Enbridge Inc.
Enbridge
Annual Report
ENB
Can energy be transported safely?
“While we have a strong safety record delivering energy, that is not
good enough for us. We believe all incidents can be prevented and
we’re investing billions of dollars to work towards that goal.”
Cynthia Hansen, Senior Vice President, Enterprise Safety & Operational Reliability
↳ Page 6
How is Enbridge growing?
“We’re currently working on $36 billion in commercially secured growth
projects, and every single one of our businesses is growing—from liquids
and gas pipelines to renewable power generation to gas distribution.”
Byron Neiles, Senior Vice President, Major Projects
↳ Page 9
How is Enbridge preparing for the future of energy?
“ We’re investing in renewable and alternative energy technologies that
provide attractive returns to our investors while reducing our carbon footprint.”
Don Thompson, Vice President, Green Power and Transmission
↳ Page 17
Why should I invest in Enbridge?
“ We’ve consistently delivered industry-leading returns to our shareholders,
and with our significant secured growth opportunities, we’re confident
we’ll continue to do so for many years to come.”
Adam McKnight, Director, Investor Relations
↳ Page 23
2013
2013 Awards and Recognition
↳ Page 34
Management’s Discussion & Analysis
↳ Page 36
Consolidated Financial Statements
↳ Page 121
Notes to the Consolidated Financial
Statements
↳ Page 126
Glossary
↳ Page 181
Five-Year Consolidated Highlights
↳ Page 182
Investor Information
↳ Page 184
ET
G+E
R+I
SI
LTS
An Energy Transformation
North America is in the midst of a
transformation in the way energy
is produced, transported and
used. Enbridge is deeply involved
in this shift.
↳ Page 3
Growth + Execution
Excellence in project execution
is critical to capturing growth
opportunities across all
of Enbridge’s businesses.
↳ Page 9
Renewables + Innovation
Society needs all forms of energy
and Enbridge is playing a major
role in that evolving energy mix.
↳ Page 17
Solid Investment
Our shareholders have done very
well by our value proposition—
industry-leading growth, a very
reliable business model, and a
growing dividend stream—and we
plan to stick with it.
↳ Page 23
Letter to Shareholders
Safety, reliability and respect for
the environment remain our highest
priorities in successfully delivering
on the largest growth plan in our
Company’s history.
↳ Page 27
Le présent document est disponible en français.
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”
section on page 42 of this Annual Report and also in the
Global 100 Most Sustainable
Corporations in the World
Dow Jones
Sustainability Indexes
The Global 100 Most Sustainable Corporations in the
In 2013, DJSI named Enbridge to both its World and
risk sections of our public disclosure filings, including
World highlights global corporations that have been
North America index. The DJSI indices track the
Management’s Discussion and Analysis, available on both
most proactive in managing environmental, social and
performance of large companies that lead the field in
the SEDAR and EDGAR systems at www.sedar.com and
governance issues. Enbridge was named to the Global 100
terms of sustainability, financial results, community
www.sec.gov/edgar.shtml, respectively.
in 2010, 2011, 2012, 2013 and again in January 2014.
relations and environmental stewardship.
Enbridge transports, distributes and generates energy.
By connecting energy supply to the best refinery and
consumer markets, we play a central role in providing
heat and light to homes, offices and factories, fuel
for vehicles and airplanes, and many other essential
products and services that support prosperity and
quality of life for millions of people. We’re now engaged
in the largest expansion in our history. As we grow, we’ll
never lose sight of our three key strategic priorities.
1. Focus on Safety + Operational Reliability
Millions of people across North America count on the energy we deliver every
day, so our top priority is and always will be the safety and reliability of our
operations. It’s our duty and responsibility to prevent incidents, be safe and
protect the environment.
2. Execute Our Growth Capital Program
We currently have $36 billion of enterprise-wide commercially secured projects
expected to come into service between 2013 and 2017—all to meet growing
demand for new energy infrastructure across North America—and we have the
execution and financial capacity and human capital available to make it all happen.
3. Extend + Diversify Our Growth
We’re confident we can extend and diversify our sources of growth well beyond
2017, both through organic growth within our existing core businesses and by
developing new growth platforms—including power generation, electricity
transmission and international—that align with our value proposition.
Enbridge Inc. 2013 Annual Report
1
Enbridge’s pipeline systems are located in
strategically important geographical areas,
giving us an unparalleled ability to grow
our energy delivery networks throughout
North America.
An Energy Transformation
ET
Driven by new technologies
that are dramatically changing
energy supply and demand
equations, North America is in
a period of transformation in
the way energy is produced,
transported and used.
As a business that is in many ways at the nexus of energy issues in
North America, Enbridge is deeply involved in this shift. As we respond
by expanding and extending our energy infrastructure network, we
will never lose sight of our Number One priority—to safely and reliably
deliver the energy that powers our society and drives our economy.
An Energy Transformation
The Energy
Landscape is
Changing, and
so is Enbridge
The world’s energy landscape
has entered a new stage of rapid
and accelerating change.
At the heart of this transformation lies
both a supply push and a demand pull.
The supply push comes from a surge in
North American oil and gas production.
Technology is unlocking massive
unconventional natural gas reserves
across the continent. On the crude
oil side, North America’s supply is
forecast to rise by seven million
barrels per day by 2025. The continent
could be energy self-sufficient—or at
least “energy secure”—as early as 2020.
At the same time, global energy
demand is shifting. It will be driven
by emerging markets—particularly
China and India—and not, as in the
past, by North America or Europe.
The International Energy Agency
estimates that emerging economies
will account for more than 90% of
net energy demand growth to 2035
and that global energy trade will be
reoriented from the Atlantic basin
to the Asia-Pacific region.
The current growth in supply alone
has resulted in significant transport-
ation bottlenecks between the growing
oil and gas supply regions and North
American and global markets. This is
because the existing infrastructure is
either not large enough to transport the
growing volumes, or the infrastructure
is not in the right places. In turn, this
has resulted in price dislocations
and volatility, with North American
energy resources heavily discounted
relative to world prices, which means
lost value for the North American
economy. For example, it’s estimated
that the Canadian economy is leaving
as much as $50 million a day on the
table because of a significant lack of
energy infrastructure, according to
the Canadian Chamber of Commerce.
These factors are driving what is
essentially a reconfiguration of North
America’s oil and gas transportation
grid. Historically, volumes have
generally flowed from coastal ports
to inland markets. The goal now is to
transport growing inland production
from areas such as the oil sands and
the Bakken region to coastal North
American refining hubs.
Enbridge Responds
We're positioned at the very
centre of this energy market
transformation.
We operate the world’s longest and
most complex crude oil pipeline
system, delivering on average more
than 2.2 million barrels per day to
Canada and the U.S.—and we’re
moving rapidly to access new markets
for Canadian and U.S. crude through
a suite of commercially secured
growth projects being rolled out
through 2017. We’re currently aiming
to open North American markets for
up to 1.7 million barrels per day of new
production. That includes connecting
Canadian oil sands product to
refineries in the Houston area through
our Gulf Coast Access program;
and connecting light oil supply from
the Bakken and western Canada to
premium markets in the U.S. Midwest,
Ontario, and Quebec through our
Eastern Access and Light Oil Market
Access initiatives.
In addition, we’re expanding capacity
in the Canadian oil sands where
Enbridge is the region’s leading pipeline
operator; we’re growing our network
of natural gas gathering, treating,
processing and transmission facilities;
and we're investing in new growth
platforms, including renewable power
generation and alternative energy
technologies, electricity transmission
and international opportunities.
And since the integrity of our energy
infrastructure is and always will be a
mission-critical activity for Enbridge,
we're also investing in cutting-edge
technologies to ensure that our energy
transportation and distribution systems
operate safely and reliably—focusing
on areas such as pipeline design and
construction, inspection, and leak
detection and control systems.
4 Enbridge Inc. 2013 Annual Report
Transport.
Distribute.
Generate.
Our energy transportation
and distribution and electricity
generation and transmission
infrastructure plays a significant
role in helping North Americans
meet their energy needs.
Liquids Pipelines
Our mainline system is the largest
conduit of oil into the United States.
We transport 53% of U.S.-bound
Canadian production, which accounts
for 15% of total U.S. imports.
Gas Pipelines + Processing
We have extensive natural gas systems
both onshore in Canada and the United
States, and offshore in the Gulf of Mexico,
that transport approximately 45% of the
natural gas produced in the deepwater
Gulf. We also have midstream processing
facilities in both Canada and the U.S.,
as well as joint-venture interests in the
Alliance Pipeline, the Vector Pipeline
and the Aux Sable fractionation plant
near Chicago.
Gas Distribution
We’re the largest natural gas distributor
in Canada. Today, Ontario-based
Enbridge Gas Distribution is delivering
affordable, clean-burning natural gas
to over 2 million residential, commercial
and industrial customers.
Power Generation + Transmission
Our power generation interests are
made up of renewable assets in Canada
and the U.S. with the capacity to
generate more than 1,800 megawatts
(MW) of emissions-free energy—
enough to power approximately 600,000
homes. Our first power transmission
project went into operation in 2013 and
we’re currently evaluating additional
investment opportunities in this area.
An Energy Transformation 5
Our Edmonton
Terminal is the
starting point of our
cross-continent
Mainline System.
Examining International Opportunities
We expect that for the foreseeable future, growth in global demand for energy
will be dominated by Asian markets. We’re looking to establish asset positions
in countries with strong energy export fundamentals, favourable investment
climates and significant infrastructure development needs. We believe three
countries offer the highest potential: Colombia, Australia and Peru. For example,
we’re currently working with partners on the development of the Oleoducto al
Pacifico pipeline, a proposed heavy oil pipeline to the Pacific coast of Colombia,
with significant support from potential shippers.
An Energy Transformation
How Enbridge
Operates
As Enbridge grows, it’s critical
that we meet the changing
public expectations for both our
Company and our industry.
Local communities want more
information and support on safety
and emergency response issues, and
more robust engagement on both
projects and operations. There is also
considerable public policy debate on
climate change and the expansion of
oil and gas production and pipelines in
North America; and First Nations and
other Aboriginal and Native American
groups are requesting better
collaboration with business and
government on the sustainable
development of natural resources
and energy infrastructure.
Enbridge is responding to these and
other new realities in ways that are
fundamentally changing the way we
do business.
Safety
Millions of North Americans count on
the energy we deliver daily. That’s why
our top priority is the safety and
reliability of our operations. It’s our
duty and our responsibility to prevent
incidents, stay safe, and reduce our
environmental impact.
Safe and reliable operations are the
foundation of our business and our
success, and our safety record
is strong. In our liquids pipelines
business over the past decade, we’ve
transported approximately 14 billion
barrels of crude oil with a safe delivery
record of 99.9993%. But we know that
is not good enough. We believe all
incidents can be prevented.
Our goal is to achieve industry
leadership in the safety and reliability
of our pipelines and facilities, and
protection of the environment. Being
a leader in these areas enables
everything else we do.
To help us reach our goal, we’ve created
a new governance structure and
enhanced processes to strengthen
Enbridge’s culture to make it one that’s
focused on prevention of incidents.
We’re also investing heavily in the
tools, training and technologies needed
to ensure our energy transportation
and distribution systems operate safely,
reliably and in an environmentally
responsible manner. Since 2012, we’ve
invested more than $4 billion in
programs and initiatives to maintain
and further enhance our pipelines
and facilities in all parts of
our business.
Consultation and Engagement
We’re adopting more proactive and
rigorous approaches to public
consultation and engagement on all
of our projects and operations.
We’re engaging with stakeholders
earlier and more often. Our outreach
activities include presentations to
municipal governments, public open
houses and information sessions along
rights-of-way, and meetings and
collaboration with first responders
and community and non-profit
organizations. The development of
energy infrastructure in both Canada
and the United States also requires
consulting with Aboriginal and Native
American groups and building mutually
beneficial relationships that respect
treaty and other Aboriginal rights.
How We Build
Pipelines
For Enbridge, safety and operational
reliability are top of mind even before
we begin to build and operate any
energy infrastructure.
We carefully select pipeline routes
and line locations and maintain
world-class standards for engineering
and design, including special design
requirements for areas such as road,
river and creek crossings. We take
the same rigorous approach with our
other facilities, such as pump stations,
terminals, plants and renewable
energy sites.
Our projects require specially designed
and engineered materials. We set
world-class standards for procurement,
including selection of pipeline materials,
corrosion-inhibiting coatings, and
cathodic protection which entails
applying a small eletrical current to
pipelines to prevent corrosion.
We use leading construction practices,
including a commitment to identify,
mitigate and proactively manage
potential construction project effects
on the environment. We pay close
attention to environmentally sensitive
areas and at-risk species.
Our projects and operations are also
subject to rigorous oversight and
approval by federal, provincial and
state regulators to ensure that we’re
complying with all applicable laws
and regulations.
6 Enbridge Inc. 2013 Annual Report
Safe Community
Our Safe Community Program provides
funding for first responders, police
agencies, firefighters, emergency medical
services and other related health providers
who would respond to emergency
situations in or near communities located
along Enbridge’s pipeline rights-of-way.
Since the program’s inception in 2002,
grants to first responder organizations
in Canada and the United States total
approximately $7 million. This is helping
to make the lives of more than eight
million people safer.
Open + Transparent
Communication
As we plan, build and operate all aspects
of our business, we’re determined to
meet heightened public expectations
regarding transparency, accountability
and performance. We believe in proactive
and frequent communication with all
our stakeholders.
As part of that effort, in 2013 we published
our first Operational Reliability Review,
which outlines our progress on Enbridge’s
safety and operational reliability goals.
Moreover, our Corporate Social
Responsibility (CSR) Report, which
we’ve been publishing annually for 10
years, provides detailed information on
Enbridge’s economic, environmental and
social performance.
The grants we provide through our Safe Community Program help emergency responders in our areas
of operation throughout North America acquire new safety equipment, obtain professional training
and deliver safety education programs in their communities.
We respond to what we hear by taking
concrete action. The input we receive
is enabling us to make better decisions
on everything from safety measures
to pipeline routes, from environmental
risk mitigation to community benefits.
advocating for areas of focus
for research and development.
These efforts can further promote
a “zero spill” mindset not only
within Enbridge, but also in the
greater pipeline community.
Industry Leadership
Community Investment
We’re also taking a leadership
position in the pipeline industry in
both Canada and the U.S. Through
sponsorship and technical leadership
of joint industry research projects,
we’ve actively pursued improvements
to both pipeline in-line inspection
technologies and engineering models
that characterize the pipe condition.
This work has provided our industry
with improved methods of managing
mechanical damage to pipelines.
We’re also an active participant
in numerous industry technical
committees and working groups—
improving codes and standards;
enhancing the current body of
knowledge about pipelines; and
We believe investing in our
communities is an essential part of
being a good neighbour and is a
contributing factor in maintaining
our social license to operate. In 2013,
our enterprise-wide community
investment expenditure totaled
approximately $14 million, which we
invested in more than 750 charitable,
non-profit, and community organizations.
We focus on supporting organizations
that contribute to the economic and
social development of the communities
where we live and work.
In 2013, we published our first
Cynthia Hansen (left) and her team are coordinating
Operational Reliability Review, which
Enbridge’s drive to be the industry leader in safety,
is available at enbridge.com/orr
operational reliability, and environmental protection.
An Energy Transformation 7
Dave Lawson (centre) and his team of
talented engineers are designing several
of our liquids pipelines growth projects in
the Alberta oil sands region, where we’re
the leading pipeline operator.
Growth + Execution
G+E
Along with the dramatic growth
in North American energy
production comes the need
for new energy infrastructure.
Enbridge’s existing assets are
ideally located, allowing us to
capture many growth oppor-
tunities for all of our businesses
right across the continent.
Combine that with our proven track record of successfully bringing projects
into service on time and on budget, and we are very strongly positioned
to drive Enbridge’s growth into the latter half of the decade and well beyond.
Growth + Execution
Where + How
We’re Growing
We’re currently developing $36 billion of commercially
secured growth projects—from liquids pipelines to
renewables. This massive slate of projects, which
represents the largest capital program in Enbridge’s
history, will enable us to deliver superior returns to
our shareholders for many years to come.
Norman Wells
Zama
Fort St. John
Fort McMurray
Cheecham
Kitimat
Blaine
Seattle
Edmonton
Hardisty
Calgary
1
Lethbridge
Rowatt
Regina
Portland
Great Falls
Cromer
Gretna
Salt Lake City
Casper
Las Vegas
Denver
Minot
Clearbrook
Superior
Montreal
Ottawa
Toronto
3
Sarnia
Buffalo
Chicago
Toledo
Flanagan
Patoka
Wood River
Cushing
Tulsa
Houston
2
New Orleans
Please see page 15
for a detailed map of
our existing assets.
Liquids Pipelines
Market Access Initiatives
To link growing producing regions
to the best markets and provide
refineries in Canada and the U.S.
with reliable North American crude
oil, we’re moving ahead with a range
of initiatives to provide producers
increased transportation capacity of
crude oil and in particular for growing
supplies of light crude oil. Three of
our initiatives—Light Oil Market
Access; Eastern Access; and Western
Gulf Coast Access—are already
commercially secured and combined
will open up new markets for up to
1.7 million barrels per day (bpd) of
crude oil by 2016.
Light Oil Market Access
This $6.3 billion1 initiative is a suite
of projects in Canada and the United
States that will collectively allow
an additional 400,000 bpd of light
crude oil from western Canada,
and from the Bakken formation in
North Dakota, to access attractive
markets in eastern Canada and
the U.S. Midwest, while ensuring
that consumers in these regions
are served with gasoline, diesel
and other products refined from
reliable supplies of North American
crude oil. The initiative includes: the
10 Enbridge Inc. 2013 Annual Report
Southern Access Extension Pipeline
from Flanagan, Illinois to the Patoka,
Illinois hub; and the Sandpiper
Pipeline, which will effectively twin
our North Dakota System and expand
its capacity by 225,000 bpd to a total
of 580,000 bpd by 2016.
Eastern Access
This $2.7 billion1 suite of projects
establishes a path for western
Canadian and Bakken crude oil to
access refineries in eastern Canada
and the Midwest and eastern United
States. For example, by reversing
the flow of our existing Line 9,
Ontario and Quebec refineries will
have access to lower-cost western
Canadian feedstock. Ontario and
Quebec currently derive, respectively,
approximately 18% and 90% of
their crude from higher priced
offshore sources.
Western Gulf Coast Access
This $5.2 billion2 initiative, whose
major components are the Seaway
Pipeline reversal and expansion
and the Flanagan South Pipeline,
connects Canadian heavy oil supply
to the vast refinery complex along
the western Gulf Coast near Houston.
of oil from Alberta for export to
refineries in the Asia-Pacific region
and U.S. west coast. The project
involves a crude oil export pipeline
and condensate import pipeline
between Bruderheim, Alberta and
a proposed new marine terminal
in Kitimat, British Columbia.
In December 2013, a federal Joint
Review Panel recommended
the federal government approve
the project, subject to 209 conditions.
The Government of Canada is
expected to render its final decision
on the Northern Gateway project
by June 2014.
Mainline + Regional Expansions
Mainline Expansion
To ensure there is adequate capacity
on our mainline system to supply
our new market access projects,
we’re expanding the capacity of our
Alberta Clipper and Southern Access
pipelines through the addition of
new pumps and pump stations. Also,
to accommodate the volume growth
we’re seeing at our Edmonton hub,
we’re building a new 36-inch line
Western Access
Our proposed Northern Gateway
Project would transport 525,000 bpd
1
Including associated Mainline expansions
2 Including associated Mainline expansions;
excluding Seaway Pipeline acquisition cost
of $1.2 billion in 2012
“With thousands of kilometres of
pipelines across North America,
we have a lot of neighbours.
Like any good relationship, it’s all
about listening, understanding
and taking action when people
have concerns.”
Gina Jordan,
National Manager,
Community Relations
As Toronto grows, so grows Enbridge Gas Distribution. We’re upgrading
and expanding our infrastructure in the Greater Toronto Area to keep pace
with the growth of Canada’s largest city.
between Edmonton and Hardisty,
Alberta with initial capacity of
570,000 bpd, expandable to
800,000 bpd.
Alberta Regional Infrastructure
Enbridge is the leading pipeline operator
in the Fort McMurray to Edmonton/
Hardisty corridors, and our strategic
position and scale in the Alberta oil
sands continues to present great growth
opportunities for the Company. With
$6.2 billion in commercially secured
growth projects from 2012 to 2017,
we’re adding significant incremental
capacity from the region. One of these
projects is our Norlite Diluent Pipeline,
which, when coupled with our existing
Southern Lights Pipeline, will create
a diluent pathway from Chicago to the
heart of the oil sands.
Bakken Regional Infrastructure
In 2013, we completed and brought into
service $0.7 billion of infrastructure
expansion projects in the prolific
Bakken region in North Dakota and
Saskatchewan to provide the region’s
crude oil producers reliable, economical
and secure access to a wide variety
of refinery markets.
Gas Pipelines +
Processing
Onshore
With its unique ability to transport
liquids-rich gas, Alliance Pipeline is
ideally positioned to benefit from
production growth in a number of
liquids-rich natural gas shale plays,
particularly the Bakken play, as well
as the Montney and Duvernay plays
in British Columbia and Alberta.
In the United States in 2013, we
enhanced access for mid-continent
natural gas liquids to the Gulf Coast
market when we put into service the
280,000 bpd Texas Express Pipeline.
Offshore
Enbridge is the largest gas gatherer
and transporter in the Gulf of Mexico,
handling 40% of total offshore gas
production and 45% of total
ultradeep gas production. In 2014,
we will see a full-year contribution
from our expanded Venice condensate
stabilization facility, which went into
service in the fourth quarter of 2013,
as well as the completion of the
first phase of the Walker Ridge Gas
Gathering System. Looking ahead, we
expect the second phase of the Walker
Ridge Gas Gathering System as well as
the Big Foot Oil Pipeline to be in service
in 2015, and the Heidelberg Lateral
Pipeline to be operational by 2016.
Processing
In Canada, we’re developing gas
gathering and compression facilities
in the Peace River Arch (PRA) region
in northwest Alberta. The PRA is in
close proximity to the Alliance
Pipeline. In Texas in 2013, the Ajax
Processing Plant went into service
and construction activities began on
the Beckville cryogenic natural gas
processing plant with an in-service
date of 2015.
Gas Distribution
With more than 2 million customers,
Enbridge Gas Distribution (EGD) is one
of the fastest growing gas distribution
franchises in North America. EGD is
currently engaged in the largest
capital expenditure program in its
history as it expands its system in the
Greater Toronto Area to meet growth
12 Enbridge Inc. 2013 Annual Report
in demand for natural gas heating of
homes and businesses. The project
represents the most significant
upgrade to the distribution system
in 20 years.
Power Generation
+ Transmission
We have interests in wind, solar,
geothermal, a fuel cell and waste
heat recovery facilities with a total
generating capacity of more than
1,800 MW of emissions-free energy.
We’re Canada’s largest solar energy
and second largest wind power
producer. In 2013, we secured a 50%
interest in the development of the
300-MW Blackspring Ridge Windfarm
in Alberta, which is expected to be
in-service in 2014, and we secured a
50% interest in the 80-MW Saint-
Robert-Bellarmin Windfarm in
Quebec. In January 2014, we
announced Enbridge will invest
approximately US$0.2 billion in the
110-MW Keechi Wind Project in Texas.
Construction commenced in December
2013 and the project is expected to
reach commissioning in 2015.
Our market access initiatives
will open up new markets for up
to 1.7 million bpd of crude oil.
Enbridge’s first power transmission
project—the 300-MW Montana-
Alberta Tie-Line (MATL) from Great
Falls, Montana to Lethbridge, Alberta—
went into operation in 2013 to
support the electric transmission
needs of new wind power facilities
in north-central Montana and buoyant
power demand in Alberta. We are
currently considering doubling MATL’s
capacity to 600 MW. Also, Enbridge is
a member of the consortium selected
in 2013 to develop the East-West Tie
Line Project, a major new electricity
transmission line in northwestern
Ontario. The line will be approximately
400 kilometres long and run between
Thunder Bay and Wawa.
Diversified Growth
While the lion’s share of our $36 billion
in commercially secured growth projects
through 2017 fall within our Liquids
Pipelines business segment, we’re
also working to develop, in a
disciplined way, new growth platforms
that align with our value proposition,
including power generation, electricity
transmission and international. This is
another reason why we’re confident
that we can meet our strategic priority
to extend and diversify Enbridge’s
growth beyond 2017.
Enbridge’s Three Keys to Project Execution
Major Projects Expertise
Staffing
Funding
One of Enbridge’s key strategic
advantages is our ability to safely
and successfully deliver our growth
projects on time and on budget.
Our Major Projects group has a team
of 1,400 people and 65% of those are
contractors, which allows us to match
the resources with activity levels.
Keys to our success include:
• Regulatory effectiveness
• Disciplined control of costs,
schedule and quality
• Rigorous risk identification
and mitigation
• Extensive governance and
reporting
• Learning lessons from each
project and incorporating those
into new business proposals
In addition, we have thousands of
contract workers in the field. Rapid
scalability of a seasoned workforce
generates value for our customers
and supports our very strong execution
track record. Our contractor selection
process is designed to ensure that
they execute their work to Enbridge’s
stringent safety standards and
uphold Enbridge’s values.
We’re well advanced in the execution
of the funding and liquidity plan to
support our long-term growth.
Enterprise-wide funding and liquidity
actions in 2013 added $10.3 billion to
our funding sources.
Enbridge’s sponsored investments
also can provide us with lower cost
funding alternatives.
Growth + Execution 13
Growth + Execution
Enbridge’s Commercially Secured
Growth Projects 2013 – 2017
Light Oil Market Access
$6.3 Billion1
We’re expanding access to markets for growing volumes of North Dakota
and western Canada light oil to premium refinery markets in Ontario,
Quebec and the U.S. Midwest, helping to ensure that consumers in these
regions are served with gasoline, diesel and other products refined from
reliable supplies of North American crude oil.
Eastern Access
$2.7 Billion1
Western Gulf Coast
Access
$5.2 Billion2
We’re establishing a path for western Canadian and Bakken crude oil to
access refineries in eastern Canada, as well as the Midwest and eastern U.S.
We’re connecting Canadian heavy oil supply to the vast refinery complex
along the western Gulf Coast near Houston.
Regional Expansions
$7.0 Billion3
We’re expanding our regional infrastructure in key producing regions,
including Alberta where we’re well positioned to tie-in new oil sands
developments to mainline pipelines and increase capacity for
current customers.
Line 3 Replacement +
Other Mainline
$9.0 Billion
We’re replacing all segments of Line 3 of our mainline between Hardisty,
Alberta and Superior, Wisconsin with new pipe using the latest available
high-strength steel and coating technology. Targeted for completion
in 2017, the Line 3 Replacement Program is the largest project in the
Company’s history.
Gas Pipeline +
Processing
$2.5 Billion
We’re expanding our offshore pipeline infrastructure in the Gulf of
Mexico; and we’re growing our network of onshore natural gas gathering,
treating, processing and transmission facilities to support the large
unconventional gas plays in both Canada and the United States.
Enbridge Gas
Distribution
$1.7 Billion
Power Generation +
Transmission
$1.5 Billion4
Enbridge Gas Distribution is upgrading and expanding its system in the
Greater Toronto Area (GTA) to meet growing demand for natural gas from
residential, commercial and industrial customers.
Our first power transmission project went into service in 2013; and with
new wind projects under development in Alberta and Texas, we’re further
solidifying our position as a leading renewable energy generator in
North America.
1
Including associated Mainline expansions
2 Including associated Mainline expansions; excluding Seaway Pipeline acquisition cost of $1.2 billion in 2012
3 2013 – 2017; includes Norlite (diluent) Pipeline System
4 Includes $1.1 billion for four wind power projects (Massif du Sud, Saint-Robert-Bellarmin and Lac Alfred in Quebec;
Blackspring Ridge in Alberta, and Keechi in Texas) and US$0.4 billion for the Montana-Alberta Tie Line
$36B
With our $36 billion slate of
commercially secured energy
infrastructure growth projects,
Enbridge is playing a pivotal
role in supporting a massive
increase in energy production
in North America—from
Alberta’s oil sands and uncon-
ventional oil and gas plays in
Canada and the United States,
to offshore Gulf of Mexico,
to renewable power generation.
14 Enbridge Inc. 2013 Annual Report
Norman Wells
Zama
3
Fort McMurray
Cheecham
Fort St. John
2
Kitimat
1
Edmonton
Hardisty
Blaine
Seattle
Calgary
1
Portland
Lethbridge
4
Great Falls
Regina
Rowatt
Cromer
Gretna
5
Minot
Clearbrook
Superior
Casper
Salt Lake City
Las Vegas
Denver
8
Our 10,000+ employees are
working hard every day to
safely meet the energy needs
of North Americans
1
2
3
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
Power Transmission
Gas Distribution
Wind Assets
Storage
Solar Assets
Waste Heat Recovery
Geothermal Assets
Fuel Cell
Montreal
7
Ottawa
6
Toronto
3
Sarnia
Buffalo
1.1 million bpd
Chicago
Toledo
Flanagan
Patoka
Wood River
Cushing
Tulsa
Houston
2
New Orleans
With Bakken crude oil production expected to grow
to approximately 1.1 million barrels per day in 2014,
we’re expanding access from the region to attractive
refinery markets in Ontario, Quebec and the U.S.
Midwest.
2 million+ customers
Enbridge Gas Distribution already has more
than two million customers and is now investing
in the largest system expansion in its over
160-year history.
4,000 jobs
By establishing a clear path for western Canadian and
Bakken crude oil to refineries in Quebec, our Line 9B
Reversal and Expansion Project is helping to protect
critical refinery capacity and sustain more than 4,000
refining and petrochemical industry jobs.
1.6 million tonnes
Our renewable and alternative energy projects in
Canada and the United States result in the avoidance
of approximately 1.6 million tonnes of GHG emissions
each year.
1 $1.2 billion
3 million bpd
40%+ U.S. refining capacity
Our proposed Northern Gateway Project
With oil sands production expected to grow to more
We’re connecting Canadian heavy oil supply to the vast
would generate $1.2 billion in tax revenue for
than 3 million bpd by 2020, we’re enlarging our
U.S. Gulf Coast refinery complex, which is the largest
British Columbia over 30 years—funds that
infrastructure in Alberta to help connect growing
in the world and accounts for more than 40% of U.S.
support education, hospitals and infrastructure.
supply with the best markets.
petroleum refining capacity.
6 billion bcf/d
300 MW
45% total production
Our Alliance Pipeline system traverses the Montney
Our first power transmission project—the 300-MW
In the Gulf of Mexico, the large, new reservoirs are in
and Duvernay plays, where production of liquids-rich
Montana-Alberta Tie-Line—went into service in 2013,
the ultra-deepwater, where Enbridge already handles
gas is currently projected to grow to more than
supporting the electric transmission needs of new wind
45% of total natural gas production.
6 billion cubic feet per day by 2025.
power facilities in north-central Montana and strong
power demand in Alberta.
Enbridge is the second-largest
generator of wind energy in
Canada, providing enough
power to meet the needs of
more than 420,000 homes.
Renewables + Innovation
R+I
Society needs all forms of
energy. As one of the largest
renewable energy companies
in Canada, we’re already
playing a part in that bigger
picture and we’re planning to
do even more in the future.
Our investments in renewable and alternative energy technologies
are a key element of our business strategy, as are our investments in
innovative technologies designed to lower the environmental impact
of hydrocarbons.
Our Silver State North
solar project in Nevada
generates enough
emissions-free energy to
serve 9,000 homes.
We’re Investing in a
Cleaner Energy Future
While it’s widely recognized global
demand for energy will continue to
grow, Enbridge also knows that society
wants to see wider use of clean energy—
and we believe finding lower impact
energy solutions is in everyone’s best
interests. Since 2002, we’ve been
investing in renewable and alternative
energy technologies that provide both
attractive returns to our investors and
significant environmental benefits.
Furthermore, as the economics and
technologies that support clean power
generation continue to improve, we
believe the future for this part of our
business is very promising.
We’ve built Enbridge’s clean power
generation business from the ground
up and to date have invested more than
$3 billion in renewable and alternative
energy projects across North America
that have the capacity to generate
more than 1,800 MW of emissions-free
energy—enough to meet the energy
needs of approximately 600,000 homes.
Today we’re Canada’s largest solar and
second largest wind power producer;
and in the United States, we’re a
growing renewable energy player with
investments in wind, solar and
geothermal. We’re also investing in a
wide range of alternative energy
projects including waste heat recovery,
run-of-river power generation, and
technologies that will make it
economical to store renewable energy.
Our renewable energy projects are
underpinned by attractive long-term
power purchase agreements and
fixed-price contracts that deliver stable
cash flows and attractive returns similar
to those realized by our oil and gas
transportation and delivery operations.
These projects also contribute to
Enbridge’s Neutral Footprint
commitment to generate a kilowatt
hour of renewable energy for every
additional kilowatt hour of additional
electricity that the Company’s
expansion projects consume.
In coming years, we’ll grow our power
generation capacity in a measured
fashion with the objective of approx-
imately doubling capacity by 2017.
We’ll achieve this both by continuing
to invest in renewable and alternative
energy projects and by investing in
technologies and businesses that are
strategically aligned with Enbridge’s
business interests. For example, we’re
looking at adding natural gas-fired
electricity generation to our business
mix. North Americans want clean and
affordable energy options, and we
believe natural gas is a fuel of choice
due to its low-carbon intensity.
This is another way we can help society
transition to a lower-carbon intensive
economy, while at the same time lay
the foundation for a more diversified
asset base and continued growth and
prosperity for the Company.
We also support efforts by our Gas
Distribution customers to use energy
wisely through our demand-side
18 Enbridge Inc. 2013 Annual Report
With three solar projects in
Ontario generating 100 MW,
Enbridge is Canada’s largest
solar energy generator.
Enbridge’s Renewables
Investments—By the Numbers
management (DSM) programs.
From homeowners to large industrial
facilities, we encourage, educate,
facilitate and incentivize customers to
adopt energy saving equipment and
operating practices to reduce
consumption of natural gas. Since 1995,
our DSM programs have delivered net
energy savings to customers of
approximately $2.3 billion and helped
our customers avoid cumulatively
nearly 15 million tonnes of carbon
dioxide emissions.
Our Renewable
Energy Story So Far
Wind
Enbridge has interests in 13 wind
farms—in Quebec, Ontario,
Saskatchewan, Alberta, Colorado
and Texas—with a combined total
capacity of 1,662 MW of electricity.
Approximately one-third of that total
is now in Quebec, which is the largest
wind power market in Canada.
In January 2014, we announced
Enbridge will invest approximately
US$0.2 billion in the 110-MW Keechi
Wind Project in Texas. Construction
commenced in December 2013 and
the project is expected to reach
commissioning in 2015. Texas is the
leader in wind energy generation in the
United States both in terms of installed
capacity and number of turbines, and
this investment represents a natural
extension for Enbridge’s growing U.S.
renewable energy portfolio.
Wind-generated electricity is the
fastest-growing sector of electricity
generation in North America, as
substantial technological advances,
cost reductions, renewable portfolio
standards and availability of long-
term power purchase agreements have
enabled wind projects to become
economically attractive investments.
We expect future wind opportunities
to come through the securement of
construction-ready or operational
projects, expansion of our existing
operations and development of new
greenfield projects throughout
North America.
Solar
Our four solar energy projects, in
Ontario and Nevada, have the capacity
to generate 150 MW of electricity.
Our 80-MW Sarnia Solar facility
in Ontario is one of the largest
photovoltaic solar energy facilities in
North America. We believe that solar
energy continues to offer meaningful
opportunities for long-term growth.
Geothermal
Geothermal power is recovered from
the heat of the earth’s interior. Enbridge
owns a 40% interest in the 23-MW
Neal Hot Springs Geothermal Project in
Oregon that is delivering electricity to
the Idaho Power grid under a 25-year
power purchase agreement.
13 wind farms
Enbridge’s interest: 1,121 MW
Total capacity: 1,662 MW
4 solar farms
Enbridge’s interest: 150 MW
Total capacity: 150 MW
1 geothermal project
Enbridge’s interest: 9 MW
Total capacity: 23 MW
Renewables + Innovation 19
Renewables + Innovations
Investing
in Energy
Innovation
Enbridge has a team of scientists and business people searching the world
for new technologies that are strategically aligned with Enbridge’s business
interests. Called the Pathfinders Group, they first thoroughly screen the best
of the ideas to ensure that they’re technically sound and then commercially
structure any investment in a way that makes sense for Enbridge. Once Enbridge’s
investment in a particular technology reaches a significant size, the group
turns it over to one of Enbridge’s business units to grow and operate it as a
new business platform.
Two technologies—wind and solar energy—have already moved from the
incubation stage to the point where they have become meaningful and
profitable new businesses for Enbridge, and our Pathfinders Group hopes to
add more clean energy platforms to our portfolio in the years to come.
For example, we currently have equity and project investments in companies
that are developing run-of-river hydro, electricity generation from waste
energy sources, the transportation of compressed natural gas by sea,
large-scale electricity storage, and next-generation solar technology.
In 2013, we invested in:
• Temporal Power Ltd., a developer and manufacturer of electrical energy
storage systems (please see story on facing page).
• On-Ramp Wireless Inc., a developer of wireless solutions that enable us
to better connect with and monitor assets, such as transmission pipelines,
in a more economical and reliable manner than conventional wireless
technologies currently allow.
• Smart Pipe Company Inc., the developer of a high-pressure, self-monitoring
internal pipeline replacement system, which features an embedded fibre
optic inspection system that allows the pipeline operator to continually
monitor and instantly detect and locate possible leaks, abnormal temperature
changes, third-party impacts or ground movement.
Pipeline Integrity + Leak Detection
Given that our core business is the safe transportation of liquid hydrocarbons,
we’re committed to continuous improvements to ensure the reliability and
integrity of our pipeline systems, and the systems and technologies we use
to detect leaks. Over the past four years, we’ve been steadily increasing our
investments in innovative leak detection technologies, with the goal of
implementing industry-leading leak detection capability.
Innovations we’re evaluating and investing in include: real-time leak
detection technologies; ultra-high-sensitivity gas-leak monitoring systems;
advanced aerial leak-detection technologies; gas-sensing technology for
use on aboveground storage tanks; and leak-response technologies. For more
information on these, please visit: csr.enbridge.com/innovation
Neutral Footprint
Through our Neutral Footprint
commitments, which began in January
2009, we’ve formally committed to
planting a tree for every tree we
remove and helping to conserve an
acre of natural habitat for every
acre we permanently alter when
building new energy infrastructure,
as well as generating a kilowatt
hour of renewable energy for every
kilowatt hour of additional energy
our expansion projects consume.
Our Neutral Footprint commitments
are voluntary and are applied and
integrated into our new projects.
For the current status of our Neutral
Footprint commitments, please see
our Neutral Footprint dashboard online
at: enbridge.com/neutralfootprint
20 Enbridge Inc. 2013 Annual Report
Walter Kresic, Enbridge’s
Vice President, Pipeline
Integrity (right) and Tom
Machnik, NDT Systems &
Services Inc., look over a
custom-designed in-line
inspection tool.
Finding Solutions for Energy Storage
One of the biggest constraints on
renewable energy is its intermittency.
Because the wind doesn’t blow and
the sun doesn’t shine uniformly all
the time, operators of the power grid
have a real problem balancing supply
and demand every second.
What’s needed is a way to manage
the natural ebb and flow of renewable
energy by finding new ways to store
electricity for use when it’s needed.
As Canada’s top producer of solar
power and second largest generator
of wind power, with large renewable
energy projects in the U.S. as well,
Enbridge is investing in technologies
that support large-scale energy storage.
In 2012, Enbridge invested $5 million
in Hydrogenics Corporation, whose
water electrolysis technology can
convert surplus renewable energy into
ultra-clean-burning hydrogen gas.
By converting electricity to gas, the
hydrogen can be stored in vast
natural gas pipeline networks such as
Enbridge Gas Distribution’s system.
The stored electricity can be returned
to the grid, when required, using
gas-powered generators.
In 2013, Enbridge also invested
$5 million in Temporal Power, developer
of an innovative flywheel technology.
A cylinder suspended in a vacuum
chamber, the flywheel acts as a
mechanical battery: when the wind is
blowing or the sun is shining, it charges
by using a motor to spin the cylinder;
later when it’s time to extract electricity,
the flywheel uses kinetic energy to spin
a generator. Each flywheel can produce
500 kilowatts of power. Flywheels
can be grouped in modules to provide
scalable generation facilities.
“Electricity storage devices such as
power-to-gas and flywheel technologies
can be enablers of renewables,” says
Chuck Szmurlo, Enbridge’s Vice
President, Alternative and Emerging
Technology. “By investing in these
technologies, we’re helping to advance
the economic effectiveness of intermit-
tent sources like wind and solar.”
Renewables + Innovation 21
Chuck Szmurlo (standing) and his Pathfinders
Group are leading Enbridge’s search for promising
opportunities for investment in emerging clean
energy technologies.
Our shareholders depend on Enbridge to
deliver a predictable and growing stream
of dividends, and we do. Over the past
10 years, we’ve delivered average annual
dividend growth of approximately 13%.
Solid Investment
SI
Enbridge’s shareholders have
done very well by our value
proposition—visible growth,
a very reliable business model,
and growing dividend stream—
and we plan to stick with it.
Through this proven formula, we’ve consistently created superior
shareholder value over many years, regardless of what market sectors
are in or out of favour.
Solid Investment
Our Value
Creation Formula
Enbridge is focused on
maintaining our long-standing
value proposition that has
delivered superior returns
over the long term, regardless
of what sectors are in favour.
Industry-Leading Growth
We’re confident we’ll continue to deliver superior growth
for many years to come. On the strength of our excellent
competitive position in North America, we now have
$36 billion in growth projects under construction or on
the drawing boards. All of these projects are commercially
secured and planned to be in service by 2017. On top of that,
we have an additional inventory of $5 billion in projects that
are still in development, giving us a record $41-billion growth
plan through 2017. The progress we made on our capital
program in 2013 gives us confidence that we’ll be able to
deliver 10% to 12% average annual adjusted earnings per
share (EPS) growth through 2017; and it puts us on a solid
footing to extend our industry-leading growth beyond that.
A Reliable Business Model
Our reliable business model is the backbone of our value
proposition. It has consistently achieved financial results
within a tight guidance band and has delivered value for
shareholders for more than six decades, and we don’t intend
to change it. The three main elements include our commercial
model, state-of-the-art project management capabilities,
and financial risk management. A substantial amount of
Enbridge’s earnings come from fees paid by customers for
essential energy delivery services and we carefully limit
our exposure to commodity price, interest rate and foreign
exchange risks.
Our commercial model favours organic growth, as it provides
us with the highest risk-adjusted returns, with commercial
structures that minimize volume and capacity exposure with
long-term throughput or capacity commitments.
Our financial risk management strategy is focused on
mitigating our exposure to interest rate variability, foreign
exchange, and commodity prices through a comprehensive
hedging program; maintaining our credit ratings; diversifying
our funding sources; and providing liquidity through
substantial standby bank credit capacity that stood at
$17.6 billion at year end. Enterprise-wide, we secured over
$10 billion in funding in 2013 and bolstered our balance
sheet with $3.8 billion in equity capital raised. We have
access to multiple low-cost funding alternatives, including
our sponsored investments—Enbridge Income Fund and
Enbridge Energy Partners (EEP), as well as Midcoast
Energy Partners, a subsidiary of EEP formed in 2013.
