. The weather was 5% colder compared
with 2000 and was slightly warmer than normal.

In the rate-making process, the OEB approves revenue rates that are designed to recover the cost of providing
service and to provide a return on equity. Rates are set on a forecast basis. The cost of providing service includes
the cost of gas commodity purchases and transportation costs, operation and maintenance costs, depreciation,
income taxes, and the cost of capital used to finance all assets used in gas distribution, storage and transmission.
The cost of capital, which is expressed as an allowed rate of return on rate base, is designed principally to meet
the cost of interest on long and short-term debt, satisfy the dividend requirements of preferred shareholders, and
provide a return on investment on common equity. It is the responsibility of Enbridge Gas to demonstrate to the
OEB the prudency of the costs it has incurred or the activities it has undertaken. Enbridge Gas does not profit
from the sale of the natural gas commodity.

Enbridge Gas continued to operate under a targeted Performance-Based Regulation plan (PBR plan), which expired
at the end of fiscal 2002. The PBR plan used a formula to calculate the level of operation and maintenance costs
recoverable in rates. The formula included escalation factors for customer growth and inflation; these were offset by
an annual productivity credit of 1.1%. The PBR plan also allowed for the recovery, subject to OEB approval, of
factors impacting operation and maintenance costs that are outside of management’s control. During the PBR
plan period, Enbridge Gas retained the savings it achieved as operation and maintenance expenses were lower
than those calculated under the formula.

The allowed rate of return on common equity for Enbridge Gas is based on the yield on Canadian government
long-term bonds. For 2002, the allowed rate of return was 9.66% (2001 — 9.54%, 2000 — 9.73%) on a deemed
common equity ratio of 35%.

Over the last three years, Enbridge Gas added 157,000 customers, including approximately 52,000 customers in
2002. This growth was attributable to the continued preference for natural gas among homeowners and builders
due to the price advantage and environmental benefits over other forms of energy. The new residential housing
market was strong in 2002 and 2001 and, through marketing programs, builders have continued to choose natural
gas for new housing construction.

E N B R I D G E

I N C .

M D & A

Enbridge Commercial Services
The contribution from Enbridge Commercial Services (ECS) was $10.7 million for the year ended December 31,
2002, a decrease of $3.6 million compared with the prior year. The decrease is due to the positive impact of tax
rate reductions in 2001 and the transfer of the remaining ECS operations into Enbridge Gas in the fourth quarter.

Lower earnings from ECS in 2001, compared with 2000, reflect the transfer of the merchandise finance plan to
the Energy Services business effective January 1, 2001. The merchandise finance plan business is included as a
component of discontinued operations.

Noverco
The contribution from Noverco was $20.6 million in 2002, compared with $16.3 million in 2001. The increase
is due to lower financing costs and higher incentive earnings. Equity earnings from Noverco in 2001 were lower
than 2000, mainly due to the positive impact of tax rate reductions in 2000.

Variations from normal weather do not affect Noverco’s earnings as the utility is not exposed to weather risk.
A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preference share
investment, which is based on the yield of 10-year Government of Canada bonds plus 4.45%. The weighted
average dividend yield on the preference shares, which is reset annually, was approximately 10% for each of the
last three years.

Enbridge Gas New Brunswick
Earnings from Enbridge Gas New Brunswick improved in 2002 as a result of a full year of operations. Customer
attachment to the new facilities continued to be slower than expected largely due to the shortage of skilled workers
to install heating, ventilation and air conditioning equipment. This has resulted in an increase in the regulatory
receivable used during the development period to defer annual shortfalls between EGNB’s revenues and cost of
service. This deferral is anticipated to be significantly higher than expected at the project’s commencement. The
recovery of this deferral will be determined by the regulator at the end of the development period.

Earnings in 2001 were slightly lower than 2000. Construction of new natural gas distribution facilities commenced
in the third quarter of 2000. Customer attachment to the new facilities has been slower than expected, resulting
in lower earnings in 2001. Earnings in 2000 consisted mainly of AEDC.

Gas Services
Gas Services experienced a loss of $7.8 million for the year ended December 31, 2002, compared with a loss
of $5.3 million in 2001. The loss increased in 2002 because of reduced basis differentials between Alberta
and Chicago and between Chicago and Dawn, Ontario. The basis differential is the cost of transportation
between natural gas hubs and determines the revenue which can be obtained from transportation capacity. The
loss in 2001 was attributable to losses on the Company’s Alliance and Vector
merchant capacity, also from the narrowing of the basis differential.

Enbridge Gas New Brunswick continued
to expand its distribution system and
add new customers.

E N B R I D G E

I N C .

M D & A

Aux Sable
Enbridge owns a 30.9% interest in the Aux Sable facilities, which process natural
gas delivered through Alliance. As the gas transported by Alliance is liquids-rich,
it must be processed prior to delivery to other systems. Aux Sable commenced
operations in December 2000 and has the capacity to process up to 1.6 bcfd of
natural gas. In 2002, the loss from Aux Sable was $3.1 million, an improvement
of $3.1 million from the loss of $6.2 million incurred for the year ended
December 31, 2001. The improvement is due to improved margins between the
prices of natural gas liquids and natural gas in 2002. In 2001, Aux Sable
generated a loss of $6.2 million due to the unfavourable spread between gas
liquids and natural gas prices during the first half of the year. The facilities
operated at a break-even level during the last half of 2001.

Enbridge Gas Distribution is developing, in
consultation with stakeholders, an
incentive regulation plan.

OUTLOOK

Enbridge Gas
2003 Rate Application
Enbridge Gas has filed its 2003 rate application with the OEB, requesting an order to approve rates for the sale,
distribution, transmission and storage of gas, which reflected a gross revenue deficiency, or proposed increase in
revenue rates, of $101.7 million. Of this amount, approximately $9.0 million is associated with changes to the
distribution volume forecast, gas in storage inventory valuation and cost of capital (including the application of the
OEB-approved rate of return on common equity formula), offset somewhat by a decline in federal taxation rates.
A further $43.8 million of the increase arises from a requested increase in operating and maintenance expense
recovery and $13.0 million from the proposed mechanism for recovery of the regulatory receivable related to the
unbundling of the Energy Services business. The remainder relates to variances in all other items requested for
recovery in the application. The 2003 rate application is a traditional cost-of-service application as the PBR plan
ended in 2002. It is expected that the application will be heard by the OEB in early 2003 and a decision is
anticipated in the third quarter of 2003.

The 2003 rate application includes a request to review and revise the current formula used to calculate the rate
of return on common equity. It is anticipated that this request will be heard in a separate phase of the 2003
rate hearing and, as such, the increase to a proposed rate of return of 11.5% versus the 9.95% produced by
the current formula has not been incorporated into the calculation of the $101.7 million deficiency. The increase
in the requested rate of return reflects the Company’s need to compete for investment dollars in the
North American marketplace.

Regulatory Receivable
In a prior rate case, the OEB approved the recovery of $50.0 million of future income taxes related to the water
heater rental business that was transferred to the Energy Service business in 1999. As part of its 2002 rate case,
the Company applied for a mechanism to recover a portion of the $50.0 million. This aspect of the Company’s
application was deferred and the regulatory process is under way.

E N B R I D G E

I N C .

M D & A

Incentive Regulation Plan
The trend in North America is toward incentive, or performance-based, regulation. Enbridge Gas has completed
its three-year, OEB-approved targeted PBR plan. The OEB expects Enbridge Gas to develop, in consultation
with stakeholders, an appropriate incentive regulation plan. Enbridge Gas has provided a proposal for an incentive
regulation plan to stakeholders for the purposes of discussion. For fiscal 2003, Enbridge Gas has filed a cost-of-
service rate application with the OEB, which would be used to establish the base year rates for the incentive
regulation term. The proposal suggests that rates be adjusted annually by a consumer price index and that utility
earnings above or below the OEB-approved return on common equity be shared equally between ratepayers and
Enbridge. Enbridge Gas has proposed that certain costs, such as gas commodity costs and capital expenditures
for the safe operation and maintenance of the distribution system, should be passed through to ratepayers outside
of the calculated rates. Enbridge Gas is holding discussions currently with stakeholders, the outcome of
which may result in changes to the proposal. The plan will be presented to the OEB following the establishment
of base rates for 2003.

2002 Rates Decision
The OEB approved the 2002 revenue requirement and final rates in August 2002. In December 2002, the OEB
released its decision with respect to several policy issues stemming from the 2002 rate case. The OEB’s
decision included concerns and questions about the Company’s business operations in regards to outsourcing
agreements, including the pipeline transportation contract with Alliance, as well as the agreements with
Enbridge and its affiliates. As Enbridge Gas does not accept some aspects of the decision, it has filed a notice
of motion, requesting the OEB to review its decision on Alliance and affiliate outsourcing, or in the alternative
in this latter matter, to conduct a generic hearing on rules for affiliate outsourcing. Enbridge Gas also has filed
an appeal to the Divisional Courts on matters arising from what Enbridge Gas believes to be errors in law
in the decision.

Direct Purchase
Deregulation of the natural gas industry has introduced many changes to the natural gas distribution business,
one of which occurred in the gas marketing segment of the industry. Prior to the advent of deregulation in 1985,
Enbridge Gas supplied natural gas to 100% of its customer base. In 2002, 759,000 customers purchased their
supply of gas from sources other than the utility (2001 — 695,000, 2000 — 602,000). Earnings are not impacted
by the customers’ choice of gas commodity supplier, provided any migration is accurately forecast in advance and
incorporated in the volume underlying the rate application. Enbridge Gas intends to continue to provide customers
the option of purchasing their natural gas directly from the utility.

Enbridge Gas New Brunswick
Customer attachment to the EGNB system has been slower than expected. EGNB
plans to increase the attachment rate by becoming actively involved in the sale of
the natural gas commodity and the sale, installation and service of natural gas
equipment to the residential and small commercial markets. This “bundled”
approach currently is not permitted under provincial legislation. The Company
believes that the government of New Brunswick will be receptive to its plans.

CAPITAL EXPENDITURES
Capital expenditures for the Energy Distribution business are expected to be
approximately $322 million. The majority of the expenditures relate to expansion
of and core maintenance on the Enbridge Gas distribution system. In addition,
expansion of the Enbridge Gas New Brunswick distribution system will continue.

E N B R I D G E

I N C .

Enbridge has a more than 150-year history
of safely providing gas to customers
in Ontario.

M D & A

BUSINESS RISKS

Enbridge Gas
The business risks inherent in the natural gas distribution industry impact
the ability of Enbridge Gas to realize the revenue level required to generate
the allowed return on equity. These business risks include timely and adequate
rate relief, accuracy in forecasting distribution volume and, most importantly,
achieving the forecast natural gas distribution volume. With the ongoing changes
in the electricity industry, Enbridge Gas may face an emerging risk of increased
competition in the energy market.

The regulatory process in North America has been evolving in recent years
towards incentive or performance-based regulation and away from traditional

As a distributor of natural gas, Enbridge provides
service to more than 1.6 million residential,
commercial and industrial customers.

cost-of-service regulation. Since the PBR plan only applied to operation and maintenance expenses, it did not
materially change existing business risks. It is Enbridge Gas’ intention to introduce a comprehensive form of
incentive regulation for 2004. It is anticipated that this form of regulation will provide greater opportunity
to earn in excess of the allowed rate of return, but, as a result, may impact business risk.

Volume Risks
Since customers are billed on a volumetric basis, the ability to collect the total revenue requirement (the cost of
providing service) depends upon achieving the forecast distribution volume established in the rate-making process.
The probability of realizing such volume is contingent upon four key forecast variables: weather; economic
conditions; pricing of competitive energy sources; and the number of customers. Sales and transportation of gas
for customers in the residential and commercial sectors account for approximately 74% of total distribution volume.
Weather during the year, measured in degree-days, has a significant impact on distribution volume as a major
portion of the gas distributed to these two markets is used ultimately for space heating. Sales and transportation
service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions.
As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers
have the ability to switch to an alternate fuel. Customer additions are important to all market sectors as continued
expansion adds to the total consumption of natural gas.

Even in those circumstances where Enbridge Gas attains its total forecast distribution volume, it may not earn the
approved return on equity due to other forecast variables. The mix of sales and transportation of gas for customers
and the mix between the higher margin residential and commercial sectors and lower margin industrial sector
could impact results. The timing of gas sales is also a factor, as the winter season has higher rates than the
summer season.

During 2002, Enbridge Gas received approval from the OEB to defer the difference between forecast and actual
unaccounted for gas. Unaccounted for gas is the difference between volume entering the distribution system and
that delivered to customers, determined based on meter readings. The difference is deferred as a receivable from
or payable to ratepayers until the OEB approves its disposition.

E N B R I D G E

I N C .

M D & A

Rate Relief
Enbridge Gas does not profit from the sale of the natural gas commodity nor is it at risk for the difference between
the actual cost of gas purchased and the price approved by the OEB. This difference is deferred as a receivable
from or payable to ratepayers until the OEB approves its disposition. Enbridge Gas monitors the balance and its
potential impact on ratepayers and will request interim rate relief that will allow it to recover or refund the gas
commodity cost differential. Rate relief can also be sought for other significant unbudgeted amounts, allowing
Enbridge Gas to recover the costs of providing and maintaining the quality of its service while achieving the
allowed rate of return on rate base.

Enbridge Gas implemented a quarterly rate adjustment mechanism starting in 2002. This allows for the quarterly
adjustment of rates to reflect changes in natural gas commodity prices. Adjustments are subject to approval by
the OEB.

Forecasting Accuracy
Forecasting accuracy is a risk since rate applications are made or rates are established in advance based on anticipated
distribution volume by class of customer. Forecasts are also made for the future cost of capital including the
forecast yield rate for long-term Government of Canada Bonds used in the determination of the return on equity.
Consequently, reliability of the forecasting process should ensure that any changes in cost of service, regardless
of whether they are caused by inflation or by level of business activity, would be recovered in new rates approved
for that year based on the anticipated distribution volume.

Gas Services
Earnings from Gas Services are dependent upon the basis (location) differentials between Alberta and Chicago
and between Chicago and Dawn. To the extent that the difference in the price of natural gas in the various
locations is not greater than the cost of transportation between Alberta and Chicago or Dawn, earnings will be
negatively affected.

Aux Sable
Earnings from Aux Sable will continue to be exposed to the effect of unfavourable spreads between the sale prices
of natural gas liquids and the purchase price of replacement natural gas. Equity earnings would be negatively
impacted by a decrease in the spread and positively impacted by an increase in the spread.

