Enbridge Annual Report 2009

FY2009 Annual Report · Enbridge

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EnbridgE inc. | 2009 AnnuAl RepoRt

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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

WhErE ENErgY
mEETS PEoPLE

letter to Shareholders 13
executive Management team 18

Corporate Governance 19
Corporate Social Responsibility 20

Assets & opportunities 22
Financial Results 28

On the cover: Enbridge Gas Distribution (EGD) is a
compelling part of our growth story. As Canada’s largest
natural gas distribution company, EGD connects about
1.9 million residential, commercial and industrial
customers to safe and environmentally preferable natural
gas and adds as many as 45,000 new customers every year.

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”
on page 35 of this annual report and also in the 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.

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 in the
Ballroom of the Metropolitan Centre, Calgary, Alberta at
1:30 p.m. MSt on Wednesday, May 5, 2010. A live
audio 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 français.

Designed and produced by Karo group Calgary.

Printed in Canada by Blanchette Press.

10%

Cert no. SW-COC-002068

2010 Enbridge inc. common Share dividends

1st Q 2nd Q

3rd Q

4th Q

Dividend

$0.425

$–

payment date

Mar. 1

Jun. 1 Sep. 1 Dec. 1

Record date 1

Feb. 15 May 14 Aug. 13 nov. 15

Board declaration Dec. 2/09 May 4 July 27 nov. 2

Spp deadline 3

Feb. 22 May 25 Aug. 25 nov. 24

DRIp enrollment 2

Feb. 8 May 7 Aug. 6 nov. 8

Dividend Record Dates for Common Shares are generally

February 15, May 15, August 15 and November 15 in each year;

however, record date is accelerated for weekends and adjusted

to accommodate the Annual General Meeting date.

The Dividend Reinvestment Program Enrollment Cut-off Date is five

business days prior to the Dividend Record Date.

The Share Purchase Plan Cut-off Date is five business days prior

to the Dividend Payment Date.

* ENBRIDGE, the ENBRIDGE LOGO and the ENBRIDGE ENERGY SPIRAL
are trademarks or registered trademarks of Enbridge Inc. in Canada
and other countries.

enbridge Inc., a Canadian company, is a north
American leader in delivering energy. As a transporter
of energy, enbridge operates, in Canada and the
united States, the world’s longest crude oil and liquids
transportation system. the Company also has a growing
involvement in the natural gas transmission and
midstream businesses and is expanding its interests
in renewable and green energy technologies, including
wind and solar energy, hybrid fuel cells and carbon
dioxide sequestration. As a distributor of energy,
enbridge owns and operates Canada’s largest natural
gas distribution company and provides distribution
services in ontario, Quebec, new Brunswick and
new York State. enbridge employs approximately
6,000 people, primarily in Canada and the united
States. enbridge’s common shares trade on the toronto
and new York stock exchanges under the symbol enB.

www.enbridge.com

Affiliations, Partnerships and Accreditations

WE’rE IN
ThE ENErgY
DELIvErY
BUSINESS

We deliver the crude oil
that fuels the cars, buses
and trucks that we drive.

We deliver the natural
gas that keeps us warm
and cooks our food.
We deliver the green
energy that lights our
businesses and powers
our computers.

We deliver the energy
people need, in a safe,
responsible and
sustainable way.

Enbridge’s Edmonton Terminal is the starting
point of the mainline system, the world’s longest,
most complex crude oil pipeline system with an
export capacity of 2.1 million barrels. We transport
71% of western Canadian crude oil exports and
satisfy 12% of the U.S.’s daily crude oil imports.

WE ArE IN ThE
BUSINESS oF
DELIvErINg vALUE
To ShArEhoLDErS

three key features guide
our success: Growth.
Income. Reliability. It’s a
powerful combination that
has delivered success few
companies can match.

1,500

1,200

900

600

300

1953

Enbridge 13.5%

S&P/TSX 9.3%

2009

total Shareholder Return

(Total Return Index March 1953 =1)

Since inception, we have achieved a 13.5% average
annual return to shareholders and we are focused
on maintaining this track record.

The global recession in 2009 devastated returns for
most companies. Not Enbridge. With adjusted earnings
per share growth of 25% in 2009, Enbridge delivered
its best year ever, with strong performance across
all its operations and new projects continuing
to come into service on time and on budget.

Value At the end of 2009, the value of Enbridge’s
equity market capitalization stood at $18.4 billion,
one of the largest corporations in Canada.

Shareholders An investment of $1.00 in Enbridge in
March 1953 would have been worth approximately $1,300
at the end of 2009.

where
vALUE
meets
ShArEhoLDErS

High Growth $12 billion in new Liquids, Gas and Green
projects in service or expected to be in service 2008 to 2011;
$5 billion secured post-2011; $30 billion in new opportunities.

Reliability Over the last 10 years—including the recent
global recession and financial crisis—Enbridge has
consistently grown earnings.

where
hIgh groWTh

meets
rELIABILITY

AN INvESTmENT
IN ENBrIDgE
groWS rELIABLY

At enbridge you can
benefit from a reliable
investment while still
enjoying the steady
growth few companies
can match. In 2009,
enbridge achieved record
adjusted earnings per
share growth of 25%.

2.35

1.88

1.74 1.79

1.59

1.50 1.47

1.34

1.23

1.08

10e

Adjusted earnings per Share

(Canadian dollars per share)

the diversity of enbridge’s businesses contributes
to the reliability of our growth. Adjusted earnings
per share are expected to grow by about 11% in
2010 and are targeted to grow by 10% per year
on average into the second half of the decade.

Enbridge’s large network of natural gas gathering,
treating, processing and transmission facilities in the
southern U.S. is well positioned for growth arising from
the region’s prolific shale gas plays.

AN INvESTmENT
IN ENBrIDgE PAYS
hANDSomE DIvIDENDS

our record is unmatched.
the 15% dividend increase
announced in December
2009 was our 15th consecutive
annual increase. over the last
decade, enbridge’s dividend
growth has significantly
outperformed that of our
peers. We are focused on
continuing this performance.

1.70

1.48

1.32

1.23

1.15

1.04

0.92

0.83

0.76

0.70

0.64

10e

Growing Dividends

(Canadian dollars per share)

We aim to pay out 60 to 70% of our adjusted earnings
as dividends to our investors. Dividends have increased,
on average, approximately 10.3% annually over the
last decade.

Enbridge has delivered solid income growth
for shareholders since its inception in 1953.
Our shareholders can continue to count on solid
income performance with dividends tracking earnings
growth. Enbridge common shares trade on the Toronto
and New York stock exchanges under the symbol ENB.

Investment Enbridge common shares offer a competitive
dividend yield of 3.5%, making it an attractive investment
for income-oriented investors.

Income Enbridge has paid, and consistently increased common
share dividends since inception in 1953. Based on estimated
2010 dividends, the annual increase has averaged 10%.

where
INvESTmENT

meets
INComE

Positioning Our continent-wide energy delivery network is ideally
located to serve the newest and most prolific opportunities — oil
sands, shale gas and deepwater Gulf of Mexico.

Advantage Our technical expertise and track record for
developing projects on time, on budget and safely are distinct
competitive advantages.

where
PoSITIoNINg

meets
ADvANTAgE

WE CoNNECT vITAL
SoUrCES oF SUPPLY
WITh rEFINErS AND
CoNSUmErS ACroSS
ThE CoNTINENT

We are ideally positioned
for growth. our existing
infrastructure is located
in strategic geographical
locations, which puts us in
a strong position to deliver
energy to the fastest-
growing north American
and global markets.

Fort
McMurray

Calgary

Toronto

Houston

Supply sources
Enbridge assets

Geographic Reach
enbridge is expanding its far-reaching energy delivery
network to help ensure north Americans always have
access to secure and reliable sources of energy.

Enbridge serves a majority of the deepwater platforms in the
Gulf of Mexico. On the strength of our extensive presence, we
now transport about 50% of Gulf deepwater gas production and
are capturing new gas gathering and crude oil transportation
opportunities serving the region’s ultra deepwater developments.

oUr grEEN ENErgY
INvESTmENTS gENErATE
ATTrACTIvE rETUrNS

Investing in green energy
is good for the environment
and great for our investors.
our renewable assets follow
the same reliable business
model as our traditional
energy assets and are part
of the reason you can expect
reliable income growth as
we move forward.

Hybrid Fuel Cell 2.2 MW

Waste-Heat Recovery 20 MW

Solar 80 MW

Wind 360 MW

Green power Generation
enbridge’s Green energy footprint is small, but diversified
and growing. our interests in renewable and alternative
power generation in operation and under construction
have capacity to generate enough electricity to serve
more than 150,000 homes.

Enbridge’s 20-MW Sarnia Solar Project, already one of the
largest photovoltaic solar energy facilities in North America,
is adding another 60 MW of capacity in 2010 to supply
more emissions-free power to the Ontario grid.

Renewable Enbridge now has interests in over 460 MW of
emissions-free green power capacity — wind, solar, waste-heat
recovery and hybrid fuel cells.

Return Through the use of long-term power purchase
agreements and fixed price contracts, our renewable energy
projects can deliver stable cash flows and attractive returns.

where
rENEWABLE

meets
rETUrN

where
PAST SUCCESS

meets
ThE FUTUrE

5
5
5
,
1

1
2
3
,
1

2009

2008

5
5
8

7
7
6

2009 earnings

(millions of Canadian dollars)

enbridge delivered adjusted
earnings at the top end
of the Company’s 2009
guidance range.

08
09
Actual

08
09
Adjusted

LETTEr To
ShArEhoLDErS
enbridge maintained
its reliable performance
through the global
recession, and is now
stronger than it has ever
been and poised for
continued steady growth.

We had an outstanding year in 2009, delivering
the best results in the company’s history and
building on a more than 50-year track record
of exceptional performance. Adjusted earnings
per share increased 25% to $2.35 per common
share. Actual earnings increased 18% to
$1,555 million, or $4.27 per common share,
compared with $1,321 million, or $3.67 per
common share, in 2008. Enbridge’s strong
earnings throughout the global recession are a
testament to Enbridge’s reliable business model,
which delivers steady financial performance.

EnbridgE inc. 2009 ANNUAL rEPorT

enbridge had an
outstanding year in
2009–the best in the
Company’s history.

Patrick D. Daniel, President
and Chief Executive Officer
David A. Arledge, Chair
of the Board of Directors

Reliable Business Model
our reliable business model results in highly predictable earnings.

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

Commodity prices, interest rates and
foreign exchange rates in combination
should not impact Enbridge’s
earnings by more than 5%.

95% of revenue
is from a low-risk, diversified
base of large, reputable
investment-grade customers.

in 2010 and 2011. Moreover, we have secured
over $5 billion of new projects for post-2012
and have an additional inventory of opportunities
of approximately $30 billion currently under
development across our Liquids Pipelines,
Natural Gas and Green Energy businesses.

LiquidS PiPELinES
In Liquids Pipelines in 2009, commercial
operations began on the second phase of the
Southern Access Project. Combined with the first
phase, Southern Access has increased capacity on

enbridge’s earnings are

targeted to grow on

average by 10% per year.

our mainline by 400,000
barrels per day (bpd).
We also completed both our
Spearhead Expansion Project
to extend the reach of
Canadian crude oil into the
North American storage hub
at Cushing, Oklahoma, and

the Line 4 Project, which extended Line 4 of
our mainline system from Hardisty, Alberta, back
to Edmonton. In the first quarter 2009, we
brought two key components of the Southern
Lights diluent project into service: a new 20-inch
light sour (LSr) crude oil pipeline from Cromer,
Manitoba, to Clearbrook, Minnesota, and
modifications to existing Line 2. Combined,
the LSr Pipeline and Line 2 modifications increase
southbound capacity on the Enbridge mainline
and will permit Line 13 to be taken out of service
and reversed for diluent service in 2010.
We complemented those pipeline projects with

Our Liquids Pipelines, Gas Transportation and
Green Energy businesses are all well positioned to
contribute further reliable growth in 2010 and well
beyond, with a large array of attractive investment
opportunities under development and coming to
fruition at a steady pace. We have built up ample
financial capability and liquidity reserves to take
full advantage of these opportunities.

Based on the midpoint of our guidance,
we expect adjusted earnings per share will grow
by approximately 11% this year over 2009,
and as a result Enbridge’s Board
of Directors has raised the 2010
dividend by 15%. This represents
the Company’s 15th consecutive
annual dividend increase.
Over the past decade, Enbridge
has delivered a 10% compound
annual growth rate on its
dividend — well ahead of the broader market and
our peers.

We are targeting Enbridge’s earnings per share to
grow on average by 10% per year into the second half
of this decade with dividends increasing in parallel.

Enbridge’s strong performance in 2009, and the
continued solid growth we expect to deliver in 2010
and beyond, are the direct result of the $4.5 billion
in commercially secured growth projects we brought
into service in 2008 and 2009 and the additional
$7 billion in projects expected to come into service

LEttEr tO ShArEhOLdErS

Financial Highlights

Year ended December 31,

2009

2008

2007

4.27

2.35

1.48

555

22.2%

66.2%

3.67

1.88

1.32

489

22.2%

66.6%

1.97

1.79

1.23

453

13.6%

66.5%

(millions of Canadian dollars, except per share amounts)

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

the expansion of storage facilities, including adding
7.5 million barrels of capacity to our Hardisty
contract terminal, making that facility one of the
largest storage facilities in North America.

Liquids Pipelines will continue to deliver strong
growth in earnings and cash flow in 2010 as we
start up two of our largest projects, Alberta Clipper,
the largest mainline expansion in
Enbridge’s histor y, and the
unique Southern Lights Pipeline
from Chicago to Edmonton that
will deliver diluent to western
Canada. We will also strengthen
our competitive advantage as
the largest pipeline operator in
the important Bakken region
as Enbridge Income Fund and
Enbridge Energy Partners, L.P.
complete expansions of their Saskatchewan and
North Dakota systems, respectively, and work to
secure commercial support for subsequent phases.

enbridge has secured

a number of attractive

opportunities to expand

our oil sands regional

infrastructure.

Looking beyond 2010, we’re encouraged by signs
of renewed activity in the Alberta oil sands.
Enbridge has secured a number of attractive
opportunities to expand our oil sands regional
infrastructure, including the Woodland Pipeline to
serve the Kearl Lake oil sands project, additional
pipeline and terminal facilities to support expansion
of the Christina Lake enhanced oil project and
additional volumes on our Waupisoo Pipeline from
the Leismer oil sands project.

We enjoy a very strong competitive position in
the oil sands region and we’re actively pursuing
further opportunities to connect new production
through expansion of our existing systems and the
construction of new pipelines. We also continue to
make progress on our Northern Gateway Project,
a proposed twin pipeline system running from near
Edmonton, Alberta, to a new marine terminal in
Kitimat, British Columbia, to
export crude oil and import
condensate. Northern Gateway
would provide an outlet for
bitumen and synthetic crude to
both Asia and California markets,
opening up a completely new
market to Alberta producers and
ensuring that they maximize the
value of Canadian crude. We
anticipate filing our regulatory

application for Northern Gateway with the
National Energy Board in early 2010.

nAturAL gAS And OFFShOrE
Growth opportunities for our Natural Gas business
have never been better.

In 2009, Enbridge Offshore Pipelines secured two
attractive deepwater projects in the Gulf of Mexico:
the US$500 million Walker Ridge Gas Gathering
System and the US$250 million Big Foot Oil
Pipeline. There are a number of additional deepwater
projects under development. Our extensive systems

EnbridgE inc. 2009 ANNUAL rEPorT

operating Highlights

liquids pipelines—Average Deliveries (thousands of barrels per day)

enbridge System 1

enbridge Regional oil Sands System 2

Spearhead pipeline

olympic pipeline

natural Gas Delivery and Services

Gas pipelines—Average throughput Volumes (millions of cubic feet per day)

Alliance pipeline uS

Vector pipeline

enbridge offshore pipelines

enbridge Gas Distribution

Volumes (billions of cubic feet)

number of active customers 3 (thousands)

2009

2008

2007

2,061

2,030

2,005

259

121

280

1,601

1,334

2,037

408

1,937

202

110

291

1,609

1,321

1,672

433

1,898

164

103

284

1,598

1,034

2,060

440

1,861

in the Gulf and strong technical and operating
capabilities position us well to capture new oil and
gas opportunities.

Our onshore natural gas assets are also very well
positioned to take advantage of the many emerging
shale gas plays in both Canada and the United
States. In 2009 we advanced a number of projects,
including our proposed LaCrosse Pipeline connecting
the prolific Haynesville shale in Texas and
Louisiana to key markets.

Enbridge Gas Distribution (EGD) continued in
2009 to improve its already steady and reliable
performance, achieving
an increase in its return
on investment in the
second year of its five-
year incentive regulation
regime. Even in a down
economy, EGD is adding
between 30,000 and
45,000 new customers a
year and now has close to two million customers,
making it one of the fastest growing utilities in
North America.

grEEn EnErgy
In our Green Energy business, we brought our
190-MW Ontario Wind Power Project — the
second largest wind farm in Canada — into full
commercial operation in 2009. We also completed
construction and testing of the first phase of the
20-MW, $100 million Sarnia Solar Energy Project,
and that project is now supplying emissions-free
power to the Ontario grid. We are also moving
ahead with a $300 million expansion of the Sarnia
facility to add another 60 MW of capacity this year.
Once completed, the Sarnia Solar Project will be
one of the largest photovoltaic solar energy facilities
in North America.

enbridge’s Green investments

build on our excellent track record

in environmental stewardship and

emissions reductions.

Our Green Energy
business will expand
further in late 2010
when we bring the
99-MW Talbot Wind
Project in Ontario into
commercial operation.

All of Enbridge’s Green Energy investments feature
an attractive, reliable commercial model that is very
similar to our traditional businesses. They also build
on our excellent track record in environmental
stewardship and emissions reductions. These
investments add value for our shareholders both

Enbridge System includes Canadian mainline deliveries in western Canada and to the Lakehead System at the United States 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 Enbridge Regional Oil Sands System.

Number of active customers is the number of natural gas-consuming EGD customers at the end of the year.

LEttEr tO ShArEhOLdErS

Reducing GHG emissions
Despite a substantial increase in the size and throughput
of our operations, we are on track to achieve our goal
of a 20% reduction in GHG emissions by 2010. In 2009,
enbridge was recognized for the third consecutive year as
a Canadian leader in carbon disclosure by the Conference
Board of Canada as part of the international Carbon
Disclosure project.

Our success over the past 60 years has been built
on not only strong business results, but also our
long-standing commitment to being a good
neighbour and a fully participating member of the
communities in which we operate. We recognize
that as a leader in business we have a duty to
use our expertise and strengths to build stronger
communities. That commitment is shared by
our more than 6,000 employees, who are deeply
engaged in our growth and sustainability initiatives.

We recognize that as a leader

in business we have a duty to

use our expertise and strengths

to build stronger communities.

We thank all employees
for their exemplary work
in strengthening
Enbridge’s reputation
and relationships and
in striving each and
every day to fulfill our
responsibility to safely

426

427

377

Target: 20% less than 1990 levels
(kt CO2e)

329

339

10
Target

from a financial and an environmental perspective.
While our Green Energy business today is small
relative to our liquids and gas businesses, we are
committed to its continued growth through
capturing new opportunities that meet our
investment criteria.

cOrPOrAtE SOciAL rESPOnSibiLity
Energy delivery is Enbridge’s prime corporate
responsibility. Energy is essential for humanity,
powering every aspect of
society. A critical part of our
responsibility is delivering
energy safely and in an
environmentally responsible
way. Several years ago, we
set a target of reducing the
dir ect gr eenhouse gas
emissions (GHG) of our Canadian operations to
20% below our 1990 levels by 2010. We are already
at 23% below our 1990 levels, and that is with
a substantial increase in the size and throughput
of our operations.

In 2009, we extended our commitment to
environmental sustainability by setting a new
and ambitious goal: to move toward a neutral
environmental footprint for all new projects.
We intend to achieve this by conserving an acre for
every acre of wilderness we impact, planting a tree
for every tree we must remove to build new facilities
and generating a kilowatt of renewable power for
every kilowatt our new operations consume.

and reliably deliver energy to people.

The Enbridge team was deeply saddened by the
death in January 2010 of our colleague Nalvester
Maxie in a hydrogen sulfide leak at our gas treating
plant near Bryans Mill, Texas. Also, the Company’s
systems experienced two notable leaks in Canada
in 2009 and one in the United States in January
2010. All Enbridge employees strive for zero
safety incidents and work hard every day to
minimize the Company’s environmental impact,
and these incidents heighten our resolve to meet
those commitments.

EnbridgE inc. 2009 ANNUAL rEPorT

exeCutIVe
MAnAGeMent
teAM (left to right)

Al Monaco Executive Vice
President, Major Projects
& Green Energy
Patrick d. daniel President
& Chief Executive Officer
J. richard bird Executive Vice
President, Chief Financial Officer
& Corporate Development
david t. robottom Executive
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

in cOncLuSiOn
We believe Enbridge’s value proposition is unique

MAnAgEMEnt And bOArd chAngES
We want to express special thanks to Bonnie DuPont,
G r o u p V i c e P r e s i d e n t ,
Corporate Resources, who
retires from Enbridge in
March 2010. Bonnie has made
a huge contribution to the
management of Enbridge over
the past decade. We wish
Bonnie well in her retirement.

highly reliable financial

performance even during

difficult financial times.

enbridge’s value proposition…

and compelling — sustained
visible growth and steady
income, coupled with
highly reliable financial
performance even during
difficult economic times.

As Enbridge continues

In July 2009, the Board of Directors announced
the appointment of Charles W. Fischer, former
President and Chief Executive Officer of Nexen
Inc., to the Board. We are delighted to welcome
an individual of Charlie’s reputation and expertise.
With more than 30 years’ experience in the energy
industry and a strong personal commitment to
community involvement, Charlie is a great leader
and one who will make a significant contribution to
the Board and the future direction of the Company.

to grow, our shareholders will benefit from a
superior investment opportunity, today and well
into the future.

david A. Arledge
Chair of the Board of Directors

Patrick d. daniel
President and Chief Executive Officer

March 3, 2010

LEttEr tO ShArEhOLdErS

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.

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 with respect to 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.

BoARD oF DIReCtoRS (left to right)

dan c. tutcher Corporate Director
Houston, Texas

catherine L. Williams Corporate Director
Calgary, Alberta

J. herb England Chairman & Chief Executive Officer,
Stahlman-England Irrigation Inc.
Naples, Florida

J. Lorne braithwaite Corporate Director
Thornhill, Ontario

charles W. Fisher Corporate Director
Calgary, Alberta

James J. blanchard Senior Partner,
DLA Piper U.S., LLP
Beverly Hills, Michigan

david A. Arledge Chair of the Board, Enbridge Inc.
Naples, Florida

david A. Leslie Corporate Director
Toronto, Ontario

george K. Petty Corporate Director
San Luis Obispo, California

Patrick d. daniel President & Chief Executive Officer,
Enbridge Inc.
Calgary, Alberta

charles E. Shultz Chair & Chief Executive Officer,
Dauntless Energy Inc.
Calgary, Alberta

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,
www.enbridge.com.

EnbridgE inc. 2009 ANNUAL rEPorT

Corporate Social Responsibility You can read more about
Enbridge’s initiatives in our annual Corporate Social
Responsibility Report at www.enbridge.com/csr2009.

WE’rE BUILDINg
morE ThAN
PIPELINES

“We believe that to
be a good corporate
citizen, we have
a responsibility to
give back to the
communities that
contribute to our
business success.
Investing in these
communities helps
sustain them as
vibrant and healthy
places to live and
work – which, in turn,
sustains us as a
healthy company.”

patrick D. Daniel,
president & Ceo, enbridge Inc.

Enbridge’s School Plus program
helped Randelle Pete of the Little Pine First
Nation and her grade 11 classmates from
S¯akewew High School in North Battleford,
Saskatchewan, participate in a field trip to
study the aquatic and terrestrial ecology
of nearby Finlayson Island. To date,
the School Plus Program has benefited
children from kindergarten to high
school in 42 First Nations schools.

Sustainability In early 2010, Enbridge was named one of the
Global 100 Most Sustainable Corporations — the highest-ranking
Canadian company on the list and the top energy company.

Community In 2009, Enbridge contributed $9.2 million: 22%
to Health & Safety, 22% to Education, 10% to Environment and
46% to Culture & Community. www.enbridge.com/community

where
SUSTAINABILITY

meets
CommUNITY

Enbridge is in the business of delivering energy
to communities throughout North America, and
we believe we have an obligation to do so in a
responsible and sustainable way.

carbon management strategy
Enbridge has already exceeded its target of reducing
direct greenhouse gas emissions of Canadian
operations to 20% below 1990 levels by 2010.
By 2008, we had achieved a 23% reduction. We are
in the process of developing a more comprehensive
Carbon Management Strategy that will include
further actions to reduce the Company’s own direct
emissions. We also have comprehensive energy-
efficiency programs in place that help our natural gas
distribution customers use energy more efficiently.

Looking ahead to a future where society makes
greater use of renewable energy sources, we are
investing in green energy technologies, including
wind power, fuel cells, waste-heat recovery and
solar. We are also participating in the emerging
technology of carbon dioxide (CO2) capture,
pipelining and sequestration.

Stakeholder engagement and consultation
Enbridge is building an unprecedented number
of projects in North America.

To ensure specific concerns are identified and
understood, we engage stakeholders (e.g.,
landowners) and communities (e.g., Aboriginal
communities) early in the project planning.
This enables us to adjust our plans as appropriate
and resolve remaining concerns, where possible.
Communication with stakeholders continues
through regulatory review to construction and
into operations.

Enbridge aims to meet or exceed regulatory
requirements regarding public consultation. For
example, for the Enbridge Northern Gateway Project
we established community advisory boards to guide
the design, construction and operation of the proposed
project. We have also implemented an Aboriginal
and Native American Policy that encourages
partnerships, program sponsorships, employment
opportunities and other capacity-building efforts.

community partnerships and investment
For communities to be sustainable, they must have
solid infrastructure and programming in four areas:
Education, Health & Safety, Culture & Community
and the Environment. Enbridge also believes that the
time, effort and investments it makes in communities
contribute to maintaining our social licence to
operate. We launched three flagship programs in 2009:

Safe Community
This program supports first response emergency
organizations in communities near Enbridge’s
rights-of-way.

natural legacy
Enbridge is committed to environmental stewardship
and habitat remediation and conservation, and
this program focuses on planting and maintaining
native trees and plants in urban and rural areas along
Enbridge’s rights-of-way.

School plus
Established in partnership with the Assembly
of First Nations, School Plus supports enriched
programming and extracurricular activities in First
Nations schools near major Enbridge pipeline
routes and the Ontario Wind Power Project.

EnbridgE inc. 2009 ANNUAL rEPorT

Supply In both Canada and the United States, producers are
developing vast new oil and gas resources and there is an
increasing demand for renewable energy.

Demand North American industry and consumers alike are
seeking secure and reliable sources of energy supply to
support economic growth.

where
SUPPLY

meets
DEmAND

Norman Wells

Horn
River

Zama

Fort
St. John
Montney

Western Canada
Sedimentary Basin
(WCSB)

Edmonton

Fort McMurray

Cheecham

Blaine

Seattle

Portland

Calgary

Hardisty

Kerrobert

Lethbridge

Regina

Cromer

Gretna

Bakken

Minot

Clearbrook

Superior

Ottawa

Montreal

Rockies

Casper

Salt Lake City

Toronto

Buffalo

Delavan
Streator
Flanagan

Chicago

Patoka

Wood River

Sarnia
Toledo

Marcellus

Cushing

Tulsa

Anadarko/Barnett/Bossier/Haynesville

New Orleans

Houston

Gulf of Mexico

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

Solar Assets

Wind Assets

Norman Wells

Horn

River

Zama

Fort

St. John

Montney

Western Canada

Sedimentary Basin

(WCSB)

Edmonton

Fort McMurray

Cheecham

Calgary

Hardisty

Kerrobert

Blaine

Seattle

Lethbridge

Portland

Rockies

Casper

Salt Lake City

Regina

Cromer

Gretna

Bakken

Minot

Clearbrook

Superior

Ottawa

Montreal

Toronto

Buffalo

Delavan

Streator

Flanagan

Chicago

Patoka

Wood River

Sarnia

Toledo

Marcellus

Cushing

Tulsa

Anadarko/Barnett/Bossier/Haynesville

New Orleans

Houston

Gulf of Mexico

Shale gas: Abundant deposits in
both Canada and the United States
make unconventional and shale gas
major new sources of natural gas supply.

oil Sands: This is the second largest
resource play in the world, with an
estimated 170 billion barrels of proven
recoverable reserves.

Bakken: This region, which straddles
the Canada-U.S. border, is estimated
to contain five billion barrels of
technically recoverable oil.

renewables: more governments in
North America are focusing on green
energy initiatives as society transitions
to greater use of renewables.

gulf of mexico: This prolific oil and
natural gas region is one of the largest
sources of supply to the U.S. market.

