Enbridge Annual Report 2008

FY2008 Annual Report · Enbridge

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Enbridge common shares trade on the
Toronto Stock Exchange in Canada and on the
New York Stock Exchange in the United States
under the trading symbol ENB.

Enbridge Inc.
3000, 425 - 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
Telephone: (403) 231-3900
Facsimile: (403) 231-3920
Toll free: (800) 481-2804

www.enbridge.com

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 BNY
Mellon Shareowner 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
• any other investment related inquiries
Please contact Enbridge Investor Relations or visit
Enbridge’s website at www.enbridge.com.

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

Annual Meeting
The Annual Meeting of Shareholders will be held at
Le Royal Meridien King Edward Hotel, Toronto, Ontario
at 1:30 p.m. EDT on Wednesday, May 6, 2009.
A live webcast of the meeting will be available at
www.enbridge.com and will be archived on the site
for approximately one year. Webcast details will be
available on the company’s website closer to the
meeting date.

Le présent document est disponible en franc¸ais.

2009 dividend information for common Shares and
preferred Shares, Series A 1

Record date

Payment date

Common Share Dividend
Reinvestment Plan (DRIP)
enrolment cut-off date

Common Share Purchase
Plan cut-off date for DRIP

1st Q

2nd Q

3rd Q

4th Q

Feb. 16 May 15

Aug. 17 Nov. 16

Mar. 1

Jun. 1

Sep. 1

Dec. 1

Feb. 9

May 8

Aug. 10

Nov. 9

Feb. 23 May 25

Aug. 25 Nov. 24

1 Dividend dates are subject to the dividends being declared by the Board
of Directors.

* ENBRIDGE, the ENBRIDGE LOGO and the ENBRIDGE ENERGY SPIRAL

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

Enbridge Inc. is a leader in energy transportation
and distribution in North America and internationally.
Our key objective is to generate superior shareholder value.
In Canada and the United States, we operate the world’s
longest crude oil and liquids transportation system. We
own and operate Canada’s largest natural gas distribution
company. We have growing involvement in natural gas
transmission and midstream businesses throughout North
America. We are investing in renewable and alternative
energy initiatives as well as international energy projects.
Enbridge employs approximately 6,000 people in Canada,
the U.S. and South America.
Enbridge’s 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.
www.enbridge.com

dElivEring
vAluE

Designed and produced by Karo Group Calgary. Printed in Canada by Blanchette Press.

Cert no. SW-COC-002068

Printed on post-consumer recycled paper, a portion of which was manufactured with wind energy.

Safety. Income. Growth.

Our low-risk business model
delivers steady income
and visible, long-term growth.

We’re well positioned
financially and geographically
to take advantage of the
many growth opportunities
before us.

That’s Enbridge.

On the cover:
Over 99% of the pipes Enbridge will use in its expansion projects will be made from recycled steel.

Forward-looking Information: This Annual Report includes references to forward-looking information.
By its nature this information applies certain assumptions and expectations about future outcomes, so we
remind you it is subject to risks and uncertainties that affect every business, including ours. The more
significant factors and risks that might affect future outcomes for Enbridge are listed and discussed in the
“Forward-looking Information” and risk sections of our public disclosure filings, including Management’s
Discussion & Analysis, available on both the SEDAR and EDGAR systems at www.sedar.com and
www.sec.gov/edgar.shtml.

An investment in Enbridge is low risk.

We’re managing risk.
From the capital cost of our growth projects,
the volumes we’re contracted to carry,
and the creditworthiness of our customers to
the impact of fluctuating commodity prices and
foreign exchange and interest rates,
our low-risk business model results
in highly predictable earnings.

Low-risk Business Model

Commodity prices, interest rates
and foreign exchange rates in
combination can impact
Enbridge’s earnings by
no more than 5%.

90% of revenue
is from a low-risk, diversiﬁed
base of large, reputable
investment-grade customers.

80% of earnings
are from volume-insensitive,
long-term commercial
arrangements.

SAFE
InvESTmEnT

Enbridge’s central control centre
enables us to continually monitor the
operations of our crude oil pipeline
system and ensure the safe and
reliable delivery of energy.

Strong dividends.

Currently, Enbridge aims
to pay out 60% to 70% of
adjusted earnings as dividends.
In 2009, we have raised our
quarterly dividend by 12%.

This represents the
fourteenth consecutive year
we’ve increased our dividend.

10-Year Dividend Trend

Over the last decade, Enbridge’s dividend has grown on average by 9.5% annually.

2009e
$1.48 per share

2008
$1.32

2007
$1.23

2006
$1.15

2005
$1.04

2004
91.5¢

2003
83.0¢

2002
76.0¢

2001
70.0¢

2000
63.5¢

1999
59.75¢

STEAdy
IncOmE

Enbridge is expanding its crude oil
terminaling facilities at Hardisty,
Alberta, Cushing, Oklahoma and
numerous other centres along the
liquids pipelines right-of-way in
Canada and the United States.

We’re growing.

Our current Liquids Pipelines
growth projects will help us achieve
average annual earnings per share growth
of 10%+ over the next four years.

We’re also well positioned to
capture many opportunities in large and
growing natural gas developments —
onshore in both Canada and the U.S.
and offshore in the Gulf of Mexico.

Earnings Per Share Growth

2012e

2008
$1.88
per share

2002
$1.34
per share

vISIblE
GrOWTh

Between 2007 and 2011, Enbridge
will have brought into service
approximately $10 billion of new
liquids pipelines growth projects.

We are secure.

A strong balance sheet,
solid cash flow, strong credit ratings
and adequate credit facilities mean
we can fund our current growth
projects and take advantage of
new opportunities.

With this financial flexibility,
we can also choose the most
advantageous time to consider
debt or equity markets.

Growing Cash Flow

Funds from operations (FFO) will nearly double by 2012,
providing a solid base for future growth.

2012e

2008
Funds from
Operations
$1.4 billion

Funds from

Operations

Funds from

Operations

less Dividends

and Maintenance

2.5

2.0

1.5

1.0

0.5

0.0

2007

2008

2009e

2010e

2011e

2012e

WEll
FInAncEd

Ship Shoal 207 is a natural gas
junction platform on Enbridge’s
Manta Ray System in the
Gulf of Mexico.

We have a responsibility for the future.

That’s why we’re investing in
renewable and clean energy technologies
including wind power, hybrid fuel cells
and carbon dioxide sequestration.

We’re also reducing our own
greenhouse gas emissions and
helping our customers
reduce theirs.

Reducing GHG Emissions

As of 2008, we had reduced our Canadian direct greenhouse gas (GHG) emissions
by 27% below 1990 levels, exceeding our initial target of a 20% reduction by 2010.
We’re now revising our GHG reduction target for our Canadian operations
and developing a Company-wide target that will include our assets in the U.S.

424
Kilotonnes (Kt)
1990

426 Kt
1995

375 Kt
2000

326 Kt
2005

311 Kt
2008

302 Kt
2010e

ThInkInG
AhEAd

Enbridge’s share of the power
generated by the four wind
power projects in which we
have interests is the equivalent
of about 35% of the power
consumed by our Canadian
crude oil mainline.

An Enbridge employee readies gas meters for
installation in Ontario homes. Enbridge Gas
Distribution added 41,000 new customers in 2008
and expects to have two million by 2011—just one
part of our company’s compelling growth story.

mEASurInG
SuccESS

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2008 HigHligHts

Year ended December 31,

2008

2007

2006

Financial (unaudited; millions of Canadian dollars, except per share amounts)

Earnings Applicable to Common Shareholders

Earnings per Common Share

Adjusted Earnings per Common Share

Dividends per Common Share

Total Common Share Dividends Declared

Return on Average Shareholders’ Equity

Debt to Debt Plus Shareholders’ Equity

operating

Liquids Pipelines—Average Deliveries (thousands of barrels per day)

Enbridge System 1

Athabasca System 2

Spearhead Pipeline

Olympic Pipeline

Gas Pipelines—Average Throughput Volume (millions of cubic feet per day)

Alliance Pipeline US

Vector Pipeline

Enbridge Offshore Pipelines

Gas Distribution and Services

Volumes 3 (billions of cubic feet)

Number of active customers 3 (thousands)

Degree-day deficiency 4

Actual

Forecast based on normal weather

1,320.8

700.2

615.4

3.67

1.88

1.32

1.97

1.79

1.23

1.81

1.74

1.15

489.3

452.3

403.1

22.2% 13.6% 13.9%

66.6% 66.5% 68.6%

2,030

2,005

2,013

202

110

291

164

103

284

190

289

1,609

1,321

1,672

1,598

1,034

2,060

1,592

1,015

2,153

444

450

408

1,942

1,902

1,852

3,802

3,543

3,659

3,617

3,355

3,745

1 Enbridge System includes Canadian mainline deliveries in Western Canada and to the Lakehead System at the U.S. border as well as Line 8 and Line 9

in Eastern Canada.

2 Volumes are for the Athabasca mainline and Waupisoo Pipeline and do not include laterals on the Athabasca System.

3 Gas Distribution and Services volumes and the number of active customers are derived from the aggregate system supply and direct purchase gas

supply arrangements.

4 Degree-day deficiency is a measure of coldness, which is indicative of volumetric requirements of natural gas utilized for heating purposes. 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 Greater Toronto Area.

2 Letter to Shareholders
6 Enbridge’s Leadership Team
7 Corporate Governance

8 Operations & Assets
15 Corporate Social Responsibility
16 Financial Results

A solid
YEAr

Enbridge Outperforms

Total Shareholder Return

Since the start of the financial crisis in
June 2007, Enbridge has consistently
outperformed the markets and our peers.

June
2007

Dec.
2008

15.7%
Enbridge

0.5%
Canadian
Peer Average

-32.5%
TSX
Composite
Index

lEttEr to
sHArEHoldErs

dear Fellow shareholders,

Our strong results in 2008 confirm that

Enbridge’s value proposition for investors

of safety, income and growth can deliver

even in a difficult economic environment.

Adjusted earnings per share increased

approximately 6% to $1.88, which was

near the midpoint of our guidance range.

Actual earnings rose 89% to $1,321 million

or $3.67 per common share, compared with

$700.2 million or $1.97 per common share

in 2007.

Our Total Shareholder Return (TSR) in

2008 was among the top ten on the TSX 60

index of Canada’s largest companies. From

the start of the credit crisis in mid-2007 to

the end of 2008, a period of broad market

decline, we significantly outperformed our

peers in Canada and the United States, as

well as the broader market indices.

DAViD A. ARLEDGE

Chair of the Board of Directors

PATRiCk D. DANiEL

President and Chief Executive Officer

All of our businesses performed strongly in
2008. Enbridge is fortunate to have managed
well through the crisis in the financial markets
and slump in energy prices due to our strong
business model. We also expect strong earnings
in 2009, and on that basis Enbridge’s Board
of Directors has increased the 2009 annual
dividend by 12%.

Our medium-term financial prospects are equally
robust. We expect to grow annual earnings per
share by more than 10% throughout our current
planning horizon as we continue to bring our
commercially secured crude oil pipeline projects
into service. We remain confident of delivering
20% growth in 2009 alone.

Every aspect of our business today is strategically
well positioned for growth.

Throughout 2008 we remained on schedule
and on budget with the construction of our
$12 billion of crude oil pipeline projects to
serve growth in oil volumes.

schedule and on budget, in an environment
of tight labour markets and escalating costs.

And we have “shovels in the ground” on our
remaining commercially secured projects that are
scheduled to come into service over the course
of 2009 and 2010, including mainline expansion
projects Alberta Clipper, Line 4 and Southern
Access Expansion; and, the Southern Lights
diluent pipeline and the Hardisty Terminal Project.

These projects carry little or no volume risk
nor commodity price risk which means returns
are predictable.

We also made progress in 2008 on proposals
to deliver a new stable and reliable source of
Canadian crude oil to U.S. Gulf Coast markets.
We entered into an agreement with BP Pipelines
(North America) Inc. to develop a new delivery
system between Illinois and Texas. We also
continued to work with Exxon Mobil
Corporation to develop the proposed Texas
Access Pipeline.

We completed construction, and put into service
the 350,000 barrels-per-day Waupisoo Pipeline,
which links oil sands producers to their
upgraders and refineries in Edmonton. The
project was completed one month ahead of

While we now anticipate delays in a number of
the heavy oil projects that drive our long-term
development, we fully expect that all of the
projects ultimately will proceed once crude oil
prices recover and capital costs decrease.

EnbridgE inc. ANNUAL REPORT 2008

opportunitiEs Abound

FOR wELL-FiNANCED

AND GEOGRAPhiCALLy

wELL-POSiTiONED

COmPANiES LikE ENbRiDGE

As part of the cost structure for our customers,
we are very much aware of the need to carefully
manage the cost of our services across all aspects
of our energy delivery business. We have a long
track record of successfully managing costs,
improving productivity and sharing the savings
with our customers, and this has become an
even more important success factor for Enbridge
right now.

Opportunities abound for well-financed and
geographically well-positioned companies
like Enbridge.

We expect to see significant new natural gas
infrastructure developments over the next five
to 10 years in North America. Some of this
growth will be driven by the increasingly
important shale gas plays in British Columbia,
Saskatchewan, North Dakota, Texas and
Louisiana, as well as growing production from
the U.S. Rockies and anticipated development
in the deep-water in the Gulf of Mexico.
Enbridge is strongly positioned to consider any
and all opportunities that meet our criteria for
safety, income and growth. We have the
financial strength to be a valued partner in
many of these developments.

Our existing gas assets all stand to benefit from
these opportunities—the Alliance and Vector
pipelines that move Western Canadian natural
gas to the U.S. Midwest and Ontario; our
substantial natural gas gathering, processing
and transmission infrastructure in the Gulf
of Mexico; and Enbridge Energy Partners,
in which we increased our ownership stake
to approximately 27% from approximately
15% in 2008.

Enbridge Gas Distribution (EGD) celebrated its
160th anniversary in 2008 with another year of
improved results on the strength of continuing
growth in residential and commercial customers
as well as the new incentive regulation program.
EGD is Canada’s largest natural gas distribution
utility, with approximately 1.9 million customers.

Internationally in 2008, our investment in
Colombia again performed well, and we sold
our 25% stake in CLH in Spain for $1.38 billion.
We applied proceeds from the CLH sale
toward funding our North American pipeline
expansion projects.

Enbridge is one of the world’s most sustainable
corporations, and one of the ways we achieve

lEttEr to sHArEHoldErs

this is through our investment in renewable and
clean energy initiatives:

•

In 2008, we completed construction
of a 190 megawatt Ontario wind
project, the second largest wind farm
in Canada.

We are leading the Alberta Saline Aquifer
Project (ASAP), which now includes 38
partners working to develop the long-term
sequestration of CO2. ASAP is the largest
project of its kind in North America. We
expect to begin construction on the pilot
project this year, with injections of carbon
dioxide beginning in 2010. We are
participating in a similar initiative
in Saskatchewan.

We officially launched the world’s first hybrid
fuel cell, which produces 2.2 megawatts of
environmentally preferred, ultra-clean
electricity, or enough power for approximately
1,700 residences. Enbridge has exclusive
North American distribution rights for the
hybrid fuel cell technology.

Ensuring the safety of our employees,
contractors and the public is always a top
priority for Enbridge. We are deeply saddened
to report that one of our valued colleagues,
Henri St. Pierre, died in 2008 in an electrical
accident at our Kerrobert, Saskatchewan, station.
We have intensified our efforts to live up to our
commitment of protecting the health and safety
of all individuals affected by our activities.

Robert W. Martin will be retiring from
the Board of Directors effective May 2009.
A Board member since 1992, Bob was
President and Chief Executive Officer of
The Consumers’ Gas Company Ltd. (now
Enbridge Gas Distribution) from 1984 to
1992. The Board extends its warmest thanks
to Bob for his years of dedicated service.

Enbridge is fundamentally in great shape. Our
success in issuing $500 million of long-term

debt in late 2008 in the midst of very
uncertain capital markets is a testament to the
Company’s financial strength. We entered
2009 with approximately $3 billion of
liquidity, which provides us with the flexibility
we need to capitalize on our many
growth opportunities.

Most notably, we are achieving these results
at a time when both financial and commodity
markets are facing unprecedented challenges.
While we at Enbridge are proud of our
results and our continuing ability to deliver
value to our shareholders, we are mindful
and respectful of the impact of current
economic conditions on our customers,
our business partners and the communities
in which we do business.

Our more than 6,000 employees are
committed to the task of safely delivering
energy, and we wish to thank them for
their outstanding achievements in 2008.

Over its 60-year history, Enbridge has
been a very good investment for shareholders,
consistently providing safety, income and
growth. The best is yet to come over the next
four years as shareholders reap the benefits of
strong growth, increasing dividends and a safe
haven during uncertain times.

david A. Arledge
Chair of the Board of Directors

patrick d. daniel
President and Chief Executive Officer

March 4, 2009

EnbridgE inc. ANNUAL REPORT 2008

EnbridgE’s
lEAdErsHip tEAm

We have structured our executive management
team to ensure the successful execution of the
Company’s growth plans and to maintain the
success of its current operations. Our goal is to
continue to deliver superior returns to our
shareholders and maintain the credibility the
Company has earned with all
of its stakeholders.

ExEcutivE mAnAgEmEnt tEAm (left to right)
Al monAco

Executive Vice President, Major Projects

pAtrick d. dAniEl

President & Chief Executive Officer

J. ricHArd bird

Executive Vice President, Chief Financial Officer

& Corporate Development

dAvid t. robottom

Group Vice President, Corporate Law

bonniE d. dupont

Group Vice President, Corporate Resources

stEpHEn J.J. lEtwin

Executive Vice President,

Gas Transportation & International

stEpHEn J. wuori

Executive Vice President, Liquids Pipelines

EnbridgE’s lEAdErsHip tEAm

corporAtE
govErnAncE

At Enbridge, corporate governance means
that a comprehensive system of stewardship
and accountability is in place and functioning
among Directors, management and employees
of the Company.

boArd oF dirEctors (left to right)
gEorgE k. pEttY Corporate Director
San Luis Obispo, California

cAtHErinE l. williAms Corporate Director
Calgary, Alberta

Enbridge is committed to the principles of good
governance, and the Company employs a variety
of policies, programs and practices to manage
corporate governance and ensure compliance.

The Board of Directors is responsible for the
overall stewardship of Enbridge and, in discharging
that responsibility, reviews, approves and provides
guidance in respect of the strategic plan of the
Company and monitors implementation.

The Board approves all significant decisions that
affect the Company and reviews the results. The
Board also oversees identification of the Company’s
principal risks on an annual basis, monitors risk
management programs, reviews succession
planning and seeks assurance that internal
control systems and management information
systems are in place and operating effectively.

E. susAn EvAns Corporate Director*
Calgary, Alberta

dAvid A. lEsliE Corporate Director
Toronto, Ontario

dAn c. tutcHEr Corporate Director
Houston, Texas

pAtrick d. dAniEl

President & Chief Executive Officer, Enbridge Inc.
Calgary, Alberta

dAvid A. ArlEdgE Chair of the Board, Enbridge Inc.
Naples, Florida

robErt w. mArtin Corporate Director
Toronto, Ontario

J. lornE brAitHwAitE Corporate Director
Thornhill, Ontario

JAmEs J. blAncHArd Senior Partner,

DLA Piper U.S., LLP
Beverly Hills, Michigan

J. HErb EnglAnd Chairman & CEO,

Stahlman-England Irrigation Inc.
Naples, Florida

Additional information about Enbridge’s Corporate Governance,

Board of Directors and Senior Management team can be found

in the Corporate Governance section of Enbridge’s website, at

www.enbridge.com/investor/corporategovernance.

*Retired from the Board in May 2008.

cHArlEs E. sHultz Chair & Chief Executive Officer,

Dauntless Energy Inc.
Calgary, Alberta

EnbridgE inc. ANNUAL REPORT 2008

wEll
positionEd

wE ArE in An unpArAllElEd position

bOTh FiNANCiALLy AND GEOGRAPhiCALLy

TO ExPAND AND ExTEND OUR NETwORkS

ThROUGh ORGANiC AND OPPORTUNiSTiC GROwTh.

ENBRIDGE INC. Headquarters
Calgary, Alberta, Canada

ENBRIDGE ENERGY PARTNERS, L.P. Headquarters
Houston, Texas, USA

ENBRIDGE GAS DISTRIBUTION Headquarters
Toronto, Ontario, Canada

Liquids Systems and Joint Ventures

Natural Gas Systems and Joint Ventures

Gas Distribution

Wind Assets

Clearbrook

Quebec

Superior

Sarnia

Chicago

Patoka

Montreal

Ottawa

Toronto

Buffalo

Philadelphia

Norman Wells

Fort St. John

Zama

Fort McMurray

Edmonton

Calgary

Regina

Vancouver

Seattle

Portland

Casper

Salt Lake City

Cushing

Wood
River

Dallas

Houston

New Orleans

Gulf of Mexico

Coveñas

VENEZUELA
VENEZUEL A

Cusiana/
Cupiagua

Bogotá

C O L O M B I A
COLOMBIA
COLOMBIA

opErAtions
& AssEts

COmmEmORATiNG OUR PAST,
CELEbRATiNG OUR FUTURE

In 2009, Enbridge is proud to celebrate the pioneering
spirit of our forebears and our first 60 years of safely and
reliably delivering energy. On April 30, 1949, Enbridge’s
predecessor, Interprovincial Pipe Line Company, received
its charter and embarked upon the construction of the first
crude oil pipeline connecting newly discovered oil fields in
Alberta with eastern Canadian and U.S. markets.

liquids pipElinEs

wHAt wE’rE doing todAY
Enbridge is Canada’s largest transporter of
crude oil.

We export 69% of Western Canadian oil, which
represents 11% of the U.S.’s daily crude oil
imports. On any single day, Enbridge is the
largest single conduit of oil into the U.S.

The Company’s mainline is the world’s longest,
most sophisticated crude oil pipeline system.
With an export capacity of 2.1 million barrels
per day, we move close to 100 separate
commodities, including more than 20 types
of refined products.

How wE’rE building For tomorrow
Enbridge is the preeminent pipeline provider to
Canada’s oil sands—the largest resource play in
the world. With an estimated 178 billion barrels
of oil sands reserves, Canada ranks second only
to Saudi Arabia in global oil reserves.

commercially secured growth
We are currently engaged in the largest capital
program in our 60-year history—investing
$12 billion to expand our North American
pipeline and terminal network primarily
to support broadening access of oil sands
production to U.S. refining markets.

By 2011, we will have almost doubled the
size of our Liquids Pipelines business, further
diversifying the markets we serve and playing
an even more significant role in energy delivery
in North America.

Shovels in the Ground
Alberta clipper construction began in August
2008 and is scheduled to be in service by
mid-2010. construction of southern lights
began in late summer 2008 and is scheduled
to be in service by the end of 2010.

the Alberta clipper Expansion and southern
lights projects will be built to the highest
standards of pipeline safety and integrity using
the latest pipeline engineering and construction
technologies and practices.

EnbridgE inc. ANNUAL REPORT 2008

COmmERCiALLy SECURED LiqUiDS PiPELiNES PROjECTS

waupisoo
pipeline
350,000 bpd
capacity;
in service
on May 31, 2008

line 4 Extension
880,000 bpd capacity between
Edmonton and Hardisty;
in service 2009

southern lights
180,000 bpd diluent line;
in service in 2010

southern Access
Mainline expansion with phased
in-service dates from 2006 to 2009

spearhead Expansion
68,300 bpd additional capacity;
in service 2009

Alberta clipper
450,000 bpd capacity;
in service in 2010

bakken in play
Our two sponsored investments—Enbridge
Income Fund and Enbridge Energy Partners,
L.P.—are expanding their pipeline systems to
address significant growth in oil production in
the Bakken Formation, which spans parts of
Saskatchewan, North Dakota and Montana.
The Energy Information Administration in the
United States estimates that the Bakken shale
has up to 503 billion barrels of resources in
place (proven, probable and possible).

In response to increasing Bakken production
in Saskatchewan, Enbridge Income Fund
completed an expansion of its Westspur System
in 2008, increasing capacity by 34% to 255,000
barrels per day (bpd). It also announced plans
for a $100-million, 129,000-bpd expansion of
its Weyburn, Westspur and Saskatchewan
pipeline systems to be completed by 2010.

To serve North Dakota and Montana, Enbridge
Energy Partners added 30,000 bpd of crude oil
delivery capacity to its North Dakota System in
2007, bringing total capacity to 110,000 bpd,
and is now proceeding with a further
$150-million, 51,000-bpd expansion to
be in service by early 2010.

Enbridge has a 72.3% overall economic interest
in Enbridge Income Fund and a 27% overall
ownership in Enbridge Energy Partners.

opErAtions & AssEts

Alberta Clipper, which will provide Western Canadian producers
additional transportation capacity to U.S. and Canadian
markets, involves the construction of a new 914-millimetre
(36-inch) diameter, 1,607-kilometre (1,000-mile) crude oil
pipeline from Hardisty, Alberta, to Superior, Wisconsin.

ENBRIDGE INC. Headquarters

Calgary, Alberta, Canada

ENBRIDGE ENERGY PARTNERS, L.P. Headquarters

Houston, Texas, USA

ENBRIDGE GAS DISTRIBUTION Headquarters
Toronto, Ontario, Canada

Liquids Systems and Joint Ventures

Natural Gas Systems and Joint Ventures

Gas Distribution

Wind Assets

Regina

Salt Lake City

Wamsutter

Cheyenne

Clearbrook

Superior

Chicago

NATURAL GAS GROwTh OPPORTUNiTiES

Alliance Pipeline Inc. (50% owned by Enbridge) is jointly
proposing a natural gas pipeline connecting the U.S.
Rocky Mountain Region to the Chicago market hub.
The proposed Rockies Alliance Pipeline — or RAP —
is being developed in response to rapidly increasing supply
from the U.S. Rockies region and will initially provide
1.3 billion cubic feet per day (Bcf/d) of transportation
capacity, expandable to 1.7 Bcf/d. Pending commercial
support, the pipeline is expected to be in service in 2013.

gAs pipElinEs

wHAt wE’rE doing todAY

western canada
Enbridge has major stakes in the Alliance and
Vector natural gas pipeline systems. The Alliance
System transports natural gas from the Western
Canada Sedimentary Basin to the U.S. Midwest.
Connecting with the Alliance System at Chicago,
the Vector Pipeline provides natural gas supplies
for local distribution and end-user customers in
Illinois, Indiana, Michigan and Ontario.

gulf of mexico
Through Enbridge Offshore Pipelines,
we today transport approximately 40% of all
current deepwater natural gas production in the
Gulf of Mexico, a prolific natural gas region.
Enbridge Offshore Pipelines has interests in
11 transmission and gathering pipelines in five
major pipeline corridors in Louisiana and
Mississippi offshore waters.

texas gas
Enbridge Energy Partners is a large natural gas
gatherer and processor in the Anadarko Basin,
Barnett Shale and Bossier Sands of Texas, which

are three of the top four areas for natural gas
development in the U.S. Enbridge Energy
Partners transports approximately 15% of Texas
natural gas production. In 2008, Enbridge Inc.
increased its ownership stake in Enbridge
Energy Partners to 27% from approximately 15%.

How wE’rE building For tomorrow
The Alliance System is well positioned for
opportunities arising from the development of
natural gas in northeast British Columbia, the
U.S. Rocky Mountain region, Alaska and
Canada’s Arctic.

The Vector Pipeline, which expanded capacity in
2007 to 1.2 billion cubic feet per day (bcf/d), is
undertaking a 0.1-bcf/d expansion in 2009 with
potential further expansion in 2010 to 2011.

Enbridge Offshore Pipelines is growing its
natural gas gathering, processing and transmission
infrastructure in the Gulf of Mexico.

Enbridge Energy Partners expects to see
strong growth in demand for processing and
gathering pipelines to serve Texas onshore
natural gas production.

EnbridgE inc. ANNUAL REPORT 2008

160 yEARS OF ExPERiENCE

Enbridge Gas Distribution is building on a 160-year
history of delivering energy to consumers safely and
reliably. Our roots stretch back to 1848, when energy
customers in Toronto incorporated a company then called
Consumers Gas to secure a “purer, more regular, cheaper
supply of gas.” In marking our 160th anniversary in
2008, we honoured our past achievements and look
forward to continuing leadership as one of North
America’s largest natural gas distributors.

gAs distribution And sErvicEs

wHAt wE’rE doing todAY
Enbridge Gas Distribution is Canada’s largest gas
distribution utility and one of the fastest growing
in North America. Enbridge Gas Distribution
and its affiliates serve approximately 1.9 million
customers in central and eastern Ontario,
southwestern Quebec and parts of northern
New York State. In 2008, Enbridge Gas
Distribution added over 41,000 new customers
and marked its 160th anniversary of operations.

In addition, Enbridge:

•

owns 32.1% of Noverco Inc., which holds
a majority interest in Gaz Métro Limited
Partnership, the company that distributes
natural gas in Quebec; and

owns 70.9% of, and operates, Enbridge
Gas New Brunswick (EGNB), which owns
the natural gas distribution franchise in the
province of New Brunswick.

How wE’rE building For tomorrow
Enbridge Gas Distribution expects to add
35,000 customers in 2009 and have about
two million customers by 2011.

opErAtions & AssEts

Consumers Gas Building, Toronto, Ontario, ca. 1876

We are optimizing the performance of Enbridge
Gas Distribution through incentive regulation
(IR), which went into effect in 2008. IR reduces
regulatory costs. It also provides shareholder
incentives for improved efficiency and revenue
growth, more flexibility for utility management
and shared cost savings with customers. The
customer share of savings achieved in 2008
was $5.8 million.

We are also positioning ourselves for
opportunities such as new infrastructure for
gas-fired power generation in Ontario and
growth in Enbridge’s unregulated businesses,
including natural gas storage. In 2009, we are
conducting an open season for approximately
2.5 bcf of new storage capacity.

Ottawa Expansion
the Alfred and plantagenet project, one of the
most significant system expansions undertaken
in the ottawa area in the last decade, will provide
natural gas service to 2,800 new customers in
three communities east of the city. thanks to the
innovation and teamwork of employees involved, this
project met or exceeded all safety, quality, timing
and budget targets. organic growth projects are key
in today’s business environment, characterized by a
declining new construction market.

ONTARiO wiND POwER

In 2008, Enbridge completed construction of its Ontario
Wind Power project—the second largest wind farm
in Canada. The 115-turbine wind farm located in Bruce
County, Ontario, on the eastern shore of Lake Huron is
contributing 190 megawatts of emissions-free energy to
Ontario’s grid—enough electricity to supply about 63,000
Ontario homes and reduce greenhouse gas emissions
equivalent to taking about 30,000 vehicles off the road.

FuEl cEll powEr plAnt
In 2008, we officially launched the world’s
first hybrid fuel cell power plant that is designed
for gas utility pressure reduction stations.
The plant harvests pipeline energy that would
otherwise be wasted, and the fuel cell operates
without burning any fuel to produce about
2.2 megawatts of environmentally preferred,
near zero-emissions electricity—enough to
serve about 1,700 Ontario homes.

Enbridge has exclusive North American
distribution rights for the hybrid fuel cell
technology. We plan to replicate the plant
throughout our distribution network in Ontario
and market the hybrid fuel cell to other natural
gas pipeline companies in North America.

solAr And gEotHErmAl
We are currently exploring the potential for
solar power projects in Ontario and evaluating
opportunities for taking an equity position
in new solar power technologies. We are also
examining our potential involvement in
geothermal energy.

EnbridgE inc. ANNUAL REPORT 2008

rEnEwAblE And
grEEn EnErgY dEvElopmEnt

We are encouraging the use of renewable and
clean energy by investing in wind power and
new energy technologies such as fuel cells.
We are also positioning ourselves for the future
by participating in the emerging technology of
carbon dioxide (CO2) capture, pipelining and
sequestration and participating in research for
the safe transport of ethanol through pipelines.

wind powEr
Enbridge owns a 100% working interest in the
190-megawatt Ontario Wind Power project.
Located in Bruce County, Ontario, it is the
second largest wind farm in Canada. Enbridge
Income Fund owns interests in two wind farms
in Alberta and one in Saskatchewan. These four
wind power projects have a combined capacity of
more than 260 megawatts, our share of which is
enough green energy to provide 35% of our total
Canadian crude oil mainline power consumption.

We expect future wind opportunities to come
through expanding our existing operations, as
well as developing new greenfield projects near
Enbridge operations throughout North
America, particularly where operating synergies
can be applied.

coal

saline
aquifier

co2
capture

C O 2

bitumen
upgraders

oilsands

C O 2

co2
capture

cokers

CO
2

C O 2

sequestration

co2

non-permeable layer

saline
aquifier

enhanced
oil recovery

co2

oil

CARbON DiOxiDE SEqUESTRATiON

co2 cApturE, pipElining
And sEquEstrA tion
Enbridge is involved in two initiatives in
Canada that are investigating the feasibility
of the long-term commercial sequestration of
carbon dioxide (CO2) in deep saline aquifers.

CO2 capture, pipelining and sequestration
developments are widely considered to be one
of the most immediate, feasible and meaningful
ways to reduce greenhouse gas emissions on a
large scale and address the challenges posed
by climate change.

We are leading a consortium of 38 energy
industry participants in the Alberta Saline
Aquifer Project (ASAP), and we are one of five
participants in the Saskatchewan Aquistore
project, which is managed by the Petroleum
Technology Research Centre.

These initiatives will play a major role in
advancing industry and government’s
knowledge of CO2 capture and sequestration.

Phase I of ASAP, which is on track to be
completed in spring 2009, has identified suitable
deep saline aquifer locations for long-term CO2
sequestration in Alberta. Saline aquifers are
underground formations containing brine or salt
water that is not suitable for agricultural purposes
or for drinking.

The ASAP consortium also engaged in
discussions with representatives of organizations
that could supply large amounts of carbon
dioxide. The goal is to sequester between 1,000
and 3,000 tonnes of CO2 daily—the equivalent
of pulling between 73,000 and 219,000 cars off
Alberta roads.

Phase II of ASAP involves developing a pilot
project, receiving all the necessary regulatory
approvals and injecting carbon dioxide into the
identified aquifers. The consortium now expects
construction on the pilot project will begin in
2009 and injections of CO2 to begin in 2010.

Phase III will involve expanding the pilot project
to a large-scale, long-term commercial operation.

opErAtions & AssEts

corporAtE
sociAl
rEsponsibilitY

EnbridgE’s drivE For

opErAting ExcEllEncE

iS bUiLT ON A STRONG FOUNDATiON OF

CORE VALUES AND CORPORATE SOCiAL

RESPONSibiLiTy POLiCiES AND PRACTiCES.

Improving Energy Efficiency

Enbridge gas distribution has more than 40
demand-side management (dsm) programs that
encourage customers to adopt energy-saving
initiatives to reduce consumption of natural gas.
since 1995, our dsm programs have delivered
about 4.4 billion cubic metres of natural gas
savings, the equivalent of enough gas to supply
approximately 1.4 million homes for one year.

DSM Natural Gas Savings (by Volume)

2003
385,503,497 m3

2004
455,624,194 m3

2005
532,681,439 m3

2006
623,150,603 m3

2007
713,871,082 m3

2008
797,327,733 m3

EnbridgE inc. ANNUAL REPORT 2008

wE’rE building
morE tHAn pipElinEs

As a leader in corporate social responsibility
(CSR), we always aim to be the best by
conducting business in a socially responsible and
ethical way, protecting the environment and the
health and safety of people, supporting human
rights and engaging, respecting and supporting
the communities and cultures in which we live
and work.

We want to make our communities more
sustainable, so we’re investing in four key
building blocks—the environment, education,
culture and community, and health and safety.

We believe we have a responsibility for the future
and that our energy can make all the difference.
For more information on the good thinking
we’re putting into improving our CSR
performance, please visit our 2008 CSR Report
at www.enbridge.com.

FinAnciAl
rEsults

Total Shareholder Return

For over 50 years, we have achieved a 12.8% average annual return to shareholders
and are focused on maintaining this enviable track record.

Total Return Index
December 1958 = 1

FinAnciAl
rEsults

Enbridge 12.8%

500

400

300

200

100

1958

1968

1978

1988

1998

2008

9.2%
S&P/TSX

17 Management’s Discussion and Analysis
76 Management’s Report
77 Independent Auditors’ Report
79 Consolidated Statements of Earnings
80 Consolidated Statements of Comprehensive Income
81 Consolidated Statements of Shareholders’ Equity
82 Consolidated Statements of Cash Flows

83 Consolidated Statements of Financial Position
84 Notes to the Consolidated Financial Statements
133 Supplementary Information
134 Five-year Consolidated Highlights
136 Enbridge Businesses
137 Awards and Recognition in 2008
138 Investor Information

MANAGEMENT’S DISCUSSION AND ANALYSIS

CONSOLIDATED EARNINGS

(millions of Canadian dollars, except per share amounts)

Liquids Pipelines

Gas Pipelines

Sponsored Investments

Gas Distribution and Services

International

Corporate

Earnings Applicable to Common Shareholders

Earnings per Common Share

Diluted Earnings per Common Share

2008

328.0

48.5

111.7

300.6

608.2

(76.2)

1,320.8

3.67

3.64

2007

287.2

69.7

96.9

179.4

95.1

(28.1)

700.2

1.97

1.95

2006

274.2

61.2

86.8

173.7

83.2

(63.7)

615.4

1.81

1.79

Earnings applicable to common shareholders were $1,320.8 million for the year ended December 31,
2008, or $3.67 per share, compared with $700.2 million, or $1.97 per share, for the same period in
2007. The increase in earnings resulted from allowance for equity funds used during construction
(AEDC) in Liquids Pipelines, a higher contribution from Enbridge Gas Distribution (EGD) and
unrealized fair value gains on derivative financial instruments in Aux Sable and Energy Services, partially
offset by decreased earnings from International as the Company sold its interest in Compa˜n´ıa Log´ıstica
de Hidrocarburos CLH, S.A. (CLH) in the second quarter of 2008. Earnings for the year ended
December 31, 2008 also reflected a $556.1 million after-tax gain on the sale of CLH, partially offset by
the recognition of a $32.2 million income tax charge as a result of an unfavourable court decision related
to previously owned U.S. pipeline assets.

Earnings applicable to common shareholders were $700.2 million for the year ended December 31,
2007, or $1.97 per share, compared with $615.4 million, or $1.81 per share, in 2006. The $84.8 million
increase was primarily due to colder than normal weather and strong performance at EGD, lower
corporate interest expense and increased earnings at Enbridge Energy Partners, L.P. (EEP). The 2007
results also included a significant benefit from favorable legislated Canadian tax changes enacted in 2007.
The positive factors were partially offset by lower contributions from the Aux Sable natural gas
fractionation facility and Energy Services.

Earnings Applicable to Common Shareholders

(millions of Canadian dollars)

1,320.8

240.9

287.9

392.3

458.5

576.5

667.2

645.3

556.0

615.4

700.2

5MAR200917084720
07

ENBRIDGE INC.

ANNUAL REPORT 2008

FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this Management’s
Discussion and Analysis (MD&A) to provide Enbridge Inc. (Enbridge or the Company) shareholders and
potential investors with information about the Company and its subsidiaries, including management’s
assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be
appropriate for other purposes. Forward-looking statements are typically identified by words such as
‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and
similar words suggesting future outcomes or statements regarding an outlook. Although Enbridge believes
that these forward-looking statements are reasonable based on the information available on the date such
statements are made and processes used to prepare the information, such statements are not guarantees of
future performance and readers are cautioned against placing undue reliance on forward-looking
statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and
uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ
materially from those expressed or implied by such statements. Material assumptions include assumptions
about: the expected supply and demand for crude oil, natural gas and natural gas liquids; prices of crude oil,
natural gas and natural gas liquids; expected exchange rates; inflation; interest rates; the availability and
price of labour and pipeline construction materials; operational reliability; anticipated in-service dates
and weather.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating
performance, regulatory parameters, weather, economic conditions, exchange rates, interest rates and
commodity prices, including but not limited to those risks and uncertainties discussed in this MD&A and in
the Company’s other filings with Canadian and United States securities regulators. The impact of any one
risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as
these are interdependent and Enbridge’s future course of action depends on management’s assessment of all
information available at the relevant time. Except to the extent required by law, Enbridge assumes no
obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise,
whether as a result of new information, future events or otherwise. All subsequent forward-looking
statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are
expressly qualified in their entirety by these cautionary statements.

NON-GAAP MEASURES
This MD&A contains references to adjusted earnings, which represent earnings applicable to common
shareholders adjusted for non-recurring or non-operating factors on both a consolidated and segmented
basis. These factors are reconciled and discussed in the Financial Results sections for the affected business
segments. Management believes that the presentation of adjusted earnings provides useful information
to investors and shareholders as it provides increased transparency and predictive value. Management
uses adjusted earnings to set targets, assess performance of the Company and set the Company’s
dividend payout target. Adjusted earnings and adjusted earnings for each of the segments are not
measures that have a standardized meaning prescribed by Canadian generally accepted accounting
principles (GAAP) and are not considered GAAP measures; therefore, these measures may not be
comparable with similar measures presented by other issuers. See Non-GAAP Reconciliation section for
a reconciliation of the GAAP and non-GAAP measures.

MANAGEMENT’S DISCUSSION AND ANALYSIS

ADJUSTED EARNINGS

(millions of Canadian dollars, except per share amounts)

Liquids Pipelines

Gas Pipelines

Sponsored Investments

Gas Distribution and Services

International

Corporate

Adjusted earnings

Adjusted earnings per Common Share

2008

332.1

45.7

100.9

204.3

52.1

(57.8)

677.3

1.88

2007

286.0

64.4

86.5

168.9

89.9

(59.2)

636.5

1.79

2006

274.2

61.2

74.3

177.7

83.2

(77.7)

592.9

1.74

Adjusted earnings were $677.3 million, or $1.88 per share, for the year ended December 31, 2008,
compared with $636.5 million, or $1.79 per share, for the year ended December 31, 2007.

Significant operating factors that increased adjusted earnings in 2008 included:

(cid:127)

New facilities within Liquids Pipelines as well as AEDC on Southern Lights Pipeline and, within
Enbridge System, on both Southern Access Mainline Expansion and Alberta Clipper Project.
Increased Aux Sable adjusted earnings due to strong fractionation margins which enabled the
Company to recognize earnings from the upside sharing mechanism.
Higher incentive income and increased earnings at EEP primarily due to higher gas and crude oil
delivery volumes, tariff surcharges for recent expansions and a greater ownership interest.
Improved earnings in Energy Services resulting from market conditions which enabled higher
margins to be captured on storage and transportation contracts as well as increased transportation
and storage volumes.

Significant operating factors that decreased adjusted earnings in 2008 included:

(cid:127)

Decreased earnings from International as a result of the sale of CLH in the second quarter of 2008.
Lost revenue from Enbridge Offshore Pipelines (Offshore) as a result of Hurricanes Gustav and Ike.

2008 Commercial and Construction Accomplishments:

(cid:127)

Alberta Clipper, Southern Lights Pipeline and Line 4 Extension were approved by the National
Energy Board (NEB) and construction began on the Canadian portion of Alberta Clipper Project,
Line 4 Extension and various segments of Southern Lights Pipeline.
First phase of the U.S. Southern Access Expansion Project has been completed on schedule and
construction commenced on Phase 2 of Southern Access Expansion Project.
Waupisoo Pipeline, which was completed one month ahead of schedule and on budget.
Spearhead Pipeline expansion commenced.
Project financing of US$1.3 billion and $0.4 billion secured for Southern Lights Pipeline.