I N T E R N A T I O N A L

FINANCIAL RESULTS

(millions of Canadian dollars)
OCENSA/CITCOL
CLH
Jose Terminal
Consulting, business development costs and other

2002
35.3
33.3
3.2
(3.8)
68.0

2001
35.1
–
5.9
(5.4)
35.6

2000
30.3
–
1.5
(5.4)
26.4

BUSINESS ACTIVITIES
International includes earnings from the investments in OCENSA, a crude oil pipeline in Colombia, and CLH,
Spain’s largest refined products transportation and storage business. Earnings also include fees earned as
operator of the Jose Terminal in Venezuela and from technology and consulting services provided by
Enbridge Technology Inc.

E N B R I D G E

I N C .

M D & A

In the first quarter of 2002, the purchase of a 25% interest in CLH, for
approximately $430 million was completed. Enbridge has a role in management
of CLH through Board representation and the appointment of management positions.

RESULTS OF OPERATIONS
Earnings increased by $32.4 million to $68.0 million in 2002. The acquisition
of CLH in the first quarter of 2002 represented the growth in International.
Earnings from other operations approximated 2001.

CLH is Spain’s largest refined products
transportation and storage business.

Earnings in 2001 increased by $9.2 million to $35.6 million. The increase was
partially due to the additional OCENSA ownership interest acquired in the third
quarter of 2000. In addition, higher fees were earned to operate the Jose Terminal,

resulting from the new long-term operating contract finalized in the second quarter of 2001.

OUTLOOK
The International business will continue to focus on select countries in key regions based on global trends in
supply and demand. In addition, opportunistic acquisitions will be assessed based on risk/reward. The technology
and consulting business is expected to provide support in connection with identification and development
of equity participation projects.

The Jose Terminal long-term operating agreement has been in a force majeure situation since December 2002
as a result of the political uncertainty in Venezuela. The Venezuelan military and the Ministry of Energy and
Mines are currently in control of the terminal facilities. Discussions are continuing with PDVSA, the national
oil company, to return the operating company, in which Enbridge holds a 45% interest, to its role under the
operating agreement. In the event the operating role is not re-established, the contract provides for certain
payments to the operator.

Historically, International has focussed on “grass roots” infrastructure projects. Increased international asset
rationalization, the changing corporate strategies of multinationals, and the privatization of energy transportation
activities in focus regions should continue to present investment and acquisition opportunities. Opportunities will
be evaluated against the Company’s established investment criteria. Latin America and Western Europe are key
regions of interest. Enbridge plans for the International segment to contribute approximately 15% of earnings
over the long-term.

BUSINESS RISKS
The International business is subject to risks related to political and economic instability, currency volatility,
market volatility, government regulations, foreign investment rules, security of assets, and environmental
considerations. The Company assesses and monitors international regions and specific countries on an ongoing
basis for changes in these risks. Risks are mitigated by a combination of Enbridge’s contractual arrangements,
operation of the assets, regular analysis of country risk, and foreign currency hedging and insurance programs.

C O R P O R A T E

(millions of Canadian dollars)
Corporate Financing
Other

2002
(64.9)
22.5
(42.4)

2001
(70.4)
14.7
(55.7)

2000
(59.0)
(28.8)
(87.8)

The Corporate segment includes new business development activities and corporate financing costs.

E N B R I D G E

I N C .

M D & A

Corporate costs amounted to $42.4 million in 2002, a decrease of $13.3 million from 2001. In 2002, Corporate
included an after-tax gain on the sale of securities of $17.8 million and lower financing costs. Preferred securities
distributions increased in 2002 due to the new issue in February 2002. In addition, corporate activities contributed
less in 2002 than in 2001 and business development activities were increased in 2002.

Corporate costs totalled $55.7 million in 2001, compared with $87.8 million in 2000. Higher financing costs
associated with investments made late in 2000 and the acquisition of Enbridge Midcoast Energy in May 2001
were incurred during the year. These costs are not allocated to the business operations. Corporate activities also
generated improved results in 2001. In 2000, the Company recorded a loss on foreign exchange contracts of
$15.6 million, after tax, and income tax expense related to tax rate reductions.

In December 2000, the federal government substantively enacted a 6% reduction in corporate tax rates. As a
result, certain of the Company’s anticipated U.S. dollar cash flows became overhedged for accounting purposes.
The derivative financial instruments were valued at market prices and a loss of $15.6 million was charged to
income in 2000. The forward foreign exchange contracts subsequently were designated as a hedge of certain of the
Company’s equity net investments in the United States in the third quarter of 2001.

D I S C O N T I N U E D O P E R A T I O N S

In January 2002, the Company announced the sale of the retail and commercial energy services business, including
the water heater rental program, to focus on its core activities of energy transportation and distribution. The sale,
for proceeds of $1 billion, was completed in the second quarter of 2002. This business included: the water heater
rental program; retail appliance, fireplace and water heater sales and service; and mass market commercial
plumbing, heating, ventilation and air conditioning, appliance repair and electrician contractor services in
Canada and the United States.

Earnings from discontinued operations for the year ended December 31, 2002 were $242.3 million,
compared with $45.3 million for 2001. The 2002 results included a gain on sale of $240.0 million. Earnings
in 2001 included a full year’s results of operations and $14.3 million related to the positive effect of income tax
rate reductions.

Earnings from discontinued operations were $45.3 million in 2001, compared with earnings of $34.6 million
in 2000. The increase is attributable to growth in the business, particularly the water heater rental program.

C R I T I C A L A C C O U N T I N G P O L I C I E S

RATE REGULATION
The Company follows generally accepted accounting principles, which may differ for regulated operations from
those otherwise expected in non-regulated businesses. These differences occur when the regulatory agencies
render their decisions on rate applications and generally involve the timing of revenue and expense recognition
to ensure that the actions of the regulator, which create assets and liabilities, have been reflected in the
financial statements.

The accounting for these items is based on an expectation of the future actions of the regulator. For example,
the Company does not record future income taxes related to its regulated operations as the taxes payable method
is prescribed by the regulator for rate-making purposes and there is reasonable expectation that all such future
income taxes will be recovered in rates when they become payable. Similarly, the deferral of differences between
amounts included in rates and actual experience for specified expenses is based on the expectation that the
regulator will approve the refund to or recovery from ratepayers of the deferred balance, normally in the
following year.

E N B R I D G E

I N C .

M D & A

If the regulator’s future actions are different from the Company’s expectations,
the timing and amount of the recovery of liabilities or refund of assets, recorded
or unrecorded, could be significantly different from that reflected in the
financial statements.

L I Q U I D I T Y A N D C A P I T A L R E S O U R C E S

The Company’s cash generated from operations, commercial paper issuances,
available capacity under credit facilities and access to capital markets in Canada
and the United States for the issue of long-term debt, equity, or other securities
are expected to be sufficient to satisfy liquidity requirements.

Enbridge reduced its debt to equity ratio
to 64.4% as of year end.

One of the Company’s objectives in 2002 was to reduce its debt to equity ratio

and, therefore, strengthen its balance sheet. This objective was achieved. The debt to equity ratio, including
short-term borrowings, at December 31, 2002, was 64.4%, compared with 72.9% at the end of 2001. The reduced
leverage was primarily a result of the proceeds received on the sales of the Energy Services business and the
Enbridge Midcoast Energy assets.

The most significant transaction affecting both investing and financing activities in 2002 was the sale of the
Enbridge Midcoast Energy assets for US$820 million. The Company received cash proceeds of $529.3 million.
The remaining consideration was in the form of assumed debt owing to the Company. Concurrent with the sale
transaction, EEM completed a public offering of 9,000,000 shares, including 1,550,000 shares purchased by
Enbridge. The net proceeds of $421.9 million were used to purchase i-units in EEP. The statement of cash flows
includes the proceeds of EEM’s issuance of shares and investment in EEP, because EEM is a subsidiary of the
Company. The 82.8% interest in EEM not held by Enbridge is displayed as non-controlling interests on the
consolidated statement of financial position. The Company’s consolidated leverage is expected to improve
further through reductions in the assumed affiliated debt as EEP secures additional financing.

OPERATING ACTIVITIES
Cash provided by operating activities before changes in operating assets and liabilities and cash from discontinued
operations was $732.7 million for the year ended December 31, 2002, compared with $735.7 million and
$599.8 million for 2001 and 2000, respectively.

In 2002, cash from operations is consistent with the prior year. Earnings from continuing operations were lower
but include higher non-cash charges which increased cash from operations. The non-cash charges include the loss
on sale of the Enbridge Midcoast Energy assets and higher future income tax expense.

The increase in cash from operations in 2001 was attributable to higher earnings and a decreased level of non-cash
credits. The lower non-cash credits reflected smaller future income tax recoveries resulting from tax rate reductions
and increased cash distributions from Alliance and Vector consistent with operations commencing in late 2000.

The decreased funding requirements for operating assets and liabilities in 2002 was due to lower gas in storage
and decreased accounts receivable, commensurate with the lower cost of gas in 2002. In 2001 and 2000, working
capital funding was required to fund an increase in gas in storage that resulted from the higher commodity cost for
natural gas. The higher cost of gas also increased accounts receivable balances in the gas distribution business.

E N B R I D G E

I N C .

M D & A

Since the Company’s pension plans are adequately funded, no additional funding above usual levels is anticipated
for 2003.

INVESTING ACTIVITIES
Cash used in investing activities for the year ended December 31, 2002 was $251.7 million, compared with
$1,621.7 million in 2001 and $949.8 million in 2000.

During 2002, the Company completed the acquisition of the Northeast Texas assets, included in the asset sale to
EEP, acquired a 25% equity investment in CLH and increased its equity ownership of Alliance. These items, in
addition to capital expenditures in Energy Transportation North and Energy Distribution, represent the majority
of the cash used for investing purposes and more than offset the cash inflows from the sales of the Enbridge
Midcoast Energy assets and the Energy Services business. Capital expenditures in Energy Transportation North
primarily related to construction of new facilities on the Athabasca System. Energy Distribution capital expenditures
included capital maintenance and expansion of the gas distribution system. Cash provided from investing
activities includes proceeds from the sale of marketable securities and partial repayment by EEP of short-term
loans required to finance acquisitions.

Activity in 2001 was the result of acquisitions, including Midcoast Energy Resources, a greater interest in Frontier
Pipeline, and gathering assets in South Texas, as well as a short-term loan to EEP to bridge finance an acquisition.
There were increased additions to property, plant and equipment during 2001, which included the construction
of Terrace Phase II and the Athabasca System facilities expansion, capital maintenance and expansion of the gas
distribution business, and the capital program of Enbridge Midcoast Energy subsequent to acquisition. These were
offset, in part, by significantly reduced long-term investment activity, as Alliance and Vector construction was
completed in late 2000.

FINANCING ACTIVITIES
Over the three-year period, the Company’s financing requirements have reflected its growth and investment strategies.
The decision to finance with debt or equity is based on the capital structure for each business and the overall
capitalization of the consolidated enterprise. Certain of the regulated pipeline and gas distribution businesses issue
long-term debt to finance capital expenditures. This external financing may be supplemented by debt or equity
injections from the parent company. Debt, and equity when required, has been issued to finance business
acquisitions, investments in subsidiaries and long-term investments. Funds for debt retirements are generated
through cash provided from operating activities, as well as through the issue of replacement debt.

In 2002, cash used for financing activities to reduce short-term debt was partially offset by cash received from the
issue of additional common shares and preferred securities. These activities were consistent with the goal
of improving the Company’s debt to equity ratio and financing the growth in
the business. Proceeds from the issuance of shares by EEM were used to invest
in i-units of EEP, as described above.

In 2001, cash provided from financing activities was greater than 2000 to
support the increased levels of investing activity, primarily through acquisition,
and higher capital expenditures. Investing activity was financed primarily with
short-term variable rate debt on an interim basis.

The Company expects to further improve its
consolidated leverage in 2003.

E N B R I D G E

I N C .

M D & A

Capital Expenditures,
Investments and
Acquisitions
(millions of dollars)

5
.
5
4
6
,
1

2
.
1
4
1
,
1

2
.
4
2
3
,
1

9
.
1
0
3
,
2

7
.
5
3
9

98 99

R I S K M A N A G E M E N T

OPERATING RISK
As Enbridge continues to diversify its energy transportation and distribution
businesses in North America and internationally, the risk profile of the Company
will change. Entry into non-regulated businesses imposes greater economic
exposure and requires more “at risk” capital. The Company’s expectation of higher
returns from these businesses justifies the level of risk. In addition, these operating
risks are actively managed through insurance and other programs.

MARKET RISK
Earnings and cash flows are subject to volatility stemming from movements in the
Canadian dollar exchange rate relative to other currencies and interest rates. The
Company has adopted an earnings at risk methodology to measure its exposure to
market risk. To manage market risk, Enbridge uses derivative financial instruments
to create offsetting positions to specific exposures. The Company has established
risk management policies, approved by the Board of Directors, covering the use
of derivative financial instruments for hedging purposes. Ongoing monitoring and
senior management reporting procedures are in place. Derivative financial instruments
are not used to create speculative positions. The financial instruments used and
outstanding are described in Note 12 to the consolidated financial statements.

Foreign Exchange Risk
The Company has a hedging program to eliminate 80% to 100% of the long-term exposure related to its foreign
currency denominated cash flows. The Company also hedges certain of its foreign currency denominated net
equity investments. The redemption of the investment in OCENSA also is hedged.

Interest Rate Risk
Enbridge is exposed to interest rate fluctuations on variable rate debt and floating to fixed swaps are used to
manage this exposure. The Company monitors its levels of fixed and variable rate debt instruments and, from time
to time, fixed to floating swaps are used to help maintain balances of each commensurate with the Company’s
financing strategies. The Company also enters into interest rate derivatives to hedge a portion of the interest cost
of future debt issues related to specific capital projects.

Commodity Price Risk
The Company uses over-the-counter natural gas price swaps, futures, options and collars to manage physical
exposures that arise from the merchant capacity commitments on Alliance and Vector. For the period that the
Enbridge Midcoast Energy assets were owned, the Company was exposed to the margin between the price of
natural gas and natural gas liquids. Enbridge used over-the-counter commodity derivatives to fix the selling price
of the natural gas liquids and the cost of purchasing natural gas to establish the margins. The derivative financial
instruments used to manage this exposure were transferred to EEP as part of the sale transaction.

Natural Gas Supply Management
Customers of Enbridge Gas are exposed to changes in the price of the natural gas commodity. A portion of the
future natural gas supply requirements is hedged using natural gas swaps and options that manage the price of
natural gas, as allowed by the OEB. Since the cost of the natural gas commodity is paid by customers, this risk
mitigation strategy is for the account of the customers. The OEB monitors the policies, procedures and results
of this hedging program.

Quarterly Financial Information
Selected financial information for the eight most recently completed quarters is shown on page 70.

E N B R I D G E

I N C .