ENBrIDgE IS
LEADINg ThE WAY

name any of north
America’s major energy
resource development
opportunities – the oil sands,
the Bakken Formation,
shale gas, Gulf of Mexico
deepwater, renewable
sources – and enbridge is
there, positioned to deliver
energy to key north
American markets.

projects completed in 2009

Southern Access pipeline (phase 2)

Spearhead pipeline expansion

line 4 extension

Hardisty terminal expansion

ontario Wind power

Sarnia Solar energy (phase 1)

light Sour pipeline (lSr pipeline)

Commercially secured growth projects

Alberta Clipper expansion (2010)

Southern lights pipeline (2010)

Saskatchewan and north Dakota systems expansions
(Bakken) (2010)

Sarnia Solar energy (60-MW expansion) (2010)

talbot Wind energy (2010)

Christina lake (oil sands) (2011)

leismer project Contract (oil sands) (2011)

Woodland pipeline (oil sands) (2012)

Walker Ridge Gas Gathering System (Gulf of Mexico) (2014)

Big Foot oil pipeline (Gulf of Mexico) (2014)

Fort Hills pipeline (oil sands) (tBD)

Enbridge is the largest pipeline operator in Canada’s
oil sands region, a leading pipeline operator in North
America’s shale gas regions, the dominant pipeline
company in the Bakken region, a leader in renewable
energy production and the largest operator in the
deepwater Gulf of Mexico.

EnbridgE inc. 2009 ANNUAL rEPorT

on any single day, enbridge is

the single largest conduit of oil

into the u.S., exporting 71%

of western Canadian crude oil,

and satisfying 12% of the u.S.’s

crude oil import needs.

Canada’s oil sands

The opportunity
With about 174 billion barrels of combined
conventional and oil sands established reserves,
Canada ranks second only to Saudi Arabia in
global oil reserves.

Of that total, 170 billion barrels are concentrated
in Alberta’s oil sands deposits, making them the
largest resource play in the world.

Today, the oil sands produce over one million barrels
of oil per day, and it is estimated that by 2020,
production will grow to about four million barrels.

Enbridge is there
Enbridge is the largest pipeline operator in the
oil sands region.

Our 345,000-barrels-per-day (bpd) Athabasca
Pipeline, which runs through the heart of the
oil sands to Hardisty, currently has four oil sands
projects connected to it and has an ultimate design
capacity of 570,000 bpd with the addition of new
pump stations.

Our 350,000-bpd Waupisoo Pipeline, which went
into service in 2008, connects three new oil sands
projects to refineries and upgraders at Edmonton. It is
expandable to 600,000 bpd by adding pump stations.

Ultimate
Capacity
1,170,000 bpd

Current
Capacity
695,000 bpd

We’re growing
Enbridge is actively pursuing many significant
growth opportunities to connect new oil sands
production through expansion of our existing
systems and the construction of new pipelines.

We are building on our very strong competitive
position in the region, which stems from our
proven track record for on-time, on-budget
development and the economies of scale of
being the largest operator.

Enbridge’s regional Oil Sands System both our

Athabasca and Waupisoo pipelines are designed for

low-cost expansion from their current combined capacity

of 695,000 bpd to 1,170,000 bpd — ready for oil

sands growth.

ASSEtS & OPPOrtunitiES

Rapid growth

Enbridge gas distribution is canada’s largest gas

distribution utility and one of the fastest growing in

north America. Enbridge gas distribution serves

approximately 1.9 million customers in central and

eastern Ontario and parts of northern new york State.

in 2009, Enbridge gas distribution added about 32,000

new customers. We continue to improve the return on

this business under incentive regulation, enhancing

shareholder value while at the same time enabling us to

provide significant savings to our customers in the form

of reduced charges for gas delivery.

the Bakken Formation

Shale gas

The opportunity
Producers are driving significant oil and gas
production growth in the Bakken Formation, which
spans parts of Saskatchewan, Manitoba, North
Dakota and Montana and is estimated to contain
five billion barrels of technically recoverable oil.

The opportunity
Shale gas (an emerging form of unconventional
gas) is of growing importance to North American
energy supply and by the end of this decade could
account for over 30% of natural gas production in
Canada and the Lower 48 combined.

Enbridge is there
Enbridge is strengthening our clear competitive
advantage in the Bakken region with growth
projects on both sides of the Canada-U.S. border.

We are already the dominant pipeline company
in the region through our two sponsored
investments — Enbridge Income Fund and
Enbridge Energy Partners, L.P.

The Bakken also contains natural gas and natural
gas liquids (NGLs), presenting another growth
opportunity for the Alliance Pipeline and Aux Sable
NGL plant.

Beyond 2010
Looking ahead, we see a tremendous long-term
opportunity to build on our existing infrastructure
and presence in the Bakken, both in liquids and
natural gas, and we are actively working on
additional projects for both the Canadian and
U.S. sections of this basin.

There are abundant shale gas deposits already under
development in northeastern British Columbia
(Montney and Horn River plays), Saskatchewan
and North Dakota (the Bakken Formation),
south-central U.S. (Barnett Shale, Fayette, Eagle
Ford and Haynesville plays) and the northeastern
U.S. (Marcellus Shale).

Enbridge is there
Enbridge is already strongly positioned in the top
quartile of pipeline operators in the major shale gas
plays in the Lower 48. Enbridge Energy Partners’
gas assets are located in three of the most prolific
gas-producing regions in the southeastern U.S.
and right next door to the Haynesville Formation,
and currently transport, gather and process over
three billion cubic feet per day.

The Alliance Pipeline is ideally located right in the
heart of the Montney shale gas play in northeastern
British Columbia and the Bakken Formation in
Saskatchewan and North Dakota.

EnbridgE inc. 2009 ANNUAL rEPorT

offshore expertise

in 2009, Enbridge secured two major offshore projects

in the ultra deepwater gulf of Mexico. the Walker

ridge gas gathering Project will be constructed

over 306 kilometres (190 miles) and at depths up

to 2,130 metres (7,000 feet) and the big Foot Oil

Pipeline at depths up to 1,800 metres (5,900 feet)

over 64 kilometres (40 miles). delivering such projects

requires strong technical skills, world-class contractors

and exceptional project management capabilities.

Enbridge has a strong team with an established track

record in the gulf coast. those attributes, combined

with our extensive infrastructure, position us well

to capture opportunities from new oil and natural gas

finds in the region.

Enbridge is there
Enbridge has the best positioning of any provider
in the deepwater Gulf of Mexico.

Enbridge serves a majority of the strategically
located deepwater host platforms, and our
extensive presence in the region positions us
well to capture new opportunities both in gas
gathering and crude oil.

Enbridge offshore pipelines currently transport
about 50% of all deepwater Gulf of Mexico natural
gas production and include joint-venture interests
in 13 transmission and gathering pipelines in five
major pipeline corridors in Louisiana, Mississippi
and Alabama offshore waters of the Gulf of Mexico.

our growth projects
In 2009, Enbridge announced two new projects
for the Gulf of Mexico ultra deepwater — the
Walker Ridge Gas Gathering System and the
Big Foot Oil Pipeline — both of which are
structured to strengthen returns and align
more closely to the reliable business model
of Enbridge’s traditional businesses.

Gulf of Mexico ultra deepwater

The opportunity
The Gulf of Mexico is a prolific oil and natural gas
region and one of the largest sources of supply to
the U.S. market.

The ultra deepwater areas — those with water depths
of 1,520 metres (5,000 feet) and over — have very
large reservoirs, and despite recent commodity
price declines, large producers are continuing
to explore the ultra deepwater Gulf. The U.S.
Department of the Interior recently forecast that
oil production in the Gulf of Mexico will increase
substantially over the next several years, possibly
reaching 1.8 million bpd.

Houston

New Orleans

STINGRAY
CORRIDOR

DESTIN
CORRIDOR

MISSISSIPPI
CANYON
CORRIDOR

GARDEN BANKS
CORRIDOR

Big Foot-CVX

Jack/St. Malo-CVX

Secured Enbridge Projects

Existing Enbridge Pipelines

Prospects

new discoveries gas and oil production is expected to

grow based on the discovery of large new reservoirs in

the ultra deepwater gulf of Mexico. Enbridge has the

existing infrastructure and the technical capabilities

required to capture these new growth opportunities.

ASSEtS & OPPOrtunitiES

Innovative solar technology

the photovoltaic technology in use at Enbridge’s Sarnia

Solar Project generates electricity with no air emissions,

no waste production and no water use. When expanded

to 80 MW by the end of 2010, the Sarnia Solar Project

will be one of the largest photovoltaic solar facilities in

north America, and Enbridge expects it will generate

enough power to meet the needs of over 12,800 homes

and help to save the equivalent of approximately
39,000 tonnes of cO2 per year.

Green energy

The opportunity
The public’s focus on conservation and climate
change continues to motivate governments to
increase their emphasis on energy efficiency and
green energy initiatives, including wind, water,
biomass, biogas, solar, waste heat, fuel cell and
geothermal energy generation.

Enbridge is there
Enbridge has been a leader in green energy
generation for almost a decade, and we plan to keep
it that way for many decades to come as society
transitions to a greater use of renewable energy.

Solar: Enbridge entered solar energy in a significant
way in 2009 with its investment in the 80-MW
Sarnia Solar facility. Enbridge believes that solar
energy represents meaningful opportunities for
long-term growth.

Wind: We currently have wind farms in Alberta,
Saskatchewan and Ontario with a combined
capacity of over 260 MW, and in 2009 added the
99-MW Talbot Wind Project, expected to begin
operations by the end of 2010. We expect future
wind opportunities to come through expanding
our existing operations and developing new
greenfield projects near Enbridge operations
throughout North America.

Fuel cell: In 2008, Enbridge launched the world’s
first hybrid fuel cell power plant that harvests
energy that would otherwise be wasted at gas
utility pressure reduction stations. The fuel cell
produces about 2.2 MW of near zero-emissions
electricity—enough to serve about 1,700 homes.
We plan to replicate the plant throughout our
distribution network in Ontario and market the
hybrid fuel cell to other natural gas utility
companies in North America.

Waste heat: Enbridge Income Fund has a 50%
interest in NRGreen, which generates electricity
using waste heat from four of Alliance Canada’s
compressor stations, generating a total of about
20 MW that is sold under long-term contract to
Saskatchewan’s grid.

Wind Power the 190-MW Enbridge Ontario Wind Power

Project went into full commercial operation in the first

quarter of 2009.

EnbridgE inc. 2009 ANNUAL rEPorT

FINANCIAL rESULTS
Management’s Discussion
and Analysis
29 overview

30 Performance overview

36 Corporate vision and Key objective

36 Corporate Strategy

40 Industry Fundamentals

42 growth Projects

44 Liquids Pipelines
47 Natural gas Delivery and Services
48 Sponsored Investments
49 Corporate

50 Liquids Pipelines

57 Natural gas Delivery and Services

70 Sponsored Investments

76 Corporate

77 Liquidity and Capital resources

81 Contingencies and Commitments

82 Quarterly Financial Information

83 related Party Transactions

84 risk management

91 Financial Instruments

95 Critical Accounting Estimates

97 Change in Accounting Policies

101 Controls and Procedures

102 Non-gAAP reconciliations

Consolidated Financial
Statements
103 management’s report

104 Independent Auditors’ report

106 Consolidated Statements of Earnings

107 Consolidated Statements of Comprehensive Income

108 Consolidated Statements of Shareholders’ Equity

109 Consolidated Statements of Cash Flows

110 Consolidated Statements of Financial Position

notes to the Consolidated
Financial Statements

111 1. general Business Description
112 2. Summary of Significant

Accounting Policies
117 3. Changes in Accounting Policies
119 4. Segmented Information
121 5. Financial Statement Effects of

rate regulation
124 6. gain on Sale of Investments
124 7. Accounts receivable and other
125 8. Inventory
125 9. Property, Plant and Equipment
126 10. Joint ventures
128 11. Long-Term Investments
129 12. Deferred Amounts and other Assets
130 13. Intangible Assets
130 14. goodwill
131 15. Accounts Payable and other
131 16. Debt
132 17. Non-recourse Debt
133 18. other Long-Term Liabilities
133 19. Non-Controlling Interests
134 20. Share Capital
135 21. Stock option and Stock Unit Plans
139 22. Components of Accumulated other

Comprehensive Income/(Loss)

139 23. risk management
145 24. Fair value of Financial Instruments
148 25. Capital Disclosures
149 26. Income Taxes
150 27. Post-Employment Benefits
155 28. other Investment Income
155 29. Changes in operating Assets and Liabilities
155 30. related Party Transactions
157 31. Commitments and Contingencies
158 32. guarantees
159 33. United States Accounting Principles

163 glossary

164 Five-Year Consolidated highlights

166 Enbridge Businesses

167 2009 Awards and recognition

168 Investor Information

FinAnciAL rESuLtS

mANAgEmENT’S DISCUSSIoN AND ANALYSIS
This Management’s Discussion and Analysis (MD&A) dated February 18, 2010 should be read in conjunction
with the audited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the
Company) for the year ended December 31, 2009, which are prepared in accordance with Canadian generally
accepted accounting principles (GAAP). All financial measures presented in this MD&A are expressed in
Canadian dollars, unless otherwise indicated. Additional information related to the Company, including
its Annual Information Form, is available on SEDAR at www.sedar.com.

overview
Enbridge is a North American leader in delivering energy. As a transporter
of energy, Enbridge operates, in Canada and the United States, the world’s
longest crude oil and liquids transportation system. The Company also has a
significant involvement in the natural gas transmission and midstream businesses.
As a distributor of energy, Enbridge owns and operates Canada’s largest natural
gas distribution company and provides distribution services in Ontario, Quebec,
New Brunswick and New York State. As a clean energy generator, Enbridge is
expanding its interests in renewable and green energy technologies, including
wind and solar energy, and hybrid fuel cells. Enbridge employs approximately
6,000 people, primarily in Canada and the United States.

The Company’s activities are carried out through four business segments,
Liquids Pipelines, Natural Gas Delivery and Services, Sponsored Investments
and Corporate, as discussed below.

9
6
1
,
8
1 2
0
7
,
4
2

7
0
9
,
9
1

9
7
3
,
8
1

1
1
2
,
7
1

LiquidS PiPELinES
Liquids Pipelines includes the operation and construction of the Enbridge
crude oil mainline system and feeder pipelines that transport crude oil and
other liquid hydrocarbons. Liquids Pipelines consists of crude oil, natural gas
liquids (NGLs) and refined products pipelines and terminals in Canada and
the United States.

� Liquids Pipelines
� Natural Gas Delivery and Services
� Sponsored Investments
� Corporate

total Assets
(millions of Canadian dollars)

nAturAL gAS dELiVEry And SEr VicES
Natural Gas Delivery and Services consists of natural gas utility operations, investments in natural gas
pipelines, the Company’s commodity marketing businesses and international activities.

The core of the Company’s natural gas utility operations is Enbridge Gas Distribution Inc. (EGD) which
serves residential, commercial, industrial and transportation customers, primarily in central and eastern
Ontario as well as northern New York State. This business segment also includes natural gas distribution
activities in Quebec and New Brunswick.

Investments in natural gas pipelines include the Company’s interests in the United States portion
of Alliance Pipeline (Alliance Pipeline US), Vector Pipeline and transmission and gathering pipelines
in the Gulf of Mexico.

This segment also includes the Company’s investment in Aux Sable, a natural gas fractionation and
extraction business.

The commodity marketing businesses manage the Company’s volume commitments on Alliance and
Vector Pipelines, as well as perform commodity storage, transport and supply management services,
as principal and agent.

EnbridgE inc. 2009 ANNUAL rEPorT

SPOnSOrEd inVEStMEntS
Sponsored Investments includes the Company’s 27% ownership interest in Enbridge Energy Partners, L.P.
(EEP), Enbridge’s funding of 66.7% of the United States segment of the Alberta Clipper Project through EEP
and Enbridge Energy, L.P. (EELP) and a 72% economic interest (41.9% voting interest) in Enbridge Income
Fund (EIF). Enbridge manages the day-to-day operations and develops and assesses opportunities for each of
these investments, including both organic growth and acquisition opportunities.

EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines
and transports, gathers, processes and markets natural gas and NGLs. EIF is a publicly traded income fund
whose primary operations include a crude oil and liquids pipeline and gathering system, a 50% interest in
the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and partial interests in several green
energy investments.

cOrPOrAtE
Corporate consists of new business development activities and investing as well as financing activities,
including general corporate investments and financing costs not allocated to the business segments.
Corporate also includes the Company’s investments in green energy projects.

performance overview

(millions of Canadian dollars, except per share amounts)

Earnings Applicable to common Shareholders

liquids pipelines

natural Gas Delivery and Services

Sponsored Investments

Corporate

earnings per Common Share

Diluted earnings per Common Share

Adjusted Earnings 1

liquids pipelines

natural Gas Delivery and Services

Sponsored Investments

Corporate

Adjusted earnings per Common Share 1

cash Flow data

Three months Ended
December 31,

Year Ended December 31,

2009

2008

2009

2008

2007

141

300

0.81

0.80

141

(25)

239

0.64

102

143

(13)

264

0.72

0.71

106

(21)

202

0.55

445

635

141

334

328

958

111

(76)

1,555

1,321

4.27

4.25

3.67

3.64

454

289

151

(39)

855

332

302

101

(58)

677

287

344

(28)

700

1.97

1.95

286

324

(59)

637

2.35

1.88

1.79

Cash provided by operating activities

182

431

2,017

1,372

1,362

Cash used in investing activities

(1,162)

(2,091)

(3,306)

(2,853)

(2,229)

Cash provided by financing activities

912

1,930

1,109

1,840

904

dividends

Common Share Dividends Declared

Dividends per Common Share

revenues

Commodity Sales

139

0.37

123

0.33

555

1.48

489

1.32

453

1.23

2,491

3,116

9,720

13,432

9,536

transportation and other services

696

808

2,746

2,699

2,383

total Assets

total Long-term Liabilities

3,187

3,924

12,466

16,131

11,919

28,169

24,701

28,169

24,701

19,907

16,392

13,179

16,392

13,179

10,467

Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP.

For more information on non-GAAP measures see pages 36 and 102.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

EArningS APPLicAbLE tO cOMMOn ShArEhOLdErS
Earnings applicable to common shareholders for the three months ended December 31, 2009 were
$300 million, or $0.81 per common share, an increase of $36 million compared with $264 million,
or $0.72 per common share, for the three months ended December 31, 2008. The increase primarily
resulted from allowance for equity funds used during construction (AEDC) in Liquids Pipelines and
EELP, within Sponsored Investments, as well as a higher contribution from EEP, also within Sponsored
Investments. Other factors contributing to the increase include favourable tax rate changes and net
unrealized fair value gains on derivative financial instruments used to risk manage foreign exchange
variability. These earnings increases were partially offset by decreased earnings from Aux Sable due to
unrealized derivative fair value losses of $25 million recognized in the fourth quarter of 2009 compared
with similar gains of $35 million recognized in the fourth quarter 2008.

Earnings applicable to common shareholders were $1,555 million for the year ended December 31, 2009,
or $4.27 per common share, compared with $1,321 million, or $3.67 per common share, for the year ended
December 31, 2008. Included in earnings for the year ended December 31, 2009 was a $329 million gain
related to the sale of the Company’s investment in Oleoducto Central S.A. (OCENSA) and a $25 million
gain related to the sale of NetThruPut (NTP). Earnings for the year ended December 31, 2008 included
a gain of $556 million related to the sale of the Company’s investment in Compañía Logística de
Hidrocarburos CLH, S.A. (CLH). Excluding the impact of these dispositions, earnings for the year ended
December 31, 2009 were $436 million higher than for the year ended December 31, 2008. The increase
in earnings resulted from similar factors as for the three months results as well as unrealized foreign
exchange gains on the translation of foreign-denominated intercompany loans.

Earnings applicable to common shareholders were $1,321 million for the year ended December 31, 2008,
compared with $700 million for the year ended December 31, 2007. The increase in earnings resulted from
AEDC in Liquids Pipelines, a higher contribution from EGD and unrealized fair value gains on derivative
financial instruments in Aux Sable, Energy Services and Corporate, partially offset by decreased earnings
from International as the Company sold its interest in CLH in the second quarter of 2008. Earnings for
the year ended December 31, 2008 also reflected a $556 million gain on the sale of CLH, partially offset
by the recognition of a $32 million income tax charge as a result of an unfavourable court decision related
to previously owned United States pipeline assets.

AdJuStEd EArningS
Adjusted earnings were $239 million, or $0.64 per
common share, for the three months ended
December 31, 2009, compared with $202 million,
or $0.55 per common share, for the months ended
December 31, 2008. Adjusted earnings were
$855 million, or $2.35 per common share, for the
year ended December 31, 2009, compared with
$677 million, or $1.88 per common share,
for the year ended December 31, 2008.

1,555

1,321

667

645

577

615

556

700

459

392

Earnings Applicable to common Shareholders
(millions of Canadian dollars)

EnbridgE inc. 2009 ANNUAL rEPorT

The increase in adjusted earnings for both the fourth quarter and full year primarily resulted from increased
contributions from a number of the Company’s assets as follows:

•

AEDC on both Alberta Clipper (within Enbridge System and EELP) and Southern Lights Pipeline.
An increased contribution from EEP resulting from additional assets placed in service and related tariff
surcharges for recent expansions, the Company’s increased ownership interest and a more favourable
exchange rate.
Increased adjusted earnings from Enbridge Offshore Pipelines (Offshore) due to higher volumes and
a more favourable exchange rate.
Increased adjusted earnings from Energy Services due to higher volumes and the impact of realizing
favourable storage and transportation margins.

677

637

593

537

496

491

428

382

335

Adjusted Earnings
(millions of Canadian dollars)

855

These increases were partially offset by decreased
earnings from International as a result of the sale
of OCENSA in the first quarter of 2009 and CLH
in the second quarter of 2008.

Adjusted earnings for the year ended December 31,
2008 were $677 million, or $1.88 per common
share, compared with $637 million, or $1.79 per
common share, for the year ended December 31,
2007. The $40 million, or $0.09 per common share,
increase was primarily a result of:

•

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.
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 following
an additional subscription of Class A units in December 2008.
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.

These significant operating factors that increased 2008 adjusted earnings were partially offset by decreased
earnings from International as a result of the sale of CLH in the second quarter of 2008 and lost revenue
from Offshore as a result of Hurricanes Gustav and Ike.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

cASh FLOWS
The Company increased cash generated by operating activities each year from 2007 through 2009 on the
success of its growth projects and strong operating results, culminating with cash provided by operating
activities of $2,017 million for the year ended December 31, 2009. Operating cash flow, together with cash
provided by financing activities and proceeds from the sale of an international investment in 2009, funded
the Company’s ongoing growth initiatives in 2009, including capital expenditures of $3,225 million.

For the three months ended December 31, 2009, cash provided by operating and financing activities of
$182 million and $912 million, respectively, funded investing activities of $1,162 million, which consisted
primarily of capital expenditures. The decline in additions to property, plant and equipment in the fourth
quarter of 2009 compared with the fourth quarter of 2008 reflects the completion of several, substantial
construction projects that were under development in 2008, including Southern Access Mainline Expansion,
Line 4 Extension, Spearhead Pipeline Expansion and Hardisty Terminal projects.

diVidEndS
The Company has paid, and consistently increased,
common share dividends since its public inception in
1953. Based on estimated 2010 dividends, the annual
rate of increase has averaged 10.3% since 2000 and
10.0% since inception. In December 2009, the
Company announced a 15% increase in its quarterly
dividend to $0.425 per common share, or $1.70
annualized, effective March 1, 2010. The Company’s
dividend payout policy and ratio reflects a strong
and stable long-term outlook for its business.
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 2010 pay out is expected to be near the midpoint
of the range. In 2009, dividends paid per share were
63% of adjusted earnings per share (2008 – 70%,
2007 – 69%).

1.70

1.48

1.32

1.23

1.15

1.04

0.92

0.83

0.76

0.70

0.64

10e

dividends per common Share
(Canadian dollars per share)

The following chart shows dividends per share for the last 10 years, as well as estimated dividends for 2010,
based on the quarterly dividend of $0.425 per common share declared by the Board of Directors on
December 3, 2009.

EnbridgE inc. 2009 ANNUAL rEPorT

rEVEnuES
The Company generates revenue from two primary sources: commodity sales, and transportation and
other services.

Commodity sales revenue is earned through the Company’s natural gas distribution and energy marketing
activities and is subject to fluctuations in commodity prices. While revenues generated by the natural gas
distribution business vary with the price of natural gas, earnings remain neutral due to the pass through
nature of these costs. Similarly, the impact of commodity prices on revenues derived from the Company’s
energy marketing activities do not directly impact earnings since commodity prices also affect input costs
associated with such activities. Commodity sales revenue for the year ended December 31, 2009 totaled
$9,720 million compared with $13,432 million for the year ended December 31, 2008 and $9,536 for the
year ended December 31, 2007. Commodity sales revenue totaled $2,491 million in the fourth quarter of
2009, a 20% decline from the fourth quarter of 2008. Similar trends were experienced in commodity costs
over these same periods. The period-over-period variances are primarily driven by natural gas and crude oil
commodity prices, both of which increased notably in 2008 over 2007, only to experience subsequent
declines in 2009 amidst global economic uncertainty.

Transportation and other services includes revenues derived from the Company’s liquids transportation and
natural gas transmission services, renewable energy generation and related services. Transportation and other
services revenue for the year ended December 31, 2009 totaled $2,746 million compared with revenues of
$2,699 million for the year ended December 31, 2008. Main contributors to this variance include:

•

Increased contributions from Liquids Pipelines growth projects that entered service in 2009, including
the Line 4 Extension, Spearhead Expansion, LSr Pipeline (constructed in conjunction with the
Southern Lights Pipeline Project) and Hardisty Terminal projects.
Full year contributions from Waupisoo Pipeline and Ontario Wind Project that entered service at
various stages throughout 2008.
Completion of the Shenzi Lateral project within Offshore in April 2009.
Unfavourable variances in realized and unrealized gains and losses on derivative instruments used to
manage natural gas processing margins in Aux Sable.

Transportation and other services revenue for the three months ended December 31, 2009 was
$696 million compared with $808 million for the corresponding period of 2008. The decline is primarily
due to variances in realized and unrealized gains and losses on derivative instruments used to manage
natural gas processing margins in Aux Sable.

For the year ended December 31, 2008, transportation and other services revenue increased 13% to
$2,699 million compared with $2,383 million in 2007. Segment highlights include:

•

Revenues in the Liquids Pipelines segment increased due to higher base tolls on Enbridge System and
the new Waupisoo Pipeline included in the Enbridge Regional Oil Sands System.
Natural Gas Delivery and Services transportation revenue included higher Alliance Pipeline US tolls,
the impact of Vector Pipeline expansion and revenues from Neptune within Offshore.
EIF revenue, within Sponsored Investments, increased due to higher tolls at Alliance Pipeline Canada
and higher allowance oil revenue from the Saskatchewan System.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

FOrWArd-LOOKing inFOrMA tiOn
Forward-looking information, or forward-looking statements, have been included in this MD&A to provide
the Company’s 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. Forward-looking information or
statements included or incorporated by reference in this document include, but are not limited to, statements
with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share;
expected costs related to projects under construction; expected in-service dates for projects under construction;
expected capital expenditures; and estimated future dividends.

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; customer project
approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service
dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and
natural gas liquids, and the prices of these commodities, are material to and underlay all forward-looking
statements. These factors are relevant to all forward-looking statements as they may impact current and future
levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the
economies and business environments in which the Company operates, may impact levels of demand for the
Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to
the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on
a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings
or adjusted earnings and associated per share amounts, or estimated future dividends. The most relevant
assumptions associated with forward-looking statements on projects under construction, including estimated
in-service dates, and expected capital expenditures include: the availability and price of labour and pipeline
construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the
effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals
on construction schedules.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance,
regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange
rates, interest rates, commodity prices and supply and demand for commodities, 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.

EnbridgE inc. 2009 ANNUAL rEPorT

nOn-gAAP MEASurES
This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss 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/(loss) provides useful
information to investors and shareholders as it provides increased transparency and predictive value.
Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the
Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the
segments are not measures that have a standardized meaning prescribed by Canadian GAAP and are not
considered GAAP measures; therefore, these measures may not be comparable with similar measures
presented by other issuers. See Non-GAAP Reconciliations section for a reconciliation of the GAAP and
non-GAAP measures.

Corporate Vision and Key objective
Enbridge’s vision is to be the leading energy delivery company in North America. While the Company may
be viewed as having achieved elements of this vision, enhancing and sustaining this position remains a
continuing, long-term pursuit. The Company’s objective is to generate superior economic value for
shareholders through investing capital in a low-risk and disciplined manner. Consistently applied, such
stewardship could continue to generate attractive risk adjusted returns and in turn, provide for consistent
and growing dividend distributions and related capital appreciation.