Adjusted Earnings per Common Share

(Canadian dollars per share)

1.50

1.47

1.59

1.34

1.23

1.74

1.79

1.88

1.02

1.08

0.91

5MAR200917084458
07

ENBRIDGE INC.

ANNUAL REPORT 2008

CORPORATE STRATEGY

CORPORATE VISION AND KEY OBJECTIVE
Enbridge is an energy delivery company that transports natural gas and crude oil, which are used for
many purposes, including to heat homes, power transportation systems and provide fuel and feedstock
for industries. The Company’s vision is to be North America’s leading energy delivery company and its
key objective is to generate superior shareholder value. The Company will deliver superior shareholder
value through an investment proposition consisting of:

(cid:127)

industry leading earnings per share growth rate;
a low risk commercial business model; and
a balanced combination of near-term dividend income and capital appreciation.

STRATEGY
Enbridge’s 2008 Strategic Plan consisted of four key strategic priorities to generate superior shareholder
value and position the Company for the energy environment of the future.

1. Expand Existing Core Businesses

Developing and operating energy delivery infrastructure assets remains the Company’s core
competency and strength. To capitalize on its asset position, Enbridge will pursue opportunities in
both its liquids and natural gas delivery businesses. The Company will aggressively focus on the
expansion and extension of its liquids pipeline and terminaling businesses. The Company will also
seek to capture additional growth opportunities associated with its gas businesses to maintain as
much diversification as is prudent. Strategies for each core business are included in the sections
to follow.

2. Focus on Operations

Effective day-to-day management of operations is integral to Enbridge’s broader strategy.
Achieving the Company’s long-term objectives depends on its ability to consistently deliver safe,
cost-effective and high quality service to customers and meet the broader expectations of
communities it serves. Operational excellence will ensure that the Company is able to deliver
consistent and predictable operating and financial performance while rapidly growing its asset and
earnings base. Enbridge will continue its focus on operational excellence, including cost efficiency,
safety and customer service.

3. Mitigating and Managing Execution Risk

Executing Enbridge’s unprecedented capital program demands effective strategies for mitigating
and managing project development risk. Key priorities include enhanced project management
systems and processes, proactive human resource planning and an increased focus on
social investment, to both facilitate project development and meet the expectations of the
Company’s stakeholders.

4. Developing New Platforms for Longer-term Growth

In the longer term, developing new business platforms will be important to maintaining growth and
diversification within the Company. New platforms currently being pursued include renewable
energy (wind and solar), CO2 transportation and sequestration and investment in smaller start-up
entities to enable the development of new technologies that complement the Company’s
core operations.

MANAGEMENT’S DISCUSSION AND ANALYSIS

To successfully pursue these strategies, the Company must also mitigate other risks. These risks, and the
Company’s strategies for managing them, are described under Risk Management.

Enbridge’s strategy is reviewed annually with direction from its Board of Directors. The Company
continually assesses ways to generate value for shareholders, including reviewing opportunities that may
lead to acquisitions, dispositions or other strategic transactions, some of which may be material.
Opportunities are screened, analyzed and must meet operating, strategic and financial benchmarks
before being pursued.

COMPETITIVE ADVANTAGE
The Company’s ability to execute its strategy and realize its corporate vision depends primarily on three
key strengths. These include the strategic position of the Company’s major assets, the diversification of
its businesses and its consistent focus on operational excellence including customer service.

The Company’s assets are well positioned in North America. In the Liquids Pipelines business, the
Company operates a major conduit between U.S. markets and the attractive oil sands reserves in western
Canada. Enbridge has economies of scale and scheduling flexibility because of its multiple separate lines
and the flexibility to move over 95 different grades of crude oil. Enbridge’s existing right of way is
valuable in developing major expansion projects due to increasing environmental and landowner
challenges in securing new or expanded energy corridors. Also, the Company serves a diversity of
markets because of the extent and reach of its pipeline systems. The gas businesses are also well located.
The Ontario gas utility franchise in Toronto benefits from significant customer addition rates due to
immigration and urbanization.

The Company’s sources of earnings and growth are diversified among liquids pipelines, gas pipelines, gas
distribution and international investments. As well, the Company is actively exploring new growth
platforms that would further diversify and complement existing core businesses.

The Company is focused on adding value for customers and improving customers’ profitability. This
focus has aligned the Company with supply-demand fundamentals, which have consistently formed a
basis for the Company’s strategy. The Company seeks to provide value to customers in a variety of
innovative ways, including provision of access to new markets for producers and new sources of supply
for refiners, diversifying the supply of diluent required for transportation of heavy crude and protection
of batch quality and value.

GROWTH PROJECTS
The thrust of the Company’s current strategy is growth through development and construction of new
infrastructure. The Company is advancing the development of a number of organic growth projects,
some of which are summarized below, which support annual organic earnings per share growth rates
averaging 10% ‘plus’ over the 2007 to 2012 time frame. These projects are at various stages
of development; some are recently completed and in service.

ENBRIDGE INC.

ANNUAL REPORT 2008

While different milestones are relevant to each, for simplicity management has classified projects into two
categories – Commercially Secured and Under Development. Commercially Secured projects, including
those being undertaken by EEP, are largely expected to be completed within the next two years. Projects
Under Development are those which the Company believes it has a reasonable probability of
competitively winning but has not yet completed commercial terms for. While Enbridge will undertake
acquisitions that are accretive to earnings on an opportunistic basis, growth project execution remains
the Company’s primary near term focus. The following table summarizes commercially secured projects
that have not yet been placed into service.

Commercially Secured Projects 1

(in billions of Canadian dollars unless stated otherwise)

Liquids Pipelines

Estimated
Capital Cost 2

Expenditures
to Date

Expected
In-Service Date

Status

Southern Access Mainline

$0.2 billion

2008

Expansion – Canadian portion

Substantially

complete

Line 4 Extension

$0.3 billion

$0.2 billion

Early 2009

Under

construction

Spearhead Pipeline Expansion

US$0.1 billion

First half of 2009

Under

construction

4. Hardisty Terminal

$0.6 billion

$0.4 billion

2009

Under

(in stages)

construction

Southern Lights Pipeline

$0.5 billion +

$0.3 billion +

Light Sour Line –

Under

US$1.7 billion

US$0.9 billion

Early 2009;

construction

6. Alberta Clipper – Canadian portion

$2.4 billion

$0.8 billion

Diluent Line –

Late 2010

Mid-2010

Under

construction

Fort Hills Pipeline System

~$2.0 billion

$0.1 billion

No earlier than

Being

2012

reevaluated

Sponsored Investments

EEP – Southern Access Mainline

US$2.1 billion

US$1.9 billion

2008 - 2009

Under

Expansion – U.S. portion

(in stages)

construction

EEP – North Dakota System

US$0.1 billion

No significant

Q1 2010

Under

Expansion

expenditures to

date

10. EEP – Alberta Clipper –

US$1.2 billion

US$0.1 billion

Mid-2010

U.S. portion

construction

Awaiting

regulatory

approval

11. EIF – Saskatchewan System

$0.1 billion

No significant

Q3 2010

Pre-construction

expenditures to

date

1 Descriptions of each project are included in the strategy section for each business segment.

These amounts are estimates only and subject to upward or downward adjustment based on various factors.

Risks related to the development and completion of organic growth projects are described under Risk
Management.

MANAGEMENT’S DISCUSSION AND ANALYSIS

Fort McMurray

Edmonton

Hardisty

Superior

Quebec City

Chicago

Toledo

Patoka

Cushing

Houston

New
Orleans

COMMERCIALLY SECURED PROJECTS

Liquids Pipelines

1 Southern Access Mainline

Expansion—Canadian portion

2 Line 4 Extension

3 Spearhead Pipeline Expansion

4 Hardisty Terminal

5 Southern Lights Pipeline

6 Alberta Clipper—Canadian portion

7 Fort Hills Pipeline System

Sponsored Investments

8 EEP—Southern Access Mainline

Expansion—U.S. portion

9 EEP—North Dakota System Expansion

10 EEP—Alberta Clipper—U.S. portion
11 EIF—Saskatchewan System

Current Assets

Growth Opportunities

6MAR200914080102

ENBRIDGE INC.

ANNUAL REPORT 2008

DISRUPTION OF FUNCTIONING OF CAPITAL MARKETS
Multiple events during 2008 involving numerous financial institutions have restricted liquidity in the
capital markets. Despite efforts by government agencies to provide liquidity to the financial sector,
capital markets currently remain constrained. Given the Company’s current and future growth and
related funding requirements, these events and market conditions pose potential challenges. The
Company’s strong, predictable, internally generated cash flows; common share issuances under the
Company Dividend Reinvestment and Share Purchase Plan; and access to adequate and recently
increased committed credit facilities from diversified sources assist in mitigating these challenges.
Maintaining the Company’s investment grade credit rating may also support continued access to capital
markets and debt refinancing at reasonable terms, if required. See Sensitivity Analysis and Risk
Management – Credit Risk sections.

Decline in Commodity Prices
Since the end of the third quarter, commodity prices have significantly declined. As an energy
transportation company, Enbridge has very limited direct exposure to commodity price changes and the
Company employs comprehensive risk management practices to largely fix and mitigate any residual
commercial exposures. Most significantly, the Company’s assets and operations are largely secured by
high quality shipper volume commitments. Similarly, liquids pipelines growth projects under
construction are commercially secured with limited volume sensitivity and are therefore not expected to
be significantly impacted by commodity price declines. Low commodity prices are resulting in the delays
or cancellation of some oil and gas development and expansion projects. Should current trends continue
long term, opportunities for future growth projects may be adversely affected. See Liquidity and
Capital Resources.

DIVIDENDS
The Company has paid common share dividends since its inception. Based on estimated 2009 dividends,
the rate of increase has averaged 10.1% since 1953. The Company’s dividend payout ratio reflects a
strong and stable long-term outlook for its business. Despite current economic conditions, in
December 2008 the Company announced a 12% increase in its quarterly dividend to $0.37 per common
share, or $1.48 annualized. The Company continues to target a pay out of approximately 60% to 70% of
adjusted earnings as dividends and, with the most recent dividend increase, the 2009 pay out should be
near the midpoint of the range. In 2008, dividends paid per share were 70% of adjusted earnings per
share (2007 – 69%, 2006 – 66%).

The following chart shows dividends per share for the last 10 years, as well as estimated dividends for
2009, based on the quarterly dividend of $0.37 per common share declared by the Board of Directors on
December 3, 2008.

CORPORATE SOCIAL RESPONSIBILITY
Enbridge has a strong foundation of core values and corporate social responsibility policies and practices.
Enbridge defines Corporate Social Responsibility (CSR) as conducting business in a socially responsible
and ethical way, protecting the environment and the health and safety of people, supporting human
rights and engaging, respecting and supporting the communities and cultures with which the
Company works.

Dividends per Common Share

(Canadian dollars per share)

1.23

1.15

1.04

1.32

1.48

0.60

0.64

0.70

0.76

0.92

0.83

5MAR200917084596
08

09E

MANAGEMENT’S DISCUSSION AND ANALYSIS

A comprehensive system of stewardship and accountability is in place and functioning among Directors,
management and employees. Examples
include compliance with applicable Sarbanes-Oxley
requirements and the Canadian securities regulators’ corporate governance guidelines and rules, the use
of internal and external reviews and audits to assess each business segment’s compliance with
government regulations and internal policies and management systems, and to provide guidance for
making further improvements. Employee and Director compliance with Enbridge’s Statement on
Business Conduct, a majority of independent Directors on the Company’s Board of Directors and plain
and open communication with stakeholders are other examples of stewardship and accountability.

Environmental initiatives include pursuing alternative and renewable energy technologies, minimizing
pipeline leaks by conducting on-going inspection and maintenance programs and the development of a
strategy to reduce greenhouse gas emissions. This strategy involves improving the energy efficiency of
pipelines, encouraging the efficient use of natural gas by customers and replacing older cast iron pipe at
EGD with new polyethylene mains. Enbridge engages employees on health and safety issues through
training, communication programs and the establishment of local and regional Environmental, Health
and Safety committees.

Stakeholder relations involves developing and maintaining positive relationships with employees,
contractors, suppliers, customers, landowners, investors, community residents, aboriginal communities,
business partners, government agencies and regulators, provincial, state and federal legislators, local
officials, environmental groups and the media. Initiatives include early-stage project consultation with a
variety of stakeholders on organic growth projects and public awareness programs on pipeline safety.

Enbridge supports universal human rights and reinforces this principle with comprehensive policies and
practices addressing human rights. For example, Enbridge was one of the first Canadian companies to
adopt the Voluntary Principles on Security and Human Rights, which stress the importance of
promoting and protecting human rights throughout the world and the constructive role business can
play in advancing these goals.

The Company makes voluntary contributions to charitable and non-profit organizations in the areas of:
education, health, environment, social services, arts and culture, community leadership and
volunteerism, in order to contribute to the economic and social development of communities where
Enbridge employees live and work.

While Enbridge is focused on generating long-term value for investors, Corporate Social Responsibility
defines the Company’s commitment to achieving and sustaining that objective in a socially and
environmentally responsible way.

CORE BUSINESSES
The Company’s activities are carried out through five business segments:

(cid:127)

Liquids Pipelines, which includes the operation and construction of the Enbridge crude oil mainline
system and feeder pipelines that transport crude oil and other liquid hydrocarbons.
Gas Pipelines, which consists of the Company’s interests in natural gas pipelines including Alliance
Pipeline US, Vector Pipeline and Enbridge Offshore Pipelines.
Sponsored Investments, which includes investments in Enbridge Income Fund (EIF or the Fund)
and EEP, both managed by Enbridge.
Gas Distribution and Services, which consists of gas utility operations which serve residential,
commercial, industrial and transportation customers, primarily in central and eastern Ontario, the
most significant being EGD. It also includes natural gas distribution activities in Quebec,
New Brunswick and New York State, the Company’s investment in Aux Sable, a natural gas
fractionation and extraction business, and the Company’s commodity marketing businesses.
International, which includes the Company’s energy-delivery investment outside of North America.

ENBRIDGE INC.

ANNUAL REPORT 2008

LIQUIDS PIPELINES

Liquids Pipelines consists of crude oil, natural gas liquids (NGLs) and refined products pipelines in
Canada and the United States.

EARNINGS

(millions of Canadian dollars)

Enbridge System

Athabasca System

Spearhead Pipeline

Olympic Pipeline

Southern Lights Pipeline

Feeder Pipelines and Other

Adjusted Earnings

Enbridge System – impact of tax changes

Feeder Pipelines and Other – asset impairment loss

Earnings

2008

211.5

69.1

12.0

7.1

27.6

4.8

332.1

–

(4.1)

328.0

2007

202.5

53.7

10.0

9.9

6.8

3.1

286.0

1.2

–

287.2

2006

202.3

52.8

6.3

6.5

–

6.3

274.2

–

274.2

Liquids Pipelines adjusted earnings were $332.1 million in 2008 compared with $286.0 million in 2007.
The increase was due primarily to strong contributions from the Enbridge and Athabasca Systems, as
well as the recognition of AEDC on Enbridge System and Southern Lights Pipeline.

While under construction, certain regulated pipelines are entitled to recognize AEDC in earnings. These
amounts will contribute to earnings throughout the Company’s significant growth period and will be
collected in tolls once the pipelines are in service. The earnings impact of AEDC for the year ended
December 31, 2008 was $17.8 million (2007 – $2.9 million) for Enbridge System and $27.6 million
(2007 – $6.8 million) for Southern Lights Pipeline.

Liquids Pipelines adjusted earnings were $286.0 million in 2007 compared with $274.2 million in 2006.
The increase was due primarily to strong contributions from Spearhead and Olympic Pipelines, as well as
the recognition of AEDC on Southern Lights Pipeline.

Liquids Pipelines earnings were impacted by the following non-operating adjusting items:

(cid:127)

In the fourth quarter of 2008, the Company recorded an impairment loss of $4.1 million on
Manyberries Pipeline, a small feeder pipeline located in Canada.
Enbridge System was affected by favorable tax rate changes in 2007.

Liquids Pipelines revenues were $1,170.5 million in the year ended December 31, 2008, an increase of
$79.6 million compared with $1,090.9 million in the year ended December 31, 2007. This increase
is due to higher base tolls on Enbridge System and the new Waupisoo Pipeline included in the
Athabasca System.

Revenues in the Liquids Pipelines segment increased to $1,090.9 million in the year ended
December 31, 2007 from $1,048.1 million in the year ended December 31, 2006. The increased
revenue was partially due to increased volumes on Spearhead Pipeline and higher tolls on Olympic
Pipeline. In addition, revenue reflected full year contribution from Spearhead Pipeline and
Olympic Pipeline.

Liquids Pipelines
(millions of Canadian dollars)

Adjusted Earnings

Earnings
(millions of Canadian dollars)

219.9

229.1

274.2

286.0

332.1
2MAR200907311222

219.9

229.1

274.2

287.2

328.0
28FEB200902511982

MANAGEMENT’S DISCUSSION AND ANALYSIS

ENBRIDGE SYSTEM
The mainline system is comprised of Enbridge
System and Lakehead System (the portion of the
mainline in the United States that is operated by
Enbridge and owned by EEP). Enbridge has
operated, and frequently expanded, the mainline
system since 1949. Through five adjacent
pipelines with
capacity of
approximately 2.0 million barrels per day (bpd),
the system transports various grades of crude oil
and diluted bitumen from Western Canada to the
Midwest region of the United States and Eastern
Canada. Also included in Enbridge System and
located in Eastern Canada are two crude oil
pipelines and one refined products pipeline with
a combined capacity of 0.4 million bpd. Average
system utilization in 2008 was 85% and it is expected to increase in 2009.

Liquids Pipelines

combined

6MAR200918563710

Results of Operations
Enbridge System adjusted earnings were $211.5 million for the year ended December 31, 2008
compared with $202.5 million for the year ended December 31, 2007. Enbridge System adjusted
earnings increased due to increased tolls from a higher rate base as a result of Southern Access Mainline
Expansion entering service on March 31, 2008 and the AEDC recognized while the project was
under construction.

Enbridge System adjusted earnings were $202.5 million for the year ended December 31, 2007
compared with $202.3 million for the year ended December 31, 2006. The effect of increased incentive
tolling settlement (ITS) metrics bonuses and higher System Expansion Program (SEP) II utilization
were offset by increased operating costs and higher taxes in the Terrace component, resulting in
consistent earnings in 2007 and 2006.

For the years ended December 31, 2008 and 2006 adjusted earnings equaled earnings. In 2007,
Enbridge System earnings increased by $1.2 million as a result of favorable tax rate changes.

Incentive Tolling
Tolls on Enbridge System are governed by various agreements, which are subject to the approval of the
NEB. The NEB’s jurisdiction over the Enbridge System includes statutory authority over matters such as
construction, rates and ratemaking agreements and other contractual arrangements with customers.
Significant agreements include the ITS applicable to the Enbridge mainline system (excluding Line 8
and Line 9), the Terrace agreement, the SEP II Risk Sharing Agreement and the Southern Access
Expansion Agreement which is recovered via the Mainline Expansion Toll. Tolls on the core mainline
system have been governed by incentive tolling settlements since 1995, with the current ITS term being
effective through 2009.

The ITS allows the sharing of earnings in excess of a stipulated threshold and provides a fixed annual
mainline integrity allowance. In addition, performance metrics bonuses and penalties were added to the
current ITS to further align the Company’s interests with its shippers. The Company has the opportunity
to increase earnings by achieving performance targets and may incur penalties if performance falls short
of specified thresholds.

Enbridge achieved total metrics bonuses of approximately $15 million for the year ended December 31,
2008 compared with approximately $11 million and $10 million for the years ended December 31, 2007
and 2006, respectively.

ENBRIDGE INC.

ANNUAL REPORT 2008

In conjunction with the Terrace Agreement, the ITS continues the throughput protection provisions
included in earlier incentive tolling arrangements, ensuring the Company is insulated from volume
fluctuations beyond its control. The agreements govern both current and future shippers on the pipeline
and establish tolls each year based on an agreed capacity and an allowed revenue requirement. Where
actual volumes on the pipeline fall short of the agreed capacity and Enbridge is unable to fully collect its
annual revenue requirement, the deficiency is rolled into the subsequent year’s tolls for collection from
shippers at that time and a receivable, referred to as the Transportation Revenue Variance (TRV), is
recognized. This basis may affect the timing of recognition of revenues compared with that otherwise
expected under GAAP for companies that are not rate-regulated. As at December 31, 2008,
$113.6 million (2007 – $143.4 million) was recorded as tolling deferrals.

Enbridge pays taxes each year only on the tolls collected in cash; therefore, the tax payable on the TRV
lags behind the recognition of the revenue. As the Terrace capacity is increasingly utilized, there will be
less TRV recorded and more cash tolls collected. This will result in the Company paying taxes in future
years on both the prior year’s TRV and the current year’s cash tolls.

ATHABASCA SYSTEM
Athabasca System, includes two long haul pipelines, the Athabasca Pipeline and the Waupisoo Pipeline,
as well as a variety of other facilities including the MacKay River, Christina Lake, Surmont and Long Lake
facilities. It also includes the Company’s interest in the Hardisty Caverns Limited Partnership, which
provides crude oil tankage services, and two large terminals – the Athabasca Terminal located North of
Fort McMurray, Alberta and the Cheecham Terminal which is a new hub located 95 kilometres south of
Fort McMurray where the Waupisoo Pipeline initiates.

The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline, built in 1999, that
links the Athabasca oil sands in the Fort McMurray, Alberta region to a pipeline hub at Hardisty, Alberta.
The Athabasca Pipeline has an ultimate design capacity of approximately 570,000 bpd and is currently
configured to transport approximately 390,000 bpd.

The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca
Pipeline which commenced in 1999. Revenue is recorded based on the contract terms negotiated with
the major shipper, rather than the cash tolls collected. The contract provides for volumes and tolls that
will achieve an underpinning return on equity based on an assumed debt/equity ratio and level of
operating costs. The committed volumes and the tolls specified in the contract do not generate sufficient
cash revenues in the early years to compensate Enbridge for the debt and equity returns as well as the cost
of providing service; therefore, Enbridge is recording a receivable in these years. This treatment ensures
that the revenue recognized each period is in accordance with the contract. This receivable is
contractually guaranteed by the shipper and will be collected in the later years of the contract.

The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered into
service on May 31, 2008 and provides access to the Edmonton market for oil sands producers. The
Waupisoo Pipeline initiates at Enbridge’s Cheecham Terminal and terminates at its Edmonton Mainline
Terminal. The pipeline is currently configured to transport 350,000 bpd, but is ultimately rated for a
design capacity of 600,000 bpd, providing Enbridge with opportunities for economic expansion
achieved through the addition of pump stations to the line.

Enbridge has a long-term (25-year) take-or-pay commitment with the four founding shippers on the
Waupisoo Pipeline who collectively have contracted for approximately one-third of the initial capacity on
the line. The associated revenues provide for a base return on equity with significant upside potential as
incremental founder and third party volumes are added.

MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations
Earnings for the year ended December 31, 2008 were $69.1 million compared with $53.7 million for
the year ended December 31, 2007. The increase in Athabasca System earnings reflected tolls collected
on Waupisoo Pipeline since being placed into service at the end of May 2008 and the positive impact of
terminal infrastructure additions. The increase in full year earnings was partially offset by higher
operating costs.

Earnings for the year ended December 31, 2007 were $53.7 million compared with $52.8 million
for the year ended December 31, 2006. The increase was due to earnings from infrastructure
additions, partially offset by higher operating costs including increased property taxes and minor
leak remediation costs.

SPEARHEAD PIPELINE
The Spearhead Pipeline commenced delivery of crude oil from Chicago, Illinois to Cushing, Oklahoma
in March 2006. The performance of this 125,000 bpd pipeline has steadily increased and with the
support of shippers, the Spearhead Pipeline Expansion is underway to increase capacity to 193,000 bpd.

Results of Operations
Earnings increased to $12.0 million for the year ended December 31, 2008 compared with
$10.0 million for the year ended December 31, 2007 as a result of higher throughputs and higher tolls
on committed volumes.

Earnings increased to $10.0 million for the year ended December 31, 2007 compared with $6.3 million
for the year ended December 31, 2006. Spearhead Pipeline commenced operations at the beginning of
March 2006; therefore, 2007 earnings reflect a full year of operations as well as increased throughput.

OLYMPIC PIPELINE
In February 2006, Enbridge acquired a 65% interest in the Olympic Pipeline from BP Pipelines (North
America) Inc. (BP). Olympic is the largest refined products pipeline in the State of Washington,
transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. The pipeline system extends
approximately 480 kilometres (300 miles) from Blaine, Washington to Portland, Oregon, connecting
four Puget Sound refineries to terminals in Washington and Portland. BP is the operator of the pipeline.

Results of Operations
Earnings for the year ended December 31, 2008 were $7.1 million compared with $9.9 million for the
year ended December 31, 2007. Olympic Pipeline earnings reflected lower average tolls effective July 1,
2008 to compensate for over collection in 2007. Olympic’s cost of service tolling methodology requires
annual toll adjustments for over or under collection of the cost of service in prior years. 2008 earnings
also reflected an increase in pipeline integrity costs.

Earnings for the year ended December 31, 2007 were $9.9 million compared with $6.5 million for the
year ended December 31, 2006. Higher tolls as well as a full year contribution from Olympic Pipeline
resulted in the $3.4 million increase.

SOUTHERN LIGHTS PIPELINE
This pipeline received regulatory approval in Canada in the first quarter of 2008 and is currently under
construction in both the United States and Canada. Upon completion, the 180,000 bpd, 20-inch
diameter Southern Lights Pipeline will transport diluent from Chicago, Illinois to Edmonton, Alberta.

Results of Operations
The Company is entitled to collect an AEDC in tolls once the pipeline is in service. Earnings for both
2008 and 2007 reflect the AEDC recognized while the project is under construction.

ENBRIDGE INC.

ANNUAL REPORT 2008

FEEDER PIPELINES AND OTHER
Feeder Pipelines and Other primarily includes the NW System, which transports crude oil from Norman
Wells in the Northwest Territories to Zama, Alberta; interests in a number of liquids pipelines in
the United States; contract tankage facilities; and business development costs related to Liquids
Pipelines activities.

Results of Operations
Adjusted earnings in Feeder Pipelines and Other were $4.8 million for the year ended December 31,
2008 compared with $3.1 million for fiscal 2007. The increase in adjusted earnings resulted from a
decrease in business development expenditures and improved operating results on a number of
feeder systems.

Adjusted earnings for the year ended December 31, 2007 were $3.1 million compared with $6.3 million
for fiscal 2006. The decrease in earnings was primarily due to increased business development costs
related to the Company’s organic growth projects.

Earnings for the year ended December 31, 2008 were impacted by an impairment loss of $4.1 million on
Manyberries Pipeline.

STRATEGY
The Company seeks to go beyond the traditional regulated utility business model to create additional
value for customers. In addition to incentive tolling models, the Liquids Pipelines strategy focuses
proactively on understanding Western Canadian supply and downstream demand fundamentals and then
proposing timely new or reconfigured infrastructure solutions to improve customer profitability.

Future Prospects for Liquids
Historically, Western Canada has been a key source of oil supply serving U.S. energy needs. For the past
five years, Canada has surpassed both Mexico and Saudi Arabia to become the largest crude oil exporter
to the U.S. Canada’s oil sands, one of the largest oil reserves in the world, are becoming an increasingly
prominent source of supply. Combined conventional and oil sands established reserves of approximately
178 billion barrels compare with Saudi Arabia’s proved reserves of approximately 264 billion barrels.
The NEB estimates that total Western Canadian Sedimentary Basin (WCSB) production averaged
approximately 2.4 million bpd in 2008 and 2007. Development of the Alberta Oil Sands is expected to
moderate due to declining demand and commodity prices and it is unlikely that all announced and
planned oil sands projects will proceed as planned. The Canadian Association of Petroleum Producers’
(CAPP) December 2008 estimates indicate that future production for the Alberta Oil Sands is expected
to steadily increase to more than 1.8 million bpd by 2018 based on a subset of currently approved
applications and announced expansions. The Company is actively working with customers to ensure that
Enbridge mainline system will allow Canadian crude oil greater access to markets in the United States.

Crude oil price volatility in 2008 has caused some crude oil producers to cancel or defer projects that
were planned to commence over the next decade. Cancellations and project deferrals are expected to
temper the rate of growth over the next several years relative to prior forecasts. If the rate of crude oil
production from the WCSB declines, immediate need for new pipeline infrastructure will likely decline.
In addition to Enbridge’s expansions, a significant competitor is expected to complete construction of a
pipeline system to Wood River, Illinois. This competing pipeline, together with the Southern Access and
Alberta Clipper expansions, may provide sufficient capacity for the near term. In this case, expansion
activities will be more modest than experienced over the last several years. Although a number of oil
sands projects have announced delays, the supply from the oil sands is forecasted to grow at a steady pace.

Key Components of the Liquids Pipelines Strategy
The Liquids Pipelines strategy is driven by shippers’ need for adequate export capacity, market
alternatives and economic sources of diluent, and U.S. refiners’ need to maintain diversified sources of

MANAGEMENT’S DISCUSSION AND ANALYSIS

supply. The five key components of the Liquids Pipelines strategy are discussed below as well as progress
made to date and future plans towards further advancing the strategy.

1. Mainline Capacity Development
The Chicago refining market is expected to remain a major export destination for Western Canadian
crude. The Company is working with shippers and refiners to further expand this market and markets
beyond, both in Canada and the United States, through the Southern Access Mainline Expansion and
the Alberta Clipper Project. The Line 4 Extension Project is a third, smaller debottlenecking project that
has been undertaken to expand capacity.

Southern Access Mainline Expansion Project
The Southern Access Mainline Expansion Project will ultimately add a total of 400,000 bpd incremental
capacity to the mainline system. In Canada, upgrades at 18 pump stations to improve pumping
effectiveness are substantially complete. The Company started collecting associated tolls in April 2008.

In the United States, the new 42-inch diameter pipeline from Superior to Delavan, Wisconsin was placed
into commercial service and was ready to receive linefill at the end of the first quarter of 2008. In the
fourth quarter of 2008 the system began receiving crude, as it was made available by shippers, and is
scheduled to be completely filled by the end of the first quarter of 2009. The first stage of the expansion
adds capacity of approximately 190,000 bpd to the pipeline and system-wide toll surcharges were
effective April 1, 2008 for the facilities that have been put into service. Construction of the second stage
of the expansion project from Delavan, Wisconsin to Flanagan, Illinois, started in June 2008 and is on
schedule for completion in the first quarter of 2009.

The expected cost of the project, which is fully recoverable in tolls, has decreased to an estimated
US$2.3 billion (Enbridge – $0.2 billion, EEP – US$2.1 billion). The estimated capital cost for the
Canadian portion was revised from $0.3 billion to $0.2 billion based on refinements to the scope of the
project, agreed to with CAPP, to reflect the subsequent approval of the Alberta Clipper Project.
Expenditures to date on the Southern Access Mainline Expansion are US$1.9 billion and $0.2 billion on
the U.S. and Canadian portions, respectively.

Alberta Clipper Project
The Alberta Clipper Project involves the construction of a new 36-inch diameter pipeline from Hardisty,
Alberta to Superior, Wisconsin generally within or alongside Enbridge’s existing right-of-way. The
Alberta Clipper Project will interconnect with the existing mainline system in Superior where it will
provide access to Enbridge’s full range of delivery points and storage options, including Chicago,
Toledo, Sarnia, Patoka, Wood River and Cushing. The project will have an initial capacity of
450,000 bpd, is expandable to 800,000 bpd and will form part of the existing Enbridge System in
Canada and the EEP Lakehead System in the United States.

In the first quarter of 2008, Enbridge received NEB approval to construct this 1,607-kilometre
(1,000-mile) 36-inch diameter crude oil pipeline. Construction on the Canadian segment of the line
commenced in August 2008, with an expected in-service date of mid-2010 and an expected cost of
$2.4 billion, including escalation of the original ‘‘constant 2007 dollar’’ cost estimate to current ‘‘as
spent’’ dollars, and allowance for funds used during construction (AFUDC). The U.S. segment, to be
undertaken by EEP, is awaiting regulatory approval, with construction expected to begin in mid-2009.
Subject to regulatory approval, the U.S. segment of the Alberta Clipper project is also expected to be in
service in mid-2010. The cost of the U.S. segment is estimated at US$1.2 billion. Enbridge will share in
cost overruns or savings against estimates, for costs deemed to be controllable costs. Controllable costs
comprise approximately 70% of the total cost estimate.

ENBRIDGE INC.

ANNUAL REPORT 2008

Line 4 Extension Project
In April 2008 the NEB approved Enbridge’s regulatory application for the construction and operation
of the $0.3 billion Line 4 Extension project. Subsequent NEB route approval was received in July 2008.
Construction commenced in August 2008, with the Line 4 Extension expected to be in service in
early 2009.

2. Regional Oil Sands Development
Enbridge continues to be well positioned to capture significant growth from development of the
regional infrastructure required to transport oil sands production to local markets or into major export
pipelines. Successful execution of this strategy during 2007 and 2008 has further reinforced Enbridge’s
dominant position in the oil sands and provides increased leverage for future growth. Optimizing the
Athabasca, Waupisoo and Fort Hills Pipelines will form the foundation of development efforts for the
next wave of oil sands growth.

Fort Hills Pipeline System
In November 2007, Enbridge was selected by the Fort Hills Energy L.P. (FHELP) as their pipeline and
terminaling services provider for both the initial phase of the Fort Hills project and all subsequent
expansions. The scope of the Fort Hills Pipeline System is being re-evaluated by FHELP to reflect
changing market conditions. The planned in-service date for the initial facilities has been deferred from
mid-2011 to no earlier than 2012, subject to sanctioning of the overall project by FHELP.

3. Feeder System Expansions
Expanding the reach and capacity of the feeder pipeline systems will continue to be a priority. A particular
focus will be the development of opportunities to expand gathering and feeder systems in Saskatchewan
and North Dakota which are being driven by growing production from the Bakken play in the Williston
Basin. The Company is advancing this component of its strategy through both the North Dakota System
Expansion at EEP and the Saskatchewan System Capacity Expansion discussed in the Sponsored
Investments section.

4. New Market Access
Enbridge’s successful initiative to provide access for Canadian crude oil to the Cushing market through
the acquisition and reversal of the Spearhead Pipeline has provided validation of the value to industry of
market optionality. In addition to the planned construction of the Southern Access Extension which is
expected to provide access to the Patoka market, Enbridge will continue to pursue new opportunities to
provide broader market access for Canadian bitumen and synthetic crudes. Key opportunities being
pursued include: Eastern PADD II access into the Michigan and Ohio markets; access to U.S. Gulf Coast
refining centers through a combination of smaller incremental opportunities and large volume solutions;
PADD I access into the East Coast market near Philadelphia; and the Northern Gateway pipeline to the
Pacific Coast.

2,001

1,872

2,013

2,005

2,030
28FEB200902510752

MANAGEMENT’S DISCUSSION AND ANALYSIS

Enbridge System Deliveries
Deliveries on the Enbridge System include Canadian
mainline deliveries in Western Canada and to the

(thousands of barrels per day)

Lakehead System at the U.S. border as well as Line 8 and

Line 9 in Eastern Canada.

Southern Access Extension Project
The Southern Access Extension Project involves the construction of a new crude oil pipeline extending
the mainline from Flanagan to Patoka, Illinois. Project timing is being re-evaluated given changing
customer product export preferences and as a result of delays in the regulatory process and the May 2008
denial by the Federal Energy Regulatory Commission (FERC) of the Company’s October 2007 filing
seeking a declaratory order (i.e. advance approval) of the tariff rate structure for the pipeline. Enbridge
remains committed to meeting the shippers’ need for transportation of crude oil from the Chicago area
to the Patoka, Illinois hub and is working with customers to reposition the project in a manner that is
commercially appropriate for the market and includes a tolling structure acceptable to the FERC.

Spearhead Pipeline Expansion
Construction on the Spearhead Pipeline Expansion began in September 2008. This expansion, to be
effected through additional pumping stations, will increase system capacity from Flanagan, Illinois to
Cushing, Oklahoma by 68,300 bpd to 193,300 bpd. The expansion is expected to cost US $0.1 billion
and to be completed in the first half of 2009.

U.S. Gulf Coast Access
Based on feedback from shippers, Enbridge’s focus will be on smaller scale alternatives involving low cost
reconfiguration of existing facilities to accommodate U.S. Gulf Coast market access at volumes which are
more closely aligned with supply growth.

United States Gulf Coast Joint Initiative The Company and BP are currently developing an initiative to
deliver incremental volumes of Canadian heavy crude oil to U.S. Gulf Coast markets. The initiative
would involve the reversal of the BP #1 pipeline system between Flanagan, Illinois and Cushing,
Oklahoma as well as the use of existing pipelines and rights-of-way between Cushing and Houston,
Texas. The scope of the project provides for a pipeline system with over 150,000 bpd of new capacity
between Flanagan and Cushing and approximately 250,000 bpd of capacity between Cushing and
Houston. BP is expected to be a significant shipper on the new system. The partners are currently
finalizing commercial terms to present to additional shippers who have indicated interest in this
alternative. The target in-service date for the pipeline system is late 2012.

Trailbreaker Project The Company initiated plans to provide access for western Canadian crude oil to
refineries along the U.S. eastern seaboard and the U.S. Gulf Coast via the marine terminal at Portland,
Maine. The Trailbreaker project contemplates the expansion and reversal of existing facilities to create a
pipeline route to Portland. An open season process held by third-party owned Portland-Montreal Pipe
Line did not receive sufficient commercial support for the reversal of one of its pipelines to transport
crude oil from Montreal, Quebec to Portland. As a result, CAPP has exercised its right to withdraw
support from the project at this time. Enbridge continues to engage in discussions with customers to
determine timing and conditions for proceeding with this project.

Texas Access Pipeline The Company will continue to work with Exxon Mobil to develop the
450,000 bpd Texas Access Pipeline to provide the lowest cost large scale transportation solution to meet
shippers’ post-2012 requirements to providing U.S. Gulf Coast access for the volumes and on the
schedule required by shippers.

Northern Gateway Project
The Northern Gateway Project involves constructing a twin pipeline system running from near
Edmonton, Alberta, to a new marine terminal in Kitimat, British Columbia. One pipeline will transport
crude oil for export from the Edmonton area to Kitimat, and is expected to be a 36-inch diameter line
with an initial capacity of 525,000 bpd. The other pipeline will be used to import condensate and is
expected to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

The Company has secured funding from third party oil sands producers and Pacific Rim refiners to seek
regulatory approval of the project.

ENBRIDGE INC.

ANNUAL REPORT 2008

The Company has requested the NEB and the Canadian Environmental Assessment Agency (CEAA) to
resume their activities in respect of the environmental assessment process for the proposed project.
CEAA will carry out consultations with potentially affected Aboriginal groups. The project is
undergoing its own comprehensive public consultation program, which includes a series of community
open houses designed to gather input, answer questions and build public awareness and understanding
about the project.

The Company is committed to working with First Nations and M´etis communities along the pipeline
route to create opportunities for economic partnerships and to incorporate traditional knowledge into
the planning and operations of the proposed project. See Aboriginal Relations.

Enbridge expects to file its regulatory application with the NEB in 2009. Subject to continued
commercial support, regulatory and other approvals, the Company estimates that Northern Gateway
could be in-service in the 2014 to 2015 time frame. The NEB posts public filings related to Northern
Gateway on its website and Enbridge also maintains a Northern Gateway Project page on its own
website. None of the information contained on, or connected to, either the NEB website or Enbridge’s
website is incorporated or otherwise part of this MD&A and we disclaim any intent to incorporate any of
such information, either expressly or by reference.

5. Diluent Supply and Refined Products
With the Southern Lights diluent pipeline project on schedule for completion in 2010, the Company’s
strategy has shifted to expanding the number of physical connections to the pipeline to increase available
supply in the U.S. and available market outlets in Alberta. Selective development of refined products
infrastructure will also be pursued.

Southern Lights Pipeline
When completed, the 180,000 bpd Southern Lights pipeline will transport diluent from Chicago,
Illinois to Edmonton, Alberta. The project involves reversing the flow of a portion of Enbridge’s Line
13, an existing crude oil pipeline which runs from Edmonton to Clearbrook, Minnesota. In order to
replace the light crude capacity that would be lost through the reversal of Line 13, the Southern Lights
Project also includes the construction of a new 20-inch diameter light sour crude oil pipeline
(LSr Pipeline) from Cromer, Manitoba to Clearbrook, and modifications to existing Line 2. These
changes to the existing crude oil system will ultimately increase southbound light crude system capacity
by approximately 45,000 bpd.

The Canadian portion of the Southern Lights Pipeline received NEB approval in the first quarter of
2008, enabling construction to commence on the LSr Pipeline and Line 2 modifications. Line
2 modifications, which allow Line 2 to operate at higher design rates, were nearing completion at the end
of 2008. Due to a delay in NEB routing approvals, the planned in-service date for the LSr Pipeline has
been delayed to early 2009.

In the U.S., construction of the LSr Pipeline and Line 2 modifications are complete. Diluent pipeline
construction between Superior and Delavan, Wisconsin was completed in early 2008. Construction of
the second segment of the diluent pipeline between Delavan, Wisconsin and Streator, Illinois was also
substantially completed in 2008. Construction of the remaining U.S. line segments will commence in
2009. The diluent line is expected to be in service in late 2010.

The total expected project cost remains unchanged at US$1.7 billion (including AFUDC) for the
U.S. segment and $0.5 billion (including AFUDC) for the Canadian segment.

6. Terminaling and Storage Infrastructure
In addition to regulated storage facilities, Enbridge owns and operates contracted storage adjacent to its
pipeline systems. The Hardisty Terminal project will add an additional 7.5 million barrels of contract
capacity. Liquids Pipelines continues to advance downstream terminaling projects at Flanagan, Patoka,
Cushing and the U.S. Gulf Coast. Regulated storage initiatives will also be pursued at Edmonton,
Superior, Griffith and Cromer.

MANAGEMENT’S DISCUSSION AND ANALYSIS

Hardisty Terminal
Enbridge is building a crude oil terminal at Hardisty with a tankage capacity of 7.5 million barrels.
Overall project construction was approximately 71% complete at the end of 2008. Tank capacities are
expected to enter service in phases throughout 2009. Once complete, the $0.6 billion Hardisty Terminal
will be one of the largest crude oil terminals in North America.

Stonefell Terminal – BA Energy
BA Energy Inc. proposed building a bitumen upgrader near Fort Saskatchewan, Alberta for which
Enbridge had agreed to provide pipeline and terminaling services. In the second quarter of 2008,
Enbridge was directed by BA Energy to stop work on this project and place the newly constructed tanks
into standby. The Enbridge contractors have been demobilized and the project assets are in a storage
mode. Project continuance and schedule are uncertain given BA Energy’s filing for creditor protection.
Enbridge’s costs incurred to date, including a return on investment, have been fully reimbursed by
BA Energy.