M A N A G E M E N T ’ S R E P O R T

M a n a g e m e n t

’ s R e p o r

To the Shareholders of Enbridge Inc.
Management is responsible for the accompanying consolidated financial statements and all other information in
this Annual Report. The consolidated financial statements have been prepared in accordance with Canadian
generally accepted accounting principles and necessarily include amounts that reflect management’s judgement
and best estimates. Financial information contained elsewhere in this Annual Report is consistent with the
consolidated financial statements.

Management has established systems of internal control that provide reasonable assurance that assets are
safeguarded from loss or unauthorized use and produce reliable accounting records for the preparation of
financial information. The internal control system includes an internal audit function and an established code
of business conduct.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company.
The Audit, Finance & Risk Committee of the Board, composed of directors who are not officers or employees
of the Company, has a specific responsibility for ensuring that management fulfills its responsibilities for
financial reporting and internal controls related thereto. The Committee meets with management, internal
auditors and independent auditors to review the consolidated financial statements and the internal controls as
they relate to financial reporting. The Audit, Finance & Risk Committee reports its findings to the Board for
its consideration in approving the consolidated financial statements for issuance to the shareholders.

PricewaterhouseCoopers LLP, appointed by the shareholders as the Company’s independent auditors, conducts
an examination of the consolidated financial statements in accordance with Canadian generally accepted
auditing standards.

Patrick D. Daniel
President & Chief Executive Officer
January 27, 2003

D.P. Truswell
Group Vice President & Chief Financial Officer

E N B R I D G E

I N C .

A u d i

t o r s ’

R e p o r

A U D I T O R S ’ R E P O R T

To the Shareholders of Enbridge Inc.
We have audited the consolidated statements of financial position of Enbridge Inc. as at December 31, 2002
and 2001 and the consolidated statements of earnings, retained earnings and cash flows for each of the years
in the three year period ended December 31, 2002. These financial statements are the responsibility of the
Corporation’s management. Our responsibility is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards
require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial
position of the Company as at December 31, 2002 and 2001 and the results of its operations and cash flows for
each of the years in the three year period ended December 31, 2002 in accordance with Canadian generally
accepted accounting principles.

Calgary, Alberta, Canada
January 27, 2003

Chartered Accountants

Comments by Auditors for U.S. Readers on Canada-U.S. Reporting Difference
In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following
the opinion paragraph) when there is a change in accounting principles that has a material effect on the
comparability of the Corporation’s financial statements, such as the changes in stock-based compensation and
accounting for goodwill described in Note 1 to the consolidated financial statements. Our report to the
shareholders dated January 27, 2003 is expressed in accordance with Canadian reporting standards which do
not require a reference to such a change in accounting principles in the auditors’ report when the change is
properly accounted for and adequately disclosed in the financial statements.

Calgary, Alberta, Canada
January 27, 2003

Chartered Accountants

E N B R I D G E

I N C .

C O N S O L I D A T E D S T A T E M E N T S O F E A R N I N G S

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

(millions of Canadian dollars, except per share amounts)
Year ended December 31,
Revenues

Gas sales
Transportation
Energy services

Expenses

Gas costs
Operating and administrative
Depreciation
Loss on sale of Enbridge Midcoast Energy assets

Operating Income
Investment and Other Income (Note 15)
Interest Expense (Note 8)

Income Taxes (Note 13)
Earnings From Continuing Operations
Earnings From Discontinued Operations (Note 5)
Earnings
Preferred Security Distributions (Note 9)
Preferred Share Dividends (Note 10)
Earnings Applicable to Common Shareholders
Earnings Applicable to Common Shareholders

Continuing Operations
Discontinued Operations

Earnings Per Common Share (Note 10)

Continuing Operations
Discontinued Operations

Diluted Earnings Per Common Share (Note 10)

Continuing Operations
Discontinued Operations

C O N S O L I D A T E D S T A T E M E N T S O F R E T A I N E D E A R N I N G S

(millions of Canadian dollars, except per share amounts)
Year ended December 31,
Retained Earnings at Beginning of Year
Earnings Applicable to Common Shareholders
Effect of Change in Accounting for Income Taxes
Effect of Change in Accounting for Stock-Based Compensation
Preferred Securities Issue Costs
Common Share Dividends
Retained Earnings at End of Year
Dividends Paid Per Common Share

2002
812.3
576.5
–
(5.4)
(4.2)
(251.1)
1,128.1
1.52

2001
581.3
458.5
–
–
–
(227.5)
812.3
1.40

The accompanying notes to the consolidated financial statements are an integral part of these statements.

E N B R I D G E

I N C .

2002

2001

2000

2,987.7
1,296.6
263.2
4,547.5

2,578.0
834.1
403.9
122.7
3,938.7
608.8
283.1
(422.0)
469.9
(102.1)
367.8
242.3
610.1
(26.7)
(6.9)
576.5

334.2
242.3
576.5

2.09
1.51
3.60

2.06
1.50
3.56

2,675.3
1,177.6
228.0
4,080.9

1,407.0
1,035.2
128.4
2,570.6

958.8
613.0
387.5
–
1,959.3
611.3

2,202.8
739.1
392.5
–
3,334.4
746.5
194.9171.5
(437.1)(389.2)
504.3
(66.7)(13.7)
437.6
45.334.6
482.9
(17.5)(15.3)
(6.9)(6.9)
458.5392.3

413.2
45.3
458.5

2.63
0.28
2.91

2.60
0.28
2.88

393.6

379.9

414.5

357.7
34.6
392.3

2.32
0.22
2.54

2.31
0.22
2.53

2000
503.1
392.3
(112.0)
–
–
(202.1)
581.3
1.27

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S

(millions of Canadian dollars)
Year ended December 31,
Cash Provided By Operating Activities

Earnings from continuing operations
Charges/(credits) not affecting cash

Depreciation
Equity earnings less than/(in excess of) cash distributions
Gain on reduction of ownership interest (Note 7)
Loss on foreign exchange contracts
Gain on sale of securities
Loss on sale of Enbridge Midcoast Energy assets (Note 3)
Future income taxes
Other

Changes in operating assets and liabilities (Note 16)
Cash provided by operating activities of discontinued operations

Investing Activities
Acquisitions
Long-term investments
Additions to property, plant and equipment
Sale of Energy Services business (Note 5)
Sale of Enbridge Midcoast Energy assets (Note 3)
Sale of other assets
Sale of securities
Repayments by/(loans to) affiliate
Changes in construction payable
Other

Financing Activities

Net change in short-term borrowings and short-term debt
Long-term debt issues
Long-term debt repayments
Non-controlling interests
Preferred securities issued
Common shares issued
Enbridge Energy Management shares issued (Note 7)
Preferred security distributions
Preferred share dividends
Common share dividends

Increase/(Decrease) in Cash
Cash at Beginning of Year
Cash at End of Year

The accompanying notes to the consolidated financial statements are an integral part of these statements.

E N B R I D G E

I N C .

2002

2001

2000

367.8

437.6

379.9

403.9
(44.6)
(10.0)
–
(21.4)
122.7
(64.7)
(21.0)
151.6
26.3
910.6

(289.3)
(1,282.7)
(729.9)
993.3
529.3
73.8
110.5
358.1
(14.8)
–
(251.7)

(1,180.9)
247.4
(382.7)
0.2
193.5
293.1
421.9
(26.7)
(6.9)
(251.1)
(692.2)
(33.3)
74.0
40.7

392.5
1.2
(23.4)–
–
–
–
3.4
(75.6)

(323.1)(515.4)

1.9
414.5

(599.1)
(41.8)
(683.3)
–
–
–
–
(280.6)
(14.0)
(2.9)
(1,621.7)

1,521.4
905.6
(979.6)
(4.1)
–
23.3
–
(17.5)
(6.9)
(227.5)
1,214.7
7.5
66.5
74.0

387.5
(52.0)

24.5
–
–
(117.1)
(23.0)

179.1
263.5

(16.5)
(554.9)
(364.3)
–
–
–
–
–
(5.7)
(8.4)
(949.8)

(105.2)
965.4
(133.3)
21.2
–
175.4
–
(15.3)
(6.9)
(202.1)
699.2
12.9
53.6
66.5

C O N S O L I D A T E D S T A T E M E N T S O F F I N A N C I A L P O S I T I O N

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

(millions of Canadian dollars)
December 31,
Assets
Current Assets
Cash
Accounts receivable and other
Gas in storage
Current assets of discontinued operations (Note 5)
Current assets held for sale (Note 3)

Property, Plant and Equipment, net (Note 6)
Long-Term Investments (Note 7)
Receivable from Affiliate (Note 3)
Deferred Amounts
Future Income Taxes (Note 13)
Long-Term Assets of Discontinued Operations (Note 5)
Long-Term Assets Held for Sale (Note 3)

Liabilities and Shareholders’ Equity
Current Liabilities

Short-term borrowings
Accounts payable and other
Interest payable
Current maturities and short-term debt (Note 8)
Current liabilities of discontinued operations (Note 5)
Current liabilities held for sale (Note 3)

Long-Term Debt (Note 8)
Future Income Taxes (Note 13)
Non-Controlling Interests (Note 7)
Long-Term Liabilities of Discontinued Operations (Note 5)

Shareholders’ Equity
Share capital

Preferred securities (Note 9)
Preferred shares (Note 10)
Common shares (Note 10)

Retained earnings
Foreign currency translation adjustment
Reciprocal shareholding (Note 7)

Commitments and Contingencies (Note 18)

2002

2001

40.7
817.5
583.8
–
–
1,442.0
6,947.6
3,371.5
701.5
315.8
209.0
–
–
12,987.4

247.5
714.1
102.6
652.3
–
–
1,716.5
6,040.3
837.4
560.8
–
9,155.0

533.7
125.0
2,169.0
1,128.1
12.3
(135.7)
3,832.4

74.0
1,270.2
665.6
123.0
148.9
2,281.7
6,817.5
1,772.8
–
329.7
142.0
750.0
1,034.0
13,127.7

410.9
679.9
100.2
1,819.7
73.8
125.3
3,209.8
5,913.3
722.8
131.1
118.6
10,095.6

339.7
125.0
1,875.9
812.3
7.4
(128.2)
3,032.1

12,987.4

13,127.7

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Approved by the Board:

Donald J. Taylor
Chair

Robert W. Martin
Director

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

N O T E S T O T H E C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Enbridge Inc. (Enbridge or the Company) is a leader in the transportation and distribution of energy. Enbridge
conducts its business through four operating segments: Energy Transportation North, Energy Transportation South,
Energy Distribution, and International. These operating segments are strategic business units established by senior
management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation
decisions and to assess operational performance.

Energy Transportation North
Energy Transportation North includes the operation of a common carrier pipeline and feeder pipelines which
transport crude oil and other liquid hydrocarbons, equity investments in natural gas transmission pipelines and
an equity investment in a company engaged in natural gas gathering and processing.

Energy Transportation South
Energy Transportation South consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP)
and Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership). The Partnership transports
crude oil and other liquid hydrocarbons through common carrier and feeder pipelines, and transports, gathers,
processes and markets natural gas and natural gas liquids. The Company owned 100% of the assets of Enbridge
Midcoast Energy from May 2001 until October 2002, when they were sold to EEP. The business activities of
Energy Transportation South are carried out in the United States.

Energy Distribution
The Energy Distribution business consists of gas utility operations which serve residential, commercial, industrial
and transportation customers, primarily in central and eastern Ontario. This business also includes natural gas
distribution activities in Quebec, New Brunswick and New York State, as well as gas services operations,
including the equity investment in Aux Sable.

International
The Company’s International business invests in energy transportation and related energy projects outside of
Canada and the United States. This business also provides consulting and training services related to proprietary
pipeline operating technologies and natural gas distribution.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements of the Company are prepared in accordance with Canadian generally
accepted accounting principles (Canadian GAAP). These accounting principles are different in some respects from
United States generally accepted accounting principles (U.S. GAAP) and the significant differences that impact
the Company’s financial statements are described in Note 19. Amounts are stated in Canadian dollars unless
otherwise noted.

The preparation of financial statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses, as well as the disclosure of contingent assets and liabilities in the financial statements. Actual
results could differ from those estimates.

Basis of Presentation
The consolidated financial statements include the accounts of Enbridge Inc., its subsidiaries and its proportionate
share of the accounts of joint ventures. Investments in entities which are not subsidiaries or joint ventures, but
over which the Company exercises significant influence, are accounted for using the equity method. Other
investments are accounted for at cost.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

The Company’s Energy Distribution business is conducted primarily through a wholly owned subsidiary,
Enbridge Gas Distribution Inc. (Enbridge Gas), formerly The Consumers’ Gas Company Ltd. The fiscal year-end
of Enbridge Gas is September 30 and its results are consolidated on a one quarter lag basis, which reflects the
results of Enbridge Gas operations in accordance with its regulatory, tax and operating cycles. Accordingly,
references to "December 31" mean the financial position of Enbridge Gas as at September 30 and references
to the "year ended December 31" mean the results of Enbridge Gas for the year ended September 30.

Regulation
The Company’s Energy Transportation and Energy Distribution activities are subject to regulation by various
authorities, including the National Energy Board (NEB), the Federal Energy Regulatory Commission
(FERC), and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters
such as construction, rates and underlying accounting practices, and ratemaking agreements with customers.
In order to recognize the economic effects of the actions of the regulator, the timing of recognition of certain
revenues and expenses in these operations may differ from that otherwise expected under generally
accepted accounting principles.

Revenue Recognition
Revenues are recorded when products have been delivered or services have been performed. Certain of the
Energy Transportation and Energy Distribution operations are subject to regulation and, accordingly, there are
circumstances where revenues recognized do not match the cash tolls or the billed amounts. For rate-regulated
operations, revenue is recognized in a manner that is consistent with the underlying rate design as mandated
by the regulatory authority. Certain other operations recognize revenue under the terms of enforceable,
committed long-term delivery contracts.

Income Taxes
The regulated activities of the Company recover income tax expense based on the taxes payable method when
prescribed by regulators for ratemaking purposes or when stipulated in ratemaking agreements. Therefore, rates
do not include the recovery of future income taxes related to temporary differences. Consequently, the taxes
payable method is followed for accounting purposes as there is reasonable expectation that all future income
taxes will be recovered in rates when they become payable.

For all other operations, the liability method of accounting for income taxes is followed. Future income tax
assets and liabilities are determined based on temporary differences between the tax bases of assets and liabilities
and their carrying values for accounting purposes. Future income tax assets and liabilities are measured using
the tax rate that is expected to apply when the temporary differences reverse.