Corporate Strategy
In support of its long-term vision, the Company employs several key strategies that guide decision making
across the enterprise. The Company’s strategies focus on:

•

leveraging the strategic location of its existing asset base;
developing new platforms for growth and diversification;
focusing on execution and operating excellence;
maintaining financial strength and flexibility; and
development of people, safety and environmental stewardship and corporate social responsibility.

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.

StrEngthEning Our cOrE buSinESS
The Company has an established history of serving the North American transportation needs of key
crude oil and natural gas markets. The Company is focused on adding value for customers and improving
customers’ profitability. This focus has aligned the Company with its customers and relevant supply and
demand fundamentals and has consistently formed a basis for the Company’s strategy. However, evolving
supply and demand fundamentals and growing competition are serving to create new opportunities and
challenges within the Company’s core businesses. Amid this changing business environment, the Company
is strengthening its core business position and aggressively pursuing new opportunities to expand and
extend its current asset base.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

Extending the reach of the current asset base is a multi-faceted objective. Key strategies within the Liquids
Pipelines segment include regional pipeline development, gathering system and storage infrastructure
expansion and new market access. Regional pipeline development primarily includes projects which connect
new oil sands lease production to existing hubs upstream of the Canadian mainline. The commercial
agreement and ongoing development activity related to the Woodland Pipeline represents a recent success
in realizing this objective. The Company is working with several other oil sands customers in developing
further transportation options for other projects in the oil sands region of northern Alberta. The Company
is also expanding its gathering systems in Saskatchewan and North Dakota which are strategically located to
capture increased production from the Bakken play. As transportation needs grow so too do terminal and
storage infrastructure requirements throughout the network, and the Company’s strategy will seek
opportunities to provide additional capacity in the Fort McMurray and Hardisty, Alberta regions as well as
in the Cushing, Oklahoma area. The Company continues to pursue opportunities to provide its customers
broader market access for Canadian bitumen and synthetic crudes and provide new sources of supply for
refiners. These efforts include leveraging existing pipeline networks into additional United States markets
as well as developing the proposed Northern Gateway pipeline to provide access to markets off the Pacific
Coast of Canada.

The fundamentals of the natural gas market in North America have been significantly altered in recent years
with the emergence of unconventional shale gas plays. The Company’s natural gas strategy includes
expanding its footprint in these emerging areas. Alliance Pipeline is well positioned to service the Montney
play in northeast British Columbia and is currently evaluating opportunities to expand its service offerings
in that area. Growth in the Haynesville shale in northwest Louisiana will lend additional support to the
Company’s proposed LaCrosse Pipeline. In addition to these onshore strategies, the Company continues to
pursue and win natural gas gathering expansion opportunities for ultra-deep projects in the Gulf of Mexico
which improve the risk and return profile of its investment in this area.

dEVELOPing nEW PLAtFOrMS FOr grOWth
And diVErSiFicA tiOn
The development of new platforms to diversify and sustain long-term growth is
an important strategy for Enbridge. Renewable energy is a significant source of
potential new growth as government initiatives and changing social beliefs are
creating new opportunities to deliver green energy solutions with risk and return
characteristics consistent with Enbridge’s low-risk business model. Renewable
energy projects can deliver stable cash flows and attractive returns though the
use of long-term power purchase agreements and fixed price engineering,
procurement and construction contracts. Renewable energy is also an important
part of Enbridge’s corporate social responsibility strategies, particularly with
respect to greenhouse gases (GHG) and the environment. Business development
efforts in renewable energy are focused primarily on clean power projects,
including wind, solar, waste heat recovery and fuel cell initiatives.

%
2
.
2
2

%
9
.
3
1

%
6
.
3
1

%
2
.
3
1

Similar to renewable energy, carbon dioxide (CO2) capture and sequestration
not only supports Enbridge’s social investment strategy but also represents
a potentially significant investment opportunity, should the technology
prove viable.

return on Average
Shareholders’ Equity
(percentage)

The Company’s Pathfinding group will also continue to explore other
longer-term energy technologies and facilitate innovations to assist its
customers and sustain its favourable position.

EnbridgE inc. 2009 ANNUAL rEPorT

FOcuSing On ExEcutiOn And OPErA tiOnS
Effective project execution and management of operations is a critical component of Enbridge’s strategic
plan. Operational excellence is particularly critical in an environment where customers have become
increasingly cost conscious, competition in the Company’s core business has intensified and environmental
stewardship has heightened.

Successful execution of the existing slate of commercially secured projects is a significant driver of Enbridge’s
near-term earnings and cash flow growth, and, therefore, a strategic priority. Project execution is a core
competency at Enbridge and the Company continues to build upon its project management skills and
processes, primarily through the Major Projects support team which was established in early 2008. Major
Projects now manages projects above $50 million for all liquids, natural gas and renewable projects and
continues to deliver projects on time and on budget. Major Projects focuses on success factors such as cost
estimation, regulatory permitting, material and labour sourcing and project governance. This competency is
highly valued and represents another Enbridge strength when competing for new business.

Cost efficiency and operating performance is becoming an increasing driver of value in a deregulated world
with increased competition. Under the incentive programs in place in certain of the Company’s business
units, rates and tolls, as well as the Company’s earnings, depend on cost and operating performance.
Returns in the Company’s natural gas gathering and processing business are also directly impacted by
operating costs. Key initiatives within the business units to manage costs include: upgrading management
information and reporting systems; rigorous cost tracking performance against relevant benchmarks; and
implementing best practice procurement strategies and enhanced “change management” processes to
ensure anticipated savings are realized from new programs.

Superior service, safety and reliability are integral to Enbridge’s customer value proposition. As always, cost
management initiatives are balanced with the safe and reliable operation of the Company’s system and the
need to ensure ongoing customer satisfaction. Throughout the organization, the Company is placing
increased emphasis on understanding customers and their decision processes, and on regular measurement
and management of service quality.

With respect to safety, Enbridge strives to employ the best available practices and technologies for integrity
management, systems maintenance and operations in order to mitigate risks to the public, our employees
and the environment.

PrESErVing FinAnciAL StrEngth And FLExibiLity
Disciplined capital management is a fundamental and company differentiating characteristic. As an asset-
intensive business, Enbridge creates value for its investors through maximizing the spread between its
return on invested capital and its cost of funds. Enbridge’s financial strategies ensure the Company has
sufficient liquidity to meet its capital requirements. To support this objective, the Company develops
financing plans and strategies to maintain and improve Enbridge’s credit ratings, diversify its funding
sources and maintain ready access to capital markets in both Canada and the United States.

A key tenet of the Company’s low-risk business model is mitigation of exposure to certain market price
risks. As a result, the Company has developed a robust risk management process which ensures earnings
volatility from manageable risk remains contained within the Company’s approved guideline of 5% of adjusted
earnings. Enbridge will continue to proactively hedge interest rate, foreign exchange and commodity price
exposures. As well, the continued management of counterparty credit risk remains an ongoing priority.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

EnVirOnMEnt AL StEWArdShiP And cOrPOrA tE SOciAL rESPOnSibiLity
Enbridge has strong corporate social responsibility practices. Enbridge defines corporate social responsibility
as conducting business in a socially responsible 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. Enbridge’s complete 2009 Corporate Social Responsibility Report can be
found at www.enbridge.com/csr2009. None of the information contained on, or connected to, the
Enbridge website is incorporated or otherwise part of this MD&A.

In 2009, the Company launched an enterprise-wide goal of achieving a neutral environmental footprint
by 2015. The goal consists of three key commitments:

•

we will conserve an acre of natural or wilderness land for every acre we permanently impact from
the construction of new facilities;
we will plant a tree for every tree we remove to build new facilities; and
we will generate a kilowatt of renewable power, through our investments in renewable and alternative
energy, for each kilowatt of power consumed by our operations.

To achieve its neutral footprint goal, Enbridge will work with nature conservancies in Canada and the
United States to help purchase natural wilderness lands throughout North America. The land that Enbridge
conserves will be similar to the areas that have been affected. The Company has also begun to plant trees.
To mark the Company’s 60th anniversary, Enbridge planted more than 60,000 trees in 60 communities
along its rights of way in Canada and the United States.

Enbridge’s community investments are also noteworthy. The Company launched three major community
investment initiatives in 2009. School Plus, in partnership with the Assembly of First Nations, provides
financial support to enrichment programming and extracurricular activities in First Nations schools near
major Enbridge rights-of-way; the Safe Community program serves to confirm the priority Enbridge places
on health and safety in our right-of-way communities, by directly and visibly supporting those right-of-way
organizations who would respond to an emergency on one or more of our lines or at one of our facilities;
and the Natural Legacy program focuses on tree planting and specific environmental initiatives in
communities in proximity to our major rights-of-way.

To complement community investments in its Canadian and United States operating areas, Enbridge
will also exercise leadership in extending the benefits of energy availability to underdeveloped countries.
In 2009, Enbridge launched the energy4everyone Foundation, which has applied to the Canadian Revenue
Agency for charitable status, with a vision of empowering people and communities to improve their own
lives by providing energy to everyone. The Foundation aims to leverage the expertise and resources of the
Canadian energy industry to affect significant enhancement in quality of life through the delivery and
deployment of affordable, reliable and sustainable energy services and technologies to communities in
need around the world.

EnbridgE inc. 2009 ANNUAL rEPorT

5
3
7
,
2

0
.
9
4
5
1

6
0
7
,
2

6
2
7
,
2

1
6
7
,
2

0
.
2
0
5
1

0
.
5
8
3
1

0
.
0
7
3
1

07
� Oil Sands
� Other

canadian crude
Oil Production
(thousands of barrels per day)

Sources: National Energy Board

(2007–2009), Canadian Association

of Petroleum Producers (2010).

Industry Fundamentals
SuPPLy And dEMAnd FOr LiquidS
North American liquids infrastructure fundamentals remain favourable for
the foreseeable future. The United States continues to be reliant on imported
crude oil to satisfy its needs. Western Canada has surpassed both Mexico and
Saudi Arabia to become the largest crude oil exporter to the United States.
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 174 billion barrels compare with Saudi
Arabia’s proved reserves of approximately 260 billion barrels. The National
Energy Board (NEB) estimates that total Western Canadian Sedimentary Basin
(WCSB) production averaged approximately 2.5 million barrels per day (bpd)
in 2009 (2008 – 2.4 million bpd; 2007 – 2.4 million bpd). Other sources of
supply growth include deepwater Gulf of Mexico, which is also distant from
market, and some of the shale plays like the Bakken in the midcontinent.

In connection with the global economic downturn, crude oil price weakness
and volatility caused some crude oil producers to defer projects that were
planned to commence over the next decade. More recently, improved
macroeconomic conditions, higher oil prices and reduced development costs
have spurred a number of oil sands projects to be revisited and sanctioned;
however, a tempered rate of growth is expected in the near term relative to
prior forecasts. The Canadian Association of Petroleum Producers’ (CAPP)
June 2009 growth case estimates indicate that future WCSB production is

expected to steadily increase to more than 3.6 million bpd by 2019. This forecasted growth of
1.1 million bpd is attributed to increased oil sands production in Alberta.

While global demand for crude oil is expected to resume its growth trajectory given the strength in emerging
regions, North American demand for crude oil in the next few years is expected to remain relatively flat.
Inventories of crude oil and refined product remain very high as influenced by the recent economic
downturn and the emergence of biofuels. Refining economics have materially weakened over this period,
contributing to the recent announcements of a variety of marginal refinery closures. Most of these closures
are in regions that are not served by Enbridge infrastructure. Other more profitable refineries are growing
and have reconfiguration projects under construction. Some of these refineries currently process Canadian
crude and some are preparing to. Accordingly, there remain meaningful growth opportunities for Canadian
crude oil into existing and new markets in the United States.

With the expected increase in heavy oil production in western Canada, there is an increasing requirement
for condensate (or similar light commodity) to be used as a blending agent in order to transport these high
viscosity volumes to market. Condensate is a light hydrocarbon which is conventionally a by-product of
natural gas production or NGLs fractionation. Production of this commodity is decreasing in western
Canada but with the demand for diluents from heavy oil producers, there has been an increasing need to
import. Currently, volumes are transported via rail to Alberta from the United States as well as from
international sources via tankers and rail from the West Coast. In mid-2010, Enbridge’s Southern Lights
condensate pipeline will be in service bringing incremental volumes of condensate from the United States
to Alberta to meet producer’s needs.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

SuPPLy And dEMAnd FOr nA turAL gAS
Over the course of the last year the North American gas industry has evolved
meaningfully. Shale gas is proving to be an enormous and wide spread resource
that may alter continental gas flow directions. With robust supplies of shale gas
located in the lower 48 United States, it may not be necessary to import large
quantities of liquefied natural gas (LNG) into North America as previously
envisioned, and pipelines to access northern gas may be deferred for many
years. Growth expectations for shale gas are so strong that the industry’s
greatest challenge now has transitioned to how to sustain development by
extending market demand.

Since the 1990s, production in the Rocky Mountain region of the
United States, primarily from tight shale gas, has more than doubled to
approximately 9 billion cubic feet per day (bcf/d). This amount of growth
will likely repeat over the next 12 to 15 years. Established shale plays in the
Midcontinent region such as the Barnett, Fayetteville and Woodford, along
with emerging plays such as Haynesville in northwest Louisiana and Marcellus
in Appalachia, have now become the continental gas development hotspots.
After seeing a decline in drilling rig activity in some of these plays in the summer
of 2009, activity in these regions has increased in recent months with the prospect
of higher future prices. This increased drilling could contribute significantly to
supply in 2010, extending the natural gas price weakness seen in 2009.

2
7

1
7

8
6

07
� Shale
� Other

north American
natural gas Production
(billions of cubic feet per day)

Sources: Energy Information

Administration (United States),

National Energy Board (Canada),

Enbridge research.

Additional shale plays exist throughout North America, such as the Horn River
and Montney in British Columbia and Utica shale in Quebec. Shale plays
located closer to populated markets, such as the Marcellus, are particularly notable in that they require
limited infrastructure to access premium prices. If market area shale gas proves to be extensive, it may have a
significant impact on the long haul transport business, displacing supplies from distant basins and offloading
associated pipelines. On the other hand, opportunities abound for gathering, processing and short haul
connectivity.

North American natural gas demand contracted in 2009 as a direct impact of the recession. Industrial
demand weakened the most while low gas prices led to gas for coal substitution in power generation,
supporting gas demand in that sector. Following the anticipated economic recovery, natural gas demand is
expected to grow in all sectors but gas-fired generation may lead the group as natural gas is expected to be a
preferred fuel in an increasingly carbon-conscious marketplace. While gas fired generation growth will
occur, it will be restricted for the next several years as coal projects already under construction enter service
and more renewable power projects come on line.

Even with an economic recovery, growth in unconventional gas supply is expected to be limited by growth
in demand, resulting in North American prices remaining lower relative to recent years. This lower price
level should be further supported by the relatively lower, and increasingly so, cost of developing shale gas
supply. With a lower cost structure, North American gas is likely on a divergent path with oil, which should
help support strong fractionation spreads.

Global LNG production is ramping up with several projects under construction. In the near term, LNG
supply from these new projects will be seeking markets during a global recession. North American markets
may be susceptible to dumping of LNG for short periods, impacting gas prices, at least until global
economies recover.

Overall, abundant low cost gas supplies are anticipated to be positive news for North American gas markets
and are likely to lead to renewed interest in natural gas as an economically priced, clean burning fuel.

EnbridgE inc. 2009 ANNUAL rEPorT

Growth projects
Enbridge is in the midst of its largest capital program in the Company’s 60 year history. During 2008
and 2009, the Company has completed more than $4.5 billion of new growth projects and has $7 billion of
additional commercially secured projects scheduled to come into service in 2010 and 2011, with a further
$5 billion secured for post-2011 in service. In addition, the Company has a further $30 billion in growth
opportunities under development, but not yet commercially secured, for the post-2011 period, of which it
expects to be successful on a significant portion.

The following table summarizes commercially secured projects, within each of the Company’s business
segments, which were recently completed, or are currently under active development or construction.
These growth projects contribute to anticipated annual earnings per share growth rates expected to average
10% through 2013, with the inventory of projects under development expected to sustain this growth rate
into the second half of the decade.

Actual/Estimated
Capital Cost 1

Expenditures
to Date

Actual/Expected
In-Service Date

Status

(in billions of Canadian dollars,
unless stated otherwise)

LiquidS PiPELinES

1. Southern Access Mainline

$0.2 billion

2008

expansion – Canadian portion

2. Spearhead pipeline expansion

uS$0.1 billion uS$0.1 billion

2009

3. line 4 extension

$0.3 billion

4. Hardisty Contract terminal

$0.6 billion

5. Alberta Clipper – Canadian portion $2.3 billion

$2.1 billion

2009

2010

6. Southern lights pipeline

$0.5 billion +
uS$1.7 billion

$0.5 billion +
uS$1.4 billion

light Sour line – 2009;
Diluent line – 2010

7. Woodland pipeline – phase I

$0.5 billion

2012

no significant
expenditures
to date

8. Fort Hills pipeline System

~$2.0 billion

$0.1 billion

tBD

nAturAL gAS dELiVEry And SErVicES

9. Shenzi lateral

uS$0.1 billion uS$0.1 billion

2009

10. Walker Ridge Gas

Gathering System

11. Big Foot oil pipeline

uS$0.5 billion no significant
expenditures
to date

uS$0.3 billion no significant
expenditures
to date

2014

Complete

Mechanically complete

under construction

Regulatory and
pre-construction

Commercially secured;
pending customer timing

Complete

pre-construction

Sponsored Investments

Corporate

Expected
2010

Actual
2009

Actual
2008

1,022

2,662

2,898

677

258

552

440

400

217

544

700

109

2,509

3,719

4,251

The Company’s capital expansion initiatives are described in Growth Projects.
The Company also requires capital for ongoing core maintenance and capital
improvements in many of its businesses. In total, Enbridge expects to spend
approximately $2,509 million during 2010 on maintenance and capital projects,
including equity investments in EEP and EELP (within Sponsored Investments),
which are substantially secured. While consistent or still in excess of longer term
historic levels, the expected decline in 2010 expenditures relative to 2009 and
2008 reflects the completion of certain large multi-year construction projects.
The 2010 expected corporate capital expenditures increase reflects new green
investments in wind and solar power generation. 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, or through access to capital markets as required.

The decision to finance with debt or equity is based on the capital structure
for each business and the overall capitalization of the consolidated enterprise.
Certain of the regulated pipeline and gas distribution businesses issue long-
term debt to finance capital expenditures. This external financing may be
supplemented by debt or equity injections from the parent company. Debt,
and equity when required, has been issued 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 issuance of replacement debt.

1
5
2
,
4

9
1
7
,
3

9
0
5
,
2

Actual
08

Expected
10

Actual
09
� Liquids Pipelines
� Natural Gas Delivery and Services
� Sponsored Investments
� Corporate

capital Expenditures
and investments
(millions of Canadian dollars)

EnbridgE inc. 2009 ANNUAL rEPorT

FinAncing ActiVitiES
In 2009, the Company generated cash of $1,109 million through financing activities compared with
$1,840 million and $904 million in 2008 and 2007, respectively.

Significant financing activities in 2009 include medium-term note issues of $1,500 million compared
with $498 million in 2008 and $1,342 million in 2007. In 2009, the Company issued both a $400 million
seven-year and 10-year term note along with a $200 million 30-year term note. Enbridge Pipelines Inc.
(EPI) issued $300 million and $200 million in 10-year and 30-year term notes, respectively. In comparison,
in 2008 EGD issued a $200 million five-year term note and EPI closed a $300 million 10-year term note;
2007 included the issuance of US$1,100 million in term notes issued in the United States market by
the Company and $200 million of term notes issued by EGD in the Canadian market. Cash generated
through debenture and term note issues is partially offset by repayments of debentures and term notes
which totaled $516 million, $602 million and $635 million for the years ended December 31, 2009, 2008
and 2007, respectively.

In 2008, the Company secured financing that is non-recourse to the Company specific to the Canadian
and United States segments of the Southern Lights Project. Net proceeds on Southern Lights financing
were $343 million for the year ended December 31, 2009 and $1,238 million for the year ended
December 31, 2008.

Short-term borrowings are used primarily to finance near term working capital requirements, including
inventory at EGD. Due to the decline in natural gas commodity prices in 2009 compared with 2008, and
the resultant decline in cash needed to finance inventory requirements, the Company made net repayments
on short term borrowings totaling $366 million in 2009. In comparison, the net change in short-term
borrowings provided cash of $329 million in 2008, and a net repayment of short-term borrowings of
$262 million was made in 2007.

Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on
the purchase of common shares with reinvested dividends. For the year ended December 31, 2009,
dividends declared were $555 million (2008 – $489 million), of which $414 million (2008 – $359 million)
were paid in cash and reflected in financing activities. The remaining $141 million of dividends declared
were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash
payment. For the year ended December 31, 2009 and December 31, 2008, 25% and 27%, respectively,
of total dividends declared were reinvested.

Outstanding Share data 1

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

Common Shares – issued and outstanding (voting equity shares)

total issued and outstanding stock options (7,512,712 vested)

Outstanding share data information is provided as at February 10, 2010.

Number

5,000,000

378,351,456

15,735,885

MAnAgEMEnt’S diScuSSiOn And AnALySiS

Contingencies and Commitments
EnbridgE gAS diStributiOn inc.

bloor Street incident
EGD was 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 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 and the appeal was heard by the Court during November and December 2009.
The Court’s decision has been reserved and EGD expects it to be released in early 2010. EGD does not believe
any fines that may be levied would have a 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.

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 LitigA tiOn
The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings
which arise in the normal course of business, including interventions in regulatory proceedings and challenges
to regulatory approvals and permits by special interest groups. 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.

cOMMitMEntS
The Company has signed contracts for the purchase of services, pipe and other materials totaling
$697 million. Of this amount, $406 million is to be used in the construction of several Liquids Pipelines
projects including Southern Lights Pipeline.

On July 20, 2009, the Company committed to fund 66.7% of the United States segment of the Alberta
Clipper Project through EEP and EELP. The total cost of the United States segment is estimated at
US$1,300 million.

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

Total

Less than 1 year

1–3 years

3–5 years

After 5 years

(millions of Canadian dollars)

long-term debt 1

non-recourse long-term debt 1

Capital and operating leases

long-term contracts 2,3

post-employment benefit obligations 4

12,168

1,472

176

1,654

600

109

834

total Contractual obligations

15,544

1,635

151

140

444

–

775

1,269

10,148

156

238

–

1,067

138

–

1,698

11,436

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

Approximately $406 million of these contracts are commitments for materials related to the construction of Liquids Pipelines projects. Changes to the

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

Contracts totaling $138 million are between the Company and proportionately consolidated joint venture entities.

Assumes only required payments will be made into the pension plans in 2010. Contributions are made in accordance with the independent actuarial

valuations as of December 31, 2009. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

EnbridgE inc. 2009 ANNUAL rEPorT

Quarterly Financial Information 1

2009

Total

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

Revenues

3,783

2,868

2,629

3,186

12,466

earnings applicable to common shareholders

earnings per common share

Diluted earnings per common share

Dividends per common share

558

1.54

1.53

0.37

393

1.08

0.37

304

0.83

0.37

300

1,555

0.81

0.80

0.37

4.27

4.25

1.48

2008

Total

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

Revenues

3,968

3,871

4,368

3,924

16,131

earnings applicable to common shareholders

earnings per common share

Diluted earnings per common share

Dividends per common share

251

0.70

0.33

658

1.83

1.81

0.33

148

0.41

0.33

264

0.72

0.71

0.33

1,321

3.67

3.64

1.32

Quarterly financial information has been extracted from financial statements prepared in accordance with Canadian GAAP.

Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but
not limited to, seasonality in the Company’s gas distribution businesses, fluctuations in market prices such
as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of
in-service dates of new projects.

EGD and the Company’s other gas distribution businesses are subject to seasonal demand. A significant
portion of gas distribution customers use natural gas for space heating; therefore, volumes delivered and
resultant revenues and earnings typically increase during the winter months of the first and fourth quarters
of any given year. Revenues generated by EGD and other gas distribution businesses also vary from quarter-
to-quarter with fluctuations in the price of natural gas, although earnings remain neutral due to the pass
through nature of these costs. Further, in EGD, as a result of continued changes in customer billing to
increase the fixed charge portion and decrease the per unit volumetric charge, revenues and earnings will
shift from the colder winter quarters progressively to the warmer summer quarters, with no material impact
on full year revenue and earnings. This change will also impact the comparability of a given quarter from
year to year. In each of the four quarters of 2009, revenues generated by EGD and other gas distribution
businesses have declined compared with the corresponding quarters of 2008 primarily due to depressed
natural gas prices throughout 2009 compared with the prior year.

The Company actively manages its exposure to market price risks including, but not limited to, commodity
prices and foreign exchange rates. To the extent derivative instruments used to manage these risks are
non-qualifying for the purposes of hedge accounting, unrealized fair value gains and losses on these instruments
will impact earnings. Most notably, earnings were negatively impacted by an unrealized derivative fair value
loss of $43 million in the first quarter of 2009, and positively impacted by unrealized derivative fair value
gains of $115 million, $102 million and $33 million for the second, third and fourth quarters of 2009,
respectively. In comparison, earnings for the fourth quarter of 2008 included an unrealized derivative fair
value gain of $26 million, while the first three quarters of 2008 had no similar impact. Further, second,
third and fourth quarter earnings of 2009 include unrealized foreign exchange gains on translation of
intercompany loans of $68 million, $50 million and $15 million, respectively, compared with nil in each
of the corresponding periods of 2008.

Other significant items that impacted the quarterly results include a gain of $329 million on the disposition
of the Company’s investment in OCENSA in the first quarter of 2009 and a gain on sale of the Company’s
investment in CLH in the amount of $556 million in the second quarter of 2008.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

Finally, the Company is in the midst of a substantial capital program and the timing of construction
and completion of growth projects may impact the comparability of quarterly results. The Company’s
capital expansion initiatives, including construction commencement and in-service dates, are described
in Growth Projects.

Related party transactions
All related party transactions are provided in the normal course of business and, unless otherwise noted,
measured at the exchange amount, which is the amount of consideration established and agreed to by the
related parties.

EEP, an equity investee, 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, for
the year ended December 31, 2009 are $342 million (2008 – $302 million; 2007 – $267 million) to EEP
and $6 million (2008 – $6 million; 2007 – $5 million) to Vector Pipeline. At December 31, 2009, the
Company has accounts receivable of $38 million (2008 – $41 million) from EEP and $1 million
(2008 – $1 million) from Vector Pipeline.

The Company has provided EEP with an unsecured revolving credit agreement for general liquidity
support. The credit facility provides for a maximum principle amount of US$500 million for a three-year
term maturing in December 2010. At December 31, 2009 and 2008, there were no amounts outstanding
on this facility.

EGD, a subsidiary of the Company, has contracts for gas transportation services from Alliance and Vector
Pipeline. EGD is charged market prices for these services. For the year ended December 31, 2009, EGD
was charged $42 million (2008 – $41 million; 2007 – $36 million) for services from Alliance Pipeline and
$29 million (2008 – $27 million; 2007 – $25 million) from Vector Pipeline.

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. For the year ended December 31, 2009,
amounts purchased were $16 million (2008 – $52 million; 2007 – $43 million) and sales were $6 million
(2008 – $7 million; 2007 – $4 million).

Enbridge Gas Services Inc. and Enbridge Gas Services (US) Inc., subsidiaries of the Company, have
transportation commitments, measured at market value, through 2015 on Alliance Pipeline Canada,
Alliance Pipeline US and Vector Pipeline. For the year ended December 31, 2009, amounts paid to Alliance
Pipeline Canada were $9 million (2008 – $9 million; 2007 – $8 million), amounts paid to Alliance Pipeline
US were $7 million (2008 – $7 million; 2007 – $7 million) and amounts paid to Vector Pipeline were
$16 million (2008 – $16 million; 2007 – $16 million).

Tidal Energy Marketing Inc., a subsidiary of the Company, purchases and sells commodities at prevailing
market prices with EEP and a subsidiary of EEP. For the year ended December 31, 2009, amounts
purchased were $80 million (2008 – $24 million; 2007 – $5 million) and sales were $7 million
(2008 – $9 million; 2007 – $6 million).

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. For the year ended December 31, 2009, amounts charged by CustomerWorks to EGD were nil
(2008 – nil; 2007 – $26 million). CustomerWorks also rented an automated billing system from Enbridge
Commercial Services Inc. (ECS), a subsidiary of the Company. For the year ended December 31, 2009,
amounts charged by ECS to CustomerWorks were $2 million (2008 – $2 million; 2007 – $2 million).