CAPITAL EXPENDITURES
In 2008, the Liquids Pipelines segment spent $164 million on capital maintenance and improvements
compared with an expected $150 million. In 2009, the Company expects to spend approximately
$160 million on capital maintenance and improvements.

Total expenditures for organic growth projects described above were $2.7 billion for 2008 compared
with an expected $2.8 billion. For 2009, the Company expects to spend $2.9 billion for the organic
growth projects. Discussion of the Company’s access to financing is included under Liquidity and
Capital Resources.

BUSINESS RISKS
The risks identified below are specific to the Liquids Pipelines business. General risks that affect the
Company as a whole are described under Risk Management.

Supply and Demand
The operation of the Company’s liquids pipelines depends on the supply of, and demand for, crude oil
and other liquid hydrocarbons from Western Canada. Supply, in turn, depends on a number of variables,
including the price of crude oil and bitumen, the availability and cost of capital and labour for oil sands
projects and the price of natural gas used for steam production.

Demand depends, among other things, on weather, gasoline price and consumption, manufacturing,
alternative energy sources and global supply disruptions.

Competition
Competition among pipelines is based primarily on the cost of transportation, access to supply, the
quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing
carriers are available to producers to ship western Canadian liquids hydrocarbons to markets in either
Canada or the United States. Competition could also arise from pipeline proposals that may provide
access to market areas currently served by the Company’s liquids pipelines. One such competing project
is currently under construction to initially serve markets at Wood River, Illinois and Cushing, Oklahoma,
commencing in late 2009. This pipeline will have an initial capacity of 435,000 bpd and an ultimate
capacity of 590,000 bpd. Commercial support has also been announced to construct additional
ex-Alberta capacity of 500,000 bpd for an in-service date during 2012, which would be complemented
by an extension of the system from Cushing, Oklahoma to Nederland, Texas. The Company believes that
its liquids pipelines are serving larger markets and provide attractive options to producers in the WCSB
due to their competitive tolls and multiple delivery and storage points.

Also, shippers are not required to enter into long-term shipping commitments on Enbridge’s mainline
system. The Company’s existing right-of-way provides a competitive advantage as it can be difficult and
costly to obtain new rights of way for new pipelines. The ITS and the Terrace Agreement on the

ENBRIDGE INC.

ANNUAL REPORT 2008

Enbridge System provide throughput protection which insulates the Company from negative volume
fluctuations beyond its control. The Lakehead System, owned by EEP, has no similar throughput
protection on its existing system but will on the Southern Access and Alberta Clipper expansions.

Increased competition could arise from new feeder systems servicing the same geographic regions as the
Company’s feeder pipelines.

Alberta Royalty Review
In September 2007, the Alberta Royalty Review Panel issued its recommendations to the government of
the Province of Alberta calling for the adoption of measures to increase the Alberta government’s share
of revenues from oil sands development. A majority of the recommendations of the report were
subsequently adopted by the Alberta government and became effective January 1, 2009. These measures
may impact how oil sands developers evaluate future projects and this may reduce the level of future
volumes expected to flow through the mainline system.

ITS Metrics
The ITS governing the Enbridge System measures the Company’s performance in areas key to customer
service. If the Company fails to meet the baseline targets set out in the ITS for all service and reliability
metrics, the Company could be required to pay penalties to shippers up to a maximum of $30 million
in 2009.

Potential Pressure Restrictions
The Company’s Liquids Pipelines systems consist of individual pipelines of varying ages. With
appropriate inspection and maintenance, the physical life of the pipeline is indefinitely long; however, as
the pipelines age the level of expenditures required for inspection and maintenance may increase.
Temporary pressure restrictions have been established on some sections of certain pipelines pending
completion of specific inspection and repair programs. Pressure restrictions may from time to time be
established on other of the Company’s pipelines. Pressure restrictions reduce the available capacity of the
applicable line segment and could result in a loss of throughput if and when the full capacity of that line
segment would otherwise have been utilized. Pressure restrictions to date have not given rise to any loss
of throughput. While the Enbridge System is volume-protected, EEP’s Lakehead System and certain
other pipelines would be adversely affected by pressure restrictions that reduce volumes transported.
Additionally, on the Enbridge System ITS metrics penalties may apply if available capacity is reduced
below baseline targets.

Regulation
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
those operations. The NEB prescribes a benchmark multi-pipeline rate of return on common equity,
which is 8.57% in 2009 (2008 – 8.71%). To the extent the NEB rate of return fluctuates, a portion of the
Enbridge System and other liquids pipelines earnings will change. The Company believes that regulatory
risk is reduced through the negotiation of long-term agreements with shippers, such as the ITS, Terrace
Agreement and agreements for projects currently under construction, which will govern the majority of
the segment’s assets.

MANAGEMENT’S DISCUSSION AND ANALYSIS

GAS PIPELINES

Gas Pipelines activities consist of investments in Alliance Pipeline US, Vector Pipeline and Enbridge
Offshore Pipelines. Enbridge has joint control over these investments with one or more other owners.
Enbridge owns a 50% interest in Alliance Pipeline US, a 60% interest in Vector Pipeline and interests
ranging from 22% to 100% in the pipelines comprising Offshore.

EARNINGS

(millions of Canadian dollars)

Alliance Pipeline US

Vector Pipeline

Enbridge Offshore Pipelines

Adjusted Earnings

Alliance Pipeline US – shipper claim settlement

Offshore – property insurance recovery from 2005 hurricanes,

net of repair costs

Earnings

2008

24.9

14.2

6.6

45.7

2.8

–

48.5

2007

27.7

14.9

21.8

64.4

–

5.3

69.7

2006

29.7

13.4

18.1

61.2

–

61.2

Adjusted earnings from Gas Pipelines were $45.7 million for the year ended December 31, 2008
compared with $64.4 million for the year ended December 31, 2007. The decrease in adjusted earnings
was substantially due to continuing natural production declines and lost revenue and clean up costs
related to Hurricanes Gustav and Ike in Offshore.

Adjusted earnings from Gas Pipelines were $64.4 million for the year ended December 31, 2007
compared with $61.2 million for the year ended December 31, 2006. Adjusted earnings improved as
construction of the Neptune Pipelines (within Offshore) was completed and stand-by fees were earned
starting in the fourth quarter of 2007.

Gas Pipelines earnings were impacted by the following non-operating adjusting items:

(cid:127)

In the first quarter of 2008, Alliance Pipeline US received $2.8 million in proceeds from the
settlement of a claim against a former shipper which repudiated its capacity commitment.
Earnings for the year ended December, 2007 included insurance proceeds of $5.3 million related to
the replacement of damaged infrastructure as a result of the 2005 hurricanes.

Revenues for the year ended December 31, 2008 were $359.3 million compared with $321.3 for the
year ended December 31, 2007. The increase in revenues is due to higher Alliance Pipeline US tolls,
Vector expansion and revenues from Neptune within Offshore.

Revenues for the year ended December 31, 2007 were $321.3 million compared with $345.9 million for
the year ended December 31, 2006. The decrease in revenues was substantially due to the effect of the
weaker U.S. dollar.

Gas Pipelines
(millions of Canadian dollars)

Adjusted Earnings

Earnings
(millions of Canadian dollars)

53.8

59.8

61.2

64.4

45.7

2MAR200907310787

53.8

59.8

61.2

69.7

48.5
3MAR200920570185

ENBRIDGE INC.

ANNUAL REPORT 2008

(1,875-mile)

ALLIANCE PIPELINE US
The Alliance System (Alliance), which includes
both the Canadian and U.S. portions of the
pipeline system, consists of an approximately
3,000-kilometre
integrated,
high-pressure natural gas transmission pipeline
system and an approximately 730-kilometre
(455-mile) lateral pipeline system and related
infrastructure. Alliance transports liquids-rich
natural gas from northeast British Columbia and
northwest Alberta to Channahon, Illinois. The
pipeline has firm service shipping contract
capacity to deliver 1.325 billion cubic feet per
day (bcf/d). EIF, described under Sponsored
Investments, owns 50% of the Canadian portion
of the Alliance System.

Gas Pipelines

3MAR200902102512

Alliance connects with Aux Sable, a natural gas liquids extraction facility in Channahon, Illinois. The
natural gas may then be transported to two local natural gas distribution systems in the Chicago area and
five interstate natural gas pipelines, providing shippers with access to natural gas markets in the
midwestern and northeastern United States and eastern Canada. Enbridge owns 42.7% of Aux Sable and
its results are included under Gas Distribution and Services.

Results of Operations
Alliance Pipeline US adjusted earnings were $24.9 million for the year ended December 31, 2008
compared with $27.7 million for the year ended December 31, 2007. The decrease was primarily due to
the weaker average U.S. dollar during 2008 and the depreciating ratebase.

The $2.0 million decrease in adjusted earnings between the years ended December 31, 2007 and 2006
was also primarily due to the weaker average U.S. dollar.

In the first quarter of 2008, Alliance Pipeline US received $2.8 million in proceeds from the settlement
of a claim against a former shipper which repudiated its capacity commitment, resulting in increased
earnings for the year ended December 31, 2008. Earnings for the years ended December 31, 2007 and
2006 equaled adjusted earnings.

Transportation Contracts
Alliance has long-term, take-or-pay contracts through 2015 to transport 1.305 bcf/d of natural gas or
98.5% of the total contracted capacity. Alliance has an additional 20 million cubic feet per day (mmcf/d)
of natural gas contracted through 2010. These contracts permit Alliance to recover the cost of service,
which includes operating and maintenance costs, the cost of financing, an allowance for income tax, an
annual allowance for depreciation and an allowed return on equity. Each long-term contract may be
renewed upon five years notice for successive one-year terms beyond the original 15-year primary term.
Alliance Pipeline US operations are regulated by the FERC.

Depreciation expense included in the cost of service is based on negotiated depreciation rates contained in
the transportation contracts, while depreciation expense in the financial statements is recorded on
a straight-line basis at 4% per annum. Negotiated depreciation expense is generally less than the financial
statement amount at the beginning of the contract and higher than straight-line depreciation in the
later years of the shipper transportation agreements. This difference results in recognition of a long-term
receivable, referred to as deferred transportation revenue that is expected to be recovered from shippers in
subsequent years, beginning in 2009 for Alliance Pipeline US and 2012 for Alliance Pipeline Canada. As at
December 31, 2008, $182.3 million (US$148.9 million) (2007 – $143.7 million; US$145.4 million) was
recorded as deferred transportation revenue.

MANAGEMENT’S DISCUSSION AND ANALYSIS

VECTOR PIPELINE
The Company provides operating services to, and holds a 60% joint venture interest in, Vector Pipeline,
which transports natural gas from Chicago to Dawn, Ontario. Vector Pipeline has the capacity to deliver
a nominal 1.2 bcf/d and is operating at or near capacity.

Vector Pipeline’s primary sources of supply are through interconnections with the Alliance System and
the Northern Border Pipeline in Joliet, Illinois. Approximately 58% of the long haul capacity of Vector
Pipeline is committed to long-term, 15-year firm transportation contracts at rates negotiated with the
shippers and approved by the FERC. The remaining capacity is sold at market rates and at various term
lengths. Transportation service is provided through a number of different forms of service agreements
such as Firm Transportation Service and Interruptible Transportation Service.

Results of Operations
Vector Pipeline earnings were $14.2 million for the year ended December 31, 2008 compared with
$14.9 million for the year ended December 31, 2007. Earnings decreased as a result of increased taxes
and by the weaker average U.S. dollar in 2008.

Vector Pipeline earnings were $14.9 million for the year ended December 31, 2007 compared with
$13.4 million for the year ended December 31, 2006. Earnings improved, despite the stronger Canadian
dollar, due to its late year expansion and lower operating costs in 2007.

STRATEGY
The Gas Pipelines strategy is developed based on the Company’s forecast supply and demand for
natural gas.

Supply and Demand for Natural Gas
The Chicago market is anticipated to enjoy robust supply as a result of increasing conventional
production in the Rocky Mountains; expanding unconventional mid-continent production; and new
supply from Gulf Coast liquefied natural gas (LNG) facilities. Surplus gas in Chicago may result in
greater deliveries from this region to the Ontario market as traditional exports from Western Canada are
expected to decline.

Further development of the oil sands projects in Alberta will increase the demand for natural gas as
various extraction and upgrading processes require the use of natural gas. However, growth in natural
gas demand in this sector may be tempered by alternative energy sources and delay or cancellation of oil
sands projects.

Over time, the introduction of new supply from shale plays in northeast British Columbia and the
U.S. Midcon region; increasing supply from the U.S. Rockies; LNG; and potential supply from the
Alaska North Slope/Mackenzie Delta are expected to adequately supply the market and may provide
opportunities for Enbridge to deliver this natural gas to markets.

Alliance Pipeline Recontracting Strategy
The Alliance Pipeline continues to be fully contracted on a firm service basis and is expected to run at or
near full capacity until at least 2015 when existing long-term shipper contracts expire. Alliance Pipeline
US is developing strategies to maximize its competitiveness, post-2015, in light of falling export
production from Western Canada and the potential for surplus export pipeline capacity. Alliance is well
placed to benefit from incremental unconventional volumes from shale plays in British Columbia and the
northern gas development.

Rockies Alliance Pipeline
Alliance Pipeline US and Questar Overthrust Pipeline Company are jointly proposing a natural gas
pipeline connecting the U.S. Rocky Mountain Region to the Chicago market hub. The proposed
Rockies Alliance Pipeline (RAP) project is being developed in response to rapidly increasing supply from
the U.S. Rockies region. RAP will enable producers, marketers and end-users to connect new gas
supplies in the Greater Green River, Piceance, Uinta and Powder River basins with one of the largest and

ENBRIDGE INC.

ANNUAL REPORT 2008

fastest growing markets in North America. The RAP project will take advantage of existing infrastructure
with both Questar and Alliance to provide competitive transportation to key market areas.

Upon in-service of the proposed project, RAP will initially provide 1.3 bcf/d of transportation capacity
which is expandable to 1.7 bcf/d with the addition of compression. Provided that sufficient commercial
support for the project is obtained in 2009, the pipeline is expected to be in-service in 2013.

Vector Pipeline Expansion
The Vector pipeline is undertaking a 0.1 bcf/d expansion in 2009 with potential further expansion
in 2010-2011.

BUSINESS RISKS
The risks identified below are specific to Alliance Pipeline US and Vector Pipeline. General risks that
affect the entire Company are described under Risk Management.

Supply and Demand
Advances in clean-coal technology and nuclear power as sources of power generation may reduce growth
in natural gas demand over the longer term. However, demand is supported by declining U.S. traditional
energy production, increasing need for clean burning natural gas and rising use of gas for power
generation. Currently, pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline US and
Vector Pipeline have been unaffected by this excess capacity environment mainly because of long-term
capacity contracts extending to 2015. Vector Pipeline’s interruptible capacity could be negatively
impacted by the basis (location) differential in the price of natural gas between Chicago and Dawn,
Ontario relative to the transportation toll.

Exposure to Shippers
The failure of shippers to perform their contractual obligations could have an adverse effect on the cash
flows and financial condition of Alliance Pipeline US and Vector Pipeline. To reduce this risk, Alliance
Pipeline US and Vector Pipeline monitor the creditworthiness of each shipper and receive collateral for
future shipping tolls should a shipper’s credit position not meet tariff requirements. These pipelines also
have diverse groups of long-term transportation shippers, which include various gas and energy
distribution companies, producers and marketing companies, further reducing the exposure.

Competition
Alliance Pipeline US faces competition for pipeline transportation services to the Chicago area from both
existing and proposed pipeline projects. Competing pipelines provide natural gas transportation services
from the WCSB to distribution systems in the Midwestern United States. In addition, there are several
proposals to upgrade existing pipelines serving these markets. Any new or upgraded pipelines could
either allow shippers greater access to natural gas markets or offer natural gas transportation services that
are more desirable than those provided by the Alliance System. Shippers on Alliance Pipeline US have
access to additional high compression delivery capacity at no additional cost, other than fuel
requirements, serving to enhance Alliance Pipeline US’ competitive position.

Vector Pipeline faces competition for pipeline transportation services to its delivery points from new or
upgraded pipelines, which could offer transportation that is more desirable to shippers because of cost,
supply location, facilities or other factors. Vector Pipeline has mitigated this risk by entering into
long-term firm transportation contracts for approximately 58% of its capacity and medium-term
contracts for the remaining capacity. These long-term firm contracts provide for additional
compensation to Vector Pipeline if shippers do not extend their contracts beyond the initial term. The
effectiveness of these mitigating factors is evidenced by the increased utilization of the pipeline since its
construction, despite the presence of transportation alternatives.

Regulation
Both Vector Pipeline and Alliance Pipeline US operations are regulated by the FERC. On a yearly basis,
following consultation with shippers, Alliance Pipeline US files its annual rates with the FERC
for approval.

MANAGEMENT’S DISCUSSION AND ANALYSIS

FERC has intensified its oversight of financial reporting, risk standards and affiliate rules and has issued
new standards on managing pipeline integrity. The Company continues ongoing dialogue with
regulatory agencies and participates in industry lobby groups to ensure it is informed of emerging issues
in a timely manner.

Alberta Royalty Review
The Alberta Royalty Review as described under Liquids Pipelines is also applicable to both Vector
Pipeline and Alliance Pipeline US.

ENBRIDGE OFFSHORE PIPELINES
Enbridge Offshore Pipelines is comprised of 11 natural gas gathering and FERC-regulated transmission
pipelines in five major corridors in the Gulf of Mexico, extending to deepwater frontiers. These pipelines
include almost 1,500 miles (2,400 kilometres) of underwater pipe and onshore facilities and transported
approximately 1.7 bcf/d during 2008.

Results of Operations
Adjusted earnings for the year ended December 31, 2008 in Offshore were $6.6 million compared with
$21.8 million for the year ended December 31, 2007. Offshore adjusted earnings decreased as a result of
continuing natural production declines as well as approximately $11.0 million in lost revenue and clean
up costs related to Hurricanes Gustav and Ike. These decreases were partially offset by stand-by fees on
the Neptune oil and gas pipelines which came into service in the fourth quarter of 2007, as well as
contributions from Atlantis and Thunderhorse platform volumes. Also, adjusted earnings for the year
ended December 31, 2008 included approximately $2.0 million (2007 – $6.0 million) from business
interruption insurance proceeds related to lost revenue in 2005 and 2006 as a result of the
2005 hurricanes.

Offshore adjusted earnings for the year ended December 31, 2007 were $21.8 million compared with
$18.1 million for the year ended December 31, 2006. In 2007, earnings reflected the impact of a weaker
U.S. dollar, continuing repair and inspection costs and expected continuing natural production declines
on deliveries to the pipelines in 2007. Start up issues experienced by producers on key production
platforms, resulting from the effects of the extreme 2005 hurricane season, delayed new sources of
volumes during the year; however, volumes from the Atlantis platform started contributing to earnings
at the end of 2007. Adjusted earnings for the year ended December 31, 2007 also included
approximately $6.0 million from business interruption insurance proceeds related to lost revenue in
2005 and 2006 as a result of the 2005 hurricanes which was offset by approximately $0.7 million in
repair costs.

Earnings for the year ended December 31,2007 included non-operating insurance proceeds of
$5.3 million related to the replacement of damaged infrastructure as a result of the 2005 hurricanes.

Transportation Contracts
The primary shippers on the Offshore systems are producers who execute life-of-lease commitments in
connection with transmission and gathering service contracts. In exchange, Offshore provides firm
capacity for the contract term at an agreed upon rate. The throughput volume generally reflects the
lease’s maximum sustainable production. The transportation contracts allow the shippers to define a
maximum daily quantity (MDQ), which corresponds with the expected production life. The contracts
typically have minimum throughput volumes which are subject to take-or-pay criteria but also provide
the shippers with flexibility given advance notice criteria to modify the projected MDQ schedule to
match current deliverability expectations.

Increasingly, and reflecting recent setbacks from hurricanes, certain transportation contracts are
beginning to reflect hurricane allowances to cover increased operating and repair costs.

The long-term transport rates established in the gathering and transmission service agreements are
generally market-based but are established using a cost of service methodology, which includes operating
cost, projected revenue generation directly tied to production deliverability and the appropriate cost
of capital.

ENBRIDGE INC.

ANNUAL REPORT 2008

Strategy
While Offshore’s longer-term growth potential is attractive, the magnitude and timing of this growth
will very much depend on the ability and willingness of upstream producers to develop new plays.
Offshore will utilize its inherent advantages (existing infrastructure, operational expertise, reputation
and integrity of personnel) to compete for new pipeline development opportunities. Projects under
construction are described below.

Shenzi Project
Enbridge has completed constructing a natural gas lateral to connect the new deepwater Shenzi field to
existing Gulf of Mexico pipelines. The US$65.0 million 11-mile (18-kilometre), 12-inch diameter gas
pipeline has capacity of 0.1 bcf/d. In-service is currently scheduled for the second quarter of 2009,
concurrent with producer first volumes. The Shenzi lateral will deliver natural gas through the
Company’s 22%-owned Cleopatra Pipeline, the 50%-owned Manta Ray Pipeline and the 50%-owned
Nautilus Pipeline.

Thunder Horse Production Project
During the second quarter of 2008, the first well in the Thunder Horse Project was put in service ahead
of the producer’s revised schedule, with production continuing to ramp-up as new wells are brought on
to production. This significant third party-owned project, which will deliver natural gas into Offshore’s
gathering systems, has experienced startup issues due to the severe 2005 hurricanes which delayed its
original in-service schedule.

Business Risks
The risks identified below are specific to Enbridge Offshore Pipelines. General risks that affect the
Company as a whole are described under Risk Management.

Weather
Adverse weather, such as hurricanes, may impact Offshore financial performance directly or indirectly.
Direct impacts may include damage to Offshore facilities resulting in lower throughput and inspection
and repair costs. Indirect impacts include damage to third party production platforms, onshore
processing plants and refineries that may decrease throughput on Offshore systems.

The Company continues to maintain an active risk management program that includes comprehensive
insurance coverage. However, costs have increased in the form of higher insurance premiums and
deductibles as well as longer waiting periods for business interruption claims. It is expected the incidence
and severity of windstorm occurrences, and the Company’s direct experience in the Gulf of Mexico, will
dictate future costs and coverage levels in this region.

Competition
There is competition for new and existing business in the Gulf of Mexico. Offshore has been able to
capture key opportunities, positioning it to more fully utilize existing capacity. Offshore serves a majority
of the strategically located deepwater host platforms and its extensive presence in the deepwater Gulf of
Mexico has Offshore well positioned to generate incremental revenues, with modest capital investment,
by transporting production from sub-sea development of smaller fields tied back to existing host
platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying the risk of
declining production, as demonstrated with the newly constructed Neptune crude oil lateral. Given rates
of decline, Offshore Pipelines typically have available capacity resulting in significant and aggressive
competition for new developments in the Gulf of Mexico.

Regulation
The transportation rates on many of Offshore’s transmission pipelines are generally based on a regulated
cost of service methodology and are subject to regulation by the FERC. These rates may be subject
to challenge.

Other Risks
Other risks directly impacting financial performance include underperformance relative to expected
reservoir production rates, delays in project start-up timing and capital expenditures in excess of those
estimated. Capital risk is mitigated in some circumstances by having area producers as joint venture
partners and through cost of service tolling arrangements. Start-up delays are mitigated by the right to
collect stand-by fees.

MANAGEMENT’S DISCUSSION AND ANALYSIS

CAPITAL EXPENDITURES
The Company expects to spend approximately $70 million in 2009 in the Gas Pipelines segment for
ongoing capital improvements, core maintenance capital projects and expansion, including the projects
described above. In 2008, the Company spent $136 million on capital expenditures in the Gas Pipelines
segment which was consistent with expectations. Discussion of the Company’s access to financing is
included under Liquidity and Capital Resources.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 27.0% ownership interest in EEP and a 41.9% voting
interest in EIF. Enbridge manages the day-to-day operations of, and develops and assesses opportunities
for each, including both organic growth and acquisition opportunities.

EARNINGS

(millions of Canadian dollars)

Enbridge Energy Partners

Enbridge Income Fund

Adjusted Earnings

EEP – dilution gain on Class A unit issuance

EEP – unrealized derivative fair value gains/(losses)

EEP – gain on sale of Kansas Pipeline Company

EEP – impact of 2008 hurricanes and project write-offs

EIF – Alliance Canada shipper claim settlement

EIF – impact of tax rate changes

Earnings

2008

59.8

41.1

100.9

4.5

7.2

–

(2.2)

1.3

–

111.7

2007

47.3

39.2

86.5

11.8

(6.3)

3.0

–

1.9

96.9

2006

36.5

37.8

74.3

–

6.5

–

6.0

86.8

Adjusted earnings from Sponsored Investments were $100.9 million for the year ended December 31,
2008 compared with $86.5 million in 2007. Adjusted earnings increased as a result of the strong
performance at EEP and increased distributions from EIF.

Adjusted earnings from Sponsored Investments were $86.5 million for the year ended December 31,
2007 compared with $74.3 million in 2006. The increase in adjusted earnings was primarily a result of
the strong performance at EEP.

Sponsored Investments earnings were impacted by several non-operating adjusting items:

(cid:127)

Earnings in 2008 and 2007 included EEP dilution gains because Enbridge did not fully participate
in EEP’s Class A unit offerings, decreasing Enbridge’s ownership interest in EEP to 14.6%. In
December 2008, the Company purchased an additional US$500.0 million in Class A units
increasing Enbridge ownership interest in EEP to 27.0%. Earnings from EEP included a change in
the unrealized fair value on derivative financial instruments in each period.
2008 earnings from EEP included non-routine costs associated with Hurricanes Gustav and Ike, of
which Enbridge’s share is $0.8 million for the quarter and $1.6 million for the year-to-date, as well
as the write-off of certain projects cancelled due to market conditions.
Earnings from EIF for the year ended December 31, 2008 included proceeds of $1.3 million from
the settlement of a claim against a former shipper on Alliance Canada which repudiated its capacity
commitment.

Sponsored Investments
(millions of Canadian dollars)

Adjusted Earnings

Earnings
(millions of Canadian dollars)

58.6

60.9

74.3

86.5

100.9
2MAR200907311376

66.2

64.8

86.8

96.9

111.7
28FEB200902512517

ENBRIDGE INC.

ANNUAL REPORT 2008

Revenues from Sponsored Investments include
only revenues from EIF as the Company
accounts for its interest in EEP using the equity
method. For the year ended December 31, 2008,
revenues were $297.5 million compared with
revenues of $270.3 million for the year ended
December 31, 2007. The increase in revenue was
a result of increased revenues from both higher
tolls at Alliance Canada and higher allowance oil
revenue from the Saskatchewan System.

For the year ended December 31, 2007,
revenues were $270.3 million compared with
revenues of $254.7 million for the year ended
December 31, 2006. The $15.6 million increase
in revenue was a result of increased tolls on the
Alliance and Saskatchewan System as well as a full year contribution from the wind assets purchased
in Q4-2006.

Enbridge Energy Partners – Liquids Pipelines

3MAR200902102113

ENBRIDGE ENERGY PARTNERS
EEP owns and operates crude oil and liquid petroleum transmission pipeline systems, natural gas
gathering and related facilities and marketing assets in the United States. Significant assets include the
Lakehead System, which is the extension of the Enbridge System in the U.S., natural gas gathering and
processing assets in Texas, the mid-continent crude oil system, various interstate and intrastate natural
gas pipelines and a crude oil feeder pipeline in North Dakota.

Results of Operations
Adjusted earnings from EEP were $59.8 million for the year ended December 31, 2008, compared with
$47.3 million for the year ended December 31, 2007. EEP adjusted earnings increased as a result of
higher incentive income and increased earnings at EEP due to higher gas and crude oil delivery volumes,
tariff surcharges for recent expansions and additional revenue resulting from higher average crude oil
prices associated with allowance oil. These increases were partially offset by increased operating and
administrative costs and write downs of natural gas inventory to fair market value as a result of declines in
the price of natural gas. Also, the Company’s ownership interest in EEP increased to 27.0% in
December 2008.

EEP earnings were favourably impacted by dilution gains because Enbridge did not fully participate in
EEP’s Class A unit offerings and by a change in the unrealized fair value on derivative financial
instruments. Also, 2008 earnings from EEP included non-routine costs associated with Hurricanes
Gustav and Ike, of which Enbridge’s share is $1.6 million, as well as the write-off of certain projects
cancelled due to market conditions.

Adjusted earnings from EEP were $47.3 million for the year ended December 31, 2007 compared with
$36.5 million for the year ended December 31, 2006 despite the stronger Canadian dollar. The increase
in adjusted earnings reflects Enbridge’s larger average ownership interest in 2007 as well as higher
incentive income, increased processing margins and higher volumes on principal natural gas and liquids
systems that were partially offset by higher operating expenses.

Non-operating adjusting items impacted EEP earnings for fiscal 2007 and 2006 as follows:

(cid:127)

Dilution gains resulting from Enbridge not fully participating in Class A unit issuances.
Unrealized derivative fair value gains and losses (losses in 2007 of $6.3 million; gains in 2006 of
$6.5 million).
Enbridge’s $3.0 million share of the gain on the sale of Kansas Pipeline Company (KPC).

MANAGEMENT’S DISCUSSION AND ANALYSIS

In the third quarter of 2006, EEP issued new
Class C units. Enbridge participated in the
offering and no dilution gains resulted. The
Class C unit issuance increased Enbridge’s
ownership interest in EEP from 10.9% to 16.6%.
Enbridge’s average ownership interest in 2006
was 13.0%. In the second quarter of 2007, EEP
issued partnership units. Because Enbridge did
not fully participate in these offerings, dilution
gains of $11.8 million resulted and Enbridge’s
ownership interest in the Partnership decreased
from 16.6% to 15.1%. Enbridge’s average
ownership interest in 2007 was 15.5%. In
March 2008, Enbridge did not participate in
EEP’s issuance of Class A units, resulting in a
$4.5 million dilution gain and a decrease in
ownership interest to 14.6%. In late 2008, Enbridge purchased 16.3 million Class A common units of
EEP, resulting in an ownership increase to 27.0%. The Company’s average ownership interest in EEP
during 2008 was 15.7%

Enbridge Energy Partners – Gas Pipelines

3MAR200902101970

Distributions
EEP makes quarterly distributions of its available cash to its common unitholders, including Enbridge.
Under the Partnership Agreement, Enbridge, as general partner (GP), receives incremental incentive
cash distributions, which represent incentive income, on the portion of cash distributions, on a per unit
basis, that exceed certain target thresholds as follows:

Quarterly Cash Distributions per Unit:

Up to $0.59 per unit

First target – $0.59 per unit up to $0.70 per unit

Second target – $0.70 per unit up to $0.99 per unit

Over second target – cash distributions greater than $0.99 per unit

Unitholders
including Enbridge

Enbridge GP
Interest

98%

85%

75%

50%

15%

25%

50%

During 2006 EEP paid quarterly distributions of $0.925 per unit. In the first three quarters of 2007,
EEP paid quarterly distributions of $0.925 per unit and effective November 2007, EEP increased
quarterly distributions to $0.95 per unit. In the first two quarters of 2008 EEP paid quarterly
distributions of $0.95 per unit and effective August 2008, EEP increased quarterly distributions to
$0.99 per unit. Of the $75.7 million Enbridge recognized as earnings from EEP during 2008, 29%
(2007 – 43%; 2006 – 37%) were general partner incentive earnings while 71% (2007 – 57%; 2006 –
63%) were Enbridge’s limited partner share of EEP’s earnings.

Strategy
Crude oil price volatility in 2008 has caused some crude oil producers to delay projects that were
expected to commence over the next decade and this will cause EEP’s expansion activities in and around
EEP’s Lakehead System to be more modest than experienced over the last several years. Significant
liquidity tightening and volatility in the capital markets will necessitate a less aggressive capital program
in EEP’s natural gas business in the near term. During this period of volatility EEP will continue to focus
primarily on development of the existing pipeline systems and those currently under construction.
EEP will continue to evaluate strategic opportunities to further expand the service capabilities of its
existing system.

ENBRIDGE INC.

ANNUAL REPORT 2008

In addition to the projects described under Liquids Pipelines, EEP is undertaking the following project:

North Dakota System Expansion
EEP is undertaking a further US$0.1 billion expansion of the North Dakota Pipeline System. The
expansion is expected to increase system capacity from 110,000 bpd to 161,000 bpd and will consist of
upgrades to existing pump stations, additional tankage as well as extensive use of drag reducing agents
that are injected into the pipeline. The commercial structure for this expansion is a cost of service based
surcharge that will be added to the existing transportation rates. Approval was received from the FERC
in October 2008. The expansion is expected to be in-service in early 2010.

Business Risks

Financing Risk
EEP has made and expects to continue making substantial capital expenditures for the construction and
development of crude oil and natural gas infrastructure. EEP intends to finance its future capital
expenditures by utilizing cash from operations, borrowings under existing credit facilities and lastly from
borrowings under the $500 million revolving credit agreement with Enbridge (see Liquidity and Capital
Resources). EEP also expects to obtain permanent financing through the issuance of additional debt and
equity securities, but may be unable to do so on attractive terms due to a number of factors including a
lack of demand, poor economic conditions, unfavorable interest rates or its financial condition or credit
rating at the time. In the event additional capital resources are unavailable; EEP may curtail construction
and development activities, or be forced to sell some of its assets on an untimely or unfavorable basis in
order to raise capital.

Supply and Demand
The profitability of EEP depends to a large extent on the volume of products transported on its pipeline
systems. The volume of shipments on EEP’s Lakehead System depends primarily on the supply of
western Canadian crude oil and the demand for crude oil in the Great Lakes and Midwest regions of the
United States and eastern Canada.

EEP’s natural gas gathering assets are also subject to changes in supply and demand for natural gas,
NGLs and related products. Commodity prices impact the willingness of natural gas producers to invest
in additional infrastructure to produce natural gas. These assets are also subject to competitive pressures
from third-party and producer-owned gathering systems.

Regulation
In the U.S., the interstate and intrastate gas pipelines owned and operated by EEP are subject to
regulation by the FERC or state regulators and its revenues could decrease if tariff rates were protested.
While gas gathering pipelines are not currently subject to active regulation, proposals to more actively
regulate intrastate gathering pipelines are currently being considered in certain of the states in which
EEP operates.

Market Price Risk
EEP’s gas processing business is subject to commodity price risk for natural gas and NGLs. Historically,
these risks have been managed by using physical and financial contracts, fixing the prices of natural gas
and NGLs. Certain of these financial contracts do not qualify for cash flow hedge accounting and EEP’s
earnings are exposed to associated mark-to-market valuation changes.

MANAGEMENT’S DISCUSSION AND ANALYSIS

ENBRIDGE INCOME FUND
EIF’s primary assets include a 50% interest in
Alliance Pipeline Canada and the 100%-owned
Enbridge Saskatchewan System, both acquired
from the Company in 2003. Alliance Pipeline
Canada is the Canadian portion of the Alliance
System previously described in the Gas Pipelines
segment. The Enbridge Saskatchewan System
owns and operates crude oil and liquids pipelines
systems from producing fields
in Southern
Saskatchewan
and Southwestern Manitoba
connecting primarily with Enbridge’s mainline
pipeline to the United States.

3MAR200902102252

EIF also owns interests in three wind power
generation projects purchased from Enbridge
in October, 2006 and a business that develops and operates waste-heat power generation projects at
Alliance Pipeline Canada compressor stations.

Enbridge Income Fund

Results of Operations
Adjusted earnings from EIF were $41.1 million for the year ended December 31, 2008, compared with
the prior year of $39.2 million. EIF adjusted earnings for the year ended December 31, 2008 reflected a
7.5% increase in the monthly distributions received from the Fund, effective May 2008, as well as a
one-time special distribution of $0.024 per unit. On November 3, 2008, the Fund announced that it will
increase regular monthly distributions by 11.6% to $0.096 per unit, effective with the distribution to be
paid at the end of January 2009. This increase in adjusted earnings for the full year and in the fourth
quarter was offset by higher tax on distributions received from EIF.

Adjusted earnings from EIF were $39.2 million for the year ended December 31, 2007, comparable with
prior year adjusted earnings of $37.8 million.

In 2007, EIF recognized future taxes within entities that will become taxable in 2011 as a result of the
enactment of Bill C-52, which is discussed under Tax Fairness Plan. This future tax increase was more
than offset by the revaluation of future income tax obligations previously recorded as a result of tax rate
reductions in the second and fourth quarters of 2007.

Tax Fairness Plan
On June 22, 2007, the ‘‘Tax Fairness Plan’’ income trust taxation legislation, Bill C-52, received Royal
Assent. Under the enacted legislation, a distribution tax will be imposed on Enbridge Income Fund
starting in 2011. The impact of the Tax Fairness Plan on the Fund’s reported earnings was relatively
small because most of the assets are rate regulated and future taxes are expected to be included in the
approved rates charged to customers. However, as enacted in its present form, the Tax Fairness Plan will
serve to reduce, all other things being equal, cash available for distribution by EIF commencing in 2011.

Incentive and Management Fees
Enbridge receives a base annual management fee of $0.1 million for management services provided to
EIF plus incentive fees equal to 25% of annual cash distributions over $0.825 per trust unit. In 2008, the
Company received incentive fees of $5.3 million (2007 – $3.5 million, 2006 – $2.4 million). The
Company is the primary beneficiary of EIF through a combination of the voting units and a non-voting
preferred unit investment and as such EIF is consolidated under variable interest entity accounting rules.

ENBRIDGE INC.

ANNUAL REPORT 2008

Strategy
EIF will maximize the efficiency and profitability of its existing assets, pursue organic growth and
expansion opportunities, invest in the expansion activities within its assets including the Saskatchewan
System expansion and Alliance Canada receipt facilities expansion as well as three new waste heat power
generation projects. The following project is being undertaken by EIF:

Saskatchewan System Capacity Expansion
EIF will begin construction in 2009 on Phase II of the Saskatchewan System Capacity Expansion. This
expansion consists of four separate projects that will reduce capacity constraints at a variety of locations.
Collectively, the projects will increase capacity across the system by approximately 129,000 bpd at an
estimated cost of approximately $100 million. Completion of the four capacity expansion projects is
expected by the third quarter of 2010.

Business Risks
Risks for Alliance Pipeline Canada are similar to those identified for Alliance Pipeline US in the Gas
Pipelines segment. The following risks relate to the Saskatchewan System. General risks that affect the
Company as a whole are described under Risk Management.

Competition
The Saskatchewan System faces competition in pipeline transportation from other pipelines as well as
other forms of transportation, most notably trucking. These alternative transportation options could
charge rates or provide service to locations that result in greater net profit for shippers and thereby
potentially reduce shipping on the Saskatchewan System or result in possible toll reductions. The
Saskatchewan System manages exposure to loss of shippers by ensuring the shipping rates are competitive
and by providing a high level of service. Further, the Saskatchewan System’s right-of-way and expansion
efforts have created a competitive advantage. The Saskatchewan System will continue to focus on
increasing efficiencies and its expansion projects in order to meet its shippers’ growing demand.

Demand for Services
Operations and tolls for the Saskatchewan Gathering and the Westspur Systems are, in general, based on
volumes transported and are on terms similar to a common carrier basis with no specific on-going
volume commitments. There is no assurance that shippers will continue to utilize these systems in the
future or transport volumes on similar terms or at similar tolls.

GAS DISTRIBUTION AND SERVICES

Gas Distribution and Services consists of gas utility operations which serve residential, commercial,
industrial and transportation customers, primarily in central and eastern Ontario, the most significant
being EGD. It also includes natural gas distribution activities in Quebec, New Brunswick and New York
State, the Company’s investment in Aux Sable (a natural gas fractionation and extraction business) and
the Company’s Energy Services businesses.

MANAGEMENT’S DISCUSSION AND ANALYSIS

EARNINGS

(millions of Canadian dollars)

Enbridge Gas Distribution

Noverco

Enbridge Gas New Brunswick (EGNB)

Other Gas Distribution

Energy Services

Aux Sable

Other

Adjusted Earnings

EGD – colder/(warmer) than normal weather

EGD – provision for one-time charges

EGD/Noverco – impact of tax changes

Noverco – dilution gain

Energy Services – unrealized derivative fair value gains/(losses)

Energy Services – SemGroup and Lehman bankruptcies

Aux Sable – unrealized derivative fair value gains/(losses)

Other – gain on sale of investment in Inuvik Gas

Earnings

2008

123.3

20.4

14.7

7.6

16.8

28.3

(6.8)

204.3

23.1

(2.8)

–

22.6

(5.7)

54.5

4.6

300.6

2007

114.6

18.6

12.1

7.3

6.0

10.6

(0.3)

168.9

14.2

–

26.8

–

(2.4)

–

(28.1)

–

179.4

2006

98.7

18.7

9.8

6.5

10.1

25.8

8.1

177.7

(36.9)

–

28.9

4.0

–

173.7

Adjusted earnings were $204.3 million for the year ended December 31, 2008 compared with
$168.9 million for the year ended December 31, 2007. Earnings increased primarily due to customer
growth and higher ancillary revenues at EGD, customer growth at EGNB and improved financial
performance at Energy Services and Aux Sable.

Adjusted earnings were $168.9 million for the year ended December 31, 2007 compared with
$177.7 million for the year ended December 31, 2006. Decreased earnings were due to lower
contributions from Aux Sable and the Energy Services businesses, partially offset by customer growth
and higher operating margins at EGD.

Gas Distribution and Services earnings were impacted by the following non-operating adjusting items:

(cid:127)

EGD’s earnings included a $2.8 million provision for one-time charges to better align certain
operating practices with its strategy under incentive regulation (IR).
Energy Services earnings reflected unrealized fair value gains in 2008 and losses in 2007 on
derivative instruments, resulting from forward risk management positions used to ‘‘lock-in’’ the
profitability of forward physical transportation and storage transactions at Tidal Energy.
Energy Services earnings for 2008 also included a $5.7 million write-off as a result of bankruptcies
by SemGroup and Lehman Brothers. The full amount of all such receivables has been provided for;
however, some potential for partial recovery exists.
Aux Sable year-to-date earnings reflected unrealized fair value gains in 2008 and losses in 2007 on
derivative financial instruments used to mitigate the uncertainty of the Company’s 2009 share of the
contingent upside sharing mechanism which allows Aux Sable to share in natural gas processing margins
in excess of certain thresholds. Similar to Energy Services, these non-cash gains arose due to the
revaluation of financial derivatives used to ‘‘lock in’’ the profitability of forward contracted prices.

Gas Distribution and Services
(millions of Canadian dollars)

Adjusted Earnings

Earnings
(millions of Canadian dollars)

164.8

169.7

177.7

168.9

204.3
3MAR200920570313

311.4

177.0

173.7

179.4

300.6
28FEB200902511251

ENBRIDGE INC.

ANNUAL REPORT 2008

Revenues for the year ended December 31,
2008 were $14,279.6 million compared with
$10,217.9 million
ended
for
December 31, 2007. The increase in revenues was
due to higher average commodity prices in Energy
Services and EGD as well as unrealized derivative
gains on risk managed forward positions.

year

the

Revenues for the year ended December 31,
2007 were $10,217.9 million compared with
$8,973.2 million for the year ended December 31,
2006. The increase in revenues was a result of a
significant increase in volumes transacted by
Energy Services and, to a lesser extent, an increase
in commodity prices for those transactions.