We plan to use all our funding alternatives selectively
to minimize our funding costs.
Finally, our state-of-the-art project management approach
reduces residual capital cost and schedule risk by ensuring
the capital program is delivered on time and on budget.
This is all underpinned by a rigorous capital investment
review process to ensure each project meets or exceeds our
expected return targets.
Our guidance range for 2013 adjusted earnings was $1.74 to
$1.90 per common share and we delivered $1.78 per common
share. Our guidance range for 2014 adjusted earnings is
$1.84 to $2.04 per common share.
Significant Dividend Income
Our shareholders depend on Enbridge to deliver a predictable
and growing stream of dividends, and we do. We aim to
consistently pay out 60% to 70% of adjusted earnings as
dividends. Given the transparency of our $41 billion growth
capital program and resulting 10 to 12% adjusted EPS growth
through 2017, we expect the dividend growth to follow.
24 Enbridge Inc. 2013 Annual Report
ENB = 17% CAGR
S&P/TSX = 8% CAGR
03
04
05
06
07
08
09
10
11
12
13
Total Shareholder Return*
*Compound annual growth rate 2002 – 2013
In 2013, Enbridge’s total shareholder return (TSR) was 11%. Over the past 10 years, Enbridge’s TSR has
outperformed the S&P/TSX Composite Index on average by 9 percentage points per year.
Dividends per
common share
(Canadian dollars per share)
.
8
9
5 0
8
4 0
7
.
0
.
.
4
0
2
–
4
8
.
1
e
0
4
6 1
2
.
1
.
3
1
.
1
Adjusted earnings
per common share
(Canadian dollars per share)
8
7
.
1
2
6
.
1
6
4
.
1
2
3
.
1
8
1
.
1
09 10
11
12
13 14e
09 10
11
12
13 14e
Over the past 10 years, we’ve delivered average
In 2013, Enbridge delivered an 11% increase
annual dividend growth of approximately 13%.
in adjusted earnings over 2012, right at the
In December 2013, we announced an 11%
midpoint of the 10% to 12% expected through
dividend increase. This represents Enbridge’s
2017. This result brings our average annual
19th consecutive annual increase and reflects
adjusted EPS growth rate over the past five
our confidence in the Company achieving robust
years to 14%. We entered 2014 well positioned
earnings growth over our five-year planning
to deliver 10% to 12% average annual growth
horizon to 2017.
in adjusted earnings per share through 2017.
We’re also confident we can extend our industry-
leading growth rate well beyond 2017.
10% – 12%
anticipated average annual adjusted
EPS growth through 2017
$1 Billion
total common share dividends
declared in 2013
15th
16th
17th
18th
19th
$10Billion+
enterprise-wide funding secured
in 2013 to support our growth
consecutive annual dividend increase
announced in December 2013
Solid Investment 25
Letter to Shareholders
LTSLTS
The energy marketplace is
changing dramatically and
Enbridge is at the forefront
of that change.
Globally, the need for energy to enhance peoples’ quality of life continues
to increase, driven primarily by Asia. It’s undeniable that we’ll need all
forms of energy to meet global demand. While the rate of growth of
renewable energy outpaces all other sources, fossil fuels—and increasingly,
natural gas—remain a core part of our energy mix.
Continued from previous page
In North America, technical innovation
is driving robust supply growth. Only a
few years ago we were facing declining
energy supplies and increased imports.
Today, the continent is on the road to
energy independence. We’re experi-
encing significant growth in energy
production—in Alberta’s oil sands; in
Canadian and U.S. unconventional oil
and gas plays; and offshore in the Gulf
of Mexico.
In step with the production surge, the
continent’s energy transportation grid is
being transformed. In the past, energy
supply generally flowed from the coast
to inland markets. Today, growing inland
production needs to access coastal and
export markets. Enbridge is right in the
middle of this transformation.
The changing fundamentals in
North America are very positive for
Enbridge. Our assets are strategically
positioned to match growing and new
energy supplies to the markets where
they're needed.
That said, we’re cognizant of the
challenges posed by the magnitude
of potential opportunities. Safety,
reliability and respect for the environment
remain our highest priorities in
successfully delivering on the largest
growth plan in our Company’s history.
We continue to deliver strong
financial performance
Against this backdrop of change, our
strong financial performance remained
a constant in 2013. Adjusted earnings
rose approximately 16% over 2012 to
$1.4 billion, which equated to adjusted
earnings per share (EPS) of $1.78, or
11% growth.
This was a very good result relative to
our peers and we achieved it despite a
large amount of prefunding to support
the execution of our $36 billion growth
capital plan. We faced headwinds over
the course of the year that negatively
impacted our liquids pipelines business
including lower than anticipated
throughput on the Seaway Pipeline and
capacity limitations on our mainline
28 Enbridge Inc. 2013 Annual Report
related to timing of completion of
inspection and repair programs.
Tailwinds in other areas largely offset
those impacts, illustrating the strength
and diversity of our assets.
Over the past five years, we’ve
achieved an industry-leading,
compound average annual adjusted
EPS growth rate of 14%. Dividend
growth has tracked EPS growth
over that same five-year period.
We increased the dividend by 11%
effective March 2013—our nineteenth
consecutive annual dividend increase.
Our total shareholder return, including
dividends, was 11%, a very strong result
relative to other investments. Over
the past decade, we’ve delivered an
annualized total shareholder return
of more than 17%—well above the
broader market and our peer group.
There’s also a high degree of
transparency to our future growth.
In 2013 we secured another $6 billion
of new investment, which brought our
total portfolio of commercially secured
growth projects for the period
2013 – 2017 to more than $29 billion.
In early 2014, we added another
$7 billion to bring the total to $36 billion
and we have an additional $5 billion
in development. We’re confident this
inventory of projects will significantly
extend our industry-leading EPS growth
rate beyond 2017.
combination of three things: an industry-
leading growth rate; a reliable business
model; and a dependable and growing
stream of dividends. This approach has
delivered superior returns to our
shareholders over the long term,
regardless of what sectors are in favour,
and will remain the foundation for
future growth.
Here’s where the future growth
is coming from
Liquids Pipelines
The core of our Liquids Pipelines
strategy is to expand and extend
market access for our customers to
ensure good connectivity between
supply and key markets. Our projects
are meeting producers’ needs for
greater capacity and access to new
markets, along with helping to satisfy
refiners’ needs for secure, reliable
and cost-competitive supply.
Over the past year, we secured and
advanced numerous regional oil sands
projects with in-service dates through
2017. Of note were the Wood Buffalo
Extension project that will connect the
eleventh oil sands project to our system,
and our Norlite diluent pipeline that will
bring diluent to the oil sands. Our strong
regional positions in Alberta and in the
Bakken extend our mainline capability
upstream to connect growing supply
with the best markets.
Our management team remains
focused on maintaining our long-
standing value proposition—a unique
We also made good progress with
our market access initiatives, which
are expected to open new markets
Financial Highlights
Year ended December 31,
(millions of Canadian dollars, except per share amounts)
Earnings per common share
Adjusted earnings per common share
Dividends paid per common share
Common share dividends declared
Return on average shareholders’ equity
Debt to debt plus total equity1
2013
2012
2011
0.55
1.78
1.26
1,035
3.5%
58.2%
0.78
1.61
1.13
895
1.07
1.44
0.98
759
6.4%
60.2%
11.5%
64.8%
1
Total debt (including short-term borrowings) divided by the sum of total debt and total equity inclusive of
noncontrolling interests and redeemable noncontrolling interests.
“We’re intensely focused on solidifying
our competitive advantage—maximizing
value for our customers through the
highest standards for safe and reliable
operational performance and outstanding
project execution.”
for up to 1.7 million barrels per day.
These initiatives include Eastern Access,
Western Gulf Coast Access, and Light
Oil Market Access, which are already
secured and in execution.
In early March this year we announced
that we’ve received shipper support
for a near $7 billion investment in our
Canadian and U.S. mainline system—the
backbone of our crude oil transportation
system. The Line 3 Replacement (L3R)
Program is targeted to be in service in
the second half of 2017 and will provide
increased reliability to our customers.
In December 2013, following extensive
review, the federal Joint Review Panel
(JRP) recommended approval of the
Northern Gateway Project to the
Canadian federal government, subject
to 209 conditions. The JRP concluded
Northern Gateway is in the Canadian
public interest and that it can be built
and operated safely without significant
adverse effects. While regulatory
approval is an important element, it’s
just one step. We know more work
needs to be done and we are focused
on engaging Aboriginal groups and
other stakeholders to listen and address
concerns. The government is expected
to make a final decision by June 2014.
Gas Pipelines & Processing
In our Gas Pipelines & Processing
business, through Enbridge Energy
Partners, L.P. (EEP), we successfully
completed several organic growth
projects in 2013, including the Texas
Express natural gas liquids (NGL) system
joint venture and the Ajax cryogenic gas
processing plant in Texas.
In November 2013, Midcoast Energy
Partners, L.P. (MEP), a subsidiary of EEP,
completed an initial public offering,
raising US$355 million. MEP is serving
as EEP’s primary vehicle for owning
and growing EEP’s natural gas and
NGL midstream business in the United
States. MEP will provide EEP with
another source of funding and enhance
the strategic focus of our U.S. gas
gathering and processing operations.
Enbridge Gas Distribution
In January 2014, Enbridge Gas
Distribution (EGD) received approval
from the Ontario Energy Board to
upgrade the backbone of our natural
gas distribution system in the Greater
Toronto Area (GTA). The $700 million
GTA Project represents the first major
expansion of our natural gas
distribution system in 20 years,
over which time our total number of
customers has doubled to two million
customers. The GTA Project will
provide significant benefit to EGD
customers, allowing for continued
system reliability in delivering the
energy they count on and providing
more customers access to lower-cost
natural gas supply.
New growth platforms
We’re also making good progress
with our new growth platforms.
In 2013, we put into service three wind
farms in Quebec and acquired a 50%
interest in a 300-megawatt (MW) wind
project in Alberta. In January 2014, we
announced the 110-MW Keechi Wind
Project in Texas, bringing Enbridge’s
interests in renewable generating
capacity to more than 1,800 MW.
In 2013, we also commenced operation
of our first power transmission project,
the Montana-Alberta Tie-Line (MATL).
Liquids Pipelines
Average Deliveries (2013)
Canadian Mainline1
1,737
in thousands
of barrels/day
533
172
Regional Oil
Sands System2
Spearhead Pipeline
1
Canadian Mainline includes deliveries ex-Gretna,
Manitoba, which is made up of United States
and eastern Canada deliveries originating from
western Canada
2
Volumes are for the Athabasca mainline and the
Waupisoo Pipeline and exclude laterals on the
Regional Oil Sands System
Gas Distribution
Number of Active Customers (thousands)
2,065
Gas Pipelines, Processing
and Energy Services
Average Throughout Volume (2013)
Alliance Pipeline US
1,565
millions of
cubic feet
per day
1,494
1,412
Vector Pipeline
Enbridge Offshore Pipelines
Letter to Shareholders 29
Continued from previous page
“We’re committed to working collaboratively
with our stakeholders to incorporate their
input and build the best possible projects.”
Our success to date in competing
for new business brings with it the
challenge of managing a record slate of
growth projects. Our current portfolio
under management is comprised of
34 projects at $31 billion. The unique
skillset, rigorous approach and
discipline of our Major Projects team
give us confidence that we can deliver.
However, we remain vigilant in staying
on top of our resourcing needs—from
people to equipment to materials—to
make sure our organizational capacity
keeps pace with our workload.
The production, transportation and
use of energy has become a focal
point of public debate. Energy
infrastructure development—from
pipelines to renewables—is challenged
by intensified scrutiny and heightened
expectations from the public and
from regulators.
While most people understand the
economic arguments in favour of
infrastructure development, we’ve
learned that those benefits are no
longer enough to gain public support.
The public wants to know that our
industry—and those who regulate it—
are doing everything in their power to
protect communities and
the environment.
We’re committed to working
collaboratively with our stakeholders
to incorporate their input and build
the best possible projects. In 2013, we
appointed a Chief Sustainability Officer
who will focus on building constructive
relationships and ensuring sustainability
is reflected in our decisions. We’ve
created a new function responsible
for Enterprise Safety & Operational
Reliability, reporting to the CEO.
Our Operations and Integrity
We had an excellent year in our Energy
Services business and we expect it will
continue to significantly supplement
the earnings from our infrastructure
businesses. We also continue to
advance international opportunities
at a measured pace with a focus on
Colombia, Peru and Australia.
We’re mindful of the challenges
While we have confidence in the future
growth outlook, we are also mindful of
our responsibilities and the challenges.
Surging growth in crude oil and natural
gas is changing the competitive
landscape. While Enbridge has a strong
competitive position and solid customer
relationships, we’re not taking that for
granted. We’re intensely focused on
solidifying our position and growing
it—maximizing value for our customers
through a deep understanding of their
needs, timely and flexible solutions, the
highest standards for safe and reliable
operational performance, and strong
project execution.
Power Generated
by Renewable and
Alternative Energy
(Gigawatt/hour)
2
0
8
,
2
4
3
3
,
2
8
4
2
,
1
11
12
13
30 Enbridge Inc. 2013 Annual Report
Committee is the most important
body in our Company and brings
together leaders accountable for
operations, integrity and safety
across our organization.
We remain focused on three
key priorities
Our vision is to be the leading energy
delivery company in North America.
We’re driven by our purpose—the safe
and reliable delivery of the energy that
keeps North Americans warm, takes us
places, powers our industries, schools
and hospitals, fuels our economy, and
supports our quality of life. What we
do makes a positive difference in
people’s lives.
We’re guided by three key priorities:
safety and operational reliability;
executing our growth capital program;
and extending and diversifying
Enbridge’s growth beyond 2017.
Priority #1 –
Safety and Operational Reliability
Our Number One priority remains an
intense focus on safety and operational
reliability because it supports
everything we do and it reflects our
responsibility to our communities and
our customers.
We made good progress towards our
goals. Over the last three years, we’ve
been engaged in the most extensive
maintenance, integrity and inspection
program in the history of the North
American pipeline industry—one that
far exceeds regulatory requirements.
We’re also investing in leak detection
technologies and strengthening our
emergency response capacity.
The year was not without its challenges.
In June, as a result of ground
movement caused by once-in-a-century
groundwater levels, we experienced
a leak on Line 37, a 12-inch pipeline in
northern Alberta. Our team’s response
was exemplary with repairs and
remediation carried out safely under
some of the most trying conditions
we’ve ever experienced. Safety guided
every decision, including shutting down
five adjacent pipelines along the same
corridor until we could ensure their
safe operation.
To further improve transparency,
we published our first Operational
Reliability Review, which provides a
broad overview of our efforts to ensure
Enbridge’s operations are as safe as
possible for the public, the environment
and our employees and contractors.
We believe it’s essential to share the
actions we’ve taken as well as how
we measure up against our key
performance indicators.
We’ve strengthened safety leadership
throughout our Company and we’ve
placed oversight at the highest level
by creating a Safety & Reliability
Committee of the Board. Every single
employee at Enbridge is accountable
for safety, with their compensation
aligned to safety results. Our belief that
all incidents are preventable drives a
strong safety culture.
We see safety and operational reliability
as a necessary foundation for how
we do business and a key component
to realizing the benefits of our record
growth program.
Priority #2 –
Executing our Capital Program
Our second priority is to execute well
on our $41 billion enterprise-wide
growth program, which will drive our
industry-leading growth rate for the
next several years.
We’ve made excellent progress. In 2013,
17 projects came into service totaling
$5 billion, almost all on time and on
budget. One exception was the MATL
project, which was delayed due to
permitting issues, but is now operational.
We take a systematic approach to
managing capital cost and schedule risk.
Our execution capability is something
that our customers have come to value
and is a competitive advantage that helps
us win business.
We’re also focused even more on
earning the confidence of communities
and the public. We engage stakeholders
earlier and more often to understand
concerns and incorporate their input
into our projects.
An equally critical part of executing our
growth projects is raising the necessary
Executive Leadership Team
J. Richard Bird
Executive Vice President,
Chief Financial Officer &
Corporate Development
Glenn Beaumont
President,
Enbridge Gas Distribution
Janet A. Holder
Executive Vice President,
Western Access
Greg Harper
President,
Gas Pipelines and
Processing
D. Guy Jarvis
President,
Liquids Pipelines
Al Monaco
President & Chief
Executive Officer
Karen L. Radford
Executive Vice President,
People & Partners
David T. Robottom
Executive Vice President &
Chief Legal Officer
Stephen J. Wuori
Strategic Advisor,
Office of the President
and CEO
Leon A. Zupan
Chief Operating Officer,
Liquids Pipelines
Letter to Shareholders 31
“ Over the past five years, we’ve achieved an
industry-leading compound average annual
adjusted EPS growth rate of 14%. Over the past
decade, we’ve delivered an annualized total
shareholder return of more than 17%—well
above the broader market and our peer group.”
generation, electricity transmission,
international and energy services.
We’ve made some very good headway
in these areas, with significant invest-
ments in renewable power generation
over the past five years. While our
near-term focus remains on liquids
pipelines, we intend to continue to
bring these new platforms along at a
measured pace, in preparation for them
to play a bigger role in the future.
We have confidence in
the road ahead
In closing, we would like to acknowl-
edge the Enbridge team. 2013 was
another demanding year and we’re
extremely proud of the dedication and
commitment they’ve shown in support
of the safe operation of our systems and
our growth agenda.
The energy landscape is undergoing
dramatic change and Enbridge is
playing a critical role in safely and
reliably delivering energy to the best
markets. We’re excited about our future.
With great assets, a strong competitive
position and multiple opportunities for
growth, the outlook for our Company
has never been better.
Al Monaco
David A. Arledge
President & Chief Executive Officer
Chair, Board of Directors
March 7, 2014
capital funding. In 2013, we added
more than $10 billion to our funding
sources—one of the largest capital-
raising programs in North America.
Good execution also rests on making
sure we have the right human resources
to make it happen. The Enbridge team
has grown by nearly 30% over the last
two years. We’ve been able to attract
good talent, and being rated as one of
Canada’s top employers has helped in
that effort.
We put a lot of effort into developing
our people. Over the past 12 months, we
welcomed new leaders to our executive
leadership team, highlighting the
attention we pay to succession planning
and reinforcing the effectiveness of our
leadership development program in
ensuring we have talented people ready
to step into important roles.
Priority #3 –
Extend and Diversify Growth
Our third priority is to both extend and
diversify growth for the longer term.
While much of 2013’s growth was
driven by liquids pipelines projects,
we continue to grow our natural gas
businesses. We see significant
opportunity to build on our existing
footprint that extends from shale plays
in northeast British Columbia through
U.S. Midwest hubs, as well as extensive
gathering and processing assets
throughout Texas and Louisiana.
Additional growth will come from
new platforms that align with our
value proposition, including power
32 Enbridge Inc. 2013 Annual Report
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 and the operational risk management plan of
the Company, and monitors their implementation.
The Board approves all significant decisions that affect the Company,
and reviews its financial and operational results. The Board also oversees
identification of the Company’s principal risks on an annual basis, monitors
risk management programs, reviews succession planning and compensation
programs, and seeks assurance that internal control systems and management
information systems are in place and operating effectively.
Board of Directors
David A. Arledge
Chair of the Board, Enbridge Inc.,
Naples, Florida
James J. Blanchard
Senior Partner, DLA Piper U.S., LLP,
Beverly Hills, Michigan
J. Lorne Braithwaite
President & Chief Executive Officer,
Build Toronto,
Thornhill, Ontario
V. Maureen Kempston Darkes
Corporate Director,
Lauderdale-by-the-Sea, Florida
J. Herb England
Chairman & Chief Executive Officer,
Stahlman-England Irrigation Inc.,
Naples, Florida
Charles W. Fischer
Corporate Director,
Calgary, Alberta
David A. Leslie
Corporate Director,
Toronto, Ontario
Al Monaco
President & Chief Executive Officer,
Enbridge Inc.,
Calgary, Alberta
George K. Petty
Corporate Director,
San Luis Obispo, California
Charles E. Shultz
Chair & Chief Executive Officer,
Dauntless Energy Inc.,
Calgary, Alberta
Dan C. Tutcher
Corporate Director,
Houston, Texas
Catherine L. Williams
Corporate Director,
Calgary, Alberta
Corporate Governance 33
2013 Awards and
Recognition
By focusing on our core values of Integrity,
Safety and Respect, Enbridge has received many
awards and much recognition over the years from
independent third parties for our performance
in the areas of sustainability; environmental
performance; financial health; workplace health,
safety and fairness; community relations; and
public disclosure. Listed below are some of the
awards and recognition we received in 2013.
Sustainability
Global 100 Most Sustainable Corporations
in the World
The Global 100 Most Sustainable Corporations in the World,
which is an annual assessment initiated by Corporate
Knights magazine, highlights global corporations that have
been most proactive in managing environmental, social and
governance issues. Enbridge was named to the Global 100 in
2010, 2011, 2012, 2013 and again in January 2014.
Dow Jones Sustainability Indexes (DJSI)
DJSI named Enbridge to both its World and North
America index. The DJSI indexes track the performance
of large companies that lead the field in terms of
sustainability, financial results, community relations
and environmental stewardship.
Carbon Disclosure Project (CDP)
The CDP named Enbridge on its Global 500 List of the
top 500 companies in the area of GHG disclosure and
management. Enbridge ranked Number 16 among the 40
global companies included in the energy sector. The CDP,
which represents 767 institutional investors with more than
US$92 trillion in assets, is an independent not-for-profit
organization working to drive GHG reduction and sustainable
water use by businesses and cities.
RobecoSAM/KPMG Gold Class Sustainability Leader,
Pipeline Sector
RobecoSAM and KPMG recognized Enbridge as a “Gold
Class Sustainability Leader” (in the Pipeline sector) in their
Sustainability Yearbook 2013. RobecoSAM and KPMG
publish the yearbook to be used as a guide for investors on
which companies are doing the most to address the risks and
opportunities of sustainability.
Best 50 Corporate Citizens in Canada
Corporate Knights magazine recognized Enbridge as being
one of Canada’s Best 50 Corporate Citizens, the eleventh
year in a row the Company has been recognized. The ranking
is the longest running of its kind and is determined based
on a thorough analysis of contenders’ publicly disclosed
environmental, social and governance indicators.
Forbes 100 Most Trustworthy Companies
in America
Enbridge Energy Partners, L.P. was again recognized on
this Forbes Magazine list as a company that demonstrates
transparent and conservative accounting practices, solid
corporate governance and prudent management.
Top Employer
Canada’s Top 100 Employers
Canada’s Top 100 Employers listing is a national evaluation to
determine which employers lead their industries in offering
exceptional workplaces for their employees. This is the ninth
consecutive year Enbridge has been on the list and twelfth
since the list’s inception 14 years ago.
Alberta’s Top Employers
Alberta’s Top Employers is an annual competition that
recognizes Alberta employers that lead their industries in
offering exceptional places to work.
Houston’s Healthiest Employers
The Houston Business Journal ranked Enbridge sixth in its
Healthiest Employer survey for 2013. The survey gauges the
effectiveness of companies’ wellness programs.
Aboriginal Relations
Silver Level, Progressive Aboriginal Relations (PAR)
Certification (2012 – 2014), Canadian Council for
Aboriginal Business (CCAB)
The CCAB is a national business organization whose
members include Aboriginal businesses, Aboriginal
community-owned economic development corporations,
and companies operating in Canada. The CCAB’s PAR
certification program recognizes and supports continuous
improvement in Aboriginal relations.
Financial Reporting
Corporate Reporting Award, Chartered Professional
Accountants of Canada (CPA Canada)
The Corporate Reporting Awards, presented annually by
CPA Canada, recognize the best reporting practices in the
country. Enbridge received the 2013 Award of Excellence
for Corporate Reporting in the ‘Utilities/Pipelines and Real
Estate’ industry sector.
34 Enbridge Inc. 2013 Annual Report
Enbridge Inc.
Financial Report
Management’s Discussion and Analysis
Notes to the Consolidated Financial Statements
36
38
43
46
48
62
65
75
79
87
97
Overview
Performance Overview
Corporate Vision and Strategy
Industry Fundamentals
Growth Projects – Commercially Secured Projects
50
55
55
58
Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing and Energy Services
Sponsored Investments
Growth Projects – Other Projects Under Development
Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing and Energy Services
Sponsored Investments
Corporate
100 Liquidity and Capital Resources
106 Outstanding Share Data
107 Quarterly Financial Information
108
108
113
115
116
117
Related Party Transactions
Risk Management and Financial Instruments
Critical Accounting Estimates
Changes in Accounting Policies
Controls and Procedures
Non-GAAP Reconciliations
Consolidated Financial Statements
118 Management’s Report
119
121
Independent Auditor’s Report
Consolidated Statements of Earnings
122 Consolidated Statements of Comprehensive Income
126
126
133
133
135
138
1. General Business Description
2. Summary of Significant Accounting Policies
3. Changes in Accounting Policies
4. Revision of Prior Period Financial Statements
5. Segmented Information
6. Financial Statement Effects of Rate Regulation
140
7. Acquisitions and Dispositions
142
142
143
145
146
148
148
149
149
150
151
152
153
155
158
160
170
172
177
177
177
178
8. Accounts Receivable and Other
9. Inventory
10. Property, Plant and Equipment
11. Variable Interest Entity
12. Long-term Investments
13. Deferred Amounts and Other Assets
14. Intangible Assets
15. Goodwill
16. Accounts Payable and Other
17. Debt
18. Other Long-Term Liabilities
19. Noncontrolling Interests
20. Share Capital
21. Stock Option and Stock Unit Plans
22. Components of Accumulated Other
Comprehensive Loss
23. Risk Management and Financial Instruments
24. Income Taxes
25. Retirement and Postretirement Benefits
26. Other Income/(Expense)
27. Changes in Operating Assets and Liabilities
28. Related Party Transactions
29. Commitments and Contingencies
123 Consolidated Statements of Changes in Equity
180
30. Guarantees
124 Consolidated Statements of Cash Flows
125 Consolidated Statements of Financial Position
181 Glossary
182
184
Five-Year Consolidated Highlights
Investor Information
Management’s Discussion and Analysis
This Management’s Discussion and Analysis (MD&A) dated February 14, 2014 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, 2013, prepared in accordance with
accounting principles generally accepted in the United States of America (U.S. 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
In connection with the preparation of the Company’s first quarter consolidated financial statements,
an error was identified in the manner in which the Company historically recorded deferred regulatory
assets associated with the difference between depreciation expense calculated in accordance with U.S.
GAAP and negotiated depreciation rates recovered in transportation tolls for certain of its regulated
operations. The error was not material to any of the Company’s previously issued consolidated financial
statements; however, as discussed in Note 4, Revision of Prior Period Financial Statements, to the
consolidated financial statements as at December 31, 2013, prior year comparative financial statements
have been revised to correct the effect of this error. This non-cash revision did not impact cash flows
for any prior period. The discussion and analysis included herein is based on revised financial results for
the year ended December 31, 2013 or other comparative periods as indicated.
Overview
Enbridge, 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 significant and growing involvement in natural gas gathering, transmission and
midstream businesses and an increasing involvement in power transmission.
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 generator of energy, Enbridge has
interests in more than 1,800 megawatts (MW) of renewable and alternative energy
generating capacity and is expanding its interests in wind, solar and geothermal
facilities. Enbridge has approximately 10,000 employees and contractors,
primarily in Canada and the United States.
The Company’s activities are carried out through five business segments: Liquids
Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services;
Sponsored Investments; and Corporate, as discussed below.
Liquids Pipelines
Liquids Pipelines consists of common carrier and contract crude oil, natural
gas liquids (NGL) and refined products pipelines and terminals in Canada and
the United States, including Canadian Mainline, Regional Oil Sands System,
Southern Lights Pipeline, Seaway Pipeline, Spearhead Pipeline and Feeder
Pipelines and Other.
Gas Distribution
Gas Distribution consists of the Company’s natural gas utility operations, the
core of which is Enbridge Gas Distribution Inc. (EGD), which serves residential,
commercial and industrial 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.
1
8
6
5
,
7
5
1
0
0
8
,
6
4
Total Assets
(millions of Canadian dollars)
1
0
3
1
,
1
4
1
0
3
2
,
6
3
2
1
0
7
,
4
2
09
10
11
12
13
■ Liquid Pipelines
■ Gas Distribution
■ Gas Pipelines, Processing
and Energy Services
■ Sponsored Investments
■ Corporate
1 Financial information has been extracted
from financial statements prepared in
accordance with U.S. GAAP.
2 Financial information has been extracted
from financial statements prepared in
accordance with Canadian GAAP.
36 Enbridge Inc. 2013 Annual Report
Gas Pipelines, Processing and Energy Services
Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines,
gathering and processing facilities and the Company’s energy services businesses, along with
renewable energy and transmission facilities.
Investments in natural gas pipelines include the Company’s interests in the United States portion of
the Alliance System (Alliance Pipeline US), the Vector Pipeline (Vector) and transmission and gathering
pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in
Aux Sable, a natural gas fractionation and extraction business located near the terminus of the Alliance
System (Alliance). The energy services businesses undertake physical commodity marketing activity
and logistical services, refinery supply services and manage the Company’s volume commitments on
the Alliance, Vector and other pipeline systems.
Sponsored Investments
Sponsored Investments includes the Company’s 20.6% ownership interest in Enbridge Energy Partners,
L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project
through EEP and Enbridge Energy, Limited Partnership (EELP) and an overall 67.3% economic interest
in Enbridge Income Fund (the Fund), held both directly and indirectly through Enbridge Income Fund
Holdings Inc. (ENF). Enbridge, through its subsidiaries, 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
including the Lakehead Pipeline System (Lakehead System) which is the United States portion of
the Enbridge mainline system, and transports, gathers, processes and markets natural gas and NGL.
The primary operations of the Fund include renewable power generation, crude oil and liquids pipeline
and storage businesses in western Canada and a 50% interest in the Canadian portion of the Alliance
System (Alliance Pipeline Canada).
Corporate
Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development
activities, general corporate investments and financing costs not allocated to the business segments.
Management’s Discussion and Analysis 37
Performance Overview
(millions of Canadian dollars, except per share amounts)
Earnings attributable to common shareholders
Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing and Energy Services
Sponsored Investments
Corporate
Earnings/(loss) attributable to common shareholders
from continuing operations
Discontinued operations – Gas Pipelines,
Processing and Energy Services
Earnings/(loss) per common share
Diluted earnings/(loss) per common share
Adjusted earnings1
Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing and Energy Services
Sponsored Investments
Corporate
Adjusted earnings per common share1
Cash flow data
Cash provided by operating activities
Cash used in investing activities
Cash provided by financing activities
Dividends
Common share dividends declared
Dividends paid per common share
Revenues
Commodity sales
Gas distribution sales
Transportation and other services
Total assets
Total long-term liabilities
Three months ended
December 31,
Year ended
December 31,
2013
2012
2013
2012
2011
46
80
(325)
79
(151)
(271)
4
(267)
(0.33)
(0.32)
205
67
17
89
(16)
362
0.44
781
(3,277)
2,744
261
0.3150
6,939
710
644
8,293
57,568
28,277
130
127
32
72
(136)
225
(79)
146
0.19
0.18
177
63
42
68
(23)
327
0.42
502
(2,182)
1,725
227
0.2825
4,978
585
1,444
7,007
46,800
25,227
427
129
(68)
268
(314)
442
4
446
0.55
0.55
770
176
203
313
(28)
1,434
1.78
3,341
(9,431)
5,070
1,035
1.26
26,039
2,265
4,614
32,918
57,568
28,277
697
207
(377)
283
(129)
681
(79)
602
0.78
0.77
655
176
176
264
(30)
1,241
1.61
2,874
(6,204)
4,395
895
1.13
18,494
1,910
4,256
24,660
46,800
25,227
470
(88)
328
268
(171)
807
(6)
801
1.07
1.05
501
173
180
243
(16)
1,081
1.44
3,371
(5,079)
2,030
759
0.98
20,374
1,906
4,509
26,789
41,130
23,958
1
Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed
by generally accepted accounting principles. For more information on non-GAAP measures see page 43.
38 Enbridge Inc. 2013 Annual Report
Earnings Attributable to Common Shareholders
Earnings attributable to common shareholders were
$446 million ($0.55 per common share) for the year ended
December 31, 2013 compared with $602 million ($0.78 per
common share) for the year ended December 31, 2012 and
$801 million ($1.07 per common share) for the year ended
December 31, 2011. The Company has delivered significant
earnings growth from operations over the course of the last
three years, as discussed below in Performance Overview –
Adjusted Earnings; however, the positive impact of this
growth and the comparability of the Company’s earnings are
impacted by a number of unusual, non-recurring or non-
operating factors, the most significant of which is changes in
unrealized derivative fair value gains or losses. The Company
has a comprehensive long-term economic hedging program
to mitigate exposures to interest rate, foreign exchange and
commodity prices. The changes in unrealized mark-to-market
accounting impacts from this program create volatility in
short-term earnings but the Company believes over the long-
term it supports reliable cash flows and dividend growth.
Earnings Attributable to Common Shareholders
(millions of Canadian dollars)
2
5
5
5
,
1
2
1
2
3
,
1
2
0
0
2 7
5
1
6
2
5
4
6
2
6
5
5
1
0
3
9
1
1
0
8
1
2
0
6
1
6
4
4
04
05
06
07
08
09
10
11
12
13
Also impacting the comparability of earnings between fiscal
years were certain out-of-period adjustments recognized
in 2013, including a non-cash adjustment of $37 million
after-tax to defer revenues associated with make-up rights
earned under certain long-term take-or-pay contracts within
Regional Oil Sands System. Regional Oil Sands System also
had an out-of-period adjustment of $31 million after-tax related to the recovery of income taxes
under a long-term contract, partially offset by a related correction to deferred income tax expense.
In Gas Distribution, the Company recognized an out-of-year adjustment of $56 million after-tax
reflecting an increase to gas transportation costs which had incorrectly been deferred.
1 Financial information has been extracted from financial
statements prepared in accordance with U.S. GAAP.
2 Financial information has been extracted from financial
statements prepared in accordance with Canadian GAAP.
Other significant items impacting the comparability of earnings year-over-year were costs and related
insurance recoveries associated with the Line 6B crude oil release. Earnings for the years ended
December 31, 2013, 2012 and 2011 included EEP’s cost estimates of US$302 million ($44 million after-tax
attributable to Enbridge), US$55 million ($8 million after-tax attributable to Enbridge) and US$215 million
($33 million after-tax attributable to Enbridge), respectively. The aforementioned costs are before
insurance recoveries and excluding additional fines and penalties other than the fines and penalties
discussed under Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A
and 6B Crude Oil Releases – Line 6B Crude Oil Release. Insurance recoveries recorded by EEP for the
years ended December 31, 2013, 2012 and 2011 were US$42 million ($6 million after-tax attributable
to Enbridge), US$170 million ($24 million after-tax attributable to Enbridge) and US$335 million
($50 million after-tax attributable to Enbridge), respectively, related to the Line 6B crude oil release.
See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude
Oil Releases – Insurance Recoveries. Within Liquids Pipelines, 2013 earnings reflected remediation and
long-term stabilization costs of approximately $56 million after-tax and before insurance recoveries
related to the Line 37 crude oil release that occurred in June 2013. See Liquids Pipelines – Regional Oil
Sands System – Line 37 Crude Oil Release.
Fourth quarter earnings drivers were largely consistent with year-to-date trends and continued to
include changes in unrealized fair value derivative and foreign exchange gains and losses. Aside from
operating factors discussed in Performance Overview – Adjusted Earnings, factors unique to the fourth
quarter of 2013 included a further recognition of US$65 million ($9 million after-tax attributable to
Enbridge) of costs related to the Line 6B crude oil release and an additional $3 million after-tax accrual
related to Line 37 remediation activities.
Management’s Discussion and Analysis 39
Adjusted Earnings
A key tenet of the Company’s investor value proposition is “visible growth”, supported by an ongoing
focus on safe and reliable operations and a disciplined approach to investment and project execution.
The Company has consistently delivered on this proposition, growing adjusted earnings from $1.44 per
common share in 2011 to $1.61 per common share in 2012 and $1.78 per common share in 2013.
The upward trend in adjusted earnings over these years was predominantly attributable to strong
operating performance from the Company’s Liquids Pipelines assets and contributions from new
assets placed into service. The Canadian Mainline has performed favourably under the Competitive
Toll Settlement (CTS) which took effect mid-2011 and has benefitted from heightened throughput since
that time. Strong supply from western Canada and the ongoing effect of crude oil price differentials,
whereby demand for discounted crude by United States midwest refiners remained high, drove increased
throughput on Canadian Mainline in both 2013 and 2012. New Liquids Pipelines assets placed into service
in recent years included the Woodland and Wood Buffalo pipelines which, together with expanded
capacity on Seaway Crude Pipeline System (Seaway Pipeline), contributed to adjusted earnings growth in
2013. Renewable energy investments continued to be an important component of Enbridge’s strategy to
diversify and sustain longer-term earnings growth. Between 2011 and 2013 Enbridge placed into service
five wind farms and two solar farms, and commenced operations of its first power transmission project in
mid-2013. Adjusted earnings for the year ended December 31, 2013 also reflected contributions from the
Company’s recent entry into the Canadian natural gas midstream infrastructure space.
Enbridge’s sponsored vehicles, EEP and the Fund, also contributed to the year-over-year adjusted
earnings growth. The Fund benefitted from an expanded asset base following the acquisition of assets
from Enbridge (drop down transactions) in both 2011 and 2012, as well as completion of the Bakken
Expansion Project, a project undertaken jointly with EEP. In addition to expanding its North Dakota
regional infrastructure, EEP was also successful in completing several other organic growth projects,
including the Texas Express NGL System joint venture and the Ajax Cryogenic Processing Plant
(Ajax Plant). EEP’s Lakehead System benefitted from strong volumes in both 2012 and 2013, similar to
Canadian Mainline, while its natural gas and NGL businesses continued to experience lower volumes and
prices due to declining drilling activity in dry gas basins of the
United States as a result of a sustained low natural gas
commodity price environment.
Adjusted Earnings
(millions of Canadian dollars)
Other factors which contributed to changes in adjusted
earnings year-over-year included market factors impacting
the Company’s Energy Services businesses and its Aux Sable
fractionation plant, as well as the Company’s continued
activity in the capital markets through the issuance of
preference shares and debt to fund future growth projects.
After a decrease in adjusted earnings in 2012 compared with
2011 due to unfavourable market conditions, Energy Services
earnings increased in 2013 as changing market conditions
gave rise to a greater number of and more profitable margin
opportunities. Reflecting the opposite trend, Aux Sable
adjusted earnings increased in 2012 over 2011 due to new
assets being placed into service and higher fractionation
margins, but declined in 2013 on lower fractionation
margins and lower ethane processing volumes due to
ethane rejections.
With respect to the fourth quarter of 2013, many of these
same annual trends continued. The primary drivers of quarter-
over-quarter adjusted earnings growth were volume increases
on Canadian Mainline, contributions from new assets
placed into service in Regional Oil Sands System and higher
contributions from EEP’s liquids business due to a combination
of higher throughput and tolls. Although no full year effect,
40 Enbridge Inc. 2013 Annual Report
1
4
3
4
,
1
1
1
4
2
,
1
1
1
8
0
,
1
1
3
6
9
2
5
5
8
2
7
7
6
2
7
3
6
2
3
9
5
2
7
3
5
2
1
9
4
04
05
06
07
08
09
10
11
12
13
1 Financial information has been extracted from financial
statements prepared in accordance with U.S. GAAP.
2 Financial information has been extracted from financial
statements prepared in accordance with Canadian GAAP.
the fourth quarter of 2013 also included a favourable adjustment in Regional Oil Sands System related to
a reduction in third party revenue sharing with the founding shipper on the Athabasca pipeline. Partially
offsetting earnings growth in the fourth quarter of 2013 was a loss incurred by Energy Services due to
changing market conditions, which gave rise to losses on certain physical positions, in addition to losses
on financial contracts intended to hedge the value of committed physical transportation capacity but
which were ineffective in doing so in the last three months of the year.
Cash Flows
Cash provided by operating activities was $3,341 million for the year ended December 31, 2013, mainly
driven by strong operating performance from the Company’s core assets, particularly from Liquids
Pipelines, and the cash flow generation from growth projects placed into service in recent years.
In addition, during 2013, upon realization of a substantial gain on the disposition of a portion of its
investment in Enbridge shares, Noverco paid Enbridge a one-time dividend of $248 million. Partially
offsetting these cash inflows were changes in operating assets and liabilities which fluctuate in the normal
course due to various factors impacting the timing of cash receipts and payments.
In 2013, the Company was active in the capital markets with the issuance of $1,428 million in preference
shares, common shares of approximately $628 million and $2,845 million in medium-term notes and also
significantly bolstered its liquidity through the securement of additional credit facilities. The proceeds
of the capital market transactions, together with additional borrowings from its credit facilities, cash
generated from operations and cash on hand were more than sufficient to finance the Company’s nearly
$10 billion net investment in expansion initiatives during 2013, and are expected to provide financing
flexibility for the Company’s growth opportunities in 2014.
Dividends
Dividends per Common Share
The Company has paid common share dividends since it
became a publicly traded company in 1953. In December
2013, the Company announced an 11% increase in its quarterly
dividend to $0.35 per common share, or $1.40 annualized,
effective March 1, 2014. Assuming this currently announced
quarterly dividend is annualized for 2014, the Company has
generated compound annual average growth of 11.8% since
2004. The Company continues to target a dividend payout
of approximately 60% to 70% of adjusted earnings over
the longer term. In 2013, the dividend payout was 71%
(2012 – 70%; 2011 – 67%) of adjusted earnings per share.
Revenues
5
8
0
.
4
7
.
6 0
6
0
.
2
6
0
.
8
5
.
0
2
5
6 0
.
4
0
.
0
4
.
1
6
2
.
1
3
1
.
1
8
9
0
.
The Company generates revenue from three primary sources:
commodity sales, gas distribution sales and transportation
and other services. Commodity sales of $26,039 million for
the year ended December 31, 2013 (2012 – $18,494 million;
2011 – $20,374 million) were earned through the Company’s
energy services operations. Revenues from these operations depend on activity levels, which vary from
year to year depending on market conditions and commodity prices. Commodity prices do not directly
impact earnings since these earnings reflect a margin or percentage of revenue which depends more on
differences in commodity prices between locations and points in time than on the absolute level of prices.
09
06
04
08
05
07
10
11
12
13
14e
Gas distribution sales are primarily earned by EGD and are recognized in a manner consistent with
the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas
distribution businesses are driven by volumes delivered, which vary with weather and customer base,
as well as regulator-approved rates. The cost of natural gas is charged to customers through rates but
does not ultimately impact earnings due to the pass through nature of these costs.
Management’s Discussion and Analysis 41
Transportation and other services revenues are earned
from the Company’s crude oil and natural gas pipeline
transportation businesses and also includes power production
revenues from the Company’s portfolio of renewable and
power generation assets. For the Company’s transportation
assets operating under market-based arrangements, revenues
are driven by volumes transported and tolls. For rate-
regulated assets, revenues are charged in accordance with
tolls established by the regulator and, in most cost-of-service
based arrangements, is reflective of the Company’s cost to
provide the service plus a regulator-approved rate of return.