Effective January 1, 2000, the Company adopted new recommendations for accounting for income taxes.
Adoption of the recommendations resulted in a charge to retained earnings of $112.0 million, of which $76.1
million related to rental assets of Enbridge Gas no longer regulated by the OEB, $22.4 million related to the
tax effect of differences between the carrying amounts of investments and their respective tax bases, and the
remaining $13.5 million related to other non-regulated assets.

Foreign Currency Translation
The functional currency of the Company’s foreign operations, except for certain financing and investing operations,
is the U.S. dollar. These operations are self-sustaining and translated into Canadian dollars using the current
rate method. Gains and losses resulting from these translation adjustments are included as a separate component
of shareholders’ equity.

E N B R I D G E

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The Company’s foreign financing and investing operations are integrated with those of the parent company and
are translated into Canadian dollars using the temporal method. Gains and losses resulting from these translation
adjustments are included in earnings.

Cash
Cash includes short-term and demand deposits with a term to maturity of three months or less and are recorded
at cost.

Gas in Storage
Natural gas in storage is recorded in inventory at prices approved by the OEB in the determination of customer
sales rates. The actual price of gas purchased may differ from the OEB-approved price and includes the effect
of natural gas price risk management activities. The difference between the approved price and the actual cost
of the gas purchased is deferred for future disposition by the OEB.

Property, Plant and Equipment
Expenditures for system expansion and major renewals and betterments are capitalized; maintenance and
repair costs are expensed as incurred. Regulated operations capitalize an allowance for interest during
construction and, if approved, an allowance for equity funds used during construction, at rates authorized
by the regulatory authorities.

Depreciation
Depreciation of property, plant and equipment generally is provided on a straight-line basis over the estimated
service lives of the assets.

Future Removal and Site Restoration Costs
Future removal and site restoration costs for the Energy Transportation operations are not determinable and will
be recognized when approved for recovery in tolls by the regulators. Accordingly, no provision has been made
for these costs as there is reasonable expectation that they will be recovered through future tolls when they
become payable.

Depreciation expense for Energy Distribution operations includes a provision for future removal and site restoration
costs at rates approved by the regulator. Actual costs incurred are charged to accumulated depreciation.

Goodwill
Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition
of a business. Effective January 1, 2002, the Company adopted the new standard of the Canadian Institute of
Chartered Accountants (CICA) related to goodwill and other intangible assets. Under the new standard, goodwill
is not amortized but is tested for impairment at least annually and written down to fair value if the criteria for
impairment are met. The standard is being applied prospectively. Goodwill arising from the acquisition of
Midcoast Energy Resources, Inc. in May 2001 (sold to EEP in October 2002), was amortized on a straight-line
basis over 30 years prior to the adoption of the new standard. Results of operations for the year ended
December 31, 2001 included goodwill amortization of $7.2 million. This amortization reduced both earnings
per common share and diluted earnings per common share by $0.05 for the year ended December 31, 2001.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Derivative Financial Instruments
Gains and losses on financial instruments used to hedge the Company’s net investment in foreign operations are
included in the foreign currency translation adjustment in shareholders’ equity. Amounts received or paid related
to derivative financial instruments used to hedge the currency risk of cash flows from foreign currency denominated
transactions are recognized concurrently with the hedged cash flows. Amounts received or paid related to
derivative financial instruments used to hedge the price of energy commodities are recognized as part of the cost
of the underlying physical purchases. For other derivative financial instruments used for hedging purposes,
amounts received or paid, including any gains and losses realized upon settlement, are recognized over the term
of the hedged item.

The Company applies settlement accounting to derivative financial instruments. Under this method, gains and
losses on derivative instruments that qualify for hedge accounting are not recorded until they are realized. The
notional amounts are not recorded in the financial statements as they do not represent amounts exchanged by
the counterparties.

Post-Employment Benefits
The Company maintains both defined benefit and defined contribution pension plans. Pension costs and obligations
for the defined benefit pension plans are determined using the projected benefit method and are charged to
earnings as services are rendered, except for the regulated operations of the Energy Distribution segment where
contributions made to the plan are expensed as paid, consistent with the recovery of such costs in rates. For the
defined contribution plans, contributions made by the Company are expensed.

The Company also provides post-employment benefits other than pensions, including group health care and life
insurance benefits for eligible retirees, their spouses and qualified dependants. The cost of such benefits is accrued
during the years employees render service, except for the regulated operations of the Energy Distribution segment
where the cost of providing these benefits is expensed as paid, consistent with the recovery of such costs in rates.

Stock-Based Compensation
Effective January 1, 2002, the Company adopted the new CICA standard for stock-based compensation. Awards
not required to be expensed under the new standard, such as stock options, are accounted for as capital
transactions when the options are exercised. The standard requires retroactive application for certain other stock
compensation awards as a charge to opening retained earnings without restatement of prior periods. Outstanding
stock appreciation rights, which expire in 2003 and 2004, resulted in a charge to opening retained earnings, on
adoption, of $5.4 million.

Comparative Amounts
Certain comparative amounts have been restated to conform with the current year’s financial statement presentation.

Change in Accounting Policy
In September 2002, the CICA announced the deferral of the effective date of the accounting guideline on Hedging
Relationships to fiscal years beginning on or after July 1, 2003. In addition, in December 2002, the CICA approved
an exposure draft to amend the guideline. As a result, the Company is deferring adoption of the new guideline.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

2. SEGMENTED INFORMATION
Year ended December 31, 2002

(millions of dollars)
Revenues
Gas costs
Operating and administrative
Depreciation
Loss on sale of Enbridge Midcoast

Energy assets
Operating income/(loss)
Investment and other income
Interest and preferred equity charges
Income taxes
Earnings/(loss) from

North
742.7
–
(263.6)
(143.2)

–
335.9
82.7
(99.8)
(82.6)

Energy Transportation

Energy

South Distribution International Corporate 1 Consolidated
27.2
4,547.5
(2,578.0)
–
(834.1)
(19.0)
(403.9)
(2.9)

2,506.6
(1,526.6)
(404.3)
(229.9)

6.8
–
(16.5)
(3.1)

1,264.2
(1,051.4)
(130.7)
(24.8)

(122.7)
(65.4)
44.2
(28.1)
7.9

–
345.8
19.9
(161.1)
(90.8)

–
5.3
64.0
(1.6)
0.3

–
(12.8)
72.3
(165.0)
63.1

continuing operations

236.2

(41.4)

113.8

68.0

(42.4)

Earnings from discontinued operations
Earnings applicable

to common shareholders

Year ended December 31, 2001

Energy Transportation

Energy

(122.7)
608.8
283.1
(455.6)
(102.1)

334.2

242.3

576.5

(millions of dollars)
Revenues
Gas costs
Operating and administrative
Depreciation
Operating income/(loss)
Investment and other income/(expense)
Interest and preferred equity charges
Income taxes
Earnings/(loss) from

North
695.6
–
(242.6)
(134.9)
318.1
69.6
(104.0)
(78.6)

South Distribution International Corporate1 Consolidated
30.8
708.8
4,080.9
(2,202.8)
–
(558.9)
(739.1)
(19.0)
(71.3)
(392.5)
(2.5)
(29.2)
746.5
9.3
49.4
194.9
27.0
53.0
(461.5)
(0.1)
(28.3)
(66.7)
(0.6)
(27.7)

2,638.3
(1,643.9)
(385.1)
(222.1)
387.2
(0.2)
(161.7)
(43.5)

7.4
–
(21.1)
(3.8)
(17.5)
45.5
(167.4)
83.7

continuing operations

205.1

46.4

181.8

35.6

(55.7)

Earnings from discontinued operations
Earnings applicable

to common shareholders

413.2

45.3

458.5

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Energy Transportation

Energy

North
699.5
–
(243.9)
(156.3)
299.3
55.3
(106.4)
(55.6)

South Distribution International Corporate 1 Consolidated
2,570.6
22.2
30.1
(958.8)
–
–
(613.0)
(17.8)
(18.5)
(387.5)
(0.7)
(7.5)
611.3
3.7
4.1
171.5
22.6
35.3
(411.4)
–
(1.9)
(13.7)
0.1
(14.2)

1,812.4
(958.8)
(307.8)
(214.3)
331.5
50.8
(166.1)
(13.0)

6.4
–
(25.0)
(8.7)
(27.3)
7.5
(137.0)
69.0

Year ended December 31, 2000

(millions of dollars)
Revenues
Gas costs
Operating and administrative
Depreciation
Operating income/(loss)
Investment and other income
Interest and preferred equity charges
Income taxes
Earnings/(loss) from

continuing operations

192.6

23.3

203.2

26.4

(87.8)

Earnings from discontinued operations
Earnings applicable

to common shareholders

357.7

34.6

392.3

1 Corporate includes new business development activities and investing and financing activities, including general corporate investments and financing costs not

allocated to the business segments.

2 The measurement basis for preparation of segmented information is consistent with the significant accounting policies described in Note 1.
3 Segmented information was restated to reflect changes in the internal organization of the Company in the fourth quarter of 2002.

Total Assets

(millions of dollars)
December 31,
Energy Transportation North
Energy Transportation South 1
Energy Distribution
International
Corporate

Discontinued Operations

2002
4,621.3
1,151.1
5,275.8
830.7
1,108.5
12,987.4
–
12,987.4

2001
4,244.2
1,544.9
5,401.8
294.3
769.5
12,254.7
873.0
13,127.7

1 Includes goodwill of $330.4 million in 2001 related to the acquisition of Enbridge Midcoast Energy, sold in the fourth quarter of 2002, as described in Note 3.

Additions to Property, Plant and Equipment

(millions of dollars)
Year ended December 31,
Energy Transportation North
Energy Transportation South
Energy Distribution
International and Corporate

Discontinued Operations

2002
257.4
128.9
313.2
7.5
707.0
22.9
729.9

2001
216.1
85.9
302.6
35.2
639.8
43.5
683.3

2000
85.9
0.6
255.4
2.0
343.9
20.4
364.3

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

2. SEGMENTED INFORMATION (continued)
Geographic Information
Revenues

(millions of dollars)
Year ended December 31,
Canada
United States
Other

Revenues are attributed to countries based on the country of origin of the product or services sold.

Property, Plant and Equipment

(millions of dollars)
December 31,
Canada
United States
Other

2002
3,102.3
1,418.0
27.2
4,547.5

2001
3,317.7
736.8
26.4
4,080.9

2002
6,733.6
204.8
9.2
6,947.6

2000
2,511.1
41.8
17.7
2,570.6

2001
6,630.4
176.9
10.2
6,817.5

3. SALE OF ENBRIDGE MIDCOAST ENERGY ASSETS
In October 2002, the Company closed the sale of the United States assets of Enbridge Midcoast Energy to EEP,
including the Northeast Texas assets described in Note 4, for proceeds of US$820.0 million. The Company
received cash proceeds of approximately US$339.0 million and the remaining consideration, in the form of
assumed affiliate debt, will be settled when EEP secures additional financing.

The Company continues to exercise significant influence over the assets sold and, for the period that the assets
were held for sale, results of operations were not segregated from continuing operations. For the year ended
December 31, 2002, excluding the loss on sale of $82.2 million after tax, the assets generated after-tax earnings
of $7.3 million.

4. ACQUISITIONS
Northeast Texas
In March 2002, the Company acquired natural gas gathering and processing facilities in Northeast Texas for
cash consideration of $289.3 million. These assets are included in the sale described in Note 3. The results
of operations have been included in the consolidated statement of earnings for the period of ownership.

(millions of dollars)
Fair Value of Assets Acquired

Property, plant and equipment
Goodwill
Working capital deficiency

Purchase Price
Cash
Transaction costs

E N B R I D G E

I N C .

242.3
56.2
(9.2)
289.3

288.2
1.1
289.3

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Midcoast Energy Resources, Inc.
On May 11, 2001, the Company acquired all the outstanding shares of Midcoast Energy Resources, Inc.,
a Houston-based energy company, for cash consideration of $561.8 million and the assumption of long-term debt.
This business is included in the sale described in Note 3. The acquisition was accounted for using the purchase
method and the results of operations have been included in the consolidated statements of earnings from the
date of acquisition until they were sold in October 2002.

(millions of dollars)
Fair Value of Assets Acquired

Property, plant and equipment
Working capital deficiency
Goodwill
Future income taxes
Other non-current assets

Purchase Price
Cash
Long-term debt assumed
Transaction costs

677.3
(37.2)
328.9
(39.0)
37.8
967.8

554.5
406.0
7.3
967.8

Frontier Pipeline Company
The Company acquired an additional 34.0% interest in Frontier Pipeline Company for $46.0 million in December
2001, increasing the Company’s ownership to 77.8%. The purchase price was allocated primarily to property,
plant and equipment.

5. DISCONTINUED OPERATIONS
The sale of the Company’s operations that provide energy products and services to retail and commercial customers,
including the water heater rental program, closed in May 2002.

Selected financial information related to discontinued operations is as follows.

Earnings

(millions of dollars)
Year ended December 31,
Net gain on disposition, net of tax
Earnings
Earnings from discontinued operations

Selected Earnings Information

(millions of dollars)
Year ended December 31,
Revenues

Income tax expense/(recovery)

Allocated interest expense

2002
240.0
2.3
242.3

2002
181.9

34.6

12.1

2001
–
45.3
45.3

2001
463.0

2.5

35.4

2000
–
34.6
34.6

2000
388.5

(15.6)

38.5

E N B R I D G E

I N C .

C o n s o l

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S t a t e m e n t s

6. PROPERTY, PLANT AND EQUIPMENT
(millions of dollars)
December 31, 2002
Energy Transportation North
Energy Transportation South
Energy Distribution
Other

Weighted Average
Depreciation Rate
3.3%
4.1%
3.6%
6.6%

(millions of dollars)
December 31, 2001
Energy Transportation North
Energy Transportation South
Energy Distribution
Other

Weighted Average
Depreciation Rate
2.5%
3.9%
3.2%
6.1%

7. LONG-TERM INVESTMENTS
(millions of dollars)
December 31,
Equity Investments

Energy Transportation North

Alliance Pipeline
Vector Pipeline
AltaGas Services

Energy Transportation South

The Partnership
Chicap Pipeline

Energy Distribution

Noverco
Aux Sable

International

Compañía Logistica de Hidrocarburos (CLH)

Other

Cost Investments

Energy Distribution

Noverco
International

OCENSA Pipeline
Global Thermoelectric

E N B R I D G E

I N C .