Gas Distribution and Services

3MAR200902102928

ENBRIDGE GAS DISTRIBUTION
EGD is Canada’s largest natural gas distribution company and has been in operation for more than
160 years. It serves approximately 1.9 million customers in central and eastern Ontario, southwestern
Quebec and parts of northern New York State. EGD’s utility operations are regulated by the Ontario
Energy Board (OEB) and by the New York State Public Service Commission.

Results of Operations
Adjusted earnings for the year ended December 31, 2008 were $123.3 million compared with
$114.6 million for the year ended December 31, 2007. EGD’s increased adjusted earnings for 2008
reflect early success during its first of five years under IR, specifically through customer growth and
higher ancillary revenues.

EGD’s earnings included a $2.8 million provision for one-time charges to better align certain operating
practices with the EGD’s strategy under IR.

Adjusted earnings for the year ended December 31, 2007 were $114.6 million compared with
$98.7 million for the year ended December 31, 2006. Adjusted earnings in 2007 increased compared
with 2006 because of customer growth, higher rates from the increased rate base and a higher deemed
equity component of the rate base for regulatory purposes.

Incentive Regulation
Improving the regulatory environment is a key strategic thrust to provide greater operational and
organizational flexibility. In 2008, EGD moved to an IR methodology. Under IR, the distribution
revenue requirement and therefore rates, are based on a formulaic approach, using 2007 as the
starting point.

The objectives of the IR plan are as follows:

(cid:127)

reduce regulatory costs;
provide incentive for improved efficiency;
provide more flexibility for utility management; and
provide more stable rates.

2009 Rate Adjustment Application
On September 26, 2008, EGD filed an application with the OEB to adjust rates for 2009 pursuant to the
2008 approved IR formula. Subject to OEB approval, the rate adjustment would be effective January 1,
2009. A settlement agreement containing all as applied for aspects of the formulaic component of the IR
rate setting process was approved by the OEB on December 18, 2008.

MANAGEMENT’S DISCUSSION AND ANALYSIS

2008 Rates
In 2007, EGD filed a rate application requesting a revenue cap incentive rate mechanism calculated on a
revenue per customer basis for the 2008 to 2012 period. The OEB approved the settlement agreement
(the Settlement) with customer representatives.

EGD received a fiscal 2008 final rate order from the OEB on May 15, 2008, approving the
implementation of a change in rates effective July 1, 2008, which enabled EGD to recover the approved
revenues retroactively to January 1, 2008. The final rate order also approved a change in customer billing
to increase the fixed charge portion and decrease the per unit volumetric charge, with no material annual
earnings impact. The fixed charge portion will increase progressively over the IR term.

2007 Rates
EGD’s rates for 2007 were set under a Cost of Service methodology that allowed the revenues to be set
to recover EGD’s forecast costs. Forecast costs included natural gas commodity and transportation,
operation and maintenance, amortization, municipal taxes, income taxes and the debt and equity costs of
financing the rate base. The rate base is EGD’s investment in all assets used in natural gas distribution,
storage and transmission and an allowance for working capital. Under Cost of Service, it was the
responsibility of EGD to demonstrate to the OEB the prudence of the costs it incurred or the activities
it undertook.

Key elements of the OEB’s 2007 rate decision, including issues previously settled and approved by the
OEB, and a previous decision are summarized below:

Regulatory Year

Rate base (millions of Canadian dollars)

Deemed common equity for regulatory purposes

Rate of return on common equity

Approved 2007

$3,745.7

36%

8.39%

For 2007, EGD was granted a 1% increase in the equity component of its deemed capital structure. The
36% deemed equity level is better reflective of changes in EGD’s current business and financial risk
relative to the earlier deemed equity level of 35%.

Strategy
EGD’s vision is to become North America’s leading energy distribution company. To achieve this vision,
EGD has outlined the following strategic objectives:

(cid:127)

achieve top decile safety performance;
enhance operational and financial governance effectiveness;
deliver shareholder value;
maintain a healthy and productive work environment; and
enhance customer and stakeholder relationships.

One of EGD’s major strategic initiatives is to continue to enhance the effectiveness of the business
operations under IR, including rationalizing capital investment and increasing productivity. In addition,
EGD will seek new growth opportunities, including growth in its core natural gas distribution business,
investment in new infrastructure for power generation and fuel switching, development and delivery of
energy efficiency programs and billing services for third parties, as well as the development of new
natural gas storage space.

Customer Growth
Another major strategic initiative is enhancing customer growth. EGD added over 41,000 new
customers during the year ended December 31, 2008 (over 43,000 in the year ended December 31,
2007). In addition to traditional gas distribution growth expected, new earnings growth opportunities
include investment in new infrastructure for power generation, fuel switching, implementation of
turboexpanders on the natural gas distribution system, development and delivery of energy efficiency
programs and billing services for third parties, as well as development of new natural gas storage space.

ENBRIDGE INC.

ANNUAL REPORT 2008

Storage Project
The Company provides storage services to wholesale storage market participants. In 2008, the Company
provided approximately 3 million gigajoules of high deliverability storage capacity to these customers.
Management continues to monitor the storage market and expects to develop new storage capacity when
it is economically appropriate.

Customer Care and Customer Information System
In April 2007, EGD entered into new five-year customer care services contracts with third-party service
providers for meter reading, billing, billing administration, call handling and collections. The total cost
of the contracts is approximately $274 million over the five-year term. EGD is also working towards
implementing a new Customer Information System, which will replace the legacy system by July 2009
and at an estimated cost of $119 million, in order to meet regulatory requirements and to meet the need
for a more robust and technologically up-to-date system.

The OEB has approved a six-year rate recovery arrangement for customer care services and a 10 year
recovery of the $119 million to be invested in the new CIS.

Capital Expenditures
EGD’s capital expenditures in 2008 were $411 million and are expected to be $389 million in 2009 as
EGD completes laterals for new power generating facilities, and builds its CIS system discussed above.

Legal Proceedings

Bloor Street Incident
EGD had been charged under both the Ontario Technical Standards and Safety Act (TSSA) and the
Ontario Occupational Health and Safety Act (OHSA) in connection with an explosion that occurred on
Bloor Street West in Toronto on April 24, 2003. On October 25, 2007, all of the TSSA and OHSA
charges laid against EGD were dismissed by the Ontario Court of Justice. The decision has been
appealed by the Crown to the Ontario Superior Court of Justice. The appeal is scheduled to be heard by
the Court during November 2009. The maximum possible fine upon conviction would not result in any
material financial impact on EGD.

EGD has also been named as a defendant in a number of civil actions related to the explosion. All
significant civil actions have been settled without any material financial impact on EGD. A Coroner’s
Inquest in connection with the explosion is also possible.

Harper Gardens Incident
On February 14, 2007, an explosion and fire occurred at a residence on Harper Gardens in Toronto. The
home was destroyed and a resident of the home was killed. A natural gas contractor working in the home
at the time of the explosion was seriously injured. Several public authorities commenced investigations in
connection with the incident. The Company has also been named as a defendant in civil actions related to
the incident, but does not expect these actions to result in any material financial impact.

1,756

1,805

1,852

1,902

1,942
28FEB200902511084

MANAGEMENT’S DISCUSSION AND ANALYSIS

Gas Distribution and Services –
Number of Active Customers
EGD added over 41,000 customers in 2008 (over 43,000

(thousands)

in 2007).

GST Overpayment
In December 2007, EGD discovered that it had remitted excess GST to the Canada Revenue Agency
(CRA). In respect of certain months within the 2003 to 2005 calendar year periods, the amount of such
overpayment is approximately $40 million. EGD expects that it will recover the overpayment from the
CRA during 2009.

Business Risks
The risks identified below are specific to EGD. General risks that affect the Company as a whole are
described under Risk Management.

Regulatory Risk
The formula currently approved by the OEB for determination of the return on equity, which is
embedded and escalated within rates over the IR period, is based on the OEB’s current risk assessment of
EGD for the 2007 fiscal year.

The Settlement allows certain categories of expense, added at Cost of Service base amounts, and
uncontrollable external factors in the IR formula, which will permit EGD to recover, with OEB approval,
certain costs that are beyond management control, but are necessary for the maintenance of its services.
The Settlement also includes a mechanism to end the IR plan and return to cost of service if there are
significant and unanticipated developments that threaten the sustainability of the IR plan. The above
noted terms set out in the Settlement mitigate EGD’s risk to factors beyond management’s control.

EGD does not profit from the sale of the natural gas commodity nor is it at risk for the difference
between the actual cost of natural gas purchased and the price approved by the OEB. This difference is
deferred as a receivable from or payable to customers until the OEB approves its refund or collection.
EGD monitors the balance and its potential impact on customers and will request interim rate relief that
will allow EGD to recover or refund the natural gas commodity cost differential. EGD has a quarterly
rate adjustment mechanism in place for the natural gas commodity. This allows for the quarterly
adjustment of rates to reflect changes in natural gas commodity prices. Adjustments are subject to prior
approval by the OEB.

Volume Risks
Since customers are billed on both a fixed charge and on a volumetric basis, EGD’s ability to collect its
total revenue requirement depends on achieving the forecast distribution volume established in the
rate-making process. Under IR, volume forecasts will be reviewed and approved by the OEB annually.
The probability of realizing such volume is contingent upon four key forecast variables: weather,
economic conditions, pricing of competitive energy sources and the growth of customers.

Weather is a significant driver of delivery volumes, given that a significant portion of EGD’s customer
base uses natural gas for space heating. In recent years, earnings have been impacted given the unusual
pattern of weather during the year.

Distribution volume may also be impacted by the increased adoption of energy efficient technologies,
along with more efficient building construction, that continues to place downward pressure on
consumption. In addition, conservation efforts by customers to partially mitigate the impact of higher
natural gas commodity prices further contribute to the decline in annual average consumption.

575

438

408

450

444

28FEB200902512660

Volume of Gas Distributed
Gas volumes distributed reflect the growing number of
active customer and the impact each year of warmer than

(billion cubic feet)

normal or colder than normal weather. The 2004 volumes

reflects the 15-month period.

ENBRIDGE INC.

ANNUAL REPORT 2008

Sales and transportation of gas for customers in the residential and commercial sectors account for
approximately 79% (2007 – 78%) of total distribution volume. 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 EGD attains its total forecast distribution volume, it may not earn the
return on equity due to other forecast variables such as the mix between the higher margin residential
and commercial sectors and the lower margin industrial sector.

This distribution volume risk for general service customers is mitigated by the use of appropriate
forecasting models and through the average use true-up variance account that was established under the
IR Settlement Agreement. This variance account enables recovery from or repayment to customers of
amounts representing variances in the actual and forecast average use by general service customers. EGD
is still at distribution volume risk for contract customers.

NOVERCO
Enbridge owns an equity interest in Noverco through ownership of 32.1% of the common shares and a
cost investment in preferred shares. Noverco is a holding company that owns approximately 71.0% of
Gaz Metro Limited Partnership (Gaz Metro), a publicly traded gas distribution company operating in
the province of Quebec and the state of Vermont.

Results of Operations
Noverco adjusted earnings were $20.4 million for the year ended December 31, 2008, comparable to
$18.6 million for the year ended December 31, 2007 and $18.7 million for the year ended
December 31, 2006.

In 2006, earnings were impacted by a non-operating adjusting item of a $4.0 million as a result of the
recognition of a dilution gain from a Gaz Metro unit issuance in which Noverco did not participate.

Weather variations do not affect Noverco’s earnings as Gaz Metro is not exposed to weather risk. A
significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred
share investment, which is based on the yield of 10-year Government of Canada bonds plus 4.34%.

ENBRIDGE GAS NEW BRUNSWICK
The Company owns 70.9% of, and operates, Enbridge Gas New Brunswick, which owns the natural gas
distribution franchise in the province of New Brunswick. EGNB is constructing a new distribution
system and has approximately 9,400 customers. Approximately 725 kilometres (450 miles) of
distribution main has been installed with the capability of attaching approximately 30,000 customers.

Results of Operations
EGNB earnings were $14.7 million for the year ended December 31, 2008 compared with $12.1 million
for the year ended December 31, 2007 and $9.8 million for the year ended December 31, 2006.
Earnings were higher in 2008 and 2007 as a result of franchise customer growth.

EGNB is regulated by the New Brunswick Energy and Utilities Board (EUB). As it is currently in the
development period, EGNB’s cost of service exceeds its distribution revenues. The EUB has approved
the deferral of the difference between distribution revenues and the cost of service during the
development period for recovery in future rates. This recovery period is expected to start in 2010 and
end no sooner than December 31, 2040. On December 31, 2008, the regulatory deferral asset was
$132.7 million (2007 – $117.7 million).

ENERGY SERVICES
Energy Services includes Gas Services and Tidal Energy, the Company’s energy marketing businesses.
Gas Services markets natural gas to optimize Enbridge’s commitments on the Alliance and Vector

MANAGEMENT’S DISCUSSION AND ANALYSIS

Pipelines. It also has a growing business of providing fee-for-service arrangements for third parties,
leveraging its marketing expertise and access to transportation capacity. Capacity commitments as of
December 31, 2008 were 32.7 mmcf/d on the Alliance Pipeline (2.5% of total capacity) and
144 mmcf/d on Vector Pipeline (12.0% of total capacity). Capacity commitments as of December 31,
2007 were 32.2 mmcf/d on the Alliance Pipeline (2.0% of total capacity) and 162.1 mmcf/d on Vector
Pipeline (16.4% of total capacity).

Earnings from Gas Services are dependent upon the basis (location) differentials between Alberta and
Chicago, for Alliance Pipeline, and between Chicago and Dawn, for Vector Pipeline. To the extent the
cost of transportation on these two pipelines exceeds the gas commodity basis differential, earnings will
be negatively affected.

Tidal Energy provides crude oil and NGLs marketing services for the Company and its customers in a full
range of condensate and crude oil types including light sweet, light and medium sours and several heavy
grades. Tidal Energy transacts at many of the major North American market hubs and provides its
customers with a variety of programs including flexible pricing arrangements, hedging programs,
product exchanges, physical storage programs and total supply management, through the analysis and
implementation of different transportation options, reduced quality differentials and tariff structures,
and utilizing risk management pricing options. Tidal Energy’s business involves buying, selling and
storing large quantities of crude oil. Tidal Energy is primarily a physical barrel marketing company and in
the course of its market activities, physical receipt or delivery shortfalls can create modest commodity
exposures. Any open positions created from this physical business are tightly monitored and must
comply with the Company’s formal risk management policies.

Results of Operations
Adjusted earnings from Energy Services were $16.8 million for the year ended December 31, 2008
compared with $6.0 million for the year ended December 31, 2007. Energy Services adjusted earnings
increased due to higher margins captured on storage and transportation contracts as well as increased
transportation and storage volumes in Tidal Energy.

Energy Services earnings were impacted by several non-operating adjusting items; unrealized fair value
gains on derivative instruments, resulting from forward risk management positions used to ‘‘lock-in’’ the
profitability of forward physical transportation and storage transactions at Tidal Energy, and a
$5.7 million write-off as a result of bankruptcies by SemGroup and Lehman Brothers. The full amount
of all such receivables has been provided for and some potential for partial recovery exists.

Adjusted earnings from Energy Services were $6.0 million for the year ended December 31, 2007
compared with $10.1 million for the year ended December 31, 2006. The decrease in adjusted earnings
was due to outstanding storage transactions in Tidal Energy that were negatively impacted by rising
crude oil prices. Tidal Energy buys crude oil, stores it and sells it forward at a higher price, locking in a
profit on the transaction. However, during the life of the transaction, Tidal Energy may hold the oil held
in storage and use it to satisfy a new forward sale at an additional deferred profit. Tidal Energy then
purchases oil at spot prices to satisfy the original sale transaction. As a result, losses will be recognized in
periods of rising oil prices and profitability will be deferred until the original transaction settles.

AUX SABLE
Enbridge owns 42.7% of Aux Sable, a NGLs extraction and fractionation business near Chicago. Aux
Sable owns and operates a plant at the terminus of the Alliance System. The plant extracts NGLs from the
energy-rich natural gas transported on the Alliance System, as necessary, to meet the heat content
requirements of local distribution companies, which require natural gas with less NGLs, or lower heat
content, and to take advantage of positive commodity price spreads.

Aux Sable has an agreement with BP Products North America Inc. to sell its NGLs production to BP. In
return, BP pays Aux Sable a fixed annual fee and a share of any net margin generated from the business in
excess of specified natural gas processing margin thresholds (the upside sharing mechanism). In addition,
BP compensates Aux Sable for all operating, maintenance and capital costs associated with the Aux Sable

ENBRIDGE INC.

ANNUAL REPORT 2008

facilities subject to certain limits on capital costs. BP supplies, at its cost, all make-up gas and fuel supply
gas to the Aux Sable facilities and is responsible for the capacity on the Alliance Pipeline held by an Aux
Sable affiliate, at market rates. The agreement is for an initial term of 20 years, commencing January 1,
2006 and may be extended by mutual agreement for 10-year terms. If cumulative losses exceed a certain
limit, BP will have the option to terminate the agreement, although Aux Sable has the right to reduce
such losses to avoid termination.

Results of Operations
Adjusted earnings for the year ended December 31, 2008 were $28.3 million compared with
$10.6 million for the year ended December 31, 2007. Aux Sable adjusted earnings increased due to
strong fractionation margins and enhanced plant performance, in addition to favourable risk
management positions, which enabled the Company to recognize earnings from the upside
sharing mechanism.

Aux Sable year-to-date earnings reflected unrealized fair value gains on derivative financial instruments
used to risk manage the Company’s 2009 share of the contingent upside sharing mechanism, which
allows Aux Sable to share in natural gas processing margins in excess of certain thresholds. Similar to
Energy Services, these non-cash, non-operating gains arose due to the revaluation of financial derivatives
used to ‘‘lock in’’ the profitability of forward contracted prices.

Adjusted earnings for the year ended December 31, 2007 were $10.6 million compared with earnings of
$25.8 million for the year ended December 31, 2006. The decrease was due to lower fractionation
spreads in 2007 compared with 2006 as well as the weaker U.S. dollar.

Aux Sable’s 2007 reported earnings included $28.1 million of unrealized derivative fair value losses
related to the Company’s share of 2008 contingent upside sharing revenue.

OTHER
The adjusted operating loss in Other was $6.8 million in 2008 compared with $0.3 million in 2007.
Losses in Other for the year ended December 31, 2008 primarily reflected lower earnings from
CustomerWorks which resulted from the April 2007 transition of customer care services related to EGD
to a third-party service provider pursuant to an OEB recommendation.

Adjusted operating loss in Other was $0.3 million in 2007 compared with adjusted earnings of
$8.1 million in 2006. Lower earnings in 2007 were primarily due to the change at Customer Works.

Strategy

Other Natural Gas Distribution Strategies
Enbridge intends to pursue natural gas business development opportunities complementary to the
existing gas distribution and services businesses through:

(cid:127)

developing LNG regasification projects and related pipeline infrastructure;
pursuing marketing and storage opportunities that optimize existing assets; and
exploring gas-fired generation opportunities that are underpinned by long-term contracts and
improve the utilization of existing assets. The approach is to slowly build this business and utilize
partners to share development risks.

Further to this strategy, Enbridge is developing a number of projects, which are described below.

Rabaska LNG Facility
In the second quarter of 2008, the Rabaska partners signed a Letter of Intent with Gazprom
Marketing & Trading USA, Inc. (GMTUSA) regarding supply for the proposed Rabaska LNG
regasification terminal. The Letter of Intent outlines the major terms under which GMTUSA will
become an equity partner in the proposed Rabaska LNG project and will contract for 100% of the
Rabaska terminal’s capacity. The Rabaska LNG facility has all major authorizations, including project
and land use approvals from the province of Quebec in October 2007 and federal government approvals
in March 2008. Pending commercial advancement of GMTUSA’s upstream development, the project is
schedule to be in service in 2013 or 2014.

MANAGEMENT’S DISCUSSION AND ANALYSIS

NetThruPut
In 2007, the Company and its partner in NetThruPut (NTP) entered into an agreement with the TSX
Group granting the TSX Group the option to purchase NTP, an internet-based crude oil trading and
clearing platform. Proceeds of $9.5 million were received from the sale of the option. The option may be
exercised at a time after March 15, 2009 for a price of approximately $60 million. The agreement also
provides the Company and its partner in NTP an option to sell NTP under the same terms to the TSX
Group. The Company has a 52% ownership interest in NTP.

CAPITAL EXPENDITURES
Capital expenditures in Gas Distribution and Services, excluding EGD, were $73 million in 2008
(2007 – $86 million). Capital expenditures for 2009 are expected to be $93 million.

INTERNATIONAL

International includes the Company’s investment in, and management of, Oleoducto Central S.A.
(OCENSA), a crude oil pipeline in Colombia, as well as earnings from the Company’s interest in
Compa˜n´ıa Log´ıstica de Hidrocarburos CLH, S.A., Spain’s largest refined products transportation and
storage business, prior to its sale. Other includes administration and business development.

EARNINGS

(millions of Canadian dollars)

OCENSA/CITCol

CLH

Other

Adjusted Earnings

CLH – gain on sale of investment

CLH – gain on land sale

Earnings

2008

32.7

24.7

(5.3)

52.1

556.1

–

608.2

2007

32.9

60.4

(3.4)

89.9

–

5.2

95.1

2006

33.9

54.5

(5.2)

83.2

–

83.2

Adjusted earnings for the year ended December 31, 2008 were $52.1 million compared with
$89.9 million for the year ended December 31, 2007. International’s adjusted earnings decreased for the
year ended December 31, 2008 as a result of the sale of CLH on June 17, 2008, which also resulted in a
non-operating gain on disposal of $556.1 million increasing 2008 earnings to $608.2 million compared
with $95.1 million in 2007.

Adjusted earnings for the year ended December 31, 2007 were $89.9 million compared with
$83.2 million for the year ended December 31, 2006. The increase in adjusted earnings was due to
stronger operating earnings in CLH as a result of higher transported volumes, an increase in operating
revenues from complimentary businesses, lower income taxes as a result of a tax rate reduction in Spain
and lower business development costs in Other.

Earnings in 2007 included a $5.2 million gain on the sale of land within CLH.

International
(millions of Canadian dollars)

Adjusted Earnings

Earnings
(millions of Canadian dollars)

73.8

79.8

83.2

89.9

4MAR200912241693

52.1

73.6

87.4

83.2

95.1

608.2
28FEB200902511428

ENBRIDGE INC.

ANNUAL REPORT 2008

interest

investment on which

OCENSA/CITCol
in
The Company owns a 24.7%
the
OCENSA, an
Company earns a fixed return. OCENSA is one
of two main crude oil export pipelines within
Colombia. Through a 100% owned entity,
CITCol, the Company manages the pipeline and
earns a fee for this service, which includes
incentives for operating performance. In 2007,
OCENSA made the final payments with respect
to its original US$1.6 billion project debt
further debt servicing
financing. With no
obligations OCENSA may opt
to begin
returning the Company’s initial equity capital
starting in 2009, in accordance with the terms of
the project agreements.

Colombia – OCENSA

3MAR200902101816

CLH
On June 17, 2008, the Company sold its 25% equity interest in CLH. Proceeds from the disposal of the
CLH investment were applied toward funding the Company’s North American growth projects.

STRATEGY
The Company’s strategy internationally has always been patient and opportunistic. Two staggered
investments in Colombia and Spain over the course of 13 years, and the recent profitable sale of the
Spanish investment, demonstrate this approach. While the International portfolio has recently decreased
in size, the Company continues to view this business segment as attractive and it could potentially once
again become a meaningful portion of the Company. International investments provide unique
diversification and potentially premium risk-adjusted returns, provided they meet the Company’s
stringent investment criteria.

BUSINESS RISKS
The International business is subject to risks related to political and economic instability, currency
volatility, market and supply 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 governance involvement, contractual arrangements, influence in operation of the assets,
regular analysis of country risk as well as foreign currency hedging and insurance programs.

Competition
The Company’s current strategic focus may constrain the level of resources and attention focused on
opportunities in the broader international market. International has mitigated the risk by monitoring
and investigating international investment opportunities.

MANAGEMENT’S DISCUSSION AND ANALYSIS

CORPORATE

Corporate includes new business development activities and investing and financing activities, including
general corporate investments and financing costs not allocated to the business segments. This segment
also includes new platforms currently being pursued by the Company including renewable energy (wind
and solar), CO2 transportation and sequestration and Pathfinding initiatives. Pathfinding initiatives
include pursuing investment in smaller start-up entities where that investment will enable the
development of promising new technologies that complement the Company’s core operations.

(millions of Canadian dollars)

Adjusted Corporate Costs

Gain on sale of corporate aircraft

U.S. pipeline tax decision

Unrealized derivative fair value gains

Asset impairment loss

Impact of tax changes

Costs

2008

(57.8)

4.9

(32.2)

26.2

(17.3)

–

(76.2)

2007

(59.2)

2006

(77.7)

–

31.1

(28.1)

14.0

(63.7)

Corporate costs before adjusting items were $57.8 million for the year ended December 31, 2008,
comparable with $59.2 million for the year ended December 31, 2007.

2008 corporate costs were impacted by the following non-operating adjusting items:

(cid:127)

A $4.9 million gain on the sale of a corporate aircraft.
An unfavourable court decision related to the tax basis of previously owned U.S. pipeline assets
which resulted in the recognition of a $32.2 million income tax expense.
Unrealized fair value gain on derivative financial instruments, resulting from forward risk
management positions to minimize the volatility of future U.S. dollar earnings across the Company.
Asset impairment loss related to the write-off of goodwill related to the Company’s Ontario wind
power assets as well as a write-down of the Company’s investment in NSolv, a technology
development venture.

Corporate costs before adjusting items were $59.2 million for the year ended December 31, 2007,
compared with $77.7 million in 2006. Corporate costs decreased due to lower interest expense resulting
from decreased average debt balances throughout 2007 as a result of the equity issuance in the first
quarter. As well, expenditures on corporate development activity decreased because of the Company’s
focus on organic growth. Corporate costs were impacted by the non-operating adjusting item of
favorable legislated tax changes in both years.

STRATEGY
In the longer term, developing new business platforms will be important to maintaining growth and
diversification within the Company. New platforms currently being pursued include renewable energy
(wind and solar), CO2 transportation and sequestration and Pathfinding initiatives. The Company is
currently undertaking the following projects:

ENBRIDGE INC.

ANNUAL REPORT 2008

Ontario Wind Project
Construction of the 190-megawatt Enbridge Ontario Wind Power Project, located in the Municipality
of Kincardine on the Eastern shore of Lake Huron in Ontario, was completed in the fourth quarter of
2008. Although turbines were fully available for operation at the end of 2008, staging of turbine
operations was implemented to ensure safe and reliable operations for the wind project. As of
December 31, 2008, 65 of the 115 wind turbines (56.5%) were operating and reliably delivering power
to the grid. The remaining 50 turbines will be phased into service with all turbines targeted to deliver
power to the grid by early February 2009. The final capital cost of the project is estimated at
$481 million.

Alberta Saline Aquifer Project
The 38-member Alberta Saline Aquifer Project (ASAP) is on track to complete Phase I in Spring 2009.
Phase I has identified specific reservoir locations that offer the potential for long term carbon dioxide
sequestration and has developed a preliminary design and cost estimate for a carbon dioxide
sequestration pilot. Following receipt of regulatory approvals, the ASAP team anticipates that it will
begin Phase II, constructing the pilot project, including drilling of the injection and monitoring wells in
2009, with injections of carbon dioxide beginning in 2010. Phase III will involve expanding the pilot
project to a large-scale, long-term commercial operation. ASAP, spearheaded by Enbridge, is the largest
project of its kind in North America and will play a major role in advancing industry and government’s
knowledge of carbon dioxide sequestration.

Hybrid Fuel Cell Power Plant
In October 2008, the Company and FuelCell Energy Inc. announced the opening of the world’s first
hybrid fuel cell power plant. The plant, which will produce 2.2 megawatts of environmentally preferred,
ultra-clean electricity, or enough power for approximately 1,700 residences, is also the first multi-
megawatt commercial fuel cell to operate in Canada. Support for this $10 million project was provided
by both the Canadian and Ontario Governments. The Company, as the exclusive distributor of the
hybrid fuel cell technology, will be promoting the technology to other natural gas distribution
companies throughout North America.

CAPITAL EXPENDITURES
Capital expenditures in Corporate were $117 million in 2008 (2007 – $159 million). Capital
expenditures for 2009 are expected to be $80 million.

LIQUIDITY AND CAPITAL RESOURCES

The Company will utilize cash from operations and the issuance of commercial paper and/or credit
facility draws to fund liabilities as they become due, finance capital expenditures and pay common share
dividends throughout 2009. At December 31, 2008, the Company had $6.5 billion (2007 –
$5.6 billion) of committed credit facilities excluding the Southern Lights project financing described
below, of which $3.4 billion was drawn or used to backstop commercial paper. The Company
has provided EEP with a revolving credit agreement for up to US$0.5 billion resulting in net
available liquidity at December 31, 2008 for the Company of $3.0 billion, inclusive of cash and cash

MANAGEMENT’S DISCUSSION AND ANALYSIS

equivalents of $0.5 billion. The following table provides details of the company’s credit facilities at
December 31, 2008.

(millions of Canadian dollars)

Liquids Pipelines

Gas Distribution and Services

Corporate 1

Expiry Dates

2010 - 2011

2009 - 2010

2010 - 2013

Total
Facilities

1,300.0

1,014.7

4,185.8

Credit
Facility
Draws

525.5

11.1

962.3

Commercial
Paper
Backstop

–

874.5

Available

774.5

129.1

1,075.1

2,148.4

6,500.5

1,498.9

1,949.6

3,052.0

Southern Lights project financing 2

2014

2,028.1

1,358.9

–

669.2

Credit facilities

8,528.6

2,857.8

1,949.6

3,721.2

Total facilities exclusive of $49.0 million commitment of Lehman Brothers Bank given the bankruptcy filing of its parent in September 2008.

Total facilities inclusive of $140.2 million which is available if certain conditions related to the project are met.

In January 2009, a credit facility established in December 2008, was increased by $0.2 billion to
$0.5 billion as a result of new lender commitments, providing additional liquidity. The Company will
look to access the capital markets for long-term financing as projects approach the in service date and to
manage overall liquidity. The Company was successful in accessing $0.5 billion from the debt capital
markets in the fourth quarter of 2008, as noted below in Financing Activities.

During 2008, the Company established $0.4 billion and US$1.3 billion in project financing that is
non-recourse to the Company, for the Canadian and U.S. components of the Southern Lights project.
These facilities are sufficient to fund the debt component of the Southern Lights financing and comprise
construction, cost overrun and letter of credit facilities that mature in 2014, which is four years beyond
the expected completion date of the project. At December 31, 2008, $0.3 billion and US$0.9 billion
were drawn under the project financing facilities.

The Company’s credit facility agreements include standard default and covenant provisions whereby
accelerated repayment may be required if the Company were to default on payment or violate certain
covenants. As in prior years, the Company expects to continue to comply with these provisions and
therefore not trigger any early repayments.

The Company continues to manage its debt to capitalization ratio to maintain a strong balance sheet.
The Company’s debt to capitalization ratio at December 31, 2008, including short-term borrowings but
excluding non-recourse debt and project financing was 60.7%, compared with 62.7% at the end of 2007.
Including all debt, the capitalization ratio was 66.6% compared with 66.5% at the end of 2007.

The Company invests its surplus cash in short-term investment grade instruments with credit worthy
counterparties. At December 31, 2008, there were $474.2 million of short-term investments intended
to enhance access to short-term liquidity given the recent market turbulence. Short-term investments
were $87.8 million in 2007 and $66.8 million in 2006.

Excluding current maturities of long-term debt, the Company has a positive working capital position,
consistent with December 31, 2007.

(millions of Canadian dollars)

Cash and cash equivalents

Accounts receivable and other

Inventory

Short-term borrowings

Accounts payable and other

Interest payable

Working capital

2008

541.7

2007

166.7

2,322.5

2,388.7

844.7

(874.6)

709.4

(545.6)

(2,411.5)

(2,213.8)

(101.9)

320.9

(89.1)

416.3

ENBRIDGE INC.

ANNUAL REPORT 2008

Changes in commodity prices impact accounts receivable, inventory and accounts payable at Tidal
Energy and EGD.

OPERATING ACTIVITIES
Cash from operating activities increased to $1,387.7 million for the year ended December 31, 2008
from $1,351.6 million for the year ended December 31, 2007 and $1,315.3 million for the year ended
December 31, 2006.

(millions of Canadian dollars)

Earnings net of non-cash items

Changes in operating assets and liabilities

Cash Provided by Operating Activities

2008

1,398.0

(10.3)

2007

1,358.0

(6.4)

1,387.7

1,351.6

2006

1,191.6

123.7

1,315.3

Cash provided by earnings net of non-cash items, was $1,398.0 million for the year ended December 31,
2008, compared with $1,358.0 million and $1,191.6 million for 2007 and 2006, respectively. The
increased earnings from operating activities in 2008 and 2007 resulted primarily from higher earnings at
EGD. Cash from operating activities are stable and predictable for the Company given the regulated
nature of the assets.

There are no material restrictions on the Company’s cash with the exception of proportionately
consolidated joint venture cash of $73.6 million, which cannot be accessed until distributed to
the Company.

Changes in operating assets and liabilities were $130.1 million lower in 2007 compared with 2006. This
decrease primarily resulted from increased accounts receivable at EGD at December 31, 2007 due to the
relatively colder weather experienced during the final billing periods of the year.

INVESTING ACTIVITIES
In 2008, cash used for investing activities was $2,852.9 million compared with $2,228.8 million in
2007, an increase of $624.1 million. In 2008, the Company had increased capital expenditures primarily
due to growth projects such as Southern Lights, Alberta Clipper and Line 4 as well as core maintenance
expenditures incurred primarily at EGD and Enbridge System. In November 2008, the Company
increased its investment in EEP by subscribing for 16.3 million Class A common units for
US$500.0 million. These expenditures were partially offset by the proceeds from the sale of Enbridge’s
investment in CLH in 2008.

Cash used for investing activities for the year ended December 31, 2007 was $2,228.8 million compared
with $1,597.6 million in 2006 as a result of increased capital expenditures primarily due to growth
projects such as Southern Lights, Waupisoo Pipeline and Ontario Wind Project as well as core
maintenance expenditures incurred primarily at EGD and Enbridge System.

FINANCING ACTIVITIES
In 2008, the Company generated $1,840.2 million through financing activities compared with
$904.2 million and $268.1 million in 2007 and 2006, respectively.

Short-term borrowings at EGD are used primarily to finance working capital, including inventory.

In 2008, the Company added new credit facilities of $1.3 billion. Increased funding through commercial
paper issuances and draws under committed credit facilities was required in 2008 to fund capital
expenditures and the Company’s investment in EEP. In 2007, the Company expanded its available
liquidity through credit facility expansions and additions totaling $1.9 billion.

In the last quarter of 2008, the Company issued $0.5 billion of long-term notes. Specifically, EGD issued
a $0.2 billion five-year term note and Enbridge Pipelines Inc. closed a $0.3 billion ten-year term note.
The Company had total note maturities of $0.6 billion, of which $0.3 billion was repaid by EGD.
Financing activities in 2007 included the issuance of US$1.1 billion of term notes in the U.S. market and

MANAGEMENT’S DISCUSSION AND ANALYSIS

$0.2 billion of term notes in the Canadian market to offset term note maturities of $0.6 billion. During
2006, the Company issued $1.1 billion and repaid $400 million of term notes.

During 2008, the Company borrowed $0.3 billion and US$0.9 billion in project financing that is
non-recourse to the Company, for the Canadian and U.S. components of the Southern Lights project.
This financing resulted in the full repayment and cancellation of a US$0.5 billion facility established in
2007 to fund project costs directly related to the Southern Lights Project on an interim basis, which had
been guaranteed by the Company.

Dividends paid on common shares decreased in 2008 due to the increased use of the Company’s
dividend reinvestment plan, which provided a $130.1 million increase in equity funding. Dividends paid
on common shares increased in 2007 due to an increased number of common shares outstanding and a
higher dividend rate.

Equity Issuance
On February 2, 2007, Enbridge closed the issuance to the public of 13.5 million common shares for
$38.75 per share and issued 1.5 million common shares to Noverco for $38.75 per share, which
maintained Noverco’s ownership interest in Enbridge at approximately 9.5%. Net proceeds from both
offerings totaled $566.4 million.

Preferred Securities
The Company redeemed its $200 million, 7.8% Preferred Securities on February 15, 2007.

EXPECTED CAPITAL EXPENDITURES
The numerous organic growth projects and other growth initiatives described in the business unit
sections will require capital funding. The Company also requires capital for ongoing core maintenance
and capital improvements in many of its businesses. In total, Enbridge expects to spend approximately
$3.7 billion during 2009 on capital projects and maintenance. The Company expects to finance these
expenditures through cash from operating activities and available liquidity. The Company may also raise
capital through the monetization or disposition of selected assets.

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. For certain construction
projects, financing costs are eligible for reimbursement through tolls. This external financing may be
supplemented by debt or equity injections from the parent company. Debt, and equity when required,
has been issued by the Company 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.

496.4

724.1

1,205.9

2,299.2

3,635.7
6MAR200907562171

Capital Expenditures
Capital expenditures increased in 2008 primarily
due to expenditures on growth in projects as well as

(millions of Canadian dollars)

core maintenance expenditures incurred.

ENBRIDGE INC.

ANNUAL REPORT 2008

Payments due for contractual obligations over the next five years and thereafter are as follows:

(millions of Canadian dollars)

Long-term debt 1

Non-recourse long-term debt 1

Capital and operating leases

Long term contracts 2, 3

Pension obligations 4

Total

10,673.7

1,617.2

180.0

3,345.4

48.4

Total Contractual Obligations

15,864.7

Less than
1 year

533.1

176.2

15.1

2,058.8

48.4

2,831.6

1-3 years

3-5 years

750.0

259.7

32.3

616.4

–

450.0

218.3

35.2

407.5

–

After
5 years

8,940.6

963.0

97.4

262.7

–

1,658.4

1,111.0

10,263.7

Excludes interest. Changes to the planned funding requirements are dependent on the terms of any debt re-financing agreements.

Approximately $1,579.0 million of these contracts are commitments for materials related to the construction of Liquids Pipelines projects. Changes to the

planned funding requirements, including cancelation, are dependent on changes to the related projects.

Contracts totaling $35 million are within proportionately consolidated joint venture entities and contracts totaling $230.3 million are between the Company and

proportionately consolidated joint venture entities.

Assumes no discretionary payments will be made into the pension plans in 2009. Contributions subsequent to 2009 will be made in accordance with the

independent actuarial valuations required as of December 31, 2009. Contributions, including discretionary payments, may be larger than current amounts

pending future asset performance.

SENSITIVITY ANALYSIS

The Company’s earnings will fluctuate with changes in certain market prices, volumetric throughput on
certain assets, with weather and other factors.

MARKET PRICES
Earnings at Risk (EaR) is the principal risk management metric used to quantify market price risk
sensitivity at Enbridge. EaR is an objective, statistically derived risk metric that measures, with a 97.5%
level of confidence, the maximum adverse change in projected 12-month earnings that could result from
market price risk over a one-month period. The Company’s policy is to target a maximum EaR of 5%
of 1 year forecasted earnings. On December 31, 2008, the Company’s EaR was 2.5% (2007 – 2.8%) of
1 year forecasted adjusted earnings.

The following table shows the EaR from changes to different types of market price risk. These EaR
numbers are based on business conditions and hedging programs as of December 31, 2008 and may not
be applicable to other periods.

Risk

Commodity

Foreign Exchange

Interest Rate

EaR

$13.7 million

$3.6 million

$3.2 million

VOLUMETRIC THROUGHPUT
Transportation volumetric risks are managed through tariff agreements. Most of the Company’s tariff
agreements provide for take-or-pay or throughput insensitivity.

WEATHER
Weather is a significant driver of delivery volumes at EGD, given that a significant portion of EGD’s
customers use natural gas for space heating. Weather, measured in terms of degree day deficiency,
normally directly impacts EGD’s earnings as noted below. Degree-day is a measure of coldness,
calculated as the total number of degrees each day by which the daily mean temperature falls below
18 degrees Celsius.

Factor

Weather

Volume

Incremental change

Approximate incremental impact

17 degree days

1 billion cubic feet

$1.4 million (after-tax)

MANAGEMENT’S DISCUSSION AND ANALYSIS

In recent years weather has impacted earnings by a larger magnitude than the above sensitivities would
suggest. This results from the unusual pattern of distribution of degree days during the year and their
relative effectiveness. Degree days are fully effective, typically in the peak winter months, when their
occurrence directly impacts the consumption pattern by a similar magnitude.

Weather risk is also present in Enbridge Offshore Pipelines; hurricanes have impacted earnings by
$11 million in 2008.

RISK MANAGEMENT

The Company’s business activities are subject to execution, financing, market price, credit and operating
risks, among others. The Company has formal risk management policies, processes and systems designed
to mitigate these risks.

The current economic conditions have not caused the Company to change any risk management
practices. The existing philosophy and framework was designed to be applied consistently in all market
conditions. The Company continues to closely measure and monitor risks using best practice
methodologies and manage exposures within the risk constraints of approved policies.

EXECUTION RISK
The Company’s ability to successfully execute the development of its organic growth projects may be
influenced by capital constraints, third-party opposition, delays in government approvals, cost
escalations, construction delays and shortages (collectively Execution Risk). The Company’s significant
growth plans may strain its resources and may be subject to high cost pressures in the North American
energy sector. Early stage project risks include right-of-way procurement, special interest group
opposition, Crown consultation, environmental and regulatory permitting. Cost escalations may impact
project economics. Construction delays due to slow delivery of materials, contractor non-performance,
weather conditions and shortages may impact project development. Labour shortages, inexperience and
productivity issues may also affect the successful completion of the projects.

The Company has a clearly defined management and governance structure for all major projects. Capital
constraints and cost escalation risks are mitigated through structuring of commercial agreements. The
Company’s emphasis on corporate social responsibility promotes generally positive relationships with
landowners, aboriginal groups and governments. Cost tracking and centralized purchasing is used on all
major projects. Strategic relationships have been developed with suppliers and contractors.
Compensation programs, communications and the working environment are aligned to attract, develop
and retain qualified personnel. In early 2008, the Company made changes in its senior management team
structure which further emphasize successful project execution.

FINANCING RISK
The Company’s financing risk relates to the price volatility and availability of debt and equity to finance
organic growth projects and refinance existing debt maturities. This risk is directly influenced by market
factors, as Canadian and U.S. debt and equity market conditions can change dramatically, affecting
capital availability.

To address this risk, the Company maintains sufficient liquidity through committed credit facilities with
its banking groups which would enable the Company to fund all anticipated requirements for one year
without accessing the capital markets. In addition, the Company ensures that it can readily access the
Canadian and U.S. public capital markets by maintaining current shelf prospectuses with the securities
regulators.

MARKET PRICE RISK
Enbridge’s earnings are subject to movements in interest rates, foreign exchange rates and commodity
prices (collectively Market Price Risk). Given the Company’s desire to maintain a stable and consistent
earnings profile, it has implemented a Board of Directors approved Market Price Risk Policy to minimize
the likelihood that adverse earnings fluctuations arising from movements in market prices across all of its

ENBRIDGE INC.