Higher transportation and other services revenues reflected
increased throughput on the Company’s core liquids pipeline
assets as well as new assets placed into service during 2013.
The Company’s revenues also included changes in unrealized
derivative fair value gains or losses related to foreign exchange
and commodity price contracts used to manage exposures
from movements in foreign exchange rates and commodity
prices. The unrealized mark-to-market accounting creates
volatility and impacts the comparability of revenue in the
short-term, but the Company believes over the long-term, the
economic hedging program supports reliable cash flows and
dividend growth.
Forward-Looking Information
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 and affiliates, 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/(loss) or adjusted earnings/(loss);
expected earnings/(loss) or adjusted earnings/(loss) per share;
expected future cash flows; expected costs related to projects
under construction; expected in-service dates for projects under
construction; expected capital expenditures; estimated future
dividends; and expected costs related to leak remediation and
potential insurance recoveries.
Although Enbridge believes 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, NGL and
renewable energy; prices of crude oil, natural gas, NGL and
renewable energy; expected exchange rates; inflation; interest
rates; the availability and price of labour and pipeline
construction materials; operational reliability; customer and
regulatory 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, NGL and renewable
energy, and the prices of these commodities, are material to and
underlie 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, and 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/(loss) or adjusted earnings/(loss) 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 date
and expected capital expenditures include: the availability and
price of labour and 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, changes in tax law and tax rate
increases, 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.
42 Enbridge Inc. 2013 Annual Report
Non-GAAP Measures
This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss
attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors on
both a consolidated and segmented basis. These factors, referred to as adjusting items, are reconciled
and discussed in the financial results sections for the affected business segments. Adjusting items
referred to as changes in unrealized derivative fair value gains or loss are presented net of amounts
realized on the settlement of derivative contracts during the applicable period. Management believes
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, including setting the Company’s dividend payout target, and to assess performance of
the Company. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not
measures that have a standardized meaning prescribed by U.S. 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 for a reconciliation of the GAAP and non-GAAP measures.
Corporate Vision and Strategy
Vision
Enbridge’s vision is to be the leading energy delivery company in North America. The Company
transports, distributes and generates energy and its primary purpose is to deliver the energy North
Americans need in the safest, most reliable and most efficient way possible.
Among its peers, Enbridge strives to be the leader, which means not only leadership in value creation
for shareholders but also leadership with respect to safety and operational reliability, environmental
stewardship, customer service, employee satisfaction and community investment. Driven by this
vision, the Company delivers value for shareholders from a proven and unique value proposition which
combines visible growth, a reliable business model and a dependable and growing income stream.
Strategy
The Company’s initiatives centre around eight areas of strategic emphasis in four key focus areas.
These strategies are reviewed at least annually with direction from its Board of Directors.
Commitment to Safety and Operational Reliability
Execute
Secure the Longer-Term Future
• Focus on project management
• Preserve financing strength and flexibility
• Strengthen core businesses
• Develop new platforms for growth and diversification
Maintain the Foundation
• Uphold Enbridge values
• Maintain the Company’s social license to operate
• Retain, attract and develop highly capable people
Commitment to Safety and Operational Reliability
The commitment to safety and operational reliability means achieving industry leadership in process,
public and personal safety, operational reliability and integrity of the Company’s pipelines and facilities
and the protection of the environment. This is the Company’s number one priority and sets the
foundation for the strategic plan.
Under the umbrella of the Company’s Operational Risk Management (ORM) Plan introduced in 2011, the
Company has undertaken extensive maintenance, integrity and inspection programs across its pipeline
systems. The ORM Plan has also bolstered incident response capabilities, employee and public safety
and improved communications with landowners and first responders. In 2013, Enbridge established
Management’s Discussion and Analysis 43
the role of Senior Vice President, Enterprise Safety &
Operational Reliability, a new centralized role accountable
for defining and executing on an enterprise-wide vision,
culture and set of integrated strategies and policies that
support the Company’s ORM objectives.
Execute
Focus on Project Management
Enbridge’s objective is to safely deliver projects on time and
on budget and at the lowest practical cost while maintaining
the highest standards for safety, quality, customer
satisfaction, environmental and regulatory compliance. With
an approximate $29 billion portfolio of commercially secured
projects, successful project execution is critical to achieving
the Company’s long-term growth plan. Enbridge, through
its Major Projects group (Major Projects), continues to build
upon its rigorous project management processes including:
employee and contractor safety; long-term supply chain
agreements; quality design, materials and construction;
extensive regulatory and public consultation; robust cost,
schedule and risk controls; and efficient project transition to
operating units.
Preserve Financial Strength and Flexibility
The maintenance of adequate financial strength and
flexibility is crucial to Enbridge’s growth strategy. Enbridge’s
financial strategies are designed to ensure the Company has
sufficient financial flexibility to meet its capital requirements.
To support this objective, the Company develops financing
plans and strategies to maintain or improve its credit ratings,
diversify its funding sources and maintain substantial standby
bank credit capacity and access to capital markets in both
Canada and the United States.
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 assessed using strict operating, strategic and
financial benchmarks with the objective of ensuring the
enduring financial strength and stability of the Company.
Secure the Longer-Term Future
Strengthen Core Businesses
Within Liquids Pipelines, strategies are focused on providing
access to new markets for growing production from western
Canada and the Bakken, optimizing and expanding mainline
operations and expanding regional oil sands infrastructure.
Through Enbridge’s market access initiatives, shippers will
be provided greater connectivity to markets in Ontario,
Quebec, the Gulf Coast and upper-midwest helping secure
the best pricing for their products depending on crude
type. Significant market access programs include Gulf
Coast Access, Eastern Access and Light Oil Market Access.
In 2013, the Company made significant progress on each
of these market initiatives including the completion of
the Seaway Pipeline expansion to increase transportation
capacity to the Gulf Coast to up to 400,000 barrels per
day (bpd) depending on crude oil slate. To facilitate these
downstream growth projects and continued growth in
base volumes, a number of supporting mainline expansions
are being undertaken. In addition, the Company is also
focused on maximizing existing operating capacity through
optimization initiatives such as improved scheduling and
tankage management.
The objective of Regional Oil Sands System expansion is
to optimize existing asset corridors to secure incremental
supply expected from the western Canadian oil sands over
the next decade. The Company currently has approximately
$6 billion of regional infrastructure under development,
including the expansion and twinning of the Athabasca
pipeline; the extension of the Wood Buffalo Pipeline (Wood
Buffalo Extension); and the Norlite Pipeline System (Norlite),
which will transport diluent from the Edmonton region to oil
sands producers.
The Company’s natural gas strategies include leveraging the
competitive advantages of its existing assets and expanding
its footprint in emerging areas. Combined, Alliance and
the Aux Sable NGL fractionation plant are well positioned
to provide liquids-rich gas transportation and processing
to developing regions in northeast British Columbia,
western Alberta and the Bakken. Alliance is also evaluating
opportunities to expand service offerings in those areas.
Enbridge is also partnering with producers to develop
needed Canadian midstream infrastructure. In addition to
these onshore strategies, the Company continues to pursue
crude oil and natural gas gathering expansion opportunities
for ultra-deep projects in the Gulf of Mexico, building on
momentum achieved with the Walker Ridge Gas Gathering
System (WRGGS), Big Foot Oil Pipeline (Big Foot Pipeline)
and Heidelberg Lateral Pipeline (Heidelberg) projects
currently under construction.
Develop New Platforms for Growth and Diversification
The development of new platforms to diversify and
sustain long-term growth is an important strategic priority.
The Company is currently focusing its development efforts
towards securing investment in additional renewable energy
and power transmission facilities, as well as developing
opportunities in gas-fired power generation, liquefied
natural gas development and select energy delivery assets
outside North America. The Company also invests in early
stage energy technologies that complement the Company’s
core businesses.
44 Enbridge Inc. 2013 Annual Report
Enbridge has advanced its renewable power strategy
considerably over the past several years and has interests
in a renewable energy portfolio with a generation capacity
of more than 1,800 MW. Since the beginning of 2013,
the Company has been successful in securing several
projects, including the Keechi Wind Project (Keechi) in
Texas, Blackspring Ridge Wind Project (Blackspring Ridge)
in Alberta and the Saint Robert Bellarmin Wind Project
in Quebec, which collectively will have the capacity to
generate an approximate 500 MW of renewable energy.
Maintain the Foundation
Uphold Enbridge Values
Enbridge adheres to a strong set of core values that govern
how it conducts its business and pursues strategic priorities,
as articulated in its value statement “Enbridge employees
demonstrate integrity, safety and respect in support of our
communities, the environment and each other”. Employees
uphold these values in their interactions with each other,
with customers, suppliers, landowners, community members
and all others with whom the Company deals, and ensure
the Company’s business decisions are consistent with these
values. Employees and contractors are required, on an
annual basis, to certify their compliance with the Company’s
Statement on Business Conduct policy which sets out its
requirements and expectations regarding conduct.
Maintain the Company’s Social License to Operate
Earning and maintaining “social license”—the approval and
acceptance of the communities in which the Company
operates or is proposing new projects—is critical to
Enbridge’s ability to execute on its growth plans. To earn the
public’s trust, and to protect and reinforce the Company’s
reputation with its stakeholders, Enbridge is committed
to integrating Corporate Social Responsibility (CSR) into
every aspect of its business. The Company defines CSR as
conducting business in an ethical and responsible manner,
protecting the environment and the safety of people,
providing economic and other benefits to the communities
in which the Company operates, supporting universal human
rights and employing a variety of policies, programs and
practices to manage corporate governance and ensure
fair, full and timely disclosure. The Company provides its
stakeholders with open, transparent disclosure of its CSR
performance and prepares its annual CSR Report using
the Global Reporting Initiative G3.1 sustainability reporting
guidelines, which serve as a generally accepted framework
for reporting on an organization’s economic, environmental
and social performance.
One of Enbridge’s CSR environmental objectives is its Neutral
Footprint plan, which includes initiatives to counteract the
environmental impact of all Enbridge’s pipeline expansion
projects. Neutral Footprint initiatives include:
• planting a tree for every tree the Company removes to
build new pipelines and facilities;
• conserving an acre of natural habitat for every acre the
Company permanently alters; and
• generating a kilowatt hour of renewable energy for every
kilowatt hour the Company’s expansions consume.
The 2013 CSR Report can be found at csr.enbridge.com
and progress updates on the Company’s Neutral Footprint
initiatives can be found at enbridge.com/neutralfootprint and
in the annual CSR Report. None of the information contained
on, or connected to, the Enbridge website is incorporated
or otherwise part of this MD&A.
To complement community investments in its Canadian
and United States operating areas, Enbridge created the
energy4everyone foundation (the Foundation) in 2009. The
Foundation aims to leverage the expertise and resources of
the Canadian energy industry to affect significant positive
change through the delivery and deployment of affordable,
reliable and sustainable energy services and technologies
in communities in need around the world. To date, the
Foundation has completed projects in Costa Rica, Ghana,
Nicaragua, Peru and Tanzania.
Retain, Attract and Develop Highly Capable People
Investing in the attraction, retention and development of
employees and future leaders is fundamental to executing
Enbridge’s growth strategy and creating sustainability
for future success. People-related focus areas include
broadening recruiting efforts beyond traditional industry
and geographical reaches, ensuring succession capability
through accelerated leadership development programs
and building change management capabilities throughout
the enterprise to ensure projects and initiatives achieve the
intended benefits. Furthermore, Enbridge strives to maintain
industry competitive compensation and retention programs
that provide both short-term and long-term incentives.
Management’s Discussion and Analysis 45
Industry Fundamentals
Supply and Demand for Liquids
Enbridge has an established and successful history of being the largest transporter of crude oil to
the United States, the world’s largest market. While United States demand for Canadian crude oil
production will support the use of Enbridge infrastructure for the foreseeable future, North American
and global crude oil supply and demand fundamentals are shifting and Enbridge has a crucial role to
play in this transition by developing long-term transportation options that enable the efficient flow of
crude oil from supply regions to end-user markets.
Global energy consumption is expected to continue to grow, with the growth in crude oil demand
primarily driven by non-Organisation for Economic Co-operation and Development (OECD) regions,
such as Asia and the Middle East, with China expected to be the largest single growth market. In OECD
countries, including Canada, the United States and western European nations, conservation, limited
population growth and a shift to alternative energy will reduce crude oil demand over the long-term.
Accordingly, there is a strategic opportunity for North American producers to meet growing global
demand outside North America.
In terms of supply, North American crude oil production growth is expected to outpace growth from
Organization of the Petroleum Exporting Countries over the 2014 to 2030 time period. The primary
driver of the production growth stems from the expansion of shale oil and oil sands production.
The emergence of shale oil plays, including the Bakken in North Dakota, have altered the United States
crude oil production landscape and is expected to double total United States crude oil production
over the next 20 years, although the rate of growth could be tempered by increased environmental
regulation in future years. In Canada, the Western Canadian Sedimentary Basin (WCSB) continues to
be viewed as one of the world’s largest and most secure supply sources of crude oil. Investment in the
WCSB continues to be strong and several new projects and expansions of existing oil sands production
facilities have been added or accelerated due to supportive oil prices and increased foreign investment.
The combination of relatively flat domestic demand, growing supply and
shortages of pipeline infrastructure, has led to volatile crude oil price differentials
in North America. In recent years, an over-supply to land-locked markets has
resulted in a divergence between West Texas Intermediate (WTI) and world
pricing, resulting in lower netbacks for North American producers than could
otherwise be achieved if selling into global markets. The impact of price
differentials has been even more pronounced for western Canadian producers as
insufficient pipeline infrastructure has resulted in a further discounting of Alberta
crude against WTI. To address these market challenges, crude oil transportation
infrastructure will have to undergo a major change in configuration. While
producers have sought alternative means of transportation, such as rail, to access
higher netback markets in the short-term, pipelines will continue to be the most
cost effective means of transportation for the longer-term.
Enbridge’s role in helping to address the evolving supply and demand
fundamentals, and improving netbacks for producers and supply costs to
refiners, is to provide expanded pipeline capacity and sustainable connectivity to
alternative markets. In 2013, Enbridge added to its growing slate of commercially
secured projects within Liquids Pipelines to provide market access solutions
and additional regional oil sands infrastructure. The Company’s market access
initiatives include the Gulf Coast Access Program, Eastern Access Program and
Light Oil Market Access Program, all of which provide producers greater access
to North American refinery markets.
Despite these initiatives, and those of competitors, heavy oil prices from western
Canada will likely continue to lag behind world prices, heightening the need for
access to growing Asian markets. Details of the Company’s Northern Gateway
Project (Northern Gateway), a proposed pipeline system from Alberta to the coast
46 Enbridge Inc. 2013 Annual Report
Canadian Crude
Oil Production
(thousands of barrels per day)
0
9
6
,
3
0
1
5
,
3
0
3
2
,
3
0
0
0
,
3
11
12
13
14e
■ Oil Sands
■ Other
Sources: National Energy Board,
Canadian Association of Petroleum
Producers
of British Columbia, and associated marine terminal, along with the Company’s other projects under
development, can be found in Growth Projects – Commercially Secured Projects and Growth Projects –
Other Projects Under Development.
Supply and Demand for Natural Gas and NGL
The North American natural gas market is transitioning to a better balance as gas production growth
has slowed after several years of robust increases. As a result, natural gas prices have firmed modestly
over the past year. Natural gas supply remains ample and could respond quickly to rising demand,
thereby limiting further price advances. As the economy recovers and natural gas prices remain
relatively low, gas demand in the United States is expected to increase, primarily from the power
generation and industrial sectors. Within Canada, natural gas demand growth is expected to be driven
primarily by continued oil sands development.
The Northeast has become the primary source of United States natural gas supply
growth as regional gas production has exceeded demand. The significant resource
base within the Marcellus and Utica shale gas plays in the northeastern United
States has fundamentally altered the flow pattern of gas in North America and is
displacing Gulf Coast and WCSB supplies. While this presents opportunities for
new regional infrastructure as natural gas producers seek alternative markets, it
may also present challenges for existing infrastructure serving these supply areas.
In a weak natural gas price environment, producers have been shifting from
dry gas drilling to developing rich gas reservoirs to take advantage of the
relatively higher value of NGL inherent in the gas stream. NGL that can be
extracted from liquids-rich gas streams include ethane, propane, butane and
natural gasoline, which are used in a variety of industrial, commercial and other
applications. Recently, extraction margins have been pressured by robust supply
and corresponding weaker prices for ethane. This has led to significant ethane
rejection and projects to export increased volumes of propane. The growing NGL
supply is also straining the existing infrastructure capacity and causing regional
price differentials. With the majority of petrochemical facilities located in the Gulf
Coast, additional infrastructure will be required to expand processing facilities
and take-away pipeline capacity.
Similar to crude oil, significant differentials exist between North American and
world gas prices. While North American gas prices continue to be relatively
low, the price for liquefied natural gas (LNG) in global markets is more closely
linked to higher crude oil prices, providing an opportunity to capture more
favourable netbacks on LNG exports from North America, if that pricing linkage
is maintained. Based on the prospect for higher global LNG demand, the large
resource base in western Canada and changing North American natural gas flow
patterns discussed above, there is an increasing probability that one or more
projects to export LNG off the west Coast of Canada will proceed.
North American
Natural Gas Production
(billions of cubic feet per day)
7
7
9
7
9
7
9
7
11
12
13
14e
■ Shale
■ Other
Sources: Energy Information
Administration (United States),
National Energy Board (Canada),
Enbridge research
In response to these evolving natural gas and NGL fundamentals, Enbridge
believes it is well positioned to provide value-added solutions to producers. Alliance is uniquely
configured to transport liquids-rich gas and is currently evaluating service offerings to best meet
the needs of producers. The focus on liquids-rich gas development also creates opportunities for
Aux Sable, an extraction and fractionation facility near Chicago, Illinois near the terminus of Alliance.
Enbridge is also responding to the need for regional infrastructure with additional investment in
Canadian and United States midstream processing and pipeline facilities.
Supply and Demand for Renewable Energy
North American economic growth over the longer term is expected to drive growing electricity
demand. Given the accelerated pace of retirement of aging coal-fired generation plants in
North America after 2015 due to impending emission regulations, significant new generation capacity
is expected to be required. While coal and nuclear facilities will continue to be a core component of
Management’s Discussion and Analysis 47
power generation in North America, gas fired and renewable
energy facilities, including biomass, hydro, solar and wind,
are expected to be the preferred sources to replace
coal-fired generation, due to their lower carbon intensities.
The United States National Renewable Energy Laboratory
reports that North America has significant wind and solar
resources, with wind alone having the potential to provide
capacity for over 10,000 gigawatts of power generation.
Solar resources in southwestern states such as Arizona,
California and Nevada are considered to be the best in the
world for large-scale solar plants. According to Environment
Canada, Canada also has an abundance of wind and solar
resources with particularly strong wind resources in the
northeastern regions.
Expanding renewable energy infrastructure in North
America is not without challenges. Growing renewable
generation capacity is expected to necessitate substantial
capital investment to upgrade existing transmission systems
or, in many cases, build new transmission lines, as these
high quality wind and solar resources are often found in
regions which are not in close proximity to high demand
markets. Furthermore, the profitability of renewable
energy projects, to date, has in part been supported by
certain tax and government incentives. In the near-term,
uncertainty over the continuing availability of tax or other
government incentives and the ability to secure long-term
power purchase agreements (PPA) through government
or investor-owned power authorities may hinder the pace
of future new renewable capacity development. However,
continued improvement in technology and manufacturing
capacity in the past few years has reduced capital costs
associated with renewable energy infrastructure and has
also improved yield factors of power generation assets.
These positive developments are expected to render
renewable energy more competitive and support ongoing
investment over the long-term.
Enbridge continues to be active in renewable asset
development and secured the development of three
additional wind farms in 2013; and now has interests in more
than 1,800 MW of renewable energy generation capacity.
In 2013, Enbridge also completed its first power transmission
line, the Montana-Alberta Tie-Line (MATL). The Company
will continue to seek new opportunities to grow its portfolio
of renewable power generation and power transmission
businesses that meet its investment criteria.
Growth Projects –
Commercially Secured
Projects
In 2013, the Company was successful in placing
approximately $5 billion of growth projects into service
across several business units. Enbridge also added to its slate
of commercially secured growth projects which now totals
approximately $29 billion.
The Company’s growth initiatives are anchored by three
major market access initiatives, supported by several
mainline system expansion projects which are designed to
ensure that there is sufficient capacity to feed these new
extensions. The three major market access initiatives are:
• Gulf Coast Access Program;
• Eastern Access Program; and
• Light Oil Market Access Program.
The $5.8 billion Gulf Coast Access Program includes the
Seaway Pipeline, the Flanagan South Pipeline Project and
elements of the Canadian Mainline and Lakehead System
Mainline expansions and will increase access to refinery
markets in the Gulf Coast. The $2.7 billion Eastern Access
Program is expected to allow for greater access for crude
oil into Chicago, further east into Toledo and ultimately into
Ontario and Quebec. The Eastern Access Program includes
the Company’s Toledo pipeline expansion, Line 9 reversal,
the existing Spearhead North pipeline expansion, Line 6B
replacement and Line 5 expansion. Finally, the $6.2 billion
Light Oil Market Access Program brings together a group
of projects to support the increasing supply of light oil from
Canada and the Bakken and also supplement the Eastern
Access Program through the upsize of the Line 9B and Line
6B capacity expansion. The Light Oil Market Access Program
also includes the Southern Access Extension, the Sandpiper
Project (Sandpiper), Canadian Mainline System Terminal
Flexibility and Connectivity and twinning of the Spearhead
North pipeline and Line 61 expansion included within the
Lakehead System Mainline Expansion. The Company also
has approximately $6 billion in regional infrastructure
projects under development, solidifying its position as the
largest pipeline operator in the oil sands region of Alberta.
In keeping with the Company’s strategic priority to develop
new platforms to diversify and sustain long-term growth,
Enbridge continued to expand its renewable energy
generation capacity in 2013. The Company secured wind
power generation projects with a generation capacity of
approximately 500 MW and also placed the 300-MW MATL,
Enbridge’s first power transmission project, into service.
The following table summarizes the current status of the
Company’s commercially secured projects, organized by
business segment.
48 Enbridge Inc. 2013 Annual Report
Estimated1
Capital Cost1
Expenditures2
to Date2
Expected
In-Service Date
Status
(Canadian dollars, unless stated otherwise)
Liquids Pipelines
1
Seaway Crude Pipeline System
Acquisition/Reversal/Expansion
US$1.3 billion
US$1.2 billion
2012 – 2013
Complete
Twinning/Extension
Suncor Bitumen Blend
Athabasca Pipeline Capacity Expansion
US$1.1 billion
US$0.6 billion
$0.2 billion
$0.4 billion
$0.2 billion
$0.4 billion
Eastern Access3
Toledo Expansion
US$0.2 billion
US$0.2 billion
Line 9 Reversal and Expansion
$0.4 billion
$0.2 billion
2014
2013
2013
(in phases)
2013
2013 – 2014
(in phases)
Under construction
Complete
Complete
Complete
Pre-construction
Eddystone Rail Project
US$0.1 billion
No significant
expenditures to date
2014
Under construction
Norealis Pipeline
$0.5 billion
$0.4 billion
2014
Substantially
complete
Flanagan South Pipeline Project
US$2.8 billion
US$1.6 billion
2014
Under construction
Canadian Mainline Expansion
$0.6 billion
$0.1 billion
Surmont Phase 2 Expansion
$0.3 billion
$0.1 billion
Athabasca Pipeline Twinning
Edmonton to Hardisty Expansion
Southern Access Extension
AOC Hangingstone Lateral
Sunday Creek Terminal Expansion
Canadian Mainline System Terminal
Flexibility and Connectivity
Woodland Pipeline Extension
JACOS Hangingstone Project
Wood Buffalo Extension
Norlite Pipeline System
$1.2 billion
$1.8 billion
$0.6 billion
$0.2 billion
US$0.8 billion
US$0.1 billion
$0.1 billion
No significant
expenditures to date
$0.2 billion
$0.6 billion
$0.6 billion
$0.1 billion
$1.6 billion
$1.4 billion
$0.1 billion
$0.2 billion
$0.1 billion
No significant
expenditures to date
No significant
expenditures to date
No significant
expenditures to date
2014 – 2015
(in phases)
2014 – 2015
(in phases)
Under construction
Under construction
2015
2015
2015
2015
Under construction
Pre-construction
Pre-construction
Pre-construction
2015
Pre-construction
2013 – 2015
(in phases)
Under construction
2015
2016
Pre-construction
Pre-construction
2017
Pre-construction
2017
Pre-construction
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Gas Distribution
20
Greater Toronto Area Project
$0.7 billion
No significant
expenditures to date
2015
Pre-construction
Gas Pipelines, Processing and Energy Services
21
Massif du Sud Wind Project
$0.2 billion
Saint Robert Bellarmin Wind Project
Lac Alfred Wind Project
$0.1 billion
$0.3 billion
$0.2 billion
$0.1 billion
$0.3 billion
Montana-Alberta Tie-Line
US$0.4 billion
US$0.3 billion
Cabin Gas Plant
Pipestone and Sexsmith Project
$0.8 billion
$0.3 billion
$0.8 billion
To be determined
$0.2 billion
22
23
24
25
26
27
28
29
30
31
32
33
Tioga Lateral Pipeline
US$0.1 billion
US$0.1 billion
Venice Condensate Stabilization Facility
US$0.1 billion
US$0.1 billion
Blackspring Ridge Wind Project
$0.3 billion
$0.2 billion
Walker Ridge Gas Gathering System
US$0.4 billion
US$0.2 billion
Big Foot Oil Pipeline
Keechi Wind Project
Heidelberg Lateral Pipeline
US$0.1 billion
US$0.2 billion
US$0.1 billion
US$0.2 billion
No significant
expenditures to date
No significant
expenditures to date
2013
2013
2013
(in phases)
2013
Complete
Complete
Complete
Complete
Deferred
2012 – 2014
(in phases)
2013
2013
2014
2014 – 2015
(in phases)
Under construction
Complete
Complete
Under construction
Under construction
2015
2015
Under construction
Under construction
2016
Pre-construction
Management’s Discussion and Analysis 49
Estimated1
Capital Cost1
Expenditures2
to Date2
Expected
In-Service Date
(Canadian dollars, unless stated otherwise)
Sponsored Investments
34
EEP – Bakken Expansion Program
US$0.3 billion
US$0.3 billion
35
36
37
38
39
40
41
42
43
The Fund – Bakken Expansion Program
$0.2 billion
$0.2 billion
EEP – Berthold Rail Project
US$0.1 billion
US$0.1 billion
EEP – Ajax Cryogenic Processing Plant
US$0.2 billion
US$0.2 billion
EEP – Bakken Access Program
US$0.1 billion
US$0.1 billion
EEP – Texas Express NGL System
US$0.4 billion
US$0.4 billion
EEP – Line 6B 75-Mile Replacement
US$0.4 billion
US$0.4 billion
Program
EEP – Eastern Access4
US$2.6 billion
US$1.3 billion
EEP – Lakehead System Mainline
US$2.4 billion
US$0.2 billion
Expansion4
EEP – Beckville Cryogenic Processing
US$0.1 billion
Facility
No significant
expenditures to date
Status
Complete
Complete
Complete
Complete
Complete
Complete
2013
2013
2013
2013
2013
2013
2013 – 2014
(in phases)
2013 – 2016
(in phases)
2014 – 2016
(in phases)
Under construction
Under construction
Under construction
2015
Pre-construction
44
EEP – Sandpiper Project
US$2.6 billion
US$0.1 billion
2016
Pre-construction
1
2
3
4
These amounts are estimates and subject to upward or downward adjustment based on various factors. Where appropriate, the amounts
reflect Enbridge’s share of joint venture projects.
Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2013.
See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access for
project discussion.
The Eastern Access and Lakehead System Mainline Expansion projects are funded 75% by Enbridge and 25% by EEP.
Risks related to the development and completion of growth projects are described under
Risk Management and Financial Instruments – General Business Risks.
Liquids Pipelines
Seaway Crude Pipeline System
Acquisition of Interest
In 2011, Enbridge acquired a 50% interest in the Seaway Pipeline at a cost of approximately US$1.2 billion.
Seaway Pipeline includes the 805-kilometre (500-mile) 30-inch diameter long-haul system from Freeport,
Texas to Cushing, Oklahoma.
Reversal and Expansion
The flow direction of the Seaway Pipeline was reversed, enabling it to transport crude oil from the
oversupplied hub in Cushing, Oklahoma to the Gulf Coast. The initial reversal of the pipeline and
preliminary service commenced in 2012, providing initial capacity of 150,000 bpd. Further pump
station additions and modifications were completed in January 2013, increasing capacity available
to shippers to up to approximately 400,000 bpd, depending on crude oil slate. Actual throughput
experienced in 2013 was curtailed due to constraints on third party takeaway facilities. A 105-kilometre
(65-mile), 36-inch diameter pipeline lateral from the Seaway Jones Creek facility to Enterprise Product
Partners L.P.’s (Enterprise) ECHO crude oil terminal (ECHO Terminal) in Houston, Texas was placed into
service in January 2014 and is expected to relieve these constraints.
Twinning and Extension
Based on additional capacity commitments from shippers, a second line is being constructed that
is expected to more than double the existing capacity of the Seaway Pipeline to 850,000 bpd by
mid-2014. This 30-inch diameter pipeline will follow the same route as the existing Seaway Pipeline.
Included in the project scope is the lateral from the Seaway Jones Creek facility southwest of Houston,
Texas into the ECHO Terminal noted above.
50 Enbridge Inc. 2013 Annual Report
Norman Wells
Zama
Fort McMurray
Cheecham
Edmonton
Hardisty
8
Blaine
Portland
Salt Lake City
Casper
6
Fort McMurray
18
13
17
2
Cheecham
16
9
19
14
10
18
Edmonton
15
11
3
Hardisty
Superior
Montreal
Toronto
Sarnia
4
Toledo
Chicago
Buffalo
5
7
12
Patoka
Wood River
Cushing
1
Houston
New Orleans
Current
Assets
Growth
Opportunities
Liquids Pipelines
1
2
3
4
5
6
7
8
Seaway Crude Pipeline
System (Including Acquisition,
Reversal, Expansion,
Twinning and Extension)
Suncor Bitumen Blend
Athabasca Pipeline
Capacity Expansion
Eastern Access (Including
Toledo expansion and Line
9 reversal and expansion)
Eddystone Rail Project
Norealis Pipeline
9
Surmont Phase 2 Expansion
10 Athabasca Pipeline Twinning
11
12
Edmonton to Hardisty Expansion
Southern Access Extension
13 AOC Hangingstone Lateral
14 Sunday Creek Terminal Expansion
15 Canadian Mainline System
Terminal Flexibility
and Connectivity
16 Woodland Pipeline Extension
17
JACOS Hangingstone Project
Flanagan South Pipeline Project
Canadian Mainline Expansion
18 Wood Buffalo Extension
19 Norlite Pipeline System
Management’s Discussion and Analysis 51
In addition, a 137-kilometre (85-mile) pipeline will be
constructed from the ECHO Terminal to the Port Arthur/
Beaumont, Texas refining centre to provide shippers access
to the region’s heavy oil refining capabilities. This extension
will provide capacity of 750,000 bpd and is now expected to
be available in mid-2014.
Including the acquisition of the initial 50% interest,
Enbridge’s total expected cost for the Seaway Pipeline
is approximately US$2.4 billion. The acquisition, reversal
and expansion are expected to cost US$1.3 billion, with
the twinning, extension and lateral to the ECHO Terminal
components of the project expected to cost approximately
US$1.1 billion. Total expenditures incurred to date are
approximately US$1.8 billion.
Suncor Bitumen Blend
Under an agreement with Suncor Energy Oil Sands Limited
Partnership (Suncor Partnership), the Suncor Bitumen Blend
project involved the construction of a new 350,000 barrel
tank, new blend and diluent lines and pumping capacity to
connect with Suncor Partnership’s lines just outside Enbridge’s
Athabasca Tank Farm. Enbridge completed construction of the
new facilities in June 2013, which enables Suncor Partnership
to transport blended bitumen volumes from its Firebag
production into the Wood Buffalo Pipeline. The project was
completed at an approximate cost of $0.2 billion.
South Cheecham Rail and Truck Terminal
The Company partnered with Keyera Corp. (Keyera) to
construct the initial phase of the South Cheecham Rail and
Truck Terminal (the Terminal), located approximately 75
kilometres (47 miles) southeast of Fort McMurray, Alberta.
The Terminal, which is being developed in phases, will be a
multi-purpose hydrocarbon rail and truck terminal, designed
to support bitumen producers within the Athabasca oil sands
area and facilitate product moving in and out of the region.
In addition to the facilities for handling diluent and diluted
bitumen at the Terminal, the initial phase includes both a
diluent and a diluted bitumen pipeline connection to Statoil
Canada Limited’s Cheecham Terminal which could be
connected to Enbridge’s existing Cheecham Terminal in the
future. Construction of the first phase was completed and
placed into service in October 2013 with post-completion
expenditures expected to be incurred into 2014. The cost of
the first phase is expected to be approximately $90 million
and Enbridge’s share of the project costs will be based upon
its 50% joint venture interest. Construction of additional
phases of the Terminal is under active consideration by the
Company and Keyera.
Athabasca Pipeline Capacity Expansion
In December 2013, the Company completed the second
phase of the expansion of its Athabasca Pipeline to its full
capacity of approximately 570,000 bpd, depending on the
mix of crude oil types. The first phase of the expansion,
which increased capacity to approximately 430,000 bpd,
was completed and placed into service in March 2013.
The Athabasca Pipeline transports crude oil from various
oil sands projects to the mainline hub at Hardisty, Alberta.
The completed expansion will accommodate additional
contractual commitments, including incremental production
from the Christina Lake Oil Sands Project operated by
Cenovus Energy Inc. (Cenovus). The total cost of the project
was approximately $0.4 billion.
Eddystone Rail Project
The Company entered into a joint venture agreement
with Canopy Prospecting Inc. to develop a unit-train
unloading facility and related local pipeline infrastructure
near Philadelphia, Pennsylvania to deliver Bakken and
other light sweet crude oil to Philadelphia area refineries.
The Eddystone Rail Project includes leasing portions of a
power generation facility and reconfiguring existing track
to accommodate 120-car unit-trains, installing crude oil
offloading equipment, refurbishing an existing 200,000
barrel tank and upgrading an existing barge loading facility.
The project is expected to be placed into service in the first
quarter of 2014 and will receive and deliver an initial capacity
of 80,000 bpd, expandable to 160,000 bpd. The total
estimated cost of the project is approximately US$0.1 billion
and Enbridge’s share of the project costs will be based upon
its 75% joint venture interest.
Norealis Pipeline
In order to provide pipeline and terminalling services to
the proposed Husky Energy Inc. operated Sunrise Energy
Project, the Company is undertaking construction of a new
originating terminal (Norealis Terminal), a 112-kilometre
(66-mile) 24-inch diameter pipeline from the Norealis
Terminal to the Cheecham Terminal and additional
tankage at Cheecham. The estimated cost of the project
is approximately $0.5 billion, with expenditures to date of
approximately $0.4 billion. The terminal scope of work was
substantially completed in December 2013 and the overall
system is expected to be available for service in the first
quarter of 2014.
Flanagan South Pipeline Project
The 950-kilometre (590-mile) Flanagan South Pipeline will
have an initial capacity of approximately 600,000 bpd to
transport crude oil from the Company’s terminal at Flanagan,
Illinois to Cushing, Oklahoma. The 36-inch diameter pipeline
is being installed adjacent to the Company’s Spearhead
Pipeline for the majority of the route. Subject to regulatory
and other approvals, the pipeline is expected to be in service
in the third quarter of 2014. The estimated cost of the project
is approximately US$2.8 billion, with expenditures to date of
approximately US$1.6 billion.
52 Enbridge Inc. 2013 Annual Report
On August 23, 2013, the Sierra Club and National Wildlife
Federation (the Plaintiff) filed a complaint for Declaratory
and Injunctive Relief (the Complaint) with the United States
District Court for the District of Columbia (the Court).
The Complaint was filed against multiple federal agencies
(the Defendants) and included a request that the Court issue
a preliminary injunction suspending previously granted
federal permits and ordering Enbridge to discontinue
construction of the project on the basis that the Defendants
failed to comply with environmental review standards of
the National Environmental Protection Act. On September
5, 2013, Enbridge obtained intervener status and joined the
Defendants in filing a response in opposition to the motion
for preliminary injunction. The Court hearing was held on
September 27, 2013 and the Plaintiff’s request for preliminary
injunction was denied by the Court on November 13, 2013.
A court hearing is scheduled for February 21, 2014 concerning
the merits of the Complaint against the federal agencies.
Canadian Mainline Expansion
Enbridge is undertaking an estimated $0.2 billion expansion
of the Alberta Clipper line between Hardisty, Alberta and
the Canada/United States border near Gretna, Manitoba.
The scope of the project involves the addition of pumping
horsepower sufficient to raise the capacity of the Alberta
Clipper line by 120,000 bpd to a capacity of 570,000 bpd
and is expected to be in service in the third quarter of 2014.
In January 2013, Enbridge announced a further expansion
of the Canadian Mainline system between Hardisty,
Alberta and the Canada/United States border near Gretna,
Manitoba, at an estimated cost of $0.4 billion. Subject to
National Energy Board (NEB) approval, the scope of the
additional expansion involves the addition of pumping
horsepower sufficient to raise the capacity of the Alberta
Clipper line by another 230,000 bpd to its full capacity of
800,000 bpd and is expected to be in service in 2015.
The total estimated cost for the Canadian Mainline
Expansion is $0.6 billion, with expenditures to date
of approximately $0.1 billion. Delays in receipt of the
applicable regulatory approvals on EEP’s portion of the
mainline system expansion are expected to affect the
Canadian Mainline Expansion. However, temporary system
optimization actions are being undertaken to substantially
mitigate any impact on throughput from the delay. See
Growth Projects – Commercially Secured Projects –
Sponsored Investments – Enbridge Energy Partners, L.P. –
Lakehead System Mainline Expansion.
Surmont Phase 2 Expansion
In May 2013, the Company announced it had entered
into a terminal services agreement with ConocoPhillips
Canada Resources Corp. (ConocoPhillips) and Total E&P
Canada Ltd. (the ConocoPhillips Partnership) to expand the
Cheecham Terminal to accommodate incremental bitumen
production from Surmont’s Phase 2 expansion. The Company
is constructing two new 450,000 barrel blend tanks and
converting an existing tank from blend to diluent service.
The expansion is expected to come into service in two
phases, with the blended product system expected in the
fourth quarter of 2014 and the diluent system expected in
the first quarter of 2015. The estimated cost of the project
is approximately $0.3 billion with expenditures to date of
approximately $0.1 billion.
Athabasca Pipeline Twinning
This project involves the twinning of the southern section
of the Company’s Athabasca Pipeline from Kirby Lake,
Alberta to the Hardisty, Alberta crude oil hub to provide
additional capacity to serve expected oil sands growth in
the Kirby Lake producing region. The expansion project,
with an estimated cost of approximately $1.2 billion, and
expenditures to date of approximately of $0.6 billion,
will include 346 kilometres (215 miles) of 36-inch pipeline
adjacent to the existing Athabasca Pipeline right-of-way.
The initial annual capacity of the pipeline will be
approximately 450,000 bpd, with expansion potential to
800,000 bpd. Subject to regulatory and other approvals,
the line is expected to enter service in 2015.
Edmonton to Hardisty Expansion
The Company is undertaking an expansion of the Canadian
Mainline system between Edmonton, Alberta and Hardisty,
Alberta. The expansion project, with an estimated cost of
approximately $1.8 billion, and expenditures incurred to date
of approximately $0.2 billion, will include 181 kilometres
(112 miles) of new 36-inch diameter pipeline, expected to
generally follow the same route as Enbridge’s existing Line 4
pipeline, and new terminal facilities in Edmonton which
include five new 500,000 barrel tanks and connections
into existing infrastructure at Hardisty Terminal. The initial
capacity of the new line will be approximately 570,000 bpd,
with expansion potential to 800,000 bpd and is expected to
be placed into service in 2015.
Southern Access Extension
The Southern Access Extension project will consist of the
construction of a new 265-kilometre (165-mile) 24-inch
diameter crude oil pipeline from Flanagan, Illinois to Patoka,
Illinois as well as additional tankage and two new pump
stations. Subject to regulatory and other approvals, the
project is expected to be placed into service in 2015 at an
approximate cost of US$0.8 billion, with expenditures to
date of approximately US$0.1 billion. The initial capacity of
the new line is expected to be approximately 300,000 bpd.
Prior to the binding open season that closed in January 2013,
Enbridge had received sufficient capacity commitments
from an anchor shipper to support the 24-inch pipeline.
In June 2013, a second open season to solicit additional
Management’s Discussion and Analysis 53
capacity commitments from shippers was announced and
subsequently closed in September 2013. The Company
received a further capacity commitment through the second
open season, which can be accommodated within the initial
capacity planned for the pipeline.
AOC Hangingstone Lateral
In March 2013, the Company announced that it entered into
an agreement with Athabasca Oil Corporation (AOC) to
provide pipeline and terminalling services to the proposed
AOC Hangingstone Oil Sands Project (AOC Hangingstone)
in Alberta. Phase I of the project will involve the construction
of a new 49-kilometre (31-mile) 16-inch diameter pipeline
from the AOC Hangingstone project site to Enbridge’s
existing Cheecham Terminal, and related facility
modifications at Cheecham. Phase I of the project will
provide an initial capacity of 16,000 bpd and is expected
to be placed into service in 2015 at an estimated cost of
approximately $0.1 billion. Phase 2 of the project, which is
subject to commercial approval, would provide up to an
additional 60,000 bpd for a total capacity of 76,000 bpd.
Sunday Creek Terminal Expansion
In January 2014, the Company announced it will construct
additional facilities at its Sunday Creek Terminal, located
in the Christina Lake area of northern Alberta, to support
production growth from the Christina Lake oil sands operated
by Cenovus and jointly owned with ConocoPhillips.
The expansion includes development of a new site adjacent
to the existing terminal, construction of a new 350,000
barrel tank with associated piping, pumps and measurement
equipment, as well as civil work for a future tank. The existing
Sunday Creek Terminal was put into service in August 2011.
The estimated cost for the expansion is approximately
$0.2 billion, with expenditures to date of approximately
$0.1 billion and a targeted in-service date of 2015.
Canadian Mainline System Terminal Flexibility
and Connectivity
As part of the Light Oil Market Access Program initiative,
the Company is undertaking the Canadian Mainline System
Terminal Flexibility and Connectivity project in order to
accommodate additional light oil volumes and enhance the
operational flexibility of the Canadian mainline terminals.
The cost of the project is expected to be approximately
$0.6 billion, with expenditures incurred to date of
approximately $0.2 billion, and with varying completion
dates from 2013 through 2015 related to existing terminal
facility modifications. These modifications are comprised of
upgrading existing booster pumps, additional booster pumps
and new tank line connections.