Accumulated
Cost Depreciation
1,657.9
99.7
822.3
21.1
2,601.0

4,526.2
262.0
4,687.4
73.0
9,548.6

Accumulated
Cost Depreciation
1,516.8
90.0
706.7
12.5
2,326.0

4,260.1
266.9
4,542.2
74.3
9,143.5

Net
2,868.3
162.3
3,865.1
51.9
6,947.6

Net
2,743.3
176.9
3,835.5
61.8
6,817.5

Ownership
Interest

2002

2001

37.1%
45.0%
40.3%

14.1%
22.8%

32.1%
30.9%

25.0%

678.6
474.8
204.2
1,357.6

376.6
472.9
181.1
1,030.6

815.5
32.4
847.9

28.9
135.0
163.9

541.2
31.2

93.5
31.7
125.2

33.9
124.6
158.5

–
28.8

181.4

223.3
25.0
3,371.5

223.3
25.0
1,772.8

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Equity investments include $551.9 million (2001 — $208.1 million) representing the unamortized excess of the
purchase price over the underlying net book value of the investee’s assets at the date of purchase. The excess has
been allocated to property, plant and equipment on the basis of estimated fair values and is amortized over the
economic life of the assets.

In October 2002, EEM, a partially-owned subsidiary, completed an initial public offering of 9,000,000 limited
liability shares. The proceeds from the offering were used to purchase i-units, a new class of limited partnership
interests from EEP. The Company purchased 17.2% of the EEM shares, increasing its total net investment in the
Partnership to 14.1% from 12.9%. Although 82.8% of EEM is widely held, the Company has voting control of
EEM. The Company’s statement of financial position includes 100% of EEM’s investment in EEP which totals
$529.9 million. The Company’s net investment in the Partnership, after deducting the non-controlling interest of
$438.8 million, is $376.7 million.

In 2002 and prior to the formation of EEM, EEP completed a public issue of partnership units. As the Company
elected not to participate in this offering, its effective interest in EEP was reduced to 12.9% from 13.6%. This
resulted in recognition of a dilution gain of $10.0 million, before tax. In 2001, EEP completed two public issues of
partnership units, in which the Company elected not to participate. As a result of these offerings, the Company’s
effective ownership interest in EEP was reduced to 13.6% from 15.3%, resulting in recognition of dilution gains
of $23.4 million, before tax.

In 2002, the Company invested $294.7 million in Alliance and $20.6 million in Aux Sable, increasing the
Company’s ownership interests from 21.4% to 37.1% and 21.4% to 30.9%, respectively. The purchase price
included $7.1 million representing the excess of the purchase price over the underlying net book value of the
assets. The excess has been allocated to property, plant and equipment and is being amortized over the economic
life of the assets.

In 2002, the Company invested $430.8 million in CLH, a refined products transportation and storage company in
Spain. The Company’s 25% interest is accounted for by the equity method. Contingent consideration of up to
90 million Euros ($149.1 million) will become payable over the next four years if certain minimum annual volume
targets are met. The purchase price included $340.9 million representing the excess of the purchase price over the
underlying net book value of the assets. The excess has been allocated to property, plant and equipment and is
being amortized over the economic life of the assets.

Noverco holds an approximate 10% reciprocal shareholding in the Company. As a result, the Company has a
pro-rata interest of 3.2% in its own shares (2001 — 3.2%). Both the equity investment in Noverco Inc. and
shareholders’ equity have been reduced by the reciprocal shareholding of $135.7 million (2001 — $128.2 million).

Income from Equity Investments

(millions of dollars)
Year ended December 31,
Energy Transportation North
Energy Transportation South
Energy Distribution
International

2002
78.6
41.9
(3.7)
34.1
150.9

2001
65.6
32.0
(17.9)
0.3
80.0

2000
54.2
37.7
7.5
–
99.4

Consolidated retained earnings at December 31, 2002 includes undistributed earnings from equity investments of
$155.7 million (2001 — $104.1 million).

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

8. DEBT
(millions of dollars)
December 31,
Energy Transportation North

Debentures
Medium-term notes
Other 1

Energy Transportation South

Senior term notes 2 (US$275.0 million)
Variable rate credit facility 3

Energy Distribution
Debentures
Medium-term notes 4
Other
Corporate

Medium-term notes
Variable rate credit facility
Preferred securities (Note 9)
Other 5
Total Debt

Weighted Average
Interest Rate

9.07%
6.66%

8.08%

11.00%
5.86%

6.14%

7.79%

Current maturities of long-term debt
Other short-term debt

Current Maturities and Short-Term Debt
Long-Term Debt

1 Primarily commercial paper borrowings.
2 The principal amount is recorded at the swapped rate.
3 Includes US$160.0 million (2001 — US$300.0 million).
4 Includes $100.0 million floating rate note swapped to 3.03%.
5 Primarily commercial paper borrowings. Includes US$582.5 million (2001 — US$470.2 million).

Maturity

2008-2024
2005-2029

2005-2007
2003

2004-2024
2003-2028

2004-2032
2005
2048-2051

2002

300.0
622.5
58.8

397.8
252.7

635.0
1,105.0
9.0

1,788.7
400.0
16.3
1,106.8
6,692.6
225.0
427.3
652.3
6,040.3

2001

300.0
622.3
150.1

397.8
477.8

635.0
1,105.0
9.5

1,927.9
400.0
10.3
1,697.3
7,733.0
325.0
1,494.7
1,819.7
5,913.3

Short-term debt in the amount of $1,000.0 million (2000 — $840.0 million) is supported by the availability
of long-term committed credit facilities and has been classified as long-term debt.

Long-term debt maturities for the years ending December 31, 2003 through 2007 are $225.0 million,
$450.0 million, $928.6 million, $440.0 million and $369.3 million, respectively.

Short-term Borrowings
Short-term borrowings, which primarily finance gas in storage and other working capital items, are comprised of
commercial paper with maturities of less than one year. Of these borrowings, $100 million (2001 — $200.0 million)
was swapped to a weighted average fixed interest rate of 2.6% (2001 — 5.7%).

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Weighted Average
Effective Rate1

2002
2001
Notional Amounts

6.04%

7.40%
–

–
2.30%
–

25.4

US$275.0
–

US$275.0
US$140.0

–
400.0
–

40.0
400.0
150.0

2002
392.9
29.0
9.6
(9.5)
422.0

2001
345.0
85.8
12.2
(5.9)
437.1

2000
375.2
1.5
18.5
(6.0)
389.2

Interest Rate Management
(millions of dollars)
December 31,
Energy Transportation North
Commercial paper
Energy Transportation South
Senior term notes 2
Variable rate credit facilities

Corporate

Medium-term notes
Variable rate debt
Commercial paper

1 Reflects the effective rate after giving effect to floating to fixed swap agreements.
2 Subject to a cross-currency swap.

Interest Expense

(millions of dollars)
Year ended December 31,
Long-term debt
Commercial paper and other short-term debt
Short-term borrowings
Capitalized

In 2002, total interest paid was $429.3 million (2001 — $452.2 million; 2000 — $372.0 million).

Credit Facilities
(millions of dollars)
December 31, 2002
Energy Transportation North
Energy Transportation South (US$300.0 million)
Energy Distribution
Corporate

Committed Uncommitted
–
–
5.5
–
5.5

150.0
473.9
659.0
1,900.0
3,182.9

Drawdowns
–
252.7
14.5
400.0
667.2

Committed facilities carry a weighted average standby fee of 0.097% per annum on the unutilized portion. The
committed facilities for Energy Transportation North, Energy Transportation South and Energy Distribution expire
in 2003 and are extendible annually subject to the approval of the lenders. The committed facilities for Corporate
expire in 2003, 2005 and 2007 and are extendible annually thereafter subject to the approval of the lenders.
Drawdowns under all of these facilities bear interest at prevailing market rates.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

9. PREFERRED SECURITIES
In 2002, the Company completed a public offering of 7.8% Preferred Securities for $200.0 million. Net proceeds
were $193.5 million. The Company also has outstanding $175.0 million of 7.6% and $175.0 million of 8.0%
Preferred Securities. The Preferred Securities may be redeemed at the Company’s option, in whole or in part,
after the fifth anniversary of each issue. The Company has the right to defer, subject to certain conditions,
payments of distributions on the securities for up to 20 consecutive quarterly periods. Since deferred and regular
distributions may be settled through the issuance of common shares at the Company’s option, the Preferred
Securities are classified into their respective debt and equity components. The equity component of the Preferred
Securities is $533.7 million at December 31, 2002 (2001 — $339.7 million).

10. SHARE CAPITAL
The authorized share capital of the Company consists of an unlimited number of common shares with no par value
and an unlimited number of preferred shares.

Common Shares

(millions of dollars; number of common shares
in millions)
December 31,

Balance at beginning of year
Dividend Reinvestment and Share

Purchase Plan
Issued to Noverco
Public issue
Other
Balance at end of year

2002

2001

2000

Number
of Shares
162.9

0.2
0.5
5.0
1.1
169.7

Amount
1,875.9

8.3
23.1
225.4
36.3
2,169.0

Number
of Shares
161.8

0.2
–
–
0.9
162.9

Amount
1,852.6

7.2
–
–
16.1
1,875.9

Number
of Shares
156.3

0.2
0.6
4.5
0.2
161.8

Amount
1,677.2

7.2
19.7
143.9
4.6
1,852.6

Preferred Shares
The 5,000,000 5.5% Cumulative Redeemable Preferred Shares, Series A are entitled to fixed, cumulative,
preferential dividends of $1.375 per share per year, payable quarterly. On or after December 31, 2003, the
Company may, at its option, redeem all or a portion of the outstanding preferred shares for $26.00 per share if
redeemed on or prior to December 1, 2004; $25.75 if redeemed on or prior to December 1, 2005; $25.50
if redeemed on or prior to December 1, 2006; $25.25 if redeemed on or prior to December 1, 2007; and $25.00
if redeemed thereafter, in each case with all accrued and unpaid dividends to the redemption date.

Earnings Per Common Share
Earnings per common share is calculated by dividing earnings applicable to common shareholders by the weighted
average number of common shares outstanding. The weighted average number of shares outstanding has been
reduced by the Company’s pro-rata weighted average interest in its own common shares of 5.3 million shares
(2001 — 5.2 million shares), resulting from the investment in Noverco.

The treasury stock method, used for calculating diluted earnings per share, uses an adjusted weighted average
number of common shares outstanding which reflects the exercise of stock options.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

(number of common shares in millions)
December 31,
Weighted average shares outstanding
Effect of dilutive securities

Stock options

Diluted weighted average shares outstanding

2002
160.3

1.7
162.0

2001
157.3

1.5
158.8

2000
154.5

0.8
155.3

Dividend Reinvestment and Share Purchase Plan
Under the plan, registered shareholders may reinvest dividends in common shares of the Company or make
optional cash payments to purchase additional common shares, in either case free of brokerage or other charges.

Shareholder Rights Plan
The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any
takeover offer for the Company. Rights issued under the plan become exercisable when a person, and any related
parties, acquires or announces the intention to acquire 20% or more of the Company’s outstanding common shares
without complying with certain provisions set out in the plan or without approval of the Board of Directors of the
Company. Should such an acquisition or announcement occur, each rights holder, other than the acquiring person
and related parties, will have the right to purchase common shares of the Company at a 50% discount to the
market price at that time.

11. STOCK OPTION PLAN
The Company’s Incentive Stock Option Plan (1999) includes fixed stock options and performance-based stock
options. A maximum of 12 million common shares is reserved for issuance under the plan.

Fixed Stock Options
Full-time, key employees are granted options to purchase common shares that are exercisable at the market price
of common shares at the date the options are granted. Generally, options vest in equal annual installments over a
four-year period and expire ten years after the issue date. Outstanding stock options expire over a period ending
no later than September 16, 2012.

Outstanding Options

(options in thousands; exercise price in dollars)
December 31,

Options at beginning of year
Options granted
Options exercised
Options cancelled or expired
Options at end of year

Options vested

2002

2001

2000

Weighted
Average
Exercise
Price
29.06
43.80
26.31
37.59
32.16

Number
5,120
1,024
(1,003)
(99)
5,042

2,639

Weighted
Average
Exercise
Price
26.76
30.11
19.27
34.47
29.06

Number
4,112
2,024
(843)
(173)
5,120

2,853

Weighted
Average
Exercise
Price
26.63
26.74
19.85
31.17
26.76

Number
3,116
1,360
(179)
(185)
4,112

1,757

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

11. STOCK OPTION PLAN (continued)
Option Characteristics

(options in thousands; exercise price in dollars)
December 31, 2002

Exercise
Price Range
12.44-19.99
20.00-29.99
30.00-39.99
40.00-47.71

Number

Options Outstanding
Weighted
Average
Remaining
(000’s) Life (years)
1.84
6.29
6.95
9.09

532
1,445
2,027
1,038
5,042

Weighted
Average
Exercise
Price
16.74
25.81
35.61
42.14

Options Vested

Weighted
Average
Exercise
Price
16.74
25.21
34.47
40.10

Number
(000’s)
532
867
1,229
11
2,639

Performance-Based Options
The Plan provides for the grant of performance-based options to executive officers. Vesting is based on the
performance of the Company’s common share price. New performance-based options were granted in 2002. The
options vest in equal annual installments over a five-year period and become exercisable, as to 50% of the grant,
when the market price of a common share exceeds $61.00 per share for 20 consecutive trading days during the
five-year period ended September 16, 2007. If the share price exceeds $71.00 for 20 consecutive trading days prior
to September 16, 2007, the remaining options will become exercisable. The performance-based options expire on
September 16, 2007 if the share price target is not reached but extend to September 16, 2010 for options that
become exercisable.

(options in thousands; exercise price in dollars)
December 31,

Options at beginning of year
Options granted
Options exercised
Options cancelled
Options at end of year
Options vested

2002

2001

2000

Weighted
Average
Exercise
Price
32.03
46.30
31.66
–
37.73
32.10

Number
1,479
810
(244)
–
2,045
1,235

Weighted
Average
Exercise
Price
31.60
41.13
–
31.35
32.03
31.31

Number
1,480
65
–
(66)
1,479
740

Weighted
Average
Exercise
Price
31.60
–
–
–
31.60
–

Number
1,480
–
–
–
1,480
–

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Pro Forma Compensation Expense
If the Company had used the fair-value based method to account for fixed stock options and performance-based
options, earnings and earnings per share would have been as follows.

(millions of dollars)
Year ended December 31,
Earnings applicable to common shareholders from continuing operations

As reported
Stock-based compensation expense
Pro forma

Earnings applicable to common shareholders

As reported
Stock-based compensation expense
Pro forma

Earnings per common share from continuing operations

As reported

Pro forma

Earnings per common share

As reported

Pro forma

2002

334.2
2.9
331.3

576.5
2.9
573.6

2.09

2.07

3.60

3.58

1 Pro forma earnings and earnings per share do not reflect options granted prior to January 1, 2002, the date of adoption of the standard

on stock-based compensation.