ANNUAL REPORT 2008

businesses will exceed a defined tolerance. The primary Market Price Risk metric used to monitor risk
and establish limits within that policy is EaR, as described above under Sensitivity Analysis.

The Company uses derivative financial instruments for market price risk management purposes. The
following summarizes the types of market price risks to which the Company is exposed and the financial
derivative hedging programs implemented.

Foreign Exchange Risk
The Company has exposure to foreign currency exchange rates, primarily arising from its U.S. dollar
denominated investments, where carrying values, cashflows and earnings are subject to foreign exchange
rate variability. The Company has implemented a policy whereby it must hedge a minimum level of
foreign currency denominated earnings exposures identified over the next five year period. Under this
policy, the Company has substantially hedged this exposure. The Company may also hedge shorter term
anticipated foreign currency denominated capital expenditures. The earnings exposure from the foreign
exchange positions is managed within the overall consolidated EaR limits of the Company.

Interest Rate Risk
The Company’s cashflows and earnings are exposed to interest rate fluctuations due to the regular
repricing of its variable rate debt. Floating to fixed interest rate swaps, collars and forward rate
agreements are used to hedge against the effect of future interest rate movements. The Company
monitors its debt portfolio mix of fixed and variable rate debt instruments to ensure that the
consolidated portfolio of debt stays within its Board of Directors approved policy limit band of a
maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company is also
exposed to fluctuations in longer term interest rates ahead of anticipated fixed rate debt issuances. Many
of the Company’s existing commercial arrangements and certain construction projects provide for the
full recovery of financing costs through tolls. The Company may enter into interest rate derivatives to
hedge a portion of the interest cost of these future debt issues. The earnings exposure from the interest
rate portfolio is managed within the overall consolidated EaR limits of the Company. As well, for certain
construction projects, financing costs are eligible for reimbursement through tolls.

Information about the debt portfolio is included in Notes 15 and 16 of the 2008 Annual Consolidated
Financial Statements.

Commodity Price Risk
The Company’s cashflows and earnings are exposed to changes in commodity prices as a result of
ownership interest in certain assets, as well as through the activities of its Energy Services affiliates. The
Company uses natural gas, power, crude oil and NGL derivative instruments to fix a portion of the
variable price exposures that may arise from commodity usage, storage, transportation and supply
agreements. The earnings exposure from the commodity positions is managed within business unit EaR
sub-limits, as well as within the overall consolidated EaR limits of the Company.

Fair Values of Derivative Instruments
Information about the financial instruments (including derivatives) outstanding at year end is included
in Note 22 of the 2008 Annual Consolidated Financial Statements.

CREDIT RISK
Credit risk arises from trade receivables, which is mitigated by credit exposure limits, contractual and
collateral requirements and netting arrangements. Credit risk in the Gas Distribution and Services
segment is mitigated by the large and diversified customer base and the ability to recover an estimate for
doubtful accounts through the ratemaking process. Certain large volume customers are exposed in times
of economic uncertainty. In these cases, the Company has secured credit enhancement to assist in
mitigating credit exposure.

Entering into derivative financial instruments can also give rise to credit risk. Credit risk arises from the
possibility that a counterparty will default on its contractual obligations and is limited to those contracts

MANAGEMENT’S DISCUSSION AND ANALYSIS

where the Company would incur a loss in replacing the instrument. Overall credit exposure limits have
been set in the Board of Directors approved Credit Policy.

The Company minimizes credit risk by entering into risk management transactions only with institutions
that possess solid investment grade credit ratings or have provided the Company with an acceptable form
of credit protection. The Company has no significant concentration with any single counterparty.
During 2008, the Company rebalanced its exposure to certain financial counterparties through
the discontinuance of certain hedges. For transactions with terms greater than five years, the Company
may also require a counterparty that would otherwise meet the Company’s credit criteria to
provide collateral.

During 2008, notwithstanding the above mitigants, severe market conditions caused two counterparties
to default resulting in the Company’s first meaningful credit losses. These losses, included in Gas
Distribution and Services earnings, totaled $5.7 million.

OPERATING RISKS

Pipeline Operating Risk
Pipeline leaks are an inherent risk of operations. Other operating risks include: the breakdown or failure
of equipment, information systems or processes; the performance of equipment at levels below those
originally intended (whether due to misuse, unexpected degradation or design, construction or
manufacturing defects); failure to maintain adequate supplies of spare parts; operator error; labour
disputes; disputes with interconnected facilities and carriers; and catastrophic events such as natural
disasters, fires, explosions, fractures, acts of terrorists and saboteurs, and other similar events, many of
which are beyond the control of the pipeline systems. The occurrence or continuance of any of these
events could increase the cost of operating the Company’s pipelines or reduce revenues, thereby
impacting earnings.

The Company has an extensive program to manage system integrity, which includes the development
and use of 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. The Company also maintains
comprehensive insurance coverage for significant pipeline leaks and has a comprehensive security
program designed to reduce security-related risks.

Regulation
Many of the Company’s pipeline operations are regulated and are subject to regulatory risk. The nature
and degree of regulation and legislation affecting energy companies in Canada and the United States has
changed significantly in past years and there is no assurance that further substantial changes will not
occur. These changes may adversely affect toll structures or other aspects of pipeline operations or the
operations of shippers.

Environmental, Health and Safety Risk
The Company’s operations, facilities and petroleum product shipments are subject to extensive national,
regional and local environmental, health and safety laws and regulations governing, among other things,
discharges to air, land and water, the handling and storage of petroleum compounds and hazardous
materials, waste disposal, the protection of employee health, safety and the environment, and the
investigation and remediation of contamination. The Company’s facilities could experience incidents,
malfunctions or other unplanned events that could result in spills or emissions in excess of permitted
levels and result in personal injury, fines, penalties or other sanctions and property damage. The
Company could also incur liability in the future for environmental contamination associated with past
and present activities and properties. The facilities and pipelines must maintain a number of
environmental and other permits from various governmental authorities in order to operate and these
facilities are subject to inspection from time to time. Failure to maintain compliance with these
requirements could result in operational interruptions, fines or penalties, or the need to install potentially
costly pollution control technology. Compliance with current and future environmental laws and
regulations, which are likely to become more stringent over time, including those governing greenhouse

ENBRIDGE INC.

ANNUAL REPORT 2008

gas emissions, may impose additional capital costs and financial expenditures and affect the demand for
the Company’s services, which could adversely affect operating results and profitability. Restrictions on
other resources, such as water or electricity, may affect the Company’s upstream customers’ ability to
produce. The Company could be targeted, along with the oil sands industry, by environmental groups
attempting to draw attention to greenhouse gas emissions.

Enbridge is committed to protecting the health and safety of employees, contractors and the general
public, and to sound environmental stewardship. The Company believes that prevention of incidents and
injuries, and protection of the environment benefits everyone and delivers increased value to
shareholders, customers and employees. Enbridge has health and safety and environmental management
systems and has established policies, programs and practices for conducting safe and environmentally
sound operations. Regular reviews and audits are conducted to assess compliance with legislation and
Company policy.

Special Interest Groups
The Company is exposed to the risk of higher costs, delays or even project cancellations due to increasing
pressure on government and regulators by aboriginal groups, landowners and other special interest
groups. Recent Supreme Court decisions have increased the ability of special interest groups to make
claims and oppose projects in regulatory and legal forums. The Company works proactively with special
interest groups to identify and develop an appropriate response to concerns regarding its projects. The
Company’s CSR program also reports on the Company’s responsiveness to environmental and
community issues. Please see the annual CSR report for further details regarding the CSR program.

Aboriginal Relations
Canadian judicial decisions have recognized that Aboriginal rights and treaty rights exist in proximity to
the Company’s operations and future project developments. The courts have also confirmed that the
Crown has a duty to consult with Aboriginal peoples when its decisions or actions may adversely affect
Aboriginal rights and interests or treaty rights 1. While good business practice generally, and a Crown
duty in some cases, consultation has the potential to delay regulatory approval processes and
construction, which may affect project economics.

Given this environment and the breadth of relationships across the Company’s geographic span,
Enbridge has recently reviewed and updated its Indigenous Peoples Policy, which has been renamed the
Aboriginal and Native American Policy. The new Policy promotes the achievement of participative and
mutually beneficial relationships with Aboriginal and Native American groups affected by the
Company’s projects and operations. Specifically, the Policy sets out principles governing the Company’s
relationships with Aboriginal and Native American peoples and makes commitments to work with
Aboriginal peoples and Native Americans so they may realize sustainable benefits from our projects and
operations. Notwithstanding the Company’s efforts to this end, the issues are complex and the impact of
Aboriginal relations on Enbridge’s operations and development initiatives is uncertain.

Workforce Development
A lack of qualified and properly trained technical, professional and operational staff and leaders would
increase the risk that the Company will not be able to implement its corporate strategy. This risk may be
compounded by the increasing rates of retirement due to workforce demographics, turnover due to
competition in certain markets and growing demand for staff to support business growth. The Company
continues to monitor company-wide workforce planning and is focused on recruiting efforts while
enhancing employee engagement. The Company offers competitive compensation programs, training,
leadership development and succession planning. Further, the supply of human capital is balanced
between hiring full-time employees and expanding the contractor workforce, particularly in the Major
Projects’ department.

See generally, R. v. Sparrow, [1990] 1 S.C.R. 1075, R. v. Badger, [1996] 1 S.C.R. 771 and Delgamuukw v. B.C., [1997] 3 S.C.R. 1010.

MANAGEMENT’S DISCUSSION AND ANALYSIS

Terrorism
The risk of terrorism appears to be growing based on the high profile of the petroleum industry in
Canada and the reliance of the U.S. on Canadian exports. An act of terrorism may result in the loss of
upstream supplies, pipelines, distribution or storage controls systems with safety and environmental
implications. The Company manages this risk through its Human Resources Protection Program, Crisis
Management Plan and insurance programs where available.

CRITICAL ACCOUNTING ESTIMATES

DEPRECIATION
Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at
December 31, 2008 of $16,389.6 million, or 66% of total assets, is generally provided on a straight-line
basis over the estimated service lives of the assets commencing when the asset is placed in service. When it
is determined that the estimated service life of an asset no longer reflects the expected remaining period
of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based
on third party engineering studies, experience and/or industry practice. There are a number of
assumptions inherent in estimating the service lives of the Company’s assets including the level of
development, exploration, drilling, reserves and production of crude oil and natural gas in the supply
areas served by the Company’s pipelines as well as the demand for crude oil and natural gas and the
integrity of the Company’s systems. Changes in these assumptions could result in adjustments to the
estimated service lives, which could result in material changes to depreciation expense in future periods
in any of the Company’s business segments, except the Corporate segment. For certain rate regulated
operations, depreciation rates are approved by the regulator and the regulator may require periodic
studies or technical updates on useful lives which may change depreciation rates. Reflecting the resource
resiliency of the basins the Company serves, revised assumptions have typically resulted in extending
useful lives.

REGULATORY ASSETS AND LIABILITIES
Certain of the Company’s Liquids Pipelines, Gas Pipelines and Gas Distribution and Services businesses
are subject to regulation by various authorities, including but not limited to, the NEB, the FERC, the
ERCB and the OEB. Regulatory bodies exercise statutory authority over matters such as construction,
rates and ratemaking, and agreements with customers. To recognize the economic effects of the actions
of the regulator, the timing of recognition of certain revenues and expenses in operations may differ from
that otherwise expected under generally accepted accounting principles for non rate-regulated entities.
Also, the Company records regulatory assets and liabilities to recognize the economic effects of the
actions of the regulator. Regulatory assets represent amounts that are expected to be recovered from
customers in future periods through rates. Regulatory liabilities represent amounts that are expected to
be refunded to customers in future periods through rates. On refund or recovery of this difference, no
earnings impact is recorded. Effectively, the income statement captures only the approved costs and the
related revenue rather than the actual costs and related revenue. As of December 31, 2008, the
Company’s regulatory assets totaled $625.5 million (2007 – $548.4 million) and regulatory liabilities
totaled $102.6 million (2007 – $173.7 million). To the extent that the regulator’s actions differ from
the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances
could differ significantly from those recorded.

POST-EMPLOYMENT BENEFITS
The Company maintains pension plans, which provide defined benefit and/or defined contribution
pension benefits and other post-employment benefits (OPEB) other than pensions to eligible retirees.
Pension costs and obligations for the defined benefit pension plans are determined using the projected
benefit method. This method involves complex actuarial calculations using several assumptions
including discount rates, expected rates of return on plan assets, health-care cost trend rates, projected
salary increases, retirement age, mortality and termination rates. These assumptions are determined by
management and are reviewed annually by the Company’s actuaries. Actual results that differ from
assumptions are amortized over future periods and therefore could materially affect the expense

ENBRIDGE INC.

ANNUAL REPORT 2008

recognized and the recorded obligation in future periods. The decline in the capital markets has reduced
the current market value of the plan assets; however, the discount rate has increased resulting in a lower
expected benefit obligation substantially offsetting the decline in the plan assets. The Company remains
able to pay the current benefit obligations using cash from operations. See Note 25 to the 2008 Annual
Consolidated Financial Statements for disclosure of the difference between the actual and the expected
results for the past two years. Pension expense is recorded within all of the Company’s business segments
with the exception of EGD which records pension expense on a cash basis in accordance with rate
regulated accounting.

Assuming no discretionary funding is made into the pension plans, funding in 2009 will be
approximately $48 million which is not considered significant to the Company.

Impact of a 0.5% Change in Key Assumptions

Obligation

Expense

Obligation

Expense

Pension Benefits

OPEB

(millions of Canadian dollars)

Decrease in discount rate

Decrease in expected return on assets

Decrease in rate of salary increase

74.6

n/a

(19.2)

9.7

6.1

(4.8)

12.9

n/a

–

1.3

0.2

–

CONTINGENT LIABILITIES
Provisions for claims filed against the Company are determined on a case by case basis. Case estimates are
reviewed on a regular basis and are updated as new information is received. The process of evaluating
claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the
final determination of which could have a material impact on the financial results of the Company and
certain of the Company’s subsidiaries and investments, including Enbridge Gas Distribution Inc.
and Enbridge Energy Company, Inc., are disclosed in Note 29 of the 2008 Annual Consolidated
Financial Statements.

ASSET RETIREMENT OBLIGATIONS
The fair value of asset retirement obligations (AROs) associated with the retirement of long-lived assets
are recognized as long-term liabilities in the period when they can be reasonably determined. The fair
value approximates the cost a third party would charge in performing the tasks necessary to retire such
assets and is recognized at the present value of expected future cash flows. AROs are added to the
carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding
liability is accreted over time through charges to earnings and is reduced by actual costs of
decommissioning and reclamation. The present value of expected future cash flows is determined using
assumptions such as the probability of abandonment in place versus removal and the estimated costs
required upon abandonment in each case, the discount rate and the estimated time to abandonment. For
the majority of the Company’s assets it is not possible to make a reasonable estimate of AROs due to the
indeterminate timing, the long-lived nature of the assets and the scope of the asset retirements. Changes
in any of these assumptions could materially affect the asset and liability recognized in respect of asset
retirement obligations as well as the resulting accretion of the liability and depreciation of the asset
within any of the Company’s business segments.

CHANGE IN ACCOUNTING POLICIES

Information about the Company’s changes in accounting policies is included in Note 2 of the 2008
Annual Consolidated Financial Statements.

FUTURE ACCOUNTING POLICIES

INTERNATIONAL FINANCIAL REPORTING STANDARDS
The Canadian Accounting Standards Board confirmed in February 2008 that publicly accountable
entities will be required to adopt International Financial Reporting Standards (IFRS) for interim and

MANAGEMENT’S DISCUSSION AND ANALYSIS

annual financial statements on January 1, 2011. The Company, as an SEC Registrant, has the option to
use U.S. GAAP instead of IFRS. During the fourth quarter 2008, the Company chose IFRS since it
believes that IFRS will provide a more transparent and appropriate presentation of financial results, and it
would avoid the cost of a second conversion when the United States converges with IFRS in or about
2014 as planned.

Enbridge has established an IFRS governance structure to monitor the progress of the transition. This
group is comprised of senior management from finance, treasury, tax and the Company’s business units
among others. The Audit, Finance and Risk Committee of the Board of Directors receives regular
reports on the advancement of the IFRS transition plan. In addition, the Company has trained internal
IFRS team members and has hired a public accounting firm to assist with project management and
technical accounting advice, as needed.

The Company has a multiyear transition plan which includes four phases – diagnostic, project planning,
policy design and implementation. In 2008, the Company completed the diagnostic phase and has
identified the relevant differences between Canadian GAAP and IFRS. The Company is in the policy
design stage and is also assessing the impact of policy alternatives on its financial statements, systems,
processes and controls. As the transition progresses, the Company will provide increased clarity into the
anticipated consequences of accounting policy changes. The Company is in the process of developing a
detailed project plan for 2009 and 2010 which will include staff communications, a training plan and an
external stakeholders communication plan. Policy design will be completed in 2009 and implementation
will begin during 2009 and be completed by the end of 2010.

Changes in accounting policies and processes and collection of additional information for disclosure will
require modifications to the Company’s information technology systems and processes as well as its
system of internal controls. The identified information technology system alterations are being
incorporated into the detailed project plan to allow time to modify and test the systems before
implementation during 2010. The impact on internal controls over financial reporting and disclosure
controls and procedures will be determined during the policy design and implementation phases.

CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that information
required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is
recorded, processed, summarized and reported within the time periods specified under Canadian and
U.S securities law. As of the year ended December 31, 2008, an evaluation was carried out under the
supervision of and with the participation of Enbridge’s management, including the Chief Executive
Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s
disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act
of 1934). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the design and operation of these disclosure controls and procedures were effective in ensuring
that information required to be disclosed by Enbridge in reports that it files with or submits to the
Securities and Exchange Commission is recorded, processed, summarized and reported within the time
periods required.

Management’s Report on Internal Controls over Financial Reporting
Management of Enbridge Inc. is responsible for establishing and maintaining adequate internal control
over financial reporting as such term is defined in the rules of the United States Securities and Exchange
Commission and the Canadian Securities Administrators. The Company’s internal control over financial
reporting is a process designed under the supervision and with the participation of executive and
financial officers to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of the Company’s financial statements for external reporting purposes in accordance
with GAAP.

ENBRIDGE INC.

ANNUAL REPORT 2008

The Company’s internal control over financial reporting includes policies and procedures that:

(cid:127)

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect
transactions and dispositions of assets of the Company;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,
use or disposition of the Company’s assets that could have a material effect on the financial
statements.

The Company’s internal control over financial reporting may not prevent or detect all misstatements
because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions or
deterioration in the degree of compliance with the Company’s policies and procedures.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of
December 31, 2008, based on the framework established in Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on
this assessment, management concluded that the Company maintained effective internal control over
financial reporting as of December 31, 2008.

During the year ended December 31, 2008, there has been no change in the Company’s internal control
over financial reporting that has materially affected, or is reasonably likely to materially affect, the
Company’s internal control over financial reporting.

QUARTERLY FINANCIAL INFORMATION 1

2008

Total

(millions of Canadian dollars, except for per share amounts)

Revenues

3,967.8

3,871.5

4,368.5

3,923.5

16,131.3

Earnings applicable to common shareholders

251.3

657.7

148.4

263.4

1,320.8

Earnings per common share

Diluted earnings per common share

Dividends per common share

0.70

0.33

1.83

1.81

0.33

0.41

0.33

0.72

0.71

0.33

3.67

3.64

1.32

2007

Total

(millions of Canadian dollars, except for per share amounts)

Revenues

3,358.2

2,728.7

2,634.0

3,198.5

11,919.4

Earnings applicable to common shareholders

Earnings per common share

Diluted earnings per common share

227.0

0.65

0.64

146.5

0.41

78.1

0.22

248.6

0.70

0.69

Dividends per common share

0.3075

700.2

1.97

1.95

1.23

1 Quarterly Financial Information has been extracted from financial statements prepared in accordance with generally accepted accounting principles.

Revenue includes amounts billed to customers of EGD for natural gas, which varies with fluctuations in
the commodity price. Higher natural gas commodity prices increase revenues, but would not similarly
impact earnings, given the cost of natural gas flows through to customers. Fluctuations in commodity
prices impact revenues and earnings from Energy Services businesses.

Significant items that impacted the quarterly earnings and revenue were as follows:

(cid:127)

Fourth quarter earnings in 2008 included higher contributions from Aux Sable and Energy Services,
Liquids Pipelines and EGD. EGD’s fixed charge per customer increased with a corresponding
decrease in the per unit volumetric charge. These changes modify the quarterly earnings profile, but
do not materially affect full year earnings as revenues are shifted from the colder winter quarters to
the warmer summer quarters.

MANAGEMENT’S DISCUSSION AND ANALYSIS

(cid:127)

Third quarter earnings in 2008 reflected increased earnings from Athabasca System, EGD, Aux
Sable and Energy Services. Revenues increased due to higher average commodity prices in 2008.
Second quarter 2008 earnings included a gain on the sale of the Company’s investment in CLH as
well as increased earnings from EEP, Aux Sable and Energy Services. Revenues were higher than the
comparable 2007 period due to higher commodity prices impacting Energy Services.
First quarter 2008 earnings included higher contributions from EGD as well as improved results in
Aux Sable and Energy Services, partially offset by the recognition of an income tax charge related to
previously owned U.S. pipeline assets. Revenues were higher than the comparable 2007 period due
to higher commodity prices impacting Energy Services.
Fourth quarter earnings in 2007 included the impact of tax changes, which increased
consolidated earnings.
Third quarter 2007 included a loss from Aux Sable.
Second quarter 2007 included higher earnings from EGD due to colder than normal weather and a
dilution gain in EEP.
First quarter 2007 included higher earnings from EGD due to colder weather than the prior year
period and the receipt of 2005 hurricane insurance proceeds.

FOURTH QUARTER 2008 HIGHLIGHTS

Earnings applicable to common shareholders were $263.4 million, or $0.72 per share, for the three
months ended December 31, 2008, compared with $248.6 million, or $0.70 per share, for the three
months ended December 31, 2007. Significant factors that increased earnings included unrealized fair
value gains on derivative financial instruments in Aux Sable and Energy Services, AEDC in Liquids
Pipelines and a higher contribution from EGD, partially offset by decreased earnings from International
as the Company sold its interest in CLH in the second quarter of 2008.

SELECTED ANNUAL INFORMATION

(millions of Canadian dollars, except per share amounts)

2008

2007

2006

Total Revenues

Common Share Dividends

Total Assets

Total Long-Term Liabilities

Earnings per Common Share

Diluted Earnings per Common Share

Dividends Per Common Share

16,131.3

11,919.4

10,644.5

489.3

452.3

403.1

24,701.4

13,976.1

19,907.4

11,117.4

18,379.3

10,544.8

3.67

3.64

1.32

1.97

1.95

1.23

1.81

1.79

1.15

Total assets and long-term liabilities increased primarily because of investments in organic growth projects.

ENBRIDGE INC.

ANNUAL REPORT 2008

2008

1,320.8

2007

700.2

2006

615.4

–

4.1

(2.8)

(1.2)

–

(5.3)

–

(6.5)

–

(11.8)

6.3

(3.0)

–

(1.9)

(6.0)

(14.2)

–

(26.8)

–

2.4

–

28.1

–

(5.2)

–

36.9

–

(28.9)

(4.0)

–

(31.1)

636.5

(14.0)

592.9

(4.5)

(7.2)

–

2.2

(1.3)

–

(23.1)

2.8

–

(22.6)

5.7

(54.5)

(4.6)

(556.1)

–

(4.9)

32.2

(26.2)

17.3

–

677.3

NON-GAAP RECONCILIATIONS

(millions of Canadian dollars)

GAAP earnings as reported

Significant after-tax non-operating factors and variances:

Liquids Pipelines

Enbridge System – impact of tax changes

Feeder Pipelines and Other – asset impairment loss

Gas Pipelines

Alliance Pipeline US – shipper claim settlement

Offshore – property insurance recovery from 2005 hurricanes,

net of repair costs

Sponsored Investments

EEP – dilution gain on Class A unit issuance

EEP – unrealized derivative fair value (gains)/losses

EEP – gain on sale of Kansas Pipeline Company

EEP – impact of 2008 hurricanes and project write-offs

EIF – Alliance Canada shipper claim settlement

EIF – impact of tax changes

Gas Distribution and Services

EGD – colder/(warmer) than normal weather

EGD – provision for one-time charges

EGD/Noverco – impact of tax changes

Noverco – dilution gains

Energy Services – unrealized derivative fair value (gains)/losses

Energy Services – SemGroup and Lehman bankruptcies

Aux Sable – unrealized derivative fair value (gains)/losses

Other – gain on sale of investment in Inuvik Gas

International

CLH – gain on sale of investment

CLH – gain on land sale

Corporate

Gain on sale of corporate aircraft

U.S. pipeline tax decision

Unrealized derivative fair value gains

Asset impairment loss

Impact of tax changes

Adjusted earnings

MANAGEMENT’S DISCUSSION AND ANALYSIS

OUTSTANDING SHARE DATA

Preferred Shares, Series A (non-voting equity shares)

Common shares – issued and outstanding (voting equity shares)

Total issued and outstanding stock options (7,535,744 vested)

Number

5,000,000

373,032,095

14,364,183

Outstanding share data information is provided as at February 4, 2009.

RELATED PARTY TRANSACTIONS

Information about the Company’s related party transactions is included in Note 28 of the 2008 Annual
Consolidated Financial Statements.

Additional information relating to Enbridge, including the Annual Information Form, is available on
www.sedar.com.

Dated February 19, 2009

ENBRIDGE INC.

ANNUAL REPORT 2008

MANAGEMENT’S REPORT

TO THE SHAREHOLDERS OF ENBRIDGE INC.

Financial Reporting
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 judgment and best
estimates. Financial information contained elsewhere in this Annual Report is consistent with the consolidated
financial statements.

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 unrelated and independent, has a
specific responsibility to oversee management’s efforts to fulfil 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.

Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting.
The Company’s internal control over financial reporting includes policies and procedures to facilitate the preparation
of relevant, reliable and timely information, to prepare consolidated financial statements for external reporting
purposes in accordance with generally accepted accounting principles and provide reasonable assurance that assets
are safeguarded.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31,
2008, based on the framework established in Internal Control – Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded
that the Company maintained effective internal control over financial reporting as of December 31, 2008.

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

21FEB200820223498

Patrick D. Daniel
President & Chief Executive Officer

February 12, 2009

21FEB200820210688

J. Richard Bird
Executive Vice President &
Chief Financial Officer

CONSOLIDATED FINANCIAL STATEMENTS

INDEPENDENT AUDITORS’ REPORT

TO THE SHAREHOLDERS OF ENBRIDGE INC.
We have completed integrated audits of Enbridge Inc.’s 2008, 2007 and 2006 consolidated financial statements and
of its internal control over financial reporting as at December 31, 2008. Our opinions, based on our audits, are
presented below.

Consolidated Financial Statements
We have audited the accompanying consolidated statements of financial position of Enbridge Inc. as at December 31,
2008 and December 31, 2007, and the related consolidated statements of earnings, comprehensive income,
shareholders’ equity and cash flows for each of the years in the three year period ended December 31, 2008. These
financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion
on these financial statements based on our audits.

We conducted our audits of the Company’s financial statements as at December 31, 2008 and December 31, 2007
and for each of the years in the three year period ended December 31, 2008 in accordance with Canadian generally
accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit of financial statements includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also
includes assessing the accounting principles used and significant estimates made by management, and evaluating
the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of the Company as at December 31, 2008 and December 31, 2007, and the results of its operations
and its cash flows for each of the years in the three year period ended December 31, 2008 in accordance with
Canadian generally accepted accounting principles.

Internal Control over Financial Reporting
We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2008, based on the
criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility
is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on
our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design
and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as
we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.

ENBRIDGE INC.

ANNUAL REPORT 2008

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as at
December 31, 2008 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

21FEB200820251268

Chartered Accountants
Calgary, Alberta, Canada

February 12, 2009

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF EARNINGS

Year ended December 31,

(millions of Canadian dollars, except per share amounts)

Revenues

Commodity sales

Transportation and other services

Expenses

Commodity costs

Operating and administrative

Depreciation and amortization

Income from Equity Investments

Other Investment Income (Note 26)

Interest Expense (Note 15)

Gain on Sale of Investment in CLH (Note 5)

Non-Controlling Interests

Income Taxes (Note 24)

Earnings

Preferred Share Dividends

Earnings Applicable to Common Shareholders

Earnings per Common Share (Note 18)

Diluted Earnings per Common Share (Note 18)

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

2008

2007

2006

13,431.9

2,699.4

9,536.4

2,383.0

8,264.5

2,380.0

16,131.3

11,919.4

10,644.5

12,792.0

1,312.2

658.4

9,009.5

1,163.7

596.9

14,762.6

10,770.1

1,368.7

1,149.3

7,824.6

1,084.2

587.4

9,496.2

1,148.3

180.3

107.8

167.8

195.1

(550.0)

(567.1)

–

962.2

(45.9)

916.3

(209.2)

707.1

(6.9)

700.2

1.97

1.95

–

869.3

(54.7)

814.6

(192.3)

622.3

(6.9)

615.4

1.81

1.79

177.1

202.7

(550.8)

694.6

1,892.3

(55.7)

1,836.6

(508.9)

1,327.7

(6.9)

1,320.8

3.67

3.64

ENBRIDGE INC.

ANNUAL REPORT 2008

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31,

(millions of Canadian dollars)

Earnings

Other Comprehensive Income/(Loss)

Change in unrealized gains/(losses) on cash flow hedges, net of tax

Reclassification to earnings of realized cash flow hedges, net of tax

Other comprehensive gain/(loss) from equity investees

Non-controlling interest in other comprehensive income

Change in foreign currency translation adjustment

Change in unrealized gains/(losses) on net investment hedges,

net of tax

Other Comprehensive Income/(Loss)

Comprehensive Income (Note 2)

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

2008

2007

2006

1,327.7

707.1

622.3

(127.4)

(1.3)

49.2

(19.6)

576.8

(159.9)

317.8

1,645.5

96.4

(6.7)

(19.8)

4.9

–

(447.1)

87.6

174.9

(197.4)

509.7

(51.6)

36.0

658.3

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Year ended December 31,

(millions of Canadian dollars, except per share amounts)

Preferred Shares (Note 18)

Common Shares (Note 18)

Balance at beginning of year

Common shares issued

Dividend reinvestment and share purchase plan

Shares issued on exercise of stock options

Balance at End of Year

Contributed Surplus

Balance at beginning of year

Stock-based compensation

Options exercised

Balance at End of Year

Retained Earnings

Balance at beginning of year

Earnings applicable to common shareholders

Common share dividends

Dividends paid to reciprocal shareholder

Cumulative impact of change in accounting policy (Note 2)

2008

2007

2006

125.0

3,026.5

–

131.3

36.2

2,416.1

566.4

17.7

26.3

2,343.8

–

18.4

53.9

3,194.0

3,026.5

2,416.1

25.7

14.5

(2.3)

37.9

2,537.3

1,320.8

(489.3)

14.6

–

18.3

8.9

(1.5)

25.7

10.0

10.5

(2.2)

18.3

2,322.7

2,098.2

700.2

(452.3)

13.7

(47.0)

615.4

(403.1)

12.2

–

Balance at End of Year

3,383.4

2,537.3

2,322.7

Accumulated Other Comprehensive Income/(Loss) (Note 20)

Balance at beginning of year

Other comprehensive income/(loss)

Cumulative impact of change in accounting policy (Note 2)

Balance at End of Year

Reciprocal Shareholding (Note 10)

Balance at beginning of year

Participation in common shares issued

Balance at End of Year

Total Shareholders’ Equity

Dividends Paid per Common Share

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

(285.0)

317.8

–

32.8

(154.3)

–

(154.3)

(135.8)

(197.4)

48.2

(285.0)

(135.7)

(18.6)

(154.3)

(171.8)

36.0

–

(135.8)

(135.7)

–

(135.7)

6,618.8

5,275.2

4,610.6

1.32

1.23

1.15

ENBRIDGE INC.

ANNUAL REPORT 2008

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,

(millions of Canadian dollars)

Operating Activities

Earnings

Depreciation and amortization

Unrealized (gains)/losses on derivative instruments

Equity earnings in excess of cash distributions

Gain on reduction of ownership interest

Gain on sale of investment in CLH

Gain on sale of investment in Inuvik Gas

Future income taxes

Goodwill and asset impairment losses

Allowance for equity funds used during construction

Non-controlling interests

Other

Changes in operating assets and liabilities (Note 27)

Investing Activities

Acquisitions (Note 5)

Long-term investments

Sale of investment in CLH

Sale of investment in Inuvik Gas

Settlement of CLH hedges

2008

2007

2006

1,327.7

658.5

(120.3)

(81.6)

(12.3)

(694.6)

(5.7)

258.1

22.7

(58.9)

55.7

48.7

(10.3)

707.1

596.9

32.3

(35.2)

(33.9)

–

40.8

–

(15.1)

45.9

19.2

(6.4)

622.3

587.4

–

(54.2)

–

(21.0)

–

(1.5)

54.7

3.9

123.7

1,387.7

1,351.6

1,315.3

–

(659.3)

1,369.0

13.5

(47.0)

–

(20.3)

(101.4)

(362.3)

–

Additions to property, plant and equipment

(3,635.7)

(2,299.2)

(1,205.9)

Affiliate loans, net

Change in construction payable

Financing Activities

Net change in short-term borrowings

Net change in commercial paper and credit facility draws

Net change in non-recourse short-term debt

Debenture and term note issues

Debenture and term note repayments

Net change in Southern Lights project financing

Non-recourse long-term debt issues

Non-recourse long-term debt repayments

Distributions to non-controlling interests

Common shares issued

Preferred share dividends

Common share dividends

Increase/(Decrease) in Cash and Cash Equivalents

Cash and Cash Equivalents at Beginning of Year

Cash and Cash Equivalents at End of Year 1

–

106.6

15.6

75.1

28.0

44.0

(2,852.9)

(2,228.8)

(1,597.6)

329.0

750.8

31.6

497.8

(602.0)

1,238.3

6.4

(65.1)

(9.9)

29.4

(6.9)

(262.3)

(266.9)

336.8

43.1

1,342.2

(634.5)

–

14.4

(58.8)

(18.2)

583.8

(6.9)

188.2

57.7

1,125.0

(400.0)

–

2.8

(60.5)

(31.3)

63.1

(6.9)

(359.2)

(435.4)

(403.1)

1,840.2

375.0

166.7

541.7

904.2

27.0

139.7

166.7

268.1

(14.2)

153.9

139.7

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

Cash and cash equivalents consists of $67.5 million (2007 – $78.9 million; 2006 – $72.9 million) of cash and $474.2 million (2007 – $87.8 million; 2006 –

$66.8 million) of short-term investments.

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31,

(millions of Canadian dollars)

Assets

Current Assets

Cash and cash equivalents

Accounts receivable and other (Note 6)

Inventory (Note 7)

Property, Plant and Equipment, net (Note 8)

Long-Term Investments (Note 10)

Deferred Amounts and Other Assets (Note 11)

Intangible Assets (Note 12)

Goodwill (Note 13)

Future Income Taxes (Note 24)

Liabilities and Shareholders’ Equity

Current Liabilities

Short-term borrowings (Note 15)

Accounts payable and other (Note 14)

Interest payable

Current maturities of long-term debt (Note 15)

Current maturities of non-recourse long-term debt (Note 16)

Long-Term Debt (Note 15)

Non-Recourse Long-Term Debt (Note 16)

Other Long-Term Liabilities

Future Income Taxes (Note 24)

Non-Controlling Interests (Note 17)

Shareholders’ Equity

Share capital

Preferred shares (Note 18)

Common shares (Note 18)

Contributed surplus

Retained earnings

Accumulated other comprehensive income/(loss) (Note 20)

Reciprocal shareholding (Note 10)

Commitments and Contingencies (Note 29)

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

Approved by the Board of Directors:

2008

2007

541.7

2,322.5

844.7

3,708.9

166.7

2,388.7

709.4

3,264.8

16,389.6

12,597.6

2,491.8

1,318.4

225.3

389.2

178.2

2,076.3

1,182.0

212.0

388.0

186.7

24,701.4

19,907.4

874.6

2,411.5

101.9

533.8

184.7

4,106.5

10,154.9

1,474.0

259.0

1,290.8

797.4

545.6

2,213.8

89.1

605.2

61.1

3,514.8

7,729.0

1,508.4

253.9

975.6

650.5

18,082.6

14,632.2

125.0

3,194.0

37.9

3,383.4

32.8

(154.3)

125.0

3,026.5

25.7

2,537.3

(285.0)

(154.3)

6,618.8

5,275.2

24,701.4

19,907.4

David A. Arledge
Chair

21FEB200820171614

David A. Leslie
Director

21FEB200820191209

ENBRIDGE INC.

ANNUAL REPORT 2008

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Enbridge Inc. (Enbridge or the Company) is a publicly traded energy transportation and distribution company.
Enbridge conducts its business through five operating segments identified based on products and services offered:
Liquids Pipelines, Gas Pipelines, Sponsored Investments, Gas Distribution and Services 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.

LIQUIDS PIPELINES
Liquids Pipelines includes the Canadian common carrier pipeline and feeder pipelines that transport crude oil and
other liquid hydrocarbons including the Enbridge System, the Athabasca System, Spearhead Pipeline, Southern
Lights Pipeline and a proportionately consolidated investment in the Olympic Pipeline.

GAS PIPELINES
Gas Pipelines consists of proportionately consolidated investments in natural gas pipelines including the U.S. portion
of the Alliance Pipeline, Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico.

SPONSORED INVESTMENTS
Sponsored Investments consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP), a publicly
traded master limited partnership, and Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership) as
well as Enbridge Income Fund (EIF).

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. EIF is a publicly traded income fund
whose primary operations include a 50% interest in the Canadian portion of the Alliance Pipeline and a crude oil and
liquids pipeline and gathering system.

GAS DISTRIBUTION AND SERVICES
Gas Distribution and Services consists of natural gas utility operations which serve residential, commercial, industrial
and transportation customers, primarily in central and eastern Ontario. It also includes natural gas distribution
activities in Quebec, New Brunswick and New York State, and the Company’s proportionately consolidated investment
in Aux Sable, a natural gas fractionation and extraction business.

The Company’s commodity marketing businesses are also included in Gas Distribution and Services. These
businesses manage the Company’s volume commitments on Alliance and Vector Pipelines as well as offer commodity
storage, transport and supply management services.

INTERNATIONAL
The Company’s International business consists of investments in two energy-delivery businesses, Oleoducto
Central S.A. (OCENSA) in Colombia and, prior to its sale in June 2008, Compa ˜n´ıa Log´ıstica de Hidrocarburos
CLH, S.A. (CLH) in Spain.

CORPORATE
Corporate consists of new business development activities and investing and financing activities, including general
corporate investments and financing costs not allocated to the business segments.

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 32. Amounts are stated in Canadian dollars unless
otherwise noted.

The preparation of financial statements in conformity with Canadian GAAP 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. The most significant assets and liabilities
where we must make estimates include: values of regulatory assets and liabilities (Note 4); depreciation rates of property,
plant and equipment (Note 8); amortization rates of intangible assets (Note 12); measurement of goodwill (Note 13); valuation of

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

share based compensation (Note 19); fair values of financial instruments (Note 21 and Note 22); income taxes (Note 24); post

employment benefits (Note 25) and commitments and contingencies (Note 29). Actual results could differ from these 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. EIF is consolidated in the accounts of the Company because it is a variable
interest entity. The Company is the primary beneficiary of EIF through a combination of a 41.9% equity interest and a
preferred unit investment. 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 according to their classification as held to maturity, loans and receivables or available for sale
(see Financial Instruments). All long-term investments are assessed for impairment if the Company identifies an event
indicative of possible impairment.

REGULATION
Certain of the Company’s Liquids Pipelines, Gas Pipelines and Gas Distribution and Services businesses are subject to
regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy
Regulatory Commission (FERC), the Energy Resources Conservation Board in Alberta (ERCB), the New Brunswick
Energy and Utilities Board (EUB) and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority
over matters such as construction, rates and ratemaking and agreements with customers. 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 for non
rate-regulated entities.

Regulatory assets represent amounts that are expected to be recovered from customers in future periods through
rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through
rates. In the absence of rate regulation, the Company would not recognize regulatory assets or liabilities and the
earnings impact would be recorded in the period the expenses are incurred or revenues are earned. Long-term
regulatory assets are recorded in Deferred Amounts and Other Assets and current regulatory assets are recorded in
Accounts Receivable and Other. Long-term regulatory liabilities are included in Other Long-Term Liabilities and
current regulatory liabilities are recorded in Accounts Payable and Other. Regulatory assets are assessed for
impairment if the Company identifies an event indicative of possible impairment (Note 4).

Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is
depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest
component and, if approved by the regulator, a cost of equity component. In the absence of rate regulation, the
Company would capitalize only the interest component; therefore, the capitalized equity component, the
corresponding earnings during the construction phase and the subsequent depreciation would not be recognized.

Certain regulators prescribe the pool method of accounting for property, plant and equipment where similar assets
with comparable useful lives are grouped and depreciated as a pool. When those assets are retired or otherwise
disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated
depreciation. Entities not subject to rate regulation write off the net book value of the retired asset and include any
resulting gain or loss in earnings.

With the approval of the regulator, Enbridge Gas Distribution (EGD) capitalizes a percentage of certain operating costs.
EGD is authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future
years. In the absence of rate regulation, a portion of such costs may be charged to current earnings.

Contributions made to the defined benefit pension plan and the cost of providing post-employment benefits other than
pensions (OPEB) for the regulated operations of Gas Distribution and Services are expensed as paid, consistent with
the recovery of such costs in rates. Canadian GAAP requires costs and obligations for defined benefit pension plans
and OPEB to be determined using the projected benefit method and charged to earnings as services are rendered.

REVENUE RECOGNITION
For businesses which are not rate-regulated, revenues are recorded when products have been delivered or services
have been performed. Customer credit worthiness is assessed before agreements are signed.

ENBRIDGE INC.

ANNUAL REPORT 2008

For the rate-regulated portion of the Company’s main Canadian crude oil pipeline system, revenue is recognized in a
manner that is consistent with the underlying agreements as approved by the regulator. Certain Liquids Pipelines
revenues are recognized under the terms of a committed 30-year delivery contract rather than the cash tolls received.

For rate-regulated operations in Gas Pipelines and Sponsored Investments, transportation revenues include amounts
related to expenses recognized in the financial statements that are expected to be recovered from shippers in future
tolls. Revenue is recognized in a given period for tolls received to the extent that expenses are incurred. Differences
between the recorded transportation revenue and actual toll receipts give rise to receivable or payable balances.

A significant portion of Gas Distribution and Services operations are subject to rate-regulation. Revenue is recognized
in a manner that is consistent with the underlying rate-setting mechanism as mandated by the regulator. Gas
distribution revenues are recorded on the basis of regular meter readings and estimates of customer usage from the
last meter reading to the end of the reporting period. For the non-regulated portion of Gas Distribution and Services
operations, delivery or service performance only takes place when there is a sales contract in place specifying delivery
volumes or services required and sales prices.