Woodland Pipeline Extension
In July 2013, Enbridge announced that it had received
shipper sanctioning for the Woodland Pipeline Extension
Project. The joint venture project will extend the Woodland
Pipeline south from Enbridge’s Cheecham Terminal to
its Edmonton Terminal. The extension is a proposed
385-kilometre (228-mile), 36-inch diameter pipeline with an
initial capacity of 400,000 bpd, expandable to 800,000 bpd.
Enbridge’s share of the estimated capital cost of the project
is approximately $0.6 billion, with expenditures incurred to
date of approximately $0.1 billion. Subject to finalization of
scope and a definitive cost estimate, the project has a target
in-service date of 2015.
JACOS Hangingstone Project
In September 2013, Enbridge announced it will construct
facilities and provide transportation services to the Japan
Canada Oil Sands Limited (JACOS) Hangingstone Oil Sands
Project (JACOS Hangingstone). JACOS and Nexen Energy
ULC, a wholly owned subsidiary of China National Offshore
Oil Corporation Limited, are partners in the project which
is operated by JACOS. Subject to regulatory approval,
Enbridge plans to construct a new 50-kilometre (31-mile)
12-inch lateral pipeline to connect the JACOS Hangingstone
project site to Enbridge’s existing Cheecham Terminal. The
project will provide capacity of 40,000 bpd at an estimated
cost of approximately $0.1 billion and is expected to enter
service in 2016.
Wood Buffalo Extension
In October 2013, Enbridge announced that it was selected
by Suncor Energy Inc., Total E&P Canada Ltd. and Teck
Resources Limited (the Fort Hills Partners), as well as the
Suncor Partnership, to develop a new pipeline to transport
crude oil production to Enbridge’s mainline hub at Hardisty,
Alberta. The proposed Wood Buffalo Extension will extend
Enbridge’s existing Wood Buffalo Pipeline and include the
construction of a new 450-kilometre (281-mile) 30-inch
pipeline from Enbridge’s Cheecham Terminal to its Battle
River Terminal at Hardisty, as well as associated terminal
upgrades. The completed project will provide capacity of
490,000 bpd of diluted bitumen to be transported for the
proposed Fort Hills Partners’ oil sands project (Fort Hills
Project) in northeastern Alberta and Suncor Partnership’s
oil sands production in the Athabasca region. Subject to
regulatory approvals, the project is expected to be completed
in 2017 at an estimated cost of approximately $1.6 billion.
54 Enbridge Inc. 2013 Annual Report
Norlite Pipeline System
In October 2013, Enbridge announced it will develop Norlite, a new industry diluent pipeline to meet the
needs of multiple producers in the Athabasca oil sands region. Under the currently envisioned scope, a
20-inch diameter pipeline with an approximate ultimate capacity of up to 280,000 bpd, depending on
final scope and hydraulic design, will be anchored by throughput commitments from both the Fort Hills
Partners for production from the proposed Fort Hills Project and from Suncor Partnership’s proprietary
oil sands production. Norlite will involve the construction of a new 489-kilometre (303-mile) pipeline
from Enbridge’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s
East Tank Farm, which is adjacent to Enbridge’s existing Athabasca Terminal. If Enbridge is successful
in securing additional long term commitments on the proposed Norlite system, the scope of the project
could be increased to a 24-inch diameter pipeline system as well as include a potential lateral pipeline
to Enbridge’s Norealis Terminal. Subject to regulatory and other approvals, Norlite is expected to be
completed in 2017 at an estimated cost of approximately $1.4 billion. If upsized to a 24-inch diameter
pipeline, it will provide capacity to transport up to 270,000 bpd of diluent from Edmonton into the
Athabasca oil sands region, with the potential to be further expanded to approximately 400,000 bpd of
capacity with the addition of pump stations. Norlite has the right to access certain existing capacity on
Keyera pipelines between Edmonton and Stonefell and, in exchange, Keyera may elect to participate in
the new pipeline infrastructure as a 30% non-operating owner.
Gas Distribution
Greater Toronto Area Project
EGD plans to expand its natural gas distribution system in the
Greater Toronto Area (GTA) to meet the demands of growth
and to continue the safe and reliable delivery of natural gas
to current and future customers. At an expected cost of
approximately $0.7 billion, the proposed GTA project will
consist of two segments of pipeline and related facilities
to upgrade the existing distribution system that delivers
natural gas to several municipalities in Ontario. The Company
filed amended applications reflecting scope modifications
with the Ontario Energy Board (OEB) in February, April and
July 2013. As a result of the July scope modification, the
expected capital cost increased by approximately $0.1 billion.
OEB hearings were held in September and October 2013
and approval was received from the OEB in January 2014.
Construction is targeted to start in late 2014, with completion
expected by the end of 2015.
Gas Pipelines, Processing and Energy Services
Massif du Sud Wind Project
Ottawa
20
Toronto
Sarnia
Buffalo
Gas Distribution
20 Greater Toronto Area Project
Enbridge secured a 50% interest in the development of the 150-MW Massif du Sud Wind Project
(Massif du Sud), located 100 kilometres (60 miles) east of Quebec City, Quebec. Massif du Sud delivers
energy to Hydro-Quebec under a 20-year PPA. Project construction was completed in December 2012
at a final investment by Enbridge of approximately $0.2 billion and commercial operation commenced
in January 2013.
Management’s Discussion and Analysis 55
25
Fort St. John
26
Edmonton
Hardisty
Calgary
29
24
27
Denver
Las Vegas
23
21
22
Superior
Montreal
Toronto
Sarnia
Chicago
Toledo
Cushing
32
Houston
New Orleans
28
30
33
31
Gas Pipelines, Processing and Energy Services
21 Massif du Sud Wind Project
22 Saint Robert Bellarmin
28 Venice Condensate
Stabilization Facility
Wind Project
29 Blackspring Ridge Wind Project
23 Lac Alfred Wind Project
24 Montana-Alberta Tie-Line
25 Cabin Gas Plant
26 Pipestone and Sexsmith Project
27 Tioga Lateral Pipeline
30 Walker Ridge Gas
Gathering System
31
Big Foot Oil Pipeline
32 Keechi Wind Project
33 Heidelberg Lateral Pipeline
Current
Assets
Growth
Opportunities
Wind Assets
Solar Assets
56 Enbridge Inc. 2013 Annual Report
Saint Robert Bellarmin Wind Project
Pipestone and Sexsmith Project
In July 2013, Enbridge acquired a 50% interest in the 80-MW
Saint Robert Bellarmin Wind Project, located 300 kilometres
(185 miles) east of Montreal, Quebec. The project is
operational and power output is being delivered to
Hydro-Quebec under a 20-year PPA. The Company’s total
investment in the project was approximately $0.1 billion.
Lac Alfred Wind Project
Enbridge secured a 50% interest in the development of
the 300-MW Lac Alfred Wind Project (Lac Alfred), located
400 kilometres (250 miles) northeast of Quebec City in
Quebec’s Bas-Saint-Laurent region. Lac Alfred delivers
energy to Hydro-Quebec under a 20-year PPA. The project
was constructed under a fixed price, turnkey, engineering,
procurement and construction agreement. Construction
was completed during 2013 and commercial operations
commenced in two phases: Phase 1 in January 2013 and
Phase 2 in August 2013, with each phase providing 150-MW
of generation capacity. The Company’s total investment in
the project was approximately $0.3 billion.
Montana-Alberta Tie-Line
In September 2013, Enbridge completed and placed into
service the first 300-MW phase of MATL. MATL is a
345-kilometre (215-mile) transmission line from Great Falls,
Montana to Lethbridge, Alberta, designed to take advantage
of the growing supply of electric power in Montana and buoyant
power demand in Alberta. Post-completion expenditures
will continue to be incurred into 2014 and the estimated cost
for the first phase of the project remains at approximately
US$0.4 billion, with expenditures to date of approximately
US$0.3 billion. An expansion of an additional 300-MW of
transmission capacity is under active consideration and an
in-service date and definitive cost estimate are dependent on
finalization of scope, regulatory approval and customer support.
In 2012, the Company acquired from Encana Corporation
(Encana) certain sour gas gathering and compression
facilities located in the Peace River Arch (PRA) region of
northwest Alberta (collectively, Pipestone and Sexsmith).
These facilities were either in service (Sexsmith) or under
construction (Pipestone). Construction of new gathering
lines and NGL handling facilities are being completed in
phases with final completion expected in the second quarter
of 2014. Enbridge’s investment in Pipestone and Sexsmith is
expected to be approximately $0.3 billion, with expenditures
to date of approximately $0.2 billion. Enbridge also retains
an exclusive right to work with Encana on facility scoping
for development of additional major midstream facilities in
the liquids-rich PRA region. Financial terms of Pipestone
and Sexsmith are substantially consistent with previously
established terms of the Cabin development.
Tioga Lateral Pipeline
In September 2013, Alliance Pipeline US completed
construction and placed into-service a natural gas pipeline
lateral and associated facilities to connect production
from the Hess Corporation (Hess) Tioga field processing
plant in the Bakken region of North Dakota to the Alliance
mainline near Sherwood, North Dakota. The 127-kilometre
(79-mile) Tioga Lateral Pipeline will facilitate movement of
liquids-rich natural gas to NGL processing facilities owned
by Aux Sable near the terminus of Alliance. The pipeline
has an initial design capacity of approximately 126 million
cubic feet per day (mmcf/d), which can be expanded based
on shipper demand. Through its 50% ownership interest in
Alliance Pipeline US, Enbridge’s share of the final cost of the
project was approximately US$0.1 billion. In October 2012,
Alliance Pipeline US executed a contract with Hess as an
anchor shipper. Aux Sable and Hess reached a concurrent
agreement for provision of NGL services.
Cabin Gas Plant
Venice Condensate Stabilization Facility
In 2011, the Company secured a 71% interest in the
development of the Cabin Gas Plant (Cabin), located
60 kilometres (37 miles) northeast of Fort Nelson, British
Columbia in the Horn River Basin. The Company’s total
investment in phases 1 and 2 of Cabin was expected
to be approximately $1.1 billion. In October 2012, the
Company and its partners announced plans to defer both
the commissioning of phase 1 and the construction of
phase 2. Expenditures were incurred throughout 2013
to complete pre-commissioning construction on Phase 1
and to place Phase 2 into preservation mode. Under the
deferral, the Company’s total investment in phases 1 and 2
is approximately $0.8 billion. In December 2012, Enbridge
started earning fees on its investment made to date in both
phases 1 and 2. On May 1, 2013, the Company became
operator of Cabin.
In November 2013, the Company completed the expansion
of the Venice Condensate Stabilization and Separation
Facilities (Venice) at its Venice, Louisiana facility within
Enbridge Offshore Pipelines (Offshore). The expansion
increased the capacity of the stabilization facilities to
approximately 12,500 barrels of condensate per day
and the separation facilities to approximately 12,200 bpd.
The project was completed at an approximate cost of
US$0.1 billion. The expanded condensate stabilizing capacity
is required to accommodate additional natural gas production
from the Olympus offshore oil and gas development. Natural
gas production from Olympus will move to Enbridge’s
onshore facility at Venice via Enbridge’s Mississippi Canyon
offshore pipeline system, where the condensate will be
separated from the gas and stabilized.
Management’s Discussion and Analysis 57
Blackspring Ridge Wind Project
In April 2013, the Company announced that it had secured a
50% interest in the development of the 300-MW Blackspring
Ridge project, located 50 kilometres (31 miles) north of
Lethbridge, Alberta in Vulcan County. The project is being
constructed under a fixed price engineering, procurement
and construction contract and is expected to be completed
in the second quarter of 2014. Renewable Energy Credits
generated from Blackspring Ridge are contracted to Pacific
Gas and Electric Company under a 20-year purchase
agreement. The electricity will be sold into the Alberta
power pool with pricing fixed on 75% of production through
long-term contracts. The Company’s total investment in the
project is expected to be approximately $0.3 billion, with
expenditures incurred to date of approximately $0.2 billion.
Walker Ridge Gas Gathering System
The Company has agreements with Chevron USA Inc.
(Chevron) and Union Oil Company of California to expand
its central Gulf of Mexico offshore pipeline system. Under
the terms of the agreements, Enbridge is constructing and
will own and operate the WRGGS to provide natural gas
gathering services to the Jack St. Malo and Big Foot
ultra-deep water developments. The WRGGS includes
274 kilometres (170 miles) of 8-inch or 10-inch diameter
pipeline at depths of up to approximately 2,150 meters
(7,000 feet) with capacity of 100 mmcf/d. The Jack St. Malo
portion of the WRGGS is expected to be placed into service
in the third quarter of 2014 and the Big Foot Pipeline portion
is now expected to be placed into service in the second
quarter of 2015. The total WRGGS project is expected to
cost approximately US$0.4 billion, with expenditures to
date of approximately US$0.2 billion.
Big Foot Oil Pipeline
Under agreements with Chevron, Statoil Gulf of Mexico LLC
and Marubeni Oil & Gas (USA) Inc., Enbridge is constructing
a 64-kilometre (40-mile) 20-inch oil pipeline with capacity
of 100,000 bpd from the Big Foot ultra-deep water
development in the Gulf of Mexico. This crude oil pipeline
project is complementary to Enbridge’s undertaking of the
WRGGS construction, discussed above. Upon completion
of the project, Enbridge will operate the Big Foot Pipeline,
located approximately 274 kilometres (170 miles) south of
the coast of Louisiana. The estimated capital cost of the
project is approximately US$0.2 billion, with expenditures to
date of approximately US$0.1 billion, and is now expected to
enter service in the second quarter of 2015 to align with the
availability of production.
Keechi Wind Project
In January 2014, Enbridge announced it had entered into
an agreement with Renewable Energy Systems Americas
Inc. (RES Americas) to own and operate the 110-MW Keechi
58 Enbridge Inc. 2013 Annual Report
project, located in Jack County, Texas, at an investment of
approximately US$0.2 billion. RES Americas is constructing
the wind project under a fixed price, engineering,
procurement and construction agreement. Construction on
the project commenced in December 2013, with expected
completion in 2015. Upon attaining commercial operation,
MetLife, Inc. will provide tax equity financing for the project.
Keechi will deliver 100% of the electricity generated into the
Electric Reliability Council of Texas, Inc. market under a
20-year PPA with Microsoft Corporation.
Heidelberg Lateral Pipeline
The Company will construct, own and operate a crude oil
pipeline in the Gulf of Mexico to connect the proposed
Heidelberg development, operated by Anadarko Petroleum
Corporation (Anadarko), to an existing third-party system.
Heidelberg, a 20-inch 58-kilometre (36-mile) pipeline, will
originate in Green Canyon Block 860, approximately 320
kilometres (200 miles) southwest of New Orleans, Louisiana,
and in an estimated 1,600 metres (5,300 feet) of water.
Heidelberg is expected to be operational by 2016 at an
approximate cost of US$0.1 billion.
Sponsored Investments
Bakken Expansion Program
A joint project to further expand crude oil pipeline capacity to
accommodate growing crude oil production from the Bakken
and Three Forks formations located in North Dakota was
undertaken by EEP and the Fund. The project, undertaken by
EEP in the United States and the Fund in Canada, reversed
and expanded an existing pipeline, running from Berthold,
North Dakota, to Steelman, Saskatchewan, and constructed
a new 16-inch pipeline from a new terminal near Steelman
to the Enbridge mainline terminal near Cromer, Manitoba.
The project was completed and entered service in March
2013, providing capacity of 145,000 bpd. The United States
portion of the project was completed at an approximate cost
of US$0.3 billion and the Canadian portion of the project was
completed at an approximate cost of $0.2 billion.
Enbridge Energy Partners, L.P.
Berthold Rail Project
The Berthold Rail project expanded capacity into the
Berthold Terminal in North Dakota by 80,000 bpd and
involved the construction of a three-unit-train loading facility,
crude oil tankage and other terminal facilities adjacent to
existing infrastructure. The first phase of terminal facilities
was completed in 2012, providing additional capacity of
10,000 bpd to the Berthold Terminal. The loading facility and
crude oil tankage were subsequently completed and placed
into service in March 2013. The total cost of the project was
approximately US$0.1 billion.
Edmonton
Hardisty
Calgary
38
35
34
Gretna
Clearbrook
36
Minot
44
42
Superior
Toronto
Sarnia
40
41
Chicago
Flanagan
42
Cushing
37
39
43
Houston
New Orleans
Sponsored Investments
34 EEP – Bakken Expansion Program
35 The Fund – Bakken
Expansion Program
36 EEP – Berthold Rail Project
37 EEP – Ajax Cryogenic
Processing Plant
38 EEP – Bakken Access Program
39 EEP – Texas Express NGL System
40 EEP – Line 6B 75-Mile
Replacement Program
41
EEP – Eastern Access
42 EEP – Lakehead System
Mainline Expansion
43 EEP – Beckville Cryogenic
Processing Facility
44 EEP – Sandpiper Project
Current
Assets
Growth
Opportunities
Management’s Discussion and Analysis 59
Ajax Cryogenic Processing Plant
Line 6B 75-Mile Replacement Program
In September 2013, EEP placed into service the Ajax Plant,
comprised of a newly constructed natural gas processing
plant and related facilities, on its Anadarko System. The Ajax
Plant provides capacity of 150 mmcf/d and, in conjunction
with the Allison Plant, has increased total processing capacity
on the Anadarko System to approximately 1,150 mmcf/d.
The Anadarko System’s condensate stabilization capacity was
also increased by approximately 2,000 bpd. With the Texas
Express NGL System completed in October 2013 as discussed
below, the Ajax Plant is capable of producing approximately
15,000 bpd of NGL. The total cost of the Ajax Plant project
was approximately US$0.2 billion.
Bakken Access Program
The Bakken Access Program represents an upstream
expansion that will further complement EEP’s Bakken
expansion. The Bakken Access Program was placed into
service in phases in the middle of 2013 and enhanced crude
oil gathering capabilities on the North Dakota System by
100,000 bpd. The program involved increasing pipeline
capacity, constructing additional storage tanks and adding
truck access facilities at multiple locations in western North
Dakota at an approximate cost of US$0.1 billion.
Texas Express NGL System
In October 2013, EEP, Enterprise, Anadarko and DCP
Midstream Partners, L.P. (DCP Midstream) announced that
the Texas Express NGL System was placed into service.
The Texas Express NGL System is a joint venture that was
created to design and construct a new NGL pipeline and NGL
gathering system. The NGL pipeline is a joint venture between
EEP, Enterprise, Anadarko and DCP Midstream and the NGL
gathering system is a joint venture between EEP, Enterprise
and Anadarko. Enterprise constructed and operates the
NGL pipeline, while EEP constructed and operates the NGL
gathering system. EEP’s total investment in the Texas Express
NGL System was approximately US$0.4 billion.
The Texas Express NGL System originates in Skellytown,
Texas and extends approximately 935 kilometres (580 miles)
to NGL fractionation and storage facilities in Mont Belvieu,
Texas. The Texas Express NGL System has an initial capacity
of approximately 280,000 bpd, expandable to approximately
400,000 bpd. Approximately 250,000 bpd of capacity has
been subscribed on the pipeline. The new NGL gathering
system consists of approximately 187 kilometres (116 miles) of
gathering lines that connect the Texas Express NGL System to
natural gas processing plants in the Anadarko/Granite Wash
production area located in the Texas Panhandle and western
Oklahoma, as well as to the central Texas Barnett Shale
processing plants.
This program includes the replacement of 120 kilometres
(75 miles) of non-contiguous sections of Line 6B of EEP’s
Lakehead System. The Line 6B pipeline runs from Griffith,
Indiana through Michigan to the international border at the
St. Clair River. The new segments are being completed in
components, with approximately 104 kilometres (65 miles)
of segments placed in service since the first quarter of 2013.
The two remaining 8-kilometre (5-mile) segments in Indiana
are expected to be placed in service in the first quarter
of 2014. The total estimated capital for this replacement
program is approximately US$0.4 billion, with expenditures
to date of approximately US$0.4 billion. EEP will recover
these costs through a tariff surcharge that is part of the
system-wide rates for the Lakehead System.
Eastern Access
The Eastern Access initiative includes a series of Enbridge and
EEP crude oil pipeline projects to provide increased access
to refineries in the upper midwest United States and eastern
Canada. Projects being undertaken by Enbridge include a
reversal of its Line 9 and expansion of the Toledo Pipeline.
Projects being undertaken by EEP include an expansion of its
Line 5 and expansions of the United States mainline involving
the Spearhead North Pipeline (Line 62) and further segments
of Line 6B. The individual projects are further described below.
In August 2013, Enbridge completed the reversal of a portion of
its Line 9A in western Ontario to permit crude oil movements
eastbound from Sarnia as far as Westover, Ontario. Enbridge
also plans to undertake a full reversal of its 240,000 bpd Line
9B from Westover, Ontario to Montreal, Quebec to serve
refineries in Quebec. The Line 9B reversal is expected to be
completed at an estimated cost of approximately $0.3 billion,
including estimated costs associated with integrity digs being
performed on the line. Following an open season held on the
Line 9B reversal project, further commitments were received
that required additional delivery capacity within Ontario and
Quebec, resulting in the Line 9B capacity expansion project.
The Line 9B capacity expansion will increase the annual
capacity of Line 9B from 240,000 bpd to 300,000 bpd at an
estimated cost of approximately $0.1 billion. Subject to NEB
approval, the Line 9B reversal and Line 9B capacity expansion
are expected to be available for service in the fourth quarter
of 2014 at a total estimated cost of approximately $0.4 billion.
Expenditures incurred to date for the Lines 9A and 9B projects
are approximately $0.2 billion.
In May 2013, Enbridge completed an 80,000 bpd expansion
of its Toledo Pipeline (Line 17), which connects with the EEP
mainline at Stockbridge, Michigan and serves refineries
at Toledo, Ohio and Detroit, Michigan. The project was
completed at an approximate cost of US$0.2 billion.
Both the Toledo Pipeline and Line 9 assets are included in
the Company’s Liquids Pipelines segment.
60 Enbridge Inc. 2013 Annual Report
In May 2013, EEP completed and placed into service the
expansion of its Line 5 light crude oil line between Superior,
Wisconsin and Sarnia, Ontario. The Line 5 expansion
increased capacity by 50,000 bpd at an approximate cost
of US$0.1 billion.
In November 2013, EEP completed and placed into service
the expansion of its Line 62 between Flanagan, Illinois and
Griffith, Indiana. The Line 62 expansion increased capacity
by 105,000 bpd. EEP is also replacing additional sections
of Line 6B in Indiana and Michigan, including the addition
of new pumps and terminal upgrades at Hartsdale, Griffith
and Stockbridge, as well as tanks at Flanagan, Stockbridge
and Hartsdale, to increase capacity from 240,000 bpd to
500,000 bpd. Portions of the existing 30-inch diameter
pipeline are being replaced with 36-inch diameter pipe.
The target in-service date for the Line 6B project is split
into two phases, with the segment between Griffith and
Stockbridge expected to be completed in the first quarter
of 2014 and the segment from Ortonville, Michigan to Sarnia,
Ontario expected to be completed in the third quarter of
2014. The replacement of the Line 6B sections is in addition
to the Line 6B Replacement Program discussed previously.
The expected cost of the United States mainline expansions
is approximately US$2.2 billion, and includes the US$0.1 billion
cost of the previously discussed Line 5 expansion.
The Eastern Access initiative also includes a further upsizing
of EEP’s Line 6B. The Line 6B capacity expansion from
Griffith, Indiana to Stockbridge, Michigan will increase
capacity from 500,000 bpd to 570,000 bpd and will involve
the addition of new pumps, existing station modifications at
the Griffith and Stockbridge terminals and breakout tankage
at Stockbridge. The project is expected to be placed into
service in 2016 at an estimated capital cost of approximately
US$0.4 billion.
The total estimated cost of the projects being undertaken
by EEP as part of the Eastern Access initiative including the
United States mainline expansions, the Line 5 expansion and
the Line 6B capacity expansion project, is approximately
US$2.6 billion, with expenditures to date of approximately
US$1.3 billion. The Eastern Access projects, excluding
the Toledo Expansion and Line 9 Reversal and Expansion,
are now being funded 75% by Enbridge and 25% by EEP,
after EEP exercised the option to reduce its funding and
associated economic interest in the project by 15% on June
28, 2013. Within one year of the final in-service date of the
collective projects, EEP will have the option to increase its
economic interest held at that time by up to 15%. For further
discussion refer to Liquidity and Capital Resources.
Lakehead System Mainline Expansion
The Lakehead System Mainline Expansion includes several
projects to expand capacity of the Lakehead System
mainline between its origin at the Canada/United States
border, near Neche, North Dakota, to Flanagan, Illinois.
These projects are in addition to expansions of the Lakehead
System mainline being undertaken as part of the Eastern
Access initiative and includes the expansion of Alberta
Clipper (Line 67) and Southern Access (Line 61).
The current scope of the Alberta Clipper expansion
between the border and Superior, Wisconsin consists of two
phases. The initial phase includes an increase in capacity
from 450,000 bpd to 570,000 bpd at an estimated capital
cost of approximately US$0.2 billion. In January 2013, EEP
announced a further expansion of the Lakehead System
mainline between the border and Superior to increase
capacity from 570,000 bpd to 800,000 bpd, at an estimated
capital cost of approximately US$0.2 billion. Both phases of
the Alberta Clipper expansion require only the addition of
pumping horsepower and no pipeline construction. Subject
to regulatory and other approvals, including an amendment
to the current Presidential border crossing permit to allow
for operation of Line 67 at its currently planned operating
capacity of 800,000 bpd, the target in-service dates for the
proposed projects are the third quarter of 2014 for the initial
phase and 2015 for the second phase. It is now anticipated
that it will take longer to obtain regulatory approval than
planned. A number of temporary system optimization
actions are being undertaken to substantially mitigate any
impact on throughput.
The current scope of the Southern Access expansion
between Superior, Wisconsin and Flanagan, Illinois also
consists of two phases. The initial phase includes an
increase in capacity from 400,000 bpd to 560,000 bpd at
an estimated capital cost of approximately US$0.2 billion.
EEP also plans to undertake a further expansion of the
Southern Access line between Superior and Flanagan to
increase capacity from 560,000 bpd to 1,200,000 bpd at an
estimated capital cost of approximately US$1.3 billion. Both
phases of the expansion would require only the addition of
pumping horsepower and crude oil tanks at existing sites,
with no pipeline construction. The target in-service date
for the first phase of the expansion is expected to be in the
third quarter of 2014. For the second phase of the expansion,
which remains subject to regulatory and other approvals,
the pump station expansion is expected to be available
for service in 2015, with additional tankage requirements
expected to be completed in 2016.
As part of the Light Oil Market Access Program, EEP also
plans to expand the capacity of the Lakehead System
between Flanagan, Illinois and Griffith, Indiana. This section
of the Lakehead System will be expanded by constructing a
122-kilometre (76-mile), 36-inch diameter twin of the existing
Spearhead North Pipeline (Line 62). The project is expected
to be completed at an estimated cost of approximately
US$0.5 billion. Subject to regulatory and other approvals,
the new line will have an initial capacity of 570,000 bpd and
is expected to be placed into service in 2015.
Management’s Discussion and Analysis 61
The projects collectively referred to as the Lakehead System
Mainline Expansion are expected to cost approximately
US$2.4 billion, with expenditures incurred to date of
approximately US$0.2 billion. EEP will operate the project
on a cost-of-service basis. The Lakehead System Mainline
Expansion is now being funded 75% by Enbridge and 25% by
EEP, after EEP exercised the option to reduce its funding and
associated economic interest in the project by 15% on June
28, 2013. Within one year of the final in-service date of the
collective projects, EEP will have the option to increase its
economic interest held at that time by up to 15%. For further
discussion refer to Liquidity and Capital Resources.
Beckville Cryogenic Processing Facility
In April 2013, EEP announced plans to construct a cryogenic
natural gas processing plant near Beckville (the Beckville
Plant) in Panola County, Texas, at an expected cost of
approximately US$0.1 billion. The Beckville Plant will offer
incremental processing capacity for existing and future
customers in the 10-county Cotton Valley shale region,
where EEP’s East Texas system is located. The Beckville
Plant has a planned natural gas processing capability of 150
mmcf/d and is also expected to produce 8,500 bpd of NGL.
Construction activities have commenced and the Beckville
Plant is expected to be placed into service in 2015.
Sandpiper Project
As part of the Light Oil Market Access Program initiative,
EEP plans to undertake Sandpiper which will expand and
extend EEP’s North Dakota feeder system. The Bakken
takeaway capacity of the North Dakota System will be
expanded by 225,000 bpd to a total of 580,000 bpd.
The original proposed expansion would involve construction
of a 965-kilometre (600-mile) 24-inch diameter line from
Beaver Lodge Station near Tioga, North Dakota to the
Superior, Wisconsin mainline system terminal. The new
line will twin the 210,000 bpd North Dakota System
mainline, which now terminates at Clearbrook Terminal in
Minnesota, adding 225,000 bpd of capacity on the twin
line between Tioga and Clearbrook and 375,000 bpd of
capacity between Clearbrook and Superior. In September
2013, a scope modification was made to increase the
twin line diameter from 24-inches to 30-inches between
Clearbrook and Superior. As a result of the September 2013
scope modification, the expected capital cost increased by
approximately US$0.1 billion and Sandpiper is now expected
to cost approximately US$2.6 billion, with expenditures
incurred to date of approximately US$0.1 billion.
In November 2013, EEP and Enbridge announced that
Marathon Petroleum Corporation (MPC) had been
secured as an anchor shipper for Sandpiper. As part
of the arrangement, EEP, through its subsidiary, North
Dakota Pipeline Company LLC (NDPC) (formerly known as
Enbridge Pipelines (North Dakota) LLC), and Williston Basin
PipeLine LLC (Williston), an affiliate of MPC, entered into
an agreement to, among other things, admit Williston as a
member of NDPC. Williston will fund 37.5% of Sandpiper
construction and has the option to participate in other
growth projects (not to exceed $1.2 billion in aggregate).
As a result of Williston funding part of Sandpiper’s
construction, Williston will obtain an approximate 27%
equity interest in NDPC at the in service date of Sandpiper,
targeted for early 2016.
A petition was filed with the Federal Energy Regulatory
Commission (FERC) to approve recovery of Sandpiper’s costs
through a surcharge to the Enbridge Pipelines (North Dakota)
LLC rates between Beaver Lodge and Clearbrook and a
cost of service structure for rates between Clearbrook and
Superior. On March 22, 2013, the FERC denied the petition
on procedural grounds. EEP plans to re-file its petition with
modifications to address the FERC’s concerns. Furthermore,
in November 2013, EEP announced an open season to
solicit commitments from shippers for capacity created by
Sandpiper. The open season closed in late January 2014 with
the receipt of a further capacity commitment which can be
accommodated within the planned incremental capacity
identified above. The pipeline is expected to begin service
in early 2016, subject to obtaining regulatory and other
approvals, as well as finalization of scope.
Growth Projects – Other
Projects Under Development
The following projects have been announced by the
Company, but have not yet met Enbridge’s criteria to be
classified as commercially secured. The Company also has
significant additional attractive projects under development
which have not yet progressed to the point of public
announcement. In its long-term funding plans, the Company
makes full provision for all commercially secured projects
and makes provision for projects under development based
on an assessment of the aggregate securement success
anticipated. Actual securement success achieved could
exceed or fall short of the anticipated level.
Liquids Pipelines
Eastern Gulf Crude Access Pipeline
The memorandum of understanding (MOU) between the
Company and Energy Transfer Partners, L.P. has expired
and the Company no longer has the right to acquire an
interest in the Eastern Gulf Crude Access Pipeline.
The proposed project would have provided access to
the eastern Gulf Coast refinery market from the Patoka,
Illinois hub. The MOU expired without satisfaction of its
condition with respect to throughput commitments and
FERC approval of conversion from natural gas service to
crude oil of certain segments of pipeline that are currently
62 Enbridge Inc. 2013 Annual Report
in operation. The Company believes there is demand for
transportation service from the United States midwest to the
eastern Gulf Coast refinery market and will continue to assess
future opportunities to meet potential shipper needs, including
a revised Eastern Gulf Crude Access Pipeline joint venture.
Northern Gateway Project
Northern Gateway involves constructing a twin
1,177-kilometre (731-mile) pipeline system from near
Edmonton, Alberta to a new marine terminal in Kitimat,
British Columbia. One pipeline would transport crude oil for
export from the Edmonton area to Kitimat and is proposed
to be a 36-inch diameter line with an initial capacity of
525,000 bpd. The other pipeline would be used to transport
imported condensate from Kitimat to the Edmonton area
and is proposed to be a 20-inch diameter line with an initial
capacity of 193,000 bpd.
In 2010, Northern Gateway submitted an application to the
NEB and the Joint Review Panel (JRP) was established to
review the proposed project, pursuant to the NEB Act and
the Canadian Environmental Assessment Act. The JRP had a
broad mandate to assess the potential environmental effects
of the project and to determine if development of Northern
Gateway was in the public interest.
On December 19, 2013, the JRP issued its report on Northern
Gateway. The report found that the petroleum industry is a
significant driver of the Canadian economy and an important
contributor to the Canadian standard of living. The JRP found
that the potential economic effects of Northern Gateway on
local, regional, and national economics would be positive and
would likely be significant. The JRP is also of the view that the
Company’s commitments break new ground by providing an
unprecedented level of long-term economic, environmental,
and social benefits to Aboriginal groups. It noted that the
benefits of Northern Gateway outweigh its burdens and that
“Canadians would be better off with the Enbridge Northern
Gateway Project than without it.”
The JRP found that Northern Gateway provided appropriate
and effective opportunities for the public and potentially-
affected parties to learn about the project and to provide
their views and concerns to the Company. The JRP was
satisfied that Northern Gateway considered, and was
responsive to, the input it received regarding the design,
construction, and operation of the project.
The JRP found Northern Gateway applied a careful and
precautionary approach to its environmental assessment and
that Northern Gateway had presented a level of engineering
design information that met, or exceeded, regulatory
requirements for a thorough and comprehensive review
in terms of whether or not it can construct and operate
the project in a safe and responsible manner that protects
people and the environment. The JRP found that Northern
Gateway followed good engineering practice in determining
a route that avoids or minimizes exposure to geohazards,
had taken all reasonable steps to design a project that would
minimize risks of project malfunctions and accidents due to
naturally occurring events and that mandatory and voluntary
measures outlined by the Company would reduce the
potential for human error to the greatest extent possible.
The JRP also referenced the conclusions of the TERMPOL
committee and the evidence of various expert witnesses
appearing on behalf of Northern Gateway and the Government
of Canada in its assessment of the safety of marine transport
and concluded that shipping along the north coast of British
Columbia could be accomplished safely the vast majority
of the time even in the absence of many of the mitigation
measures that would be in place for Northern Gateway.
These additional mitigation measures would include reduced
vessel speeds, escort tugs, redundant navigational systems
and avoiding congestion in the narrower parts of the shipping
channels. The JRP noted Northern Gateway’s commitments
represent a substantial increase in spill response capabilities
beyond those required by existing legislation and currently
existing on the west coast of British Columbia, that they are
based on international best practice and continual advances
in technology and spill response planning.
The JRP included an appendix with 209 conditions that
the JRP recommended be included in any certificate that
was issued.
The JRP recommended to the Governor in Council that
certificates of public convenience and necessity for the
oil and condensate pipelines, incorporating the terms and
conditions in their report, be issued to Northern Gateway
pursuant to Part III of the NEB Act. The Government of
Canada will now consult with Aboriginal groups on the JRP
report and its recommendations prior to making a decision
on whether to direct the NEB to issue the certificates for the
pipelines. Of the 45 Aboriginal groups eligible to participate
as equity owners, 26 have signed up to do so. The Governor
in Council’s decision is expected in June 2014.
The cost estimate included in the Northern Gateway filing
with the JRP reflects a preliminary estimate prepared in
2004 and escalated to 2010. A detailed estimate based on
full engineering analysis of the pipeline route and terminal
location is currently being prepared. The detailed estimate
will reflect a larger proportion of high cost terrain, longer
tunnelling requirements and more extensive terminal
site rock excavation than provided for in the preliminary
estimate, which is expected to result in a significant increase
in the cost estimate. The revised estimate is anticipated to be
completed in the first quarter of 2014.
Five applications for judicial review have been filed with the
Federal Court and the Federal Court of Appeal; three from
Aboriginal groups and two from environmental groups.
The applications seek to set aside the findings of the JRP and
prohibit the Federal Government from taking any action to
enable the project to proceed.
Management’s Discussion and Analysis 63
Gas Pipelines, Processing and Energy Services
NEXUS Gas Transmission Project
In 2012, Enbridge, DTE Energy Company (DTE) and Spectra
Energy Corp (Spectra) announced the execution of a MOU
to jointly develop the NEXUS Gas Transmission System
(NEXUS), a project that would move growing supplies
of Ohio Utica shale gas to markets in the United States
midwest, including Ohio and Michigan, and Ontario,
Canada. The proposed NEXUS project would originate in
northeastern Ohio, include approximately 400 kilometres
(250 miles) of large diameter pipe, and be capable of
transporting one billion cubic feet per day (bcf/d) of natural
gas. The line would follow existing utility corridors to an
interconnect in Michigan and utilize the existing Vector
pipeline to reach the Ontario market. Upon completion,
Spectra would become a 20% owner in Vector, a joint
venture between DTE and Enbridge. The partners continue
to monitor Utica shale development progress, awaiting
increased interest by producers in accessing the Ohio/
Michigan/Ontario market.
Subject to continued commercial support, regulatory and
other approvals and adequately addressing landowner and
local community concerns (including those of Aboriginal
communities), the Company currently estimates that
Northern Gateway could be in service in 2018 at the earliest.
The timing and outcome of judicial reviews could also impact
the start of construction or other project activities, which
may lead to a delay in the start of operations beyond the
current forecast.
Expenditures to date, which relate primarily to the
regulatory process, are approximately $0.4 billion, of which
approximately half is being funded by potential shippers on
Northern Gateway. Given the many uncertainties surrounding
Northern Gateway, including final ownership structure,
the potential financial impact of the project cannot be
determined at this time.
The JRP posts public filings related to
Northern Gateway on its website at
gatewaypanel.review-examen.gc.ca/clf-nsi/hm-eng.html
and Northern Gateway also maintains a website at
northerngateway.ca where the full regulatory application
submitted to the NEB, the 2010 Enbridge Northern Gateway
Community Social Responsibility Report and the December
19, 2013 Report of the JRP on the Northern Gateway
Application are available. None of the information contained
on, or connected to, the JRP website or the Northern Gateway
website is incorporated in or otherwise part of this MD&A.
64 Enbridge Inc. 2013 Annual Report
Liquids Pipelines
Earnings
(millions of Canadian dollars)
Canadian Mainline
Regional Oil Sands System
Southern Lights Pipeline
Seaway Pipeline
Spearhead Pipeline
Feeder Pipelines and Other
Adjusted earnings
Canadian Mainline – changes in unrealized derivative fair value gains/(loss)
Canadian Mainline – Line 9 tolling adjustment
Canadian Mainline – shipper dispute settlement
Regional Oil Sands System – leak remediation and long-term pipeline stabilization costs
Regional Oil Sands System – make-up rights adjustment
Regional Oil Sands System – make-up rights out-of-period adjustment
Regional Oil Sands System – long-term contractual recovery out-of-period adjustment, net
Regional Oil Sands System – prior period adjustment
Regional Oil Sands System – asset impairment write-off
Spearhead Pipeline – changes in unrealized derivative fair value gains
2013
2012
2011
460
170
49
48
31
12
770
(268)
–
–
(56)
(13)
(37)
31
–
–
–
432
110
42
24
37
10
655
42
6
–
–
–
–
–
(6)
–
–
336
111
41
(3)
17
(1)
501
(48)
10
14
–
–
–
–
–
(8)
1
Earnings attributable to common shareholders
427
697
470
Liquids Pipelines adjusted earnings were $770 million in 2013 compared with adjusted
earnings of $655 million in 2012 and $501 million in 2011. The Company continued
to realize growth on Canadian Mainline primarily from strong supply from western
Canada and the ongoing effect of crude oil price differentials whereby demand
for discounted crude by United States midwest refiners remained high and drove
increases in throughput on the Canadian Mainline. New assets placed into service on
Regional Oil Sands System and expanded available capacity on Seaway Pipeline also
contributed to adjusted earnings growth.
Liquids Pipelines Earnings
(millions of Canadian dollars)
1
7
9
6
5
5
6
0
7
7
1
7
2
4
Liquids Pipelines earnings were impacted by the following adjusting items:
• Canadian Mainline earnings for each period reflected changes in unrealized
fair value gains and losses on derivative financial instruments used to manage
risk exposures inherent within the CTS, namely foreign exchange, power cost
variability and allowance oil commodity prices.
2
5
4
4
4
5
4
1
2
1
5
2
9
4
1
0
5
1
0
7
4
• Canadian Mainline earnings for 2012 and 2011 included a Line 9 tolling adjustment
related to services provided in prior periods.
• Canadian Mainline earnings for 2011 included the settlement of a shipper dispute
related to oil measurement adjustments in prior years.
• Regional Oil Sands System earnings for 2013 included a charge related to the Line
37 crude oil release which occurred in June 2013. See Liquids Pipelines – Regional
Oil Sands System – Line 37 Crude Oil Release.
• Regional Oil Sands System earnings for 2013 included an adjustment to recognize
revenue for certain long-term take-or-pay contracts ratably over the contract
life. Make-up rights are earned when minimum volume commitments are not
utilized during the period but under certain circumstances can be used to offset
overages in future periods, subject to expiry periods. Generally, under such
take-or-pay contracts, payments are received ratably over the life of the contract
as capacity is provided, regardless of volumes shipped, and are non-refundable.
09
10
11
12
13
■ GAAP Earnings
■ Adjusted Earnings
1 Financial information has been
extracted from financial statements
prepared in accordance with
U.S. GAAP.
2 Financial information has been
extracted from financial statements
prepared in accordance with
Canadian GAAP.
Management’s Discussion and Analysis 65
Should make-up rights be utilized in future periods, costs associated with such transportation service are
typically passed through to shippers, such that little or no cost is borne by Enbridge. As such, adjusted
earnings reflect contributions from these contracts ratably over the life of the contract, consistent with
contractual cash payments under the contract.
• Regional Oil Sands System earnings for 2013 included an out-of-period, non-cash adjustment to defer
revenues associated with make-up rights earned under certain long-term take-or-pay contracts.
• Regional Oil Sands System earnings for 2013 included an out-of-period, non-cash adjustment to correct
deferred income tax expense and to correct the rate at which deemed taxes are recovered under a long-
term contract.
• Regional Oil Sands System earnings for 2012 included a revenue recognition adjustment related to
prior periods.
• Regional Oil Sands System earnings for 2011 included the write-off of development expenditures on certain
project assets.
• Spearhead Pipeline earnings for 2011 included unrealized fair value gains on derivative financial instruments
used to manage exposures to allowance oil commodity prices.
Liquids Pipelines
Norman Wells
NW System
Zama
Waupisoo
Pipeline
Edmonton
Hardisty
Fort McMurray
Athabasca System
Blaine
Olympic Pipeline
Enbridge System
Portland
Gretna
Frontier Pipeline
Salt Lake City
Casper
Montreal
Toronto
Chicago
Buffalo
Sarnia
Toledo
Spearhead Pipeline
Chicap Pipeline
Patoka
Cushing
Mustang Pipeline
Ozark Pipeline
Seaway Crude
Pipeline System
66 Enbridge Inc. 2013 Annual Report
Canadian Mainline
The mainline system is comprised of Canadian Mainline and
the Lakehead System (the portion of the mainline in the United
States that is managed by Enbridge through its subsidiaries).