EnbridgE inc. 2009 ANNUAL rEPorT

ALbErtA cLiPPEr PrOJEct
In July 2009, the Company committed to fund 66.7% of the cost to construct the United States segment
of the Alberta Clipper Project. The total cost of the United States segment, which is expected to be ready
for service on April 1, 2010, is estimated at US$1,300 million, with total expenditures to date of
US$900 million. Further information on this project is included in Growth Projects.

The Company is funding 66.7% of the project’s equity requirements through EELP, an equity investee.
The Company has provided a $282 million (US$270 million) loan to EEP for debt financing related to the
construction. At December 31, 2009, this amount is included in Accounts Receivable and Other. The loan,
denominated in United States dollars, bears interest based on variable short-term rates.

In August 2008, the Company transferred $23 million, measured at market value, of 36 inch diameter line
pipe to EEP for use in constructing the United States segment of the Alberta Clipper Project.

SPEArhEAd nOrth PiPELinE
In May 2009, the Company sold a section of the Spearhead Pipeline to its affiliate EEP for proceeds of
US$75 million. This related party transaction has been recorded at the exchange amount which was
equal to the carrying amount.

SOuthErn LightS PrOJEct
In February 2009, as part of its Southern Lights Pipeline Project, the Company transferred the United
States section of a newly constructed light sour pipeline to EEP in exchange for a pipeline referred to as
Line 13. This non-monetary transaction has been recorded at the carrying amount.

In connection with the exchange discussed above, EEP entered into an arrangement to lease Line 13 from
the Company for monthly payments of US$2 million to ensure adequate southbound pipeline capacity prior
to the completion of the Alberta Clipper Project. The lease arrangement was effective in February 2009
and can be terminated at any time with written notice.

LOng-tErM rEcEiVAbLE FrOM AFFiLiA tE
The affiliate long-term note receivable of $159 million (US$130 million) as at December 31, 2008,
included in Deferred Amounts and Other Assets, was repaid by EEP in November 2009. Interest income
for the year ended December 31, 2009 related to the note receivable was $11 million (2008 – $12 million;
2007 – $10 million).

Risk Management
Enbridge’s value proposition is based on maintaining a very low risk profile. Over 85% of the Company’s
earnings come from regulated businesses; over 80% of its revenues are volume protected under cost of
service rate-making or long-term take-or-pay arrangements; and more than 95% of the Company’s revenues
come from investment grade customers. Other risks, such as capital cost and inflation, are generally
transferred to customers through contractual arrangements. In addition to contractually eliminating the
majority of its business risk, the Company has formal risk management policies, procedures and systems
designed to mitigate any residual risks, such as market price risk, credit risk and operational risk. In addition,
the Company performs an annual corporate risk assessment to scan its environment for all potential risks.
Risks are ranked based on severity and likelihood and results are considered in the Company’s strategic and
operating plans. Through this process, a range of ongoing mitigants are identified and implemented.

MArKEt PricE riSK
The Company’s earnings, cash flows and other comprehensive income (OCI) are subject to movements in
foreign exchange rates, interest 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 Market Price Risk
Management Policy which outlines a risk management governance framework and specific exposure limits to
minimize the likelihood that adverse earnings fluctuations arising from movements in market prices across all
of its businesses will exceed a defined tolerance.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

Earnings at Risk (EaR), a variant of Value at Risk, 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
the maximum adverse change in projected 12-month earnings that could result from market price risk over
a one-month period within a 97.5% confidence interval. The philosophy behind this metric is to identify the
potential risk to the Company’s annual earnings target, taking into account the illiquidity of certain
exposure positions. The Company’s policy is to limit EaR to a maximum of 5% of the next 12 months of
forecasted earnings. Earnings exposure to market price risk is managed within the overall consolidated EaR
limits of the Company. Further, commodity price risk is managed within business unit EaR sub-limits.

Various hedging programs have been put into place to help ensure that the residual market price risks
remain within policy limits, and thus help provide the Company with a general stability of earnings over a
short and medium term horizon. The following section summarizes the primary types of market price risks
to which the Company is exposed, and outlines the financial derivative hedging programs implemented.

Foreign Exchange risk
The Company’s earnings, cash flows and OCI are subject to foreign exchange rate variability, primarily arising
from the performance of its United States dollar denominated subsidiaries. The Company has implemented
a policy where it must hedge a minimum level of foreign currency denominated earnings exposures identified
over the next five year period. The Company currently has hedged over 80% of its forecast adjusted earnings
through 2014 at an average rate of approximately $1.20 C$/US$. The Company may also hedge anticipated
foreign currency denominated purchases or sales, foreign currency denominated debt, as well as certain
equity investment balances and net investments in foreign denominated subsidiaries.

interest rate risk
The Company’s earnings and cash flows are exposed to short term interest rate variability due to the regular
repricing of its variable rate debt obligations. Floating to fixed interest rate swaps and options are used to
hedge against the effect of future period interest rate movements. The Company has implemented a hedging
program to significantly mitigate the volatility to variable rate interest expense through 2013 at an average
rate of 2.2%.

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates on future
fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future
interest rate movements. The Company has implemented a hedging program to significantly mitigate its
exposure to long term interest rate variability on select forecast term debt issuances through 2013. A total
of $2,500 million of future fixed rate term debt issuances have been hedged at an average government bond
rate of 4%. Further, many of the Company’s existing commercial arrangements and certain construction
projects provide for the full recovery of financing costs through tolls.

The Company also 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.

EnbridgE inc. 2009 ANNUAL rEPorT

commodity Price risk
The Company’s earnings and cash flows 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 subsidiaries. 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 Company has implemented a hedging program, through 2011, to mitigate the volatility from
fractionation spreads (natural gas/NGLs) that impact earnings from its ownership in the Aux Sable natural
gas processing plant.

The following table summarizes the EaR as a percentage of forecast earnings from the main groups of market
price risk after the impact of the Company’s hedging programs. These EaR numbers are based on business
conditions and hedging programs as of December 31, 2009 and may not be applicable to other periods.

risk

(% of forecast 12 month forward earnings)

Foreign exchange

Interest Rate

Commodity

total

Ear

0.3%

–%

2.3%

2.6%

crEdit riSK
The Company’s earnings and cash flows could be exposed to the risk of payment default by its shippers or
other counterparties. Given the Company’s desire to maintain a stable and consistent earnings profile, it has
implemented a Counterparty Credit Risk Policy outlining a governance framework and specific exposure
limits to minimize the likelihood that adverse earnings fluctuations arise from counterparty defaults across
any of its businesses.

Further initiatives to mitigate credit exposure include ensuring that all counterparties shipping on the
regulated oil pipelines that have credit ratings below investment grade provide the carrier with a form of
credit assurance, for example, a creditworthy parental guarantee, letter of credit or cash.

Credit risk in the Natural Gas Delivery and Services segment is mitigated by its large and diversified customer
base and its 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
tightened credit terms, including obtaining additional security, to minimize the consequences of the risk of
default on receivables. Generally, the Company classifies receivables older than 30 days as past due.

The Company minimizes credit risk to derivatives counterparties by entering into risk management
transactions only with institutions that possess solid investment grade credit ratings or which 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 reduced 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 2009, despite the severe market conditions, the Company did not
suffer any material credit losses.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

FinAncing riSK
The Company’s financing risk relates to the price volatility and availability of debt to finance organic growth
projects and refinance existing debt maturities. This risk is directly influenced by market factors, as Canadian
and United States financial market conditions can change dramatically, affecting capital availability.

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

Liquidity riSK
Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including
commitments and guarantees. 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, as well as 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 United States public capital markets.

MAturitiES OF dEriVA tiVE FinAnciAL LiAbiLitiES
For the years ending December 31, 2010 through 2014, and thereafter, the Company has estimated the
following undiscounted cash flows will arise from its derivative instruments based on valuation at the
balance sheet date.

(millions of Canadian dollars)

Cash inflows

Cash outflows

net cash flows

2010

2011

2012

2013

2014

Thereafter

182

(167)

106

(29)

136

(5)

131

155

(7)

148

(3)

(25)

The maturity profile of non-derivative financial liabilities is presented in Liquidity and Capital Resources.

gEnErAL buSinESS riSKS

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, changes in shipper support over time, delays in or
changes to government and regulatory approvals, cost escalations, construction delays, shortages and
in-service delays (collectively, Execution Risk). The Company’s 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, and 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 centralized and clearly defined governance structure and process for all major projects
with dedicated resources organized to lead and execute each major project. Capital constraints and cost
escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain
complete or a share of capital cost excess. The Company’s emphasis on corporate social responsibility
promotes generally positive relationships with landowners, aboriginal groups and governments which help to
facilitate right-of-way acquisition, permitting and schedule. Detailed cost tracking and centralized purchasing

EnbridgE inc. 2009 ANNUAL rEPorT

is used on all major projects to facilitate optimum pricing and service terms. 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.

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. While the Company feels the level of insurance is adequate, it may not
be sufficient to cover all potential losses.

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. Recently shippers have challenged toll increases on various pipelines owned by some of
Enbridge’s competitors, and certain of Enbridge’s shippers have sought to delay the in-service date and
implementation of the tariff on the Company’s Alberta Clipper Project. Enbridge retains dedicated
professional staff and maintains strong relationships with customers, interveners and regulators to help
minimize regulatory risk.

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 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 GHG
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
crude oil and natural gas. The Company could be targeted, along with the oil sands industry, by
environmental groups attempting to draw attention to GHG emissions.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

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.

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. Crown consultation has the potential to delay regulatory approval
processes and construction, which may affect project economics. In some cases, respecting Aboriginal rights
may mean regulatory approval is denied or made economically challenging.

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 benefits from the Company’s 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.

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 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 Corporate Social Responsibility (CSR) program
also reports on the Company’s responsiveness to environmental and community issues. Please see
Enbridge’s annual CSR report, available online at www.enbridge.com/csr2009 for further details
regarding the CSR program.

Legislation risk

Climate Change legislation
The Canadian Federal Government has indicated that Canada will target a 17% reduction of GHG
emissions by 2020, based on 2006 emission levels. It has also signaled that 90% of Canada’s electricity will
be provided by non-emitting sources, such as hydro, nuclear, clean-coal, solar and wind, by 2020. Details
of Canada’s GHG management plan will not be released until there is clarity in the United States about its
intention to regulate GHG emissions. Canadian regulations will likely be compatible with those of the
United States in order for Canadian businesses to remain competitive and avoid the potential for punitive
trade sanctions. It is uncertain how climate legislation could affect the industry. Enbridge continues to
monitor this activity.

EnbridgE inc. 2009 ANNUAL rEPorT

low Carbon Fuel Standards
California and Oregon have adopted Low Carbon Fuel Standards and other states (including the seven New
England states) are considering the same. If widely adopted, such standards could limit United States refiners
from importing oil sands products, as they are more energy-intensive to process than conventional crude.
Flow restrictions of oil sands products to the United States would increase interest in exports to Asia, and
consequently increase interest in projects like Enbridge’s Northern Gateway Project.

Renewable energy
Enbridge has significant interest in wind and solar power and is well positioned to expand this portfolio.
Many programs to encourage and advance renewable energy exist in Canada and the United States as well
as individual provinces and states. For example, the Feed-in-Tariff program introduced by the Ontario
Green Energy Act has created significant opportunities for renewable energy growth in Ontario. The
extension of the Production Tax Credit, introduction of a federal cash grant and the potential for a
nationwide minimum Renewable Portfolio Standard have accelerated renewable energy projects across the
United States. Enbridge continues to assess and advance renewable energy opportunities and monitor
potential changes to government policies and incentives that may positively or negatively impact renewable
energy projects in a particular province, state or federal jurisdiction.

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. The Company offers competitive compensation
programs, training, leadership development and succession planning. Further, the supply of human
resources is balanced between hiring full-time employees and expanding the contractor workforce,
particularly in the Major Projects’ department.

terrorism
The risk of terrorism continues to be monitored due to the high profile of the petroleum industry
in Canada and the reliance of the United States 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.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

Financial Instruments

held for
Trading

Available
for Sale

Loans and
receivables

held to
maturity

other
Financial
Liabilities

Qualifying
Derivatives

Non-
Financial
Instruments

Total

Fair
value 1

december 31, 2009

(millions of Canadian dollars)

Assets

Cash and cash equivalents

327

Accounts receivable and other

long-term investments
Deferred amounts and

other assets

Liabilities

Short-term borrowings

Accounts payable and other

Interest payable

long-term debt

non-recourse long-term debt

other long-term liabilities

–

288

–

2,054

–

181

–

327

302

2,484 2,182

–

2,071

2,312

187

197

1,940

2,425

485

–

508

–

2,177

–

104

– 12,283

–

1,515

–

508

163

2,463 2,300

–

104

(101) 12,182 13,450

(9) 1,506

–

1,165

1,207

held for
Trading

Available
for Sale

Loans and
receivables

held to
maturity

other
Financial
Liabilities

Qualifying
Derivatives

Non-
Financial
Instruments

Total

Fair
value 1

December 31, 2008

(millions of Canadian dollars)

Assets

Cash and cash equivalents

542

Accounts receivable and other

long-term investments
Deferred amounts and

other assets

Liabilities

Short-term borrowings

Accounts payable and other

Interest payable

long-term debt

non-recourse long-term debt

other long-term liabilities

–

1,869

–

167

405

–

874

1,965

102

– 10,795

1,669

–

542

381

2,322

1,948

1,866

2,492

492

249

1,001

1,318

317

–

874

396

2,411

2,015

–

102

(106) 10,689 11,173

(10)

1,659

1,672

–

212

259

Fair value does not include non-financial instruments, which includes investments accounted for under the equity method, and available for sale equity

instruments held at cost that do not trade on an actively quoted market.

EnbridgE inc. 2009 ANNUAL rEPorT

FAir VALuE OF FinAnciAL inStruMEntS
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 investments, other than
those classified as available for sale, approximates their carrying value due to the nature of the investments.
The fair value of the Company’s long-term debt and non-recourse 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 derivative instruments approximate their cost due to the short period to maturity.
Changes in the fair value of financial liabilities other than derivative instruments are due primarily to
fluctuations in interest rates and time value.

dEriVAtiVE inStruMEntS
The following table summarizes the maturity and total notional principal or quantity outstanding related
to the Company’s derivative instruments. The Company does not have any credit-risk related contingent
features associated with its derivative instruments.

u.S. dollar cross currency swaps

(millions of Canadian dollars)

u.S. dollar forwards – purchase
(millions of United States dollars)

u.S. dollar forwards – sell

(millions of United States dollars)

Interest rate contracts

(millions of Canadian dollars)

energy commodity (bcf)

power commodity (MW/H)

december 31, 2009

December 31, 2008

maturity

Notional Principal or
Quantity outstanding

maturity

Notional Principal or
Quantity outstanding

–

2013–2022

2010–2019

1,078

2009–2017

2010–2020

3,102

2009–2021

2010–2029

2010–2011

2010–2024

6,022

2009–2029

464

2009–2010

2009–2024

138

1,118

2,548

1,164

530

MAnAgEMEnt’S diScuSSiOn And AnALySiS

dEriVAtiVE inStruMEntS

december 31, 2009

(millions of Canadian dollars)

Accounts receivable and other

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

Deferred amounts and other

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other

Accounts payable and other

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other long-term liabilities

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

total net derivative asset/(liability)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other

Derivative
Instruments used as
Cash Flow hedges

Derivative
Instruments
used as Net
Investment hedges

Non-Qualifying
Derivative
Instruments

Total Derivative
Instruments

–

285

–

128

390

117

288

485

(2)

(68)

(17)

–

(87)

(21)

(15)

(4)

–

(40)

(21)

–

(3)

–

(32)

(1)

(36)

–

(2)

334

(12)

326

(5)

(68)

(49)

(1)

(123)

(21)

(15)

(4)

(2)

(42)

434

(33)

448

EnbridgE inc. 2009 ANNUAL rEPorT

December 31, 2008

(millions of Canadian dollars)

Accounts receivable and other

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

Deferred amounts and other

u.S. dollar cross currency swaps

u.S. dollar forwards

power commodity

Accounts payable and other

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other long-term liabilities

u.S. dollar forwards

Interest rate contracts

power commodity

other

total net derivative asset/(liability)

u.S. dollar cross currency swaps

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other

Derivative
Instruments used as
Cash Flow hedges

Derivative
Instruments
used as Net
Investment hedges

Non-Qualifying
Derivative
Instruments

Total Derivative
Instruments

153

186

–

(9)

(22)

(1)

(32)

–

(12)

(11)

(3)

(36)

165

(30)

(13)

(4)

(3)

141

–

(14)

–

(4)

–

(18)

(8)

–

(1)

(2)

(11)

–

(2)

272

317

(14)

(9)

(26)

(1)

(50)

(8)

(22)

(12)

(5)

(47)

270

(30)

(5)

292

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.

An unrealized fair value loss of $53 million (2008 – $298 million) related to derivative instruments used
as cash flow and net investment hedges was recognized in OCI for the year ended December 31, 2009.
An unrealized fair value gain related to non-qualifying derivative instruments of $146 million
(2008 – $157 million) was recognized in commodity costs, other investment income and interest expense
for the year ended December 31, 2009.

Additional information about the Company’s Risk Management and Financial Instruments is included in
Notes 23 and 24 of the 2009 Annual Consolidated Financial Statements.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

Critical Accounting estimates
dEPrEciAtiOn
Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at
December 31, 2009 of $18,850 million, or 67% 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.
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.

rEguLAtOry ASSEtS And LiAbiLitiES
Certain of the Company’s Liquids Pipelines and Natural Gas Delivery and Services businesses are subject to
regulation by various authorities, including but not limited to, the NEB, the FERC, the Energy Resources
Conservation Board (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 GAAP 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, 2009, the Company’s regulatory assets totaled $1,411 million
(2008 – $635 million) and regulatory liabilities totaled $1,038 million (2008 – $109 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) 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 recognized and the recorded obligation in future periods.
The Company remains able to pay the current benefit obligations using cash from operations reflecting
strong capital market performance recovery. The shortfall from expected return on plan assets was
$24 million for the year ended December 31, 2009 (2008 – $288 million) as disclosed in Note 27 to the
2009 Annual Consolidated Financial Statements. The difference between the actual and expected return
on plan assets is amortized over the remaining service period of the active employees.

EnbridgE inc. 2009 ANNUAL rEPorT

Assuming no discretionary funding is made into the pension plans, funding in 2010 will be approximately
$74 million, which is not considered significant to the Company.

The following sensitivity analysis identifies the impact on the December 31, 2009 Consolidated Financial
Statements of a 0.5% change in key pension and OPEB assumptions.

(millions of Canadian dollars)

Decrease in discount rate

Decrease in expected return on assets

Decrease in rate of salary increase

Pension Benefits

oPEB

obligation

Expense

obligation

Expense

n/a

(17)

(5)

n/a

–

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 EGD and EECI, are detailed in the Commitments
and Contingencies section of this report and are disclosed in Note 31 of the 2009 Annual Consolidated
Financial Statements.

ASSEt rEtirEMEnt ObLigA tiOnS
In May 2009, the NEB released a report on the financial issues associated with pipeline abandonment.
The NEB will require all companies to formally assess the timeline and cost of future abandonment and, if
necessary, set aside funds to cover future abandonment costs. All pipelines regulated under the NEB Act
will be required to comply with the report’s framework and action plan. The NEB began hosting technical
meetings in September 2009 to evaluate how abandonment estimates will be calculated and submitted,
as well as proposals for how funds will be collected and set aside. The NEB’s goal is for companies,
as required, to begin setting aside funds for abandonment no later than the end of May 2014. Currently,
for certain of the Company’s assets, it is not practical to make a reasonable estimate of asset retirement
obligations for accounting purposes due to the indeterminate timing and the scope of asset retirements.
However, should the NEB action plan result in a reasonable estimate of asset retirement obligations for
accounting purposes, financial statement recognition of those obligations may be made in future periods.
As a result, regulatory assets and liabilities may be recognized to the extent the timing of recovery from
shippers differs from the recognition of abandonment costs for accounting purposes.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

Change in Accounting policies
AccOunting FOr thE EFFEctS OF rA tE rEguLAtiOn
Effective January 1, 2009, the Company adopted revisions to the Canadian Institute of Chartered
Accountants (CICA) Handbook Section 1100, Generally Accepted Accounting Principles and Section 3465,
Income Taxes. In accordance with the transitional provisions in these revised standards, the revisions to
Section 1100 were adopted prospectively and, accordingly, prior periods were not restated, while the
revisions to Section 3465 were applied retrospectively without restatement of prior periods. The adoption
of the revised standards did not impact the Company’s earnings or cash flows.

generally Accepted Accounting Principles
The revised standard no longer provides an exemption for rate-regulated entities to measure assets and liabilities
on a basis other than in accordance with primary sources of Canadian GAAP. As a result, for the pension plans and
OPEB included in EGD, the Company recognized post-employment benefit assets and liabilities for the amount
of benefits expected to be included in future rates and recovered from, or paid to, customers. In addition, the
Company reclassified certain EGD reserves for future removal and site restoration.

pension plans and opeB
On adoption of the revised standard at January 1, 2009, the Company recognized a net pension asset of
$157 million and a net OPEB liability of $75 million, with an offsetting long-term net pension regulatory
liability and long-term net OPEB regulatory asset, respectively. At December 31, 2009, the Company had a
net pension asset of $140 million and a net OPEB liability of $80 million, with an offsetting long-term net
pension regulatory liability and a long-term net OPEB regulatory asset, respectively.

Future Removal and Site Restoration Reserves
At January 1, 2009, on adoption of the revised standard, the Company reclassified amounts collected for
future removal and site restoration of $657 million, which were previously netted against Property, Plant
and Equipment, to a long-term regulatory liability. At December 31, 2009, this long-term regulatory
liability was $710 million.

income taxes
The revised standard removes the exemption for rate-regulated entities to recognize future income taxes
to the extent they were expected to be included in regulator-approved future rates and recovered from or
refunded to future customers. As a result, on January 1, 2009, the Company recognized a future income
tax liability of $816 million on regulatory assets, primarily property, plant and equipment, with an offsetting
long-term regulatory asset. A regulatory asset has been recognized as the associated future income tax
liability is expected to be recoverable in future rates. At December 31, 2009, the Company had a future
income tax liability of $829 million related to regulatory assets with an offsetting long-term regulatory asset.

intAngibLE ASSEtS
Effective January 1, 2009, the Company adopted CICA Handbook Section 3064, Goodwill and Intangible
Assets, which establishes standards for the recognition, measurement, presentation and disclosure of
goodwill and intangible assets. As a result of adopting this standard, the Company reclassified certain
software costs from Property, Plant and Equipment to Intangible Assets. This standard has been applied
retrospectively and affects presentation only.

As a result of adopting this standard, on January 1, 2009, the Company reclassified $233 million of net
software costs from Property, Plant and Equipment to Intangible Assets. At December 31, 2009,
the Company had $289 million of net software costs recorded in Intangible Assets.

EnbridgE inc. 2009 ANNUAL rEPorT

cOMMOdity inVEntOry
Effective January 1, 2009, the Company changed its accounting policy for inventory held by its energy
marketing businesses and began measuring commodity inventory at fair value, as measured at the spot price
less costs to sell, rather than lower of cost or net realizable value. This measurement basis is a more relevant
measurement for commodity inventory used for marketing purposes and better matches the commodity
inventory with the derivatives used to “lock in” the margin. This change in accounting policy has been
accounted for retrospectively and did not result in restatements of the comparative Consolidated Statements
of Earnings, Comprehensive Income, Shareholders’ Equity or Cash Flows for the years ended December
31, 2008 and 2007 and the comparative Consolidated Statement of Financial Position as at December 31,
2008 as the amounts were considered immaterial.

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

cAPitAL diScLOSurES And FinAnciAL inStruMEntS – diScLOSurES
And PrESEntAtiOn
Effective January 1, 2008, the Company adopted new 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.

FinAnciAL inStruMEntS, cOMPrEhEnSiVE incOME And hEdging rELA tiOnShiPS
Effective January 1, 2007, the Company adopted CICA Handbook Section 1530, Comprehensive Income,
Section 3251, Equity, Section 3855, Financial Instruments – Recognition and Measurement, Section 3861,
Financial Instruments – Disclosure and Presentation (subsequently replaced by Sections 3862 and 3863
adopted by the Company on January 1, 2008) and Section 3865, Hedges. In accordance with the
transitional provisions in these new standards, these policies were adopted retrospectively without restatement.
Prior period unrealized gains and losses related to the Company’s foreign currency translation adjustments
and net investment hedges are now included in accumulated other comprehensive income (AOCI).
The cumulative impact of adopting these changes in 2007 was an increase to AOCI of $48 million.

MAnAgEMEnt’S diScuSSiOn And AnALySiS

FuturE AccOunting POLiciES

business combinations
The CICA issued Handbook Section 1582, Business Combinations, which replaces Section 1581. This new
standard aligns accounting for business combinations under Canadian GAAP with IFRS. The standard
requires assets and liabilities acquired in a business combination to be measured at fair value at the acquisition
date. The standard also requires acquisition-related costs, such as advisory or legal fees, incurred to effect a
business combination to be expensed in the period in which they are incurred. The adoption of this standard
will impact the accounting treatment of future business combinations. The revised standard is effective for
business combinations occurring on or after January 1, 2011; however, earlier application is permitted.

consolidated Financial Statements and non-controlling interests
The CICA issued Handbook Sections 1601, Consolidated Financial Statements and 1602, Non-controlling
Interests, which together replace the former consolidated financial statements standard. Under the revised
standards, non-controlling interests will be classified as a component of equity, and earnings and
comprehensive income will be attributed to both the parent and non-controlling interest. The adoption
of these standards is not expected to have a material impact to the Company’s consolidated financial
statements. The revised standards are effective January 1, 2011. Should the Company early adopt Section
1582, it would also be required to adopt Sections 1601 and 1602 at the same time.

international Financial reporting Standards
The Canadian Accounting Standards Board (AcSB) confirmed in February 2008 that publicly accountable
entities will be required to adopt IFRS for interim and annual financial statements beginning on January 1,
2011, including comparative financial statements for 2010.

Enbridge’s preparations for IFRS conversion include preparing IFRS compliant accounting policies, drafting
model IFRS financial disclosures, identifying accounting differences, developing and implementing systems
solutions and process changes that support the preparation of 2010 comparative data as well as a sustainable
conversion to IFRS in 2011.

The Audit, Finance and Risk Committee of the Board of Directors receives regular reports on the
advancement of the conversion to IFRS.

Accounting and Reporting
To date, detailed IFRS compliant accounting policies and model financial statement disclosures are complete.
The Company’s IFRS compliant accounting policies differ in some regards from the Company’s current
accounting policies. The most significant differences are expected to impact the following areas:

•

property, plant and equipment
decommissioning liabilities (asset retirement obligations)
impairments
consolidation

The Company is carefully monitoring the International Accounting Standards Board’s (IASB) project on
Rate Regulated Activities. The IASB’s exposure draft on Rate Regulated Activities, published in July 2009,
would allow the Company to continue to apply rate regulated accounting with some changes. It is not
possible to determine with certainty the extent of the changes to the Company’s accounting for rate
regulated activities until the final standard is available.

The IASB’s project on joint ventures proposes to eliminate the proportionate consolidation of joint
ventures. If the project proceeds as proposed, the Company would apply equity accounting to its joint
venture interests under IFRS instead of proportionate consolidation. A final standard is expected to be
published during the first quarter of 2010 after which the Company will be able to determine the impact
of conversion to IFRS on its accounting for joint ventures.

EnbridgE inc. 2009 ANNUAL rEPorT

The Company has selected IFRS 1 elective exemptions which are practical and provide the most relevant
presentation on conversion to IFRS. The primary result of the exemptions selected is to apply certain IFRS
differences prospectively, minimizing adjustments to the IFRS opening balance sheet. The Company also
expects to elect to reduce cumulative translation differences to zero on the date of adoption. This change
would impact the Company’s retained earnings and AOCI balances, both within the equity section of the
balance sheet. In addition, the IASB’s exposure draft on Rate Regulated Activities includes an IFRS 1
exemption which would allow the Company to use the carrying amount of rate regulated property, plant
and equipment, as calculated under Canadian GAAP, as the deemed cost for IFRS on the date of adoption.
This would reduce changes to property, plant and equipment on adoption and, if it’s available, the
Company expects to use this exemption.

Information Systems and Business processes
In January 2010, the Company implemented changes to information systems and processes which ensure
that data needed for IFRS reporting of 2010 financial information for comparative purposes is gathered.
The Company has also developed processes to derive the 2010 opening balance sheet under IFRS and is
building processes and systems solutions to create 2010 IFRS compliant quarterly financial information for
comparative purposes.