FINANCIAL INSTRUMENTS
The Company classifies financial assets as either held for trading, held to maturity, loans and receivables or available
for sale. The Company classifies financial liabilities as either held for trading or other financial liabilities.

Financial assets and liabilities that are ‘‘held for trading’’ are measured at fair value with changes in fair value
recognized in earnings in other investment income, except for derivatives that are designated as, and determined to
be, effective hedging instruments, whose changes in fair value are recorded in Other Comprehensive Income (OCI).

Generally, the Company classifies equity investments in other entities that are not accounted for under the equity
method or joint venture accounting as ‘‘available for sale’’. Financial assets that are available for sale are measured at
fair value, with changes in those fair values recorded in OCI. Where actively quoted prices are not available for fair
value measurement, these financial assets are measured at amortized cost. Dividends received from available for sale
financial assets are recognized when the right to receive payment is established.

The Company assesses at each balance sheet date whether there is objective evidence that a financial asset is
impaired. For investments classified as ‘‘available for sale’’, where no actively quoted market exists for the security, the
Company internally values the expected discounted cash flows using observable market inputs and determines
whether the decline below carrying value is other than temporary. If the decline is determined to be other than
temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of
the investment.

Financial assets that are ‘‘held to maturity’’ and ‘‘loans and receivables’’ and financial liabilities that are ‘‘other financial
liabilities’’ are measured at amortized cost using the effective interest method of amortization.

Cash and cash equivalents are designated as ‘‘held for trading’’ and are measured at carrying value which
approximates fair value due to the short-term nature of these instruments. Accounts receivable and other are
designated as ‘‘loans and receivables’’. Short-term borrowings, accounts payable and other, interest payable,
long-term debt and non-recourse long-term debt are designated as ‘‘other financial liabilities’’.

Transaction Costs
Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a
financial liability. The Company incurs transaction costs primarily through the issuance of debt and classifies these
costs with the related debt. These costs are amortized using the effective interest rate method over the life of the
related debt instrument.

Hedges
The Company uses derivatives and non-derivative financial instruments to manage changes in commodity prices,
foreign currency exchange rates and interest rates. Hedge accounting is optional and it requires the Company to
document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or
cash flows of the underlying hedged item on an ongoing basis. The Company presents the earnings and cash flow
effects of hedging items with the hedged transaction.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Cash Flow Hedges
The Company uses cash flow hedges to manage changes in commodity prices, foreign currency exchange rates and
interest rates. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in OCI
and reclassified to earnings when the hedged item impacts earnings or to the carrying value of the related
non-financial asset or liability. Any hedge ineffectiveness is recorded in current period earnings.

If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is
discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related
transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in
earnings. Subsequent gains and losses from ineffective derivative instruments are recognized in earnings in the period
they occur.

Fair Value Hedges
The Company may use fair value hedges to hedge the fair value of debt instruments or commodity positions. The
change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged
asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to
be effective, the hedged asset or liability ceases to be remeasured at fair value and the fair value adjustment is
recognized in earnings over the remaining life of the hedged item.

Net Investment Hedges
The Company uses net investment hedges to manage the carrying values of U.S. dollar denominated foreign
investments. The effective portion of the change in the fair value of the hedging instrument is recorded in OCI. Any
ineffectiveness is recorded in current period earnings. Amounts recorded in Accumulated Other Comprehensive
Income or Loss (AOCI) are recognized in earnings when there is a reduction of the hedged net investment resulting
from a sale of ownership interests.

Non-Hedge Derivatives
If a derivative instrument is not an effective hedge for accounting purposes or is not designated as hedging item,
changes in the fair value are recorded in current period earnings.

INCOME TAXES
For non-regulated operations, the liability method of accounting for income taxes is followed. Future income tax assets
and liabilities are recorded 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.

The regulated activities of the Company recover income tax expense based on the taxes payable method when
prescribed by regulators or in ratemaking agreements that are subject to regulatory approval. As a result, rates do not
include the recovery of future income taxes related to temporary differences and the Company does not record future
income tax assets or liabilities related to these differences. The Company expects that all unrecorded future income
taxes will be recovered in rates when they become payable.

FOREIGN CURRENCY TRANSLATION
The Company’s U.S. dollar operations are primarily self-sustaining. Self-sustaining operations are translated into
Canadian dollars using the current rate method. Under this method, assets and liabilities are translated using
period-end exchange rates, with revenues and expenses translated using monthly average rates. Gains and losses
arising on translation of these operations are included in the cumulative translation adjustment component of AOCI.

Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into its
functional currency at the rates of exchange in effect at the period end date. Gains or losses on foreign exchange are
recorded in the Consolidated Statements of Earnings.

CASH AND CASH EQUIVALENTS
Cash and cash equivalents include short-term deposits with a term to maturity of three months or less
when purchased.

ENBRIDGE INC.

ANNUAL REPORT 2008

INVENTORY
Inventory is primarily comprised of natural gas in storage held in EGD. Natural gas in storage is recorded at the
quarterly 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. The difference between the approved price and the actual cost of the gas
purchased is deferred for future refund or collection as approved by the OEB. Other inventory, consisting primarily of
commodities held in storage, is recorded at the lower of cost and net realizable value.

PROPERTY, PLANT AND EQUIPMENT
Expenditures for construction, expansion, major renewals and betterments are capitalized; maintenance and repair
costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have a
future benefit. The Company capitalizes interest incurred during construction. For rate-regulated assets, if approved,
an allowance for equity funds used during construction (AEDC) is capitalized at rates authorized by the regulatory
authorities. Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated
service lives of the assets commencing when the asset is placed in service.

IMPAIRMENT OF LONG-LIVED ASSETS
The Company reviews the carrying values of its long-lived assets at least annually or as events or changes in
circumstances warrant. If it is determined that the carrying value of an asset exceeds the fair value and that the decline
is other than temporary based on future cash flows, the assets are written down to fair value.

DEFERRED AMOUNTS AND OTHER ASSETS
Deferred amounts and other assets include costs which regulatory authorities have permitted, or are expected to
permit, to be recovered through future rates, contractual receivables under the terms of long-term delivery contracts,
derivative financial instruments as well as pension assets. Certain deferred amounts are amortized on a straight-line
basis over various periods depending on the nature of the charges.

INTANGIBLE ASSETS
Intangible assets consist primarily of acquired long-term transportation contracts which are amortized on a
straight-line basis over the expected lives of the contracts.

GOODWILL
Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a
business. Goodwill is not subject to amortization but is tested for impairment at least annually. For the purposes of
impairment testing, reporting units are identified as business operations within an operating segment. Potential
impairment is identified when the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value.
Goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over
the implied fair value of the goodwill, based on the fair value of the assets and liabilities of the reporting unit.

ASSET RETIREMENT OBLIGATIONS
Asset retirement obligations (AROs) associated with the retirement of long-lived assets are measured at fair value and
recognized as Other Long-Term Liabilities in the period when they can be reasonably determined. The fair value
approximates the cost a third party would charge in performing the tasks necessary to retire such assets and is
recognized at the present value of expected future cash flows. AROs are added to the carrying value of the associated
asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to
earnings and is reduced by actual costs of decommissioning and reclamation. The Company’s estimates of retirement
costs could change as a result of changes in cost estimates and regulatory requirements.

For certain of the Company’s assets it is not possible to make a reasonable estimate of AROs due to the indeterminate
timing and scope of the asset retirements.

Depreciation expense for Gas Distribution and Services operations includes a provision for AROs at rates approved by
the regulator. Actual costs incurred are charged to accumulated depreciation in accordance with regulatory treatment.

POST-EMPLOYMENT BENEFITS
The Company maintains pension plans which provide defined benefit and defined contribution pension benefits.
Pension costs and obligations for the defined benefit pension plans are determined using the projected benefit

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

method and are charged to earnings as services are rendered, except for the regulated operations of Gas Distribution
and Services, where contributions made to the plan are expensed as paid consistent with the recovery of such costs in
rates. For defined contribution plans, contributions made by the Company are expensed.

Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using
market related values. Adjustments arising from plan amendments and the transitional amounts recognized on
adoption of the accounting standard are amortized on a straight-line basis over the average remaining service period
of the employees active at the date of amendment or transition. The excess of the net actuarial gain or loss over 10% of
the greater of the benefit obligation and the fair value of plan assets is amortized over the average remaining service
period of the active employees.

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 Gas Distribution and Services where
the cost of providing these benefits is expensed as paid, consistent with the recovery of such costs in rates.

STOCK-BASED COMPENSATION
Stock options granted are recorded using the fair value method. Under this method, compensation expense is
measured at fair value at the grant date and is recognized on a straight-line basis over the shorter of the vesting period
or the period to early retirement eligibility with a corresponding credit to contributed surplus. Balances in contributed
surplus are transferred to share capital when the options are exercised.

Performance Stock Units (PSUs) vest at the completion of a three-year term and Restricted Stock Units vest at the
completion of a 35-month term; both are settled in cash. During the term, an expense is recorded based on the
number of units outstanding and the current market price of the Company’s shares with an offset to Other Long-Term
Liabilities. The value of the PSU’s is also dependent on the Company’s performance relative to performance targets set
out under the plan.

COMPARATIVE AMOUNTS
Where practical, or considered material to the reader, certain comparative amounts have been reclassified to conform
with the current year’s financial statement presentation.

2. CHANGES IN ACCOUNTING POLICIES

FINANCIAL INSTRUMENTS, COMPREHENSIVE INCOME AND HEDGING RELATIONSHIPS
Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants (CICA) Handbook
Section 1530 Comprehensive Income, Section 3251 Equity, Section 3855 Financial Instruments – Recognition and
Measurement, Section 3861 Financial Instruments – Disclosure and Presentation and Section 3865 Hedges. In
accordance with the transitional provisions in these new standards, these policies were adopted prospectively and
accordingly, the prior periods were not restated. Prior period unrealized gains and losses related to the Company’s
foreign currency translation adjustments and net investment hedges are now included in AOCI.

Comprehensive Income and Equity
The new standards introduced comprehensive income, which consists of earnings and OCI. The cumulative changes
in OCI are recorded in AOCI, a separate component of shareholders’ equity. The cumulative translation adjustment,
previously presented as a separate component of shareholders’ equity, is now presented as a component of AOCI. The
components of AOCI are presented in Note 20.

Financial Instruments
CICA Handbook Section 3855 established recognition and measurement criteria for financial instruments and
requires that, generally, all financial instruments are recorded at fair value on initial recognition. Subsequent
measurement depends on whether the instrument has been classified as ‘‘held to maturity’’, ‘‘held for trading’’,
‘‘available for sale’’ or ‘‘loans and receivables’’ as defined by Section 3855.

With the exception of recognizing derivative instruments, including hedge instruments, at fair value, the carrying value
of the Company’s financial instruments did not change. The methods by which the Company determines the fair value
of its financial instruments also did not change as a result of adopting this standard.

ENBRIDGE INC.

ANNUAL REPORT 2008

Impact on Adoption
The adoption of the new standards resulted in the following adjustments on January 1, 2007:

Increase/(Decrease)

(millions of Canadian dollars)
Accounts receivable and other 1, 2

Deferred amounts and other assets 1, 2, 3, 4

Long-term investments 1

Accounts payable and other 2

Long-term debt 3

Other long-term liabilities 1, 2, 4

Future income taxes 1

Non-controlling interests 1

Accumulated other comprehensive income 1

Retained earnings 1

Assets

5.4

55.3

(57.3)

–

3.4

Liabilities
and Equity

–

57.6

(52.7)

42.5

(18.9)

(26.3)

48.2

(47.0)

3.4

As a result of the new standards for cash flow hedges, the Company recognized unrealized net gains related to interest rate, foreign exchange and commodity

hedges. The Company adjusted both deferred amounts and retained earnings for historical fair value adjustments related to certain cash flow hedges.

The Company recorded a regulatory liability due to the recognition of fixed price power contracts offset by unrealized financial instrument losses.

The Company reclassified unamortized deferred financing fees from deferred amounts and other assets to long-term debt as a result of adopting the

new standards.

4 Relates to the recognition of gas purchase hedges for the regulated gas distribution businesses at January 1, 2007.

CAPITAL DISCLOSURES AND FINANCIAL INSTRUMENTS – DISCLOSURES AND PRESENTATION
Effective January 1, 2008, the Company adopted new accounting standards for Capital Disclosures (CICA Handbook
Section 1535) and Financial Instruments – Disclosures and Presentation (CICA Handbook Sections 3862 and 3863).
While the new standards did not change the Company’s accounting policies, they resulted in additional disclosures.

Under Section 1535, the Company disclosed its objectives, policies and procedures for managing capital, summary
quantitative data about what the Company manages as capital, whether the Company has complied with any
externally imposed capital requirements and, if the Company has not complied with them, any consequences of
non-compliance with these capital requirements.

Sections 3862 and 3863 replaced Section 3861 Financial Instruments – Disclosure and Presentation. Disclosure
requirements are revised and enhanced, while presentation requirements remain essentially unchanged. The new
disclosure requirements have expanded disclosure about the significance of financial instruments for the Company’s
financial position and performance, the nature and extent of risks arising from financial instruments to which the entity
is exposed during the period and at the balance sheet date, and how the entity manages those risks.

INVENTORIES
The CICA issued Section 3031 Inventories effective January 1, 2008 which aligns accounting for inventories under
Canadian GAAP with International Financial Reporting Standards (IFRS) and has replaced Section 3030. The
adoption of the revised standard did not have a significant effect on the Company.

FUTURE ACCOUNTING POLICY CHANGES

Accounting for the Effects of Rate Regulation
In August 2007, the Canadian Accounting Standards Board (AcSB) published its decision with respect to rate
regulated operations. The AcSB decided to retain much of the existing guidance related to rate-regulated operations;
however, the exemption from the requirement to record future income taxes, as currently provided in CICA Handbook
Section 3465 Income Taxes and the exemption from CICA Handbook Section 1100 Generally Accepted Accounting
Principles will be removed, effective January 1, 2009. The Company will adopt these changes on January 1, 2009 and
the principal effect will be the recognition of future income tax liabilities on the balance sheet, offset equally by
regulatory assets (Note 4).

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Goodwill and Intangible Assets
The CICA implemented revisions to standards dealing with goodwill and intangible assets effective for fiscal years
beginning on or after October 1, 2008. Section 3064 Goodwill and Intangible Assets, which replaces Section 3062
Goodwill and Other Intangible Assets, gives guidance on the recognition of intangible assets as well as the recognition
and measurement of internally developed intangible assets. This standard is not expected to materially impact the
Company’s financial statements.

Business Combinations
The CICA issued Section 1582 Business Combinations, which replaces Section 1581. This new standard aligns
accounting for business combinations under Canadian GAAP with IFRS and is effective for business combinations
entered into on or after January 1, 2011. The adoption of the revised standard is expected to impact the Company’s
financial statements only to the extent that business combinations are entered into after the effective date.

International Financial Reporting Standards
The AcSB confirmed in February 2008 that publicly accountable entities will be required to adopt IFRS for interim and
annual financial statements for periods beginning on January 1, 2011. The Company has established a project plan
for implementing IFRS which includes determining:

(cid:127)

Changes to accounting policies and implementation decisions;
Disclosure requirements;
Changes to information systems and accounting processes;
Changes to internal controls over financial reporting and disclosure controls and procedures;
Training requirements; and
External stakeholder communications.

The impact of the adoption of IFRS on the Company’s financial reporting is not yet determinable.

3. SEGMENTED INFORMATION

Year ended December 31, 2008

(millions of Canadian dollars)

Revenues

Commodity costs

Liquids
Pipelines

Gas
Pipelines

Sponsored Investments

Gas Distribution and Services

International

Corporate

ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT

December 31,

(millions of Canadian dollars)

Liquids Pipelines

Gas Pipelines

Sponsored Investments

Gas Distribution and Services

International and Corporate

GEOGRAPHIC INFORMATION
Revenues 1

December 31,

(millions of Canadian dollars)

Canada

United States

Other

1 Revenues are based on the country of origin of the product or services sold.

PROPERTY, PLANT AND EQUIPMENT

December 31,

(millions of Canadian dollars)

Canada

United States

Other

2008

2007

7,466.7

2,736.1

3,765.5

7,631.3

357.4

2,744.4

5,334.6

2,043.9

2,688.1

7,287.3

908.6

1,644.9

24,701.4

19,907.4

2008

2007

2,904.8

1,413.1

136.4

57.8

478.2

117.0

200.4

54.9

479.8

159.1

3,694.2

2,307.3

2008

2007

2006

12,447.8

3,671.8

11.7

8,337.0

3,572.6

9.8

7,968.7

2,661.6

14.2

16,131.3

11,919.4

10,644.5

2008

2007

12,338.3

4,049.8

1.5

10,031.2

2,564.4

2.0

16,389.6

12,597.6

ENBRIDGE INC.

ANNUAL REPORT 2008

4. FINANCIAL STATEMENT EFFECTS OF RATE REGULATION

GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS
A number of businesses within the Company are subject to regulation where the rates approved by the regulator are
designed to recover the costs of providing the products and services referred to as the cost of service toll methodology.
The Company’s significant regulated businesses and related accounting impacts are described below.

Enbridge System
The primary business activities of the Enbridge System are subject to regulation by the NEB. Tolls are based on a cost
of service methodology and are based on agreements with customers which are filed with the NEB for approval.

The incentive tolling settlement (ITS) is effective from January 1, 2005 to December 31, 2009 and defines the
methodology for calculation of tolls and the revenue requirement on the core component of the Enbridge System in
Canada. Toll adjustments, for variances from requirements defined in the ITS, are filed annually with the regulator
for approval.

Athabasca Pipeline
Athabasca Pipeline is regulated by the ERCB. Tolls are established based on long-term transportation agreements with
individual shippers and taxes are recorded using the taxes payable method.

Vector Pipeline
Vector Pipeline is an interstate natural gas pipeline with a FERC approved tariff establishing rates, terms and
conditions governing its service to customers. Rates are determined using a cost of service methodology. Tariff
changes may only be implemented upon approval by the FERC. Tolls include a return on equity component of 11.04%
(2007 – 10.75%; 2006 – 10.75%) after tax.

Alliance Pipeline
The U.S. portion of the Alliance Pipeline (Alliance) is regulated by the FERC and the Canadian portion of the pipeline is
regulated by the NEB. Shippers on Alliance entered into 15-year transportation contracts expiring in December 2015,
with a cost of service toll methodology. Toll adjustments are filed annually with the regulator. The tolls include a return
on equity component of 10.88% (2007 – 10.88%; 2006 – 10.85%) after tax for the U.S. portion and 11.26% (2007 –
11.26%; 2006 – 11.25%) after tax for the Canadian portion. Alliance tolls are based on a deemed 70% debt and 30%
equity structure.

Enbridge Gas Distribution
EGD’s gas distribution operations are regulated by the OEB. EGD’s rates are based on a revenue per customer cap
incentive regulation (IR) methodology which adjusts revenues, and consequently rates, annually and relies on an
annual process to forecast volume and customer additions. Unlike the cost of service methodology used in prior years,
the concepts of rate base and return on rate base are not relevant under IR.

EGD’s rate of return on common equity embedded in rates was 8.39% (2007 – 8.39%; 2006 – 8.74%) after tax based
on a 36% (2007 – 36%; 2006 – 35%) deemed common equity component of capital for regulatory purposes.

Enbridge Gas New Brunswick
Enbridge Gas New Brunswick (EGNB) is regulated by the EUB and follows a cost of service tolling methodology. An
application for rate adjustments is filed annually for EUB approval. EGNB’s rate of return on rate base was 9.71%
(2007 – 9.70%; 2006 – 9.78%) after tax and the approved rate of return on equity was 13.00% (2007 – 13.00%;
2006 – 13.00%) after tax, based on equity which is capped at 50%.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FINANCIAL STATEMENT EFFECTS
Accounting for rate-regulated entities has resulted in recording the following regulatory assets and liabilities:

December 31,

2008

2007

(years)

2008

2007

2006

Estimated
Settlement
Period

Earnings Impact 1

(millions of Canadian dollars)

Regulatory Assets/(Liabilities)

Liquids Pipelines

Enbridge System tolling deferrals 2

Power purchase arrangements 3

113.6

(20.9)

143.4

(23.8)

1-3

(29.8)

2.9

Gas Pipelines

Deferred transportation revenue 4

Transportation revenue adjustment 5

266.7

6.7

Sponsored Investments

181.4

15-17

4.1

Deferred transportation revenue 4

79.8

65.6

Gas Distribution and Services

EGNB regulatory deferral 6

Class action lawsuit settlement 7

Ontario hearing cost 8

Purchased gas variance 9

Unaccounted for gas variance 10

Transactional services deferral 11

132.7

20.1

5.3

117.7

22.0

8.1

(75.2)

(141.1)

0.6

(6.5)

6.1

(8.8)

(22.8)

(23.8)

5.9

(2.6)

(6.1)

–

9.8

(1.4)

7.7

7.3

10.3

–

(0.7)

(8.8)

11.4

–

12.4

13.5

(1.7)

(99.3)

(9.4)

–

1.1

0.9

5.9

10.1

(1.2)

(1.8)

43.8

(3.6)

–

The effect of a number of the Company’s businesses being subject to rate regulation increased / (decreased) after tax reported earnings by the

identified amounts.

Tolls on the Enbridge System are calculated in accordance with the ITS, System Expansion Program (SEP) II and the Terrace agreements and are established

each year based on capacity, the allowed revenue requirement and the Terrace agreement. Where actual volumes shipped on the pipeline do not result in

collection of the annual revenue requirement, a receivable is recognized and incorporated into tolls in the subsequent year. Recovery in the subsequent year, in

whole or in part, is dependent upon realizing shipping volumes consistent with tolling model forecasts. Under/over collection are rolled into subsequent years. In

addition, other tolling deferrals are recorded in accordance with the various agreements.

The power purchase arrangements liability represents the fair value of fixed price contracts and related financial instruments used to manage the mix of fixed

and floating power costs (Note 21). Under rate regulation any fair value changes are passed to shippers through tolls. In the absence of rate regulation, these

changes would impact earnings in the year incurred.

4 Deferred transportation revenue is related to the cumulative difference between GAAP depreciation expense of Alliance and Vector Pipelines and depreciation

expense included in the regulated transportation rates. The Company expects to recover this difference over a number of years when depreciation rates in the

transportation agreements are expected to exceed the GAAP depreciation rates, for Alliance US beginning in 2009 and Alliance Canada beginning in 2012 and

ending in 2025 and for Vector beginning in 2008 and ending in 2023. This regulatory asset is not included in the rate base.

The transportation revenue adjustment is the cumulative difference between actual expenses of Alliance Pipeline US and estimated expenses included in

transportation rates. The transportation revenue adjustment is recoverable under the long-term transportation agreements and is not included in the rate base.

A regulatory deferral account captures the difference between EGNB’s distribution revenues and its cost of service revenue requirement during the development

period. The regulatory deferral account balance will be amortized over a recovery period approved by the EUB, currently expected to end after 2040,

commencing at the end of the development period which is expected to be 2010.

Class action lawsuit settlement deferral represents amounts paid towards the settlement of a class action lawsuit related to late payment penalties. Pursuant to

an OEB decision in February 2008, these amounts will be recovered from customers over a five-year period commencing in 2008. In the absence of rate

regulation these costs would be expensed as incurred.

8 Ontario hearing costs are incurred by EGD for the rate hearing process. EGD has historically been granted OEB approval for recovery of such hearing costs,

generally within two years. In the absence of rate regulation these costs would be expensed as incurred.

Purchased gas variance is the difference between the actual cost and the approved cost of gas reflected in rates. EGD has historically been granted approval for

recovery or required refund of this variance within the year. In the absence of rate regulation the actual cost of gas sold would be recognized in earnings in the

year sold.

10 Unaccounted for gas variance represents the difference between the total gas distributed by EGD and the amount of gas billed or billable to ratepayers, to the

extent it is different from the approved gas variance. EGD has deferred unaccounted for gas variance and has historically been granted approval for recovery or

required refund of this amount in the subsequent year. In the absence of rate regulation this variance would be included in cost of sales.

11 Transactional services deferral represents the ratepayer portion of excess earnings generated from optimization of storage and pipeline capacity. EGD has
historically been required to refund the amount to ratepayers in the following year. There would be no change in the treatment of this item in the absence of

rate regulation.

ENBRIDGE INC.

ANNUAL REPORT 2008

OTHER ITEMS AFFECTED BY RATE REGULATION

Future Income Taxes
In the absence of rate regulation, future income tax liabilities of $532.9 million (2007 – $517.1 million) associated with
certain assets, primarily property, plant and equipment, would be recorded.

The Company has recorded net future income tax liabilities of $67.7 million (2007 – $24.0 million) related to certain
regulatory asset/liability deferral accounts identified above. Accumulated future income tax liabilities of $54.5 million
(2007 – $55.6 million) related to the remaining regulatory deferral accounts have not been recognized at
December 31, 2008. In the absence of rate regulation, regulatory deferrals would not be recorded nor would the
associated future income tax liabilities. As a result of these tax impacts, earnings during the year would decrease by
$15.0 million (2007 – increase by $62.2 million).

Allowance For Funds Used During Construction and Other Capitalized Costs
With the pool method prescribed by regulators, it is not possible to identify the carrying value of the equity component
of AFUDC or its effect on depreciation. Similarly, gains or losses on the retirement of specific fixed assets in any given
year cannot be identified or quantified.

Operating Cost Capitalization
EGD entered into a consulting contract relating to asset management initiatives. The majority of the costs are being
capitalized to gas mains in accordance with regulatory approval. At December 31, 2008, $93.7 million (2007 –
$82.2 million) was included in gas mains, which are depreciated over the average service life of 25 years. In the
absence of rate regulation, the majority of these costs would be charged to current earnings.

Pension Plans
Had pension costs and obligations been recognized at EGD, the net pension asset would have increased by
$156.1 million at December 31, 2008 (2007 – $153.3 million) and earnings would have increased by $3.1 million
(2007 – decreased by $1.1 million).

Post-Employment Benefits Other than Pensions
In the absence of rate regulation, the cost of such benefits is accrued during the years employees render service. Had
these costs been accrued at EGD, the net OPEB liability would have increased by $75.5 million (2007 – $70.8 million)
and earnings would have decreased by $5.5 million (2007 – $5.8 million).

5. DISPOSITION AND ACQUISITION

DISPOSITION
On June 17, 2008, the Company sold its 25% investment in CLH for total proceeds of $1.38 billion (876 million euros),
including a dividend receivable of $17.3 million (10.9 million euros), net of transaction costs. The sale of CLH resulted
in a gain of $694.6 million. Earnings generated by the CLH investment were $24.7 million (2007 – $65.6 million;
2006 – $54.5 million) for the year ended December 31, 2008, and are included in the International operating
segment. Operating cash flows generated by the CLH investment were $11.5 million for the year ended December 31,
2008 (2007 – $58.4 million; 2006 – $56.2 million).

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

ACQUISITION
On February 1, 2006, Enbridge acquired a 65% common share interest in the Olympic Pipe Line Company for
$112.7 million in cash.

(millions of Canadian dollars)

Fair Value of Assets Acquired:

Property, plant and equipment

Other assets

Future income taxes

Other liabilities

Goodwill

Purchase Price:

Cash, net of $1.6 million cash acquired

Deposit paid in 2005

6. ACCOUNTS RECEIVABLE AND OTHER

December 31,

(millions of Canadian dollars)

Trade receivables

Unbilled revenues

Regulatory assets

Taxes receivable

GST receivable

Short-term portion of derivative assets

Prepaid expenses and deposits

Transfer fees

Due from affiliates

Dividends receivable

Other

7. INVENTORY

December 31,

(millions of Canadian dollars)

Gas

Other commodities

107.0

5.0

(6.1)

(17.0)

88.9

23.8

112.7

(11.3)

101.4

2008

2007

1,088.4

1,332.4

569.8

144.6

133.3

74.6

65.3

28.4

22.3

18.3

13.3

453.0

183.7

17.6

78.7

79.5

20.2

28.9

75.0

12.2

164.2

2,322.5

107.5

2,388.7

2008

2007

674.3

170.4

844.7

599.2

110.2

709.4

ENBRIDGE INC.

ANNUAL REPORT 2008

8. PROPERTY, PLANT AND EQUIPMENT

December 31, 2008

(millions of Canadian dollars)

Liquids Pipelines

Pipeline

Pumping equipment, buildings, tanks and other

Land and right-of-way

Under construction

Gas Pipelines

Pipeline

Land and right-of-way

Metering and other

Under construction

Sponsored Investments

Pipeline

Other

Gas Distribution and Services

Gas mains

Gas services

Regulating and metering equipment

Storage

Computer technology

Other

Under construction

International and Corporate

Wind turbines and other

Land and right-of-way

Under construction

Weighted Average
Depreciation Rate

Cost

Accumulated
Depreciation

Net

2.4%

3.7%

2.5%

–

3.6%

2.8%

5.5%

–

4.4%

8.7%

3.7%

4.1%

3.7%

2.7%

19.1%

4.5%

–

4.9%

4.0%

–

3,161.9

3,025.7

69.9

3,856.9

1,359.6

1,027.8

19.7

–

10,114.4

2,407.1

1,802.3

1,997.9

50.2

3,856.9

7,707.3

2,169.0

588.7

1,580.3

48.6

168.7

333.5

11.3

28.9

–

37.3

139.8

333.5

2,719.8

628.9

2,090.9

1,362.9

129.0

1,491.9

2,943.7

2,290.5

619.1

246.5

158.3

541.6

26.7

276.7

16.1

292.8

804.1

739.4

177.3

67.3

62.5

124.8

–

1,086.2

112.9

1,199.1

2,139.6

1,551.1

441.8

179.2

95.8

416.8

26.7

6,826.4

1,975.4

4,851.0

552.0

1.8

21.5

575.3

34.0

–

34.0

518.0

1.8

21.5

541.3

21,727.8

5,338.2

16,389.6

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2007

(millions of Canadian dollars)

Liquids Pipelines

Pipeline

Pumping equipment, buildings, tanks and other

Land and right-of-way

Under construction

Gas Pipelines

Pipeline

Land and right-of-way

Metering and other

Under construction

Sponsored Investments

Pipeline

Other

Gas Distribution and Services

Gas mains

Gas services

Regulating and metering equipment

Storage

Computer technology

Other

Under construction

International and Corporate

Other

Under construction

Weighted Average
Depreciation Rate

Cost

Accumulated
Depreciation

Net

2.2%

3.7%

1.8%

–

3.7%

2.7%

4.6%

–

4.2%

7.6%

3.3%

3.6%

3.7%

2.7%

19.4%

4.6%

–

8.1%

–

2,688.4

2,566.6

41.5

1,546.4

6,842.9

1,259.9

912.1

18.5

–

2,190.5

1,428.5

1,654.5

23.0

1,546.4

4,652.4

1,656.5

390.4

1,266.1

38.8

101.6

272.6

7.6

16.0

–

31.2

85.6

272.6

2,069.5

414.0

1,655.5

1,402.8

108.7

1,511.5

2,748.9

2,224.0

581.9

246.4

185.2

310.6

143.1

284.1

13.9

298.0

708.7

676.4

158.0

61.0

81.6

106.5

–

1,118.7

94.8

1,213.5

2,040.2

1,547.6

423.9

185.4

103.6

204.1

143.1

6,440.1

1,792.2

4,647.9

113.0

352.6

465.6

37.3

–

37.3

75.7

352.6

428.3

17,329.6

4,732.0

12,597.6

ENBRIDGE INC.

ANNUAL REPORT 2008

9. JOINT VENTURES

Enbridge has joint venture interests in the following entities:

December 31,

(millions of Canadian dollars)

Liquids Pipelines

Olympic Pipeline

Chicap Pipeline (Note 10)

Other

Gas Pipelines

Alliance Pipeline US

Vector Pipeline

Enbridge Offshore Pipelines – various joint ventures

22%-75%

Sponsored Investments

Alliance Pipeline Canada

Other

Gas Distribution and Services

Aux Sable

Other

50%

33%-50%

42.7%

42.7%-70%

Ownership
Interest

Net Assets

2008

2007

65%

43.8%

30%-50%

50%

60%

125.3

53.8

59.5

452.9

486.3

521.1

344.4

47.7

173.6

44.6

97.8

–

54.8

364.3

408.4

441.3

354.8

69.2

150.6

49.7

2,309.2

1,990.9

The following summarizes the impact of proportionately consolidating the joint ventures on the consolidated financial
statements of Enbridge:

Year ended December 31,

(millions of Canadian dollars)

Earnings

Revenues

Commodity costs

Operating and administrative

Depreciation and amortization

Interest expense

Other investment income

Proportionate share of earnings

Cash Flows

Cash provided by operating activities

Cash used in investing activities

Cash used in financing activities

Proportionate share of decrease in cash and cash equivalents

2008

2007

2006

891.0

(173.6)

(235.4)

(167.7)

(102.1)

12.7

224.9

407.7

(61.2)

(350.6)

(4.1)

844.5

(132.9)

(207.6)

(152.9)

(106.4)

6.6

251.3

312.0

(131.9)

(183.9)

(3.8)

939.4

(184.8)

(257.2)

(164.8)

(110.8)

7.3

229.1

318.3

(59.5)

(258.9)

(0.1)

100

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31,

(millions of Canadian dollars)

Financial Position

Current assets

Property, plant and equipment, net

Deferred amounts and other assets

Current liabilities

Non-recourse long-term debt

Other long-term liabilities

Proportionate share of net assets

2008

2007

179.2

3,268.9

335.6

(176.9)

146.0

2,913.1

277.6

(139.8)

(1,271.2)

(1,181.6)

(26.4)

(24.4)

2,309.2

1,990.9

During the year the Company purchased additional equity interest in Chicap Pipeline, increasing its ownership
percentage to 43.8%. As the Company now has joint control over the entity, it has been proportionally consolidated as
a joint venture in 2008. The entity was previously classified as a long-term investment (Note 10).

10. LONG-TERM INVESTMENTS

December 31,

(millions of Canadian dollars)

Equity Investments

Liquids Pipelines

Chicap Pipeline

Sponsored Investments

The Partnership

Gas Distribution and Services

Noverco Common Shares

Other

International

Compa ˜n´ıa Log´ıstica de Hidrocarburos CLH, S.A.

Corporate

Other Investments

Gas Distribution and Services

Noverco Preferred Shares

Fuel Cell Energy

International

Oleoducto Central S.A.

Corporate

Value Creation

Ownership
Interest

2008

2007

–

17.2

27.0%

2,013.2

944.8

32.1%

10.8

–

10%-35%

–

9.1

181.4

25.0

11.6

1.5

626.4

16.1

181.4

25.0

223.3

29.0

2,491.8

2,076.3

Equity investments include the unamortized excess of the purchase price over the underlying net book value of the
investee’s assets at the purchase date of $129.8 million at December 31, 2008 (2007 – $581.1 million). The excess is
attributable to the value of property, plant and equipment within the investees based on estimated fair values and is
amortized over the economic life of the assets. Consolidated retained earnings at December 31, 2008 include
undistributed earnings from equity investments of $9.5 million (2007 – $5.0 million).

THE PARTNERSHIP
The Company has a combined 27.0% ownership in EEP, through a 2.0% general partner interest, a 13.9% interest in
Class A units, a 3.4% interest in Class B units, a 5.5% interest in Class C units and a 2.2% interest in EEP via a 17.2%
investment in EEM, which owns 14.7% of EEP via its 100% interest in EEP’s i-units. The Company recorded
investment income from EEP of $161.6 million (2007 – $130.4 million; 2006 – $111.5 million) including
dilution gains.

ENBRIDGE INC.

ANNUAL REPORT 2008

101

Although 82.8% of EEM is widely held, the Company has voting control and; therefore, consolidates EEM, including its
investment in EEP of $691.0 million (2007 – $456.4 million). Net of non-controlling interest in EEM, the book value of
the Company’s investment in EEP is $1,440.9 million (2007 – $566.7 million.)

In the second quarter of 2007, EEP issued Class A and Class C partnership units. As Enbridge did not fully participate
in these offerings, dilution gains net of tax and non-controlling interest of $11.8 million resulted and Enbridge’s
ownership interest in the Partnership decreased from 16.6% to 15.1%.

In March 2008, EEP issued Class A units and, because Enbridge did not fully participate, a dilution gain of $4.5 million
resulted and Enbridge’s ownership interest in EEP decreased from 15.1% to 14.6%.

In November 2008, the Company subscribed for 16.3 million Class A common units of EEP for US$500.0 million
increasing its ownership interest from 14.6% to 27.0%. The units were acquired by the Company’s subsidiary EEC
which also contributed approximately US$10.0 million to maintain its 2.0% general partner interest.

In 2006, the Company acquired 5.4 million Class C units of EEP for $280.2 million. The Class C units have the same
voting rights as Class A and B units and are entitled to quarterly distributions equal to those paid to Class A and B
unitholders. Prior to August 15, 2009, distributions are paid in additional Class C units, where Class C units are valued
at the market value of Class A units. After August 15, 2009, distributions will be paid in cash and, subject to the
approval of existing Class A and Class B unitholders, Class C units will convert into Class A units on a one-to-one basis.
If approval of the conversion is not received, the Class C units will receive cash distributions equal to 115% of those
paid to Class A unitholders.

NOVERCO
The Company owns a preferred share investment in Noverco of $181.4 million (2007 – $181.4 million), which is
entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in
greater than 10 years plus 4.34%.

The Company also owns an equity investment in the common shares of Noverco of $10.8 million (2007 –
$11.6 million). Noverco owns an approximate 9.3% (2007 – 9.5%) reciprocal shareholding in the shares of the
Company. As a result, the Company has an indirect pro-rata interest of 3.0% (2007 – 3.1%) in its own shares. Both
the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of
$154.3 million (2007 – $154.3 million). Noverco records dividends paid by the Company as dividend income and the
Company eliminates these dividends from the earnings of Noverco. The Company records its pro-rata share of
dividends paid by the Company to Noverco as a reduction of dividends paid and an increase in the Company’s
investment in Noverco. In 2008, the Company recorded equity investment earnings of $4.4 million (2007 –
$8.5 million; 2006 – $16.8 million) related to its interest in Noverco.

CORPORATE
The Company reviews the carrying value of its long-term investments on a regular basis as events or changes in
circumstances warrant. During 2008, one of the Company’s equity investments, N-Solv, a developer of in-situ oil
sands extraction technology, failed a key milestone when its planned demonstration pilot plant was terminated. A
writedown of $7.2 million was taken to adjust the carrying value of the investment to its fair value of $6.8 million.

CLH
On June 17, 2008, the Company sold its 25% equity interest in CLH (Note 5).

OCENSA
The Company owns an investment in OCENSA, a crude oil export pipeline in Colombia of $223.3 million
(US$160.2 million) (2007 – $223.3 million; US$160.2 million), which earns a fixed rate of return.

102

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

11. DEFERRED AMOUNTS AND OTHER ASSETS

December 31,

(millions of Canadian dollars)

Regulatory deferrals

Contractual receivables

Long-term portion of derivative assets (Note 22)

Pension asset

Affiliate long-term note receivable (US$130.0 million) (Note 28)

Other

2008

2007

510.2

158.7

316.9

78.3

159.2

95.1

428.2

152.0

329.0

72.3

128.5

72.0

1,318.4

1,182.0

At December 31, 2008, deferred amounts of $42.4 million (2007 – $42.3 million) were subject to amortization and
are presented net of accumulated amortization of $23.5 million (2007 – $23.2 million). Amortization expense in 2008
was $3.0 million (2007 – $3.6 million; 2006 – $10.1 million).

12. INTANGIBLE ASSETS

December 31, 2008

(millions of Canadian dollars)

Transportation agreements

Customer lists

December 31, 2007

(millions of Canadian dollars)

Transportation agreements

Customer lists

Weighted Average
Amortization Rate

4.2%

7.1%

Weighted Average
Amortization Rate

4.2%

7.1%

Cost

268.1

10.3

278.4

Cost

241.8

8.3

250.1

Accumulated
Amortization

50.1

3.0

53.1

Accumulated
Amortization

36.3

1.8

38.1

Net

218.0

7.3

225.3

Net

205.5

6.5

212.0

Total amortization expense for intangible assets was $10.6 million for the year ended December 31, 2008
(2007 – $10.4 million; 2006 – $11.0 million). In the next five years, the Company expects the following aggregate
amortization expense.

(millions of Canadian dollars)

2009

2010

2011

2012

2013

13. GOODWILL

(millions of Canadian dollars)

Balance at January 1, 2007

Foreign exchange and other

Balance at December 31, 2007

Goodwill impairment

Foreign exchange and other

Balance at December 31, 2008

9.7

9.3

8.9

8.5

8.1

Liquids
Pipelines

Gas
Pipelines

Sponsored Investments

Credit facilities

Medium term notes

Senior notes

Fair value increment on senior notes acquired

Gas Distribution and Services

Term debt

(US$21.6 million; 2007 – US$15.7 million)

Capital lease obligations

Deferred debt issue costs

Total Non-Recourse Debt

Current Maturities

Non-Recourse Long-Term Debt

Weighted Average
Interest Rate

Maturity

2008

2007

2012

1.2

1.9

6.76%

10.62%

2015-2025

2013-2020

4.69%

6.86%

2011-2012

2009-2014

2015-2025

4.10%

12.00%

2009-2010

2016-2021

506.8

47.4

174.1

190.0

679.0

38.2

26.6

5.7

(10.3)

1,658.7

(184.7)

1,474.0

436.5

39.9

141.5

190.0

707.7

43.3

15.5

4.9

(11.7)

1,569.5

(61.1)

1,508.4

Long-term debt maturities on non-recourse borrowings for the years ending December 31, 2009 through 2013 are
$184.7 million, $92.4 million, $76.4 million, $81.9 million and $144.2 million, respectively. The medium term notes
and senior notes bear interest at fixed rates.

Interest obligations on non-recourse borrowings for the years ending December 31, 2009 through 2013 are
$93.8 million, $85.0 million, $79.4 million, $74.0 million and $68.1 million, respectively.

Certain assets of Alliance Pipeline Canada, with a carrying value of $1.1 billion, are pledged as collateral to Alliance
Pipeline Canada’s lenders and to the lenders to Alliance Pipeline US. As well, certain assets of Alliance Pipeline US,
with a carrying value of $1.0 billion, are pledged as collateral to Alliance Pipeline US’s lenders and to the lenders to
Alliance Pipeline Canada.

Non-recourse debt has a fair value of $1,671.7 million (2007 – $1,634.8 million).

17. NON-CONTROLLING INTERESTS

December 31,

(millions of Canadian dollars)

EEM

EGD Preferred Shares

EIF

EGNB

Other

2008

2007

481.0

100.0

146.9

57.1

12.4

797.4

335.1

100.0

155.9

48.8

10.7

650.5

Non-controlling interest in EEM represents the 82.8% of the listed shares of EEM not held by the Company.

The Company owns 100% of the common shares of EGD; however, the 4,000,000 4.82% Cumulative Redeemable
EGD Preferred Shares held by third parties are entitled to a claim on the assets of EGD prior to the common
shareholder. Subsequent to July 1, 2009, EGD may, at its option, redeem all or a portion of the outstanding preferred
shares for $25.00 plus all accrued and unpaid dividends to the redemption date. The preferred shares have no fixed
maturity date.