2 The Black-Scholes model was used to calculate the fair value of the fixed stock options. Significant assumptions include a risk-free interest rate of 5.33%,
expected volatility of 25%, an expected life of 10 years and an expected dividend yield of 3.51%. The weighted average grant-date fair value was $11.42
for the fixed stock options granted during the year ended December 31, 2002.

3 A barrier valuation model was used to calculate the fair value of the performance-based options. Significant assumptions include a risk-free interest rate
of 4.20%, expected volatility of 24%, an expected life of 8 years and an expected dividend yield of 3.46%. The weighted average grant-date fair value
was $7.65 for performance-based options granted during the year ended December 31, 2002.

12. FINANCIAL INSTRUMENTS
Derivative Financial Instruments Used for Risk Management
The Company is exposed to movements in foreign currency exchange rates, interest rates and the price of energy
commodities, primarily natural gas. In order to manage these exposures for both shareholders and ratepayers,
the Company utilizes derivative financial instruments to create offsetting positions to specific exposures. These
instruments are not used for speculative purposes.

Derivative financial instruments involve credit and market risks. Credit risk arises from the possibility that a
counterparty will default on its contractual obligations and is limited to those contracts where the Company
would incur a loss in replacing the instrument. The Company minimizes credit risk by entering into risk
management transactions only with institutions that possess investment grade credit ratings or with approved
forms of collateral. For transactions with terms greater than five years, the Company may also retain the right
to require a counterparty, that would otherwise meet the Company’s credit criteria, to provide collateral.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

12. FINANCIAL INSTRUMENTS (continued)
Foreign Exchange
The Company has an exposure to foreign currency exchange rates, primarily because of its U.S. dollar denominated
investments and its Euro investment in CLH where both carrying values and earnings are subject to foreign
exchange risk. The Company utilizes par forward contracts and cross currency swaps to manage a portion of
the foreign exchange exposure. In addition, cross currency swaps have been entered into to hedge the Company’s
exposure on its U.S. dollar denominated senior term notes.

Interest Costs
The Company enters into forward interest rate agreements, swaps and collars to swap floating rate debt to fixed
and hedge against the effect of future interest rate movements on its variable rate debt. The Company monitors its
debt portfolio mix of fixed and variable rate instruments and has entered into fixed to floating interest rate swaps,
with notional amounts of $300 million, to manage the balance of fixed and floating rate debt.

Energy Commodity Costs
As a result of the sale of the assets of Enbridge Midcoast Energy, the Company’s commodity price risk exposure
arising from holding inventory and purchase and sale commitments has been reduced. The Company continues
to use over-the-counter natural gas price swaps, futures, options and collars to manage physical exposures that
arise in the management of merchant capacity commitments to the Alliance and Vector pipelines.

Natural Gas Supply Management
The Company hedges a portion of the cost of future natural gas supply requirements of Enbridge Gas, as allowed
by the regulator. Amounts paid or received under the hedge agreements are recognized as part of the cost of the
natural gas purchases and are recovered through the ratemaking process. At December 31, 2002, the Company
had entered into natural gas price swaps and options to manage the price for approximately 4.3%, or 5.9 billion
cubic feet, of its forecast fiscal 2003 system gas supply.

Fair Values
The fair values of derivatives have been estimated using year-end market information. These fair values
approximate the amount that the Company would receive or pay to terminate the contracts.

(millions of dollars)
December 31,

Foreign exchange

U.S. cross currency swaps
Euro cross currency swaps
Forwards (cumulative

2002

Notional
Fair Value
Principal Receivable/

2001
Notional
Fair Value
Principal Receivable/

or Quantity

(Payable) Maturity or Quantity

(Payable) Maturity

535.8
371.1

24.9
(54.4)

2005-2022
2003

535.8
–

26.3
–

2005-2022
–

exchange amounts)

1,993.0

(244.6) 2003-2022

2,130.1

(165.9) 2002-2022

Energy Commodities
Natural gas (bcf)

Natural gas supply

management (bcf)

Interest rates

Interest rate swaps
Forward interest rate swaps

35.3

5.9

934.1
–

(1.5) 2003-2004

(0.2)

2003

0.6
–

2003-2029
–

74.4

36.0

955.4
600.0

(41.1) 2002-2006

(37.1)

2002

(12.7) 2002-2029
2002
(6.5)

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

In addition, the Company has forward foreign exchange contracts with a notional principal of Canadian $449 million,
to exchange Canadian for U.S. dollars. The instruments expire in 2003, 2005 and 2007. The contracts are not
effective hedges for accounting purposes but offset an exposure related to income taxes on foreign currency gains
or losses on Canadian dollar debt of a U.S. subsidiary. These instruments are recorded at fair value and have a
fair value receivable of $36.9 million as at December 31, 2002 (2001 — $23.9 million).

As the Company has not settled any hedging instruments in advance of the hedged transactions, there were no
deferred gains or losses for any of the Company’s hedges of anticipated transactions at December 31, 2002 and
2001. A credit risk on derivative financial instruments amounted to $105.3 million at December 31, 2002 with
no significant concentration with any single counterparty.

Fair Values of Other Financial Instruments
The fair value of financial instruments, other than derivatives, represents the amounts that would have been
received from or paid to counterparties, calculated at the reporting date, to settle these instruments. The carrying
amount of all financial instruments classified as current approximates fair value because of the short maturities
of these instruments. The estimated fair values of all other financial instruments are based on quoted market
prices or, in the absence of specific market prices, on quoted market prices for similar instruments and other
valuation techniques.

The carrying amounts of all financial instruments, except for debt, approximate fair value. The fair value of debt
does not include the effects of hedging.

Total Debt

(millions of dollars)
December 31,

Energy Transportation North
Energy Transportation South
Energy Distribution
Corporate

2002

2001

Carrying
Amount
981.3
650.5
1,749.0
3,311.8
6,692.6

Fair
Value
1,084.5
686.6
1,989.2
3,394.7
7,155.0

Carrying
Amount
1,072.4
875.6
1,749.5
4,035.5
7,733.0

Fair
Value
1,116.8
910.6
1,956.6
4,055.6
8,039.6

Trade Credit Risk
Trade receivables related to Energy Transportation North consist primarily of amounts due from companies
operating in the oil and gas industry and are collateralized by the crude oil and other products contained in the
Company’s pipelines and storage facilities. Credit risk in the Energy Distribution segment is reduced by the large
and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking
process. Included in accounts receivable is an allowance for doubtful accounts of $31.1 million at December 31,
2002 (2001 — $29.9 million).

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

13. INCOME TAXES
Income Tax Rate Reconciliation

(millions of dollars)
Year ended December 31,
Earnings before income taxes
Combined statutory income tax rate
Income taxes at statutory rate
Increase/(decrease) resulting from:

Tax rate reductions on future income tax balances
Future income taxes related to regulated operations
Non-taxable items, net
Lower foreign tax rates
Large Corporations Tax in excess of surtax
Other
Income Taxes

Continuing operations
Discontinued operations

2002
746.9
38.0%
283.8

8.1
(36.7)
(99.5)
(42.2)
16.9
6.3
136.7

102.1
34.6
136.7

2001
552.1
41.0%
226.3

(67.5)
(35.7)
(28.2)
(36.8)
18.8
(7.7)
69.2

66.7
2.5
69.2

Effective income tax rate

18.3%

12.5%

2000
412.6
43.3%
178.8

(103.7)
(40.9)
(31.0)
(21.0)
16.1
(0.2)
(1.9)

13.7
(15.6)
(1.9)

–

In 2002, income taxes paid amounted to $105.2 million (2001 — $110.5 million; 2000 — $114.7 million).

Components of Future Income Taxes

(millions of dollars)
December 31,
Future Income Tax Liabilities

Differences in accounting and tax bases of property, plant and equipment
Differences in accounting and tax bases of investments
Other

Future Income Tax Assets
Loss carryforwards
Other

Total Net Future Income Tax Liability

2002

313.8
525.7
110.1
949.6

283.0
38.2
321.2
628.4

2001

403.5
267.6
154.5
825.6

232.1
12.7
244.8
580.8

Accumulated future income taxes related to rate-regulated operations which have not been recorded in the accounts
amounted to $511.2 million at December 31, 2002 (2001 — $506.3 million). Had the liability method been
prescribed by the regulatory authorities for ratemaking purposes, such amounts would have been recorded and
recovered in revenues.

At December 31, 2002, the Company has recognized the benefit of unused tax loss carryforwards of
$822.4 million. Unused tax loss carryforwards expire as follows: 2003 — $1.6 million; 2004 — $5.8 million;
2005 — $33.8 million; 2006 — $129.1 million; 2007 — $182.3 million; 2008 — $69.2 million and 2009 and
beyond — $400.6 million.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Geographic Components of Pretax Earnings and Income Taxes

(millions of dollars)
Year ended December 31,
Earnings before income taxes

Canada
United States
Other

Continuing operations
Discontinued operations

Current income taxes

Canada
United States
Other

Continuing operations
Discontinued operations

Future income taxes

Canada
United States
Other

Continuing operations
Discontinued operations

2002

346.1
(5.0)
128.8
469.9
276.9
746.8

154.8
3.2
8.8
166.8
36.9
203.7

(54.5)
(10.5)
0.3
(64.7)
(2.3)
(67.0)
102.1
34.6
136.7

2001

297.2
103.8
103.3
504.3
47.8
552.1

44.4
8.9
10.0
63.3
20.1
83.4

(9.0)
12.4
–
3.4
(17.6)
(14.2)
66.7
2.5
69.2

2000

273.3
73.3
47.0
393.6
19.0
412.6

129.4
(4.5)
5.9
130.8
24.4
155.2

(112.4)
(4.7)
–
(117.1)
(39.9)
(157.0)
13.7
(15.6)
(1.9)

14. POST-EMPLOYMENT BENEFITS
Pension Plans
The Company has three pension plans which provide either defined benefit or defined contribution pension
benefits or both for employees of the Company. The Energy Transportation North pension plan provides non-
contributory defined pension and/or defined contribution benefits to employees. The Energy Transportation South
pension plan provides either non-contributory defined benefit pension benefits or contributory defined
contribution pension benefits. The Enbridge Gas pension plan provides contributory defined benefit pension
and/or defined contribution benefits to the majority of its employees.

Defined Benefit Plans
Retirement benefits under defined benefit plans are based on employees’ years of service and remuneration.
Contributions made by the Company are made in accordance with independent actuarial valuations and are
invested primarily in publicly traded equity and fixed income securities. The most recent actuarial valuation was
performed as of January 1, 2002.

Pension costs under the defined benefit pension plans reflect management’s best estimates of the rate of return
on pension plan assets, rate of salary increases and various other factors including mortality rates, terminations
and retirement ages. Adjustments arising from plan amendments, actuarial gains and losses, and changes to
assumptions are amortized over the expected average remaining service lives of the employees.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

14. POST-EMPLOYMENT BENEFITS (continued)
Defined Contribution Plans
Contributions are generally based on the employee’s age and/or years of service. For the Energy Transportation
South pension plan, contributions to the defined contribution plans are also based on employee contributions. For
defined contribution pension benefits, pension expense equals amounts required to be contributed by the Company.

Post-employment Benefits Other than Pensions
Post-employment benefits other than pensions (OPEB) include supplemental health, dental and life insurance
coverage for qualifying retired employees.

The following tables detail the changes in the benefit obligation, the fair value of plan assets and the recorded
asset or liability using the accrual method.

(millions of dollars)

Change in benefit obligation
Benefit obligation, January 1
Service cost
Interest cost
Amendments
Employee contributions
Actuarial loss
Benefits paid
Divestitures
Effect of exchange rate changes
Benefit obligation, December 31

Fair value of plan assets
Fair value of plan assets, January 1
Actual return on plan assets
Employer’s contributions
Employee contributions
Benefits paid
Other
Divestitures
Effect of exchange rate changes
Fair value of plan assets, December 31

Asset/(Liability)
Plan assets in excess/(deficiency) of
projected benefit obligations
Unrecognized prior service cost
Unrecognized plan surplus
Unrecognized net loss/(gain)
Recorded asset/(liability)

2002
OPEB

2001
OPEB

2002
Pension
Benefit

2001
Pension
Benefit

132.3
4.2
8.8
–
0.3
31.4
(5.7)
(10.6)
(0.2)
160.5

29.6
3.0
8.5
0.3
(5.7)
–
–
(0.2)
35.5

(125.0)
3.4
36.2
31.5
(53.9)

113.5
3.7
8.0
2.8
0.3
6.4
(4.7)
–
2.3
132.3

23.8
2.3
6.4
0.3
(4.7)
–
–
1.5
29.6

(102.7)
3.6
46.3
2.8
(50.0)

742.7
18.7
45.9
0.7
0.1
8.5
(37.9)
(67.8)
(0.8)
710.1

1,076.7
(20.3)
19.7
0.1
(37.9)
(2.3)
(100.9)
(2.0)
933.1

223.0
20.8
–
4.8
248.6

651.2
20.4
45.4
22.1
4.1
38.2
(44.0)
–
5.3
742.7

1,218.8
(122.9)
9.4
4.1
(44.0)
–
–
11.3
1,076.7

334.0
25.6
–
(119.7)
239.9

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

Net Pension Plan and OPEB Costs

(millions of dollars)
Year ended December 31,
Benefits earned during the year
Interest cost on projected benefit obligations
Expected return on plan assets
Amortization and deferral of unrecognized amounts
Amount credited to EEP
Pension and OPEB expense/(credit)

2002
25.2
54.5
(75.3)
6.9
(1.7)
9.6

2001
26.3
55.2
(93.7)
(6.8)
5.5
(13.5)

2000
23.0
51.1
(76.2)
(8.9)
6.5
(4.5)

The above tables reflect the funded status, recorded pension and OPEB assets and liabilities and pension and OPEB
expense for all of the Company’s benefit plans on an accrual basis. However, in accordance with its ability to
recover employee benefit costs on a pay-as-you-go basis for the regulated operations of Enbridge Gas, the Company
records the cost of such benefits on a cash basis. Using the cash basis for the Enbridge Gas plans and the accrual
method for other plans, the Company’s pension expense was $3.6 million (2001 — $4.0 million credit;
2000 — $2.7 million expense). The pension asset was $73.1 million (2001 — $64.8 million). The Company’s
OPEB expense totalled $6.8 million (2001 — $5.9 million; 2000 — $5.6 million). The OPEB liability was
$8.4 million (2001 — $6.8 million). The pension and OPEB assets and obligations for discontinued operations
were included in the sale transaction.

Economic Assumptions
The assumptions made in the measurement of pension expense and the projected benefit obligation or asset of
the pension plans and OPEB are as follows.