During the first quarter of 2010, the Company will determine the systems solution which will be
implemented in 2011 to support and sustain IFRS changes after conversion. Process changes needed to
sustain IFRS conversion starting in 2011 have been identified, and during 2010, process design and training
is expected to be completed. Related impacts to internal controls over financial reporting and disclosure
controls and procedures are expected to be identified during 2010.

training and Communication
The Company has a comprehensive plan to train internal personnel who will be impacted by the conversion
to IFRS. Training started during 2009 and is expected to continue throughout 2010. The Company has
also commenced preparation of an external communication plan which will depend on the nature and
magnitude of changes to the financial statements expected under IFRS.

Business Activities
The Company has reviewed the effect of IFRS conversion on its debt covenants, compensation agreements
and hedging activities and does not expect the conversion to IFRS to significantly impact these activities or
requirements.

The expected timing of key activities identified above may change prior to the IFRS conversion date due
to changes in regulation, economic conditions or other factors and the issuance of new accounting standards
or amendments to existing accounting standards, including and in addition to those noted above.

100

MAnAgEMEnt’S diScuSSiOn And AnALySiS

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 United States securities law.
As of the year ended December 31, 2009, 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 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.

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

•

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, 2009, 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, 2009.

During the year ended December 31, 2009, 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.

EnbridgE inc. 2009 ANNUAL rEPorT

101

non-GAAp Reconciliations

(millions of Canadian dollars)

GAAp earnings as reported

Significant after-tax non-recurring or non-operating factors and variances:

liquids pipelines

enbridge System – impact of tax changes

enbridge Regional oil Sands System – leak remediation costs

Feeder pipelines and other – asset impairment loss

natural Gas Delivery and Services

eGD – colder weather than normal

eGD – interest accrual on GSt refund

eGD – provision for one-time charges

eGD – impact of tax changes

noverco – impact of tax changes
offshore – property insurance recovery from hurricanes,

net of costs incurred

Alliance pipeline uS – shipper claim settlement

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

Aux Sable – loan forgiveness gain

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

energy Services – SemGroup and lehman credit loss/(recovery)

2009

2008

2007

1,555

1,321

700

–

(17)

(7)

–

(21)

(6)

(4)

–

(7)

(3)

(1)

–

(1)

–

(23)

(14)

–

(2)

(56)

–

(23)

International – gain on sale of investments in oCenSA and ClH

(329)

(556)

other – asset impairment loss

other – adoption of new accounting standard

other – gain on sale of investment in Inuvik Gas

Sponsored Investments

eep – unrealized derivative fair value (gains)/losses

eep – asset impairment loss

eep – lakehead System billing correction

eep – dilution gain on Class A unit issuance

eep – gain on sale of KpC

eep – impact of 2008 hurricanes and project write-offs

eIF – Alliance Canada shipper claim settlement

eIF – impact of tax changes

Corporate

–

(4)

–

(5)

(6)

–

(5)

–

(1)

–

unrealized derivative fair value gains
unrealized foreign exchange gains on translation of intercompany

(207)

(26)

–

(20)

(7)

(5)

–

(5)

–

(12)

(3)

–

(2)

–

(31)

–

(133)

(25)

(8)

–

(5)

855

677

637

balances, net

Gain on sale of investment in ntp

Impact of tax rate changes

Gain on sale of corporate aircraft

u.S. pipeline tax decision

Asset impairment loss

Adjusted earnings

102

MAnAgEMEnt’S diScuSSiOn And AnALySiS

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, 2009, 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, 2009.

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.

Patrick d. daniel
President & Chief Executive Officer

February 18, 2010

J. richard bird
Executive Vice President &
Chief Financial Officer

EnbridgE inc. 2009 ANNUAL rEPorT

103

INDEPENDENT AUDITorS’ rEPorT

to the Shareholders of enbridge Inc.
We have completed integrated audits of Enbridge Inc.’s 2009, 2008 and 2007 consolidated financial
statements and of its internal control over financial reporting as at December 31, 2009. Our opinions,
based on our audits, are presented below.

cOnSOLidAtEd FinAnciAL St AtEMEntS
We have audited the accompanying consolidated statements of financial position of Enbridge Inc.
as at December 31, 2009 and December 31, 2008, 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, 2009. 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, 2009 and December
31, 2008, and for each of the years in the three year period ended December 31, 2009 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, 2009 and December 31, 2008, and the results of
its operations and its cash flows for each of the years in the three year period ended December 31, 2009 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, 2009,
based on 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.

104

indEPEndEnt AuditOrS’ rEPOrt

“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership,
or, as the context requires, the PricewaterhouseCoopers global network or other member firms of the
network, each of which is a separate legal entity.

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.

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, 2009 based on criteria established in Internal Control—Integrated
Framework issued by the COSO.

Chartered Accountants
Calgary, Alberta, Canada

February 18, 2010

cOMMEntS by AuditOrS FOr u.S. rEAdErS On cAnAdA-u.S. rEPOrting diFFErEncES
In the United States, reporting standards for auditors require the addition of an explanatory paragraph
(following the opinion paragraph) when there is a change in accounting principles that has a material effect
on the comparability of the Company’s financial statements, such as the changes described in notes 3 to the
consolidated financial statements. Our report to the shareholders dated February 18, 2010 is expressed in
accordance with Canadian reporting standards, which do not require a reference to such a change in
accounting principles in the Independent Auditors’ Report when the change is properly accounted for and
adequately disclosed in the financial statements.

Chartered Accountants
Calgary, Alberta, Canada

February 18, 2010

EnbridgE inc. 2009 ANNUAL rEPorT

105

CoNSoLIDATED STATEmENTS oF EArNINgS

Year ended December 31,

2009

2008

2007

(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 28)

Interest expense (Note 16)

Gain on Sale of Investments (Note 6)

non-Controlling Interests

Income taxes (Note 26)

earnings

preferred Share Dividends

9,720

2,746

13,432

2,699

9,536

2,383

12,466

16,131

11,919

9,011

1,430

764

12,792

1,312

658

9,009

1,164

597

11,205

14,762

10,770

1,261

1,369

1,149

198

678

(597)

365

1,905

(37)

1,868

(306)

1,562

(7)

177

198

(551)

700

1,893

(56)

1,837

(509)

1,328

(7)

168

195

(550)

–

962

(46)

916

(209)

707

(7)

700

earnings Applicable to Common Shareholders

1,555

1,321

earnings per Common Share (Note 20)

4.27

3.67

1.97

Diluted earnings per Common Share (Note 20)

4.25

3.64

1.95

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

106

cOnSOLidAtEd FinAnciAL StAtEMEntS

CoNSoLIDATED STATEmENTS oF ComPrEhENSIvE INComE

Year ended December 31,

(millions of Canadian dollars)

earnings

other Comprehensive Income/(loss)

Change in unrealized gain/(loss) on cash flow hedges, net of tax
Change in unrealized gain/(loss) on net investment hedges,

net of tax

Reclassification to earnings of realized gain/(loss) on cash flow

hedges, net of tax

Reclassification to earnings of unrealized cash flow hedges,

net of tax (Note 6)

other comprehensive income/(loss) from equity investees,

net of tax

non-controlling interests in other comprehensive income

Change in foreign currency translation adjustment

other Comprehensive Income/(loss)

Comprehensive Income

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

2009

2008

2007

1,562

1,328

707

(54)

(127)

151

114

(20)

(24)

(815)

(576)

986

(160)

175

(1)

–

(101)

658

318

1,646

(7)

–

(20)

(534)

(197)

510

EnbridgE inc. 2009 ANNUAL rEPorT

107

CoNSoLIDATED STATEmENTS oF ShArEhoLDErS’ EQUITY

Year ended December 31,

2009

2008

2007

(millions of Canadian dollars, except per share amounts)

preferred Shares (Note 20)

Common Shares (Note 20)

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 declared

Dividends paid to reciprocal shareholder

Cumulative impact of change in accounting policy (Note 3)

125

3,194

3,027

143

–

131

2,416

567

3,379

3,194

3,027

(3)

3,383

1,555

(555)

–

(2)

2,537

1,321

(489)

–

(1)

2,323

700

(453)

(47)

Balance at end of Year

4,400

3,383

2,537

Accumulated other Comprehensive Income/(loss) (Note 22)

Balance at beginning of year

other comprehensive income/(loss)

Cumulative impact of change in accounting policy (Note 3)

Balance at end of Year

Reciprocal Shareholding (Note 11)

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.

(576)

–

(543)

(154)

–

(154)

7,261

1.48

(285)

318

–

(154)

–

(154)

6,619

1.32

(136)

(197)

(285)

(136)

(18)

(154)

5,276

1.23

108

cOnSOLidAtEd FinAnciAL StAtEMEntS

CoNSoLIDATED STATEmENTS oF CASh FLoWS

Year ended December 31,

(millions of Canadian dollars)

Operating Activities

earnings

Depreciation and amortization

unrealized (gain)/loss on derivative instruments

Allowance for equity funds used during construction

equity earnings in excess of cash distributions

Gain on reduction of ownership interest

Gain on sale of investments (Note 6)

Future income taxes

Goodwill and asset impairment losses

non-controlling interests

other

Changes in operating assets and liabilities (Note 29)

investing Activities

long-term investments

Affiliate loans, net

proceeds on sale of investments (Note 6)

Sale of property, plant and equipment

Settlement of hedges

2009

2008

2007

1,562

764

(204)

(135)

(9)

–

(365)

218

(105)

243

2,017

(359)

(145)

535

1,328

658

(120)

(59)

(82)

(12)

(700)

258

(26)

707

597

(15)

(35)

(34)

–

1,372

1,362

(659)

–

1,383

–

(47)

(20)

–

Additions to property, plant and equipment (Note 4)

(3,225)

(3,545)

(2,231)

Additions to intangible assets

Change in construction payable

Financing Activities

net change in short-term borrowings

net change in commercial paper and credit facility draws

Debenture and term note issues

Debenture and term note repayments

net change in Southern lights project financing

non-recourse debt issues

non-recourse debt repayments

Distributions to non-controlling interests

Common shares issued

preferred share dividends

Common share dividends

effect of translation of foreign denominated cash and cash equivalents

Increase/(Decrease) in Cash and Cash equivalents

Cash and Cash equivalents at Beginning of Year

cash and cash Equivalents at End of year 1

Supplementary cash Flow information

Income taxes paid (Note 26)

Interest paid (Note 16)

(95)

(110)

(91)

106

(68)

(3,306)

(2,853)

(2,229)

(366)

632

1,500

(516)

343

106

(172)

(33)

(7)

(414)

1,109

(35)

(215)

542

327

205

656

329

751

498

(602)

1,238

(65)

(10)

(7)

(359)

1,840

375

167

542

161

607

(262)

337

1,342

(635)

–

(59)

(18)

584

(7)

(435)

904

(10)

140

167

226

607

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

Cash and cash equivalents consists of $184 million (2008 – $68 million; 2007 – $79 million) of cash and $143 million (2008 – $474 million;

2007 – $88 million) of short-term investments and includes restricted cash of $59 million (2008 – $81 million; 2007 – $64 million).

EnbridgE inc. 2009 ANNUAL rEPorT

109

CoNSoLIDATED STATEmENTS oF FINANCIAL PoSITIoN

2009

2008

327

2,484

784

3,595

542

2,322

845

3,709

18,850

16,157

2,312

2,425

488

372

127

2,492

1,318

458

389

178

28,169

24,701

508

2,463

104

601

113

874

2,411

102

534

185

3,789

4,106

11,581

10,155

1,393

1,207

2,211

20,181

727

1,474

259

1,291

17,285

797

125

3,379

125

3,194

4,400

3,383

(543)

(154)

7,261

(154)

6,619

28,169

24,701

December 31,

(millions of Canadian dollars)

Assets

Current Assets

Cash and cash equivalents

Accounts receivable and other (Note 7)

Inventory (Note 8)

property, plant and equipment, net (Note 9)

long-term Investments (Note 11)

Deferred Amounts and other Assets (Note 12)

Intangible Assets (Note 13)

Goodwill (Note 14)

Future Income taxes (Note 26)

Liabilities and Shareholders’ Equity

Current liabilities

Short-term borrowings (Note 16)

Accounts payable and other (Note 15)

Interest payable

Current maturities of long-term debt (Note 16)

Current maturities of non-recourse long-term debt (Note 17)

long-term Debt (Note 16)

non-Recourse long-term Debt (Note 17)

other long-term liabilities (Note 18)

Future Income taxes (Note 26)

non-Controlling Interests (Note 19)

Shareholders’ equity

Share capital

preferred shares (Note 20)

Common shares (Note 20)

Contributed surplus

Retained earnings

Accumulated other comprehensive income/(loss) (Note 22)

Reciprocal shareholding (Note 11)

Commitments and Contingencies (Note 31)

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

Approved by the Board of Directors:

david A. Arledge
Chair

david A. Leslie
Director

110

cOnSOLidAtEd FinAnciAL StAtEMEntS

NoTES To ThE CoNSoLIDATED FINANCIAL STATEmENTS

General Business Description

1.
enbridge Inc. (enbridge or the Company) is a publicly traded energy transportation and distribution company.
enbridge conducts its business through four operating segments identified based on products and services offered:
liquids pipelines, natural Gas Delivery and Services, Sponsored Investments, and Corporate. 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 operation and construction of the enbridge crude oil mainline system and feeder
pipelines that transport crude oil and other liquid hydrocarbons. liquids pipelines consists of crude oil, natural gas
liquids (nGls) and refined products pipelines and terminals in Canada and the united States.

nAturAL gAS dELiVEry And SErVicES
natural Gas Delivery and Services consists of natural gas utility operations, investments in natural gas pipelines,
the Company’s commodity marketing businesses and international activities.

the core of the Company’s natural gas utility operations is enbridge Gas Distribution Inc. (eGD) which serves
residential, commercial, industrial and transportation customers, primarily in central and eastern ontario as well
as northern new York State. this business segment also includes natural gas distribution activities in Quebec and
new Brunswick.

Investments in natural gas pipelines include the Company’s interests in the united States portion of Alliance
pipeline (Alliance pipeline uS), Vector pipeline and transmission and gathering pipelines in the Gulf of Mexico.

this segment also includes the Company’s investment in Aux Sable, a natural gas fractionation and extraction
business.

the commodity marketing businesses manage the Company’s volume commitments on Alliance and Vector pipelines
as well as perform commodity storage, transport and supply management services, as principal and agent.

SPOnSOrEd inVEStMEntS
Sponsored Investments includes the Company’s 27.0% ownership interest in enbridge energy partners, l.p. (eep),
enbridge’s funding of 66.7% of the united States segment of the Alberta Clipper project through eep and enbridge
energy, l.p. (eelp) and a 72% economic interest (41.9% voting interest) in enbridge Income Fund (eIF). enbridge
manages the day-to-day operations of, and develops and assesses opportunities for each of these investments,
including both organic growth and acquisition opportunities.

eep transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and
transports, gathers, processes and markets natural gas and nGls. eIF is a publicly traded income fund whose
primary operations include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian
portion of Alliance pipeline and partial interests in several green energy investments.

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. Corporate also includes the
Company’s investments in green energy projects.

EnbridgE inc. 2009 ANNUAL rEPorT

111

Summary of Significant Accounting policies

2.
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 consolidated financial statements are described in note 33. 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 consolidated financial statements. Significant estimates
and assumptions used in preparation of the consolidated financial statements include, but are not limited to:
carrying value of regulatory assets and liabilities (Note 5); depreciation rates and carrying value of property, plant
and equipment (Note 9); amortization rates of intangible assets (Note 13); measurement of goodwill (Note 14); valuation
of share based compensation (Note 21); fair values of financial instruments (Notes 23 and 24); income taxes (Note 26);
post-employment benefits (Note 27); and commitments and contingencies (Note 31). Actual results could differ from
these estimates.

Subsequent events have been evaluated through to February 18, 2010, the date on which the consolidated
financial statements were approved by the Board of Directors and were available to be issued.

bASiS OF PrESEnt AtiOn
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).

rEguLAtiOn
Certain of the Company’s liquids pipelines and natural Gas Delivery 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 GAAp 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 generally 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.

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.

112

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

With the approval of the regulator, 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.

prior to January 1, 2009, 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 eGD were 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. effective January 1, 2009, the Company began recording a net pension asset and a net
opeB liability with an offsetting regulatory liability and asset related to the contributions to the defined benefit plan
and the cost of opeB for the regulated operations in natural Gas Delivery and Services (Note 3). there was no impact
to earnings or cash flows as a result of this change.

rEVEnuE rEcOgnitiOn
For businesses which are not rate-regulated, revenues are recorded when products have been delivered or services
have been performed and the amount of revenue can be reliably measured. Customer credit worthiness is
assessed prior to agreement signing as well as throughout the contract duration.

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 Sponsored Investments and in natural gas pipelines included in natural Gas
Delivery and Services, transportation revenues include amounts related to expenses recognized 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 a regulatory asset or liability.

For natural gas utility rate-regulated operations in natural Gas Delivery and Services, revenue is recognized in a
manner consistent with the underlying rate-setting mechanism as mandated by the regulator. natural gas utilities
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.

FinAnciAL inStruMEntS
the Company classifies financial assets and financial liabilities as held for trading, available for sale, loans and
receivables, held to maturity, other financial liabilities or derivatives in qualifying hedging relationships. All financial
instruments are initially recorded at fair value on the consolidated statement of financial position. Subsequent
measurement of the financial instrument is based on its classification.

held for trading
Financial assets and liabilities that are classified as held for trading are measured at fair value with changes in fair
value recognized in earnings in Commodity Costs, other Investment Income and Interest expense. the Company
has classified Cash and Cash equivalents and its non-qualifying derivative instruments as held for trading.

Available for Sale
Financial assets that are available for sale are measured at fair value, with changes in those fair values recorded in
other Comprehensive Income (oCI) unless actively quoted prices are not available for fair value measurement, in
which case available for sale assets are measured at cost. Generally, the Company classifies equity investments in
other entities that do not trade on an actively quoted market as available for sale. Dividends received from available
for sale financial assets are recognized in earnings when the right to receive payment is established.

Loans and receivables
loans and receivables, which include Accounts Receivable and other and long-term notes receivable, are
measured at amortized cost using the effective interest rate method, net of any impairment losses recognized.

held to Maturity
the Company has classified certain investments which are non-derivative financial assets as held to maturity.
Held to maturity investments are measured at amortized cost using the effective interest rate method.

EnbridgE inc. 2009 ANNUAL rEPorT

113

Other Financial Liabilities
other financial liabilities are recorded at amortized cost using the effective interest rate method and include
Short-term Borrowings, Accounts payable and other, Interest payable, long-term Debt and non-recourse
long-term Debt.

derivatives in qualifying hedging relationships
the Company uses derivative financial instruments to manage changes in commodity prices, foreign exchange
rates, interest rates and certain compensation tied to its share price. Hedge accounting is optional and 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. Derivatives in qualifying hedging relationships
are categorized as cash flow hedges, fair value hedges and net investment hedges.

Cash Flow Hedges
the Company uses cash flow hedges to manage changes in commodity prices, foreign exchange rates, interest rates
and certain compensation tied to its share price. the effective portion of the change in the fair value of a cash flow
hedging instrument is recorded in oCI and is reclassified to earnings when the hedged item impacts earnings or to
the carrying value of the related non-financial asset. 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 in which 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, otherwise required to be carried at cost or amortized cost,
ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged
item 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 united States dollar denominated
foreign operations. 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/loss (AoCI) are recognized in earnings when there is a reduction of the hedged net
investment resulting from a disposal of the foreign operation.

impairment
With respect to available for sale instruments, the Company assesses at each balance sheet date whether there is
objective evidence that a financial asset is impaired. If there is determined to be objective evidence of impairment,
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 asset.

With respect to loans and receivables, the Company assesses the assets for impairment when it no longer has a
reasonable assurance of timely collection. If evidence of impairment is noted, the Company reduces the value of
the loan or receivable to its estimated realizable amount, determined using discounted expected future cash flows.

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.

114

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

incOME tAxES
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 (Note 3).

FOrEign currEncy trAnSLA tiOn
the Company’s foreign operations are primarily self-sustaining. the financial statements of self-sustaining foreign
operations are translated into Canadian dollars using the current rate method. under this method, assets and
liabilities are translated using period-end exchange rates and revenues and expenses are translated using monthly
average rates. Gains and losses arising on translation of these operations are included in the cumulative translation
adjustment component of AoCI.

transactions denominated in foreign currencies are translated into Canadian dollars using the exchange rate
prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are
translated to Canadian dollars using the rate of exchange in effect at the balance sheet date whereas non-monetary
assets and liabilities are translated at the rate of exchange in effect on the date of the transaction. exchange gains
and losses resulting from translation are included in the Statement of earnings in the period that they arise.

cASh And cASh EquiVALEntS
Cash and cash equivalents include short-term investments with a term to maturity of three months or less when
purchased. Cash and cash equivalents include amounts in trust and proportionately consolidated cash from
joint ventures.

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 distribution 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 fair value as measured at the spot price less costs to sell (Note 3).

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 as events or changes in circumstances warrant.
If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset,
the asset is 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 and software costs, which are
amortized on a straight-line basis over their expected lives (Note 3).

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.

EnbridgE inc. 2009 ANNUAL rEPorT

115

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 ObLigA tiOnS
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 to perform 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.

POSt-EMPLOyMEnt bEnEFitS
the Company maintains pension plans which provide defined benefit and defined contribution pension benefits.

Defined benefit pension plan costs are determined using actuarial methods and are funded through contributions
determined using the projected benefit method, which incorporates management’s best estimate of future salary
levels, other cost escalations, retirement ages of employees and other actuarial factors. pension cost is charged to
earnings as services are rendered and includes:

•

Cost of pension plan benefits provided in exchange for employee services rendered during the year;
Amortization of the initial net transitional asset, prior service costs and amendments on a straight-line basis
over the expected average remaining service period of the active employee group covered by the plans;
Interest cost of pension plan obligations;
expected return on pension fund assets; and
Amortization of cumulative unrecognized net actuarial gains and losses, in excess of 10% of the greater of the
accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of
the active employee group covered by the plans.

Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets
for that period or from changes in actuarial assumptions used to determine the accrued benefit obligation,
including discount rate or salary inflation experience.

pension plan assets are measured at fair value. the expected return on pension plan assets is determined using
market related values and assumptions on the specific asset mix within the pension plan. the market related
values reflect estimated return on investments consistent with long-term historical averages for similar assets.

For defined contribution plans, contributions made by the Company are expensed in the period in which the
contribution occurs.

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 in which employees render service.

StOcK bASEd cOMPEnSA tiOn
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 (RSus)
vest at the completion of a 35-month term. Both pSus and RSus are settled in cash. During the vesting 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 pSus is also dependent on the Company’s
performance relative to performance targets set out under the plan.

cOMPArAtiVE AMOuntS
Certain comparative amounts have been reclassified to conform with the current year’s financial statement presentation.

116

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Changes in Accounting policies

AccOunting FOr thE EFFEctS OF rA tE rEguLAtiOn
effective January 1, 2009, the Company adopted revisions to the Canadian Institute of Chartered Accountants
(CICA) Handbook Section 1100, Generally Accepted Accounting principles and Section 3465, Income taxes. In
accordance with the transitional provisions in these revised standards, the revisions to Section 1100 were adopted
prospectively and accordingly, prior periods were not restated, while the revisions to Section 3465 were applied
retrospectively without restatement of prior periods. the adoption of the revised standards did not impact the
Company’s earnings or cash flows.

generally Accepted Accounting Principles
the revised standard no longer provides an exemption for rate-regulated entities to measure assets and liabilities
on a basis other than in accordance with primary sources of Canadian GAAp. As a result, for the pension plans and
opeB included in eGD, the Company recognized post-employment benefit assets and liabilities for the amount of
benefits expected to be included in future rates and recovered from, or paid to, customers. In addition, the
Company reclassified certain eGD reserves for future removal and site restoration.

pension plans and opeB
on adoption of the revised standard at January 1, 2009, the Company recognized a net pension asset of
$157 million and a net opeB liability of $75 million, with an offsetting long-term net pension regulatory liability and
long-term net opeB regulatory asset, respectively. At December 31, 2009, the Company had a net pension asset of
$140 million and a net opeB liability of $80 million, with an offsetting long-term net pension regulatory liability and
a long-term net opeB regulatory asset, respectively.

Future Removal and Site Restoration Reserves
At January 1, 2009, on adoption of the revised standard, the Company reclassified amounts collected for future
removal and site restoration of $657 million, which were previously netted against property, plant and equipment,
to a long-term regulatory liability. At December 31, 2009, this long-term regulatory liability was $710 million.

income taxes
the revised standard removes the exemption for rate-regulated entities to recognize future income taxes to the
extent they were expected to be included in regulator-approved future rates and recovered from or refunded to
future customers. As a result, on January 1, 2009, the Company recognized a future income tax liability of
$816 million on regulatory assets, primarily property, plant and equipment, with an offsetting long-term regulatory
asset. A regulatory asset has been recognized as the associated future income tax liability is expected to be
recoverable in future rates. At December 31, 2009, the Company had a future income tax liability of $829 million
related to regulatory assets with an offsetting long-term regulatory asset.

intAngibLE ASSEtS
effective January 1, 2009, the Company adopted CICA Handbook Section 3064, Goodwill and Intangible Assets,
which establishes standards for the recognition, measurement, presentation and disclosure of goodwill and
intangible assets. As a result of adopting this standard, the Company reclassified certain software costs from
property, plant and equipment to Intangible Assets. this standard has been applied retrospectively and affects
presentation only.

As a result of adopting this standard, on January 1, 2009, the Company reclassified $233 million of net software
costs from property, plant and equipment to Intangible Assets. At December 31, 2009, the Company had
$289 million of net software costs recorded in Intangible Assets.

EnbridgE inc. 2009 ANNUAL rEPorT

117

cOMMOdity inVEntOry
effective January 1, 2009, the Company changed its accounting policy for inventory held by its energy marketing
businesses and began measuring commodity inventory at fair value, as measured at the spot price less costs to sell,
rather than lower of cost or net realizable value. this measurement basis is a more relevant measurement for
commodity inventory used for marketing purposes and better matches the commodity inventory with the derivatives
used to “lock in” the margin. this change in accounting policy has been accounted for retrospectively and did
not result in restatements of the comparative Consolidated Statements of earnings, Comprehensive Income,
Shareholders’ equity or Cash Flows for the years ended December 31, 2008 and 2007 and the comparative
Consolidated Statement of Financial position as at December 31, 2008 as the amounts were considered immaterial.

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

cAPitAL diScLOSurES And FinAnciAL inStruMEntS—
diScLOSurES And PrESEnt AtiOn
effective January 1, 2008, the Company adopted new 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.

FinAnciAL inStruMEntS, cOMPrEhEnSiVE incOME And hEdging rELA tiOnShiPS
effective January 1, 2007, the Company adopted CICA Handbook Section 1530, Comprehensive Income, Section
3251, Equity, Section 3855, Financial Instruments – Recognition and Measurement, Section 3861, Financial
Instruments – Disclosure and Presentation (subsequently replaced by Sections 3862 and 3863 adopted by the
Company on January 1, 2008) and Section 3865, Hedges. In accordance with the transitional provisions in these
new standards, these policies were adopted retrospectively without restatement. prior period unrealized gains and
losses related to the Company’s foreign currency translation adjustments and net investment hedges are now
included in AoCI. the cumulative impact of adopting these changes in 2007 was an increase to AoCI of
$48 million.

FuturE AccOunting POLicy chAngES
business combinations
the CICA issued Handbook Section 1582, Business Combinations, which replaces Section 1581. this new
standard aligns accounting for business combinations under Canadian GAAp with IFRS. the standard requires
assets and liabilities acquired in a business combination to be measured at fair value at the acquisition date.
the standard also requires acquisition-related costs, such as advisory or legal fees, incurred to effect a business
combination to be expensed in the period in which they are incurred. the adoption of this standard will impact the
accounting treatment of future business combinations. the revised standard is effective for business combinations
occurring on or after January 1, 2011; however, earlier application is permitted.

consolidated Financial Statements and non-controlling interests
the CICA issued Handbook Sections 1601, Consolidated Financial Statements and 1602, Non-controlling Interests,
which together replace the former consolidated financial statements standard. under the revised standards,
non-controlling interests will be classified as a component of equity, and earnings and comprehensive income will
be attributed to both the parent and non-controlling interest. the adoption of these standards is not expected to
have a material impact to the Company’s consolidated financial statements. the revised standards are effective
January 1, 2011. Should the Company early adopt Section 1582, it would also be required to adopt Sections 1601
and 1602 at the same time.