106

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Non-controlling interest in EIF represents 58.1% of voting units which are held by public unitholders. Non-controlling
interest in EGNB represents 29.1% held by third parties.

18. 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

2008

2007

2006

December 31,

Number
of Shares

Amount

Number
of Shares

Amount

Number
of Shares

Amount

(millions of Canadian dollars; number of common shares in millions)

Balance at beginning of year

368.5

3,026.5

351.8

2,416.1

348.9

2,343.8

Common shares issued

Exercise of stock options

Dividend Reinvestment

–

1.3

–

36.2

15.0

1.2

566.4

26.3

and Share Purchase Plan

3.2

131.3

0.5

17.7

–

2.4

0.5

–

53.9

18.4

Balance at end of year

373.0

3,194.0

368.5

3,026.5

351.8

2,416.1

PREFERRED SHARES
The 5.0 million 5.5% Cumulative Redeemable Preferred Shares, Series A are entitled to fixed, cumulative, quarterly
preferential dividends of $1.375 per share per year. The Company may, at its option, redeem all or a portion of the
outstanding preferred shares for $25.00 per share plus all accrued and unpaid dividends.

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 11.1 million shares
(2007 – 11.1 million shares), resulting from the Company’s reciprocal investment in Noverco.

The treasury stock method is used to determine the dilutive impact of stock options. This method assumes that any
proceeds from the exercise of stock options would be used to purchase common shares at the average market price
during the period.

December 31,

(number of common shares in millions)

Weighted average shares outstanding

Effect of dilutive options

Diluted weighted average shares outstanding

2008

2007

2006

359.8

3.3

363.1

355.3

3.0

358.3

340.0

3.3

343.3

For the year ended December 31, 2008, 2,879,800 anti-dilutive stock options (2007 – 1,158,200; 2006 –
1,548,900) with a weighted average exercise price of $40.53 (2007 – $38.26; 2006 – $36.47) were excluded from
the diluted earnings per share calculation.

DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN
Under the Dividend Reinvestment and Share Purchase Plan, registered shareholders may reinvest dividends in
common shares of the Company and make additional optional cash payments to purchase common shares, free of
brokerage or other charges. Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a
2% discount on the purchase of common shares with reinvested dividends.

ENBRIDGE INC.

ANNUAL REPORT 2008

107

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 its 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 Company’s Board of Directors.
Should such an acquisition 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.

19. STOCK OPTION AND STOCK UNIT PLANS

The Company maintains four long-term incentive compensation plans: the Incentive Stock Option (ISO) Plan, the
Performance Based Stock Option (PBSO) Plan, the Performance Stock Unit (PSU) Plan and the Restricted Stock Unit
(RSU) Plan. A maximum of 30 million common shares were reserved for issuance under the 2002 ISO plan, of which
16 million have been issued to date. In 2007, a new reserve of 16.5 million shares was approved and established for
the 2007 ISO and PBSO plans, of which none have been issued to date. The PSU and RSU plans grant notional units
as if a unit was one Enbridge common share and are payable in cash.

INCENTIVE STOCK OPTIONS
Key employees are granted ISOs to purchase common shares at the market price on the grant date. ISOs vest in equal
annual installments over a four-year period and expire 10 years after the issue date. Compensation expense recorded
for the year ended December 31, 2008 for ISOs is $13.0 million (2007 – $9.0 million; 2006 – $10.5 million).

Outstanding Incentive Stock Options

December 31,

Number

(options in thousands; exercise price in Canadian dollars)

Options at beginning of year

Options granted

Options exercised

Options cancelled or expired

Options at end of year

Options vested

9,237

2,642

(1,178)

(51)

10,650

6,087

2008

2007

Weighted
Average
Exercise Price

27.24

40.54

21.85

36.83

31.05

25.32

Weighted
Average
Exercise Price

24.97

38.26

19.21

32.97

27.24

22.87

Number

9,186

1,158

(1,046)

(61)

9,237

5,865

2006

Weighted
Average
Exercised Price

22.09

36.41

19.38

28.81

24.97

20.54

Number

9,434

1,595

(1,698)

(145)

9,186

5,323

The total intrinsic value of ISOs exercised during the year ended December 31, 2008 was $22.9 million (2007 –
$19.1 million; 2006 – $27.8 million) and cash received on exercise was $25.7 million (2007 – $20.1 million; 2006 –
$32.9 million). Intrinsic value represents the difference between the Company’s share price and the exercise price,
multiplied by the number of options. The total intrinsic value of ISOs outstanding and vested at December 31, 2008
was $109.0 million and $97.2 million, respectively.

108

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Incentive Stock Option Characteristics

December 31, 2008

Options Outstanding

Exercise Price Range

Number

(options in thousands; exercise price in Canadian dollars)

Weighted
Average
Remaining
Life (years)

Weighted
Average
Exercise Price

10.00-14.99

15.00-19.99

20.00-24.99

25.00-29.99

30.00-34.99

35.00-39.99

40.00-44.99

45.00-49.99

401

731

1,914

1,189

1,252

2,533

2,072

558

10,650

1.2

1.7

3.6

5.0

6.1

7.5

9.1

6.1

13.30

18.55

21.30

25.74

31.79

37.26

40.42

49.61

31.54

Options Vested

Weighted
Average
Remaining
Life (years)

Weighted
Average
Exercise Price

1.2

1.7

3.6

5.0

6.0

7.4

–

4.4

13.30

18.55

21.30

25.74

31.75

36.98

–

25.32

Number

401

731

1,914

1,189

892

960

–

6,087

The total fair value of options vested for the ISO Plan was $9.1 million at December 31, 2008 (2007 – $7.5 million;
2006 – $5.8 million).

Weighted average assumptions used to determine the fair value of the ISOs using the Black-Scholes option pricing
model are as follows:

Year ended December 31,

Fair value per option (Canadian dollars) 1

Valuation assumptions

Expected option term (years) 2

Expected volatility 3

Expected dividend yield 4

Risk-free interest rate 5

2008

6.14

18.48%

3.34%

3.50%

2007

6.16

18.10%

3.22%

4.11%

2006

6.30

19.00%

3.23%

4.16%

1 Beginning in 2008, options granted to U.S. employees are based on NYSE prices. The option value and assumptions shown for 2008 are based on a weighted

average of the U.S. options and the Canadian options. The fair values per option were $6.20 for Canadian employees and US$5.82 for U.S. employees.

The expected option term is based on historical information.

Expected volatility is based on historical information from both the Toronto Stock Exchange and the New York Stock Exchange.

The expected dividend yield is the current annual dividend divided by the current stock price.

The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the U.S. Treasury Bond Yields.

As of December 31, 2008, unrecognized compensation cost related to non-vested share-based compensation
arrangements granted under the ISO plan was $9.7 million. The cost is expected to be recognized over a period of
2.5 years.

PERFORMANCE BASED STOCK OPTIONS
PBSOs are granted to executive officers and become exercisable when both performance targets and time vesting
requirements have been met. PBSOs were granted on September 16, 2002, August 15, 2007 and February 19, 2008.
The 2008 PBSO grant is included in the 2007 PBSO plan. All performance targets and time vesting requirements for
the 2002 PBSO grant have been met. The 2002 PBSO grant will expire on September 16, 2010. The 2007 and 2008
PBSO grants performance targets are based on the Company’s share price. Time vesting requirements for the 2007
PBSO grant are fulfilled evenly over a five-year term, ending August 15, 2012. Time vesting requirements for the 2008
PBSO grant were modified to a four and a half year term and will be completed concurrently with the 2007 grant on
August 15, 2012. Under the 2007 PBSO plan performance vesting targets must be met by February 15, 2014,
otherwise the options expire. If targets are met by February 15, 2014, the options are exercisable until August 15,
2015. Compensation expense recorded for the year ended December 31, 2008 for PBSOs was $1.8 million (2007 –
$0.7 million).

ENBRIDGE INC.

ANNUAL REPORT 2008

109

Outstanding Performance Based Stock Options

December 31,

Number

(options in thousands; exercise price in Canadian dollars)

Options at beginning of year

3,588

Options granted

Options exercised

Options cancelled

Options at end of year

Options vested

250

(100)

–

3,738

1,143

2008

2007

2006

Weighted
Average
Exercise Price

31.92

40.42

23.15

–

32.72

23.15

Weighted
Average
Exercise Price

23.15

36.57

23.15

–

31.92

23.15

Number

1,379

2,345

(136)

–

3,588

1,243

Weighted
Average
Exercise Price

21.57

–

18.00

23.15

Number

2,105

–

(645)

(81)

1,379

1,119

The total intrinsic value of PBSOs exercised during the year ended December 31, 2008 was $1.8 million (2007 –
$1.9 million; 2006 – $11.4 million) and cash received on exercise was $2.3 million (2007 – $3.1 million; 2006 –
$11.6 million). The total intrinsic value of PBSOs outstanding and vested at December 31, 2008 is $32.0 million and
$20.7 million, respectively.

Performance Based Stock Option Characteristics

December 31, 2008

Options Outstanding

Exercise Price

Number

(options in thousands; exercise price in Canadian dollars)

23.15

36.57

40.42

1,143

2,345

250

3,738

Weighted
Average
Remaining
Life (years)

Weighted
Average
Exercise Price

1.7

6.6

5.1

23.15

36.57

40.42

32.72

Options Vested

Weighted
Average
Remaining
Life (years)

Weighted
Average
Exercise Price

1.7

–

1.7

23.15

–

23.15

Number

1,143

–

1,143

The total fair value of options vested for the PBSO Plan was $1.8 million at December 31, 2008 (2007 – $1.7 million;
2006 – $1.2 million).

Assumptions used to determine the fair value of the PBSOs using the Bloomberg barrier option valuation model are
as follows:

Year ended December 31,

Fair value per option (Canadian dollars)

Valuation assumptions

Expected option term (years) 1

Expected volatility 1

Expected dividend yield 2

Risk-free interest rate 3

2008

4.82

13.60%

3.32%

3.75%

2007

3.40

13.60%

3.57%

4.38%

The expected option term and the expected volatility are based on historical information.

The expected dividend yield is the current annual dividend divided by the current stock price.

The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the U.S. Treasury Bond Yields.

As of December 31, 2008, unrecognized compensation cost related to non-vested share-based compensation
arrangements granted under the PBSO plan was $6.7 million. The cost is expected to be recognized over a period of
3.7 years.

PERFORMANCE STOCK UNITS
The Company has a PSU Plan for senior officers where cash awards are paid following a three-year performance
cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by
the Company’s weighted average share price and by a performance multiplier. The performance multiplier ranges
from 0, if the Company’s performance fails to meet threshold performance levels, to a maximum of 2, if the Company

110

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

performs within the highest range of its performance targets. The performance multiplier for the 2006 grant was based
on the Company’s total shareholder return over the three-year performance period relative to a specified peer group of
companies. The 2007 and 2008 grants derive the performance multiplier through a calculation of the Company’s
Price/Earnings ratio relative to a specified peer group of companies and the Company’s growth in earnings per share
relative to targets established at the time of grant.

Compensation expense recorded for the year ended December 31, 2008 for PSUs was $12.6 million (2007 –
$3.0 million; 2006 – $4.1 million). An estimated performance multiplier of 1.62, 1.45 and 1.93 was used to calculate
the expense based upon historical performance for the 2006, 2007 and 2008 grants, respectively.

Outstanding Performance Stock Units

December 31,

Units at beginning of year

Units granted

Units cancelled

Units matured

Dividend reinvestment

Units at end of year

2008

267,616

144,300

2007

328,716

137,200

–

(2,384)

(129,852)

(209,827)

2006

200,652

117,900

–

13,364

13,911

10,164

295,428

267,616

328,716

Of the PSUs outstanding at December 31, 2008, 146,444 units have a performance period ending December 31,
2009 and 148,984 units have a performance period ending December 31, 2010. The total intrinsic value of PSUs
outstanding at December 31, 2008 is $21.0 million (2007 – $10.7 million; 2006 – $12.7 million).

RESTRICTED STOCK UNITS
Enbridge has a RSU plan where cash awards are paid to certain non-executive employees of the Company following a
thirty-five month maturity period. RSU holders receive cash equal to the Company’s weighted average share price
multiplied by the units outstanding on the maturity date. Compensation expense recorded for the year ended
December 31, 2008 for RSUs was $15.4 million (2007 – $7.1 million; 2006 – $0.8 million).

Outstanding Restricted Stock Units

December 31,

Units at beginning of year

Units granted

Units cancelled

Units matured

Dividend reinvestment

Units at end of year

2008

456,621

418,700

2007

183,253

276,875

(23,352)

(18,627)

(179,940)

–

2006

–

181,882

–

28,005

15,120

1,371

700,034

456,621

183,253

The total intrinsic value of RSUs outstanding at December 31, 2008 is $29.4 million (2007 – $18.3 million; 2006 –
$7.7 million).

As of December 31, 2008, unrecognized compensation expense related to non-vested units granted under the PSU
and RSU plans was $27.8 million, expected to be recognized over a period of 1.7 years.

ENBRIDGE INC.

ANNUAL REPORT 2008

111

20. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

Cash Flow
Hedges

Equity
Investees

Non-
Controlling
Interests

Cumulative
Translation
Adjustment

Net
Investment
Hedges

Total

(millions of Canadian dollars)

Balance at January 1, 2006

Tax impact

Changes during the period

Tax impact

Balance at December 31, 2006

Adjustment on adoption (Note 2)

Tax impact

Changes during the period

Tax impact

Balance at December 31, 2007

Changes during the period

Tax impact

Balance at December 31, 2008

21. RISK MANAGEMENT

–

79.4

(20.3)

59.1

94.8

(5.1)

89.7

148.8

(175.8)

47.1

(128.7)

20.1

–

(57.3)

20.1

(37.2)

(29.2)

9.4

(19.8)

(57.0)

78.5

(29.3)

49.2

(7.8)

–

26.3

–

26.3

4.9

–

4.9

31.2

(19.6)

–

(486.7)

428.1

(58.6)

–

(113.2)

(486.7)

314.9

(171.8)

87.6

–

87.6

(49.0)

(2.6)

(51.6)

38.6

(2.6)

36.0

(399.1)

263.3

(135.8)

–

(447.1)

–

(447.1)

(846.2)

576.8

–

193.9

(19.0)

174.9

438.2

(179.8)

19.9

48.4

(0.2)

48.2

(182.7)

(14.7)

(197.4)

(285.0)

280.1

37.7

317.8

32.8

(19.6)

576.8

(159.9)

11.6

(269.4)

278.3

MARKET PRICE RISK
The Company’s earnings are subject to movements in interest rates, foreign exchange rates and commodity prices
(collectively, market price risk). Formal risk management policies, processes and systems have been designed to
mitigate these risks.

Earnings at Risk (EaR) is the principal risk management metric used to quantify market price risk at Enbridge. EaR is
an objective, statistically derived risk metric that measures, with a 97.5% level of confidence, the maximum adverse
change in projected 12-month earnings that could result from market price risk over a one-month period. The
Company’s policy is to target a maximum EaR of 5% of earnings.

The Company calculates EaR using Monte Carlo simulation to produce projections of earnings using a randomly
generated series of forecasted market prices and Enbridge’s current market exposures. Historical statistical
distributions of market prices and the correlation among those market prices are used to generate an entire probability
distribution of possible deviations from forecast earnings. The following summarizes the types of market price risks to
which the Company is exposed and the risk management instruments used to mitigate them.

COMMODITY PRICE RISK
The Company is exposed to gains or losses due to changes in the market price of commodities. The Company may use
natural gas, power, crude oil and natural gas liquids swaps, collars or options to manage the value of variable price
exposures that arise from commodity usage, storage, transportation and supply agreements.

Earnings and OCI impacts from unrealized changes in the commodity risk management instruments mentioned above
are driven by revaluation of these instruments at the balance sheet date. Sensitivities are based on the Company’s
estimate of a reasonably possible change in the price of the underlying commodity and each commodity sensitivity
analysis has been calculated independently of each other. For example, increasing the price of crude oil assumes that
the price of gas remains constant and that only instruments impacted directly by an increase in the price of crude oil

112

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

are affected. The impact of various price increases to commodities at December 31, 2008 would have had the
following impact on earnings:

Unit

Increase per unit

(millions of Canadian dollars)

After-tax impact

Earnings

OCI

Crude
(BBL)

$10.00

(21.4)

(3.0)

NGL
(gallons)

$0.25

Gas
(MMBTU)

$1.00

(0.1)

(7.4)

4.1

16.8

Power
(MWh)

$5.00

(0.3)

(0.5)

Fractionation
Margins
(gallon)

US$0.10

(1.5)

(2.2)

FOREIGN EXCHANGE RISK
The Company is exposed to both transaction and translation risk due to the volatility of foreign currency exchange
rates. The Company has exposure to foreign currency exchange rates, primarily arising from its U.S. dollar
denominated investments and, to a lesser extent, its monetary assets and liabilities denominated in this currency.

The carrying values of these assets and liabilities as well as the comprehensive income and earnings derived from
them, are subject to foreign exchange rate fluctuation. The Company uses par forward contracts and cross currency
swaps to manage a portion of the foreign exchange exposure related to changes in the carrying values, cashflows and
earnings of its U.S. dollar denominated investments. The Company uses some of its U.S. dollar denominated debt to
hedge the carrying values of certain equity investments. In addition, the Company uses short and long-term foreign
exchange forward contracts to manage exposure related to foreign currency denominated receivables, payables and
long-term debt.

The Canadian dollar carrying values of the Company’s equity investments and monetary assets and liabilities
denominated in U.S. dollars at December 31, 2008 are summarized below.

(millions of Canadian dollars)

Net Working Capital

Equity Investments

Long-Term Debt

Assets/
(Liabilities)

(223.3)

1,939.7

(2,112.3)

The impact of a $0.05 strengthening of the Canadian dollar relative to the US dollar at December 31, 2008, would
have resulted in a $58.4 million increase to earnings and a $19.4 million increase to OCI, due to the revaluation of
currency derivatives. Under Section 3862 of the CICA Handbook, the calculation of sensitivity to foreign exchange risk
is limited to financial instruments denominated in currencies other than the functional currency in which they are
measured and transacted. The sensitivity to changes in foreign exchange rates at the balance sheet date is primarily
driven by changes in the fair value of derivative instruments. The $0.05 increase in exchange rates is presumed to
have caused a parallel shift in the forward exchange rates used to value financial derivatives maturing in
future periods.

INTEREST RATE RISK
The Company is exposed to cashflow and revaluation risk due to the volatility of interest rates. Cash flows are impacted
by changes in market interest rates on variable rate debt (primarily commercial paper). Floating to fixed interest rate
swaps, collars and forward rate agreements are used to mitigate cash flow volatility due to future interest rate
fluctuation. The Company is also exposed to cash flow interest rate risk on fluctuations in market interest rates ahead
of anticipated fixed rate debt issuances. The Company may enter into interest rate derivatives such as bond forwards
and treasury locks to fix a portion of the interest payments of these future debt issuances. The Company monitors its
fixed and variable rate debt instruments, targeting a debt portfolio mix of up to 25% floating rate debt as a percentage
of total debt outstanding. Fixed to floating swaps are also used from time to time to manage this position and optimize
the Company’s debt portfolio. The fair value of existing fixed rate long-term debt is also impacted by changes in market
interest rates. The Company does not typically manage the fair value risk of its debt instruments.

A 1.0% increase in interest rates would have caused a $13.7 million increase in OCI at December 31, 2008 due to the
revaluation of interest rate derivatives, all of which are designated hedging instruments in cash flow hedging
relationships. The sensitivity has been calculated assuming a 1.0% shift in interest rates across the yield curve.

ENBRIDGE INC.

ANNUAL REPORT 2008

113

EQUITY PRICE RISK
Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has
exposure to its own common share price through the issuance of various forms of stock based compensation, which
affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to
manage the earnings volatility derived from one form of stock based compensation, RSUs (Note 19).

Due to revaluation of the equity derivative contracts at December 31, 2008, the impact of a $4 increase in the
Company’s share price would have been a $0.9 million increase in earnings and a $1.1 million increase in OCI.

SUMMARY OF DERIVATIVE INSTRUMENTS USED FOR RISK MANAGEMENT
The current portion of derivative assets or liabilities is included in Accounts Receivable and Other or Accounts Payable
and Other, while the long-term portion is included in Deferred Amounts and Other Assets or Other Long-Term
Liabilities.

Total Derivative Instruments

December 31,

Notional
Principal
or Quantity

2008

Derivative
Asset/
(Liability)

Notional
Principal
or Quantity

Maturity

2007

Derivative
Asset/
(Liability)

Maturity

(millions of Canadian dollars unless otherwise noted)

Foreign exchange

U.S. cross currency swaps

138.0

26.1

2013-2022

138.0

46.7

2013-2022

U.S. Forwards

(cumulative exchange amounts)

3,943.6

269.5

2009-2022

2,608.0

226.3

2008-2022

Interest rates

Interest rate swaps/collars

1,164.4

(33.0)

2009-2029

1,117.0

(8.6)

2008-2029

Equity price

Forwards (millions of shares)

0.7

(4.8)

2009-2010

–

Energy commodities

Energy commodity (bcf)

Power (MW/H)

529.9

57.0

18.6

15.8

2009-2010

2009-2024

452.9

57.0

(43.5)

2008-2010

20.6

2008-2024

The fair value of derivative instruments has been estimated using period end market information. This market
information includes observable inputs such as published market prices for commodities, interest rate yield curves
and foreign exchange rates. When possible, financial instruments are valued using quoted market prices.

Derivative Instruments used as Cash Flow Hedges

December 31,

Notional
Principal
or Quantity

2008

Derivative
Asset/
(Liability)

Notional
Principal
or Quantity

Maturity

2007

Derivative
Asset/
(Liability)

Maturity

(millions of Canadian dollars unless otherwise noted)

Foreign exchange

U.S. cross currency swaps

138.0

26.1

2013-2022

138.0

Forwards (cumulative exchange amounts) 1,661.9

164.4

2009-2022

1,761.4

46.7

138.1

2013-2022

2008-2022

Interest rates

Interest rate swaps/collars

1,164.4

(33.0)

2009-2029

1,117.0

(8.6)

2008-2029

Equity price

Forwards (millions of shares)

0.7

(2.8)

2009-2010

–

Energy commodities

Energy commodity (bcf)

Power (MW/H)

26.4

2.0

(58.3)

2009-2010

(3.4)

2009-2024

43.6

2.0

3.2

2008-2010

(2.1)

2008-2017

The Company estimates that $48.4 million of accumulated other comprehensive loss related to cash flow hedges will
be reclassified to earnings in the next 12 months.

114

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Derivative and Other Financial Instruments used as Net Investment Hedges

Notional
Principal
or Quantity

2008

Derivative
Asset/
(Liability)

Notional
Principal
or Quantity

Maturity

2007

Derivative
Asset/
(Liability)

Maturity

December 31,

(millions of Canadian dollars)

Foreign exchange

Forwards (cumulative exchange amounts)

441.9

71.0

2014-2020

749.9

187.0

2013-2020

The Company has also designated a US$300 million medium-term note and US$189.4 million of commercial paper
as hedges of certain U.S. dollar investments.

During the year, the Company terminated certain par forward currency exchange instruments for proceeds of
$48.2 million. These instruments hedged US$162.4 million of the Company’s U.S. dollar long-term investments and
were accounted for as net investment hedges with the fair value recorded as long-term assets on the balance sheet
with an equal and offsetting amount recorded in AOCI. No gain or loss related to the terminations was recorded in the
Company’s earnings.

FAIR VALUE HEDGES
As at December 31, 2008, the Company did not have any outstanding fair value hedges.

UNREALIZED GAINS AND LOSSES ON NON-QUALIFYING DERIVATIVES
The Company does not use derivative instruments for speculative purposes; however, if a derivative instrument is not
an effective hedge for accounting purposes or is not designated as a hedging item, changes in the fair value are
recorded in current period earnings. For the year ended December 31, 2008, the Company had an after tax
unrealized gain of $75.3 million (2007 – $32.3 million loss) related to non-qualifying derivatives. Realized losses on
non-qualifying derivative instruments for the year ended December 31, 2008 were $35.6 million (2007 –
$9.9 million), after tax.

The Company’s regulated Liquids Pipelines segment uses a fixed price contract and related financial instrument to
manage floating power costs. The Company recognizes the fair value of the fixed price contract, the fair value of the
financial instrument and a regulatory liability that will be recognized over the life of the fixed price contract. At
December 31, 2008, the Company recognized a liability of $3.4 million for unrealized financial instrument losses, an
asset of $24.3 million related to the fixed price power contract and a regulatory liability of $20.9 million.

LIQUIDITY RISK
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and
guarantees (see Notes 29 and 30), as they become due. In order to manage this risk, the Company forecasts the cash
requirements over the near and long term to determine whether sufficient funds will be available. The Company’s
primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial
paper and draws under committed credit facilities and longer term debt which includes debentures and medium-term
notes. The Company maintains current shelf prospectuses with the securities regulators, which enables, subject to
market conditions, ready access to either the Canadian or U.S. public capital markets. In addition, the Company
maintains sufficient liquidity through committed credit facilities (see Note 15), with a diversified group of banks and
institutions, which would enable the Company to fund all anticipated requirements for one year without accessing the
capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities and
expects to be in compliance throughout 2009. Therefore, the entire credit facility is available to the Company and the
banks are obligated to fund and have been funding the Company under the terms of the facility. The Company expects
to generate sufficient cash from operations and commercial paper issuances and draws under its committed credit
facilities to fund liabilities as they become due, finance planned investing activity and pay common share dividends
throughout the year. Additional liquidity, if necessary, is expected to be available through access to the capital markets.

Maturities of Financial Liabilities
The Company generally has no financial liabilities maturing beyond one year with the exception of its long-term
debt (Notes 15 and 16).

ENBRIDGE INC.

ANNUAL REPORT 2008

115

CREDIT RISK
Entering into derivative financial instruments can result in exposure to credit risk. 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. In light of economic conditions at the balance sheet date, the Company
has placed increased scrutiny around its credit exposures with significant financial institutions. The Company enters
into risk management transactions only with institutions that possess investment grade credit ratings. Credit risk
relating to derivative counterparties is mitigated by credit exposure limits, contractual and collateral requirements,
frequent assessment of counterparty credit ratings and netting arrangements. At December 31, 2008, the Company
has a maximum exposure to credit risk of $388.5 million related to its derivative counterparties.

Credit risk also arises from trade and other long-term receivables, which is mitigated through credit exposure limits,
contractual and collateral requirements, assessment of credit ratings and netting arrangements. Credit risk in the Gas
Distribution and Services segment is mitigated by the large and diversified customer base and the ability to recover an
estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength
of large industrial customers, and in select cases has recently tightened credit terms including obtaining additional
security, to minimize the risk of default on receivables. Generally, the Company classifies receivables older than
30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying
value, as disclosed in the financial instruments summary table below.

The change in the allowance for doubtful accounts in respect of accounts receivable is detailed below.

Year ended December 31,

(millions of Canadian dollars)

Balance at beginning of year

Additional allowance

Amounts used

Amounts reversed

Balance at end of year

2008

2007

(55.4)

(37.1)

22.3

1.2

(69.0)

(50.6)

(23.6)

18.6

0.2

(55.4)

The allowance for doubtful accounts is determined based on collection history. When the Company has determined
that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts
are applied against the impaired accounts receivable.

Estimated costs associated with uncollectible accounts receivables in EGD are recovered through regulated
distribution rates, which largely limits the Company’s exposure to credit risk related to accounts receivable, to the
extent such estimates are accurate.

Net derivative asset maturities for the years ending December 31, 2009 though 2013 and thereafter are $6.8 million,
$15.1 million, $28.7 million, $30.1 million, $36.8 million and $151.2 million.

116

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

22. FAIR VALUE OF FINANCIAL INSTRUMENTS

(millions of Canadian dollars)

Financial Assets

Cash and cash equivalents

Accounts receivable and other

Available for sale 1

Held to maturity 2

Current derivative assets 3

Long-term derivative assets 3

Long-term notes receivable

Financial Liabilities

Accounts payable and other deferred

amounts

Short-term borrowings

Long-term debt 4

Current derivative liabilities 3

Long-term derivative liabilities 3

December 31, 2008

December 31, 2007

Carrying Value

Fair Value

Carrying Value

Fair Value

541.7

2,074.0

81.1

404.7

71.6

316.9

166.9

541.7

2,074.0

n/a

359.2

71.6

316.9

132.6

166.7

2,095.4

75.0

404.7

79.5

368.5

133.8

166.7

2,095.4

n/a

379.5

79.5

368.5

133.0

2,100.8

874.6

2,100.8

874.6

2,095.5

545.6

2,095.5

545.6

13,323.9

12,786.0

10,509.1

10,489.0

49.4

46.5

95.8

46.5

82.4

64.0

82.4

64.0

Available for sale investments do not trade on an actively quoted market and no fair value disclosure is available.

2 Held to maturity investments include instruments denominated in U.S. dollars that have a fair value less than carrying value due to exchange rate fluctuations.

This decline in fair value is considered temporary.

3 Derivative assets and liabilities include those derivatives used in hedging relationships and non-qualifying derivatives.

Long-term debt includes non-recourse debt and excludes transaction costs.

The fair value of financial instruments reflects the Company’s best estimates of market value based on generally
accepted valuation techniques or models and supported by observable market prices and rates. When such prices are
not available, the Company uses discounted cash flow analysis from applicable yield curves based on observable
market inputs. The fair value of financial instruments, other than derivatives, represents the amounts that would have
been received from or paid to counterparties to settle these instruments at the reporting date.

The fair value of cash and cash equivalents and short-term borrowings approximates their carrying value due to their
short-term maturities.

The fair value of the Company’s long-term debt is based on quoted market prices for instruments of similar yield, credit
risk and tenure.

The fair value of other financial assets and liabilities other than derivatives approximate their cost due to the short
period to maturity. Changes in the fair value of financial liabilities are due solely to fluctuations in interest rates and
commodity prices as well as time value.

FAIR VALUE OF DERIVATIVES
The Company categorizes its derivative assets and liabilities measured at fair value into one of three different levels
depending on the observability of the inputs employed in the measurement.

Level 1
This category includes assets and liabilities measured at fair value based on unadjusted quoted prices for identical
assets and liabilities in active markets that are accessible at the measurement date. An active market for an asset or
liability is considered to be a market where transactions occur with sufficient frequency and volume to provide
pricing information on an ongoing basis. The Company’s Level 1 instruments consist primarily of exchange-traded
derivative instruments used to mitigate the risk of crude oil price fluctuations in its Liquids Pipelines and Energy
Services businesses.

Level 2
This category includes valuations determined using directly or indirectly observable inputs other than quoted prices
included within Level 1. Derivative instruments in this category are valued using models or other industry standard
valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted

ENBRIDGE INC.

ANNUAL REPORT 2008

117

forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for
the entire duration of the derivative instrument. Instruments valued using Level 2 inputs include non-exchange traded
derivatives such as over the counter foreign exchange forward and cross currency swap contracts, interest rate swaps,
physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can
be obtained. These instruments are used primarily in the Company’s Energy Services businesses and the
Corporate segment.

Level 3
This category includes valuations based on inputs which are less observable, unavailable or where the observable data
does not support a significant portion of the instruments’ fair value. Generally, Level 3 valuations are longer dated
transactions, occur in less active markets, occur at locations where pricing information is not available, or have no
binding broker quote to support Level 2 classification. The Company has developed methodologies, benchmarked to
industry standards, to determine fair value for these contracts based on extrapolation of observable future prices and
rates. Instruments valued using Level 3 inputs include long dated derivative power, NGL and natural gas contracts in
its Liquids Pipelines and Energy Services businesses.

When possible the estimated fair value is based on quoted market prices, and, if not available, estimates from third
party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, the Company’s uses standard
valuation techniques to calculate fair value. These methods include discounted mark to market for forwards, futures
and swaps and Black-Scholes for options. Primary inputs to these techniques include observable market prices
(interest, foreign exchange and commodity) and volatility, depending on the type of derivative and nature of the
underlying risk. The Company uses inputs and data used by willing market participants when valuing derivatives and
considers its own credit default swap spread as well as those of its counterparties in its determination of fair value.
Where possible the Company uses observable inputs.

The fair value hierarchy of financial assets and liabilities accounted for at fair value on a recurring basis at
December 31, 2008 are as follows.

(millions of Canadian dollars)

Financial assets:

Current derivative assets

Long-term derivative assets

Financial liabilities:

Current derivative liabilities

Long-term derivative liabilities

Level 1

Level 2

Level 3

Total

422.2

161.8

430.8

183.9

266.4

2,105.1

263.4

1,831.0

802.3

256.4

766.2

246.6

1,490.4

2,523.3

1,460.4

2,261.5

Changes in the fair value of $135.1 million classified as Level 3 in the fair value hierarchy during the year ended
December 31, 2008, were as follows:

Fair value measurements using significant unobservable inputs (Level 3)

(millions of Canadian dollars)

Balance at beginning of year

Total gains/(losses), realized and unrealized

Included in earnings

Included in other comprehensive income

Purchases, issuances and settlements

Balance at end of year

Unrealized gains and losses are reported within commodity costs and other investment income.

2008

(89.2)

52.0

2.4

80.7

45.9

118

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

23. CAPITAL DISCLOSURES

The Company defines capital as shareholders’ equity (excluding AOCI and reciprocal shareholdings), long-term debt
(excluding non-recourse debt and transaction costs), short-term borrowings and non-controlling interests less cash
and cash equivalents (excluding cash and cash equivalents from joint ventures and other interests not exclusively
controlled by the Company). Non-recourse debt, including debt consolidated proportionately from joint venture
interests, is excluded from the Company’s definition of capital as it is not controlled or managed exclusively by
the Company.

The Company’s capital is calculated as follows:

December 31,

(millions of Canadian dollars)

Short-term borrowings

Long-term debt (includes current portion)

Non-controlling interests

Shareholders’ equity

Cash and cash equivalents

2008

2007

874.6

10,794.4

797.4

6,740.3

(469.3)

545.6

8,393.9

650.5

5,714.5

(115.9)

18,737.4

15,188.6

The Company’s objectives when managing capital are to maintain flexibility among:

(cid:127)

enabling its businesses to operate at the highest efficiency;
providing liquidity for growth opportunities; and
providing acceptable returns to shareholders.

These objectives are primarily met through maintenance of an investment grade credit rating, which provides access
to lower cost capital. Capital is available generally through the issuance of both short and long-term debt, and equity.

The Company monitors and manages its debt to debt plus equity ratio (excluding non-recourse debt), with a target
range of 60% to 70%, to meet its capital management objectives. The debt to capitalization ratio at December 31,
2008, including short-term borrowings but excluding non-recourse short and long-term debt, was 63.1%, compared
with 62.7% at the end of 2007.

The Company must adhere to covenants in its credit facilities that are used to backstop its commercial paper program.
These covenants include maintaining a minimum Consolidated Shareholders’ Equity balance of $1 billion or greater
and a debt to Unconsolidated Shareholders’ Equity of less than 1.5. As at December 31, 2008, the Company was in
compliance with these covenants.

Under terms of the Company’s Trust Indenture, in order to continue to issue long-term debt, the Company must
maintain a ratio of Consolidated Funded Obligations (essentially all debt except non-recourse debt) to Total
Consolidated Capitalization of less than 75%. Total Consolidated Capitalization consists of shareholders’ equity,
long-term debt, non-controlling interests and future income tax. As at December 31, 2008, the Company was in
compliance with this covenant.

ENBRIDGE INC.

ANNUAL REPORT 2008

119

24. INCOME TAXES

INCOME TAX RATE RECONCILIATION

Year ended December 31,

(millions of Canadian dollars)

Earnings before income taxes

Combined statutory income tax rate

Income taxes at statutory rate

Increase/(decrease) resulting from:

Tax rates and legislated tax changes

Future income taxes related to regulated operations

Non-taxable items, net

Higher/(lower) foreign tax rates

CLH disposition

Other

Income Taxes

Effective income tax rate

2008

2007

2006

1,836.6

31.3%

574.9

(11.4)

(15.3)

2.6

3.6

(82.2)

36.7

508.9

27.7%

916.3

33.9%

310.6

(62.8)

(5.8)

(18.5)

(6.4)

–

(7.9)

209.2

22.8%

814.6

34.4%

280.2

(63.0)

(10.5)

(21.4)

(6.7)

–

13.7

192.3

23.6%

In 2008, income taxes paid amounted to $161.2 million (2007 – $226.2 million; 2006 – $182.6 million).

COMPONENTS OF FUTURE INCOME TAXES

December 31,

(millions of Canadian dollars)

Net Future Income Tax Liabilities/(Assets)

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

Differences in accounting and tax bases of investments

Other comprehensive income

Loss carryforwards

Other

Total Net Future Income Tax Liability

2008

2007

790.3

452.3

(28.2)

(150.6)

48.8

1,112.6

608.6

337.0

42.4

(222.0)

22.9

788.9

Net future income tax liability of $1,112.6 million (2007 – $788.9 million) includes future income tax liabilities of
$1,290.8 million (2007 – $975.6 million) net of future tax assets of $178.2 million (2007 – $186.7 million).

At December 31, 2008, the Company has recognized the benefit of unused tax loss carryforwards of $451.6 million
(2007 – $665.1 million). Unused tax loss carryforwards expire as follows: 2011 – $0.1 million; 2012 – $0.7 million;
2013 – $1.3 million; 2014 – $0.1 million; 2015 – $3.8 million and 2021 and beyond – $445.6 million.

120

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

GEOGRAPHIC COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

Year ended December 31,

(millions of Canadian dollars)

Earnings before income taxes

Canada

United States

Other

Current income taxes

Canada

United States

Other

Future income taxes

Canada

United States

Current and future income taxes

25. POST EMPLOYMENT BENEFITS

2008

2007

2006

624.1

419.0

793.5

1,836.6

140.5

43.3

67.0

250.8

92.4

165.7

258.1

508.9

511.1

210.2

195.0

916.3

152.7

11.9

3.8

168.4

(36.3)

77.1

40.8

209.2

430.7

237.8

146.1

814.6

204.3

0.1

8.9

213.3

(112.0)

91.0

(21.0)

192.3

PENSION PLANS
The Company has three basic pension plans which provide either defined benefit or defined contribution pension
benefits, or both to employees of the Company. The Liquids Pipelines and Gas Distribution and Services pension plans
provide Company funded defined benefit pension and/or defined contribution benefits to Canadian employees of
Enbridge. The Enbridge U.S. pension plan provides Company funded defined benefit pension benefits for U.S. based
employees. The Company has four supplemental pension plans which provide pension benefits in excess of the basic
plans for certain employees.

The measurement date used to determine the plan assets and the accrued benefit obligation was September 30,
2008 for the Canadian pension plans and December 31, 2008 for the U.S. pension plan.

Defined Benefit Plans
Benefits payable from the defined benefit plans are based on members’ years of service and final average
remuneration. These benefits are partially inflation indexed after a member’s retirement. Contributions by the
Company are made in accordance with independent actuarial valuations and are invested primarily in publicly-traded
equity and fixed income securities. The effective dates of the most recent actuarial valuations and the next required
actuarial valuations for the basic plans are as follows:

Liquids Pipelines

Enbridge U.S.

Gas Distribution and Services

Effective Date of Most Recently
Filed Actuarial Valuation

Effective Date of Next Required
Actuarial Valuation

December 31, 2006

December 31, 2007

December 31, 2006

December 31, 2009

December 31, 2008

December 31, 2009

The defined benefit pension plan costs have been determined based on management’s best estimates and
assumptions of the rate of return on pension plan assets, rate of salary increases and various other factors including
mortality rates, terminations and retirement ages.

Defined Contribution Plans
Contributions are generally based on the employee’s age, years of service and remuneration. For defined contribution
plans, pension costs equal amounts required to be contributed by the Company. Pension costs in respect of these
plans during the year were $3.9 million (2007 – $3.6 million; 2006 – $3.0 million).

ENBRIDGE INC.

ANNUAL REPORT 2008

121

POST-EMPLOYMENT BENEFITS OTHER THAN PENSIONS
Post-employment benefits other than pensions primarily include supplemental health, dental, health spending
account 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 for the Company’s defined benefit pension plans and OPEB plans using the accrual method.

(millions of Canadian dollars)

Change in Accrued Benefit Obligation

Benefit obligation at beginning of year

183.4

193.2

1,100.4

1,109.0

OPEB

Pension Benefits

2008

2007

2008

2007

Service cost

Interest cost

Amendments

Employees’ contributions

Actuarial loss/(gain)

Benefits paid

Effect of exchange rate changes

Benefit obligation at end of year

Change in Plan Assets

Fair value of plan assets at beginning of year

Actual return on plan assets

Employer’s contributions

Employees’ contributions

Benefits paid

Other

Effect of exchange rate changes

Fair value of plan assets at end of year

Funded Status

Benefit obligation

Fair value of plan assets

Overfunded/(Underfunded) status at end of year

Contribution after measurement date

Unamortized prior service cost

Unamortized transitional obligation/(asset)

Unamortized net loss

5.2

11.5

–

0.6

(26.8)

(7.3)

12.7

179.3

47.8

(11.7)

8.2

0.6

(7.3)

–

8.2

45.8

(179.3)

45.8

(133.5)

1.1

–

10.8

24.6

4.7

10.1

–

0.4

(10.2)

(6.7)

(8.1)

183.4

50.2

1.7

8.1

0.4

(6.7)

–

(5.9)

47.8

(183.4)

47.8

(135.6)

1.0

–

12.1

32.9

Net amount recognized at end of year

(97.0)

(89.6)

52.4

64.9

(3.5)

–

(125.0)

(45.6)

31.7

43.8

57.9

0.1

–

(46.4)

(42.2)

(21.8)

1,075.3

1,100.4

1,309.9

(179.7)

33.3

–

(45.6)

(1.4)

24.8

1,227.1

104.8

44.1

–

(42.2)

(1.5)

(22.4)

1,141.3

1,309.9

(1,075.3)

1,141.3

(1,100.4)

1,309.9

66.0

1.9

7.4

(15.4)

167.0

226.9

209.5

–

12.8

(17.6)

13.5

218.2

The amounts recognized include all of the Company’s plans; however, the Gas Distribution and Services plans are
funded through regulated rates on a cash basis and are not recorded as net pension assets or liabilities. Excluding Gas
Distribution and Services plans, the Company’s plans using the accrual method provide for a net pension asset of
$73.8 million (2007 – $72.3 million) and a net OPEB liability of $21.5 million (2007 – $18.8 million). The pension
asset is recorded on the balance sheet in Deferred Amounts and Other Assets while the pension liability is recorded in
Other Long-Term Liabilities, with the current portion for each recorded in working capital accounts.