Enbridge has operated, and frequently expanded, the mainline
system since 1949. Through six adjacent pipelines, with a
combined design operating capacity of approximately 2.5
million bpd, which cross the Canada/United States border
near Gretna, Manitoba and Neche, North Dakota, the system
transports various grades of crude oil and diluted bitumen
from western Canada to the midwest region of the United
States and eastern Canada. Also included in Canadian
Mainline are two crude oil pipelines and one refined products
pipeline located in eastern Canada.
Competitive Toll Settlement
Canadian Mainline tolls are governed by the 10-year
settlement reached between Enbridge and shippers on
its mainline system and approved by the NEB in 2011.
The CTS, which took effect on July 1, 2011, covers local tolls
to be charged for service on the mainline system (with the
exception of Lines 8 and 9). Under the terms of the CTS,
the initial Canadian Local Toll (CLT), applicable to deliveries
within western Canada, was based on the 2011 Incentive
Tolling Settlement (ITS) toll, subsequently adjusted by 75%
of the Canada Gross Domestic Product at Market Price Index
on July 1 of each year.
The CTS also provides for an International Joint Tariff (IJT)
for crude oil shipments originating in Canada on the mainline
system and delivered in the United States off the Lakehead
System, and into eastern Canada. The IJT, which is based on
a fixed toll for the term of the settlement that was negotiated
between Enbridge and shippers, will be adjusted annually by
the same factor as the CLT.
In limited circumstances the shippers or Enbridge may
elect to renegotiate the toll. If a renegotiation of the toll
is triggered, Enbridge and the shippers will meet and use
reasonable efforts to agree on how the CTS can be amended
to accommodate the event.
Local tolls for service on the Lakehead System will not be
affected by the CTS and will continue to be established
pursuant to EEP’s existing toll agreements. Under the terms of
the IJT agreement between Enbridge and EEP, the Canadian
Mainline’s share of the IJT toll relating to pipeline transportation
of a batch from any western Canada receipt point to the United
States border is equal to the IJT toll applicable to that batch’s
United States delivery point less the Lakehead System’s local
toll to that delivery point. This amount is referred to as the
Canadian Mainline IJT Residual Benchmark Toll.
The IJT is designed to provide mainline shippers with a
stable and competitive long-term toll, preserving and
enhancing throughput on both the Canadian Mainline and
Lakehead System. Earnings under the CTS are subject to
variability in volume throughput, as well as capital and
operating costs, and the United States dollar exchange rate.
The Company may utilize derivative financial instruments
to hedge foreign exchange rate risk on United States dollar
denominated revenues and commodity price risk resulting
from exposure to crude oil and power prices.
Incentive Tolling
Prior to the CTS taking effect on July 1, 2011, tolls on Canadian
Mainline were governed by various agreements which were
subject to NEB approval. These agreements included both
the 2011 and 2010 ITS applicable to the Canadian Mainline
(excluding Lines 8 and 9), the Terrace agreement, the SEP
II Risk Sharing agreement, the Alberta Clipper agreement
and the Southern Access Expansion agreement which were
recovered via the Mainline Expansion Toll.
Results of Operations
Canadian Mainline adjusted earnings were $460 million for the
year ended December 31, 2013 compared with $432 million for
the year ended December 31, 2012 and $336 million for the year
ended December 31, 2011. The adjusted earnings increase was
primarily driven by higher throughput from steady production
from the oil sands in Alberta priced at levels which displaced
other non-Canadian production from the midwest market
and drove increased long-haul barrels on Canadian Mainline.
Further volume growth on Canadian Mainline was limited
towards the latter half of 2013 due to longer than expected
refinery shutdowns and the delay in the start-up of a refinery
conversion to heavy oil. The tempered growth in demand from
refineries is expected to persist during the first quarter of 2014.
Partially offsetting increased throughput in 2013 was a lower
Canadian Mainline IJT Residual Benchmark Toll effective
April 1, 2013 compared with the corresponding 2012 period.
Changes in the Canadian Mainline IJT Residual Benchmark
Toll are inversely correlated to the Lakehead System Local
Toll which was higher due to increased costs in relation to
EEP’s growth projects which will be recovered through the
Lakehead System’s rate structure. Also negatively impacting
2013 adjusted earnings was an increase in power costs due to
higher throughput, as well as higher depreciation and interest
expense. Finally, income tax expense, which reflected current
income taxes only, was lower due to higher available tax
deductions from a larger asset base, including software.
The comparability of Canadian Mainline earnings
between 2012 and 2011 is affected by the change in tolling
methodology. As noted previously, from July 1, 2011 onward,
Canadian Mainline earnings (excluding Lines 8 and 9) were
governed by the CTS, whereas operations for the first six
months of 2011 were governed by a series of agreements,
the most significant being the ITS applicable to the mainline
system and the Terrace and Alberta Clipper agreements.
Management’s Discussion and Analysis 67
Canadian Mainline revenues for the year ended December 31, 2012 reflected increased volumes and
a higher Canadian Mainline IJT Residual Benchmark Toll. Volume throughput in 2012 was impacted by
market conditions as incremental oil sands crude production in Alberta and strong production growth
out of the Bakken in North Dakota bolstered supply to midwest markets and placed increased downward
pressure on crude oil prices in that market. This discounted crude oil, coupled with strong refining
margins, increased demand in the midwest for Canadian and Bakken crude oil supply and drove increased
long haul barrels on Canadian Mainline and EEP’s Lakehead System. However, during the fourth quarter
of 2012, Canadian Mainline was not able to capture the full throughput benefit of the increased supply
available to it due to capacity limitations which arose from pressure restrictions being applied to certain
lines pending completion of inspection and repair programs. An increase in operating and administrative
costs, primarily due to higher employee related costs and higher leak remediation costs, also impacted
2012 adjusted earnings.
Supplemental information on Canadian Mainline adjusted earnings for the years ended December
31, 2013 and 2012 and for the six month period from July 1, 2011, the effective date of the CTS, to
December 31, 2011 are as follows:
(millions of Canadian dollars)
Revenues
Expenses
Operating and administrative
Power
Depreciation and amortization
Other income/(expense)
Interest expense
Income taxes
Adjusted earnings
Year ended December 31,
Six months ended December 31,
2013
2012
2011
1,434
1,367
407
122
244
773
661
3
(162)
502
(42)
460
382
112
219
713
654
(4)
(131)
519
(87)
432
618
194
54
104
352
266
5
(66)
205
(31)
174
Effective United States to Canadian dollar exchange rate1
0.999
0.971
0.972
December 31,
(United States dollars per barrel)
IJT Benchmark Toll2
Lakehead System Local Toll3
Canadian Mainline IJT Residual Benchmark Toll4
2013
2012
2011
$3.98
$2.18
$1.80
$3.94
$1.85
$2.09
$3.85
$2.01
$1.84
1
2
3
4
Inclusive of realized gains or losses on foreign exchange derivative financial instruments.
The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted
toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil.
Effective July 1, 2013, the IJT Benchmark Toll increased from US$3.94 to US$3.98.
The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois.
Effective July 1, 2012, this toll increased from US$1.76 to US$1.85 and effective April 1, 2013, it subsequently increased to US$2.13.
Effective July 1, 2013, this toll increased from US$2.13 to US$2.18.
The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba.
Effective April 1, 2013, this toll decreased from US$2.09 to US$1.81 and, effective July 1, 2013, this toll decreased from US$1.81 to US$1.80.
For any shipment, this toll is the difference between the IJT Benchmark Toll for that shipment and the Lakehead System Local Toll for that shipment.
Throughput Volume1
2013
2012
2011
Q1
1,783
1,687
1,602
Q2
1,604
1,659
1,457
Q3
1,736
1,617
1,565
Q4
1,827
1,622
1,594
Total
1,737
1,646
1,554
1
Throughput, presented in thousand barrels per day, represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and
eastern Canada deliveries entering the mainline in western Canada.
68 Enbridge Inc. 2013 Annual Report
Canadian Mainline –
Average Deliveries
(thousands of barrels per day)
7
3
7
,
1
6
4
6
,
1
2
6
5
,
1
7
3
5
,
1
4
5
5
,
1
Canadian Mainline revenues include the portion of the system covered by the
CTS as well as revenues from Lines 8 and 9 in eastern Canada. Lines 8 and 9 are
currently tolled on a separate basis and comprise a relatively small proportion of
total Canadian Mainline revenues. CTS revenues include transportation revenues,
the largest component, as well as allowance oil and revenues from receipt
and delivery charges. Transportation revenues include revenues for volumes
delivered off the Canadian Mainline at Gretna and on to the Lakehead System,
to which Canadian Mainline IJT residual tolls apply, and revenues for volumes
delivered to other western Canada delivery points, to which the CLT applies.
Despite the many factors which affect Canadian Mainline revenues, the primary
determinants of those revenues will be throughput volume ex-Gretna, the United
States dollar Canadian Mainline IJT Residual Benchmark Toll and the effective
foreign exchange rate at which resultant revenues are converted into Canadian
dollars. The Company currently utilizes derivative financial instruments to
hedge foreign exchange rate risk on United States dollar denominated revenues.
The exact relationship between the primary determinants and actual Canadian
Mainline revenues will vary somewhat from quarter to quarter but is expected to
be relatively stable on average for a year, absent a systematic shift in receipt and
delivery point mix or in crude oil type mix.
The largest components of operating and administrative expense are employee
related costs, pipeline integrity, repairs and maintenance, rents and leases and
property taxes. Operating and administrative costs are relatively insensitive to
throughput volumes. The primary drivers of future increases in operating costs are expected to be
normal escalation in wage rates, prices for purchased services, the addition of new facilities and more
extensive integrity, ORM and maintenance programs.
09
10
11
12
13
Power, the most significant variable operating cost, is subject to variations in operating conditions,
including system configuration, pumping patterns and pressure requirements; however, the primary
determinants of this cost are the power prices in various jurisdictions and throughput volume.
The relationship of power consumption to throughput volume is expected to be roughly proportional
over a moderate range of volumes. The Company currently utilizes derivative financial instruments to
hedge power prices.
Depreciation and amortization expense will adjust over time as a result of additions to property, plant
and equipment due to new facilities, including integrity capital expenditures.
Canadian Mainline income taxes reflect current income taxes only. Under the CTS, the Company
retains the ability to recover deferred income taxes under an NEB order governing flow-through
income tax treatment and, as such, an offsetting regulatory asset related to deferred income taxes is
recognized as incurred.
The preceding financial overview includes expectations regarding future events and operating
conditions that the Company believes are reasonable based on currently available information;
however, such statements are not guarantees of future performance and are subject to change.
Prior to the implementation of the CTS, revenues on the Canadian Mainline were recognized in a
manner consistent with the underlying agreements as approved by the regulator, in accordance with
rate-regulated accounting. The Company discontinued the application of rate-regulated accounting
to its Canadian Mainline (excluding Lines 8 and 9) on a prospective basis commencing July 1, 2011.
A regulatory asset of approximately $470 million related to deferred income taxes recorded at the date
of discontinuance continued to be recognized as the Company retains the ability to recover deferred
income taxes under an NEB order governing flow-through income tax treatment. The regulatory asset
balance at the date of discontinuance related to tolling deferrals recognized in prior periods was being
recovered through a surcharge to the CLT and IJT.
Management’s Discussion and Analysis 69
Regional Oil Sands System
Regional Oil Sands System includes two long haul pipelines,
the Athabasca Pipeline and the Waupisoo Pipeline and two
large terminals: the Athabasca Terminal located north of
Fort McMurray, Alberta and the Cheecham Terminal, located
70 kilometres (45 miles) south of Fort McMurray where the
Waupisoo Pipeline initiates. The Regional Oil Sands System
also includes the Wood Buffalo Pipeline and Woodland
Pipeline which provide access for oil sands production from
near Fort McMurray to the Cheecham Terminal as well as a
variety of other facilities such as the MacKay River, Christina
Lake, Surmont and Long Lake laterals and related facilities.
Regional Oil Sands System
Wood Buffalo Pipeline
Woodland Pipeline
Waupisoo Pipeline
Edmonton
Fort McMurray
Cheecham
Athabasca Pipeline
Hardisty
The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic
and heavy oil pipeline, built in 1999, which links the Athabasca
oil sands in the Fort McMurray region to a pipeline hub at
Hardisty, Alberta. In March 2013, the Athabasca Pipeline’s
capacity was increased to 430,000 bpd and in December
2013 was further expanded to 570,000 bpd, depending on the
viscosity of crude being shipped. The Company has a long-
term (30-year) take-or-pay contract with the major shipper on
the Athabasca Pipeline which commenced in 1999. Revenues are recorded based on the contract terms
negotiated with the major shipper, rather than the cash tolls collected.
Calgary
Kerrobert
The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered service
in 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline
initiates at Enbridge’s Cheecham Terminal and terminates at its Edmonton Mainline Terminal. The pipeline
had an initial design capacity, dependent on crude slate, of up to 350,000 bpd. The pipeline was further
expanded to 415,000 bpd in the fourth quarter of 2012 and can ultimately be expanded to 600,000 bpd.
Enbridge has a long-term (25-year) take-or-pay commitment with multiple shippers on the Waupisoo
Pipeline who collectively have contracted for approximately three-quarters of the capacity.
Prior to December 10, 2012 Regional Oil Sands System included the Hardisty
Storage Caverns which included four salt caverns totalling 3.5 million barrels of
storage capacity. The capacity at the facilities is fully subscribed under long-term
contracts that generate revenues from storage and terminalling fees. Along with
the Hardisty Contract Terminals, the Hardisty Storage Caverns were transferred to
the Fund in December 2012. See Sponsored Investments – Enbridge Income Fund –
Crude Oil Storage and Renewable Energy Transfers for details of the transfer.
Results of Operations
Adjusted earnings for the year ended December 31, 2013 were $170 million
compared with $110 million for the year ended December 31, 2012. The increase
in adjusted earnings was due to higher contracted volumes on the Athabasca
pipeline, higher capital expansion fees on the Waupisoo pipeline and earnings
from new assets placed into service in late 2012, including the Woodland and
Wood Buffalo pipelines. Partially offsetting these earnings increases were higher
operating and administrative costs, higher depreciation expense due to the
commissioning of new assets and the absence of Hardisty Caverns earnings
following the sale to the Fund in the fourth quarter of 2012.
Adjusted earnings for the year ended December 31, 2012 were $110 million
compared with $111 million for the year ended December 31, 2011. Higher shipped
volumes and increased tolls on certain laterals, and higher earnings from an
annual escalation in storage and terminalling fees were more than offset by higher
operating and administrative expense, and higher depreciation expense. Adjusted
earnings for 2012 also included contributions from new regional infrastructure, the
70 Enbridge Inc. 2013 Annual Report
Regional Oil Sands System –
Average Deliveries
(thousands of barrels per day)
3
3
5
4
1
4
4
3
3
1
9
2
9
5
2
09
10
11
12
13
Woodland and Wood Buffalo pipelines, placed into service
in the fourth quarter of 2012, although offset by a lack of
earnings from assets sold to the Fund in December 2012.
Line 37 Crude Oil Release
On June 22, 2013, Enbridge reported a release of light
synthetic crude oil on its Line 37 pipeline approximately two
kilometres north of Enbridge’s Cheecham Terminal, which
is located approximately 70 kilometres (45 miles) southeast
of Fort McMurray, Alberta. Line 37 is part of Regional Oil
Sands System and connects facilities in the Long Lake area
to the Cheecham Terminal. The Company estimated the
volume of the release at approximately 1,300 barrels, caused
by unusually high water levels in the region which triggered
ground movement on the right-of-way. The oil released from
Line 37 was recovered and on July 11, 2013 Line 37 returned
to service at reduced operating pressure. Normal operating
pressure was restored on Line 37 on July 29, 2013 after
finalization of geotechnical analysis.
As a precaution, on June 22, 2013 the Company shut down
the pipelines that share a corridor with Line 37, including the
Athabasca, Waupisoo, Wood Buffalo and Woodland pipelines.
The southern segment of the Athabasca pipeline was returned
to service at normal pressure on June 23, 2013, with the
northern segment resuming service on June 30, 2013 at
reduced operating pressure following completion of extensive
engineering and geotechnical analysis. Full service on the
northern segment of the Athabasca pipeline was restored
on July 11, 2013. The Waupisoo pipeline between Cheecham
and Edmonton restarted on June 25, 2013 at normal
operating pressure. The Wood Buffalo pipeline was restarted
on July 2, 2013 at reduced pressure pending completion
of further geotechnical analysis in the incident area and,
on July 19, 2013, the Wood Buffalo pipeline was returned to
normal operating pressure. The Woodland pipeline had been
in the process of linefill at the time of the shutdown; linefill
activities were completed in the third quarter of 2013.
The costs expected to be incurred in connection with this
incident are approximately $56 million after-tax and before
insurance recoveries. Lost revenue associated with the
shutdown of Line 37 and the pipelines sharing a corridor with
Line 37 was minimal. Enbridge carries liability insurance for
sudden and accidental pollution events and expects to be
reimbursed for its covered costs, subject to a $10 million
deductible. The integrity and stability costs associated
with remediating the impact of the high water levels are
precautionary in nature and not covered by insurance.
Enbridge expects to record receivables for amounts claimed
for recovery pursuant to its insurance policies during the
period that it deems realization of the claim for recovery to
be probable. Federal and provincial governmental agencies
have initiated investigations into the Line 37 crude oil release
and costs estimates exclude any potential fines or penalties.
Southern Lights Pipeline
The 180,000 bpd, 20-inch diameter Southern Lights Pipeline
was placed into service on July 1, 2010 transporting diluent
from Chicago, Illinois to Edmonton, Alberta. Enbridge
receives tariff revenues under long-term contracts with
committed shippers. Tariffs provide for recovery of all
operating and debt financing costs plus a return on equity
(ROE) of 10%. Uncommitted volumes, up to a specified
amount, generate tariff revenues that are fully credited to
all shippers. Enbridge retains 25% of uncommitted tariff
revenues on volumes above the specified amount, with the
remainder being credited to shippers.
Results of Operations
Southern Lights earnings increased to $49 million for the
year ended December 31, 2013 compared with $42 million
for the year ended December 31, 2012 and $41 million
for the year ended December 31, 2011 primarily due to
higher recovery of negotiated depreciation rates in 2013
transportation tolls.
Seaway Pipeline
In 2011, Enbridge acquired a 50% interest in the
1,078-kilometre (670-mile) Seaway Pipeline including the
805-kilometre (500-mile), 30-inch diameter long-haul system
from Cushing, Oklahoma to Freeport, Texas, as well as the
Texas City Terminal and Distribution System which serves
refineries in the Houston and Texas City areas. The Seaway
Pipeline also includes 6.8 million barrels of crude oil tankage
on the Texas Gulf Coast.
The reversal of the Seaway Pipeline, enabling it to transport
crude oil from the oversupplied hub in Cushing, Oklahoma to
the Gulf Coast, was completed in May 2012, providing initial
capacity of 150,000 bpd. In January 2013, the completion of
further pump station additions and modifications increased
the capacity available to shippers to up to 400,000 bpd,
depending on crude slate. Actual throughput experienced in
2013 was curtailed due to constraints on third party takeaway
facilities. A lateral from the Seaway Jones Creek facility to
the ECHO Terminal in Houston, Texas, completed in January
2014, is expected to eliminate these constraints. Spot volumes
on Seaway Pipeline can also be impacted by the spread
between WTI and Louisiana Light Sweet crude oil prices.
Seaway Pipeline filed an application for market-based rates in
December 2011. Initially the FERC rejected the application in
March 2012 and Seaway Pipeline appealed to the District of
Columbia Circuit. In response, the FERC set the application
for further proceedings and the appeal was stayed. Since
the FERC had not issued a ruling on this application, Seaway
Pipeline filed for initial rates in order to have rates in effect by
the in-service date. The uncommitted rate on Seaway Pipeline
was challenged by several shippers. During the evidentiary
stage, FERC staff filed evidence stating that the committed
Management’s Discussion and Analysis 71
and uncommitted rates are subject to review and adjustment. Seaway Pipeline filed a Petition for
Declaratory Order (PDO) requesting the FERC confirm that it will honour and uphold contracts. The FERC
issued a decision denying the PDO on procedural grounds but stated that it will uphold its longstanding
policy of honouring contracts.
FERC hearings concluded with all parties filing their respective briefs. In September 2013, a decision from
the Administrative Law Judge (ALJ) was released finding that the uncommitted and committed rates on
Seaway Pipeline should be reduced to reflect the ALJ’s findings on the various cost of service inputs.
Seaway Pipeline filed a brief with the FERC on October 15, 2013 challenging the ALJ’s decision and asking
for expedited ruling by the FERC on the committed rates. There is no prescribed time line for a ruling from
the FERC.
Results of Operations
Seaway Pipeline earnings for the year ended December 31, 2013 were $48 million compared with
earnings of $24 million for the year ended December 31, 2012. The higher contribution reflected a full
year of operations and incremental available capacity on the pipeline in 2013. The Seaway Pipeline
reversal was completed in May 2012 providing initial capacity of 150,000 bpd. In January 2013,
the completion of further pump station additions and modifications increased the capacity available
to shippers to up to 400,000 bpd, depending on crude slate. As noted above, actual throughput
experienced in 2013 was curtailed due to constraints on third party takeaway facilities and during the
latter part of the year due to loss of spot volume shipments as a result of a lower spread between crude
oil prices at Cushing, Oklahoma and the Gulf Coast. These takeaway constraints are anticipated to be
relieved in the first quarter of 2014. Partially offsetting the earnings increase was higher financing costs
and higher depreciation expense from an increased asset base.
Seaway Pipeline earnings for the year ended December 31, 2012 were $24 million and reflected
preliminary service at an approximate capacity of 150,000 bpd which commenced in May 2012.
The $3 million loss recognized for the year ended December 31, 2011 was related to early stage
business development costs that were not eligible for capitalization.
Spearhead Pipeline
Spearhead Pipeline delivers crude oil from the Flanagan, Illinois delivery point of
the Lakehead System to Cushing, Oklahoma. The pipeline was originally placed
into service in March 2006 and an expansion was completed in May 2009,
increasing capacity from 125,000 bpd to 193,300 bpd.
Spearhead Pipeline –
Average Deliveries
(thousands of barrels per day)
Initial committed shippers and expansion shippers currently account for more
than 70% of the 193,300 bpd capacity on Spearhead. Both the initial committed
shippers and expansion shippers were required to enter into 10-year shipping
commitments at negotiated rates that were offered during the open season
process. The balance of the capacity is currently available to uncommitted
shippers on a spot basis at FERC approved rates.
1
2
1
2
7
1
4
4
1
1
5
1
2
8
Results of Operations
Adjusted earnings for Spearhead Pipeline were $31 million for the year
ended December 31, 2013 compared with $37 million for the year ended
December 31, 2012. Higher contributions from increased throughput due to
higher demand at Cushing, Oklahoma for further transportation on Seaway
Pipeline to the Gulf Coast refining market were more than offset by higher
operating expenses, predominantly higher pipeline integrity expenditures.
Operating margins were also compressed in 2013 due to an increase in
power costs that resulted from transporting a mix of heavier crude.
Spearhead Pipeline adjusted earnings were $37 million for the year ended December 31, 2012 compared
with $17 million for the year ended December 31, 2011. Spearhead Pipeline adjusted earnings increased as
a result of higher volumes and tolls, partially offset by higher operating and administrative costs, including
72 Enbridge Inc. 2013 Annual Report
09
10
11
12
13
power and repairs and maintenance. Volumes significantly
increased over 2011 due to higher commodity price
differentials which increased demand at Cushing, Oklahoma
in anticipation of additional capacity on the Seaway Pipeline
for further transportation to the Gulf Coast.
in volumes transported can directly and adversely affect
revenues and earnings. Factors such as changing market
fundamentals, capacity bottlenecks, operational incidents,
regulatory restrictions, system maintenance and increased
competition can all impact the utilization of Enbridge’s assets.
Feeder Pipelines And Other
Feeder Pipelines and Other primarily includes the
Company’s 85% interest in Olympic Pipe Line Company
(Olympic), the largest refined products pipeline in the State
of Washington, transporting approximately 290,000 bpd
of gasoline, diesel and jet fuel. It also includes the NW
System, which transports crude oil from Norman Wells in
the Northwest Territories to Zama, Alberta; interests in a
number of liquids pipelines in the United States, including
the recently expanded Toledo Pipeline which connects with
the EEP mainline at Stockbridge, Michigan; and business
development costs related to Liquids Pipelines activities.
Prior to December 10, 2012, Feeder Pipelines and Other
also included the Hardisty Contract Terminals, which
is comprised of 19 tanks with a working capacity of
approximately 7.5 million barrels of storage capacity. Along
with the Hardisty Storage Caverns, the Hardisty Contract
Terminals were transferred to the Fund in December 2012.
See Sponsored Investments – Enbridge Income Fund – Crude
Oil Storage and Renewable Energy Transfers for details of
the transfer.
Results of Operations
Feeder Pipelines and Other adjusted earnings were
$12 million for the year ended December 31, 2013 compared
with $10 million for the year ended December 31, 2012.
The earnings increase was primarily attributable to higher
volumes and tolls on Olympic.
In 2012, Feeder Pipelines and Other earnings were
$10 million compared with a loss of $1 million for the year
ended December 31, 2011. The increase in earnings was
primarily a result of a higher contribution from Olympic due
to a tariff increase, higher volumes on Toledo Pipeline and
increased terminalling fees. In 2011, earnings from Toledo
Pipeline were negatively impacted by integrity work on
Lines 6A and 6B of EEP’s Lakehead System.
Business Risks
The risks identified below are specific to the Liquids
Pipelines business. General risks that affect the Company
as a whole are described under Risk Management and
Financial Instruments – General Business Risks.
Asset Utilization
Enbridge is exposed to throughput risk under the CTS on
the Canadian Mainline and under certain tolling agreements
applicable to other Liquids Pipelines assets. A decrease
Market fundamentals, such as commodity prices and price
differentials, weather, gasoline price and consumption,
alternative energy sources and global supply disruptions
outside of Enbridge’s control can impact both the supply
of and demand for crude oil and other liquid hydrocarbons
transported on Enbridge’s pipelines. However, the long-term
outlook for Canadian crude oil production indicates a growing
source of potential supply of crude oil.
Enbridge seeks to mitigate utilization risks within its
control. The market access and expansion projects under
development are expected to reduce capacity bottlenecks
and introduce new markets for customers. Liquids Pipelines
also works with the shipper community to enhance scheduling
efficiency and communications as well as makes continuous
improvements to scheduling models and timelines to alleviate
pipeline restrictions. Throughput risk is also partially mitigated
by provisions in the CTS agreement, which allows Enbridge
to negotiate an amendment to the agreement in the event
certain minimum threshold volumes are not met.
Operational and Economic Regulation
Operational regulation risks relate to failing to comply with
applicable operational rules and regulations from government
organizations and could result in fines or operating restrictions
or an overall increase in operating and compliance costs.
Regulatory scrutiny over the integrity of Liquids Pipelines
assets has the potential to increase operating costs or limit
future projects. Potential regulation upgrades and changes
could have an impact on the Company’s future earnings
and the cost related to the construction of new projects.
The Company believes operational regulation risk is mitigated
by active monitoring and consulting on potential regulatory
requirement changes with the respective regulators or
through industry associations. The Company also develops
robust response plans to regulatory changes or enforcement
actions. While the Company believes the safe and reliable
operation of its assets and adherence to existing regulations
is the best approach to managing operational regulatory
risk, the potential remains for regulators to make unilateral
decisions that could have a financial impact on the Company.
The Company’s liquids pipelines also face economic
regulatory risk. Broadly defined, economic regulation risk is
the risk regulators or other government entities change or
reject proposed or existing commercial arrangements. The
Canadian Mainline and other liquids pipelines are subject to
the actions of various regulators, including the NEB and the
FERC, with respect to the tariffs and tolls of those operations.
The changing or rejecting of commercial arrangements
Management’s Discussion and Analysis 73
could have an adverse effect on the Company’s revenues and
earnings. The Company believes that economic regulatory risk
is reduced through the negotiation of long-term agreements
with shippers which govern the majority of the segment’s assets
and the involvement of its legal and regulatory teams in the
review of new projects to ensure compliance with applicable
regulations; however, the risk that a regulator could overturn
long-term agreements between the Company and shippers
continues to exist.
Competition
Competition may result in a reduction in demand for the
Company’s services, fewer new project opportunities or
assumption of risk that results in weaker or more volatile
financial performance than expected. Competition
among existing pipelines is based primarily on the cost of
transportation, access to supply, the quality and reliability
of service, contract carrier alternatives and proximity to
markets. Other competing carriers are available to ship western
Canadian liquids hydrocarbons to markets in either Canada or
the United States. Competition also arises from existing and
proposed pipelines that provide, or are proposed to provide,
access to market areas currently served by the Company’s
liquids pipelines, such as proposed projects expected to serve
the Gulf Coast or eastern markets, as well as from proposed
projects in the Alberta regional oil sands market. Additionally,
crude oil price differentials and the long lead-times required to
build new pipeline capacity continues to make transportation
of crude oil by rail competitive where railways are able to
access markets not currently serviced by pipelines.
The Company believes that its liquids pipelines continue
to provide attractive options to producers in the WCSB
due to its competitive tolls and flexibility through its
multiple delivery and storage points. Enbridge’s current
complement of growth projects to expand market
access and its commitment to project execution is
expected to further provide shippers reliable and
long-term competitive solutions for oil transportation.
The Company’s existing right-of-way for the Canadian
Mainline also provides a competitive advantage as it can
be difficult and costly to obtain rights of way for new
pipelines traversing new areas.
Foreign Exchange and Interest Rate Risk
The CTS agreement for the Canadian Mainline exposes
the Company to risks related to movements in foreign
exchange rates and interest rates. Foreign exchange
risk arises as the Company’s IJT under the CTS is
charged in United States dollars. These risks have been
substantially managed through the Company’s hedging
program by using financial contracts to fix the prices of
United States dollars and interest rates. Certain of these
financial contracts do not qualify for cash flow hedge
accounting and, therefore, the Company’s earnings are
exposed to associated changes in the mark-to-market
value of these contracts.
74 Enbridge Inc. 2013 Annual Report
Gas Distribution
Earnings
(millions of Canadian dollars)
Enbridge Gas Distribution Inc. (EGD)
Other Gas Distribution and Storage
Adjusted earnings
EGD – gas transportation costs out-of-period adjustment
EGD – (warmer)/colder than normal weather
EGD – tax rate changes
EGD – recognition of regulatory asset
Other Gas Distribution and Storage – regulatory deferral write-off
Earnings/(loss) attributable to common shareholders
Adjusted earnings from Gas Distribution were $176 million for the year ended
December 31, 2013 compared with $176 million for 2012 and $173 million for the
year ended December 31, 2011. EGD’s operating results for 2013 are pursuant to a
one year cost of service settlement, following completion of a five year Incentive
Regulation (IR) term at the end of 2012. EGD adjusted earnings growth reflected
the positive impacts of a larger customer base and the absence of earnings
sharing with natural gas customers under the one year cost of service settlement.
In 2012, adjusted earnings from Other Gas Distribution and Storage were
negatively impacted compared with the prior year due to changes in rate setting
methodology applicable to gas distribution operations in New Brunswick.
Gas Distribution earnings were impacted by the following adjusting items:
• EGD earnings for 2013 reflected an out-of-period correction to gas
transportation costs which had previously been deferred.
• EGD earnings for all periods were adjusted to reflect the impact of weather.
• EGD earnings for 2012 reflected the impact of unfavourable tax rate changes
on deferred income tax liabilities.
• EGD earnings for 2012 included the recognition of a regulatory asset related
to recovery of other postretirement benefit obligations (OPEB) costs pursuant
to an OEB rate order. See Gas Distribution – Enbridge Gas Distribution Inc. –
Rate Application.
• Other Gas Distribution and Storage earnings for 2011 reflected the
discontinuation of rate-regulated accounting for Enbridge Gas New Brunswick
Inc. (EGNB) and the related write-off of a deferred regulatory asset and
certain capitalized operating costs, net of tax. See Gas Distribution –
Other Gas Distribution and Storage – Enbridge Gas New Brunswick Inc. –
Regulatory Matters.
2013
2012
2011
156
20
176
(56)
9
–
–
–
129
149
27
176
–
(23)
(9)
63
–
207
135
38
173
–
1
–
–
(262)
(88)
Gas Distribution Earnings
(millions of Canadian dollars)
2
6
8
1
4
5
1
2
6
1
1
0
5
1
1
7
0
2
3
7
1
6
7
1
6
7
1
1
9
2
1
1
)
8
8
(
09
10
11
12
13
■ GAAP Earnings
■ Adjusted Earnings
1 Financial information has been
extracted from financial statements
prepared in accordance with
U.S. GAAP.
2 Financial information has been
extracted from financial statements
prepared in accordance with
Canadian GAAP.
Management’s Discussion and Analysis 75
Enbridge Gas Distribution Inc.
EGD is Canada’s largest natural gas distribution company and has been in operation
for more than 160 years. It serves over two million customers in central and eastern
Ontario and parts of northern New York State. EGD’s utility operations are regulated
by the OEB and by the New York State Public Service Commission.
Rate Application
EGD’s rates for 2013 were set pursuant to an OEB approved settlement
agreement and decision (the 2013 Settlement) related to its 2013 cost of service
rate application. The 2013 Settlement retained the previous deemed equity level
but provided for an increase in the allowed ROE. The 2013 Settlement further
retained the flow-through nature of the cost of natural gas supply and several
other cost categories.
Prior to 2013, EGD operated under a revenue cap IR mechanism, calculated
on a revenue per customer basis, with the OEB for a five-year period between
2008 and 2012. Under the IR mechanism, the Company was allowed to earn and
fully retain 100 basis points (bps) over the base return. Any return over 100 bps
was required to be shared with customers on an equal basis. The earnings
sharing mechanism resulted in the return of revenue to customers of $10 million
for the year ended December 31, 2012 and $13 million for the year ended
December 31, 2011. The earnings sharing mechanism, which was previously in
effect under IR, did not apply to the 2013 Settlement.
Enbridge Gas Distribution –
Number of Active Customers
(thousands)
1
8
9
,
1
7
9
9
,
1
7
3
9
,
1
2
3
0
,
2
5
6
0
,
2
09
10
11
12
13
The 2013 Settlement established the right to recover an existing OPEB liability of approximately
$89 million ($63 million after-tax) over a 20-year time period commencing in 2013. The 2013 Settlement
further provided for OPEB and pension costs, determined on an accrual basis, to be recovered in rates.
In July 2013, EGD filed an application with the OEB for the setting of rates through a customized IR
mechanism for the period of 2014 through 2018. A decision is anticipated in the second quarter of 2014.
The objectives of the IR plan are as follows:
• reduce regulatory costs with less frequent hearings;
• provide incentives for improved efficiency;
• provide more flexibility for utility management; and
• provide for necessary infrastructure upgrades and safety and reliability projects.
Results of Operations
Adjusted earnings for the year ended December 31, 2013 were $156 million compared with
$149 million for the year ended December 31, 2012. Higher adjusted earnings reflected customer
growth, the absence of the earnings sharing under the 2013 Settlement and higher shared savings
mechanism revenue, which results from exceeding targets on delivery of energy efficiency programs.
Also favourably impacting adjusted earnings was the recovery of pension costs allowed to be passed
on to customers under the 2013 Settlement, whereas previously these costs were partially disallowed
under the 2012 IR mechanism. Partially offsetting the favourable adjusted earnings increase was lower
revenues from non-regulated operations.
Adjusted earnings for the year ended December 31, 2012 were $149 million compared with $135 million
for the year ended December 31, 2011. The increase in EGD’s adjusted earnings was primarily due to
customer growth, favourable rate variances and higher pipeline capacity optimization. This growth was
partially offset by an increase in system integrity and safety-related costs and higher employee costs,
as well as higher depreciation due to a higher in-service asset base.
76 Enbridge Inc. 2013 Annual Report
Other Gas Distribution and Storage
Other Gas Distribution includes natural gas distribution
utility operations in Quebec and New Brunswick, the most
significant being EGNB (100% owned and operated by the
Company), which owns the natural gas distribution franchise
in the province of New Brunswick. EGNB has approximately
11,000 customers and is regulated by the New Brunswick
Energy and Utilities Board (EUB).
Enbridge Gas New Brunswick Inc. – Regulatory Matters
On December 9, 2011 the Government of New Brunswick
tabled and then subsequently passed legislation related to the
regulatory process for setting rates for gas distribution within
the province. The legislation permitted the government to
implement new regulations which could affect the franchise
agreement between EGNB and the province, impact prior
decisions by the province’s independent regulator and
influence the regulator’s future decisions.
Gas Distribution
Enbridge Gas
New Brunswick
Moncton
Quebec City
Ottawa
Toronto
Montreal
Chicago
Enbridge Gas
Distribution
A final rates and tariffs regulation was subsequently
enacted by the Government of New Brunswick on April 16, 2012. Based on the amended rate setting
methodology and specific conditions outlined therein, EGNB no longer met the criteria for the
continuation of rate-regulated accounting. As a result, the Company eliminated from its Consolidated
Statements of Financial Position a deferred regulatory asset of $180 million and a regulatory asset with
respect to capitalized operating costs of $103 million, net of an income tax recovery of $21 million.
As the final rates and tariffs regulation published on April 16, 2012 provided further evidence of a
condition that existed on December 31, 2011, the charge totalling $262 million, after-tax, was reflected
as a subsequent event in the Company’s Consolidated Financial Statements for the year ended
December 31, 2011 presented in accordance with U.S. GAAP and filed in May 2012.
The Company commenced legal proceedings against the Government of New Brunswick, seeking
damages for breach of contract, in April 2012. The Company also commenced a separate application
to the New Brunswick Court of Queen’s Bench to quash the Government’s rates and tariffs regulation in
May 2012. The Company’s application was initially dismissed, but on appeal it was ultimately successful,
in part. The Court of Appeal ruled that the part of the rates and tariffs regulation that caps rates
according to a maximum revenue-to-cost ratio was beyond the regulation-making authority of the New
Brunswick Lieutenant Governor-in-Council. The Court of Appeal upheld the portion of the regulation
that requires EGNB to charge customers the lower of market or cost-based rates. As a result of this
outcome, EGNB applied on June 14, 2013 to the EUB for new rates, effective July 1, 2013, for commercial
and industrial customers. On July 26, 2013, the EUB granted EGNB’s application for new rates, but
with an effective date of August 1, 2013. The EUB’s decision enabled EGNB to fully recover its revenue
requirement from August 1, 2013 until the next rate period. Accordingly, EGNB has also indefinitely
adjourned its application for judicial review of the EUB’s original decision regarding rates to take effect
as of October 1, 2012. EGNB filed its 2014 rate application on October 1, 2013, the outcome of which will
determine rates during the next rate period, and a decision is expected in the first quarter of 2014.
On February 4, 2014, EGNB commenced a further legal proceeding against the Government of
New Brunswick. The action seeks damages for improper extinguishment of the deferred regulatory
asset that was previously eliminated from EGNB’s Consolidated Statements of Financial Position, as
discussed above. There is no assurance that any of EGNB’s legal proceedings against the Province of
New Brunswick will be successful or will result in any recovery.
Management’s Discussion and Analysis 77
Results of Operations
Natural Gas Cost Risk
Other Gas Distribution and Storage adjusted earnings were
$20 million for the year ended December 31, 2013 compared
with $27 million for the year ended December 31, 2012
and reflected lower rates from a revised rate setting
methodology that became effective October 1, 2012 in
EGNB. The earnings decrease was partially offset by new
rates that became effective August 1, 2013 which allowed
EGNB to fully recover its revenue requirement and drove
higher earnings in the second half of 2013.
Other Gas Distribution and Storage adjusted earnings were
$27 million for the year ended December 31, 2012 compared
with $38 million for the year ended December 31, 2011.
This adjusted earnings decrease was primarily due to the
change in rate setting methodology applicable to EGNB
enacted in 2012. Effective January 1, 2012, the discontinuance
of rate-regulated accounting at EGNB resulted in earnings
subject to increased variability, including quarterly
seasonality, as there was no further accumulation of
the regulatory deferral account. Earnings for 2012 were
impacted by lower volume due to a decrease in demand
for natural gas, which was the result of a warmer than
normal winter.
Business Risks
The risks identified below are specific to Gas Distribution
business. General risks that affect the Company as a
whole are described under Risk Management and Financial
Instruments – General Business Risks.
Economic Regulation
The utility operations of Gas Distribution are regulated by the
OEB and EUB among others. Regulators’ future actions may
differ from current expectations, or future legislative changes
may impact the regulatory environments in which Gas
Distribution operates. To the extent that the regulators’ future
actions are different from current expectations, the timing
and amount of recovery or refund of amounts recorded
on the Consolidated Statements of Financial Position,
or that would have been recorded on the Consolidated
Statements of Financial Position in absence of the effects
of regulation, could be different from the amounts that are
eventually recovered or refunded. The Company seeks to
mitigate economic regulation risk by maintaining regular and
transparent communication with regulators and interveners
on rate negotiations. The terms of rate negotiations are
also reviewed by the Company’s legal, regulatory and
finance teams. Specific to the 2014 IR plan negotiations, the
Company has used Alternate Dispute Resolution process
when negotiating with the regulators and interveners in order
to minimize more costly and time consuming formal hearings.
EGD does not profit from the sale of natural gas nor is it at
risk for the difference between the actual cost of natural
gas purchased and the price approved by the OEB for
inclusion in distribution rates. This difference is deferred
as a receivable from or payable to customers until the
OEB approves its refund or collection. EGD monitors the
balance and its potential impact on customers and may
request interim rate relief to recover or refund the natural
gas cost differential. While the cost of natural gas does not
impact EGD’s earnings, it does affect the amount of EGD’s
investment in gas in storage. EGNB is also subject to natural
gas cost risk as increases in natural gas prices that cannot be
charged to customers could negatively impact earnings.
Volume Risk
Since customers are billed on a volumetric basis, EGD’s
ability to collect its total revenue requirement (the cost
of providing service) depends on achieving the forecast
distribution volume established in the rate-making process.
The probability of realizing such volume is contingent upon
four key forecast variables: weather, economic conditions,
pricing of competitive energy sources and growth in the
number of customers.
Weather is a significant driver of delivery volumes, given that
a significant portion of EGD’s customer base uses natural gas
for space heating. Distribution volume may also be impacted
by the increased adoption of energy efficient technologies,
along with more efficient building construction, that
continues to place downward pressure on consumption.
In addition, conservation efforts by customers may further
contribute to a decline in annual average consumption.
Sales and transportation of gas for customers in the
residential and small commercial sectors account for
approximately 80% of total distribution volume. Sales and
transportation service to large volume commercial and
industrial customers is more susceptible to prevailing
economic conditions. As well, the pricing of competitive
energy sources affects volume distributed to these
sectors as some customers have the ability to switch to an
alternate fuel. Customer additions from all market sectors
are important as continued expansion adds to the total
consumption of natural gas.