118

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Segmented Information

year ended december 31, 2009

(millions of Canadian dollars)

Revenues

Commodity costs

operating and administrative

Depreciation and amortization

Income from equity investments
other investment income and gain on

sale of investments

Interest and preferred share dividends

non-controlling interests

Income taxes

earnings applicable to common shareholders

Year ended December 31, 2008

(millions of Canadian dollars)

Revenues

Commodity costs

operating and administrative

Depreciation and amortization

Income from equity investments
other investment income and gain on

sale of investments

Interest and preferred share dividends

non-controlling interests

Income taxes

earnings applicable to common shareholders

Year ended December 31, 2007

(millions of Canadian dollars)

Revenues

Commodity costs

operating and administrative

Depreciation and amortization

Income from equity investments
other investment income and gain on sale of

investments

Interest and preferred share dividends

non-controlling interests

Income taxes

earnings applicable to common shareholders

Liquids
Pipelines

Natural gas
Delivery and
Services

Sponsored
Investments

Corporate

Consolidated

1,333

10,776

–

(9,011)

(565)

(230)

538

–

161

(144)

(2)

(108)

445

(709)

(419)

637

370

(257)

(7)

(118)

635

313

–

(113)

(88)

112

188

(56)

(28)

(88)

141

12,466

–

(9,011)

(43)

(27)

(26)

–

(1,430)

(764)

1,261

198

499

1,043

(147)

–

(604)

(37)

(306)

334

1,555

Liquids
Pipelines

Natural gas
Delivery and
Services

Sponsored
Investments

Corporate

Consolidated

1,170

14,650

–

(12,792)

(492)

(181)

497

–

(111)

(1)

(118)

328

(685)

(392)

781

759

(270)

(7)

(335)

958

298

–

(102)

(78)

118

148

(60)

(47)

(73)

111

16,131

–

(12,792)

(33)

(7)

(27)

(1)

(117)

(1)

(76)

(1,312)

(658)

1,369

177

898

(558)

(56)

(509)

1,321

Liquids
Pipelines

Natural gas
Delivery and
Services

Sponsored
Investments

Corporate

Consolidated

1,091

10,549

–

(9,009)

(427)

(156)

508

(1)

(101)

(1)

(134)

287

(632)

(360)

548

(271)

(6)

(88)

344

270

–

(79)

(75)

116

(62)

(38)

(54)

–

(26)

(6)

(23)

(1)

(123)

(1)

(28)

11,919

(9,009)

(1,164)

(597)

1,149

168

195

(557)

(46)

(209)

700

the measurement basis for preparation of segmented information is consistent with the significant accounting
policies described in note 2.

EnbridgE inc. 2009 ANNUAL rEPorT

119

tOtAL ASSEtS

December 31,

(millions of Canadian dollars)

liquids pipelines

natural Gas Delivery and Services

Sponsored Investments

Corporate

AdditiOnS tO PrOPErty , PLAnt And EquiPMEnt 1

December 31,

(millions of Canadian dollars)

liquids pipelines

natural Gas Delivery and Services

Sponsored Investments

Corporate

Includes AEDC.

gEOgrAPhic inFOrMA tiOn
revenues 1

Year ended December 31,

(millions of Canadian dollars)

Canada

united States

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

2009

2008

10,763

7,467

11,207

10,724

3,860

2,339

3,766

2,744

28,169

24,701

2009

2008

2,662

2,898

440

217

544

109

3,360

3,604

2009

2008

2007

9,503

2,963

12,459

3,672

8,346

3,573

12,466

16,131

11,919

2009

2008

15,101

12,107

3,749

4,050

18,850

16,157

120

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Financial Statement effects of Rate Regulation

gEnErAL inFOrMA tiOn 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 products and services to customers, 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) was 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. Surcharges are also determined for a number of system expansion components and are added to the
base toll determined for the core system. Discussions and negotiations continue with the Canadian Association of
petroleum producers (CApp) and a representative shipper group for an extension to the 2005 ItS which will support
a competitive toll structure. the Company anticipates it will reach a settlement by the end of the first quarter of
2010. In the event that a settlement cannot be reached, the Company could file a cost of service application.

Athabasca Pipeline
Athabasca pipeline is regulated by the eRCB. tolls are established based on long-term transportation agreements
with individual shippers.

Vector Pipeline
Vector pipeline is an interstate natural gas pipeline in the united States with a FeRC approved tariff that
establishes 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 for the year
ended December 31, 2009 include an after-tax return on equity (Roe) component of 11.07% (2008 – 11.04%;
2007 – 10.75%).

Alliance Pipeline
the united States portion of the Alliance pipeline is regulated by the FeRC and the Canadian portion of the
pipeline is regulated by the neB. Shippers on the Alliance pipeline are subject to 15-year transportation contracts
that expire in December 2015, with a cost of service toll methodology. toll adjustments are filed annually with the
regulator. the tolls for the year ended December 31, 2009 include an after-tax Roe component of 10.88%
(2008 – 10.88%; 2007 – 10.88%) for the united States portion and 11.26% (2008 – 11.26%; 2007 – 11.26%)
for the Canadian portion. Alliance pipeline 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, expiring in December 2012, which adjusts revenues, and consequently
rates, annually and relies on an annual process to forecast volume and customer additions.

eGD’s after-tax rate of return on common equity embedded in rates was 8.39% for the year ended December 31,
2009 (2008 – 8.39%; 2007 – 8.39%) based on a 36% (2008 – 36%; 2007 – 36%) 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 after-tax Roe was 13.00%
(2008 – 13.00%; 2007 – 13.00%) based on equity which is capped at 50%.

EnbridgE inc. 2009 ANNUAL rEPorT

121

FinAnciAL StAtEMEnt EFFEctS
Accounting for rate-regulated entities has resulted in the recognition of the following regulatory assets and liabilities:

Estimated
Settlement
Period
(years)

2009

2008

Earnings Impact 1

2009

2008

2007

December 31,

(millions of Canadian dollars)

regulatory Assets/(Liabilities)

liquids pipelines

Future income taxes 2

enbridge System tolling deferrals 3

power purchase arrangements 4

natural Gas Delivery and Services

Future income taxes 2

Deferred transportation revenue 5

eGnB regulatory deferral 6

Class action lawsuit settlement 7

Shared savings mechanism 8

ontario hearing costs 9

transportation revenue adjustment 10

unaccounted for gas variance 11
Future removal and site
restoration reserves 12

purchased gas variance 13

pension plans and opeB, net 14

earnings sharing deferral 15

transactional services deferral 16

Sponsored Investments

Future income taxes 2

Deferred transportation revenue 5

–

1–3

–

14–16

–

504

(2)

600

227

185

155

(710)

(227)

(60)

(25)

(14)

–

114

(21)

–

267

133

–

(75)

–

(6)

(7)

(416)

353

189

373

–

526

–

(16)

(30)

(27)

–

(1)

–

(2)

(4)

–

(19)

(11)

(6)

–

(2)

–

(2)

–

(11)

(6)

–

(23)

(24)

(47)

–

(1)

(3)

–

(16)

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.

This regulatory asset is an offsetting balance to a future income tax liability recognized on adoption of a revised accounting standard (Note 3). The future

income tax liability primarily relates to future income taxes associated with property, plant and equipment. The balance has been recognized as a regulatory

asset since the flow-through treatment of taxes for rate-setting purposes would ensure eventual recovery of these balances as the temporary differences

reverse. The recovery period will depend on the period in which the future income tax amounts reverse. In the absence of rate regulation, the liability

method of accounting for income taxes would be utilized and future income tax expense would be recorded.

Tolls on the Enbridge System are calculated in accordance with the ITS, System Expansion Program (SEP), Terrace, Southern Access, Line 4 and the

Alberta Clipper agreements and are established each year based on capacity and the allowed revenue requirement. Where actual volumes shipped on the

pipeline do not result in collection of the annual revenue requirement, a regulatory asset 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 or over

collections 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 23). 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.

Deferred transportation revenue is related to the cumulative difference between Canadian GAAP depreciation expense for 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 Canadian GAAP depreciation rates: for Alliance Pipeline US beginning in 2009,
for Alliance Pipeline Canada beginning in 2011 and ending in 2025 and for Vector Pipeline beginning in 2008 and ending in 2023. This regulatory asset is

not included in the rate base.

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

the development period. The regulatory deferral account balance is expected to be amortized over a recovery period approved by the EUB expected to

commence at the end of the development period in 2010 and expected to end in 2040.

122

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

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.

Shared savings mechanism (SSM) deferral represents the benefit derived by EGD as a result of its energy efficiency programs. EGD has historically been

granted OEB approval to recover the SSM amount through rates after a detailed review by the OEB. The process of review and subsequent recovery may

extend over a few years. In the absence of rate regulation, the amount would be included in earnings in the year of approval.

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.

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

included in transportation rates. The deferred transportation revenue adjustment is recoverable, typically in the following year, under the long-term

transportation agreements and is not included in the rate base.

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 Commodity Costs.

Future removal and site restoration reserves results from the adoption of a revised accounting standard in 2009 (Note 3). With the approval of the

regulators, certain of the Company’s businesses collect amounts from customers to fund future costs for removal and site restoration relating to property,

plant and equipment and are collected as part of depreciation charged on property, plant and equipment. The balance represents the net amount that EGD

has collected from customers, net of actual costs expended on removal and site restoration as at December 31, 2009. In the absence of rate regulation,

this balance would not be recorded as amounts would not have been collected from customers.

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

this balance to customers in the following year. In the absence of rate regulation the actual cost of gas would be included in commodity costs and

commodity sales would be adjusted by the purchased gas variance.

This pension plan and OPEB account results from the adoption of a revised accounting standard in 2009 (Note 3). EGD continues to record and recover

pension plan contributions and OPEB expenditures through rates on a cash basis. However, as a result of the revised accounting standard, a net asset was

recorded representing the amount of pension and OPEB benefits calculated on an accrual basis, with an offsetting net regulatory liability. The settlement

period is not determinable. In the absence of rate regulation, there would be no regulatory offset to the net asset.

Earnings sharing deferral represents amounts relating to the earnings sharing mechanism, which forms part of the IR Settlement. The earnings sharing is

payable to ratepayers and represents 50% of earnings excluding the effects of weather, represented by the ROE in excess of 100 basis points above the

notional allowed utility ROE. The December 31, 2009 balance relates to the years ended December 31, 2009 and 2008. There would be no change in the

treatment of this item in the absence of rate regulation.

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.

OthEr itEMS AFFEctEd by rA tE rEguLAtiOn
Future income taxes
on January 1, 2009, the Company adopted a change in accounting standard that impacted the recognition of
future income taxes as it relates to rate regulated activities. effective January 1, 2009, future income tax balances
arising primarily from property, plant and equipment are recognized, along with offsetting regulatory assets or
liabilities to the extent such balances are expected to be included in future rates. previously, neither the future
income tax balance nor the associated regulatory asset or liability would have been recognized.

At December 31, 2008, in the absence of rate regulation, a future income tax liability of $533 million associated
primarily with property, plant and equipment would have been recognized.

At December 31, 2008 the Company had recorded net future income tax liabilities of $68 million related to certain
regulatory asset and liability deferral accounts identified above. Accumulated future income tax liabilities of
$55 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 for the year ended December 31, 2008 would have
decreased by $15 million (2007 – increased by $62 million).

Allowance for Funds used during construction and Other capitalized costs
under the pool method prescribed by certain 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 certain 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, 2009, costs relating to this
consulting contract of $112 million (2008 – $94 million) were included in property, plant and equipment, and are
being depreciated over the average service life of 25 years. In the absence of rate regulation, these costs would be
charged to current earnings.

EnbridgE inc. 2009 ANNUAL rEPorT

123

Pension Plans
prior to January 1, 2009 had pension costs and obligations been recognized at eGD, the net pension asset would
have increased by $157 million at December 31, 2008 and earnings would have increased by $3 million for the
year ended December 31, 2008 (2007 – decreased by $1 million) (Note 3).

post-employment Benefits other than pensions
prior to January 1, 2009 had the cost of opeB been accrued at eGD, the net opeB liability would have increased
by $75 million as at December 31, 2008 and earnings would have decreased by $6 million for the year ended
December 31, 2008 (2007 – $6 million) (Note 3).

Gain on Sale of Investments

December 31,

(millions of Canadian dollars)

netthruput (ntp)

oleoducto Central S.A. (oCenSA)

Compañía logística de Hidrocarburos ClH, S.A. (ClH)

other

2009

2008

2007

336

–

365

–

695

700

–

ntP
on May 1, 2009, the Company sold its investment in ntp, an internet-based exchange facility for physical crude oil
products, for proceeds of $32 million. earnings generated by the ntp investment for the year ended December 31,
2009 were $1 million (2008 – $1 million) and are included in the Corporate operating segment.

OcEnSA
on March 17, 2009, the Company sold its investment in oCenSA, a crude oil pipeline in Colombia, for proceeds of
$512 million (uS$402 million). earnings and cash flows from operating activities generated by this investment for
the year ended December 31, 2009 were $7 million (2008 – $33 million). earnings from the oCenSA investment
are included in the natural Gas Delivery and Services operating segment. As a result of the sale of oCenSA, the
Company reclassified $20 million of after-tax gains on unrealized cash flow hedges from oCI to earnings in the year
ended December 31, 2009.

cLh
on June 17, 2008, the Company sold its 25% investment in ClH for total proceeds of $1,380 million
(€876 million), net of transaction costs. the sale of ClH resulted in a gain of $695 million. earnings generated by
the ClH investment for the year ended December 31, 2008 were $25 million (2007 – $66 million), and are
included in the natural Gas Delivery and Services operating segment. operating cash flows generated by the ClH
investment for the year ended December 31, 2008 were $12 million (2007 – $58 million).

Accounts Receivable and other

December 31,

(millions of Canadian dollars)

unbilled revenues

trade receivables

Regulatory assets

taxes receivable

Short-term portion of derivative assets (Note 23)

Due from affiliates (Note 30)

prepaid expenses and deposits

Dividends receivable

GSt receivable

other

124

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

2009

2008

1,018

607

181

128

336

–

2,484

751

907

138

133

186

2,322

Inventory

December 31,

(millions of Canadian dollars)

natural gas

other commodities

property, plant and equipment

2009

2008

492

292

784

674

171

845

december 31, 2009

(millions of Canadian dollars)

liquids pipelines

pipeline

pumping equipment, buildings, tanks and other

land and right-of-way

under construction

natural Gas Delivery and Services

pipeline

Regulating, metering and other equipment

Gas mains and services

Storage

Computer technology

land and right-of-way

under construction

Sponsored Investments

pipeline

other

Corporate

Wind turbines and other

land and right-of-way

under construction

Weighted Average
Depreciation rate

Cost

Accumulated
Depreciation

Net

2.4%

3.5%

2.0%

–

3.5%

4.0%

3.4%

2.8%

20.6%

4.1%

–

4.6%

6.9%

4.5%

4.0%

–

4,053

4,029

118

4,129

1,481

1,065

–

12,329

2,569

1,971

1,204

5,133

241

103

341

570

280

854

–

9,013

1,777

1,406

139

1,545

631

730

368

386

–

2,572

2,964

4,129

9,760

1,401

924

4,279

198

341

7,236

1,038

121

1,159

596

695

23,617

4,767

18,850

EnbridgE inc. 2009 ANNUAL rEPorT

125

December 31, 2008

(millions of Canadian dollars)

liquids pipelines

pipeline

pumping equipment, buildings, tanks and other

land and right-of-way

under construction

natural Gas Delivery and Services

pipeline

Regulating, metering and other equipment

Gas mains and services

Storage

Computer technology

land and right-of-way

under construction

Sponsored Investments

pipeline

other

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%

4.4%

3.7%

2.7%

19.0%

2.8%

–

4.4%

8.1%

4.9%

4.0%

–

3,162

2,958

3,857

10,047

2,169

1,226

5,074

239

360

9,139

1,363

112

1,475

508

532

1,360

986

–

2,366

589

307

1,401

–

2,372

277

281

–

1,802

1,972

3,857

7,681

1,580

919

3,673

178

360

6,767

1,086

108

1,194

491

515

Joint Ventures

10.
the impact of the Company’s joint venture interests on net assets, earnings, cash flows and financial position is
summarized below.

21,193

5,036

16,157

December 31,

(millions of Canadian dollars)

liquids pipelines

olympic pipelines

Chicap pipeline

other

natural Gas Delivery and Services

Alliance pipeline uS

Vector pipeline

enbridge offshore pipelines – various joint ventures

Aux Sable

other

Sponsored Investments

Alliance pipeline Canada

other

126

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

ownership Interest

2009

2008

Net Assets

65%

43.8%

30%-50%

50%

60%

22%-75%

42.7%

42.7%-70%

50%

33%-50%

111

383

420

385

153

676

2,270

125

453

486

521

174

688

2,608

the following table summarizes the impact of proportionately consolidating the joint ventures to the consolidated
financial statements of the Company.

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

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

2009

2008

2007

781

(74)

(226)

(171)

(99)

221

342

(49)

(296)

(3)

891

(174)

(235)

(173)

(97)

225

408

(61)

(351)

(4)

844

(133)

(208)

(153)

(106)

251

312

(132)

(184)

(4)

2009

2008

173

2,769

696

(212)

(1,109)

(47)

2,270

179

3,221

735

(177)

(1,309)

(41)

2,608

During the year ended December 31, 2009, the Company purchased the additional 50% interest in Starfish
pipeline Company, llC, increasing its ownership percentage to 100.0%. As the Company established control over
the entity effective December 31, 2009, it has consolidated its interest in Starfish pipeline Company, llC from that
date forward. prior to December 31, 2009, the entity was classified as a joint venture.

During the year ended December 31, 2008, the Company purchased an additional equity interest in Chicap
pipeline, increasing its ownership percentage to 43.8%. As the Company established joint control over the entity
effective october 31, 2008, it has proportionally consolidated its interest in Chicap pipeline from that date forward.
prior to october 31, 2008, the entity was classified as a long-term investment.

EnbridgE inc. 2009 ANNUAL rEPorT

127

11.

long-term Investments

December 31,

(millions of Canadian dollars)

Equity investments

Sponsored Investments

the partnership

enbridge energy, l.p. – Series AC

natural Gas Delivery and Services

noverco Inc. Common Shares

Corporate

other

Other investments

natural Gas Delivery and Services

noverco Inc. preferred Shares

Fuel Cell energy ltd.

oCenSA

Corporate

Value Creation Inc.

ownership Interest

2009

2008

27.0%

66.7%

32.1%

10%–33%

1,697

2,014

357

181

–

181

223

2,312

2,492

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 $126 million at December 31, 2009 (2008 – $130 million). the excess is
attributable to the value of property, plant and equipment within the investees based on estimated fair values at the
purchase date and is amortized over the economic life of the assets. During 2009 dividends from equity investments
exceeded equity investment earnings by $75 million; whereas during 2008, equity investment earnings exceeded
dividends in the year by $10 million.

thE PArtnErShiP
the partnership includes the Company’s investments in eep and enbridge energy Management, l.l.C. (eeM).
the Company has a combined 27.0% ownership in eep, through a 2.0% general partner interest, a 19.4% interest
in Class A units, a 3.3% interest in Class B units and a 2.3% interest in eep as a result of a 17.2% investment in
eeM, which owns 12.6% of eep through its 100% interest in eep’s i-units. the Company recorded investment
income from eep of $175 million for the year ended December 31, 2009 (2008 – $162 million including dilution
gains; 2007 – $130 million including dilution gains).

Although 82.8% of eeM is widely held, the Company has voting control and therefore consolidates its investment in
eeM, including its investment in eep of $615 million (2008 – $691 million). net of non-controlling interests in eeM,
the book value of the Company’s investment in eep is $1,544 million (2008 – $1,441 million.)

In october 2009, the Company converted its investment in eep Class C units into Class A common units. the Class
C units converted on a one-for-one basis, resulting in the issuance and receipt of 21,333,273 Class A common
units. prior to the unit conversion, distributions were paid in additional Class C units where Class C units were
valued at the market value of Class A units.

In March 2008, eep issued Class A units and, because enbridge did not fully participate in this issuance,
a dilution gain of $5 million was recognized 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$510 million increasing its ownership interest from 14.6% to 27.0%.

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 interests of $12 million were recognized
and enbridge’s ownership interest in the partnership decreased from 16.6% to 15.1%.

128

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

EnbridgE EnErgy, L.P.
the Company has a 66.7% interest in the series AC units of eelp, which is constructing the united States segment
of the Alberta Clipper project (Note 30).

nOVErcO
the Company owns a preferred share investment in noverco Inc. (noverco) of $181 million at December 31, 2009
(2008 – $181 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 $14 million at December 31,
2009 (2008 – $11 million). noverco owns an approximate 9.2% (2008 – 9.3%) reciprocal shareholding in the
shares of the Company. As a result, the Company has an indirect pro-rata interest of 2.9% (2008 – 3.0%) in its own
shares. Both the equity investment in noverco and shareholders’ equity have been reduced by the reciprocal
shareholding of $154 million at December 31, 2009 (2008 – $154 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 2009, the Company recorded equity investment
earnings of $10 million (2008 – $4 million; 2007 – $9 million) related to its interest in noverco.

OcEnSA
on March 17, 2009 the Company sold its investment in oCenSA (Note 6).

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 million was recognized in the year ended December 31, 2008 to adjust the carrying value of
this investment to its fair value of $7 million.

12.

Deferred Amounts and other Assets

December 31,

(millions of Canadian dollars)

Regulatory assets

long-term portion of derivative assets (Note 23)

pension asset (Note 27)

Affiliate long-term note receivable, (Note 30)

Contractual receivables

other

2009

2008

1,419

485

216

–

171

134

510

317

159

103

2,425

1,318

At December 31, 2009, deferred amounts of $71 million (2008 – $48 million) were subject to amortization and are
presented net of accumulated amortization of $34 million (2008 – $26 million). Amortization expense in 2009 was
$7 million (2008 – $5 million; 2007 – $4 million).

EnbridgE inc. 2009 ANNUAL rEPorT

129

13.

Intangible Assets

december 31, 2009

(millions of Canadian dollars)

Software

transportation agreements

power purchase Agreements

Customer lists

December 31, 2008

(millions of Canadian dollars)

Software

transportation agreements

power purchase Agreements

Customer lists

Weighted Average
Amortization rate

17.1%

4.2%

4.0%

7.1%

Weighted Average
Amortization rate

17.6%

4.2%

4.0%

7.1%

Cost

448

232

707

Cost

536

252

814

Accumulated
Amortization

159

219

Accumulated
Amortization

303

–

356

Net

289

176

488

Net

233

202

458

total amortization expense for intangible assets was $44 million for the year ended December 31, 2009
(2008 – $58 million; 2007 – $43 million). the Company expects aggregate amortization expense for the years
ending December 31, 2010 through 2014 of $58 million, $49 million, $42 million, $36 million and $30 million,
respectively.

14.

Goodwill

(millions of Canadian dollars)

Balance at December 31, 2007

Goodwill impairment

Foreign exchange and other

Balance at December 31, 2008

Goodwill impairment

Foreign exchange and other

Balance at December 31, 2009

Liquids
Pipelines

Natural gas Delivery
and Services

Sponsored
Investments

Corporate

Consolidated

–

(3)

–

(7)

308

–

308

–

308

(13)

–

388

(13)

389

(7)

(10)

372

In the fourth quarter of 2009, the Company recognized an impairment of $7 million on goodwill related to enbridge
electric Connections Inc. within the natural Gas Delivery and Services segment.

In the fourth quarter of 2008, the Company concluded the goodwill related to ontario Wind power, within the
Corporate operating segment, was impaired. Accordingly an impairment loss of $13 million was recorded.

130

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

15.

Accounts payable and other

December 31,

(millions of Canadian dollars)

operating accrued liabilities

trade payables

Construction payables

Current derivative liabilities (Note 23)

Contractor holdbacks

taxes payable

Security deposits

other

16.

Debt

December 31,

(millions of Canadian dollars)

liquids pipelines

Debentures

Medium-term notes

Southern lights project financing 1

Commercial paper and credit facility draws, net

other 2

natural Gas Delivery and Services

Debentures

Medium-term notes

Commercial paper and credit facility draws, net

Corporate

u.S. dollar term notes 3

Medium-term notes

Commercial paper and credit facility draws, net 4

Deferred debt issue costs and other

total Debt

Current Maturities

Short-term Borrowings

long-term Debt

2009

2008

1,313

415

163

123

108

103

178

963

548

273

123

113

2,463

2,411

Weighted Average
Interest rate

maturity

2009

2008

8.20%

2024

5.48%

2012–2039

2.05%

2014

11.04%

2010–2024

5.77%

2014–2036

5.48%

2014–2017

5.47%

2010–2039

200

1,525

1,531

874

385

1,795

512

1,151

2,568

2,235

(101)

200

1,125

1,359

525

485

1,795

883

1,680

1,568

2,034

(106)

0.26%

12,690

11,563

(601)

(508)

(534)

(874)

11,581

10,155

2009 – $385 million and US$1,095 million (2008 – $318 million and US$850 million).

Primarily capital lease obligations.

2009 – US$1,100 million (2008 – US$1,372 million).

2009 – $1,973 million and US$250 million (2008 – $1,189 million and US$690 million).

Debenture and term note maturities for the years ending December 31, 2010 through 2014 are $600 million,
$150 million, $250 million, $200 million and $819 million, respectively. the Company’s debentures and term notes
bear interest at fixed rates and the interest obligations for the years ending December 31, 2010 through 2014 are
$445 million, $407 million, $399 million, $383 million and $360 million, respectively.

EnbridgE inc. 2009 ANNUAL rEPorT

131

intErESt ExPEnSE

Year ended December 31,

(millions of Canadian dollars)

Debentures and term notes

non-recourse long-term debt

Commercial paper and credit facility draws

Southern lights project financing

Capitalized

crEdit FAciLitiES

december 31, 2009

(millions of Canadian dollars)

liquids pipelines

natural Gas Delivery and Services

Corporate

2009

2008

2007

484

(96)

597

404

100

(81)

551

418

102

–

(61)

550

Expiry Dates

Total Facilities

Credit Facility
Draws 2

Available

2011

2010–2011

2011–2013

1,300

813

3,898

6,011

1,796

7,807

876

512

2,255

3,643

1,531

5,174

424

301

1,643

2,368

265

2,633

Southern lights project financing 1

2014

total Credit Facilities

Total facilities inclusive of $186 million which is available if certain conditions related to the project are met.

Includes facility draws and commercial paper issuances, net of discount, that are back-stopped by the credit facility.

Credit facilities carry a weighted average standby fee of 0.39% per annum on the unused portion and draws bear
interest at market rates. Certain credit facilities serve as a backstop to the commercial paper programs and the
Company has the option to extend the facilities, which are currently set to mature from 2010 to 2014.

Commercial paper and credit facility draws, net of short-term borrowings, of $3,113 million (2008 – $2,567 million)
are supported by the availability of long-term committed credit facilities and therefore have been classified as
long-term debt.

17.

non-Recourse Debt

December 31,

(millions of Canadian dollars)

natural Gas Delivery and Services

long-term credit facilities 1

Senior notes 2

term debt 3

Capital lease obligations

Sponsored Investments

Credit facilities

Medium-term notes

Senior notes

Fair value increment on senior notes acquired

Deferred debt issue costs and other

total non-Recourse Debt

Current Maturities

non-Recourse long-term Debt

2009 – US$1 million (2008 – US$1 million).

2009 – US$382 million (2008 – US$414 million).

2009 – US$23 million (2008 – US$22 million).

Weighted Average
Interest rate

maturity

2009

2008

2012

6.77%

2015–2025

3.09%

2010–2019

10.45%

2020

2011–2012

5.25%

2014

6.63%

2015–2025

400

222

708

(9)

507

174

190

679

(10)

1,506

(113)

1,393

1,659

(185)

1,474

132

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Maturities on non-recourse borrowings for the years ending December 31, 2010 through 2014 are $113 million,
$71 million, $77 million, $81 million and $81 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, 2010
through 2014 are $82 million, $78 million, $72 million, $67 million and $61 million, respectively.

Certain assets of Alliance pipeline Canada, with a carrying value of $1,055 million, 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 $806 million, are pledged as collateral to Alliance pipeline uS’s lenders
and to the lenders to Alliance pipeline Canada.

18.

other long-term liabilities

December 31,

(millions of Canadian dollars)

Future removal and site restoration reserves (Note 5)

Regulatory liabilities

other post-employment benefit liabilities (Note 27)

Derivative liabilities (Note 23)

other

19.

non-Controlling Interests

December 31,

(millions of Canadian dollars)

eeM

eIF

eGD preferred Shares

eGnB

other

2009

2008

710

138

110

207

1,207

–

190

259

2009

2008

424

134

100

727

481

147

100

797

non-controlling interests in eeM represents the 82.8% of the listed shares of eeM not held by the Company.

the Company owns 100% of the outstanding common shares of eGD; however, the four million Cumulative
Redeemable eGD preferred Shares held by third parties are entitled to a claim on the assets of eGD prior to the
common shareholder. the fixed yield rate on these preferred shares was 4.93% per annum until July 1, 2009, after
which floating adjustable cumulative cash dividends are payable at 80% of the prime rate. the preferred shares
have no fixed maturity date. eGD may, at its option, redeem all or a portion of the outstanding shares for $25 per
share plus all accrued and unpaid dividends to the redemption date. As at December 31, 2009, no preferred
shares have been redeemed.

non-controlling interests in eIF represents 58.1% of voting units that are held by public unitholders.
non-controlling interests in eGnB represents 27.5% of the limited partnership units held by third parties.