122

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The weighted average assumptions made in the measurement of the projected benefit obligations of the pension plans
and OPEB are as follows:

Year ended December 31,

Discount rate

Average rate of salary increases

2008

6.42%

OPEB

2007

5.71%

2006

5.37%

Pension Benefits

2008

6.59%

5.00%

2007

5.65%

5.00%

2006

5.27%

5.00%

NET PENSION PLAN AND OPEB COSTS RECOGNIZED

Year ended December 31,

(millions of Canadian dollars)

Benefits earned during the year

Interest cost on projected benefit obligations

Actual return on plan assets

Difference between actual and expected return on plan assets

Amortization of prior service costs

Amortization of transitional obligation

Amortization of actuarial loss

Amount charged to EEP

Pension and OPEB cost recognized

2008

2007

2006

57.6

76.4

191.4

(287.7)

2.0

(0.9)

4.9

(10.8)

32.9

52.1

68.0

45.7

64.2

(106.5)

(80.3)

19.9

2.0

(0.9)

13.9

(11.3)

37.2

(3.4)

2.0

(0.8)

15.3

(10.5)

32.2

The table reflects the pension and OPEB cost for all of the Company’s benefit plans on an accrual basis. Using the
cash basis for Gas Distribution and Services rate regulated plans and the accrual method for all other plans, the
Company’s pension cost was $27.4 million (2007 – $23.4 million; 2006 – $20.1 million), and its OPEB cost was
$6.8 million for 2008 (2007 – $6.9 million; 2006 – $7.0 million).

The weighted average assumptions made in the measurement of the cost of the pension plans and OPEB are
as follows:

Year ended December 31,

Discount rate

Average rate of return on pension

2008

5.71%

OPEB

2007

5.37%

2006

5.30%

plan assets

6.00%

4.50%

Average rate of salary increases

Pension Benefits

2008

5.65%

7.30%

5.00%

2007

5.27%

7.31%

5.00%

2006

5.24%

7.31%

4.44%

MEDICAL COST TREND RATES
The assumed rates for the next year used to measure the expected cost of benefits are as follows:

Canadian Plans

Drugs

Other Medical and Dental

U.S. Plan

Medical Cost Trend
Rate Assumption for
Next Fiscal Year

Ultimate Medical Cost
Trend Rate Assumption

Year in which Ultimate
Medical Cost Trend Rate
Assumption is Achieved

10%

2016

2008

2013

A one percent increase in the assumed medical and dental care trend rate would result in an increase of $25.0 million
in the accumulated post-employment benefit obligations and an increase of $2.3 million in benefit and interest costs.
A one percent decrease in the assumed medical and dental care trend rate would result in a decrease of $20.3 million
in the accumulated post-employment benefit obligations and a decrease of $1.8 million in benefit and interest costs.

ENBRIDGE INC.

ANNUAL REPORT 2008

123

MAJOR CATEGORIES OF PLAN ASSETS

OPEB

2008

Year ended December 31,

Actual

Amount

(millions of Canadian dollars)

Equity securities

Fixed income securities

Other

Total Assets

–

84.2%

15.8%

100%

–

38.6

7.2

45.8

2007

Actual

–

85.4%

14.6%

100%

Pension Benefits

2008

Actual

Amount

57.3%

35.1%

7.6%

653.5

400.5

87.3

100%

1,141.3

2007

Actual

60.7%

33.5%

5.8%

100%

Plan assets are invested primarily in readily marketable investments with constraints on the credit quality of fixed
income securities.

The Company manages the investment risk of its pension funds by setting a long term asset mix policy for each plan
after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going
concern and solvency funded status and cash flow requirements of the plans; (iv) the operating environment and
financial situation of the Company and its ability to withstand fluctuations in pension contributions; and (v) the future
economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between
assets. The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity
and debt securities based on long-term expectations.

The target asset mix for each of the pension plans are as follows:

Equity securities

Fixed income securities

Other

Enbridge Inc.
and Affiliates

62.5%

32.5%

Enbridge Gas
Distribution Inc.
and Affiliates

52.5%

42.5%

Enbridge (U.S.) Inc.

EXPECTED RATE OF RETURN ON PLAN ASSETS

Year ended December 31,

Canadian Plans

U.S. Plan

OPEB

Pension Benefits

2008

6.00%

2007

4.50%

2008

7.25%

7.75%

PLAN CONTRIBUTIONS BY THE COMPANY

Year ended December 31,

(millions of Canadian dollars)

Total contributions

Contributions expected to be paid in 2009

OPEB

Pension Benefits

2008

8.2

10.1

2007

8.1

2008

33.3

48.4

57.5%

37.5%

2007

7.25%

7.75%

2007

44.1

BENEFITS EXPECTED TO BE PAID BY THE COMPANY

Year ended December 31,

(millions of dollars)

2009

2010

2011

2012

2013

2014-2018

Expected future benefit payments

54.8

57.8

60.5

63.7

67.1

395.8

124

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

26. OTHER INVESTMENT INCOME

Year ended December 31,

(millions of Canadian dollars)

Interest income on affiliate loans

Gain on reduction of EEP ownership interest

Noverco preferred dividends income

OCENSA investment income

Net foreign currency gains

Allowance for equity funds used during construction (AEDC)

Hurricane insurance recoveries

Other

2008

33.5

12.5

16.1

23.4

43.0

58.9

–

15.3

202.7

2007

32.7

33.9

15.8

24.7

26.2

15.1

14.6

32.1

195.1

2006

29.3

–

15.6

26.8

13.3

1.5

6.0

15.3

107.8

27. CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,

(millions of Canadian dollars)

Accounts receivable and other

Inventory

Deferred amounts and other assets

Accounts payable and other 1

Interest payable

2008

2007

2006

201.6

(135.3)

95.5

(181.4)

9.3

(10.3)

(502.1)

159.5

(134.6)

503.8

(5.9)

20.7

3.9

134.1

(67.3)

43.5

12.5

126.7

Changes in construction payable are included in investing activities.

28. RELATED PARTY TRANSACTIONS

EEP does not have employees and uses the services of the Company for managing and operating its businesses.
Vector Pipeline, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services,
which are charged at cost in accordance with service agreements, are:

Year ended December 31,

(millions of Canadian dollars)

EEP

Vector Pipeline

2008

2007

2006

301.9

5.8

307.7

267.1

4.8

271.9

244.9

4.1

249.0

At December 31, 2008, the Company has accounts receivable from EEP of $40.9 million (2007 – $32.4 million).

The Company has provided EEP with an unsecured revolving credit agreement. The credit facility provides for a
maximum principle amount of US$500.0 million for a three-year term maturing in December 2010. At December 31,
2008 and 2007, there were no amounts outstanding on this facility.

EGD, a subsidiary of the Company, has contracts for gas transportation services from Alliance Pipeline and Vector
Pipeline. EGD is charged market prices for these services:

Year ended December 31,

(millions of Canadian dollars)

Alliance Pipeline Canada

Alliance Pipeline US

Vector Pipeline

2008

23.6

17.1

27.0

67.7

2007

21.3

15.1

25.0

61.4

2006

23.6

14.1

27.3

65.0

ENBRIDGE INC.

ANNUAL REPORT 2008

125

CustomerWorks Limited Partnership (CustomerWorks), a joint venture, provided customer care services to EGD under
an agreement having a five-year term which expired in 2007 and was not renewed. EGD was charged market prices
for these services. CustomerWorks also rented an automated billing system from Enbridge Commercial Services Inc.
(ECS), a subsidiary of the Company. Amounts charged by/(to) CustomerWorks are as follows:

Year ended December 31,

(millions of Canadian dollars)

EGD

ECS

2008

2007

2006

–

(2.0)

26.3

(1.8)

24.5

108.5

(8.1)

100.4

Enbridge Gas Services (US) Inc., a subsidiary of the Company, purchases and sells gas at prevailing market prices
with Enbridge Marketing (US) Inc., a subsidiary of EEP. Amounts paid/(recovered) are as follows:

Year ended December 31,

(millions of Canadian dollars)

Purchases

Sales

2008

2007

2006

52.1

(7.5)

44.6

43.5

(4.1)

39.4

29.2

(6.3)

22.9

Enbridge Gas Services Inc., a subsidiary of the Company, has transportation commitments, measured at market
value, through 2015 on Alliance Pipeline Canada and Vector Pipeline. Amounts paid are as follows:

Year ended December 31,

(millions of Canadian dollars)

Alliance Pipeline Canada

Vector Pipeline

2008

2007

2006

9.3

0.6

9.9

8.5

0.6

9.1

8.3

0.6

8.9

Enbridge Gas Services (US) Inc., a subsidiary of the Company, has transportation commitments, measured at market
value, through 2015 on Alliance Pipeline US and Vector Pipeline. Amounts paid are as follows:

Year ended December 31,

(millions of Canadian dollars)

Alliance Pipeline US

Vector Pipeline

2008

7.0

15.4

22.4

2007

6.6

15.6

22.2

2006

6.9

16.5

23.4

Tidal Energy Marketing Inc., a subsidiary of the Company, purchases and sells commodities at prevailing market
prices with EEP and a subsidiary of EEP as follows:

Year ended December 31,

(millions of Canadian dollars)

Purchases

Sales

2008

2007

2006

24.5

(9.4)

15.1

4.6

(5.5)

(0.9)

17.0

(6.7)

10.3

RECEIVABLE FROM AFFILIATE
The receivable from affiliate of $159.2 million (2007 – $128.5 million), included in Deferred Amounts and Other
Assets, initially resulted from the sale of Enbridge Midcoast Energy to EEP. During 2007, the original loan receivable
was repaid and a new loan was entered into. The loan, denominated in U.S. dollars, bears interest at 8.4% and
matures in 2017. Interest income related to the note was $11.6 million, $10.0 million and $11.8 million, in 2008,
2007 and 2006, respectively.

126

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

TRANSFER OF LINE PIPE
The Company and EEP, an equity investee, regularly collaborate on construction projects. Examples of such projects
include the Southern Access and Alberta Clipper projects where the Company is constructing the Canadian portion of
the projects and EEP is constructing the United States portion. In August 2008, the Company transferred
$22.5 million, measured at market value, of 36 inch diameter line pipe to EEP for use in constructing the Alberta
Clipper project. The line pipe was initially obtained by the Company for use in constructing the Southern Access
Extension, which has been delayed due to a prolonged regulatory process.

29. COMMITMENTS AND CONTINGENCIES

COMMITMENTS
The Company has significant signed contracts for the purchase of services, pipe and other materials totaling
$1,986.0 million, to be used in the construction of several Liquids Pipelines projects including Southern Lights
Pipeline, Alberta Clipper Project, Southern Access Expansion, Hardisty Terminal, Fort Hills Pipeline and Line 4
Extension and certain other administrative services.

ENBRIDGE GAS DISTRIBUTION INC.

Bloor Street Incident
The Company had been charged under both the Ontario Technical Standards and Safety Act (TSSA) and the Ontario
Occupational Health and Safety Act (OHSA) in connection with an explosion that occurred on Bloor Street West in
Toronto in April 2003. In October 2007, all of the TSSA and OHSA charges laid against the Company were dismissed
by the Ontario Court of Justice. The decision has been appealed by the Crown to the Ontario Superior Court of Justice.
The appeal is scheduled to be heard by the Court during 2009. The maximum possible fine upon conviction would not
result in any material financial impact on the Company.

The Company has also been named as a defendant in a number of civil actions related to the explosion. All significant
civil actions have been settled without any material financial impact on the Company. A Coroner’s Inquest in
connection with the explosion is also possible.

GST Overpayment
In December 2007, EGD discovered that it had remitted excess GST to the Canada Revenue Agency (CRA). In respect
of certain months within the 2003 to 2005 calendar year periods, the amount of such overpayment is approximately
$40 million and is included in accounts receivable. The Company expects that it will recover the overpayment from the
CRA during 2009.

Harper Gardens Incident
On February 14, 2007, an explosion and fire occurred at a residence on Harper Gardens in Toronto. The home was
destroyed and a resident of the home was killed. A natural gas contractor working in the home at the time of the
explosion was seriously injured. Several public authorities commenced investigations in connection with the incident.
The Company has also been named as a defendant in civil actions related to the incident, but does not expect these
actions to result in any material financial impact.

Remediation of Discontinued Manufactured Gas Plant Sites
EGD may incur future costs due to claims relating to alleged coal tar contamination at or near former manufactured
gas plant (MGP) sites. In October 2002, a claim was filed for $55.0 million in damages relating to a certain MGP site.
EGD filed a statement of defence in June 2003 denying liability. Although the Company believes that it has a valid
defence to this claim, certain risks exist. The probable overall cost cannot be determined at this time due to
uncertainty about the presence and extent of damage in addition to the potential alternative remediation approaches
which vary in cost. EGD expects that costs, if any, not recovered through insurance may be recovered through rates.
As such, EGD does not believe the outcome will have any material financial impact.

ENBRIDGE ENERGY COMPANY, INC.
Enbridge Energy Company, Inc. (EEC), a subsidiary of the Company and the general partner of EEP, is the former
owner of Enbridge Midcoast Energy Inc. (Midcoast). The IRS challenged Midcoast’s tax treatment of its 1999
acquisition of several partnerships that owned a natural gas pipeline system in Kansas (these assets were sold to EEP
in 2002 and subsequently sold by EEP in 2007). In March 2008, an unfavourable court decision was received
sustaining the IRS position, decreasing the U.S. tax basis for the pipeline assets. The Company’s earnings for 2008
reflected a decrease of $32.2 million in consideration of the adverse court decision which, when combined with

ENBRIDGE INC.

ANNUAL REPORT 2008

127

amounts previously recorded, provides fully for the liability. Given loss carryforwards in EEC prior to the decision, the
cash tax impact of the decision was not significant. The Company continues to believe the tax treatment of the
acquisition and the related tax deductions claimed were appropriate and has appealed the decision.

OTHER TAX MATTERS
Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the
Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

OTHER LITIGATION
The Company and its subsidiaries are subject to various other legal actions and proceedings which arise in the normal
course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty,
Management believes that the resolution of such actions and proceedings will not have a material impact on the
Company’s consolidated financial position or results of operations.

30. GUARANTEES

EEC, as the general partner of 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 is subject to recourse with respect to US$93.0 million of EEP’s long-term debt
at December 31, 2008 (2007 – US$124.0 million).

The Company has also agreed to indemnify EEM for any tax liability related to EEM’s formation, management of EEP
and ownership of i-units of EEP. The Company has not made any significant payment under these tax
indemnifications. The Company does not believe there is a material exposure at this time.

In the normal course of conducting business, the Company enters into agreements which indemnify third parties. The
Company cannot reasonably estimate the maximum potential amounts that could become payable to third parties
under these agreements; however, historically, the Company has not made any significant payments under these
indemnification provisions. While many of these agreements may specify a maximum potential exposure, or a
specified duration to the indemnification obligation, there are circumstances where the amount and duration are
unlimited. Examples where such indemnification obligations have been issued include:

Sale Agreements for Assets or Businesses:

(cid:127)

breaches of representations, warranties or covenants;
loss or damages to property;
environmental liabilities;
changes in laws;
valuation differences;
litigation; and
contingent liabilities.

Provision of Services and Other Agreements:

(cid:127)

breaches of representations, warranties or covenants;
changes in laws;
intellectual property rights infringement; and
litigation.

When disposing of assets or businesses, the Company may indemnify the purchaser for certain tax liabilities incurred
while the Company owned the assets or for a misrepresentation related to taxes that result in a loss to the purchaser.
Similarly, the Company may indemnify the purchaser of assets for certain tax liabilities related to those assets.

128

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

31. SUBSEQUENT EVENT

In January, 2009, the Company secured incremental credit of $225 million from its banking group for an existing
credit facility established in December 2008. The new commitments provide additional liquidity and increase the total
credit facilities to $8.8 billion.

32. 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

Year ended December 31,

2008

2007

2006

(millions of Canadian dollars, except per share amounts)

Earnings under Canadian and U.S. GAAP Applicable

to Common Shareholders

Earnings under Canadian and U.S. GAAP

Other comprehensive income/(loss) under Canadian GAAP

Underfunded pension adjustment (net of tax) 4

Unrealized net gain/(loss) on cash flow hedges

Comprehensive income under U.S. GAAP

Earnings per common share under U.S. GAAP

Diluted earnings per common share under U.S. GAAP

1,320.8

1,327.7

317.8

(56.6)

–

1,588.9

3.67

3.64

700.2

707.1

(197.4)

23.3

–

533.0

1.97

1.95

615.4

622.3

36.0

–

(64.2)

594.1

1.81

1.79

ENBRIDGE INC.

ANNUAL REPORT 2008

129

FINANCIAL POSITION

December 31,

(millions of Canadian dollars)

Assets

Cash and cash equivalents 2, 5

Accounts receivable and other 2, 3, 5

Inventory 2, 5

2008

Canada

United
States

2007

Canada

United
States

541.7

2,322.5

844.7

3,708.9

961.0

3,174.8

911.3

5,047.1

166.7

2,388.7

709.4

3,264.8

214.4

3,118.4

817.3

4,150.1

Property, plant and equipment, net 2, 5

16,389.6

24,738.0

12,597.6

17,999.4

Long-term investments 2, 5

Deferred amounts and other assets 1, 2, 3, 4, 5

Intangible assets 5

Goodwill 5

Future income taxes 1, 5

Liabilities and Shareholders’ Equity

Short-term borrowings

Accounts payable and other 2, 3, 5

Interest payable 5

Current maturities and short-term debt 5

Current portion of non-recourse debt 2, 5

Long-term debt 3

Non-recourse long-term debt 2, 5

Other long-term liabilities 2, 4, 5

Future income taxes 1, 2, 3, 4, 5

Non-controlling interests 5

Shareholders’ Equity

Preferred shares

Common shares

Contributed surplus

Retained earnings

Additional paid in capital

Accumulated other comprehensive loss 3, 4

Reciprocal shareholding

2,491.8

1,318.4

225.3

389.2

178.2

412.2

2,079.5

333.9

807.7

178.2

2,076.3

1,182.0

212.0

388.0

186.7

1,253.1

1,653.5

302.4

725.1

187.3

24,701.4

33,596.6

19,907.4

26,270.9

874.6

2,411.5

101.9

533.8

184.7

874.6

3,202.7

143.6

533.8

706.0

4,106.5

5,460.7

10,154.9

10,256.9

1,474.0

259.0

1,290.8

797.4

5,447.5

398.6

2,014.2

3,493.8

545.6

2,213.8

89.1

605.2

61.1

3,514.8

7,729.0

1,508.4

253.9

975.6

650.5

545.5

3,195.1

109.8

632.7

60.9

4,544.0

7,771.7

4,337.2

479.2

1,545.7

2,355.2

18,082.6

27,071.7

14,632.2

21,033.0

125.0

3,194.0

37.9

125.0

3,194.0

–

3,383.4

3,350.5

–

32.8

81.7

(72.0)

(154.3)

125.0

3,026.5

25.7

2,537.3

–

(285.0)

(154.3)

125.0

3,026.5

–

2,504.4

69.6

(333.3)

(154.3)

6,618.8

6,524.9

5,275.2

5,237.9

24,701.4

33,596.6

19,907.4

26,270.9

Future Income Taxes

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. At December 31, 2008, a deferred tax liability of $803.3 million (2007 – $572.7 million) is recorded for

U.S. GAAP purposes and reflects the difference between the carrying value and the tax basis of property, plant and equipment. Regulated companies following

the taxes payable method are not required to record this additional tax liability under Canadian GAAP. For the year ended December 31, 2007, to recover the

additional deferred income taxes recorded under U.S. GAAP through the ratemaking process, it would have been necessary to record incremental revenue of

$785.6 million.

Accounting for Joint Ventures

U.S. GAAP requires the Company’s investments in joint ventures to be accounted for using the equity method. However, under an accommodation of the

U.S. Securities and Exchange Commission, accounting for jointly controlled investments need not be reconciled from Canadian to U.S. GAAP if the joint venture

is jointly controlled by all parties having an equity interest in the entity. Joint ventures in which all owners do not share joint control are reconciled to U.S. GAAP.

The different accounting treatment affects only display and classification and not earnings or shareholders’ equity.

130

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Accumulated Other Comprehensive Loss

Financial instruments are now recognized in Canadian GAAP in substantially the same manner as U.S. GAAP. As a result of the change in Canadian accounting,

certain comparative balances have been reclassified for U.S. GAAP purposes, including the recognition of regulated non-financial instruments and offsetting

regulatory liabilities as well as OCI from equity investees. In addition, transaction costs arising from the issuance of debt are now recorded net against the related

long-term debt. For U.S. GAAP, these transaction costs are reclassified to deferred amounts and other assets.

The only Canadian – U.S. GAAP difference in accumulated other comprehensive loss is the underfunded status of the pension and OPEB plans. The following

are the impacts of the underfunded status on OCI in Canadian dollars.

Amounts removed from other comprehensive income (OCI) and recognized as components of the net pension and OPEB costs in the year is as follows:

Year ended December 31,

(millions of Canadian dollars)

Prior service cost

Net transitional obligation

Net loss

Amounts accumulated in OCI that have not yet been recognized as a component of net periodic benefit cost is as follows:

Year ended December 31,

(millions of Canadian dollars)

Prior service cost

Net transitional obligation

Net loss

Net amounts reflected in OCI for the year are as follows:

Year ended December 31,

(millions of Canadian dollars)

Unamortized prior service cost

Unamortized net transitional obligation

Net loss/(gain)

2008

2007

0.5

(1.0)

1.6

1.1

0.5

(1.0)

3.1

2.6

2008

2007

0.8

(5.8)

109.9

104.9

2008

(2.8)

1.0

58.4

56.6

3.5

(6.7)

51.5

48.3

2007

(0.9)

0.9

(23.3)

The Company estimates that approximately $1.2 million related to pension and OPEB plans at December 31, 2008 will be reclassified into earnings in the next

twelve months.

(millions of Canadian dollars)

Net transitional obligation

Prior service costs

Loss

Reclassification

Pension Benefits

OPEB

(1.1)

0.2

1.4

0.5

–

0.2

0.7

The after tax amounts recognized in the tables above exclude the Gas Distribution and Services plans since these plans are funded through regulated rates on a

cash basis and are not recorded as net pension assets or liabilities.

Pension Funding Status

FAS 158, Employers’ Accounting for Defined Pension and Other Postretirement Plans, requires an employer to recognize the overfunded or underfunded status

of a defined benefit post retirement plan or OPEB as an asset or liability and to recognize changes in the funded status in the period in which they occur through

comprehensive income. FAS 158 adjustments resulted in an increase in the net liability of $158.7 million (December 31, 2007 – $73.1 million) for the

underfunded status of the plans, a decrease in deferred tax liability of $53.8 million (December 31, 2007 – $24.8 million) and an increase in accumulated other

comprehensive loss of $104.9 million (December 31, 2007 – $48.3 million). As required by FAS 158, the Company adjusted the amounts recognized related to

the Canadian pension plans to reflect a December 31 measurement date.

Consolidation of a Limited Partnership

As a result of adopting EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity

When the Limited Partners Have Certain Rights, the Company is consolidating its 27.0% interest in Enbridge Energy Partners for U.S. GAAP purposes, resulting

in an increase to both assets and liabilities of $8,248.2 million (December 31, 2007 – $5,932.7 million) and no changes to equity and earnings.

6 Unrecognized tax benefits

(millions of Canadian dollars)

Unrecognized Tax Benefits at January 1,

Gross increases for tax positions of current year

Gross decreases for tax positions of prior years

Changes in translation of foreign currency

Settlements during the period

Unrecognized Tax Benefits at December 31,

2008

61.0

33.4

(82.4)

0.8

–

12.8

2007

78.0

5.0

(14.0)

(6.0)

(2.0)

61.0

The unrecognized tax benefits at December 31, 2008, if recognized, would affect the Company’s effective income tax rate. Gross increases include a

$32.2 million charge for the U.S. tax matter currently under litigation, to unrecognize all of the tax benefits. As an unfavourable court decision was rendered in

ENBRIDGE INC.

ANNUAL REPORT 2008

131

2008, the full tax benefit balance of $64.6 was reversed and the unrecognized benefits removed as reflected in gross decreases. The Company does

not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its consolidated

financial statements.

The Company recognizes accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense. Income tax expense for the

year ended December 31, 2008 includes $1.8 million (2007 – $2.0 million) of interest. As at December 31, 2008, interest and penalties of $8.8 million (2007 –

$7.0 million) have been accrued.

The Company and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax, or the relevant

income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years

through 2002 and all returns are generally closed through 2003. All U.S. federal income tax returns and generally all U.S. state and local income tax returns are

closed through 2004 for all tax matters with the exception of the ongoing tax litigation. U.S. federal income tax returns for 2005 are currently under examination

by the Internal Revenue Service.

Indefinite reversal rule

We have not provided deferred taxes on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.

These earnings relate to ongoing operations and as at December 31, 2008 were approximately $427.6M. It is not practicable to determine, due to the availability

of U.S. foreign tax credits, the deferred income tax liability that would be payable if such earnings were not reinvested indefinitely.

NEW ACCOUNTING STANDARDS

Fair Value Measurements
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements. The Statement defines fair value,
establishes a framework for measuring fair value in the context of GAAP and expands the disclosure surrounding fair
value measurement. In January 2008, the FASB deferred the implementation of this standard for all non-financial
assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial
statements on a recurring basis, until January 1, 2009. For financial assets and liabilities, the Company has adopted
this standard on January 1, 2008.

Fair Value Option for Assets and Liabilities
In February 2007, the FASB issued Statement No. 159, Fair Value Option for Financial Assets and Liabilities. This
standard provides companies with an option to measure, at specified election dates, certain financial assets and
liabilities at fair value. Changes in fair value are recognized in earnings. The Company has adopted this standard
effective January 1, 2008, but has not elected to use the optional fair value measurement.

Future Accounting Standards
The following standards will be effective for the Company beginning on January 1, 2009. Management does not
expect the adoption of any of these standards to significantly impact the financial statements.

Business Combinations
In December 2007, the FASB issued Statement No. 141(R), Business Combinations. This Statement retains the
fundamental requirements in FAS 141, requiring that the acquisition method of accounting be used for all business
combinations and for an acquirer to be identified for each business combination. The Statement revises how the
acquisition method is applied when measuring and recognizing certain items acquired.

Accounting for Non-Controlling Interests
In December 2007, the FASB issued Statement No. 160, Non-Controlling Interests in Consolidated Financial
Statements. This Statement amends ARB 51 to establish accounting and reporting standards for a non-controlling
interest in a subsidiary and for deconsolidation of a subsidiary.

Derivative Instrument and Hedging Activities Disclosures
In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging
Activities. This Statement revises disclosure requirements for derivative instruments and hedging activities.

132

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

SUPPLEMENTARY INFORMATION (UNAUDITED)

QUARTERLY SHARE TRADING INFORMATION

The Toronto Stock Exchange

2008

(Canadian dollars)

High

Low

Volume (millions)

2007

(Canadian dollars)

High

Low

Volume (millions)

The New York Stock Exchange

2008

(U.S. dollars)

High

Low

Volume (millions)

2007

(U.S dollars)

High

Low

Volume (millions)

First

Second

Third

Fourth

42.95

36.25

42.33

57.8

46.27

41.06

44.06

62.4

45.85

37.50

39.38

75.7

43.00

33.10

39.56

96.6

First

Second

Third

Fourth

41.48

36.50

37.66

60.6

38.35

35.21

35.90

45.8

38.74

33.62

36.44

47.3

40.97

35.75

40.01

50.1

First

Second

Third

Fourth

43.16

35.59

41.16

20.5

46.76

40.25

43.18

15.6

44.81

35.97

38.09

30.3

38.90

26.29

32.47

60.2

First

Second

Third

Fourth

35.40

30.93

32.65

9.1

36.15

32.06

33.78

11.7

37.13

31.26

36.67

12.6

44.29

36.20

40.43

15.6

ENBRIDGE INC.

ANNUAL REPORT 2008

133

FIVE-YEAR CONSOLIDATED HIGHLIGHTS

FINANCIAL AND OPERATING INFORMATION

(millions of Canadian dollars, except where otherwise noted)

Earnings Applicable to Common Shareholders

Liquids Pipelines

Gas Pipelines

Sponsored Investments

Gas Distribution and Services

International

Corporate

Adjusted Earnings 2

Cash Flow Data

Cash provided by operating activities

before changes in operating assets

and liabilities

Cash provided by operating activities

Additions to property, plant and

equipment

Total Common Share Dividends Declared

Operating Data

Liquids Pipelines – Average

Deliveries (thousands of barrels per day)
Enbridge System 3
Athabasca System 4
Spearhead Pipeline

Olympic Pipeline

Gas Pipelines – Average Daily Throughput

Volume (millions of cubic feet per day)

Alliance Pipeline US

Vector Pipeline

Enbridge Offshore Pipelines
Gas Distribution and Services 5
Volumes (billions of cubic feet)

Number of active customers (thousands)
Degree day deficiency 6

Actual

Forecast based on normal weather

2008

2007

2006

2005

20041

328.0

48.5

111.7

300.6

608.2

(76.2)

1,320.8

677.3

287.2

69.7

96.9

179.4

95.1

(28.1)

700.2

636.5

274.2

61.2

86.8

173.7

83.2

(63.7)

615.4

592.9

229.1

59.8

64.8

177.0

87.4

(62.1)

556.0

537.2

219.9

53.8

66.2

311.4

73.6

(79.6)

645.3

491.1

1,398.0

1,387.7

3,635.7

489.3

1,358.0

1,351.6

2,299.2

452.3

1,191.6

1,315.3

1,205.9

403.1

1,300.9

947.0

1,027.8

886.7

724.1

361.1

496.4

315.8

2,030

2,005

2,013

202

110

291

1,609

1,321

1,672

444

1,942

3,802
3,543

164

103

284

1,598

1,034

2,060

450

1,902

3,659

3,617

190

289

1,592

1,015

2,153

408

1,852

3,355

3,745

1,872

142

–

1,597

1,033

2,102

438

1,805

3,750

3,747

2,001

149

–

1,581

997

–

575

1,756

5,052

4,849

As a result of the elimination of the quarter lag basis of consolidation, Gas Distribution and Services financial and operating information for 2004 reflects earnings

for the 15 months ended December 31, 2004 for Enbridge Gas Distribution, Noverco and other gas distribution entities.

Adjusted earnings represents earnings applicable to common shareholders adjusted for non-recurring or non-operating factors primarily including

non-operating gains and losses, the impact of weather, regulatory disallowances and impacts of tax rate changes. Adjusted earnings is not a measure that has a

standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and is not considered a GAAP measure; therefore, this

measure may not be comparable with similar measures presented by other issuers. Management believes the presentation of adjusted earnings provides useful

information to investors and shareholders as it provides increased predictive value and performance trends. Earnings for 2004 have been adjusted to eliminate

the quarter lag basis of consolidation described above.

Enbridge System includes Canadian mainline deliveries in Western Canada and to the Lakehead System at the U.S. border as well as Line 8 and Line 9 in

Eastern Canada.

Volumes are for the Athabasca mainline and the Waupisoo Pipeline and do not include laterals on the Athabasca System.

5 Gas Distribution and Services volumes and the number of active customers are derived from the aggregate system supply and direct purchase gas supply

arrangements.

6 Degree day deficiency is a measure of coldness which is indicative of volumetric requirements of natural gas utilized for heating purposes. 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 Greater Toronto area.

134

FIVE-YEAR CONSOLIDATED HIGHLIGHTS

SHAREHOLDER AND INVESTOR INFORMATION

(per share amounts in dollars)

Shares Outstanding

(millions)

Weighted average common shares

outstanding

Diluted weighted average common

2008

2007

2006

2005

2004

359.8

355.3

340.0

337.4

334.5

shares outstanding

363.1

358.3

343.3

341.2

337.2

Common Share Trading (TSX)

High

Low

Volume (millions)

Per Common Share Information

Earnings per common share
Adjusted earnings per common share 1
Dividends per common share

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

46.27

33.10

39.56

292.5

3.67

1.88

1.32

22.2%

9.9%

66.6%

3.8x

70.2%

41.48

33.62

40.01

203.8

1.97

1.79

1.23

13.6%

7.0%

66.5%

2.4x

68.7%

41.45

31.75

40.27

173.7

1.81

1.74

1.15

13.9%

7.0%

68.6%

2.4x

66.1%

38.82

28.59

36.34

211.3

1.65

1.59

1.04

13.2%

6.9%

68.9%

2.4x

65.2%

30.08

23.63

29.85

155.4

1.93

1.47

0.92

17.0%

8.3%

67.1%

2.8x

62.3%

Adjusted earnings represents earnings applicable to common shareholders adjusted for non-recurring or non-operating factors primarily including

non-operating gains and losses, the impact of weather, regulatory disallowances and impacts of tax rate changes. Adjusted earnings is not a measure that has a

standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and is not considered a GAAP measure; therefore, this

measure may not be comparable with similar measures presented by other issuers. Management believes the presentation of adjusted earnings provides useful

information to investors and shareholders as it provides increased predictive value and performance trends. Earnings for 2004 have been adjusted to eliminate

the quarter lag basis of consolidation described above.

Earnings applicable to common shareholders divided by average shareholders’ equity (weighted monthly during the year).

Sum of after-tax earnings (including earnings from discontinued operations) and after-tax interest expense, divided by weighted average capital employed.

Capital employed is equal to the sum of shareholders’ equity, EGD preferred shares, future income taxes, deferred credits and total debt (including short-term

borrowings).

Total debt (including short-term borrowings) divided by the sum of total debt and shareholders’ equity.

Earnings before taxes and interest expenses divided by interest expense (including capitalized interest).

6 Dividends per common share divided by adjusted earnings per common share applicable to common shareholders.

ENBRIDGE INC.

ANNUAL REPORT 2008

135

ENBRIDGE BUSINESSES

LIQUIDS PIPELINES
Enbridge Pipelines Inc. (100%)

GAS DISTRIBUTION AND SERVICES
Enbridge Gas Distribution (100%)

Enbridge Pipelines (NW) Inc. (100%)

(cid:127)

St. Lawrence Gas Company, Inc.

Enbridge Pipelines (Athabasca) Inc. (100%)

Gazifere Inc. (100%)

Enbridge Pipelines (Toledo) Inc. (100%)

Niagara Gas Transmission Limited (100%)

Enbridge Southern Lights LLC (100%)

Noverco Inc. (32.1%), which owns:

Enbridge Midstream Inc. (100%)

Gateway Pipeline Limited Partnership (100%)

Mustang Pipe Line Partners (30%)

Chicap Pipe Line Company (43.8%)

Frontier Pipeline Company (77.8%)

CCPS Transportation L.L.C.

(Spearhead Pipeline) (100%)

Olympic Pipe Line Company (65%)

(cid:127)

Gaz M ´etro Limited Partnership (71.0%),
which owns:

(cid:127) Vermont Gas Systems, Inc. (100%)

(cid:127) TQM Pipeline and company,
Limited Partnership (50%)

(cid:127) Portland Natural Gas Transmission

System (38.3%)

Enbridge Gas New Brunswick Limited

Partnership (70.9%)

Hardisty Caverns Limited Partnership (50%)

CustomerWorks Limited Partnership (70%)

GAS PIPELINES
Alliance Pipeline L.P. (U.S. portion) (50%)

Vector Pipeline Limited Partnership (60%)

Enbridge Offshore Pipelines, L.L.C.

(22% – 100%)

SPONSORED INVESTMENTS
Enbridge Energy Partners, L.P. (27%)

(cid:127)

Lakehead System

(cid:127)

North Dakota System

(cid:127)

Mid-Continent System

(cid:127)

Various Natural Gas Systems

Enbridge Income Fund

(72.3% overall economic interest)

Enbridge Commercial Services Inc. (100%)

Aux Sable Liquids Products Inc. (42.7%)

Enbridge Gas Services (U.S.) Inc. (100%)

Enbridge Gas Services Inc. (100%)

Tidal Energy Marketing Inc. (100%)

Tidal Energy Markets (U.S.) L.L.C. (100%)

Enbridge Solutions Inc. (100%)

Enbridge Electric Connections Inc. (100%)

Rabaska Limited Partnership (33%)

INTERNATIONAL
Oleoducto Central S.A. (24.7%)

Enbridge Technology Inc. (100%)

(cid:127)

Enbridge Pipelines (Saskatchewan) Inc. (100%)

CORPORATE

(cid:127)

Alliance Pipeline Limited Partnership

(Canadian portion) (50%)

Enbridge Ontario Wind Power Project LP

(100%)

(cid:127)

SunBridge Wind Power Project (50%)

NetThruPut Inc. (52%)

(cid:127)

Magrath Wind Power Project (33.3%)

FuelCell Energy (strategic alliance)

(cid:127)

Chin Chute Wind Power Project (33.3%)

(cid:127)

NRGreen Power Limited Partnership (50%)

136

ENBRIDGE BUSINESSES

2008 AWARDS AND RECOGNITION

Alberta’s Top

Alberta’s Top 40 Employers:
40 Employers is an annual competition organized by
Mediacorp Canada in partnership with the Human
Resources Institute of Alberta. The designation
recognizes industry-leading employers in Alberta that
offer exceptional places to work.

Mediacorp Canada

Canada’s Top 100 Employers:
again recognized Enbridge as being one of Canada’s
top employers in 2008. This competition, now in its
ninth year, recognizes employers that are industry
leaders at attracting and retaining employees. More
than 2,000 companies in Canada applied for this
year’s ranking.

Canadian Standards Association (CSA) Greenhouse
Gas (GHG) Registry, Gold Champion Level Reporter:
For the third year in a row, the CSA awarded
Enbridge’s Canadian operations ‘‘Gold Level’’ status
for our GHG emissions reporting. Gold is the highest
level recognized.

Canadian Utility Fleet Forum E3 Gold Fleet Award:
The Fraser Basin Council awarded Enbridge Gas
Distribution a Gold Fleet Award for excellence in
environmentally friendly fleet management. Enbridge’s
Ontario fleet is the first commercial fleet to be rated
under the Council’s E3 Fleet program, and the first
fleet ever to receive a Gold Fleet Award.

Conference Board of Canada Carbon Disclosure
Leadership Index:
Enbridge was ranked third out
of 103 Canadian companies that responded to
the Carbon Disclosure Project (CDP) questionnaire
in 2008. In collaboration with the Conference
Board of Canada, the CDP evaluates companies
on GHG emissions disclosure, emissions reduction
targets, and risk and opportunity identification.
Enbridge’s high ranking reflects the quality,
completeness and comprehensiveness of our
climate change disclosures.

Corporate Knights Best 50 Corporate Citizens in
Canada:
Enbridge ranked as one of Canada’s Best
50 Corporate Citizens in Corporate Knights’
2008 ranking.

Dow Jones Sustainability Index (North America):
Enbridge Inc. was named to the Dow Jones
Sustainability Index North America (DJSI North
America) in 2008. The DJSI tracks the financial
performance of leading sustainability-driven
companies worldwide. The DJSI North America
includes the top 20 per cent of companies in each of
57 sectors out of the 600 largest North American
companies listed on the Dow Jones Global Index.

EnerQuality Corporation Award of Excellence:
EnerQuality Corporation awarded Enbridge Gas
Distribution an Award of Excellence for being the
Industry Partner of the Year in 2008. Enbridge was
recognized for our contributions to sustainable and
energy efficient home building.

Fortune America’s Most Admired Companies:
Enbridge Energy Partners (EEP) ranked fourth among
the pipeline companies listed on the 2008 Fortune
America’s Most Admired Companies list. This is the
third year in a row that EEP has been among the top
five of the most admired pipeline companies, ranking
fourth in 2007 and third in 2006 among its peers.

Governance

Governance Metrics International:
Metrics International released new ratings and
research reports for the 4,200 companies in its system
in 2008, and awarded Enbridge an overall global
rating of 10.0, the highest rating GMI assigns.
Enbridge is one of only 42 companies, or one per cent,
to achieve this rating.

Indian and Northern Affairs Canada Aboriginal
Relations Award of Distinction:
Affairs awarded Enbridge its Aboriginal Relations
Award of Distinction at the annual Alberta Business
Awards in 2008.

Indian and Northern

United Nations Global Compact Award:
The Calgary
Chapter of the United Nations Association of Canada
presented Enbridge with the 2008 United Nations
Global Compact Award in 2008. This award recognizes
Enbridge’s local and international leadership and
demonstrated track record in corporate
social responsibility.

ENBRIDGE INC.

ANNUAL REPORT 2008

137

New York Stock Exchange Disclosure Differences
As a foreign private issuer, Enbridge Inc. is required
to disclose any significant ways in which its corporate
governance practices differ from those followed by
U.S. companies under NYSE listing standards. This
disclosure can be obtained from the U.S. Compliance
subsection of the Corporate Governance section of the
Enbridge website at www.enbridge.com.

Form 40-F
The Company files annually with the U.S. Securities
and Exchange Commission 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. In addition
a link to it is available on the ‘‘Reports and Filings’’
subsection of the ‘‘Financial Reports’’ section of
our website.

Corporate Social Responsibility Report
Enbridge publishes an annual Corporate Social
Responsibility report. The 2008 report is available on
the Company’s website at www.enbridge.com/csr2008

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

INVESTOR INFORMATION

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
P.O. Box 7010,
Adelaide Street Postal Station
Toronto, Ontario M5C 2W9
Toll free: (800) 387-0825
Internet: www.cibcmellon.com/investorinquiry
CIBC Mellon Trust Company also has offices in
Halifax, Montreal, Calgary and Vancouver.

Co-Registrar and Co-Transfer Agent in the
United States
BNY Mellon Shareowner Services
480 Washington Blvd.
Jersey City, New Jersey
U.S.A. 07310
Toll free: (800) 387-0825
Internet: www.cibcmellon.com/investorinquiry

Debentures and Notes — Registrars and Trustees:
The registrar and trustee for Enbridge Debentures
is Computershare Trust Company of Canada,
with offices in Montreal, Toronto, Winnipeg, Calgary,
Halifax and Vancouver.

Auditors
PricewaterhouseCoopers LLP

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. Effective with dividends payable on
March 1, 2008, participants in the Plan will receive
a two per cent discount on the purchase of common
shares with reinvested dividends. The Company also
offers Dividend Direct Deposit which enables
shareholders to receive dividends by electronic fund
transfer (EFTS) to the bank account of their choice
in Canada. Details may be obtained from the Investor
Information section of the Enbridge website at or by
contacting CIBC Mellon Trust Company at any of the
locations listed above.

138

INVESTOR INFORMATION

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

Le présent document est disponible en franc¸ais.

2009 dividend information for common Shares and
preferred Shares, Series A 1

Record date

Payment date

Common Share Dividend
Reinvestment Plan (DRIP)
enrolment cut-off date

Common Share Purchase
Plan cut-off date for DRIP

1st Q

2nd Q

3rd Q

4th Q

Feb. 16 May 15

Aug. 17 Nov. 16

Mar. 1

Jun. 1

Sep. 1

Dec. 1

Feb. 9

May 8

Aug. 10

Nov. 9

Feb. 23 May 25

Aug. 25 Nov. 24

1 Dividend dates are subject to the dividends being declared by the Board
of Directors.

* ENBRIDGE, the ENBRIDGE LOGO and the ENBRIDGE ENERGY SPIRAL

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

dElivEring
vAluE

Designed and produced by Karo Group Calgary. Printed in Canada by Blanchette Press.

Cert no. SW-COC-002068

Printed on post-consumer recycled paper, a portion of which was manufactured with wind energy.

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Enbridge common shares trade on the
Toronto Stock Exchange in Canada and on the
New York Stock Exchange in the United States
under the trading symbol ENB.

Enbridge Inc.
3000, 425 - 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
Telephone: (403) 231-3900
Facsimile: (403) 231-3920
Toll free: (800) 481-2804