Even in those circumstances where EGD attains its total
forecast distribution volume, it may not earn its expected
ROE due to other forecast variables such as the mix between
the higher margin residential and commercial sectors and
the lower margin industrial sector. EGNB is also subject to
volume risk as the impact of weather conditions on demand
for natural gas could result in earnings fluctuations.
78 Enbridge Inc. 2013 Annual Report
Gas Pipelines, Processing and Energy Services
Earnings
(millions of Canadian dollars)
Aux Sable
Energy Services
Alliance Pipeline US
Vector Pipeline
Enbridge Offshore Pipelines (Offshore)
Other
Adjusted earnings
Aux Sable – changes in unrealized derivative fair value gains/(loss)
Energy Services – changes in unrealized derivative fair value gains/(loss)
Offshore – asset impairment loss
Other – changes in unrealized derivative fair value gains/(loss)
Earnings/(loss) attributable to common shareholders
Adjusted earnings from Gas Pipelines, Processing and Energy Services were
$203 million for the year ended December 31, 2013 compared with $176 million
for the year ended December 31, 2012 and $180 million for the year ended
December 31, 2011. Changing market conditions has resulted in variability in
earnings for this segment as lower fractionation margins in 2013 resulted in lower
contributions from Aux Sable, while favourable market conditions gave rise to
greater margin opportunities in Energy Services in 2013. The increase in earnings
in 2013 compared with 2012 also reflected contributions from additional natural
gas midstream and renewable energy investments.
Gas Pipelines, Processing and Energy Services earnings/(loss) were impacted by
the following adjusting items:
• Aux Sable earnings for 2012 and 2011 period reflected changes in the fair value
of unrealized derivative financial instruments related to the Company’s forward
gas processing risk management position.
• Energy Services earnings/(loss) for each period reflected changes in unrealized
fair value gains and losses related to the revaluation of financial derivatives
used to manage the profitability of transportation and storage transactions
and the revaluation of inventory. A gain or loss on such a financial derivative
corresponds to a similar but opposite loss or gain on the value of the
underlying physical transaction which is expected to be realized in the future
when the physical transaction settles. Unlike the change in the value of the
financial derivative, the gain or loss on the value of the underlying physical
transaction is not recorded for financial statement purposes until the periods
in which it is realized.
2013
2012
2011
49
75
43
22
(2)
16
203
–
(206)
–
(61)
(64)
68
40
39
22
(3)
10
176
10
(537)
(105)
–
(456)
55
56
39
23
(7)
14
180
(7)
125
–
24
322
Gas Pipelines, Processing
and Energy Services Earnings
(millions of Canadian dollars)
2
8
2
4
6
1
1
1
2
2
3
0
8
1
6
7
1
1
)
6
5
4
(
3
0
2
1
)
4
6
(
1
2
3
1
0
3
1
09
10
11
12
13
■ GAAP Earnings
■ Adjusted Earnings
1 Financial information has been
extracted from financial statements
prepared in accordance with
U.S. GAAP.
2 Financial information has been
extracted from financial statements
prepared in accordance with
Canadian GAAP.
• Adjusted earnings for 2013 excluded a one-time realized loss of $58 million incurred to close out
derivative contracts used to hedge forecasted Energy Services transactions which are no longer
probable to occur.
• Offshore loss for 2012 was impacted by an asset impairment loss related to certain of its assets,
predominantly located within the Stingray and Garden Banks corridors. See Gas Pipelines,
Processing and Energy Services – Enbridge Offshore Pipelines – Asset Impairment for further details.
• Other earnings/(loss) for 2013 and 2011 reflected changes in unrealized fair value gains or losses on
derivative financial instruments. In 2013, the unrealized loss reflected the change in the value of long-
term power price derivative contracts acquired to hedge expected revenues and cash flows from
Blackspring Ridge.
Management’s Discussion and Analysis 79
Aux Sable
Enbridge owns a 42.7% interest in Aux Sable US and a
50% interest in Aux Sable Canada (collectively Aux Sable).
Aux Sable US owns and operates a NGL extraction and
fractionation plant outside Chicago, Illinois near the terminus
of Alliance. The plant extracts NGL from the liquids-rich
natural gas transported on Alliance, as necessary for Alliance
to meet gas quality specifications of downstream transmission
and distribution companies and to take advantage of positive
fractionation spreads.
Aux Sable US sells its NGL production to a single counterparty
under a long-term contract. Aux Sable receives a fixed annual
fee and a share of any net margin generated from the business
in excess of specified natural gas processing margin thresholds
(the upside sharing mechanism). In addition, Aux Sable is
compensated for all operating, maintenance and capital costs
associated with its facilities subject to certain limits on capital
costs. The counterparty supplies all make-up gas and fuel gas
requirements of the Aux Sable plant. The contract is for an
initial term of 20 years, expiring March 31, 2026, and may be
extended by mutual agreement for 10-year terms.
Aux Sable also owns and operates facilities upstream of Alliance
that deliver liquids-rich gas volumes into the pipeline for further
processing at the Aux Sable plant. These facilities include the
Palermo Conditioning Plant and the Prairie Rose Pipeline in the
Bakken area of North Dakota, owned by Aux Sable US and the
Septimus Gas Plant and the Septimus Pipeline in the Montney
area of British Columbia, owned by Aux Sable Canada.
Aux Sable Canada has contracted capacity of the Septimus
Pipeline and the Septimus Gas Plant to a producer under a
10-year take-or-pay contract which provides for a return on
and of invested capital. Actual operating costs are recovered
from the producer. In 2013, the majority of capacity at the
Palermo Gas Plant and the Prairie Rose Pipeline was contracted
to producers under take-or-pay contracts. Several producers’
contract commitments decline over the next few years while
certain producer contract commitments continue through
2020 under long-term take or pay contracts or with life-of-lease
reserve dedication. Additional revenues are earned by Aux Sable
based on a sharing of available NGL margin with producers.
Results of Operations
Aux Sable adjusted earnings for the year ended
December 31, 2013 were $49 million, a decrease
from earnings of $68 million for the year ended
December 31, 2012. The decrease was mainly due to
lower fractionation margins and lower ethane processing
volumes due to ethane rejections. Lower fractionation
margins resulted in a decrease in contributions from the
upside sharing mechanism in Aux Sable’s production sales
agreement compared with the prior year.
Aux Sable adjusted earnings were $68 million for the year
ended December 31, 2012 compared with $55 million for the
80 Enbridge Inc. 2013 Annual Report
year ended December 31, 2011. Adjusted earnings increased
primarily due to higher realized fractionation margins and
earnings contributions from the Prairie Rose Pipeline and the
Palermo Conditioning Plant acquired in July 2011.
Business Risks
The risks identified below are specific to Aux Sable.
General risks that affect the entire Company are described
under Risk Management and Financial Instruments –
General Business Risks.
Commodity Price Risk
Aux Sable’s margin earned through the upside sharing
mechanism is subject to commodity price risk arising from
the price differential between the cost of natural gas and
margins achieved from the sale of extracted NGL after the
fractionation process. These risks may be mitigated through
the Company’s risk management activities.
Asset Utilization
A decrease in gas volumes or a decrease in the NGL content
of the gas stream delivered by Alliance to the Aux Sable
plant can directly and adversely affect the margin earned
through the upside sharing mechanism. Alliance is well
positioned to deliver incremental liquids-rich gas production
from new developments in the Montney and Bakken regions,
thereby mitigating volume risk. In addition, Aux Sable
attracts liquids-rich gas to Alliance through inducement and
rich gas premium contracts with producers.
Energy Services
Energy Services provides energy supply and marketing
services to North American refiners, producers and other
customers. Crude oil and NGL marketing services are
provided by Tidal Energy. This business transacts at many
North American market hubs and provides its customers with
various services, including transportation, storage, supply
management, hedging programs and product exchanges.
Tidal Energy is primarily a physical barrel marketing company
focused on capturing value from quality, time and location
differentials when opportunities arise. To execute these
strategies, Energy Services may lease storage or rail cars,
as well as hold nomination or contractual rights on both third
party and Enbridge-owned pipelines and storage facilities.
Any commodity price exposure created from this physical
business is closely monitored and must comply with the
Company’s formal risk management policies.
Tidal Energy also provides natural gas marketing services,
including marketing natural gas to optimize commitments
on certain natural gas pipelines. To the extent transportation
costs exceed the basis (location) differential, earnings will
be negatively affected. Tidal Energy also provides natural
gas supply, transportation, balancing and storage for third
parties, leveraging its natural gas marketing expertise and
access to transportation capacity.
Results of Operations
Energy Services adjusted earnings were $75 million for the year ended December 31, 2013, an increase over
adjusted earnings of $40 million for the year ended December 31, 2012. Adjusted earnings from Energy
Services are dependent on market conditions, including but not limited to, quality, time and location
differentials, and results achieved in one period may not be indicative of results to be achieved in future
periods. Dependency on market conditions was evident in the trend in quarterly earnings compared with the
prior year whereby wide location and crude grade differentials gave rise to a greater number of and more
profitable margin opportunities during the first half of 2013. These physical marketing opportunities began
to diminish in the third quarter and culminated in a fourth quarter adjusted loss for Energy Services. Market
conditions contributing to the fourth quarter adjusted loss included physical constraints which limited
physical movement of barrels, such as pipeline apportionment and refinery outages, narrowing location
spreads among markets physically accessed by Tidal Energy’s committed transportation capacity and
narrowing grade differentials which limit tank management opportunities. Although profitability declined
in most lines of business, the fourth quarter loss primarily related to losses realized on financial contracts
intended to hedge the value of committed physical transportation capacity, but which were not effective in
doing so in the last three months of the year.
Energy Services adjusted earnings decreased from $56 million for the year ended December 31, 2011 to
$40 million for the year ended December 31, 2012. The decline was primarily due to changing market
conditions which gave rise to fewer margin opportunities in crude oil and NGL marketing.
Business Risks
The risks identified below are specific to Energy Services. General risks that affect the entire Company are
described under Risk Management and Financial Instruments – General Business Risks.
Commodity Price Risk
Energy Services generates margin by capitalizing on quality, time and location differentials when
opportunities arise. Volatility in commodity prices and changing marketing conditions could limit margin
opportunities. Furthermore, commodity prices could have negative earnings impacts if the cost of the
commodity is greater than resale prices achieved by the Company. Energy Services activities are conducted
in compliance with and under the oversight of the Company’s formal risk management policies, including
the implementation of hedging programs to manage exposure to changes in commodity prices, including
exposures inherent within forecasted transactions. To the extent a forecasted transaction does not occur
as anticipated, hedge ineffectiveness or termination may result. Certain financial
contracts may not qualify for cash flow hedge accounting; therefore, the Company’s
earnings are exposed to associated changes in the mark-to-market value of
these contracts.
Alliance Pipeline US – Average
Throughput Volumes
(millions of cubic feet per day)
Competition
Energy Services earnings are generated from arbitrage opportunities which, by their
nature, can be replicated by other competitors. An increase in market participants
looking for similar arbitrage opportunities could have an impact on the Company’s
earnings. The Company’s efforts to mitigate competition risk includes diversification
of its marketing business by trading at the majority of major hubs in North America,
optimizing relationships with affiliated entities and establishing long-term relationships
with clients.
Alliance Pipeline US
The Alliance System, which includes both the Canadian and United States portions
of the pipeline system, consists of approximately 3,000 kilometres (1,864 miles)
of integrated, high-pressure natural gas transmission pipeline and approximately
860 kilometres (534 miles) of lateral pipelines and related infrastructure. Alliance
transports liquids-rich natural gas from northeast British Columbia, northwest Alberta
and the Bakken area in North Dakota to Channahon, Illinois. Alliance Pipeline US and
1
0
6
,
1
0
0
6
,
1
4
6
5
,
1
3
5
5
,
1
5
6
5
,
1
09
10
11
12
13
Management’s Discussion and Analysis 81
Alliance Pipeline Canada have firm service shipping contract capacity to deliver 1.466 bcf/d and
1.325 bcf/d, respectively. Enbridge owns 50% of Alliance Pipeline US, while the Fund, described under
Sponsored Investments, owns 50% of Alliance Pipeline Canada.
Alliance connects with the Aux Sable NGL extraction and fractionation plant. Natural gas transported on
Alliance downstream of the Aux Sable plant can be delivered to two local natural gas distribution systems
in the Chicago area and five interstate natural gas pipelines, providing shippers with access to natural gas
markets in the midwestern and eastern United States and eastern Canada.
Alliance Pipeline US runs adjacent to the Bakken oil formation in North Dakota which offers new incremental
sources of liquids-rich natural gas for delivery to downstream markets. In February 2010, a new receipt point on
the pipeline near Towner, North Dakota was placed into service. The receipt point connects to the Prairie Rose
Pipeline and provides shippers operating out of the Bakken access to Alliance. In September 2013, Alliance
Pipeline US completed construction of the Tioga Lateral which will facilitate delivery of natural gas from Hess’
Tioga field processing plant in the Bakken to downstream markets.
Transportation Contracts
Alliance Pipeline US has long-term, take-or-pay contracts to transport substantially all its 1.466 bcf/d of natural
gas capacity. These contracts permit Alliance Pipeline US, whose operations are regulated by the FERC,
to recover the cost of service, which includes operating and maintenance costs, the cost of financing, an
allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.9%.
Alliance Pipeline US is in discussions with the shipper community regarding its service offerings post the
December 2015 expiry of the majority of existing contracts.
Results of Operations
Alliance Pipeline US earnings were $43 million for the year ended December 31, 2013 compared with earnings
of $39 million for each of the years ended December 31, 2012 and 2011. The increase in earnings in 2013
compared with 2012 reflected an increase in depreciation expense recovered through tolls and earnings related
to the Tioga Lateral Pipeline which was placed into service in 2013.
Vector Pipeline
Vector, which includes both the Canadian and United States portions of the pipeline system, consists of 560
kilometres (348 miles) of mainline natural gas transmission pipeline between the Chicago, Illinois hub and a
storage complex at Dawn, Ontario. Vector’s primary sources of supply are through
interconnections with Alliance and the Northern Border Pipeline in Joliet, Illinois.
Vector has the capacity to deliver a nominal 1.3 bcf/d and is operating at or near
capacity. The Company provides operating services to and holds a 60% joint venture
interest in Vector.
Vector Pipeline – Average
Throughput Volumes
(millions of cubic feet per day)
5
2
5
,
1
4
3
5
,
1
4
9
4
,
1
6
5
4
,
1
4
3
3
,
1
Transportation Contracts
The total long haul capacity of Vector is approximately 87% committed through
November 2015. Approximately 55% of the long haul capacity is committed through
firm negotiated rate transportation contracts with shippers and approved by the FERC,
while the remaining committed capacity is sold at market rates.
In December 2013, shippers under negotiated rate transportation contracts which
represent 20% of the system’s long haul capacity elected to extend their commitments
beyond December 1, 2016 and preserve the option to extend their contracts on an
annual basis. Vector is entitled to additional compensation from shippers that terminate
their contracts prior to the November 30, 2020 expiry date.
Transportation service is provided through a number of different forms of service
agreements such as Firm Transportation Service and Interruptible Transportation
Service. Vector is an interstate natural gas pipeline with FERC and NEB approved
tariffs that establish the rates, terms and conditions governing its service to customers.
On the United States portion of Vector, maximum tariff rates are determined using
82 Enbridge Inc. 2013 Annual Report
09
10
11
12
13
a cost of service methodology and maximum tariff changes may only be implemented upon approval by the
FERC. For 2013, the FERC approved maximum tariff rates included an underlying weighted average after-tax
ROE component of 11.2%. On the Canadian portion, Vector is required to file its negotiated tolls calculation
with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return incentive
mechanism based on construction costs and are subject to a rate cap. In 2013, maximum tolls include an ROE
component of 10.5% after-tax.
Results of Operations
Vector earnings were $22 million for the year ended December 31, 2013, comparable with $22 million for
the year ended December 31, 2012 and $23 million for the year ended December 31, 2011, respectively, and
reflected the stable, cost of service commercial arrangement in place for these years.
Business Risks
The risks identified below are specific to both Alliance Pipeline US and Vector. General risks that
affect the entire Company are described under Risk Management and Financial Instruments –
General Business Risks.
Asset Utilization
Currently, natural gas pipeline capacity out of the WCSB exceeds supply, due to the low price of natural
gas and increased production from new shale gas developments. Alliance Pipeline US and Vector have
been unaffected by this excess supply environment to date mainly because of long-term capacity contracts
extending primarily to 2015. However, excess supply and depressed natural gas prices have led to a reduction
or deferral of investment in upstream gas development, and could negatively impact re-contracting beyond
this term. Additionally, increased supply from new shale developments including the Marcellus shale formation,
which is among the largest gas plays in North America, could displace gas from the WCSB to the United States
midwest further increasing re-contracting risk.
The re-contracting risk is somewhat mitigated as the Alliance System is well positioned to deliver incremental
liquids-rich gas production from developments in the Montney and Bakken regions to the Aux Sable NGL
extraction and fractionation plant. The Alliance System is also engaged with market participants in developing
new receipt facilities and services to expand its reach in transporting liquids-rich gas to premium markets.
Competition
Alliance Pipeline US faces competition for pipeline
transportation services to the Chicago area from both existing
and proposed pipeline projects to transport gas from existing
and new gas developments. Any new or upgraded pipelines
could either allow shippers greater access to natural gas
markets or offer natural gas transportation services that are
more desirable than those provided by Alliance Pipeline US
because of location, facilities or other factors. In addition, these
pipelines could charge rates or provide transportation services
to locations that result in greater net profit for shippers, with
the effect of forcing Alliance Pipeline US to realize lower
revenues and cash flows. The ability of Alliance Pipeline US to
cost-effectively transport liquids-rich gas serves to enhance its
competitive position.
Vector faces competition for pipeline transportation services
to its delivery points from new supply sources and traditional
low cost pipelines, which could offer transportation that is more
desirable to shippers because of cost, supply location, facilities
or other factors. Vector has mitigated this risk by entering into
long-term firm transportation contracts and the effectiveness
Natural Gas Pipelines
Fort St. John
Edmonton
Alliance Pipeline
(Canada)
Regina
Alliance Pipeline (US)
Superior
Toronto
Chicago
Sarnia
Vector
Pipeline
Management’s Discussion and Analysis 83
of these contracts is evidenced by the increased utilization of the pipeline since its construction, despite the
presence of transportation alternatives.
Vector and Alliance pipelines also face potential competition from new sources of natural gas such as the
Marcellus and Utica shale formation, which are in close proximity to the Chicago Hub. The further development
of these shale formations could provide an alternate source of gas to the Chicago Hub as well as decrease the
northeastern region of the United States’ reliance on natural gas imports from Canada.
Economic Regulation
Both the United States portion of Vector and Alliance Pipeline US operations are subject to regulation by
the FERC. If tariff rates are protested, the timing and amount of recovery or refund of amounts recorded on
the Consolidated Statements of Financial Position could be different from the amounts that are eventually
recovered or refunded. In addition, future profitability of the entities could be negatively impacted. On a yearly
basis, following consultation with shippers, Alliance Pipeline US files its annual rates with the FERC for approval.
The FERC has intensified its oversight of financial reporting, risk standards and affiliate rules and has issued
new standards on managing gas pipeline integrity. The Company continues ongoing dialogue with regulatory
agencies and participates in industry groups to ensure it is informed of emerging issues in a timely manner.
Enbridge Offshore Pipelines
Offshore is comprised of 13 active natural gas gathering and
FERC-regulated transmission pipelines and one active oil
pipeline with a capacity of 60,000 bpd, in five major corridors
in the Gulf of Mexico, extending to deepwater developments.
These pipelines include almost 2,600 kilometres (1,600
miles) of underwater pipe and onshore facilities with total
capacity of approximately 7.3 bcf/d. Offshore currently moves
approximately 45% of offshore deepwater gas production
through its systems in the Gulf of Mexico.
Transportation Contracts
Enbridge Offshore Pipelines
Dallas
Houston
New Orleans
The primary shippers on the Offshore systems are producers
who execute life-of-lease commitments in connection with
transmission and gathering service contracts. In exchange,
Offshore provides firm capacity for the contract term at an
agreed upon rate. The firm capacity made available generally
reflects the lease’s maximum sustainable production.
The transportation contracts allow the shippers to define
a maximum daily quantity (MDQ), over the expected production
life. Some contracts have minimum throughput volumes which are subject to ship-or-pay criteria, but also
provide the shippers with flexibility, subject to advance notice criteria, to modify the projected MDQ schedule
to match current delivery expectations. The majority of long-term transport rates are market-based, with
revenue generation directly tied to actual production deliveries. Some of the systems operate under a cost-of-
service methodology, including certain lines under FERC regulation.
The business model utilized on a go forward basis and included in the WRGGS, Big Foot Pipeline, Venice and
Heidelberg commercially secured projects differs from the historic model. These new projects have a base level
return which is locked in through either ship-or-pay commitments or fixed demand charge payments. If volumes
reach producer anticipated levels, the return on these projects may increase. In addition, Enbridge has minimal
capital cost risk on these projects and commercial agreements continue to contain life-of-lease commitments.
The WRGGS and Big Foot Pipeline project agreements provide for recovery of actual capital costs to complete
the project in fees payable by producers over the contract term. The Venice project provides for a capital cost
risk sharing mechanism whereby Enbridge is exposed to a portion of the capital costs in excess of an agreed
upon target. Conversely, Enbridge can recover in fees from producers a portion of the capital cost savings
below the agreed upon target. Adjustment is allowed for many of the Heidelberg project variables affecting its
cost, with Enbridge bearing the residual capital cost risk after these adjustments have been applied.
84 Enbridge Inc. 2013 Annual Report
Asset Impairment
In December 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax)
related to certain of its Offshore assets, predominantly located within the Stingray and Garden Banks
corridors in the Gulf of Mexico. The Company had been pursuing alternative uses for these assets;
however, due to changing competitive conditions in the fourth quarter of 2012, the Company concluded
that such alternatives were no longer likely to proceed. In addition, unique to these assets is their
significant reliance on natural gas production from shallow water areas in the Gulf of Mexico which have
been challenged by macro-economic factors including prevalence of onshore shale gas production,
hurricane disruptions, additional regulation and the low natural gas commodity price environment.
Results of Operations
For the year ended December 31, 2013, Offshore incurred an adjusted loss of
$2 million compared with an adjusted loss of $3 million for the year ended
December 31, 2012. Positive factors impacting the change in Offshore earnings
included the Venice expansion placed into service in November 2013, cost
savings achieved from the Company’s election not to renew windstorm insurance
coverage and lower depreciation expense. However, more than offsetting these
positive factors were persistent weak volumes on the majority of Offshore’s
pipelines due to decreased production in the Gulf of Mexico. The challenging
market conditions which impacted Offshore in 2013 is expected to persist and be
a drag on Offshore earnings until such time as the WRGGS and Big Foot Pipeline
are placed into service, which are expected to occur in the third quarter of 2014
and the second quarter of 2015, respectively.
For the year ended December 31, 2012, Offshore incurred an adjusted
loss of $3 million compared with a loss of $7 million for the year ended
December 31, 2011. Offshore realized losses due to weak volumes from delayed
drilling programs and scheduled production outages by producers in the
Gulf of Mexico. The decrease in loss year-over-year resulted from a higher
transportation rate for volumes shipped on the Stingray Pipeline System,
a reduction in interest expense and a $2 million favourable impact related
to the reversal of a shipper reserve pertaining to a rate case from 2011.
Business Risks
Enbridge Offshore Pipelines –
Average Throughput Volumes
(millions of cubic feet per day)
7
3
0
,
2
2
6
9
,
1
5
9
5
,
1
0
4
5
,
1
2
1
4
,
1
09
10
11
12
13
The risks identified below are specific to Offshore. General risks that affect the Company as a whole
are described under Risk Management and Financial Instruments – General Business Risks.
Asset Utilization
A decrease in gas volumes transported by Offshore natural gas pipelines can directly affect revenues
and earnings. Low natural gas prices, in part due to the prevalence of onshore shale gas, have resulted
in reduced investment in exploration activities and producing infrastructure. Offshore diversifies its risk
of declining gas production through the construction of crude oil pipelines. To date, crude oil prices
have supported stable offshore investment; however, a future decline in crude oil prices could change
the potential for future investment opportunities. Further, a sustained decline in either natural gas or
crude oil commodity prices could impact the ability of the Company to recover its investment in long-
lived offshore assets.
Competition
There is competition for new and existing business in the Gulf of Mexico, with an increasing number
of competitors willing to construct and operate production host platforms for future deepwater
prospects. Offshore has been able to capture key opportunities, allowing it to more fully utilize
existing capacity. Offshore’s gas pipelines serve a majority of the strategically located deepwater host
platforms, positioning it favourably to make incremental investments for new platform connections
and receive additional transportation volumes from sub-sea development of smaller fields tied back to
Management’s Discussion and Analysis 85
existing host platforms. Offshore is also able to construct
pipelines to transport crude oil, diversifying the risk of
declining gas production, as demonstrated with the planned
Big Foot and Heidelberg pipelines. Given rates of decline,
offshore pipelines typically have available capacity, resulting
in significant competition for new developments in the
Gulf of Mexico. Competing developments may impact the
ability of the Company to recover its investment in long-lived
offshore assets.
Natural Disaster Incidents
Adverse weather, such as hurricanes and tropical storms, may
impact Offshore’s financial performance directly or indirectly.
Direct impacts may include damage to offshore facilities
resulting in lower throughput, as well as inspection and
repair costs. Indirect impacts may include damage to third
party production platforms, onshore processing plants and
pipelines that may decrease throughput on offshore systems.
The occurrence of hurricanes in the Gulf of Mexico
increases the cost and availability of insurance coverage.
On May 1, 2013, the Company elected not to renew
windstorm coverage on its Offshore asset portfolio.
The Company expects to reassess the market for windstorm
coverage and revisit the possible purchase of coverage in
future years as the Company’s portfolio of Offshore assets
is expected to increase. Enbridge facilities are engineered
to withstand hurricane forces and constant monitoring
of weather allows for timely evacuation of personnel and
shutdown of facilities; however, damages to assets may
still occur.
Other
Other includes interests in approximately 1,250 MW of the
enterprise-wide portfolio of 1,800 MW of renewable power
generating assets. The balance of the portfolio is held by
the Fund. Of the interests presented within Other, 830 MW
represents active production from four wind farms and
one solar asset while the remainder represents interests in
growth projects under construction. Also included in Other
is MATL, the Company’s first power transmission asset, and
its natural gas midstream business, including Cabin located
in northeastern British Columbia.
To optimize funding of its enterprise-wide slate of growth
projects, Enbridge may drop down assets to its Sponsored
Investments. In 2012, Greenwich Wind Energy Project
(Greenwich), Amherstburg Solar Project (Amherstburg) and
Tilbury Solar Project (Tilbury) were transferred to the Fund,
following the 2011 transfer of the Ontario Wind, Sarnia Solar
and Talbot Wind energy projects. Earnings contributions
from these assets, net of noncontrolling interests, are
reflected within Sponsored Investments from the date
the assets were transferred to the Fund. See Sponsored
Investments – Enbridge Income Fund – Crude Oil Storage and
Renewable Energy Transfers.
Results of Operations
Adjusted earnings from Other for the year ended
December 31, 2013 were $16 million compared with
$10 million for the year ended December 31, 2012. Higher
earnings were mainly attributable to the commissioning
of Lac Alfred and contributions from fees earned on
the Company’s investment in Cabin, for which earnings
recognition commenced in December 2012. Partially
offsetting the increase in adjusted earnings was the transfer
of certain renewable energy assets to the Fund in
December 2012, as well as lower contributions from the
Cedar Point Wind Energy Project (Cedar Point) due
to lower wind resources.
Other adjusted earnings for the year ended
December 31, 2012 were $10 million compared with
$14 million for the year ended December 31, 2011.
The decrease in adjusted earnings was primarily due to the
sale of Ontario Wind, Sarnia Solar and Talbot Wind energy
projects to the Fund in October 2011, followed by the sale
of Greenwich, Amherstburg and Tilbury to the Fund in
December 2012. Higher business development costs also
contributed to the decrease in adjusted earnings. Partially
offsetting this increase were the contributions from
Cedar Point and Greenwich, which were commissioned
in late 2011, and Silver State North Solar Project (Silver State)
which was commissioned in early 2012.
86 Enbridge Inc. 2013 Annual Report
Sponsored Investments
Earnings
(millions of Canadian dollars)
Enbridge Energy Partners, L.P. (EEP)
Enbridge Energy, Limited Partnership (EELP)
Enbridge Income Fund (the Fund)
Adjusted earnings
EEP – leak insurance recoveries
EEP – leak remediation costs
EEP – changes in unrealized derivative fair value gains/(loss)
EEP – tax rate differences/changes
EEP – gain on sale of non-core assets
EEP – NGL trucking and marketing investigation costs
EEP – prior period adjustment
EEP – shipper dispute settlement
EEP – lawsuit settlement
EEP – impact of unusual weather conditions
Earnings attributable to common shareholders
Adjusted earnings from Sponsored Investments were $313 million for the year
ended December 31, 2013 compared with $264 million for the year ended
December 31, 2012 and $243 million for the year ended December 31, 2011.
The increase in adjusted earnings resulted from increased contributions from the
Fund following the transfer of certain renewable energy and crude oil storage
assets from Enbridge and its wholly-owned subsidiaries in late 2012 and late 2011.
EEP also contributed to the 2013 increase in year-over-year adjusted earnings
primarily due to Enbridge’s investment in preferred units of EEP issued in 2013,
as well as higher incentive distributions.
Sponsored Investment earnings were impacted by the following adjusting items:
• EEP earnings for each period included insurance recoveries associated with
the Line 6B crude oil release. See Sponsored Investments – Enbridge Energy
Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases.
• EEP earnings for each period included charges related to estimated costs,
before insurance recoveries, associated with the Line 6B crude oil release.
See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead
System Line 14 Crude Oil Release and Sponsored Investments – Enbridge Energy
Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases.
• EEP earnings for each period included changes in unrealized fair value gains
and losses on derivative financial instruments.
• EEP earnings for 2013 included an out-of-period, non-cash deferred income tax
adjustment related to a tax law change.
• EEP earnings for 2013 included a gain on sale from non-core assets.
• EEP earnings for 2012 and 2011 reflected charges for legal and accounting
costs associated with an investigation at a NGL trucking and marketing
subsidiary, which was concluded in the first quarter of 2012.
• EEP earnings for 2012 reflected a non-recurring out-of-period adjustment.
• EEP earnings for 2011 included proceeds from the settlement of a shipper
dispute related to oil measurement adjustments in prior years.
2013
2012
2011
151
42
50
243
50
(33)
3
–
–
(3)
–
8
1
(1)
268
3
1
3
1
8
6
2
165
38
110
313
6
(44)
(6)
(3)
2
–
–
–
–
–
268
141
38
85
264
24
(9)
(2)
–
–
(1)
7
–
–
–
283
Sponsored Investments
Earnings
(millions of Canadian dollars)
1
3
8
2
4
6
2
1
8
6
2
3
4
2
1
5
1
2
1
4
1
4
0
2
1
6
9
09
10
11
12
13
■ GAAP Earnings
■ Adjusted Earnings
1 Financial information has been
extracted from financial statements
prepared in accordance with
U.S. GAAP.
2 Financial information has been
extracted from financial statements
prepared in accordance with
Canadian GAAP.
Management’s Discussion and Analysis 87
• EEP earnings for 2011 included proceeds related to the settlement of a lawsuit during the first
quarter of 2011.
• EEP earnings for 2011 included an unfavourable effect related to decreased volumes due to
uncharacteristically cold weather in February 2011 that disrupted normal operations of its natural
gas systems.
Enbridge Energy Partners, L.P.
EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural
gas and NGL gathering, treating, processing, transportation and marketing assets in the United States.
Significant assets include the Lakehead System, which is the extension of the Canadian Mainline in the
United States, the Mid-Continent Crude Oil System consisting of an interstate crude oil pipeline and
storage facilities, a crude oil gathering system and interstate pipeline system in North Dakota and natural
gas assets located primarily in Texas. In 2013, EEP placed into service several assets including the Texas
Express NGL System, Ajax Plant and the Bakken Expansion Program. Subsidiaries of Enbridge provide
services to EEP in connection with the operation of its liquids assets, including the Lakehead System.
EEP holds its natural gas and NGL midstream assets through a combination of direct and indirect
holdings. As at December 31, 2013, EEP’s direct interest in entities or partnerships holding the natural
gas and NGL operations was approximately 61%, with the remaining ownership held by Midcoast
Energy Partners, L.P. (MEP), a publicly listed partnership trading on the New York Stock Exchange.
The balance of EEP’s interest in the natural gas and NGL operations is held indirectly through
ownership of the general partner (GP) interest, an approximate 52% limited partner interest and all
incentive distribution rights of MEP. For further discussion refer to Sponsored Investments –
Enbridge Energy Partners, L.P. – Midcoast Energy Partners, L.P. Initial Public Offering.
Enbridge Energy Partners, L.P.
Blaine
Seattle
Portland
Salt Lake City
Calgary
Regina
Cromer
Minot
North Dakota System
Gretna
Clearbrook
Superior
Casper
Lakehead System
Chicago
Sarnia
Toledo
Patoka
Wood River
Cushing
Ozark Pipeline
Midcoast Energy
Partners Natural
Gas Assets
Dallas
New Orleans
Houston
Enbridge Inc.
Liquids pipelines
Gas pipelines
88 Enbridge Inc. 2013 Annual Report
Ownership Interest
Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common
units. To the extent Enbridge does not fully participate in these offerings, the Company’s ownership
interest in EEP is reduced. At December 31, 2013, Enbridge’s ownership interest in EEP was 20.6%
(2012 - 21.8%; 2011 - 23.0%). The Company’s average ownership interest in EEP during 2013 was 21.1%
(2012 - 23.0%; 2011 - 24.4%). Additionally, Enbridge also holds a US$1.2 billion investment in EEP
preferred units. For further discussion refer to Sponsored Investments – Enbridge Energy Partners,
L.P. – EEP Preferred Unit Private Placement and Joint Funding Option Exercise.
Distributions
EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership
Agreement, Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge, as GP,
receives incremental incentive cash distributions, which represent incentive income on the portion of
cash distributions (on a per unit basis) that exceed certain target thresholds as follows:
Quarterly cash distributions per unit1:
Up to $0.295 per unit
First target – $0.295 per unit up to $0.350 per unit
Second target – $0.350 per unit up to $0.495 per unit
Over second target – cash distributions greater than $0.495 per unit
1
Distributions restated to reflect EEP’s two-for-one stock split which was effective April 2011.
Unitholders
including Enbridge
GP Interest
98%
85%
75%
50%
2%
15%
25%
50%
In 2013, EEP paid a quarterly distribution of $0.5435 per unit to common unitholders. In 2013, Enbridge
received from EEP intercompany GP incentive distributions of US$130 million (2012 - US$116 million;
2011 - US$93 million).
Results of Operations
Adjusted earnings from EEP were $165 million for the year ended December 31, 2013 compared with
$141 million for the year ended December 31, 2012. The adjusted earnings increased primarily due
to distributions received from Enbridge’s May 2013 investment in preferred units of EEP and higher
incentive distributions. Also contributing to higher adjusted earnings were contributions from EEP’s
liquids business due to higher tolls on EEP’s major liquids pipeline assets and the positive impact of new
assets placed into service. Partially offsetting the increase in adjusted earnings were lower volumes
on the North Dakota system due to wide crude oil price differentials that made transportation by rail
competitive, although tightening crude oil price differentials in the second half of 2013 resulted in some
volumes returning to the North Dakota system. Rail competition is expected to persist as rail provides
transportation service to certain markets not currently accessible by pipelines. EEP’s adjusted earnings
also reflected costs related to the completion of hydrostatic testing on Line 14 of its Lakehead System,
as well as higher depreciation expense associated with new assets placed into service. Also offsetting
the adjusted earnings increase were lower NGL prices and volumes in EEP’s natural gas and NGL
businesses and higher operating and administrative expense, primarily from an increased workforce.
Adjusted earnings from EEP were $141 million for the year ended December 31, 2012 compared with
$151 million for the year ended December 31, 2011. Adjusted earnings from EEP for 2012 included higher
GP incentive income and strong results from the liquids business primarily due to higher average
delivery volumes and increased tolls on all major liquids systems, as well as contributions from storage
terminal and other facilities that were placed into service during 2012. Earnings from the natural gas
business decreased as a result of lower natural gas and NGL prices. Earnings were also negatively
impacted by an increase in operating and administrative costs, specifically pipeline integrity costs,
personnel costs and higher property taxes.
Management’s Discussion and Analysis 89
Lakehead System Line 14 Crude Oil Release
On July 27, 2012, a release of crude oil was detected on Line
14 of EEP’s Lakehead System near Grand Marsh, Wisconsin.
The estimated volume of oil released was approximately
1,700 barrels. EEP received a Corrective Action Order
(CAO) from the Pipeline and Hazardous Materials Safety
Administration (PHMSA) on July 30, 2012, followed by an
amended CAO on August 1, 2012. Upon restart of Line 14 on
August 7, 2012, PHMSA restricted the operating pressure
to 80% of the pressure in place at the time immediately
prior to the incident. During the fourth quarter of 2013, EEP
received approval from the PHMSA to remove the pressure
restrictions and to return to normal operating pressures
for a period of 12 months. In December 2014, the PHMSA
will again consider the status of the pipeline in light of
information they acquire throughout 2014.
The total estimated cost for the Line 14 crude oil release
remains at approximately US$10 million ($1 million after-
tax attributable to Enbridge), inclusive of approximately
US$2 million of lost revenue and excluding any fines and
penalties. Despite the efforts EEP has made to ensure the
reasonableness of its estimate, changes to the estimated
amounts associated with this release are possible as more
reliable information becomes available. EEP will be pursuing
claims under Enbridge’s comprehensive insurance policy,
although it does not expect any recoveries to be significant.
Lakehead System Lines 6A and 6B Crude Oil Releases
Line 6B Crude Oil Release
On July 26, 2010, a release of crude oil on Line 6B of EEP’s
Lakehead System was reported near Marshall, Michigan.
EEP estimates that approximately 20,000 barrels of crude
oil were leaked at the site, a portion of which reached the
Talmadge Creek, a waterway that feeds the Kalamazoo River.
The released crude oil affected approximately 61 kilometres
(38 miles) of shoreline along the Talmadge Creek and
Kalamazoo River waterways, including residential areas,
businesses, farmland and marshland between Marshall and
downstream of Battle Creek, Michigan. In response to the
release, a unified command structure was established under
the jurisdiction of the Environmental Protection Agency
(EPA), the Michigan Department of Natural Resources and
Environment and other federal, state and local agencies.
As at December 31, 2013, EEP’s total cost estimate for the
Line 6B crude oil release was US$1,122 million ($181 million
after-tax attributable to Enbridge) which is an increase of
US$302 million ($44 million after-tax attributable to Enbridge)
compared to the December 31, 2012 estimate. This total
estimate is before insurance recoveries and excludes
additional fines and penalties other than those discussed
in Sponsored Investments – Enbridge Energy Partners, L.P.
– Lakehead System Lines 6A and 6B Crude Oil Releases –
Legal and Regulatory Proceedings, below. On March 14,
2013, EEP received an order from the EPA (the Order) which
90 Enbridge Inc. 2013 Annual Report
defined the scope requiring additional containment and
active recovery of submerged oil relating to the Line 6B
crude oil release. EEP submitted its initial proposed work
plan required by the EPA on April 4, 2013 and resubmitted
the work plan on April 23, 2013. The EPA approved the
Submerged Oil Recovery and Assessment (SORA) work plan
with modification on May 8, 2013. EEP incorporated the
modification and submitted an approved SORA on
May 13, 2013. The Order states the work must be completed
by December 31, 2013. EEP has currently completed
substantially all of the SORA, with the exception of required
dredging in and around Morrow Lake and its delta. EEP is
in the process of working with the EPA to ensure this work
is completed as soon as reasonably possible, inclusive of
obtaining the necessary state and local permitting that is
required and considering weather conditions.
Of the US$302 million increase compared with
December 31, 2012 related to the Line 6B crude oil release,
US$280 million is primarily related to additional work required
by the Order including further refinement and definition of the
additional dredging scope per the Order and all associated
environmental, permitting, waste removal and other related
costs, as well as increased dredge activity in and around
Morrow Lake and the delta area. The actual costs incurred may
differ from the foregoing estimate as EEP completes the work
plan with the EPA related to the Order and works with other
regulatory agencies to assure its work plan complies with their
requirements. Any such incremental costs will not be recovered
under EEP’s insurance policies as the costs for the incident
at December 31, 2013 exceeded the limits of the Company’s
insurance coverage. The remaining increase of US$22 million
reflected an estimate of the minimum amount of civil penalties
EEP may be assessed under the Clean Water Act of the United
States (Clean Water Act) in respect of the Line 6B crude oil
release. See Sponsored Investments – Enbridge Energy Partners,
L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases –
Legal and Regulatory Proceedings.
Expected losses associated with the Line 6B crude oil release
included those costs that were considered probable and that
could be reasonably estimated at December 31, 2013. Despite
the efforts EEP has made to ensure the reasonableness of
its estimates, there continues to be the potential for EEP to
incur additional costs in connection with this crude oil release
due to variations in any or all of the cost categories, including
modified or revised requirements from regulatory agencies,
in addition to fines and penalties and expenditures associated
with litigation and settlement of claims.
Line 6A Crude Oil Release
A release of crude oil from Line 6A of EEP’s Lakehead System
was reported in an industrial area of Romeoville, Illinois on
September 9, 2010. EEP estimates that approximately 9,000
barrels of crude oil were released, of which approximately
1,400 barrels were removed from the pipeline as part of the
repair. Some of the released crude oil went onto a roadway,
into a storm sewer, a waste water treatment facility and
then into a nearby retention pond. All but a small amount
of the crude oil was recovered. EEP completed excavation
and replacement of the pipeline segment and returned it to
service on September 17, 2010.
EEP continues to monitor the areas affected by the crude
oil release from Line 6A of its Lakehead System for any
additional requirements; however, the cleanup, remediation
and restoration of the areas affected by the release have been
completed. On October 21, 2013, the National Transportation
Safety Board publicly posted their final report related to the
Line 6A crude oil release that occurred in Romeoville, Illinois,
which states the probable cause of the crude oil release
was erosion caused by a leaking water pipe resulting from
an improperly installed third-party water service line below
EEP’s oil pipeline.
The total estimated cost for the Line 6A crude oil release
remains at approximately US$48 million ($7 million after-
tax attributable to Enbridge), before insurance recoveries
and excluding fines and penalties. These costs included
emergency response, environmental remediation and cleanup
activities with the crude oil release. EEP is pursuing recovery
of the costs associated with the Line 6A crude oil release from
third parties; however, there can be no assurance that any
such recovery will be obtained.
Insurance Recoveries
EEP is included in the comprehensive insurance program that
is maintained by Enbridge for its subsidiaries and affiliates
which renews throughout the year. On May 1 of each year,
EEP’s insurance program is up for renewal and includes
commercial liability insurance coverage that is consistent with
coverage considered customary for its industry and includes
coverage for environmental incidents such as those incurred
for the crude oil releases from Lines 6A and 6B, excluding
costs for fines and penalties.