Year ended December 31,

Discount rate
Average rate of salary increases
Average rate of return on

pension plan assets
Medical cost trend rate
Dental cost trend rate

2002
OPEB

2001
OPEB

6.75-7.25%

7.0-7.5%

2000
OPEB

2001
2002
Pension
Pension
Benefits
Benefits
7.0-7.5% 6.75-7.25% 6.75-7.5%
4.0%

4.0%

2000
Pension
Benefits
7.0-7.5%
4.0%

4.5-14.0% 4.5-11.0%
4.5-6.0%
4.5-5.5%

4.5-6.8%
4.5-6.0%

3.90-8.0% 7.75-8.0% 7.75-8.0%

A 1% change in the assumed medical and dental care trend rate would result in a change of $27.1 million in the
accumulated post-employment benefit obligations and a change of $2.2 million in OPEB expense.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

15. INVESTMENT AND OTHER INCOME

(millions of dollars)
Year ended December 31,
Equity investments
Cost investments
Investment income
Allowance for equity funds used during construction
Gain/(loss) on foreign currency contracts
Gain on reduction of EEP ownership interest
Gain on sale of marketable securities
Other

16. CHANGES IN OPERATING ASSETS AND LIABILITIES

(millions of dollars)
Year ended December 31,
Accounts receivable and other
Gas in storage
Deferred amounts
Accounts payable and other
Interest payable

2002
150.9
61.1
22.9
5.3
0.1
10.0
21.4
11.4
283.1

2002
75.0
76.0
72.4
(76.4)
4.6
151.6

2001
80.0
51.9
16.3
3.9
(1.7)
23.4
–
21.1
194.9

2001
(583.7)
(145.8)
(77.6)
493.1
(9.1)
(323.1)

2000
99.4
44.4
14.7
2.7
(24.5)
–
–
34.8
171.5

2000
(65.3)
(144.7)
(195.8)
(132.8)
23.2
(515.4)

Changes in accounts payable exclude changes in construction payables which are investing activities.

17. RELATED PARTY TRANSACTIONS
EEP does not have any employees and uses the services of the Company for managing and operating its business.
These services, which are charged at cost in accordance with service agreements, amounted to $97.2 million
(2001 — $56.2 million; 2000 — $46.7 million).

18. COMMITMENTS AND CONTINGENCIES
Enbridge Gas
The remediation of discontinued manufactured gas plant sites may result in future costs. The probable overall cost
of remediation cannot be determined at this time due to uncertainty about the existence or extent of environmental
risks, the complexity of laws and regulations, particularly with respect to sites decommissioned years ago and
no longer owned by Enbridge Gas, and the selection of alternative remediation approaches. Although there are
no known regulatory precedents in Canada, there are precedents in the United States for recovery in rates of costs
of a similar nature. If Enbridge Gas must contribute to any remediation costs, it would be generally allowed to
recover in rates those costs not recovered through insurance or by other means and believes that the ultimate
outcome of these matters would not have a significant impact on its financial position.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

In October 2002, the Supreme Court of Canada granted an Application for Leave to Appeal to a customer who
commenced an action against Enbridge Gas claiming that the OEB-approved late payment penalties charged to
customers were contrary to Canadian federal law. The Court will hear the plaintiff’s appeal of the Ontario Court of
Appeal’s decision, released in December 2001, to dismiss a Notice of Appeal filed by the plaintiff in April 2000.
The Company believes it has sound defences to the plaintiff’s claim and it intends to vigorously defend the action.

CAPLA Claim
The Canadian Alliance of Pipeline Landowners’ Associations and two individual landowners have commenced an
action, which they will be applying for certification as a class action, against the Company and TransCanada
PipeLines Limited. The claim relates to restrictions in the National Energy Board Act on the landowners’ use of
land within a 30-metre control zone on either side of the pipeline easements. The Company believes it has a
sound defence and intends to vigorously defend the claim. Since the outcome is indeterminable, the Company
has made no provision for any potential liability.

Enbridge Energy Partners
Enbridge Energy Company, Inc. (EEC), which holds a portion of the Company’s equity interest in EEP, has
agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating to environmental
matters, arising from operations prior to the transfer of its pipeline operations to EEP in 1991. This
indemnification does not apply to amounts that EEP would be able to recover in its tariff rates if not recovered
through insurance, or to any liabilities relating to a change in laws after December 27, 1991. In addition, in the
event of default, EEC, as the General Partner, is subject to recourse with respect to a portion of EEP’s long-term
debt which amounts to US$279 million at December 31, 2002.

19. UNITED STATES ACCOUNTING PRINCIPLES
These consolidated financial statements have been prepared in accordance with Canadian GAAP. The effects
of significant differences between Canadian GAAP and U.S. GAAP for the Company are described below.

Earnings and Comprehensive Income

(millions of dollars except per share amounts)
Year ended December 31,
Earnings under Canadian GAAP
Preferred security distributions 1
Stock-based compensation 2
Tax effect of the above adjustment
Future income tax recovery/(expense) 3
Earnings under U.S. GAAP
Unrealized net gain/(loss) on cash flow hedges 5
Foreign currency translation adjustment 5
Comprehensive income

Earnings per common share

Diluted earnings per common share

2002
610.1
(26.7)
(12.1)
4.9
–
576.2
19.5
(1.3)
594.4

3.55

3.51

2001
482.9
(17.5)
(15.2)
6.1
92.8
549.1
(150.8)
15.1
413.4

3.45

3.41

2000
414.5
(15.3)
–
–
(182.8)
216.4
–
16.2
232.6

1.36

1.35

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

19. UNITED STATES ACCOUNTING PRINCIPLES (continued)
Financial Position

(millions of dollars)
December 31,

Cash4
Accounts receivable and other 4
Property, plant and equipment 4
Accumulated depreciation 4
Long-term investments 4
Deferred amounts 3, 4
Short-term borrowings
Accounts payable and other 4
Current maturities and short-term debt
Long-term debt 1
Future income taxes 3, 5
Preferred securities 1
Retained earnings
Additional paid in capital 2
Accumulated other comprehensive income/(loss) 5

2002
Canada United States
42.7
843.4
9,506.6
2,596.3
3,421.0
1,178.7
256.8
921.1
658.5
6,612.5
1,403.0
–
1,098.9
12.1
(103.2)

40.7
817.5
9,548.6
2,601.0
3,371.5
315.8
247.5
714.1
652.3
6,040.3
628.4
533.7
1,128.1
–
12.3

2001
Canada United States
71.3
1,313.5
9,116.0
2,323.1
1,801.6
1,342.8
410.9
923.4
1,819.7
6,293.2
1,499.7
–
781.2
15.2
(121.4)

74.0
1,270.2
9,143.5
2,326.0
1,772.8
329.7
410.9
679.9
1,819.7
5,913.3
580.8
339.7
812.3
–
7.4

1 Preferred Securities

Under U.S. GAAP, the full amount of the Company’s Preferred Securities and related distributions would be recognized as debt and interest expense,
respectively. The Preferred Securities have a fair market value of $565.0 million at December 31, 2002 (2001 — $345.5 million).

2 Stock-Based Compensation

The Company accounts for stock-based compensation for U.S. GAAP purposes in accordance with APB 25, Accounting for Stock Issued to Employees, which
requires the use of the intrinsic value-based method to measure compensation expense. Under Canadian GAAP, the Company’s performance-based options do
not give rise to compensation expense. Under U.S. GAAP, the performance-based options which vested during 2002 gave rise to pre-tax compensation expense
of $12.1 million (2001 — $6.9 million; 2000 — nil).

Starting in 2002, the Company accounts for SARs in accordance with the new Canadian accounting standard for stock-based compensation which results in
the same compensation expense as under U.S. GAAP. Under U.S. GAAP in 2001 and 2000, the Company’s stock appreciation rights (SARs) are accounted for
using the intrinsic value method which resulted in pre-tax compensation expense of $8.3 million and nil, respectively.

3 Future Income Taxes

Canadian GAAP requires that the effect of tax rate reductions are recognized when they are substantively enacted. Under U.S. GAAP, the effect of tax rate
reductions cannot be recognized until enacted. In 2000, the Company recognized $92.8 million of earnings related to substantively enacted tax rate reductions
that are recognized in 2001 under U.S. GAAP. In 2000, future income taxes of $76.5 million, related to the unbundling transaction and charged to retained
earnings under Canadian GAAP as part of the adoption of the new income tax standard, are charged to earnings as a write-down of the regulatory asset
under U.S. GAAP.

Under U.S. GAAP, deferred income tax liabilities are recorded for rate-regulated operations which follow the taxes payable method for ratemaking purposes.

As these deferred income taxes are expected to be recoverable in future revenues, a corresponding regulatory asset is also recorded. These assets and liabilities
are adjusted to reflect changes in enacted income tax rates. The additional deferred income taxes under U.S. GAAP include the difference between capital cost
allowance and depreciation of property, plant and equipment of $549.3 million (2001 — $574.4 million) and the incremental revenue required for the recovery
of unrecorded taxes of $316.0 million (2001 — $370.5 million).

4 Accounting for Joint Ventures

Under U.S. GAAP, the Company’s investments in joint ventures are accounted for using the equity method.

5 Accumulated Other Comprehensive Income

At December 31, 2002, accumulated other comprehensive income consists of an accumulated foreign currency translation adjustment of $28.1 million
(2001 — $29.4 million) and net unrealized losses of $131.3 million (2001 — $150.8 million) for derivative financial instruments.

Supplemental Disclosure — Pro Forma Compensation Expense
U.S. GAAP requires that, where the fair value based method is not used to measure compensation expense,
pro forma earnings and earnings per share, calculated as if the fair value based method had been used, must
be disclosed. In Canada, these requirements apply to options granted on or after January 1, 2002 and therefore,
the Company’s Canadian GAAP disclosure does not include any options granted prior to that date.

E N B R I D G E

I N C .

C o n s o l

i d a t e d F i n a n c i a l

S t a t e m e n t s

(millions of dollars except per share amounts)
Year ended December 31,
Earnings under U.S. GAAP

As reported
Stock-based compensation expense
Pro forma

Earnings per common share

As reported
Stock-based compensation expense
Pro forma

Diluted earnings per common share

As reported
Stock-based compensation expense
Pro forma

2002

576.2
7.3
568.9

3.55
0.05
3.50

3.51
0.04
3.47

2001

549.1
4.6
544.5

3.45
0.03
3.42

3.41
0.03
3.38

2000

216.4
2.6
213.8

1.36
0.02
1.34

1.35
0.02
1.33

The fair value of stock options was calculated in the same manner, using the same assumptions, as disclosed in
Note 11 except that for Canadian GAAP, only awards granted since the adoption of the new CICA standard for
stock-based compensation on January 1, 2002 are included. Assumptions used for U.S. GAAP comparative
periods are as follows.

Year ended December 31,
Risk free interest rate
Expected life (years)
Expected volatility
Expected quarterly dividends

2001
5.38%
10
25%
$0.38

2000
5.41%
10
25%
$0.35

The weighted average grant-date fair value of options granted during 2001 under the fixed option plan in 2001
and 2000 was $10.09 and $7.80, respectively.

New Accounting Standards
Accounting for Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which is to be
adopted for fiscal years beginning after June 15, 2002. This standard requires that legal obligations associated
with the retirement of long-lived tangible assets be recognized at fair value when incurred. The Company will
adopt the new standard effective January 1, 2003. Since the majority of the Company’s operations are rate-regulated,
the new standard is not expected to have a material impact on earnings. A similar standard has been issued by
the Canadian Institute of Chartered Accountants effective January 1, 2004.

Accounting for Costs Associated with Exit or Disposal Activities
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities,
which is effective for exit or disposal activities initiated on or after December 31, 2002. This standard replaces
Emerging Issues Task Force Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity". The standard requires liabilities associated with exit or disposal activities to
be recorded, at fair value, as they are incurred rather than on the adoption of a formal plan of disposal.

Consolidation of Variable Interest Entities
In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest Entities, which is to be adopted
for interim periods commencing after July 15, 2003. The Company is assessing the impact of this standard,
if any, on its financial statements.

E N B R I D G E

I N C .

S u p p l e m e n t a r y

I n f o r m a t

i o n

S U P P L E M E N T A R Y I N F O R M A T I O N

( u n a u d i t e d )

Selected Quarterly Financial Data
(millions of dollars, except per share amounts)
2002
Operating revenue from continuing operations
Operating income from continuing operations

Margin

Earnings applicable to common shareholders

First
1,073.2
152.9
0.138

105.0
8.1
113.1

0.66
0.05
0.71
0.38

First
778.8
192.7

79.8
3.7
83.5

0.51
0.02
0.53
0.35

Continuing operations
Discontinued operations

Earnings per common share

Continuing operations
Discontinued operations

Dividends per common share

2001
Operating revenue from continuing operations
Operating income from continuing operations
Earnings applicable to common shareholders

Continuing operations
Discontinued operations

Earnings per common share

Continuing operations
Discontinued operations

Dividends per common share

Quarterly Share Trading Information
The Toronto Stock Exchange
2002 (dollars)
High
Low
Close
Volume (millions)
2001 (dollars)
High
Low
Close
Volume (millions)

Second
1,645.8
336.4
0.203

199.1
234.2
433.3

1.26
1.48
2.74
0.38

Second
1,615.9
371.9

245.3
25.1
270.4

1.56
0.16
1.72
0.35

First
46.15
41.50
44.73
21.3
First
43.00
33.90
42.35
20.7

The New York Stock Exchange and the NASDAQ National Market 1
First
2002 (U.S. dollars)
27.57
High
24.20
Low
26.52
Close
0.6
Volume (millions)
First
2001 (U.S. dollars)
28.63
High
22.25
Low
26.69
Close
0.2
Volume (millions)

Third
1,171.0
30.8
0.026

(3.9)
–
(3.9)

(0.03)
–
(0.03)
0.38

Third
974.7
92.4

58.4
6.4
64.8

0.37
0.04
0.41
0.35

Second
48.94
43.06
47.16
15.5
Second
42.50
35.55
41.19
17.7

Second
30.49
25.61
30.11
0.6
Second
27.20
23.00
27.14
0.3

Fourth
657.5
88.7
0.135

34.0
–
34.0

0.20
(0.02)
0.18
0.38

Fourth
711.5
89.5

29.7
10.1
39.8

0.19
0.06
0.25
0.35

Third
49.25
42.71
46.27
17.0
Third
43.24
39.02
42.55
13.3

Third
31.03
26.29
28.37
1.7
Third
27.50
25.50
26.94
0.5

Total
4,547.5
608.8
0.132

334.2
242.3
576.5

2.09
1.51
3.60
1.52

Total
4,080.9
746.5

413.2
45.3
458.5

2.63
0.28
2.91
1.40

Fourth
46.85
41.11
42.61
18.5
Fourth
45.55
40.89
43.40
16.0

Fourth
29.14
26.05
26.73
1.3
Fourth
28.77
26.05
27.22
0.7

1 Effective October 30, 2001, Enbridge Inc. began trading on the New York Stock Exchange and delisted from the NASDAQ.

E N B R I D G E

I N C .