EnbridgE inc. 2009 ANNUAL rEPorT

133

Share Capital

20.
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

December 31,

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

Balance at beginning of year

Common shares issued

Shares issued on exercise of stock options
Dividend Reinvestment and Share

purchase plan

Balance at end of year

2009

2008

2007

Number of
Shares

Amount

Number of
Shares

Amount

Number of
Shares

Amount

373

3,194

369

3,027

352

2,416

–

143

–

567

131

378

3,379

373

3,194

369

3,027

PrEFErrEd ShArES
the five 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 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 million
(2008 – 11 million), 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 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

2009

2008

2007

364

366

360

363

355

358

For the year ended December 31, 2009, 556,500 anti-dilutive stock options (2008 – 2,879,800; 2007 – 1,158,200)
with a weighted average exercise price of $40.98 (2008 – $40.53; 2007 – $38.26) 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.

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.

134

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Stock option and Stock unit plans

21.
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 17.5 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, 2009 for ISos is $17 million (2008 – $13 million; 2007 – $9 million).

Outstanding incentive Stock Options

December 31,

Number

2009

Weighted
Average
Exercise Price

2008

Weighted
Average
Exercise Price

Number

2007

Weighted
Average
Exercise Price

Number

(options in thousands,
exercise price in Canadian dollars)

options at beginning of year

options granted

options exercised

options cancelled or expired

10,650

3,028

(1,187)

(25)

31.05

39.62

22.01

40.65

9,237

2,642

(1,178)

(51)

options at end of year

12,466

34.01

10,650

options vested

6,550

28.96

6,087

27.24

40.54

21.85

36.83

31.05

25.32

9,186

1,158

(1,046)

(61)

9,237

5,865

24.97

38.26

19.21

32.97

27.24

22.87

the total intrinsic value of ISos exercised during the year ended December 31, 2009 was $22 million
(2008 – $23 million; 2007 – $19 million) and cash received on exercise was $26 million (2008 – $26 million;
2007 – $20 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, 2009 was $81 million (2008 – $109 million) and $76 million (2008 – $97 million), respectively.

incentive Stock Option characteristics

december 31, 2009

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

111

486

1,682

1,025

1,727

4,836

2,599

12,466

0.3

1.2

2.6

4.0

6.6

7.8

8.1

6.4

13.09

19.06

21.29

25.72

32.33

38.43

40.86

options vested

Weighted
Average
remaining Life
(years)

Weighted
Average
Exercise Price

0.3

1.2

2.6

4.0

5.1

6.4

8.1

4.5

13.09

19.06

21.29

25.72

31.77

37.10

40.87

28.96

Number

111

486

1,682

1,025

1,089

1,523

634

34.01

6,550

the total fair value of options vested under the ISo plan during the year ended December 31, 2009 was
$13 million (2008 – $9 million).

EnbridgE inc. 2009 ANNUAL rEPorT

135

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

2009

7.12

2008

6.14

2007

6.16

28.08%

18.48%

18.10%

3.87%

2.24%

3.34%

3.50%

3.22%

4.11%

Beginning in 2008, options granted to United States employees are based on New York Stock Exchange (NYSE) prices. The option value and assumptions

shown for 2009 are based on a weighted average of the United States options and the Canadian options. The fair values per option were $6.73 for

Canadian employees and US$6.86 for United States employees.

The expected option term is based on historical exercise practice.

Expected volatility is determined with reference to historic daily share price volatility.

The expected dividend yield is the current annual dividend at the grant date 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, 2009, unrecognized compensation cost related to non-vested share-based compensation
arrangements granted under the ISo plan was $14 million. the cost is expected to be fully recognized by
December 31, 2012.

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. under
the 2007 pBSo plan, performance 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, 2009 for pBSos was $2 million (2008 – $2 million; 2007 – $1 million).

Outstanding Performance based Stock Options

December 31,

(options in thousands,
exercise price in Canadian dollars)

2009

Weighted
Average
Exercise Price

Number

2008

Weighted
Average
Exercise Price

Number

options at beginning of year

3,738

32.72

3,588

options granted

options exercised

options at end of year

options vested

–

(343)

3,395

800

–

23.15

33.69

23.15

250

(100)

3,738

1,143

31.92

40.42

23.15

32.72

23.15

2007

Weighted
Average
Exercise Price

23.15

36.57

23.15

31.92

23.15

Number

1,379

2,345

(136)

3,588

1,243

the total intrinsic value of pBSos exercised during the year ended December 31, 2009 was $6 million
(2008 – $2 million; 2007 – $2 million) and cash received on exercise was $8 million (2008 – $2 million;
2007 – $3 million). the total intrinsic value of pBSos outstanding and vested at December 31, 2009 is $23 million
(2008 – $32 million) and $14 million (2008 – $21 million), respectively.

136

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Performance based Stock Option characteristics

december 31, 2009

options outstanding

Exercise Price

Number

(options in thousands,
exercise price in Canadian dollars)

Weighted
Average
remaining Life
(years)

Weighted
Average
Exercise Price

options vested

Weighted
Average
remaining Life
(years)

Weighted
Average
Exercise Price

Number

23.15

36.57

40.42

800

2,345

250

3,395

0.7

5.6

4.5

23.15

36.57

40.42

33.69

800

0.7

23.15

–

800

0.7

23.15

the total fair value of options vested under the pBSo plan during the year ended December 31, 2009 was
$2 million (2008 – $2 million; 2007 – $2 million).

Assumptions used to determine the fair value of the pBSos at the date of grant 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 2

expected dividend yield 3

Risk-free interest rate 4

2008

4.82

2007

3.40

13.60%

3.32%

3.75%

3.57%

4.38%

Expected option term is based on historical information.

Expected volatility is determined with reference to 20-day rolling period historic share price 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 United States Treasury Bond Yields.

As of December 31, 2009, unrecognized compensation cost related to non-vested share-based compensation
arrangements granted under the pBSo plan was $5 million. the cost is expected to be fully recognized by
December 31, 2012.

EnbridgE inc. 2009 ANNUAL rEPorT

137

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 zero, if the Company’s performance fails to meet threshold performance levels, to a maximum of two, if
the Company performs within the highest range of its performance targets. the 2007, 2008 and 2009 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, adjusted for non-operating or non-recurring
items, relative to targets established at the time of grant.

Compensation expense recorded for the year ended December 31, 2009 for pSus was $20 million
(2008 – $13 million; 2007 – $3 million). to calculate the 2009 expense, multipliers of two, based upon multiplier
estimates at December 31, 2009, were used for each of the 2007, 2008 and 2009 pSu grants.

Outstanding Performance Stock units

December 31,

units at beginning of year

units granted

units cancelled

units matured

Dividend reinvestment

units at end of year

2009

2008

2007

295,428

267,616

328,716

169,600

144,300

137,200

–

(2,384)

(151,882)

(129,852)

(209,827)

17,270

13,364

13,911

330,416

295,428

267,616

of the pSus outstanding at December 31, 2009, 154,518 units have a performance period ending December 31,
2010 and 175,898 have a performance period ending December 31, 2011. the total intrinsic value of pSus
outstanding at December 31, 2009 is $47 million (2008 – $21 million; 2007 – $11 million).

rEStrictEd StOcK unitS
enbridge has a RSu plan where cash awards are paid to certain non-executive employees of the Company
following a 35 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, 2009 for RSus was $23 million (2008 – $15 million; 2007 – $7 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

2009

2008

2007

700,034

456,621

183,253

543,500

418,700

276,875

(18,429)

(23,352)

(18,627)

(282,656)

(179,940)

–

45,428

28,005

15,120

987,877

700,034

456,621

the total intrinsic value of RSus outstanding at December 31, 2009 is $50 million (2008 – $29 million;
2007 – $18 million).

As of December 31, 2009, unrecognized compensation expense related to non-vested units granted under the
pSu and RSu plans was $44 million and is expected to be fully recognized by December 31, 2011.

138

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

22.

Components of Accumulated other Comprehensive Income/(loss)

Net Investment
hedges

Cumulative
Translation
Adjustment

Equity
Investees

Non-Controlling
Interests

Cash Flow
hedges

(millions of Canadian dollars)

Balance at January 1, 2007

263

(399)

Adjustment on adoption
tax impact of adjustment on

adoption

Changes during the year

tax impact

Balance at December 31, 2007

Changes during the year

tax impact

Balance at December 31, 2008

Changes during the year

tax impact

Balance at December 31, 2009

–

194

(19)

175

438

(180)

(160)

278

181

(30)

151

429

–

(534)

–

(534)

(933)

658

–

658

(275)

(815)

–

(815)

(1,090)

–

(57)

(37)

(29)

(20)

(57)

(29)

(8)

(38)

(24)

(32)

–

118

(101)

–

(101)

–

(20)

(5)

149

(175)

(128)

(31)

Total

(136)

–

(182)

(15)

(197)

(285)

280

318

(529)

(47)

(576)

(543)

23.

Risk Management

MArKEt PricE riSK
the Company’s earnings, cash flows and oCI are subject to movements in foreign exchange rates, interest 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), a variant of Value at Risk, is the principal risk management metric used to quantify market
price risk at enbridge. eaR is an objective, statistically derived risk metric that measures the maximum adverse
change in projected 12-month earnings that could result from market price risk over a one-month period within
a 97.5% confidence interval. the Company’s policy is to target a maximum eaR of 5% of earnings. earnings
exposure from market price risk is managed within the overall consolidated eaR limits of the Company. Further,
commodity price risk is managed within business unit eaR sub-limits.

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.

there is currently no uniform industry methodology for estimating eaR. the use of this metric has limitations
because it is based on historical correlations and volatilities in commodity prices and assumes future price
movements will follow a statistical distribution. Although losses are not expected to exceed the statistically
estimated eaR on 97.5% of occasions, losses on the other 2.5% of occasions could be substantially greater
than the estimated eaR.

EnbridgE inc. 2009 ANNUAL rEPorT

139

the following summarizes the types of market price risks to which the Company is exposed and the risk
management instruments used to mitigate them.

Foreign Exchange risk
the Company’s earnings, cash flows, and oCI are subject to foreign exchange rate variability, primarily arising from
its united States dollar denominated subsidiaries. the Company has implemented a policy where it must hedge
a minimum level of foreign currency denominated earnings exposures identified over the next five year period.
the Company may also hedge anticipated foreign currency denominated purchases or sales, foreign currency
denominated debt, as well as certain equity investment balances and net investments in foreign denominated
subsidiaries.

the impact of a $0.05 strengthening of the Canadian dollar across the forward curve relative to the united States
dollar at December 31, 2009, would have resulted in a $92 million increase (2008 – $58 million) to earnings and
a $27 million (2008 – $19 million) increase to oCI. the foreign exchange sensitivity analysis is limited to changes
in the fair value of financial instruments, external debt and loans to foreign operations within the Company that are
not denominated in the Company’s functional currency and are not considered a net investment. Further, the
sensitivity analysis excludes financial instruments that are not monetary items and the impact of the Company’s
united States dollar denominated self-sustaining subsidiaries on oCI.

interest rate risk
the Company’s earnings and cash flows are exposed to short term interest rate variability due to the regular
repricing of its variable rate debt. Floating to fixed interest rate swaps and options are used to hedge against the
effect of future interest rate movements. the Company has implemented a program to significantly mitigate the
volatility of short-term interest rates on interest expense through 2013 at an average rate of 2.2%.

the Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of
anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of
future interest rate movements. the Company has implemented a hedging program to significantly mitigate its
exposure to long term interest rate variability on select forecast term debt issuances through 2013. A total of
$2,500 million of future fixed rate term debt issuances have been hedged at an average government bond rate of
4.0%. Further, many of the Company’s existing commercial arrangements and certain construction projects provide
for the full recovery of financing costs through tolls.

the Company also 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.

A 1% increase across the interest rate yield curve would have caused a $2 million increase (2008 – nil) in earnings
and a $197 million increase (2008 – $14 million) in oCI at December 31, 2009 due to the revaluation of interest
rate derivatives. If interest rates had been 1% higher during the 12 months ended December 31, 2009, there
would have been a $26 million decrease (2008 – $24 million) in earnings due to increased interest expense related
to the Company’s floating rate debt assuming that the variable rate debt outstanding at December 31, 2009 had
been outstanding for the entire year, partially offset by an increase in earnings due to increased realized fair value
gains on settled interest rate hedges of $15 million (2008 – $4 million).

commodity Price risk
the Company’s earnings and cash flows 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 subsidiaries. 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 Company has implemented a hedging program to significantly mitigate the volatility from fractionation
spreads (natural gas / nGls) that impact earnings from its ownership in the Aux Sable natural gas processing
plant through 2011.

140

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

the Company has defined eaR limits for different components of businesses exposed to commodity price risk.
the calculation of these limits include physical and financial derivatives as well as physical transportation and
storage capacity contracts accounted for as executory contracts in the consolidated financial statements. positions
giving rise to commodity price exposure are monitored against these eaR limits daily. For the year ended December
31, 2009, the average eaR was $29 million (2008 – $24 million) and as at December 31, 2009 the Company’s eaR
was $22 million (2008 – $16 million).

tOtAL dEriVAtiVE inStruMEntS
the following tables summarize the balance sheet location and fair value of the Company’s derivative instruments.
the Company did not have any outstanding fair value hedges as at December 31, 2009 or December 31, 2008.

december 31, 2009

(millions of Canadian dollars)

Accounts receivable and other (Note 7)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

Deferred amounts and other (Note 12)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other

Accounts payable and other (Note 15)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other long-term liabilities (Note 18)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

total net derivative asset /(liability)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other

Derivative Instruments
Used as Cash Flow
hedges

Derivative Instruments
Used as Net Investment
hedges

Non-Qualifying
Derivative
Instruments

Total Derivative
Instruments

–

285

–

128

390

117

288

485

(2)

(68)

(17)

–

(87)

(21)

(15)

(4)

–

(40)

(21)

–

(3)

–

(32)

(1)

(36)

–

(2)

334

(12)

326

(5)

(68)

(49)

(1)

(123)

(21)

(15)

(4)

(2)

(42)

434

(33)

448

EnbridgE inc. 2009 ANNUAL rEPorT

141

December 31, 2008

(millions of Canadian dollars)

Accounts receivable and other (Note 7)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

Deferred amounts and other (Note 12)

u.S. dollar cross currency swaps

u.S. dollar forwards

power commodity

Accounts payable and other (Note 15)

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other long-term liabilities (Note 18)

u.S. dollar forwards

Interest rate contracts

power commodity

other

total net derivative asset/(liability)

u.S. dollar cross currency swaps

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other

Derivative Instruments
Used as Cash Flow
hedges

Derivative Instruments
Used as Net Investment
hedges

Non-Qualifying
Derivative
Instruments

Total Derivative
Instruments

153

186

–

(9)

(22)

(1)

(32)

–

(22)

(11)

(3)

(36)

165

(30)

(13)

(4)

(3)

141

–

(14)

–

(4)

–

(18)

(8)

–

(1)

(2)

(11)

–

(2)

272

317

(14)

(9)

(26)

(1)

(50)

(8)

(22)

(12)

(5)

(47)

270

(30)

(5)

292

the following table summarizes the maturity and total notional principal or quantity outstanding related to the
Company’s derivative instruments.

december 31, 2009

December 31, 2008

Notional Principal
or Quantity
outstanding

maturity

u.S. dollar cross currency swaps (millions of Canadian dollars)

– 2013–2022

u.S. dollar forwards – purchase (millions of United States dollars) 2010–2019

1,078 2009–2017

u.S. dollar forwards – sell (millions of United States dollars)

2010–2020

3,102 2009–2021

Interest rate contracts (millions of Canadian dollars)

energy commodity (bcf)

power commodity (MW/H)

2010–2029

2010–2011

2010–2024

6,022 2009–2029

464 2009–2010

38 2009–2024

138

1,118

2,548

1,164

530

the Company does not have any credit-risk related contingent features associated with its derivative instruments.

142

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

the Effect of derivative instruments on the Statements of Earnings and comprehensive income
the following table presents the effect of cash flow hedges and net investment hedges on the Company’s
consolidated earnings and consolidated comprehensive income.

Year ended December 31,

(millions of Canadian dollars)

Amount of unrealized Gain/(loss) Recognized in oCI

Cash Flow Hedges

u.S. dollar cross currency swaps

u.S. dollar forwards

Interest rate contracts

energy commodity

power commodity

other

net Investment Hedges

u.S. dollar forwards

total unrealized loss recognized in oCI

Amount of Gain/(loss) Reclassified from AoCI to earnings

u.S. dollar cross currency swaps 1

u.S. dollar forwards 1

Interest rate contracts 2

energy commodity 3

power commodity 3

other

total loss reclassified from AoCI to earnings

Gain/(loss) reported within Other Investment Income in the Consolidated Statement of Earnings.

Loss reported within Interest Expense in the Consolidated Statement of Earnings.

Loss reported within Commodity costs in the Consolidated Statement of Earnings.

2009

(13)

(103)

(41)

(53)

(23)

(31)

(78)

(1)

(111)

the Company estimates that $89 million of accumulated other comprehensive loss related to cash flow hedges will
be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign
exchange rates, interest rates and commodity prices when derivative contracts that are currently outstanding
mature. For all forecasted transactions, the maximum term over which the Company is hedging exposures to the
variability of cash flows is 54 months at December 31, 2009.

During 2008, the Company terminated certain par forward currency exchange instruments for proceeds of
$48 million. these instruments hedged uS$162 million of the Company’s united States dollar self-sustaining
operations and were accounted for as net investment hedges with the fair value recorded as long-term assets on
the Statement of Financial position with an equal and offsetting amount recorded in AoCI. no gain or loss related
to the terminations will be recorded in the Company’s earnings until there is a disposal of or a return of capital
on a related investment.

EnbridgE inc. 2009 ANNUAL rEPorT

143

non-qualifying derivatives
the following table presents the unrealized gains and losses associated with changes in the fair value of the
Company’s non-qualifying derivatives.

Year ended December 31,

(millions of Canadian dollars)

u.S. dollar forwards 1

Interest rate contracts 2

energy commodity 3

power commodity 3

total unrealized derivative fair value gain

Gain reported within Other Investment Income in the Consolidated Statement of Earnings.

Gain reported within Interest Expense in the Consolidated Statement of Earnings.

Gain/(loss) reported within Commodity costs in the Consolidated Statement of Earnings.

2009

2008

2007

232

(89)

146

–

122

–

157

–

(49)

–

(49)

Additional information regarding the Company’s derivative instruments is included in note 24, Fair Value of
Financial Instruments.

Liquidity riSK
liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments
and guarantees (Notes 31 and 32), as they become due. In order to manage this risk, the Company forecasts 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 united States public capital markets.
In addition, the Company maintains sufficient liquidity through committed credit facilities (Note 16) with a diversified
group of banks and institutions which, if necessary, enables 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 2010. As a result, all credit facilities
are available to the Company and the banks are obligated to fund and have been funding the Company under the
terms of the facilities. 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 activities 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 instruments
the Company generally has no financial instruments, other than derivative instruments, maturing beyond one year
with the exception of its long-term debt (Notes 16 and 17).

For the years ending December 31, 2010 through 2014, and thereafter, the Company has estimated the following
undiscounted cash flows will arise from its derivative instruments based on valuation at the balance sheet date.

2010

2011

2012

2013

2014

Thereafter

(millions of Canadian dollars)

Cash inflows

Cash outflows

net cash flows

182

(167)

106

(29)

136

(5)

131

155

(7)

148

(3)

(25)

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. 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 and contractual requirements, frequent assessment of counterparty credit
ratings and netting arrangements. At December 31, 2009, the Company has a maximum exposure to credit risk of
$517 million related to its derivative counterparties.

144

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits
and contractual requirements, assessment of credit ratings and netting arrangements. Credit risk in the natural
Gas Delivery 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 obtained additional security to minimize the risk of
default on receivables. Generally, the Company classifies and provides for 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 note 24, Fair Value of Financial Instruments.

the change in 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

Balance at end of year

2009

2008

(69)

(29)

(74)

(55)

(37)

(69)

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.

Fair Value of Financial Instruments

24.
the following table summarizes the Company’s financial instrument carrying and fair values and provides a
reconciliation to the Consolidated Statements of Financial position.

held for
Trading

Available
for Sale

Loans and
receivables

held to
maturity

other
Financial
Liabilities

Qualifying
Derivatives

Non-
Financial
Instruments

Total

Fair
value 1

327

–

2,054

181

–

327

302

2,484

2,182

–

2,071

2,312

187

197

1,940

2,425

485

december 31, 2009

(millions of Canadian dollars)

Assets

Cash and cash equivalents
Accounts receivable

and other

long-term investments
Deferred amounts and

other assets

Liabilities

Short-term borrowings

Accounts payable and other

Interest payable

long-term debt

non-recourse long-term debt

other long-term liabilities

–

288

–

508

–

2,177

–

104

– 12,283

–

1,515

–

508

163

2,463

2,300

–

104

(101) 12,182 13,450

(9) 1,506

1,573

–

1,165

1,207

EnbridgE inc. 2009 ANNUAL rEPorT

145

held for
Trading

Available
for Sale

Loans and
receivables

held to
maturity

other
Financial
Liabilities

Qualifying
Derivatives

Non-
Financial
Instruments

Total

Fair
value 1

December 31, 2008

(millions of Canadian dollars)

Assets

Cash and cash equivalents
Accounts receivable and

542

other

long-term investments
Deferred amounts and

other assets

Liabilities

Short-term borrowings

Accounts payable and other

Interest payable

long-term debt

non-recourse long-term debt

other long-term liabilities

–

1,869

–

167

405

–

874

1,965

102

– 10,795

1,669

–

542

381

2,322

1,948

1,866

2,492

492

249

1,001

1,318

317

–

874

396

2,411

2,015

–

102

(106) 10,689

11,173

(10)

1,659

1,672

–

212

259

Fair value does not include non-financial instruments, which includes investments accounted for under the equity method, and available for sale equity

instruments held at cost that do not trade on an actively quoted market.

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 values are
not available, the Company uses discounted cash flow analysis from applicable yield curves based on observable
market inputs to estimate fair value. 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 investments, other than those classified as available
for sale, approximates their carrying value due to interest terms which approximate floating market rates. the fair
value of the Company’s long-term debt and non-recourse 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
derivative instruments approximate their cost due to the short period to maturity. Changes in the fair value of
financial liabilities other than derivative instruments are due primarily to fluctuations in interest rates and time value.

FAir VALuE OF dEriVA tiVES
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
level 1 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 segment and
commodity marketing businesses.

Level 2
level 2 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 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 commodity
marketing businesses and the Corporate segment.

146

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Level 3
level 3 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
against 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 segment and commodity marketing 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 uses standard
valuation techniques to calculate fair value. these methods include discounted cash flows for forwards and swaps
and Black-Scholes pricing models for options. Depending on the type of derivative and nature of the underlying
risk, primary inputs to these techniques include observable market prices (interest, foreign exchange and
commodity) and volatility. 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 Company has categorized its derivative assets and liabilities measured at fair value as follows:

december 31, 2009

(millions of Canadian dollars)

Financial assets: 1

Current derivative assets

long-term derivative assets

Financial liabilities:

Current derivative liabilities

long-term derivative liabilities

total net derivative asset/(liability)

Excludes cash and cash equivalents.

December 31, 2008

(millions of Canadian dollars)

Financial assets: 1

Current derivative assets

long-term derivative assets

Financial liabilities:

Current derivative liabilities

long-term derivative liabilities

total net derivative asset

Excludes cash and cash equivalents.

Level 1

Level 2

Level 3

Total

–

(2)

–

481

(68)

(39)

458

(53)

(3)

(10)

128

485

(123)

(42)

448

Level 1

Level 2

Level 3

Total

–

301

(44)

(37)

229

(6)

(10)

317

(50)

(47)

292

Changes in net fair value of derivative assets and liabilities classified as level 3 in the fair value hierarchy were as follows:

Year ended December 31,

(millions of Canadian dollars)

level 3 net derivative asset at beginning of year

total gains/(losses), realized and unrealized

Included in earnings

Included in oCI

purchases, issuances and settlements

level 3 net derivative asset/(liability) at end of year

2009

2008

(37)

(9)

(61)

(10)

EnbridgE inc. 2009 ANNUAL rEPorT

147

Capital Disclosures

25.
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 1

Cash and cash equivalents

Excludes AOCI and reciprocal shareholdings.

2009

2008

508

874

12,283

10,795

727

7,958

(258)

797

6,740

(469)

21,218

18,737

the Company’s objectives when managing capital are to maintain flexibility among: 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 manages its capital by monitoring 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, 2009, including short-term borrowings but excluding non-recourse short and long-term debt, was
63.6% compared with 63.6% at the end of 2008.

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
$1,000 million or greater and an unconsolidated debt to unconsolidated shareholders’ equity ratio of less than
1.5. As at December 31, 2009, 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, 2009, the Company was in
compliance with this covenant.

148

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

26.

Income taxes

incOME tAx rAtE rEcOnciLiA tiOn

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

Sale of investments

other

Income taxes

effective income tax rate

cOMPOnEntS OF FuturE incOME t AxES

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

Regulatory assets

Financial instruments

loss carryforwards

other

2009

2008

2007

1,868

30.5%

570

(58)

(68)

(61)

(99)

306

16.4%

1,837

31.3%

575

(11)

(15)

(82)

509

27.7%

916

33.9%

311

(63)

(6)

(19)

(6)

–

(8)

209

22.8%

2009

2008

1,346

407

319

121

(138)

790

452

–

(1)

(150)

net Future Income tax liability

2,084

1,113

net future income tax liability of $2,084 million (2008 – $1,113 million) includes future income tax liabilities of
$2,211 million (2008 – $1,291 million) net of future income tax assets of $127 million (2008 – $178 million).

At December 31, 2009, the Company has recognized the benefit of unused tax loss carryforwards of $425 million
(2008 – $452 million) of which $421 start to expire in 2019 and beyond.

EnbridgE inc. 2009 ANNUAL rEPorT

149

gEOgrAPhicAL cOMPOnEntS OF PrEt Ax EArningS And incOME t AxES

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

27.

post-employment Benefits

2009

2008

2007

954

334

580

624

419

794

1,868

1,837

117

101

218

306

141

251

166

258

509

511

210

195

916

152

168

(36)

209

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 natural Gas Delivery and Services
pension plans (collectively, the Canadian plans) provide Company funded defined benefit pension and/or defined
contribution benefits to Canadian employees of enbridge. the enbridge united States pension plan (the united
States plan) provides Company funded defined benefit pension benefits for united States 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,
2009 for the Canadian plans and December 31, 2009 for the united States 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:

Canadian plans

united States plan

The December 31, 2009 valuation will be filed in mid-2010.

Effective Date of most recently
Filed Actuarial valuation

Effective Date of Next required
Actuarial valuation

December 31, 2006

December 31, 2008

December 31, 2009 1

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, benefit costs equal amounts required to be contributed by the Company.

150

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Post-Employment benefits Other than Pensions
opeB primarily include supplemental health, dental, health spending account and life insurance coverage for
qualifying retired employees.

dEFinEd bEnEFit PLAnS
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.

December 31,

(millions of Canadian dollars)

change in Accrued benefit Obligation

Benefit obligation at beginning of year

Service cost

Interest cost

Amendments

employees’ contributions

Actuarial gain

Benefits paid

effect of foreign exchange rate changes

Benefit obligation at end of year

change in Plan Assets

Pension Benefits

oPEB

2009

2008

2009

2008

1,075

1,100

179

183

–

(13)

(51)

(16)

(4)

–

(125)

(46)

1,119

1,075

Fair value of plan assets at beginning of year

1,141

Actual return on plan assets

employer’s contributions

employees’ contributions

Benefits paid

other

effect of foreign exchange rate changes

–

(51)

(1)

(17)

1,310

(180)

–

(46)

(1)

Fair value of plan assets at end of year

1,167

1,141

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

net amount recognized on an accrual basis at end of year

Adjustment to cash basis for amounts in eGD 1
net amount recognized in the Consolidated Statement

of Financial position at end of year 1

presented as follows:

Deferred Amounts and other (Note 12)

other long-term liabilities (Note 18)

(1,119)

(1,075)

(170)

1,167

1,141

(15)

167

227

(157)

(13)

161

216

–

216

–

(110)

–

(110)

–

(1)

(8)

(16)

170

(8)

(132)

–

(110)

–

(27)

(7)

179

(12)

(7)

–

(179)

(133)

–

(97)

(22)

–

(22)

Prior to January 1, 2009, the Company recognized pension benefit costs related to its regulated EGD pension plan on the cash basis. As a result, this

amount was not recognized in the Consolidated Statements of Financial Position (Note 3).