The claims for the crude oil release for Line 6B are covered by
Enbridge’s comprehensive insurance policy that expired on
April 30, 2011, which had an aggregate limit of US$650 million
for pollution liability. Based on EEP’s remediation spending
through December 31, 2013, Enbridge and its affiliates
have exceeded the limits of their coverage under this
insurance policy. Additionally, fines and penalties would
not be covered under the existing insurance policy. For the
years ended December 31, 2013 and 2012, EEP recognized
US$42 million ($6 million after-tax attributable to Enbridge)
and US$170 million ($24 million after-tax attributable to
Enbridge), respectively, of insurance recoveries as reductions
to Environmental costs in the Consolidated Statements of
Earnings. As at December 31, 2013, EEP has recorded total
insurance recoveries of US$547 million ($80 million after-tax
attributable to Enbridge) for the Line 6B crude oil release,
out of the US$650 million aggregate limit. EEP will record
receivables for additional amounts it claims for recovery
pursuant to its insurance policies during the period it deems
recovery to be probable.
In March 2013, EEP and Enbridge filed a lawsuit against the
insurers of the remaining US$145 million coverage, as one
particular insurer is disputing the recovery eligibility for
costs related to EEP’s claim on the Line 6B crude oil release
and the other remaining insurers assert that their payment is
predicated on the outcome of the recovery from that insurer.
EEP received a partial recovery payment of US$42 million
from the other remaining insurers and has since amended
its lawsuit, such that it now includes only one insurer. While
EEP believes the claims for the remaining US$103 million are
covered under the policy, there can be no assurance that EEP
will prevail in this lawsuit.
Effective May 1, 2013, Enbridge renewed its comprehensive
property and liability insurance programs, under which EEP
is insured through April 30, 2014, with a current liability
aggregate limit of US$685 million, including sudden and
accidental pollution liability. In the unlikely event multiple
insurable incidents occur which exceed coverage limits within
the same insurance period, the total insurance coverage will
be allocated among the Enbridge entities on an equitable
basis based on an insurance allocation agreement EEP has
entered into with Enbridge and another Enbridge subsidiary.
Legal and Regulatory Proceedings
A number of United States governmental agencies and
regulators have initiated investigations into the Lines 6A and
6B crude oil releases. Approximately 30 actions or claims
are pending against Enbridge, EEP or their affiliates in United
States federal and state courts in connection with the Line
6B crude oil release, including direct actions and actions
seeking class status. Based on the current status of these
cases, the Company does not expect the outcome of these
actions to be material.
As at December 31, 2013, included in EEP’s estimated costs
related to the Line 6B crude oil release is US$30 million in
fines and penalties. Of this amount, US$3.7 million related
to civil penalties assessed by PHMSA that EEP paid during
the third quarter of 2012. The total also included an amount
of US$22 million related to civil penalties EEP expects to be
required to pay under the Clean Water Act. While no final
fine or penalty has been assessed or agreed to date, EEP
believes that, based on the best information available at
this time, the US$22 million represents an estimate of the
minimum amount which may be assessed, excluding costs of
injunctive relief, if any, that may be agreed to with the relevant
governmental agencies. Given the complexity of settlement
negotiations, which EEP expects will continue, and the limited
information available to assess the matter, EEP is unable to
reasonably estimate the final penalty which might be incurred
or to reasonably estimate a range of outcomes at this time.
Discussions with governmental agencies regarding fines
and penalties are ongoing.
Management’s Discussion and Analysis 91
One claim related to Line 6A crude oil release has been
filed against Enbridge, EEP or their affiliates by the State of
Illinois in the Illinois state court in connection with this crude
oil release, and the parties are currently operating under an
agreed interim order.
Intercompany Accounts Receivable Sale
On June 28, 2013, certain of EEP’s subsidiaries entered
into a Receivables Purchase Agreement (the Receivables
Agreement) with a wholly-owned subsidiary of Enbridge,
whereby Enbridge will purchase on a monthly basis
certain trade and accrued receivables of such subsidiaries
through December 2016. Pursuant to the Receivables
Agreement, as amended on September 20, 2013, and again
on December 2, 2013, at any one point the accumulated
purchases, net of collections, shall not exceed US$450
million. The primary objective of the accounts receivable
transaction is to further enhance EEP’s available liquidity and
its cash available from operations for payment of distributions
during the next few years until EEP’s large growth capital
commitments are permanently funded, as well as to provide
an annual saving in EEP’s cost of funding during this period.
Midcoast Energy Partners, L.P. Initial Public Offering
In May 2013, EEP formed MEP as its wholly owned subsidiary.
Subsequently, on November 13, 2013, MEP completed its initial
public offering (IPO) of 18.5 million Class A common units
representing limited partner interests and subsequently issued
an additional 2.8 million Class A common units pursuant to an
underwriters’ over allotment option. MEP received proceeds of
approximately US$355 million.
EEP, through certain of its subsidiaries, holds a 2% GP interest
and the remaining limited partner interest in MEP. Upon
finalization of the offering, MEP’s initial assets consisted of an
approximate 39% ownership interest in EEP’s natural gas and
NGL midstream business. EEP retained ownership of the GP
and all the incentive distribution rights in MEP. The finalization
of the transaction resulted in a partial monetization of EEP’s
natural gas and NGL midstream assets through sale to
noncontrolling interests (being MEP’s public unitholders).
Enbridge Energy Management, L.L.C. Share Issuance
Enbridge’s ownership in EEP is held through a combination
of direct interest, including a 2% GP interest, and indirect
interest through Enbridge Energy Management, L.L.C. (EEM).
In 2013, EEM completed two separate issuances of Listed
Shares. In March 2013, EEM completed the issuance of
10.4 million Listed Shares for net proceeds of approximately
US$273 million and in September 2013, EEM completed a
further issuance of 8.4 million Listed Shares for net proceeds
of approximately US$236 million. Enbridge did not purchase
any of the offered shares. EEM subsequently used the net
proceeds from each of the offerings to invest in an equal
number of i-units of EEP.
In connection with these issuances, the Company made
capital contributions of US$6 million and US$5 million in
March and September 2013, respectively, to maintain its
2% GP interest in EEP. The proceeds from the issuances were
used by EEP to repay commercial paper, to finance a portion
of its capital expansion program relating to its core liquids and
natural gas systems and for general partnership purposes.
EEP Preferred Unit Private Placement and Joint Funding
Option Exercise
In May 2013, Enbridge invested US$1.2 billion in preferred
units of EEP to reduce the amount of near-term external
funding required by EEP to fund its share of the Company’s
organic growth program. Concurrent with the issuance,
EEP also announced it expected to exercise its option in
each of the Eastern Access and Lakehead System Mainline
Expansion joint funding agreements to reduce its economic
interest and associated funding in the respective projects.
On June 28, 2013, EEP exercised each of the options and
both projects will now be funded 75% by Enbridge and
25% by EEP. EEP will retain the option to increase its
economic interest back up to 40% in each project within
one year of the final project in-service dates. For further
discussion refer to Liquidity and Capital Resources.
Enbridge Energy, Limited Partnership
EELP holds assets that are jointly funded by Enbridge and EEP.
Included within EELP is the United States segment of Alberta
Clipper, which is a 1,670-kilometre (1,000-mile) crude oil
pipeline that provides service between Hardisty, Alberta and
Superior, Wisconsin with capacity of 450,000 bpd. Enbridge
funded 66.7% of the project’s equity requirements through
EELP, while 66.7% of the debt funding was made through EEP.
In 2012, EELP amended and restated its limited partnership
agreement to establish a series of additional partnership
interests in both the Eastern Access and Lakehead Mainline
Expansion projects. Both of these projects will be funded
75% by Enbridge and 25% by EEP. For further details on the
respective projects see Growth Projects – Commercially
Secured Projects – Sponsored Investments – Enbridge Energy
Partners, L.P. – Eastern Access and Growth Projects –
Commercially Secured Projects – Sponsored Investments –
Enbridge Energy Partners, L.P. – Lakehead System
Mainline Expansion.
Results of Operations
Earnings from EELP were $38 million for both the years
ended December 31, 2013 and 2012. EELP earnings were
comparable between years due to offsetting factors. Alberta
Clipper earnings decreased and reflected lower tolls,
which took effect April 1, 2013. Variations in Alberta Clipper
earnings from the regulated allowed return on rate base
are recovered from or refunded to shippers in the following
year. The decrease in Alberta Clipper earnings were offset
92 Enbridge Inc. 2013 Annual Report
by the positive impact of incremental revenue from several
small components of the Eastern Access project which were
placed into service in 2013, including the Line 5 expansion.
Earnings from EELP were $38 million for the year ended
December 31, 2012 compared with $42 million for the year
ended December 31, 2011 due to a reduction in rates on
Alberta Clipper which took effect April 1, 2012.
Supply for the marketing operations depends to a large
extent on the natural gas reserves and rate of drilling within
the areas served by the natural gas business. Demand is
typically driven by weather-related factors, with respect to
power plant and utility customers, and industrial demand.
EEP’s marketing business uses third party storage to balance
supply and demand factors.
Business Risks
The risks identified below are specific to EEP and EELP.
General risks that affect the Company as a whole are
described under Risk Management and Financial
Instruments – General Business Risks.
Asset Utilization
Asset utilization risk for EEP’s liquids business shares similar
risk characteristics to Liquids Pipelines as changing market
fundamentals, capacity bottlenecks, operational incidents,
regulatory restrictions, system maintenance and increased
competition can all impact the utilization of EEP’s assets.
The profitability of EEP’s liquids business depends to some
extent on the throughput of products transported on its
pipeline systems, and a decrease in volumes transported
can directly and adversely affect revenues and earnings.
Market fundamentals, such as commodity prices and price
differentials, weather, gasoline price and consumption,
alternative energy sources and global supply disruptions,
outside of EEP’s control can impact both the supply of
and demand for crude oil and other liquid hydrocarbons
transported on EEP’s pipelines. However, the long-term
outlook for Canadian crude oil production, particularly from
western Canada, and increasing United States domestic
production are expected to maintain a steady supply of
crude oil.
EEP seeks to mitigate utilization constraints within its
control. The market access and expansion projects
under development are expected to reduce capacity
bottlenecks and introduce new markets for customers.
In conjunction with Liquids Pipelines, EEP works with the
shipper community to enhance scheduling efficiency and
communications as well as makes continuous improvements
to models and timelines to alleviate pipeline restrictions.
EEP’s natural gas gathering assets are also subject to
market fundamentals affecting natural gas, NGL and
related products. Commodity prices impact the willingness
of natural gas producers to invest in additional infrastructure
to produce natural gas and, with current low natural
gas prices, infrastructure plans have been increasingly
deferred or cancelled. These assets are also subject to
competitive pressures from third-party and producer-owned
gathering systems.
Operational and Economic Regulation
Operational regulation risks relate to failing to comply
with applicable operational rules and regulations from
government organizations and could result in fines or
operating restrictions or an overall increase in operating
and compliance costs.
Regulatory scrutiny over the integrity of EEP’s assets, in
particular its liquids assets, has the potential to increase
operating costs or limit future projects. Potential regulation
upgrades and changes could have an impact on the
Company’s future earnings and the cost related to the
construction of new projects. The Company believes
operational regulation risk is mitigated by active monitoring
and consulting on potential regulatory requirement changes
with the respective regulators, directly or through industry
associations. The Company also develops robust response
plans to regulatory changes or enforcement actions.
EEP’s economic regulation is driven primarily through its
ownership of interstate oil pipelines and certain activities
within its intrastate natural gas pipelines, which are
regulated by the FERC or state regulators. The changing
or rejecting of commercial arrangements by the regulators
could have an adverse effect on the Company’s revenues and
earnings. Additionally, while EEP’s gas gathering pipelines
are not currently subject to FERC rate regulation, proposals
to more actively regulate intrastate gathering pipelines
are currently being considered in certain of the states in
which EEP operates. In addition, the FERC has also taken an
interest in regulating gas gathering systems that connect
into interstate pipelines.
The Company believes that regulatory risk is reduced
through the negotiation of long-term agreements with
shippers which govern the majority of the segment’s assets
and the involvement of its legal and regulatory teams in the
review of new projects to ensure compliance with applicable
regulations; however, the risk that a regulator could overturn
long-term agreements between the Company and shippers
continues to exist.
Management’s Discussion and Analysis 93
Competition
EEP’s Lakehead System, the United States portion of the liquids pipelines mainline, is a major crude
oil export conduit from the WCSB. Other existing competing carriers and pipeline proposals to ship
western Canadian liquids hydrocarbons to markets in the United States represent competition for
the Lakehead System; including proposed projects expected to serve the Gulf Coast market. EEP’s
Mid-Continent and North Dakota systems also face competition from existing competing pipelines,
proposed future pipelines and existing and alternative gathering facilities, predominately rail.
Competition for EEP’s storage facilities includes large integrated oil companies and other midstream
energy partnerships.
Other interstate and intrastate natural gas pipelines (or their affiliates) and other midstream businesses
that gather, treat, process and market natural gas or NGL represent competition to EEP’s natural gas
segment. The level of competition varies depending on the location of the gathering, treating and
processing facilities. However, most natural gas producers and owners have alternate gathering,
treating and processing facilities available to them, including those owned by competitors that are
substantially larger than EEP.
EEP’s marketing segment has numerous competitors, including large natural gas marketing companies,
marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and
regional marketing companies.
Commodity Price Risk
EEP’s gas processing business is subject to commodity price risk arising from movements in natural
gas and NGL prices and differentials. These risks have been managed by using physical and financial
contracts to fix the prices of natural gas and NGL. Certain of these financial contracts do not qualify
for cash flow hedge accounting therefore, EEP’s earnings are exposed to associated changes in the
mark-to-market value of these contracts.
Enbridge Income Fund
The Fund has investments in three core businesses:
renewable and alternative power generation (Green Power);
crude oil and liquids pipeline transportation and storage
(Liquids Transportation and Storage); and a 50% interest
in Alliance Pipeline Canada. Within Green Power, the Fund
has interests in over 500 MW of renewable and alternative
power generation capability. Liquids Transportation and
Storage operates a crude oil gathering system and trunkline
pipeline in southern Saskatchewan and southwestern
Manitoba, connecting to Enbridge’s mainline pipeline to the
United States (the Saskatchewan System). The Fund’s Liquids
Transportation and Storage also includes the Canadian
portion of the Bakken Expansion Program as well as the
Hardisty Contract Terminals and Hardisty Storage Caverns
located near Hardisty, Alberta.
Enbridge Income Fund
Fort St. John
Alliance Pipeline (Canada)
Edmonton
Hardisty
Regina
Saskatchewan
System
Alliance Pipeline (US)
NRGreen
waste-heat power
generation
Liquids pipelines
Gas pipelines
Crude oil
storage
Wind assets
Solar assets
Chicago
94 Enbridge Inc. 2013 Annual Report
Crude Oil Storage and Renewable Energy Transfers
Saskatchewan System Shipper Complaint
In December 2012, ENF and the Fund finalized the acquisition
of Hardisty Storage Caverns, Hardisty Contract Terminals
and the Greenwich, Amherstburg and Tilbury projects from
Enbridge and its wholly-owned subsidiaries for an aggregate
purchase price of approximately $1.2 billion, financed in part
by the issuance of additional ordinary trust units of the Fund
to ENF and additional Enbridge Commercial Trust (ECT)
preferred units to Enbridge. ENF in turn issued additional
common shares to the public and to Enbridge. Enbridge also
provided bridge debt financing (Bridge Financing) to the
Fund for the balance of the purchase price, which was repaid
in December 2012. Enbridge’s overall economic interest in
the Fund was reduced from 69.2% to 67.7% upon completion
of the transaction.
In October 2011, the Fund also acquired the Ontario Wind,
Sarnia Solar and Talbot Wind energy projects from a
wholly-owned subsidiary of Enbridge for an aggregate price
of approximately $1.2 billion. The transaction was financed
by the Fund through a combination of debt and equity,
including the issuance of additional ordinary trust units of
the Fund to ENF and ECT preferred units to Enbridge. ENF
in turn issued additional common shares to the public and
to Enbridge. Enbridge provided Bridge Financing for the
balance of the purchase price. Enbridge’s overall economic
interest in the Fund was reduced from 72.3% to 69.2% upon
completion of the transaction and associated financing.
The asset transfers described above occurred between
entities under common control of Enbridge, and the
intercompany gains realized by the selling entities in each
of the years ended December 31, 2012 and 2011 have been
eliminated from the Consolidated Financial Statements of
Enbridge. Income taxes of $56 million and $98 million for
the years ended December 31, 2012 and 2011, respectively,
incurred on the related capital gains remain as charges to
consolidated earnings. The Company retains the benefit
of cash taxes paid in the form of increased tax basis of its
investment in the underlying entities; however, accounting
recognition of such benefit is not permitted until such time
as the entities are sold outside of the consolidated group.
Through these transactions, which essentially resulted in a
partial monetization of these assets by Enbridge through sale
to noncontrolling interests (being ENF’s public shareholders),
Enbridge realized a source of funds of $213 million and
$210 million, as presented within Financing Activities on the
Consolidated Statements of Cash Flows for the years ended
December 31, 2012 and 2011, respectively. In December 2012,
the Fund issued $500 million in medium-term notes. The
funds from this issuance, together with its cash on hand and
draws on the Fund’s committed credit facility, were used to
repay the $582 million Bridge Financing to Enbridge.
On April 1, 2013, the Fund announced it concluded a
settlement (the Settlement) with a group of shippers resulting
in new tolls on the Westspur System. At the request of certain
shippers that did not execute the Settlement, the NEB did
not remove the interim status from the historical tolls and
made the new tolls interim as well. A modified agreement
was subsequently entered into with substantially all of the
shippers, and such shippers requested the NEB make both the
historical tolls and the new tolls (collectively, the Tolls) final.
On February 6, 2014, the NEB ordered the Tolls final.
The Settlement establishes a toll methodology for an initial
term of five years, with additional one year renewal terms
unless otherwise terminated. Pursuant to the Settlement,
the tolls on the Westspur System will be fixed and increased
annually with reference to an inflation index, subject to
throughput remaining within a prescribed volume band close
to volumes recently transported on the Westspur System.
The Settlement resulted in the discontinuance of rate-
regulated accounting for the Westspur System and the Fund
recorded an after-tax write-down of approximately $12 million
($4 million after-tax attributable to Enbridge) in the first
quarter of 2013 related to a deferred regulatory asset which
will not be collected under the terms of the Settlement.
Incentive and Management Fees
Enbridge receives an annual base management fee for
administrative and management services it provides to
the Fund, plus incentive fees. Incentive fees are paid to
Enbridge based on cash distributions paid by the Fund that
exceed a base distribution amount. In 2013, the Company
received intercompany incentive fees of $20 million
(2012 - $12 million; 2011 - $10 million) before income taxes.
Enbridge also provides management services to ENF.
No additional fee is charged to ENF for these services
provided the Fund is paying a fee to Enbridge.
Results of Operations
Earnings for the Fund increased from $85 million for the
year ended December 31, 2012 to $110 million for the year
ended December 31, 2013. The increase in earnings was
attributable to earnings from crude oil storage and renewable
energy assets acquired from Enbridge and its wholly-owned
subsidiaries in December 2012. Earnings were also positively
impacted by higher preferred unit distributions received from
the Fund and earnings from the Bakken Expansion Program,
which commenced operations in March 2013. Partially
offsetting these sources of earnings growth was higher
interest expense and a one-time charge recognized in the first
quarter of 2013 related to the write-off of a regulatory deferral
balance for which recoverability is no longer probable.
Management’s Discussion and Analysis 95
Liquids Transportation and Storage
Competition
Liquids Transportation and Storage, including the
Saskatchewan System, faces competition in pipeline
transportation from other pipelines as well as other
forms of transportation, most notably rail. These
alternative transportation options could charge rates
or provide service to locations that result in greater net
profit for shippers, thereby reducing shipments on the
Saskatchewan System or resulting in pressure to reduce
tolls. The Saskatchewan System’s right-of-way and
expansion efforts provide a competitive advantage.
Economic Regulation
Certain pipelines within the Saskatchewan System are subject
to the actions of various regulators, including the NEB.
Actions of the regulators related to tariffs, tolls and facilities
impact earnings and the success of expansion projects.
Delays in regulatory approvals could result in cost escalations
and construction delays. Changes in regulation, including
decisions by regulators on the applicable tariff structure or
changes in interpretations of existing regulations by courts or
regulators, could adversely affect the results of operations of
the Fund and could adversely impact the timing and amount
of recovery or settlement of regulatory balances.
Earnings from the Fund totalled $85 million for the year ended
December 31, 2012 compared with $50 million for the year
ended December 31, 2011. The increased earnings from the
Fund reflected a full year of earnings from the assets acquired
from a wholly-owned subsidiary of Enbridge in October
2011. Earnings also reflected the December 2012 transfer of
Hardisty Storage Caverns, Hardisty Contract Terminals and
the Greenwich, Amherstburg and Tilbury projects. Partially
offsetting the earnings contributions were increased interest
costs, higher business development expense and non-cash
deferred income taxes.
Business Risks
Risks for Alliance Pipeline Canada are similar to those
identified for Alliance Pipeline US in the Gas Pipelines,
Processing and Energy Services segment. The following risks
generally relate to Green Energy and Liquids Transportation
and Storage, as indicated. General risks that affect the
Company as a whole are described under Risk Management
and Financial Instruments – General Business Risks.
Green Energy
Asset Utilization
Earnings from Green Energy assets are highly dependent on
weather and atmospheric conditions as well as continued
operational availability of these energy producing assets.
While the expected energy yields for Green Energy projects
are predicted using long-term historical data, wind and solar
resources will be subject to natural variation from year to
year and from season to season. Any prolonged reduction
in wind or solar resources at any of Green Energy facilities
could lead to decreased earnings for the Fund. Additionally,
inefficiencies or interruptions of Green Energy facilities due
to operational disturbances could also impact earnings.
The Company may mitigate the risk of operational availability
by establishing Operations and Maintenance contracts
with the original equipment manufacturers that include a
negotiated operational performance asset guarantee.
The Company also monitors the operational reliability of
the assets on a 24-hour basis to monitor asset performance.
96 Enbridge Inc. 2013 Annual Report
Corporate
Earnings
(millions of Canadian dollars)
Noverco
Other Corporate
Adjusted loss
Noverco – changes in unrealized derivative fair value gains/(loss)
Noverco – equity earnings adjustment
Other Corporate – changes in unrealized derivative fair value loss
Other Corporate – impact of tax rate changes
Other Corporate – foreign tax recovery
Other Corporate – asset impairment loss
Other Corporate – unrealized foreign exchange gains/(loss) on translation
of intercompany balances, net
Other Corporate – tax on intercompany gain on sale
Loss attributable to common shareholders
2013
2012
2011
54
(82)
(28)
4
–
(306)
18
4
(6)
–
–
(314)
27
(57)
(30)
(10)
(12)
(22)
(11)
29
–
(17)
(56)
(129)
24
(40)
(16)
–
–
(87)
6
–
–
24
(98)
(171)
Total adjusted loss from Corporate was $28 million for the year ended December 31, 2013 compared
with adjusted losses of $30 million for the year ended December 31, 2012 and $16 million for the year
ended December 31, 2011. The increase in adjusted loss reflected higher dividends paid on additional
preference shares issued to fund the Company’s growth projects. Partially offsetting the increased loss
were higher contributions from Noverco’s underlying assets.
Corporate earnings/(loss) were impacted by the following adjusting items:
• Noverco earnings for 2013 and 2012 included changes in the unrealized fair value gains or losses on
derivative financial instruments.
• Noverco earnings for 2012 included an unfavourable equity earnings adjustment related to prior periods.
• Other Corporate loss for each period included changes in the unrealized fair value loss on derivative
financial instruments related to forward foreign exchange risk management positions.
• Other Corporate loss for each period reflected the anticipated future impact of tax rate changes.
• Other Corporate loss for 2013 and 2012 were reduced by recovery of taxes related to a historical
foreign investment.
• Other Corporate loss for 2013 included charges related to asset impairment losses.
• Other Corporate loss for 2012 and 2011 included net unrealized foreign exchange gain/(loss) on the
translation of foreign-denominated intercompany balances.
• Other Corporate loss for 2012 and 2011 were impacted by tax on an intercompany gain on sale.
See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy
Transfers for details of the transactions.
Management’s Discussion and Analysis 97
Noverco
Results of Operations
Noverco adjusted earnings increased to $54 million for
the year ended December 31, 2013 from $27 million for
the year ended December 31, 2012. Noverco adjusted
earnings included returns on the Company’s preferred share
investment as well as its equity earnings from Noverco’s
underlying gas and power distribution investments.
The increase in adjusted earnings was primarily attributable
to higher volumes within Gaz Metro’s Quebec-based gas
distribution franchise area, contributions from a full year of
operations of power distribution assets acquired in mid-2012
and a small one-time gain on sale of assets of approximately
$3 million. Adjusted earnings also increased slightly due
to higher preferred share investment earnings. Partially
offsetting the adjusted earnings increase was a lower ROE
allowed by the regulator for Gaz Metro.
Noverco’s investment in power distribution operations is
subject to seasonality, similar to gas distribution operations,
with the majority of its annual earnings achieved during the
colder months of the first quarter. This seasonal pattern
heightens the effect of the earnings increase attributable
to the power distribution acquisition since the 2013 results
included the first quarter, whereas 2012 did not given that
the acquisition took place mid-year.
Noverco adjusted earnings were $27 million for the year ended
December 31, 2012 compared with $24 million for the year
ended December 31, 2011 and reflected contributions from
the Company’s increased preferred share investment and
Noverco’s underlying gas distribution investments.
Enbridge owns an equity interest in Noverco through
ownership of 38.9% of its common shares and an investment
in preferred shares. Noverco is a holding company that
owns approximately 71% of Gaz Metro Limited Partnership
(Gaz Metro), a natural gas distribution company operating in
the province of Quebec with interests in subsidiary companies
operating gas transmission, gas distribution and power
distribution businesses in the province of Quebec and the
state of Vermont. Noverco also holds, directly and indirectly,
an investment in Enbridge common shares. In both 2013
and 2012, the Board of Directors of Noverco authorized the
sale of a portion of its Enbridge common share holding to
rebalance Noverco’s asset mix. On May 28, 2013, Noverco
sold 15 million Enbridge common shares through a secondary
offering. Enbridge’s share of the net after-tax proceeds of
approximately $248 million was received as dividends from
Noverco on June 4, 2013 and was used to pay a portion of
the Company’s quarterly dividend on September 1, 2013.
A portion of this dividend did not qualify for the enhanced
dividend tax credit in Canada and, accordingly, was not
designated as an “eligible dividend”. The dividend was a
“qualified dividend” for United States tax purposes.
On March 22, 2012, Noverco sold 22.5 million Enbridge
common shares through a secondary offering. Enbridge’s
share of the proceeds of approximately $317 million was
received as a dividend from Noverco on May 18, 2012 and
was used to pay a portion of the Company’s quarterly
dividend on June 1, 2012. This portion of the quarterly
dividend did not qualify for the enhanced dividend tax
credit in Canada and, accordingly, was not designated as an
“eligible dividend”. The dividend was a “qualified dividend”
for United States tax purposes.
A significant portion of the Company’s earnings from Noverco
is in the form of dividends on its preferred share investments
which are based on the yield of 10-year Government of
Canada bonds plus a margin of 4.3% to 4.4%.
98 Enbridge Inc. 2013 Annual Report
Other Corporate
Corporate also consists of the new business development activities, general corporate investments
and financing costs not allocated to the business segments. Other corporate costs include dividends
on preference shares as such dividends are a deduction in determining earnings attributable to
common shareholders.
Preference Share Issuances
Since July 2011, the Company has issued 204 million preference shares for gross proceeds of
approximately $5,127 million with the following characteristics. See Outstanding Share Data.
(Canadian dollars, unless otherwise stated)
Series B5
Series D5
Series F5
Series H5
Series J5
Series L5
Series N5
Series P5
Series R5
Series 15
Series 35
Series 55
Series 75
Gross Proceeds
Initial
Yield
Dividend1
Per Share Base2
Redemption2
Value2
Redemption and2,3
Conversion Option2,3
Date2,3
Right to
Convert Into3,4
$500 million
$450 million
$500 million
$350 million
US$200 million
US$400 million
$450 million
$400 million
$400 million
US$400 million
$600 million
US$200 million
$250 million
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.4%
4.4%
$1.00
$1.00
$1.00
$1.00
US$1.00
US$1.00
$1.00
$1.00
$1.00
US$1.00
$1.00
US$1.10
$1.10
$25
$25
$25
$25
US$25
US$25
$25
$25
$25
US$25
June 1, 2017
March 1, 2018
June 1, 2018
September 1, 2018
June 1, 2017
September 1, 2017
December 1, 2018
March 1, 2019
June 1, 2019
June 1, 2018
$25
September 1, 2019
US$25
$25
March 1, 2019
March 1, 2019
Series C
Series E
Series G
Series I
Series K
Series M
Series O
Series Q
Series S
Series 2
Series 4
Series 6
Series 8
1
2
3
The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company.
The Company may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid
dividends on the Redemption Option Date and on every fifth anniversary thereafter.
The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on the
Conversion Option Date and every fifth anniversary thereafter.
4 Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day
Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S),
2.4% (Series 4) or 2.6% (Series 8)); or US$25 x (number of days in quarter/365) x (three month United States Government treasury bill rate + 3.1% (Series K),
3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6)).
For dividends declared, see Liquidity and Capital Resources – Financing Activities.
5
Common Share Issuance
On April 16, 2013, the Company completed the issuance of 13 million Common Shares for gross
proceeds of approximately $600 million. The proceeds were used to fund the Company’s growth
projects, reduce outstanding indebtedness, invest in subsidiaries and for general corporate purposes.
Results of Operations
Other Corporate adjusted loss was $82 million for the year ended December 31, 2013 compared with an
adjusted loss of $57 million for the year ended December 31, 2012. The increased loss was attributable
to dividends paid on additional preference shares issued to fund the Company’s slate of growth
projects. Partially offsetting increased preference share dividends were lower net Corporate segment
finance costs and lower operating and administrative costs.
Other Corporate adjusted loss was $57 million for the year ended December 31, 2012 compared with an
adjusted loss of $40 million for the year ended December 31, 2011 and also reflected higher dividends
paid on incremental preference shares issued.
Management’s Discussion and Analysis 99
Liquidity and Capital
Resources
The maintenance of financial strength and flexibility is
fundamental to Enbridge’s growth strategy, particularly
in light of the level of growth projects secured or under
development. Access to timely funding from capital markets
could be limited by factors outside its control, including
but not limited to financial market volatility resulting from
economic and political events both inside and outside
North America. To mitigate such risks, the Company
actively manages financing plans and strategies to ensure
it maintains sufficient liquidity to meet routine operating
and future capital requirements. The Company targets to
maintain sufficient standby liquidity to bridge fund through
protracted capital markets disruptions of up to one year.
In the near term, the Company generally expects to utilize
cash from operations and the issuance of debt, commercial
paper and/or credit facility draws to fund liabilities as
they become due, finance capital expenditures, fund
debt retirements and pay common and preference share
dividends. The Company’s financing plan is regularly
updated to reflect evolving capital requirements and
financial market conditions and it identifies potential sources
of debt and equity funding alternatives, including utilization
of its sponsored vehicles, with the objective of diversifying
funding sources and maintaining access to low cost capital.
The Company’s financing strategy includes optimizing the
funding of its enterprise-wide slate of growth projects,
including through its sponsored vehicles. During 2013,
several actions were taken to enhance liquidity at EEP during
the next several years until its growth capital commitments
are permanently funded:
• On May 8, 2013, Enbridge invested US$1.2 billion in
preferred units issued by EEP. The preferred units, with
a price per unit of $25 (par value), have a fixed yield of
7.5% with the rate to be reset every five years. Under
the preferred units terms, quarterly cash distributions
will not be payable in cash during the first eight quarters
and will be added to the redemption value. Quarterly
cash distributions will be payable beginning in the ninth
quarter and deferred distributions are payable on the fifth
anniversary or when redemption of the units takes place.
The preferred units will be redeemable at EEP’s option
on the five-year anniversary of the issuance and every
fifth year thereafter, at par and including the deferred
distribution. Earlier redemption is permitted under certain
events including the ability to redeem the preferred units
using the net proceeds from EEP’s equity issuances or from
the sale of assets and from the issuance of debt, in equal
amounts. In addition, on or after June 1, 2016, at Enbridge’s
sole option, the preferred units can be converted into
approximately 43.2 million common units of EEP.
100 Enbridge Inc. 2013 Annual Report
• On June 28, 2013, EEP exercised options to reduce its
funding and associated economic interest in each of the
Eastern Access (excluding the Toledo Expansion and
Line 9 Reversal and Expansion) and the Lakehead System
Mainline Expansion projects by 15% to 25%. EEP retains
the option to increase its economic interest back up to
40% in each of these projects within one year of their
respective final project in-service dates.
• Also on June 28, 2013, a wholly-owned subsidiary of
Enbridge entered into an agreement with EEP and certain
of its subsidiaries to purchase accounts receivable
on a monthly basis through 2016, up to a maximum of
US$350 million at any one point, which was further
amended to a monthly maximum of US$450 million on
September 20, 2013, and again on December 2, 2013.
• On November 13, 2013, MEP, a subsidiary of EEP,
completed its IPO of 18.5 million Class A common units
representing limited partner interests and subsequently
issued an additional 2.8 million Class A common units
pursuant to the exercise of an underwriters’ option. MEP
received proceeds of approximately US$355 million from
the offering. Upon finalization of the offering, MEP’s
initial assets consisted of an approximate 39% ownership
interest in EEP’s natural gas and NGL midstream
business. EEP, through certain of its subsidiaries, holds a
2% GP interest and the remaining limited partner interest
in MEP. See Sponsored Investments – Enbridge Energy
Partners, L.P. – Midcoast Energy Partners, L.P. Initial
Public Offering.
In accordance with its financing plan, the Company has been
active in the capital markets with the following issuances
during 2013:
• Corporate - $1,467 million in preference shares;
$600 million in common shares; $1,888 million of
medium-term notes;
• Enbridge Pipelines Inc. (EPI) - $550 million of
medium-term notes;
• EGD - $400 million medium-term notes;
• EEM - US$509 million in listed shares;
• MEP - US$355 million in common units; and
• The Fund - $96 million in common units.
In addition to these debt and equity issuances, the Company
received dividends of approximately $248 million from its
investment in Noverco which resulted from Noverco’s sale of
Enbridge shares via a secondary offering.
To ensure ongoing liquidity and to mitigate the risk of capital
market disruption, Enbridge also significantly bolstered its
committed bank credit facilities in 2013, including securement of a US$850 million facility by MEP.
In addition to ensuring adequate liquidity, the Company actively manages its bank funding sources to
optimize pricing and other terms. The following table provides details of the Company’s credit facilities
at December 31, 2013 and 2012.
December 31, 2013
December 31, 2012
Maturity
Dates2
Total
Facilities
Draws3
Available
Total Facilities
(millions of Canadian dollars)
Liquids Pipelines
Gas Distribution
Sponsored Investments
Corporate
2015
2014 – 2019
2015 – 2018
2015 – 2018
Southern Lights project financing1
2014 – 2015
Total credit facilities
300
713
4,781
11,805
17,599
1,570
19,169
266
382
809
3,651
5,108
1,498
6,606
34
331
3,972
8,154
12,491
72
12,563
1
2
3
Total facilities inclusive of $63 million for debt service reserve letters of credit.
Total facilities include $35 million in demand facilities with no specified maturity date.
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
300
712
3,162
9,108
13,282
1,484
14,766
Excluding project financing, the Company’s net available liquidity of $12,909 million at
December 31, 2013 was inclusive of $756 million of unrestricted cash and cash equivalents
and net of bank indebtedness of $338 million.
The Company’s credit facility agreements include standard events of default and covenant provisions
whereby accelerated repayment may be required if the Company were to default on payment or violate
certain covenants. As at December 31, 2013, the Company was in compliance with all debt covenants
and expects to continue to comply with such covenants.
Strong growth in internal cashflow, ready access to liquidity from diversified sources and a stable
business model have enabled Enbridge to obtain and maintain a strong credit profile. The Company
actively monitors and manages key financial metrics with the objective of sustaining investment grade
credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt
capital under attractive terms. Key measures of financial strength that are closely managed include
the ability to service debt obligations from operating cash flow and the ratio of debt to total capital.
As at December 31, 2013, the Company’s debt capitalization ratio was 58.2% compared with 60.2%
as at December 31, 2012.
The Company invests a portion of its surplus cash in short-term investment grade instruments with
creditworthy counterparties. Short-term investments were $85 million as at December 31, 2013
compared with $950 million as at December 31, 2012. Surplus cash at December 31, 2013 arose primarily
due to pre-funding of equity requirements and will be used to fund the Company’s growth projects.
There are no material restrictions on the Company’s cash with the exception of restricted cash of
$7 million related to Southern Lights project financing and cash in trust of $27 million for specific
shipper commitments. Cash and cash equivalents held by EEP and the Fund are generally not readily
accessible by Enbridge until distributions are declared and paid by these entities, which occurs
quarterly for EEP and monthly for the Fund. Further, cash and cash equivalents held by certain foreign
subsidiaries may not be readily accessible for alternative uses by Enbridge.
Excluding current maturities of long-term debt, the Company had a negative working capital position
of $967 million at December 31, 2013 compared with a positive working capital position of $183 million
at December 31, 2012. The decrease in working capital is mainly attributable to a reduction in cash
on hand combined with an increase in construction payables, both of which temporarily fund growth
capital expenditures. Partially offsetting these decreases was an increase in accounts receivable in
respect of the Company’s operations that have grown period-over-period.
Management’s Discussion and Analysis
101
Despite the negative working capital as at December 31, 2013, the Company has significant net
available liquidity through committed credit facilities and other sources as previously discussed, which
allow the funding of liabilities as they become due. As at December 31, 2013, the net available liquidity
totalled $12,909 million. In addition, it is anticipated that any current maturities of long-term debt will
be refinanced upon maturity.
December 31,
(millions of Canadian dollars)
Cash and cash equivalents1
Accounts receivable and other2
Inventory
Assets held for sale3
Bank indebtedness
Short-term borrowings
Accounts payable and other4
Interest payable
Environmental liabilities
Working capital
1
2
Includes short-term investments and restricted cash of amounts in trust.
Includes Accounts receivable from affiliates.
3 Net of current liabilities held for sale.
4
Includes Accounts payable to affiliates.
Operating Activities
Cash provided by operating activities for the year ended December 31, 2013 was
$3,341 million compared with $2,874 million and $3,371 million for the years ended
December 31, 2012 and 2011, respectively. Excluding the timing effect of changes
in operating assets and liabilities, the Company has delivered a growing cash flow
stream over the last two years.
The cash flow increase was attributable in part to the successful completion of
significant projects in recent years. As discussed in Performance Overview, new
Liquids Pipelines assets placed into service in 2012 and 2013, completion of Bakken
Expansion in 2013 and addition of five wind farms and two solar farms between
2011 and 2013 all contributed to the increase in period-over-period operating cash
flows. In addition to the new assets, the Company’s core businesses also achieved
higher operating cash flows in 2013, mainly attributable to higher throughput in
Liquids Pipelines, favourable market conditions in Energy Services and stronger
contributions from EEP and the Fund. Partially offsetting the positive factors for
2013 were higher financing costs as the Company significantly advanced its funding
plan in 2013, as well as lower dividend paid by Noverco in 2013 compared with 2012.
In 2013, Noverco paid Enbridge a one-time dividend of $248 million compared with
$317 million paid in 2012 upon realization of a substantial gain on the disposition of a
portion of its investment in Enbridge shares.
The Company’s operating assets and liabilities fluctuate due to variations in
commodity prices and sales volumes within Energy Services, the timing of tax
payments, the payment of power deposits to support the Company’s growth
projects, as well as general variations in activity levels within the Company’s
businesses. The year-over-year increase in cash provided by operating activities
in 2013 was impacted by a favourable variance of $251 million for changes in
operating assets and liabilities, mainly attributable to higher activity in the
Company’s marketing and gas distribution businesses, which had higher accounts
payable balance resulting from higher purchases, partially offset by increases in
accounts receivable and inventory balances.
102 Enbridge Inc. 2013 Annual Report
2013
2012
790
5,021
1,115
17
(338)
(374)
(6,710)
(228)
(260)
(967)
1,795
4,026
779
–
(479)
(583)
(5,052)
(196)
(107)
183
Cash Provided by
Operating Activities
(millions of Canadian dollars)
1
1
7
3
,
3
1
1
4
3
,
3
1
4
7
8
,
2
2
7
1
0
,
2
1
7
7
8
,
1
09
10
11
12
13
1 Financial information has been
extracted from financial statements
prepared in accordance with
U.S. GAAP.
2 Financial information has been
extracted from financial statements
prepared in accordance with
Canadian GAAP.
Cash provided by operating activities for 2012 was lower compared to 2011
primarily due to an unfavourable variance of $1,061 million in the changes
in operating assets and liabilities. In addition, cash from operating activities
during the fourth quarter of 2012 included an outflow of US$202 million related
to a voluntary pre-payment of certain derivative liabilities. The payment was
transacted to optimize cash management opportunities and did not alter the risk
management properties of the derivative position. These cash outflows were
partially offset by the favourable operating performance of the Canadian Mainline
under CTS, strong volumes across all of the Company’s liquids pipelines assets
and general cash growth from development projects placed in service in recent
years. The dividend received from Noverco in 2012, as discussed above, also
impacted the period-over-period cash flows for 2012.
Investing Activities
Cash used in investing activities was $9,431 million for the year ended
December 31, 2013 compared with $6,204 million for the year ended
December 31, 2012 and $5,079 million for the year ended December 31, 2011.
Cash used in investing activities has increased on a year-over-year basis primarily
due to additions to property, plant and equipment associated with construction
of the Company’s expansion initiatives, which are described in Growth Projects –
Commercially Secured Projects. A summary of additions to property, plant and
equipment for the years ended December 31, 2013, 2012 and 2011 is as follows:
Year ended December 31,
(millions of Canadian dollars)
Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing and Energy Services
Sponsored Investments
Corporate
Total capital expenditures
Capital Ependitures
and Investments
(millions of Canadian dollars)
5
3
2
,
8
4
9
1
,
5
7
2
5
,
3
11
12
13
■ Liquids Pipelines
■ Gas Distribution
■ Gas Pipelines, Processing
and Energy Services
■ Sponsored Investments
■ Corporate
2013
2012
2011
4,359
533
744
2,565
34
8,235
1,926
445
933
1,886
4
5,194
906
478
959
1,157
27
3,527
Other notable investing activities in 2013 and 2012 included the funding of various investment and joint
ventures, primarily the Texas Express NGL System and Seaway Pipeline. The Company’s investing
activities for the year ended December 31, 2012 also included the acquisition of Silver State and
Pipestone and Sexsmith, as well as the remaining 10% interest in Greenwich. In comparison, for the
year ended December 31, 2011, the Company acquired its original 50% interest in Seaway Pipeline and
increased its Noverco preferred shares investment.