F I V E Y E A R C O N S O L I D A T E D H I G H L I G H T S

S u p p l e m e n t a r y

I n f o r m a t

i o n

Financial and Operating Information 1

(millions of dollars, except per share amounts)
Earnings by Segment
Energy Transportation North
Energy Transportation South
Energy Distribution 2
International
Corporate
Continuing operations
Discontinued operations 3
Earnings applicable

to common shareholders

2002
236.2
(41.4)
113.8
68.0
(42.4)
334.2
242.3

2001
205.1
46.4
181.8
35.6
(55.7)
413.2
45.3

2000
192.6
23.3
203.2
26.4
(87.8)
357.7
34.6

1999
172.5
39.1
95.2
28.7
(47.6)
287.9
–

1998
120.1
33.2
93.5
24.3
(30.2)
240.9
–

576.5

458.5

392.3

287.9

240.9

Cash Flow Data
Cash provided from operating activities
Expenditures on property, plant and equipment
Dividends paid on common shares

Operating Data
Energy Transportation 4

Deliveries (thousands of barrels per day)
Barrel miles (billions)
Average haul (miles)

Energy Distribution

Distribution volume (billion cubic feet)
Number of active customers (thousands)
Degree day deficiency 5 (degrees Celsius)
Actual
Forecast based on normal weather

910.6
729.9
251.1

2,088
705
925

410
1,623

3,362
3,700

414.5
683.3
227.5

2,109
695
903

427
1,571

3,766
3,816

263.5
364.3
202.1

2,072
735
972

421
1,520

3,569
3,929

495.1
783.7
186.4

1,942
687
968

402
1,466

3,460
4,060

312.4
1,388.4
168.3

2,024
759
1,028

397
1,414

3,352
4,079

1 Certain comparative amounts have been reclassified to conform with the current year’s basis of presentation.
2 The highlights of the Energy Distribution activities reflect the results of Enbridge Gas Distribution and other gas distribution assets on a quarter lag

basis of consolidation.

3 The results of discontinued operations cannot be disaggregated from continuing operations prior to 2000.
4 Energy Transportation operating highlights include the statistics of the 14.1% owned portion of the mainline system located in the United States.
5 Degree day deficiency is a measure of coldness. It is calculated by accumulating for each day in the fiscal period the total number of degrees by which the

daily mean temperature fell below 18 degrees Celsius. The figures given are those accumulated in the Toronto area.

E N B R I D G E

I N C .

S u p p l e m e n t a r y

I n f o r m a t

i o n

F I V E Y E A R C O N S O L I D A T E D H I G H L I G H T S

Shareholder and Investor Information

(per share amounts in dollars)

Average common shares outstanding weighted

monthly during the year (thousands)
Number of registered common shareholders

2002

2001

2000

1999

1998

160,310

157,297

154,469

150,995

145,448

at year end

7,406

7,832

8,265

8,877

9,207

Common Share Trading (TSE) 1
High
Low
Close
Volume (millions)
Per Common Share Data 1
Earnings applicable to common shareholders

Continuing operations
Discontinued operations

Dividends paid on common shares
Financial Ratios
Return on average shareholders’ equity 2
Return on average capital employed 3
Debt to debt plus shareholders’ equity 4
Debt to total capital employed
Earnings coverage of interest 5
Dividend payout ratio 6

49.25
41.11
42.61
72.3

2.09
1.51
3.60
1.520

19.9%
7.5%
64.4%
57.0%
2.7x
42.2%

45.55
33.90
43.40
67.6

2.63
0.28
2.91
1.400

18.6%
7.3%
72.9%
66.3%
2.2x
48.1%

44.00
23.00
43.70
68.2

2.32
0.22
2.54
1.270

18.6%
7.2%
69.4%
61.6%
2.0x
50.0%

36.33
28.60
28.65
51.8

1.91
–
1.91
1.195

14.3%
6.6%
68.9%
63.7%
2.0x
62.6%

35.70
28.95
35.25
61.5

1.66
–
1.66
1.120

13.8%
6.6%
71.4%
64.8%
2.0x
67.5%

1 Data for 2002, 2001 and 2000 are for the Toronto Stock Exchange only. Prior year data include the Toronto and Montreal stock exchanges.
2 Earnings applicable to common shareholders divided by average common equity (weighted monthly during the year).
3 Sum of earnings (including earnings from discontinued operations), non-controlling interest and after-tax interest expense divided by average capital employed

(weighted monthly during the year). Capital employed is equal to the sum of shareholders’ equity, non-controlling interest, future income taxes, deferred credits,
and total debt (excluding short-term borrowings which finance gas in storage).

4 Total debt (including short-term borrowings) divided by the sum of total debt and shareholders’ equity.
5 Sum of earnings before income taxes, non-controlling interest and interest expense, divided by interest expense. Includes earnings from discontinued operations.
6 Dividends per common share divided by total earnings per share applicable to common shareholders.

E N B R I D G E

I N C .

S h a r e h o l d e r

a n d

I n v e s t o r

I n f o r m a t

i o n

S H A R E H O L D E R A N D I N V E S T O R I N F O R M A T I O N

Common and
Preferred Shares
The Common Shares of
Enbridge Inc. trade in Canada
on the Toronto Stock Exchange
and in the United States on the
New York Stock Exchange
under the trading symbol
“ENB”. The Preferred Shares,
Series A, of Enbridge Inc.
trade in Canada on the Toronto
Stock Exchange under the
trading symbol “ENB.PR.A”.

Registrar and Transfer
Agent in Canada
CIBC Mellon Trust Company
199 Bay Street,
Commerce Court West
Securities Level
Toronto, Ontario M5L 1G9
Telephone: (416) 643-5000
Toll free: (800) 387-0825
Internet: www.cibcmellon.com
CIBC Mellon Trust Company
also has offices in Halifax,
Montreal, Winnipeg, Calgary,
and Vancouver.

Co-Registrar and Co-Transfer
Agent in the United States
Mellon Investor Services
85 Challenger Road
Overpeck Centre
Ridgefield Park, NJ,
07660 U.S.A.
Toll free: (800) 526-0801

Preferred Securities
Enbridge Preferred Securities,
Series B, C and D trade in
Canada on the Toronto Stock
Exchange under the trading
symbols “ENB.PR.B”,
“ENB.PR.C” and
“ENB.PR.D”, respectively.
The registrar and transfer
agent is Computershare Trust
Company of Canada (formerly
Montreal Trust Company).

Debentures
The registrar and trustee for
Enbridge Debentures is
Computershare Trust Company
of Canada (formerly Montreal
Trust Company) — Montreal,
Toronto, Winnipeg, Edmonton
and Vancouver.

Auditors
PricewaterhouseCoopers LLP

Shareholder Inquiries
If you have inquiries
regarding the following:
❚ Dividend Reinvestment

and Share Purchase Plan
change of address
share transfer
lost certificates
dividends
duplicate mailings

Please contact the registrar and
transfer agent — CIBC Mellon
Trust Company in Canada or
Mellon Investor Services in
the United States.

Other Investor Inquiries
If you have inquiries
regarding the following:
additional financial or
statistical information
industry and company
developments
latest news releases or
investor presentations
Please contact Enbridge
Investor Relations or visit
Enbridge’s web site at
www.enbridge.com.

Investor Relations
Manager, Investor Relations
Enbridge Inc.
3000, 425 - 1st Street S.W.
Calgary, Alberta, Canada
T2P 3L8
Toll free: (800) 481-2804

Annual and Special Meeting
The Annual and Special
Meeting of Shareholders will
be held in the Crystal Ballroom
at the Fairmont Palliser Hotel,
Calgary, Alberta, at 1:30 p.m.
MDT on Wednesday,
May 7, 2003.

Form 40-F
The Company files annually
with the Securities and
Exchange Commission of the
United States a report known
as the Annual Report on Form
40-F. Copies of the Form 40-F
are available, free of charge,

upon written request to
the Corporate Secretary
of the Company.

Dividend Reinvestment and
Share Purchase Plan, and
Dividend Direct Deposit
Enbridge Inc. offers a
Dividend Reinvestment and
Share Purchase Plan that
enables shareholders to
reinvest their cash dividends
in Common Shares and to
make additional cash payments
for purchases at the market
price. The Company also
offers Dividend Direct Deposit
which enables shareholders to
receive dividends by electronic
fund transfer to the bank
account of their choice in
Canada. Details may be
obtained from the Investor
Information section of
the Enbridge web site at
www.enbridge.com, or by
contacting CIBC Mellon
Trust Company.

Registered Office
Enbridge Inc.
3000, 425 - 1st Street S.W.
Calgary, Alberta, Canada
T2P 3L8
Telephone: (403) 231-3900
Facsimile: (403) 231-3920
Internet: www.enbridge.com

2003 Dividend Information for Common Shares and Preferred Shares, Series A

1st Q

Record date

Payment date

Common Share Dividend Reinvestment Plan (DRIP) enrolment cut-off date
Share Purchase Plan cut-off date (cheques can be post-dated to the payment date)

Feb. 14

March 1

Feb. 7
Feb. 21

2003 Interest Payment Information for Preferred Securities, Series B, C and D

1st Q

Record date

Payment date

Le présent document est disponible en français.

March 15

March 31

2nd Q

May 21

June 1

May 14
May 26

2nd Q

June 14

June 30

3rd Q

Aug. 15

Sept. 1

Aug. 8
Aug. 25

3rd Q

Sept. 13

Sept. 30

4th Q

Nov. 14

Dec. 1

Nov. 6
Nov. 24

4th Q

Dec. 13

Dec. 31

E N B R I D G E

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C o r p o r a t e

I n f o r m a t

i o n

C O R P O R A T E I N F O R M A T I O N

BOARD OF DIRECTORS

David A. Arledge
Corporate Director
Houston, Texas

James J. Blanchard
Senior Partner
Piper Rudnick
Washington, D.C.

J. Lorne Braithwaite
Corporate Director
Toronto, Ontario

Patrick D. Daniel
President & Chief
Executive Officer
Enbridge Inc.
Calgary, Alberta

E. Susan Evans
Corporate Director
Calgary, Alberta

William R. Fatt
Chief Executive Officer
Fairmont Hotels &
Resorts Inc.
Toronto, Ontario

Richard L. George
President & Chief
Executive Officer
Suncor Energy Inc.
Calgary, Alberta

Michel Gourdeau
President
Hydro-Québec Oil & Gas
Montreal, Québec

Louis D. Hyndman
Senior Partner
Field Atkinson Perraton
Edmonton, Alberta

Brian F. MacNeill
Chairman
Petro-Canada
Calgary, Alberta

Robert W. Martin
Corporate Director
Toronto, Ontario

George K. Petty
Corporate Director
San Luis Obispo, California

Donald J. Taylor
Chair
Enbridge Inc.
Jacksons Point, Ontario

SENIOR MANAGEMENT:
THE CORPORATE
LEADERSHIP TEAM

Patrick D. Daniel
President & Chief
Executive Officer

Mel F. Belich
Group Vice President,
International

J. Richard Bird
Group Vice President,
Transportation North

Bonnie D. DuPont
Group Vice President,
Corporate Resources

Stephen J.J. Letwin
Group Vice President,
Distribution & Services

Derek P. Truswell
Group Vice President
& Chief Financial Officer

Dan C. Tutcher
Group Vice President,
Transportation South

Stephen J. Wuori
Group Vice President,
Planning & Development

Environment, Health and Safety

Prevention of accidents and injuries, and protection of the environment benefits everyone.

That’s why environmental, health and safety performance is an integral part of Enbridge’s

businesses, and objectives and performance targets are established, programs are implemented

and results are monitored. The results are published in the Company’s Environment, Health

and Safety Annual Report. You can obtain a copy of the most recent report by e-mailing

webmaster@enbridge.com, or visiting the Enbridge website at www.enbridge.com.

E N B R I D G E

I N C .

C H A N G E S T O S E N I O R M A N A G E M E N T I N 2 0 0 3

C o r p o r a t e

I n f o r m a t

i o n

Continuity of its senior management team has been an Enbridge trademark. With the decision by Chief Financial
Officer Derek Truswell to take early retirement, after more than 34 years of outstanding service to the organization,
the Company took the opportunity to make a number of changes to its senior management team, while maintaining
its existing strengths. Effective April 1, 2003, the following changes will take effect, to fill the position of CFO,
refresh the organization, rebalance workloads and reinforce the Company’s commitment to succession management.
The Company’s four core operating units will continue to be led by the same individuals, but a number of
responsibilities have changed, and two new members have been added to the Corporate Leadership Team.

Patrick D. Daniel: as President
& Chief Executive Officer, Mr. Daniel
continues to be responsible for all
operations of the Company, and all
Group Vice Presidents report to him.

Mel F. Belich is appointed Group
Vice President, International and
Corporate Law, retaining responsibility
for International consulting,
development and operations, and
adding the Corporate Law function.

J. Richard Bird continues as Group
Vice President, Transportation North,
responsible for the operation and
development of Enbridge’s crude oil
pipeline businesses, as well as overseeing
the Company’s interests in the Alliance
and Vector natural gas pipelines.

Bonnie D. DuPont continues as Group
Vice President, Corporate Resources,
responsible for Human Resources, Public
& Government Affairs, Information
Technology, Office Services and the
Corporate Secretariat function. She adds
responsibility for the coordination of the
Environment, Health and Safety, and
Corporate Security functions.

Stephen J.J. Letwin is appointed
Group Vice President, Gas Strategy
& Corporate Development. He retains
responsibility for Energy Distribution
and adds Planning and Business
Development functions.

Jim Schultz is appointed Senior Vice
President and continues as President,
Enbridge Gas Distribution, responsible
for the Company’s Eastern Canadian
businesses. He reports to Mr. Letwin.

Dan C. Tutcher continues as Group
Vice President, Transportation South,
responsible for the Company’s
energy delivery businesses in
the United States.

Scott Wilson is appointed Senior
Vice President, Finance, responsible
for the Treasury, Controllers and
Financial Services functions.
He reports to Mr. Wuori.

Stephen J. Wuori is appointed
Group Vice President & Chief
Financial Officer, responsible
for all financial affairs of
the Company.

Designed and Produced by Rivard Communications Inc., Calgary. Printed by Quebecor World Calgary.

Enbridge common shares trade on

the Toronto Stock Exchange in Canada and on

the New York Stock Exchange in the U.S.

under the symbol “ENB”.

Enbridge Inc.

3000, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

Telephone: (403) 231-3900

Fax: (403) 231-3920

w w w. e n b r i d g e . c o m