EnbridgE inc. 2009 ANNUAL rEPorT

151

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

2009

6.46%

3.73%

2008

6.59%

5.00%

2007

2009

2008

2007

5.65%

5.00%

6.28%

6.42%

5.71%

Pension Benefits

oPEB

net benefit costs recognized

Year ended December 31,

2009

2008

2007

2009

2008

2007

Pension Benefits

oPEB

(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 1
net defined benefit costs on an

accrual basis

Adjustment to cash basis for

amounts in eGD 2

Defined contribution benefit costs
net benefit cost recognized

in the Consolidated Statements
of earnings

(51)

(27)

(2)

(20)

–

180

(273)

(2)

(8)

(3)

(105)

(2)

(7)

(1)

(6)

–

(5)

–

(15)

–

(3)

–

(2)

–

(4)

–

EEP does not have employees and uses the services of the Company for managing and operating its businesses. EEP is charged an amount, measured at

cost, for pension benefits and OPEB.

Prior to January 1, 2009, the Company recognized pension benefit costs related to its regulated EGD pension plan on the cash basis (Note 3).

the weighted average assumptions made in the measurement of the cost of the pension plans and opeB are as follows:

Pension Benefits

oPEB

Year ended December 31,

2009

2008

2007

2009

2008

2007

Discount rate
Average rate of return on pension

plan assets

Average rate of salary increases

6.59%

5.65%

5.27%

6.42%

5.71%

5.37%

7.30%

5.00%

7.30%

5.00%

7.31%

5.00%

6.09%

6.00%

4.50%

MEdicAL cOSt trEndS
the assumed rates for the next year used to measure the expected cost of benefits are as follows:

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

Canadian plans

Drugs

other Medical and Dental

united States plan

9.4%

4.5%

8.0%

4.5%

2029

2009

2029

A 1% increase in the assumed medical and dental care trend rate would result in an increase of $23 million in
the accumulated post-employment benefit obligations and an increase of $2 million in benefit and interest costs.

152

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

A 1% decrease in the assumed medical and dental care trend rate would result in a decrease of $19 million in the
accumulated post-employment benefit obligations and a decrease of $2 million in benefit and interest costs.

PLAn ASSEtS
Major categories of Plan Assets
plan assets are invested in a diversified manner, primarily in readily marketable investments including equity and
fixed income securities.

As at December 31, 2009, the pension benefits assets were invested 54.7% (2008 – 57.3%) in equity securities,
34.0% (2008 – 35.1%) in fixed income securities and 11.3% (2008 – 7.6%) in other. the opeB assets were
invested 60.5% (2008 – 58.0%) in equity securities and 39.5% (2008 – 42.0%) in fixed income securities.

Level 1 1

Level 2 2

Level 3 3

Total

december 31, 2009

(millions of Canadian dollars)

Pension benefits:

Cash and cash equivalents

Fixed income securities:

Canadian government bonds

Corporate bonds and debentures

Canadian corporate bond index fund

Canadian government bond index fund

united States debt index fund

equity:

Canadian equity securities

Canadian equity funds

united States equity funds

Global equity funds

private equity investment 4

exchange-traded foreign currency derivatives

other:

Refundable taxes receivable 5

other net receivables/(payables)

–

131

137

150

117

127

–

117

–

864

199

–

131

137

150

117

244

1,167

OPEb:

Fixed income securities:

united States government and government agency bonds

–

equity:

Global equity funds

–

Level 1 assets include assets with quoted prices in active markets for identical assets.

Level 2 assets include assets with significant observable inputs.

Level 3 assets include assets with significant unobservable inputs.

The fair value of the investment in United States Limited Partnership – Global Infrastructure Fund is established through the use of valuation models.

The fair value of refundable taxes receivable approximates carrying value due to the nature of the receivable and the short period to maturity.

EnbridgE inc. 2009 ANNUAL rEPorT

153

Changes in the net fair value of plan assets classified as level 3 in the fair value hierarchy were as follows.

Balance at beginning of year

total gains/(losses), unrealized

purchases, issuances, settlements

Balance at end of year

Private Equity Investment refundable Taxes receivable

(2)

–

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 plan; (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.

target Mix for Plan Assets

equity securities

Fixed income securities

other

Liquids Pipelines Pension Plan

Natural gas Delivery and
Services Pension Plan

Enbridge United States
Pension Plan

62.5%

32.5%

5.0%

52.5%

42.5%

5.0%

57.5%

37.5%

5.0%

Expected rate of return on Plan Assets

Year ended December 31,

Canadian plans

united States plan

Pension Benefits

oPEB

2009

2008

2009

2008

7.25%

7.75%

7.25%

7.75%

6.00%

PLAn cOntributiOnS by thE cOMPAny

Year ended December 31,

(millions of Canadian dollars)

total contributions

Contributions expected to be paid in 2010

Pension Benefits

oPEB

2009

2008

2009

2008

bEnEFitS ExPEctEd tO bE PAid by thE cOMPAny

Year ended December 31,

2010

2011

2012

2013

2014

2015–2019

(millions of Canadian dollars)

expected future benefit payments

428

154

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

28.

other Investment Income

Year ended December 31,

(millions of Canadian dollars)

net foreign currency gains

Allowance for equity funds used during construction (AeDC)

Interest income on affiliate loans

noverco preferred dividends income

Hurricane insurance recoveries

oCenSA investment income

Gain on reduction of eep ownership interest

other

29.

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

Interest payable

other long-term liabilities

2009

2008

2007

444

135

–

678

–

198

195

2009

2008

2007

(349)

134

281

243

186

(135)

(115)

(66)

(26)

(492)

160

(135)

415

(6)

Related party transactions

30.
All related party transactions are provided in the normal course of business and, unless otherwise noted, measured
at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

eep, an equity investee, 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 as follows.

Year ended December 31,

(millions of Canadian dollars)

eep

Vector pipeline

2009

2008

2007

342

348

302

308

267

272

At December 31, 2009, the Company has accounts receivable of $38 million (2008 – $41 million) from eep and
$1 million (2008 – $1 million) from Vector pipeline.

the Company has provided eep with an unsecured revolving credit agreement for general liquidity support.
the credit facility provides for a maximum principle amount of uS$500 million for a three-year term maturing in
December 2010. At December 31, 2009 and 2008, there were no amounts outstanding on this facility.

EnbridgE inc. 2009 ANNUAL rEPorT

155

eGD, a subsidiary of the Company, has contracts for gas transportation services from Alliance pipeline Canada and
uS and Vector pipeline. eGD is charged market prices for these services as follows.

Year ended December 31,

(millions of Canadian dollars)

Alliance pipeline Canada

Alliance pipeline uS

Vector pipeline

2009

2008

2007

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 charged/(recovered) are as follows.

Year ended December 31,

(millions of Canadian dollars)

purchases

Sales

2009

2008

2007

(6)

(7)

(4)

enbridge Gas Services Inc. and enbridge Gas Services (uS) Inc., subsidiaries of the Company, have transportation
commitments, measured at market value, through 2015 on Alliance pipeline Canada and Vector pipeline. Amounts
charged are as follows.

Year ended December 31,

(millions of Canadian dollars)

Alliance pipeline Canada

Alliance pipeline uS

Vector pipeline

2009

2008

2007

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

2009

2008

2007

(7)

(9)

(6)

(1)

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

2009

2008

2007

–

(2)

–

(2)

ALbErtA cLiPPEr PrOJEct
In July 2009, the Company committed to fund 66.7% of the cost to construct the united States segment of the
Alberta Clipper project. the total cost of the united States segment, which is expected to be ready for service on
April 1, 2010, is estimated at uS$1,300 million, with total expenditures to date of uS$900 million.

156

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

the Company is funding 66.7% of the project’s equity requirements through eelp, an equity investee.
the Company has provided a $282 million (uS$270 million) loan to eep for debt financing related to the
construction. At December 31, 2009, this amount is included in Accounts Receivable and other. the loan,
denominated in united States dollars, bears interest based on variable short-term rates.

In August 2008, the Company transferred $23 million, measured at market value, of 36 inch diameter line pipe
to eep for use in constructing the united States segment of the Alberta Clipper project.

SPEArhEAd nOrth PiPELinE
In May 2009, the Company sold a section of the Spearhead pipeline to its affiliate eep for proceeds of
uS$75 million. this related party transaction has been recorded at the exchange amount which was equal
to the carrying amount.

SOuthErn LightS PrOJEct
In February 2009, as part of its Southern lights pipeline project, the Company transferred the united States
section of a newly constructed light sour pipeline to eep in exchange for a pipeline referred to as line 13.
this non-monetary transaction has been recorded at the carrying amount.

In connection with the exchange discussed above, eep entered into an arrangement to lease line 13 from the
Company for monthly payments of uS$2 million to ensure adequate southbound pipeline capacity prior to the
completion of the Alberta Clipper project. the lease arrangement was effective in February 2009 and can be
terminated at any time with written notice.

LOng-tErM rEcEiVAbLE FrOM AFFiLiA tE
the affiliate long-term note receivable of $159 million (uS$130 million) as at December 31, 2008, included in
Deferred Amounts and other Assets, was repaid by eep in november 2009. Interest income for the year ended
December 31, 2009 related to the note receivable was $11 million (2008 – $12 million; 2007 – $10 million).

31.

Commitments and Contingencies

cOMMitMEntS
the Company has signed contracts for the purchase of services, pipe and other materials totaling $697 million
which are expected to be paid within the next 5 years.

EnbridgE gAS diStributiOn inc.
bloor Street incident
eGD was 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 eGD were dismissed by the ontario
Court of Justice. the decision has been appealed by the Crown to the ontario Superior Court of Justice and the
appeal was heard by the Court during november and December 2009. the Court’s decision has been reserved
and eGD expects it to be released in early 2010. eGD does not believe any fines that may be levied would have
a 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.

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 and regulatory actions and proceedings which
arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory
approvals and permits by special interest groups. 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.

EnbridgE inc. 2009 ANNUAL rEPorT

157

Guarantees

32.
enbridge energy Company, Inc. (eeC), a subsidiary of the Company and 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$62 million of eep’s long-term debt
at December 31, 2009 (2008 – uS$93 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 of such indemnification obligations include the following.

Sale Agreements for Assets or Businesses:

•

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:

•

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.

158

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

united States Accounting principles

33.
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

Year ended December 31,

(millions of Canadian dollars, except per share amounts)

earnings under Canadian GAAp Applicable to Common Shareholders

earnings under Canadian GAAp

Inventory valuation adjustment, net of tax 3
earnings attributable to non-controlling interests under

Canadian GAAp

earnings as a result of consolidating eep under u.S. GAAp 6

earnings under u.S. GAAp

Attributable to

enbridge Inc. 1

non-controlling interests 1

earnings under u.S. GAAp

earnings per Common Share attributable to enbridge Inc.

Diluted earnings per Common Share attributable to enbridge Inc.

cOMPrEhEnSiVE incOME

Year ended December 31,

(millions of Canadian dollars, except per share amounts)

earnings under u.S. GAAp

other comprehensive income/(loss) under Canadian GAAp

underfunded pension adjustment, net of tax 5
other comprehensive income attributable to non-controlling

interests under Canadian GAAp

other comprehensive income as a result of consolidating

eep under u.S. GAAp 6

Comprehensive income under u.S. GAAp

Attributable to

enbridge Inc. 1

non-controlling interests 1

Comprehensive income under u.S. GAAp

2009

2008

2007

1,555

1,562

(24)

177

1,321

1,328

–

278

1,752

1,662

1,538

214

1,752

4.71

4.68

1,328

334

1,662

3.67

3.64

700

707

–

168

921

707

214

921

1.97

1.95

2009

2008

2007

1,752

(576)

(72)

(62)

1,045

965

1,045

1,662

318

(57)

101

241

2,265

1,589

676

2,265

921

(197)

(92)

(81)

574

533

574

EnbridgE inc. 2009 ANNUAL rEPorT

159

FinAnciAL POSitiOn

December 31,

(millions of Canadian dollars)

Assets

Current Assets

Cash and cash equivalents 2,6

Accounts receivable and other 2,6

Inventory 2,3,6

2009

2008

Canada

United States

Canada

United States

327

2,484

784

3,595

478

2,848

824

4,150

542

2,322

845

3,709

961

3,175

911

5,047

property, plant and equipment, net 2,6

18,850

26,837

16,157

24,738

long-term Investments 2,6

Deferred Amounts and other Assets 2,4,5,6

Intangible Assets 6

Goodwill 6

Future Income taxes 8

Liabilities and Shareholders’ Equity

Current liabilities

Short-term borrowings

Accounts payable and other 2,6

Interest payable 6

Current maturities of long-term debt

Current maturities of non-recourse long-term debt 2,6

long-term Debt 4,6

non-Recourse long-term Debt 2,6

other long-term liabilities 2,5,6,9

Future Income taxes 2,4,5,6,8

non-Controlling Interests 1,6

Shareholders’ equity

Share capital

preferred shares

Common shares

Contributed surplus

Retained earnings 3

Additional paid in capital

Accumulated other comprehensive income/(loss) 4

Reciprocal shareholding

2,312

2,425

488

372

127

228

2,478

575

719

148

2,492

1,318

458

389

178

412

2,080

334

808

178

28,169

35,135

24,701

33,597

508

2,463

3,178

104

601

113

151

633

131

874

2,411

102

534

185

874

3,203

143

534

706

3,789

4,601

4,106

5,460

11,581

15,647

10,155

10,257

1,393

1,207

2,211

1,399

1,311

2,147

1,474

259

1,291

5,448

398

2,014

20,181

25,105

17,285

23,577

727

–

797

–

125

3,379

–

125

3,194

125

3,194

–

4,400

4,343

3,383

3,351

–

(543)

(154)

(646)

(154)

7,261

7,145

–

(154)

6,619

(72)

(154)

6,526

total enbridge Inc. liabilities and Shareholders’ equity

28,169

32,250

24,701

30,103

non-Controlling Interests 1,6

–

2,885

–

3,494

28,169

35,135

24,701

33,597

Presentation of Non-Controlling Interests
income statement and the non-controlling interest balance is presented as a liability on the balance sheet. Under U.S. GAAP, the earnings and retained

Under Canadian GAAP earnings attributable to non-controlling interests are presented as part of earnings on the

earnings attributable to non-controlling interests are presented as a separate component of equity.

For the year ended December 31, 2009, $214 million (2008 – $334 million; 2007 – $214 million) of earnings are attributable to non-controlling interests.

160

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

Included in OCI for the year ended December 31, 2009 is an unrealized loss on cash flow hedges of $62 million (2008 – $241 million unrealized gain;

2007 – $81 million unrealized loss), a decrease in currency translation adjustment of $71 million (2008 – $81 million increase; 2007 – $61 million decrease)

and an after-tax change in OCI of $1 million (2008 – $20 million; 2007 – $31 million) attributable to non-controlling interests.

Accounting for Joint Ventures
Company’s investments in joint ventures to be accounted for using the equity method. However, under an accommodation of the United States Securities

Canadian GAAP requires that investments in joint ventures are proportionately consolidated. U.S. GAAP requires the

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 presentation and classification and not earnings or shareholders’ equity. Additional information related

to the Company’s investments in joint ventures is included in Note 10, Joint Ventures.

Commodity Inventories Valuation
be recorded at the lower of cost or market. For the year ended December 31, 2009, lower of cost or market adjustments resulted in a $36 million decrease

Under Canadian GAAP commodity inventories are recorded at fair value. U.S. GAAP requires that commodity inventories

to inventory, a $12 million decrease to the future income tax liability and a $24 million decrease to earnings. There were no lower of cost or market

adjustments related to commodity inventory valuation for the years ended December 31, 2008 and 2007.

Transaction Costs
are reclassified to Deferred Amounts and Other Assets. As at December 31, 2009, $98 million (2008 – $102 million) of transaction costs were reclassified.

Under Canadian GAAP transaction costs arising from the issuance of debt are recorded in Long-Term Debt. For U.S. GAAP, these costs

Pension Funding Status
OPEB plan as an asset or liability and to recognize changes in the funded status in the period in which they occur through comprehensive income while

U.S. GAAP requires an employer to recognize the overfunded or underfunded status of a defined benefit post retirement plan or

Canadian GAAP does not require the recognition of the defined benefit post retirement plan or OPEB plan funding status.

Pension funding status adjustments resulted in an increase in the net liability of $155 million (2008 – $159 million) for the underfunded status of the plans,

a decrease in future tax liability of $52 million (2008 – $54 million) and an increase in accumulated other comprehensive loss of $103 million

(2008 – $105 million) at December 31, 2009.

Amounts removed from OCI and recognized as components of the net pension and OPEB costs in the year are as follows:

(millions of Canadian dollars)

Prior service cost

Net transitional obligation

Net loss

2009

2008

2007

(1)

Amounts included in AOCI that have not yet been recognized as a component of net periodic benefit cost are as follows:

(millions of Canadian dollars)

Prior service cost

Net transitional obligation

Accumulated net loss

Net amounts reflected in OCI for the year are as follows:

(millions of Canadian dollars)

Unamortized prior service cost

Unamortized transitional obligation

Net loss/(gain)

2009

2008

2007

(3)

107

108

(6)

110

105

(7)

2009

2008

2007

(3)

(1)

(23)

The Company estimates that approximately $15 million related to pension and OPEB plans at December 31, 2009 will be reclassified into earnings in the

next twelve months, as follows:

(millions of Canadian dollars)

Net transitional obligation

Prior service costs

Loss

Pension Benefits

OPEB

Total

(2)

–

(1)

Consolidation of a Limited Partnership
the partnership, resulting in an increase to both assets and liabilities of $6,974 million at December 31, 2009 (2008 – $8,248 million) and no recognition or

Under U.S. GAAP the Company is deemed to have control of EEP and therefore consolidates its 27% interest in

measurement changes to equity or earnings as at and for the year ended December 31, 2009.

Unrecognized Tax Benefits

(millions of Canadian dollars)

Unrecognized Tax Benefits at beginning of year

Gross increases for tax positions of current year

Gross increases for tax positions of prior years

Gross decreases for tax positions of prior years

Changes in translation of foreign currency

Unrecognized Tax Benefits at end of year

2009

2008

(1)

–

(82)

EnbridgE inc. 2009 ANNUAL rEPorT

161

The unrecognized tax benefits at December 31, 2009, if recognized, would affect the Company’s effective income tax rate. Gross increases in 2008 include a

$32 million charge for the United States tax litigated matter, to unrecognize all of the tax benefits. As an unfavourable court decision was rendered in 2008, the

full tax benefit balance of $65 was reversed and the unrecognized benefits removed as reflected in 2008 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, 2009 includes $1 million (2008 – $2 million) of interest. As at December 31, 2009, interest and penalties of $10 million

(2008 – $9 million) have been accrued.

The Company and its subsidiaries are subject to either Canadian federal and provincial income tax, United States 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 2004. Generally, all United States federal income tax returns and state and local

income tax returns are closed through 2005 for all tax matters with the exception of the previously litigated matter. Various Canadian federal and provincial

income tax returns for 2006 and 2007 are currently under examination by the Canada Revenue Agency.

Future Income Taxes
ratemaking purposes. As these deferred income taxes are expected to be recoverable in future revenues, a corresponding regulatory asset is also recorded.

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

These assets and liabilities are adjusted to reflect changes in enacted income tax rates. At December 31, 2008, a deferred tax liability of $803 million was

recorded for U.S. GAAP purposes and reflects the difference between the carrying value and the tax basis of property, plant and equipment. Effective

January 1, 2009, the Canadian GAAP exemption which precluded rate regulated entities from recognizing future income taxes was removed.

Indefinite Reversal Rule
to repatriate in the foreseeable future. These earnings relate to ongoing operations and as at December 31, 2009 were approximately $460 million

The Company has not provided future taxes on the unremitted earnings of foreign investments that the Company does not intend

(2008 – $428 million).

nEW AccOunting StAndArdS undEr u.S. gAAP
Fair Value Measurements
In September 2006, the Financial Accounting Standards Board (FASB) issued a statement that defines fair value,
establishes a framework for measuring fair value in the context of GAAp and expands the disclosure requirements
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. the Company adopted this standard for those
assets and liabilities recognized or disclosed at fair value in the financial statements on a recurring basis as of
January 1, 2008 and the aspects of the standard for non-financial assets and liabilities as of January 1, 2009.

business combinations
In December 2007, the FASB issued a revised statement related to business combinations. this statement retains
the fundamental requirements in the original statement, 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. the Company adopted this standard on January 1, 2009.

Accounting for non-controlling interests
In December 2007, the FASB issued a statement related to the classification of non-controlling interests in consolidated
financial statements. the statement requires non-controlling interests in subsidiaries to be reported as equity on the
Statement of Financial position and requires comprehensive income attributable to non-controlling interests to be
disclosed. the standard only impacts presentation and does not impact the recognition or measurement of amounts
related to non-controlling interests. the Company adopted this standard on January 1, 2009.

derivative instrument and hedging Activities disclosures
In March 2008, the FASB issued a statement revising disclosure requirements for derivative instruments and hedging
activities. the standard impacts presentation only and does not impact the recognition or measurement of amounts
related to derivative instruments and hedging activities. the Company adopted this standard on January 1, 2009.

FuturE AccOunting StAndArdS undEr u.S. gAAP
the following standards will be effective for the Company beginning on January 1, 2010. Management does not
expect the adoption of any of these standards to significantly impact the consolidated financial statements.

consolidation of Variable interest Entities
In June 2009, the FASB issued a statement revising the existing statement on Consolidation of Variable Interest
Entities. the revised Statement focuses on a qualitative approach and requires the re-assessment of existing
arrangements on an on-going basis.

Accounting for transfers of Financial Assets
In June 2009, the FASB issued a statement amending the existing statement on Transfers of Financial Assets and
Extinguishments of Liabilities. the amended standard eliminates the qualifying special purpose entity concept,
imposes stricter sale criteria, revises the de-recognition criteria and provides guidance on determining gains or
losses when a transfer qualifies as a sale.

162

nOtES tO thE cOnSOLidAtEd FinAnciAL StAtEMEntS

gLoSSArY

AcSb

AEdc

AFudc

Alliance

AOci

ArOs

ASAP

bcf

bcf/d

bpd

bps

cAPP

cEAA

cicA

ciS

cLh

cO2
cOSO

Canadian Accounting Standards Board

allowance for equity funds used
during construction

allowance for funds used during
construction

Alliance System

accumulated other
comprehensive income

asset retirement obligations

Alberta Saline Aquifer project

billion cubic feet

billion cubic feet per day

barrels per day

basis points

Canadian Association of
petroleum producers

Canadian environmental
Assessment Agency

Canadian Institute of Chartered
Accountants

customer information system

Compañía logística de Hidrocarburos
ClH, S.A.

carbon dioxide

Committee of Sponsoring organizations
of the treadway Commission

cSr

Corporate Social Responsibility

customerWorks CustomerWorks limited partnership

Ear

EcS

EEci

EELP

EEM

EEP

Egd

Egnb

EiF

EiFh

earnings at risk

enbridge Commercial Services Inc.

enbridge energy Company, Inc.

enbridge energy, l.p.

enbridge energy Management, l.l.C.

enbridge energy partners, l.p.

enbridge Gas Distribution Inc.

enbridge Gas new Brunswick

enbridge Income Fund

enbridge Income Fund Holdings

Enbridge

enbridge Inc.

EPi

Ercb

Eub

FErc

gAAP

enbridge pipelines Inc.

energy Resources Conservation Board

new Brunswick energy and
utilities Board

Federal energy Regulatory Commission

Generally Accepted Accounting
principles

gaz Metro

Gaz Metro limited partnership

ghg

greenhouse gases

iASb

iFrS

iSO

itS

JrP

KPc

Lng

LOi

LSr Pipeline

Md&A

Mdq

mmcf/d

MW/h

nEb

ngLs

noverco

ntP

nySE

general partner

International Accounting
Standards Board

International Financial
Reporting Standards

incentive regulation

incentive stock option

incentive tolling settlement

Joint Review panel

Kansas pipeline Company

liquefied natural gas

letter(s) of Intent

new 20-inch diameter light sour crude
oil pipeline being constructed in
conjunction with the Southern
lights pipeline

Management’s Discussion and Analysis

maximum daily quantity

million cubic feet per day

megawatt

megawatt per hour

national energy Board

natural gas liquids

noverco Inc.

netthruput

new York Stock exchange

OcEnSA

oleoducto Central S.A.

Oci

OEb

Offshore

OhSA

OPEb

PbSO

PSu

rOE

rSu

SEP

SiFt

SSM

tbd

other comprehensive income

ontario energy Board

enbridge offshore pipelines

ontario occupational Health and
Safety Act

Sponsored Investments

Corporate

earnings per Common Share

Diluted earnings per Common Share

Adjusted Earnings 1

liquids pipelines

natural Gas Delivery and Services

Sponsored Investments

Corporate

445

635

141

334

328

958

111

(76)

1,555

1,321

4.27

4.25

3.67

3.64

454

289

151

(39)

855

332

302

101

(58)

677

Adjusted earnings per Common Share 1

2.35

1.88

cash Flow data

287

344

(28)

700

1.97

1.95

286

324

(59)

637

1.79

274

323

(69)

615

1.81

1.79

274

322

(78)

593

1.74

Cash provided by operating activities

2,017

1,372

1,362

1,298

Cash used in investing activities

(3,306)

(2,853)

(2,229)

(1,580)

Cash provided by/(used in) financing activities

1,109

1,840

904

268

dividends

Common Share Dividends Declared

Dividends per Common Share

Shares Outstanding (millions)

Weighted average common shares outstanding

Diluted weighted average common shares outstanding

555

1.48

364

366

489

1.32

360

363

453

1.23

355

358

403

1.15

340

343

229

326

(64)

556

1.65

1.63

229

309

(62)

537

1.59

947

(877)

(22)

361

1.04

337

341

Adjusted earnings represent earnings applicable to common shareholders adjusted for non-recurring or non-operating factors. Adjusted earnings and

adjusted earnings per common share are non-GAAP measures that do no thave any standardized meaning prescribed by GAAP. For more information on

non-GAAP measures see pages 36 and 102.

164

FiVE-yEAr cOnSOLidAtEd highLightS

FIvE-YEAr CoNSoLIDATED hIghLIghTS

(per share amounts in Canadian dollars)

common Share trading (tSx)

High

low

Volume (millions)

Financial ratios

2009

2008

2007

2006

2005

48.92

35.20

48.63

46.27

41.48

41.45

38.82

33.10

33.62

31.75

28.59

39.56

40.01

40.27

36.34

228

293

204

174

211

Return on average shareholders' equity 1

22.2%

13.6%

13.9%

13.2%

Return on average capital employed 2

8.9%

9.9%

7.0%

6.9%

Debt to debt plus shareholders' equity 3

66.2%

66.6%

66.5%

68.9%

earnings coverage of interest 4

Dividend payout ratio 5

Operating data
liquids pipelines – Average Deliveries

(thousands of barrels per day)

enbridge System 6

enbridge Regional oil Sands System 7

Spearhead pipeline

olympic pipeline

natural Gas Delivery and Services

Gas pipelines – Average throughput Volumes

(millions of cublic feet per day)

Alliance pipeline uS

Vector pipeline

enbridge offshore pipelines

enbridge Gas Distribution

Volumes (billions of cubic feet)

3.6x

3.8x

2.4x

63.0%

70.2%

68.7%

66.1%

65.2%

2,061

2,030

2,005

2,013

1,872

259

121

280

202

110

291

164

103

284

190

289

142

–

1,601

1,334

2,037

1,609

1,598

1,592

1,597

1,321

1,034

1,015

1,033

1,672

2,060

2,153

2,102

408

433

440

408

439

number of active customers 8 (thousands)

1,937

1,898

1,861

1,820

1,774

Degree day deficiency 9

Actual

Forecast based on normal weather

3,767

3,514

3,802

3,659

3,355

3,750

3,543

3,617

3,745

3,747

Earnings applicable to common shareholders divided by average shareholders' equity (weighted monthly during the year).

Sum of after-tax earnings 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 income taxes and interst expense divided by interest expense (including capitalized interest).

Dividends per common share divided by adjusted earnings per common share.

Enbridge System includes Canadian mainline deliveries in Western Canada and to the Lakehead System at the United States 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 Enbridge Regional Oil Sands System.

Number of active customers is the number of natural gas consuming EGD customers at the end of the year.

Degree day deficiency is a measure of coldness which is indicative of volumetric requirements for natural gas utilized for heating purposes in EGD's

franchise area. It is calculated by accumulating, for the fiscal year, 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.

EnbridgE inc. 2009 ANNUAL rEPorT

165

ENBrIDgE BUSINESSES

LiquidS PiPELinES