Management’s Discussion and Analysis
103
Financing Activities
Cash generated from financing activities was $5,070 million for the year ended December 31, 2013
compared with $4,395 million for the year ended December 31, 2012 and $2,030 million for the year
ended December 31, 2011. The cash inflow from financing activities has increased over the 2011 to
2013 time frame as the Company executed its funding and liquidity plan in support of its long-term
growth plan. During 2013, the Company raised a total of $4,901 million through capital markets
transactions, including $1,428 million in preference shares, $628 million in common shares and
$2,845 million of medium-term notes. The Company also bolstered its liquidity in 2013 through the
securement of additional credit facilities and increased draws on such facilities and commercial paper
by $1,562 million in the year. The additional preference and common shares outstanding during the year
together with an 11% increase in the common share dividend rate, gave rise to an increase in dividends
paid in 2013 compared with the prior year.
Financing activities also included transactions between the Company’s sponsored investments and
their public unitholders, also referred to as noncontrolling interests. Significant transactions during
the year included the IPO by MEP which raised proceeds of US$355 million. EEM and the Fund also
completed issuances of units to the public of US$509 million and $96 million, respectively, in support
of the growth initiatives underway by each of those entities. The Company’s sponsored vehicles also
pay quarterly distributions to their public unitholders in accordance with distribution policies approved
by their respective Boards.
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, 2013,
dividends declared were $1,035 million (2012 - $895 million), of which $674 million (2012 - $597 million)
were paid in cash and reflected in financing activities. The remaining $361 million (2012 - $297 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 years ended December 31, 2013 and 2012, 34.9% and 33.2%,
respectively, of total dividends declared were reinvested.
On December 4, 2013, the Enbridge Board of Directors declared the following quarterly dividends with
the exception of Preference Shares, Series 7, which was declared on January 15, 2014. All dividends are
payable on March 1, 2014 to shareholders of record on February 14, 2014.
Common Shares
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J
Preference Shares, Series L
Preference Shares, Series N
Preference Shares, Series P
Preference Shares, Series R
Preference Shares, Series 1
Preference Shares, Series 3
Preference Shares, Series 5
Preference Shares, Series 71
$0.35000
$0.34375
$0.25000
$0.25000
$0.25000
$0.25000
US$0.25000
US$0.25000
$0.25000
$0.25000
$0.25000
US$0.25000
$0.25000
US$0.27500
$0.23810
1
A cash dividend of $0.2381 per share will be payable on March 1, 2014 to Series 7 preference shareholders. The regular quarterly dividend of $0.275 per share will
begin in the second quarter of 2014.
104 Enbridge Inc. 2013 Annual Report
Contractual Obligations
Payments due under contractual obligations over the next five years and thereafter are as follows:
(millions of Canadian dollars)
Long-term debt1
Capital and operating leases
Long-term contracts
Pension obligations2
Total contractual obligations
Total
Less than 1 year
1 – 3 years
3 – 5 years
After 5 years
25,532
828
13,347
152
39,859
3,184
116
6,042
152
9,494
2,324
219
2,448
–
4,991
1,911
150
1,742
–
3,803
18,113
343
3,115
–
21,571
1
2
Excludes interest. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements.
Assumes only required payments will be made into the pension plans in 2014. Contributions are made in accordance with independent actuarial valuations
as at December 31, 2013. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.
Capital Expenditure Commitments
The Company has signed contracts for the purchase of services, pipe and other materials totalling
$4,455 million which are expected to be paid over the next five years.
Contingencies
United States Legal and Regulatory Proceedings
A number of United States governmental agencies and regulators have initiated investigations into the
Lines 6A and 6B crude oil releases. Approximately 30 actions or claims are pending against Enbridge,
EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil
release, including direct actions and actions seeking class status. Based on the current status of these
cases, EEP does not expect the outcome of these actions to be material. On July 2, 2012, PHMSA
announced a Notice of Probable Violation related to the Line 6B crude oil release, including a civil
penalty of US$3.7 million that EEP paid in the third quarter of 2012.
EEP’s estimated cost at December 31, 2013 for the Line 6B crude oil release included an amount of
US$22 million related to civil penalties EEP expects to be required to pay under the Clean Water Act.
While no final fine or penalty has been assessed or agreed to date, EEP believes that, based on the best
information available at this time, the US$22 million represents an estimate of the minimum amount
which may be assessed, excluding costs of injunctive relief, if any, that may be agreed to with the
relevant governmental agencies. Given the complexity of settlement negotiations, which EEP expects
will continue, and the limited information available to assess the matter, EEP is unable to reasonably
estimate the final penalty which might be incurred or to reasonably estimate a range of outcomes at
this time. Discussions with governmental agencies regarding fines and penalties are ongoing.
One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates
by the State of Illinois in the Illinois state court. The parties are currently operating under an agreed
interim order. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A
and 6B Crude Oil Releases.
As at December 31, 2013, the Company was not aware of any claims related to the Line 14 crude oil
release. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Line 14 Crude
Oil Release.
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.
Management’s Discussion and Analysis
105
Other Legal and Regulatory Proceedings
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.
Outstanding Share Data
1
Preference Shares, Series A2
Preference Shares, Series B2,3
Preference Shares, Series D2,4
Preference Shares, Series F2,5
Preference Shares, Series H2,6
Preference Shares, Series J2,7
Preference Shares, Series L2,8
Preference Shares, Series N2,9
Preference Shares, Series P2,10
Preference Shares, Series R2,11
Preference Shares, Series 12,12
Preference Shares, Series 32,13
Preference Shares, Series 52,14
Preference Shares, Series 72,15
Common Shares – issued and outstanding (voting equity shares)
Stock Options – issued and outstanding (15,524,712 vested)
Number
5,000,000
20,000,000
18,000,000
20,000,000
14,000,000
8,000,000
16,000,000
18,000,000
16,000,000
16,000,000
16,000,000
24,000,000
8,000,000
10,000,000
831,509,051
33,516,016
1
2
Outstanding share data information is provided as at February 7, 2014.
All preference shares are non-voting equity shares. Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of
Preference Shares, the Company may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all
accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.
3 On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series B will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series B into an equal number of Cumulative Redeemable Preference Shares, Series C.
4 On March 1, 2018, and on March 1 every five years thereafter, the holders of Preference Shares, Series D will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series D into an equal number of Cumulative Redeemable Preference Shares, Series E.
5 On June 1, 2018, and on June 1 every five years thereafter, the holders of Preference Shares, Series F will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series F into an equal number of Cumulative Redeemable Preference Shares, Series G.
6 On September 1, 2018, and on September 1 every five years thereafter, the holders of Preference Shares, Series H will have the right to elect to convert (subject to
certain provisions) any or all of their Preference Shares, Series H into an equal number of Cumulative Redeemable Preference Shares, Series I.
7 On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series J will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series J into an equal number of Cumulative Redeemable Preference Shares, Series K.
8 On September 1, 2017, and on September 1 every five years thereafter, the holders of Preference Shares, Series L will have the right to elect to convert (subject to
certain provisions) any or all of their Preference Shares, Series L into an equal number of Cumulative Redeemable Preference Shares, Series M.
9 On December 1, 2018, and on December 1 every five years thereafter, the holders of Preference Shares, Series N will have the right to elect to convert (subject to
certain provisions) any or all of their Preference Shares, Series N into an equal number of Cumulative Redeemable Preference Shares, Series O.
10 On March 1, 2019, and on March 1 every five years thereafter, the holders of Preference Shares, Series P will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series P into an equal number of Cumulative Redeemable Preference Shares, Series Q.
11 On June 1, 2019 and on June 1 every five years thereafter, the holders of Preference Shares, Series R will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series R into an equal number of Cumulative Redeemable Preference Shares, Series S.
12 On June 1, 2018 and on June 1 every five years thereafter, the holders of Preference Shares, Series 1 will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series 1 into an equal number of Cumulative Redeemable Preference Shares, Series 2.
13 On September 1, 2019 and on September 1 every five years thereafter, the holders of Preference Shares, Series 3 will have the right to elect to convert (subject to
certain provisions) any or all of their Preference Shares, Series 3 into an equal number of Cumulative Redeemable Preference Shares, Series 4.
14 On March 1, 2019 and on March 1 every five years thereafter, the holders of Preference Shares, Series 5 will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series 5 into an equal number of Cumulative Redeemable Preference Shares, Series 6.
15 On March 1, 2019 and on March 1 every five years thereafter, the holders of Preference Shares, Series 7 will have the right to elect to convert (subject to certain
provisions) any or all of their Preference Shares, Series 7 into an equal number of Cumulative Redeemable Preference Shares, Series 8.
106 Enbridge Inc. 2013 Annual Report
Quarterly Financial Information
2013
(millions of Canadian dollars, except for per share amounts)
Revenues
Earnings attributable to common shareholders
Earnings per common share
Diluted earnings per common share
Dividends per common share
EGD – warmer/(colder) than normal weather
Changes in unrealized derivative fair value and intercompany
foreign exchange (gains)/loss
Q1
Q2
Q3
Q4
Total
7,897
7,730
8,998
8,293
32,918
250
0.32
0.31
42
0.05
0.05
421
0.52
0.51
(267)
(0.33)
(0.32)
0.3150
0.3150
0.3150
0.3150
6
207
(2)
–
246
(223)
(13)
613
446
0.55
0.55
1.26
(9)
843
20121
Q1
Q2
Q3
Q4
Total
(millions of Canadian dollars, except for per share amounts)
Revenues
Earnings attributable to common shareholders
Earnings per common share
Diluted earnings per common share
Dividends per common share
EGD – warmer/(colder) than normal weather
Changes in unrealized derivative fair value and intercompany
foreign exchange loss
6,532
5,445
5,676
7,007
24,660
261
0.34
0.34
8
0.01
0.01
187
0.24
0.24
146
0.19
0.18
0.2825
0.2825
0.2825
0.2825
24
110
–
252
–
93
(1)
81
602
0.78
0.77
1.13
23
536
1
Revenues, Earnings attributable to common shareholders, Earnings per common share and Diluted earnings per common share for the 2012 comparative periods
have been revised. See Note 4 to the December 31, 2013 Consolidated Financial Statements.
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 resulting 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.
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 applying hedge accounting, changes in unrealized fair
value gains and losses on these instruments will impact earnings.
Included in earnings are after-tax costs of $40 million, $13 million and $3 million incurred respectively
in the second, third and fourth quarters of 2013, in connection with the Line 37 crude oil release.
Reflected in earnings is the Company’s share of leak remediation costs associated with the Line 6B and
Line 14 crude oil releases. Remediation costs of $24 million, $6 million, $5 million and $9 million were
recognized in the first, second, third and fourth quarter of 2013; $2 million and $7 million in the second
and third quarter of 2012, respectively. Earnings also reflected insurance recoveries associated with the
Line 6B crude oil release of $6 million in the second quarter of 2013 and $24 million in the third quarter
of 2012, respectively.
In the fourth quarter of 2012, the Company recorded an impairment charge of $166 million ($105 million
after-tax) related to certain of its Offshore assets, predominantly located within the Stingray and
Garden Banks corridors. The Company had been pursuing alternative uses for these assets; however,
due to changing competitive conditions in the fourth quarter of 2012, the Company concluded
Management’s Discussion and Analysis
107
that such alternatives were no longer likely to proceed.
Also included in the fourth quarter of 2012 was a $63 million
after-tax gain on recognition of a regulatory asset related to
OPEB within EGD. Fourth quarter earnings for 2012 were also
impacted by the impact of asset transfers between entities
under common control of Enbridge, resulting in income taxes
of $56 million incurred on the related capital gains.
Formal risk management policies, processes and systems
have been designed to mitigate these risks.
The following summarizes the types of market price risks to
which the Company is exposed and the risk management
instruments used to mitigate them. The Company uses a
combination of qualifying and non-qualifying derivative
instruments to manage the risks noted below.
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 – Commercially Secured Projects
and Growth Projects – Other Projects Under Development.
Related Party Transactions
All related party transactions are undertaken in the normal
course of business and, unless otherwise noted, are measured
at the exchange amount, which is the amount of consideration
established and agreed to by the related parties.
Vector, 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,
were $6 million for the year ended December 31, 2013
(2012 - $6 million; 2011 - $6 million).
Certain wholly-owned subsidiaries within Gas Distribution
and Gas Pipelines, Processing and Energy Services have
transportation commitments with several joint venture
affiliates that are accounted for using the equity method.
Total amounts charged for transportation services for
the year ended December 31, 2013 were $222 million
(2012 - $127 million; 2011 - $106 million).
Additionally, certain wholly-owned subsidiaries within
Gas Pipelines, Processing and Energy Services made natural
gas purchases of $99 million (2012 - $15 million; 2011 - nil)
and sales of $10 million (2012 - $7 million; 2011 - $5 million)
with several joint venture affiliates during the year ended
December 31, 2013.
Amounts receivable from affiliates include a series of loans to
Vector totalling $181 million (2012 - $178 million), included in
Deferred amounts and other assets, which require quarterly
interest payments at annual interest rates from 3% to 8%.
Risk Management and
Financial Instruments
Market Price Risk
The Company’s earnings, cash flows and other
comprehensive income (OCI) are subject to movements in
foreign exchange rates, interest rates, commodity prices and
the Company’s share price (collectively, market price risk).
108 Enbridge Inc. 2013 Annual Report
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 investments and
subsidiaries, and certain revenues denominated in United
States dollars and certain expenses denominated in Euros. The
Company has implemented a policy whereby it economically
hedges a minimum level of foreign currency denominated
earnings exposures identified over a five-year forecast
horizon. 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 Company uses a combination of qualifying
and non-qualifying derivative instruments to manage
variability in cash flows arising from its United States dollar
investments and subsidiaries, and primarily non-qualifying
derivative instruments to manage variability arising from
certain revenues denominated in United States dollars.
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, primarily commercial paper. Pay
fixed-receive floating 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 impact of short-term interest rate volatility on
interest expense through 2017 through execution of floating to
fixed interest rate swaps with an average swap rate of 1.5%.
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 program to
significantly mitigate its exposure to long-term interest rate
variability on select forecast term debt issuances through
2018. A total of $10,419 million of future fixed rate term debt
issuances have been hedged at an average swap rate of 3.8%.
The Company also monitors its debt portfolio mix of fixed
and variable rate debt instruments to maintain a consolidated
portfolio of debt which stays within its Board of Directors
approved policy limit of a maximum of 25% floating rate debt
as a percentage of total debt outstanding. The Company uses
primarily qualifying derivative instruments to manage interest
rate risk.
Commodity Price Risk
The Company’s earnings and cash flows are exposed to changes in commodity prices as a result
of ownership interests in certain assets and investments, as well as through the activities of its
energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL.
The Company employs financial derivative instruments to fix a portion of the variable price exposures
that arise from physical transactions involving these commodities. The Company uses primarily
non-qualifying derivative instruments to manage commodity price risk.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price.
The Company has exposure to its own common share price through the issuance of various forms of
stock-based compensation, which affect earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to manage the earnings volatility derived from one form
of stock-based compensation, restricted stock units. The Company uses a combination of qualifying
and non-qualifying derivative instruments to manage equity price risk.
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of derivative instruments on the Company’s consolidated
earnings and consolidated comprehensive income.
Year ended December 31,
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Net investment hedges
Foreign exchange contracts
Amount of gains/(loss) reclassified from Accumulated other comprehensive income (AOCI)
to earnings (effective portion)
Foreign exchange contracts1
Interest rate contracts2
Commodity contracts3
Other contracts4
Amount of gains/(loss) reclassified from AOCI to earnings (ineffective portion and amount excluded
from effectiveness testing)
Interest rate contracts2
Commodity contracts3
Amount of gains/(loss) from non-qualifying derivatives included in earnings
Foreign exchange contracts1
Interest rate contracts2
Commodity contracts3
Other contracts4
2013
2012
2011
56
814
(9)
(2)
(81)
778
(8)
107
1
–
100
51
(3)
48
(738)
(10)
(496)
(3)
(1,247)
(12)
(46)
52
(3)
1
(8)
1
(1)
(3)
2
(1)
23
(3)
20
120
(2)
(765)
(2)
(649)
(22)
(724)
72
6
(26)
(694)
1
(10)
(55)
(2)
(66)
11
5
16
(179)
9
280
4
114
1
2
3
4
Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.
Reported within Interest expense in the Consolidated Statements of Earnings.
Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
Management’s Discussion and Analysis
109
Liquidity Risk
Liquidity risk is the risk that the Company will not be able to
meet its financial obligations, including commitments and
guarantees, as they become due. In order to manage this
risk, the Company forecasts cash requirements over a
12 month rolling time period 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 long-term debt which
includes debentures and medium-term notes. The Company
maintains current shelf prospectuses with 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
with a diversified group of banks and institutions which,
if necessary, enables the Company to fund all anticipated
requirements for approximately one year without accessing
the capital markets. The Company is in compliance with all
the terms and conditions of its committed credit facilities
as at December 31, 2013. 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.
Credit Risk
Entering into derivative financial instruments may result in
exposure to credit risk. Credit risk arises from the possibility
that a counterparty will default on its contractual obligations.
The Company enters into risk management transactions
primarily 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.
The Company generally has a policy of entering into individual
International Swaps and Derivatives Association, Inc.
agreements, or other similar derivative agreements, with the
majority of its derivative counterparties. These agreements
provide for the net settlement of derivative instruments
outstanding with specific counterparties in the event of
bankruptcy or other significant credit event, and would
reduce the Company’s credit risk exposure on derivative
asset positions outstanding with these counterparties in
these particular circumstances.
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. Within Gas Distribution, credit risk
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
110 Enbridge Inc. 2013 Annual Report
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.
Fair Value Measurements
The Company uses the most observable inputs available to
estimate the fair value of its derivatives. When possible, the
Company estimates the fair value of its derivatives based
on quoted market prices. If quoted market prices are not
available, the Company uses estimates from third party
brokers. For non-exchange traded derivatives classified
in Levels 2 and 3, the Company uses standard valuation
techniques to calculate the estimated fair value. These
methods include discounted cash flows for forwards
and swaps and Black-Scholes-Merton pricing models for
options. Depending on the type of derivative and nature of
the underlying risk, the Company uses observable market
prices (interest, foreign exchange, commodity and share)
and volatility as primary inputs to these valuation techniques.
Finally, the Company considers its own credit default swap
spread, as well as the credit default swap spreads associated
with its counterparties, in its estimation of fair value.
General Business Risks
Strategic and Commercial Risks
Public Opinion
Public opinion or reputation risk is the risk of negative impacts
on the Company’s business, operations or financial condition
resulting from changes in the Company’s reputation with
stakeholders, special interest groups, political leadership,
the media or other entities. Public opinion may be influenced
by media attention directed to development projects such
as Northern Gateway. Potential impacts of a negative public
opinion may include loss of business, legal action, increased
regulatory oversight and costs.
Reputation risk often arises as a consequence of some other
risk event, such as in connection with operational, regulatory
or legal risks. Therefore, reputation risk cannot be managed
in isolation from other risks. The Company manages
reputation risk by:
• having health, safety and environment management
systems in place, as well as policies, programs and
practices for conducting safe and environmentally
sound operations with an emphasis on the prevention
of any incidents;
• having formal risk management policies, procedures
and systems in place to identify, assess and mitigate
risks to the Company;
• operating to the highest ethical standards, with
integrity, honesty and transparency, and maintaining
positive relationships with customers, investors,
employees, partners, regulators and other stakeholders;
• having strong corporate governance practices,
including a Statement on Business Conduct, which
requires all employees to certify their compliance with
Company policy on an annual basis, and whistleblower
procedures, which allow employees to report suspected
ethical concerns on a confidential and anonymous
basis; and
• pursuing socially responsible operations as a longer-
term corporate strategy (implemented through the
Company’s CSR Policy, Climate Change Policy,
Aboriginal and Native American Policy and the Neutral
Footprint Initiative).
Project Execution
As the Company increases its slate of growth projects, it
continues to focus on completing projects safely, on-time
and on-budget. However, the Company faces the challenge
of scaling the business to manage an unprecedented number
of commercially secured growth projects. 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, inadequate
resources, in-service delays and increasing complexity of
projects (collectively, Execution Risk).
Early stage project risks include right-of-way procurement,
special interest group opposition, Crown consultation and
environmental and regulatory permitting. Cost escalations
or missed in-service dates on future projects may impact
future earnings and cashflows and may hinder the
Company’s ability to secure future projects. Construction
delays due to regulatory delays, third-party opposition,
contractor or supplier non-performance and weather
conditions may impact project development.
The Company strives to be an industry leader in project
execution through Major Projects. Major Projects is centralized
and has a 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. Early stage project
risks are mitigated by early assessment of stakeholder issues
to develop proactive relationships and specific action plans.
Consultations with regulators are held in-advance of project
construction to enhance understanding of project rationale
and ensure applications are compliant and robust, while at all
times maintaining a strong focus on integrity and public safety.
Detailed cost tracking and centralized purchasing is used on
all major projects to facilitate optimum pricing and service
terms. Strategic relationships have been developed with
suppliers and contractors and those selected are chosen based
on the Company’s strict adherence to safety including robust
safety standards embedded in contracts with suppliers. The
Company has assessed work volumes across the next several
years across its major projects to optimize the expected costs,
supply of services, material and labour to execute the projects.
Underpinning this approach is Major Project’s Project Lifecycle
Gating Control tool which helps to ensure schedule, cost,
safety and quality objectives are on track and met for each
stage of a project’s development and construction.
Planning and Investment Analysis
The Company evaluates expansion projects, acquisitions and
divestitures on an ongoing basis. Planning and investment
analysis is highly dependent on accurate forecasting
assumptions and to the extent that these assumptions do
not materialize, financial performance may be lower or more
volatile than expected. Volatility and unpredictability in the
economy, both locally and globally, change in cost estimates,
project scoping and risk assessment could result in a loss in
profits for the Company. Large scale acquisitions may involve
significant pricing and integration risk.
The planning and investment analysis process involves
all levels of management and Board of Directors’ review
to ensure alignment across the Company. A centralized
corporate development group rigorously evaluates all major
investment proposals with consistent due diligence processes,
including a thorough review of the asset quality, systems and
financial performance of the assets being assessed.
Human Resources
Like many other companies in the energy sector, Enbridge
faces a risk that it will be unable to attract and retain the
necessary skilled people resources to fulfill its growth plan.
In response to the needs of commercially secured growth
projects, the Company expects to require approximately
1,000 new positions over the next three years. Factors which
could impact Enbridge’s ability to secure these resources
include labour shortages, particularly within the Alberta
market and the shortage of technically skilled workers; rates
of retirement and turnover and the ability to successfully
transfer knowledge; and retaining Enbridge’s reputation as
a great employer.
Operational and Economic Regulation
Many of the Company’s operations are regulated and are
subject to both operational and economic 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.
Management’s Discussion and Analysis
111
Operational regulation risk relates to the failure to comply
with applicable operational rules and regulations from
government organizations and could result in fines or
operating restrictions or an overall increase in operating
and compliance costs. The Company believes operational
regulation risk is mitigated by active monitoring and
consulting on potential regulatory requirement changes
with the respective regulators, directly or through industry
associations. The Company also develops robust response
plans to regulatory changes or enforcement actions.
As stated previously, while the Company believes the safe
and reliable operation of its assets is the best manner to
adhere to existing regulations, the potential remains for
regulators to make unilateral decisions that could have a
non-recoverable financial impact on the Company.
Economic regulation risk relates to the risk regulators or
other government entities change or reject proposed or
existing commercial arrangements. These changes may
adversely affect toll structures, other aspects of pipeline
operations or the operations of shippers. Recently, shippers
have challenged toll increases on various pipelines owned
by Enbridge and some of Enbridge’s competitors. Enbridge
retains dedicated professional staff and maintains strong
relationships with customers, interveners and regulators to
help minimize economic and regulation risk.
Operational Risks
Environmental Incident
An environmental incident could have lasting reputational
impacts to Enbridge and could impact its ability to work with
various stakeholders. In addition to the cost of remediation
activities (to the extent not covered by insurance)
environmental incidents may lead to an increased cost
of operation and insuring the Company’s assets, thereby
negatively impacting earnings. The Company mitigates
risk of environmental incident through its ORM Plan, which
broadly aims to position Enbridge as the industry leader
for system integrity, environmental and safety programs.
Through the ORM Plan, the Company has expanded its
maintenance, excavation and repair programs which are
supported by operating and capital budgets directed to
pipeline integrity. Emergency response plans, operator
training and landowner education programs are included in
the Company’s response preparedness. In addition, the role
of Senior Vice President, Enterprise Safety & Operational
Reliability was established in 2013. The new centralized role
is accountable for defining and executing on an enterprise-
wide vision, culture and set of integrated strategies and
policies that support Enbridge’s objective of being the
industry leader in process, public and personal safety,
operational reliability and environmental protection.
The Company maintains comprehensive insurance coverage
for its subsidiaries and affiliates which it renews annually.
The insurance program includes coverage for commercial
liability that is considered customary for its industry and
includes coverage for environmental incidents. The total
insurance coverage will be allocated on an equitable basis in
the unlikely event multiple insurable incidents exceeding the
Company’s coverage limits are experienced by Enbridge and
two Enbridge subsidiaries covered by the same policy within
the same insurance period.
Public, Worker and Contractor Safety
Several of the Company’s pipeline systems run adjacent to
populated areas and a major incident could result in injury
to members of the public. A public safety incident could
result in reputational damage to the Company, material
repair costs or increased costs of operating and insuring
the Company’s assets. In addition, given the natural
hazards inherent in Enbridge’s operations, its workers and
contractors are subject to personal safety risks.
Safety and operational reliability are the most important
priorities at Enbridge. Enbridge’s mitigation efforts to reduce
the likelihood and severity of a public safety incident are
executed primarily through its ORM Plan and emergency
response preparedness, as described above. Enbridge
believes in a safety culture where safety incidents are not
tolerated by employees and contractors and has established
a target of zero incidents.
Service Interruption Incident
A service interruption due to a major power disruption or
curtailment on commodity supply could have a significant
impact on the Company’s ability to operate its assets
and negatively impact future earnings, relationships with
stakeholders and the Company’s reputation. Specifically,
for Gas Distribution, any prolonged interruptions would
ultimately impact gas distribution customers. Service
interruptions that impact the Company’s crude oil
transportation services can negatively impact shippers’
operations and earnings as they are dependent on Enbridge
services to move their product to market or fulfill their own
contractual arrangements. The Company mitigates service
interruption risk through its diversified sources of supply,
storage withdrawal flexibility, backup power systems, critical
parts inventory and redundancies for critical equipment.
Information Systems Incident
The Company’s infrastructure, applications and data are
becoming more integrated, creating an increased risk that
failure in one system could lead to a failure of another
system. There is also increasing industry-wide cyber-
attacking activity targeting industrial control systems.
A successful cyber-attack could lead to unavailability,
disruption or loss of key functionalities within the
112 Enbridge Inc. 2013 Annual Report
Company’s industrial control systems. As part of the
Company’s ORM Plan, the Company has continued to
broaden the scope of its systems security with increased
mitigation activities focused on the prevention, detection
and necessary response to any potential systems security
incident. Additionally, to increase accountability in relation
to systems security, all information technology security
operations in the Company are consolidated under one
leadership structure to increase consistency and compliance
with the Company’s security requirements.
The Company works proactively with special interest groups
and non-governmental organizations to identify and develop
appropriate responses to their concerns regarding its
projects. The Company is investing significant resources in
these areas. Its CSR program also reports on the Company’s
responsiveness to environmental and community issues.
Please see Enbridge’s annual CSR Report, available online
at csr.enbridge.com for further details regarding the CSR
program. None of the information contained on, or
connected to, Enbridge’s website is incorporated in
or otherwise part of this MD&A.
Business Environment Risks
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 the conditions in the
approval make a project economically challenging.
Given this environment and the breadth of relationships
across the Company’s geographic span, Enbridge has
implemented an Aboriginal and Native American Policy.
This 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
and Native American relations on Enbridge’s operations and
development initiatives is uncertain.
Critical Accounting Estimates
Depreciation
Depreciation of property, plant and equipment, the Company’s
largest asset with a net book value at December 31, 2013
of $42,279 million (2012 - $33,318 million), or 73.4% 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.
Special Interest Groups including Non-Governmental
Organizations
Asset Impairment
The Company is exposed to the risk of higher costs, delays
or even project cancellations due to increasing pressure
on governments and regulators by special interest groups,
including non-governmental organizations. Recent judicial
decisions have increased the ability of special interest
groups to make claims and oppose projects in regulatory and
legal forums. In addition to issues raised by groups focused
on particular project impacts, the Company and others in
the energy and pipeline businesses are facing opposition
from organizations opposed to oil sands development and
shipment of production from oil sands regions.
The Company evaluates the recoverability of its property,
plant and equipment when events or circumstances such
as economic obsolescence, business climate, legal or
regulatory changes or other factors indicate it may not
recover the carrying amount of the assets. The Company
continually monitors its businesses, the market and business
environments to identify indicators that could suggest
an asset may not be recoverable. An impairment loss is
recognized when the carrying amount of the asset exceeds
its fair value as determined by quoted market prices in active
markets or present value techniques. The determination of
the fair value using present value techniques requires the
Management’s Discussion and Analysis
113
use of projections and assumptions regarding future cash flows and weighted average cost of capital.
Any changes to these projections and assumptions could result in revisions to the evaluation of the
recoverability of the property, plant and equipment and the recognition of an impairment loss in the
Consolidated Statements of Earnings.
Regulatory Assets and Liabilities
Certain of the Company’s businesses are subject to regulation by various authorities, including but not
limited to, the NEB, the FERC, the Alberta Energy Regulator 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 U.S. 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. As at December 31, 2013, the Company’s significant
regulatory assets totalled $1,138 million (2012 - $1,109 million) and significant regulatory liabilities totalled
$1,016 million (2012 - $941 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.
Postretirement Benefits
The Company maintains pension plans, which provide defined benefit and/or defined contribution
pension benefits and OPEB to eligible retirees. Pension costs and obligations for the defined benefit
pension plans are determined using the universal method. This method involves complex actuarial
calculations using several assumptions including discount rates, which were determined by referring to
high-quality long-term corporate bonds with maturities that approximate the timing of future payments
the Company anticipates making under each of the respective plans, 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 actual return on plan assets exceeded the expected return on plan assets by $101 million
for the year ended December 31, 2013 (2012 - $24 million) as disclosed in Note 25, Retirement and
Postretirement Benefits, to the 2013 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.
The following sensitivity analysis identifies the impact on the December 31, 2013 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
149
–
(30)
22
8
(10)
18
–
–
2
–
–
114 Enbridge Inc. 2013 Annual Report
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 are detailed in
Note 29, Commitments and Contingencies, of the 2013
Annual Consolidated Financial Statements. In addition,
any unasserted claims that later may become evident could
have a material impact on the financial results of the
Company and certain of the Company’s subsidiaries
and investments.
Asset Retirement Obligations
In May 2009, the NEB released a report on the financial
issues associated with pipeline abandonment and
established a goal for pipelines regulated under the NEB Act
to begin collecting and setting aside funds to cover future
abandonment costs no later than January 1, 2015. Since then,
the NEB has issued revised “base case assumptions” based
on feedback from member companies. Companies have
the option to follow the base case assumptions or to submit
pipeline specific applications.
On November 29, 2011, as required by the NEB, the Company
filed its estimated abandonment costs for its regulated
pipeline systems within EPI and Enbridge Pipelines (NW)
Inc. (Group 1 companies) and Enbridge Southern Lights GP
Inc., Enbridge Bakken Pipeline Company Inc. and Enbridge
Pipelines (Westspur) Inc. (Group 2 companies). In the fourth
quarter of 2012, the NEB held a hearing on the abandonment
costs estimates for Group 1 companies and issued its decision
on February 14, 2013. The outcome does not materially
impact tolls. On February 28, 2013, Group 1 companies
filed a proposed process and mechanism to set aside the
funds for future abandonment costs and chose the trust
as the appropriate set-aside mechanism to hold pipeline
abandonment funds. On May 31, 2013, the Group 1 companies
filed collection mechanism applications and the Group 2
companies filed both their set-aside and collection mechanism
applications. Once the set-aside and collection mechanism is
approved by the NEB, both Group 1 and Group 2 companies
can start to recover these costs from shippers through tolls in
accordance with the NEB’s determination that abandonment
costs are a legitimate cost of providing service and are
recoverable upon NEB approval from users of the system.
The collections are expected to begin in 2015.
All applications by the Company will require NEB approval.
The NEB has set a hearing, covering both the set-aside
mechanism applications and the collection mechanism
applications for both Group 1 and Group 2 companies.
The hearing commenced January 14, 2014 with the decision
expected in the second quarter of 2014.
Currently, for the majority of the Company’s assets, there is
insufficient data or information to reasonably determine the
timing of settlement for estimating the fair value of the asset
retirement obligation (ARO). In these cases, the ARO cost is
considered indeterminate for accounting purposes, as there is
no data or information that can be derived from past practice,
industry practice or the estimated economic life of the asset.
Changes in Accounting Policies
United States Generally Accepted
Accounting Principles
The Company commenced reporting using U.S. GAAP as
its primary basis of accounting effective January 1, 2012,
including restatement of comparative periods. As a
Securities and Exchange Commission (SEC) registrant, the
Company is permitted to use U.S. GAAP for purposes of
meeting both its Canadian and United States continuous
disclosure requirements.
Adoption of New Standards
Balance Sheet Offsetting
Effective January 1, 2013, the Company adopted Accounting
Standards Update (ASU) 2011-11 and ASU 2013-01, which
require enhanced disclosures on the effect or potential effect
of netting arrangements on an entity’s financial position.
As the adoption of these updates impacted disclosure only,
there was no impact to the Company’s consolidated financial
position for the current or prior periods presented.
Accumulated Other Comprehensive Income
Effective January 1, 2013, the Company adopted
ASU 2013-02, which requires enhanced disclosures on
amounts reclassified out of AOCI. As the adoption of this
update impacted disclosure only, there was no impact to
the Company’s consolidated financial statements for the
current or prior periods presented.
Presentation of Unrecognized Tax Benefits
Effective December 31, 2013, the Company elected to
early adopt ASU 2013-11, which requires presentation of
unrecognized tax benefits as a reduction to a deferred tax
asset for a net operating loss carryforward unless specific
conditions exist. There was no material impact to the
consolidated financial statements for the current or prior
periods presented as a result of adopting this update.
Management’s Discussion and Analysis
115
Future Accounting Policy Changes
Obligations Resulting from Joint and Several
Liability Arrangements
ASU 2013-04 was issued in February 2013 and provides
both measurement and disclosure guidance for obligations
with fixed amounts at a reporting date resulting from joint
and several liability arrangements. The adoption of the
pronouncement is not anticipated to have a material impact
on the Company’s consolidated financial statements.
This accounting update is effective for annual and interim
periods beginning after December 15, 2013 and is to be
applied retrospectively.
Parent’s Accounting for the Cumulative
Translation Adjustment
ASU 2013-05 was issued in March 2013 and provides
guidance on the timing of release of the cumulative
translation adjustment into net income when a disposition
or ownership change occurs related to an investment in
a foreign entity or a business within a foreign entity.
The adoption of the pronouncement is not anticipated
to have a material impact on the Company’s consolidated
financial statements. This accounting update is effective for
annual and interim periods beginning after December 15,
2013 and is to be applied prospectively.
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 at
December 31, 2013, 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 SEC and the Canadian Securities Administrators is
recorded, processed, summarized and reported within the
time periods required.
Management’s Report on Internal Control 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 SEC 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 U.S. 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 U.S. GAAP; 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 at
December 31, 2013, based on the framework established in
Internal Control – Integrated Framework (1992) issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. Based on this assessment, Management
concluded that the Company maintained effective internal
control over financial reporting as at December 31, 2013.
During the year ended December 31, 2013, there has been
no material change in the Company’s internal control over
financial reporting.
The effectiveness of the Company’s internal control over
financial reporting as at December 31, 2013 has been audited
by PricewaterhouseCoopers LLP, independent auditors
appointed by the shareholders of the Company.
116 Enbridge Inc. 2013 Annual Report
Non-GAAP Reconciliations
(millions of Canadian dollars)
Earnings attributable to common shareholders
Adjusting items:
Liquids Pipelines
Canadian Mainline – changes in unrealized derivative fair value (gains)/loss1
Canadian Mainline – Line 9 tolling adjustment
Canadian Mainline – shipper dispute settlement
Regional Oil Sands System – leak remediation and long-term pipeline stabilization costs
Regional Oil Sands System – make-up-rights adjustment
Regional Oil Sands System – make-up-rights out-of-period adjustment
Regional Oil Sands System – long-term contractual recovery out-of-period adjustment, net
Regional Oil Sands System – prior period adjustment
Regional Oil Sands System – asset impairment write-off
Spearhead Pipeline – changes in unrealized derivative fair value gains1
Gas Distribution
EGD – gas transportation costs out-of-period adjustment
EGD – warmer/(colder) than normal weather
EGD – tax rate changes
EGD – recognition of regulatory asset
Other Gas Distribution and Storage - regulatory deferral write-off
Gas Pipelines, Processing and Energy Services
Aux Sable – changes in unrealized derivative fair value (gains)/loss1
Energy Services – changes in unrealized derivative fair value (gains)/loss1
Offshore – asset impairment loss
Other – changes in unrealized derivative fair value (gains)/loss1
Sponsored Investments
EEP – leak insurance recoveries
EEP – leak remediation costs
EEP – changes in unrealized derivative fair value (gains)/loss1
EEP – tax rate differences/changes
EEP – gain on sale of non-core assets
EEP – NGL trucking and marketing investigation costs
EEP – prior period adjustment
EEP – shipper dispute settlement
EEP – lawsuit settlement
EEP – impact of unusual weather conditions
Corporate
Noverco – changes in unrealized derivative fair value (gains)/loss1
Noverco – equity earnings adjustment
Other Corporate – changes in unrealized derivative fair value loss1
Other Corporate – impact of tax rate changes
Other Corporate – foreign tax recovery
Other Corporate – asset impairment loss
Other Corporate – unrealized foreign exchange (gains)/loss on translation
of intercompany balances, net
Other Corporate – tax on intercompany gain on sale
2013
2012
2011
446
602
801
268
–
–
56
13
37
(31)
–
–
–
56
(9)
–
–
–
–
206
–
61
(6)
44
6
3
(2)
–
–
–
–
–
(4)
–
306
(18)
(4)
6
–
–
(42)
(6)
–
–
–
–
–
6
–
–
–
23
9
(63)
–
(10)
537
105
–
(24)
9
2
–
–
1
(7)
–
–
–
10
12
22
11
(29)
–
17
56
48
(10)
(14)
–
–
–
–
–
8
(1)
–
(1)
–
–
262
7
(125)
–
(24)
(50)
33
(3)
–
–
3
–
(8)
(1)
1
–
–
87
(6)
–
–
(24)
98
Adjusted earnings
1,434
1,241
1,081
1
Changes in unrealized derivative fair value gains or loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period.
Management’s Discussion and Analysis
117
Management’s Report
To the Shareholders of Enbridge Inc.
Financial Reporting
Management of Enbridge Inc. (the Company) is responsible for the accompanying consolidated
financial statements. The consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in the United States of America (U.S. GAAP) and necessarily
include amounts that reflect management’s judgment and best estimates.
The Board of Directors (the Board) and its committees are responsible for all aspects related to
governance of the Company. The Audit, Finance & Risk Committee (AF&RC) of the Board, composed
of directors who are unrelated and independent, has a specific responsibility to oversee management’s
efforts to fulfill its responsibilities for financial reporting and internal controls related thereto.
The AF&RC 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
AF&RC 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 U.S. GAAP
and provide reasonable assurance that assets are safeguarded.
Management assessed the effectiveness of the Company’s internal control over financial reporting as
at December 31, 2013, based on the framework established in Internal Control – Integrated Framework
(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
this assessment, management concluded that the Company maintained effective internal control over
financial reporting as at December 31, 2013.
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 and the standards of the Public Company Accounting Oversight
Board (United States).
Al Monaco
President & Chief Executive Officer
February 14, 2014
J. Richard Bird
Executive Vice President &
Chief Financial Officer
118 Enbridge Inc. 2013 Annual Report
Independent Auditor’s Report
To the Shareholders of Enbridge Inc.
We have completed integrated audits of Enbridge Inc.’s 2013 and 2012 consolidated financial statements and its
internal control over financial reporting as at December 31, 2013 and an audit of its 2011 consolidated financial statements.
Our opinions, based on our audits, are presented below.
Report on the consolidated financial statements
We have audited the accompanying consolidated financial statements of Enbridge Inc., which comprise the consolidated
statements of financial position as at December 31, 2013 and December 31, 2012 and the consolidated statements of
earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended
December 31, 2013, and the related notes, which comprise a summary of significant accounting policies and other
explanatory information.
Management’s responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in
accordance with accounting principles generally accepted in the United States of America and for such internal control
as management determines is necessary to enable the preparation of consolidated financial statements that are free from
material misstatement, whether due to fraud or error.
Auditor’s responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our
audits 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 the audit to obtain reasonable assurance
about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing
standards also require that we comply with ethical requirements.
An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks
of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments,
the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial
statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the
appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit
opinion on the consolidated financial statements.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Enbridge
Inc. as at December 31, 2013 and December 31, 2012 and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2013 in accordance with accounting principles generally accepted in the United States
of America.
Report on internal control over financial reporting
We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2013, based on criteria
established in Internal Control - Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO).
Independent Auditor’s Report
119
Management’s responsibility for internal control over financial reporting
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.
Auditor’s responsibility
Our responsibility is to express an opinion on 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 audit opinion on the company’s internal control over
financial reporting.
Definition of internal control over financial reporting
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.
Inherent limitations
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.
Opinion
In our opinion, Enbridge Inc. maintained, in all material respects, effective internal control over financial reporting as at
December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by COSO.
Chartered Accountants
Calgary, Alberta, Canada
February 14, 2014
120 Enbridge Inc. 2013 Annual Report
Independent Auditor’s Report
120
Consolidated Statements of Earnings
Year ended December 31,
(millions of Canadian dollars, except per share amounts)
Revenues
Commodity sales
Gas distribution sales
Transportation and other services
Expenses
Commodity costs
Gas distribution costs
Operating and administrative
Depreciation and amortization
Environmental costs, net of recoveries (Note 29)
Income from equity investments (Note 12)
Other income/(expense) (Note 26)
Interest expense (Note 17)
Income taxes (Note 24)
Earnings from continuing operations
Discontinued operations (Note 10)
Earnings/(loss) from discontinued operations before income taxes
Income taxes (expense)/recovery from discontinued operations
Earnings/(loss) from discontinued operations
Earnings before extraordinary loss
Extraordinary loss, net of tax (Note 6)
Earnings
(Earnings)/loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Earnings attributable to Enbridge Inc.
Preference share dividends
Earnings attributable to Enbridge Inc. common shareholders
Earnings attributable to Enbridge Inc. common shareholders
Earnings from continuing operations
Earnings/(loss) from discontinued operations, net of tax
Extraordinary loss, net of tax (Note 6)
Earnings per common share attributable to Enbridge Inc. common shareholders (Note 20)
Continuing operations
Discontinued operations
Extraordinary item
Diluted earnings per common share attributable to Enbridge Inc. common
shareholders (Note 20)
Continuing operations
Discontinued operations
Extraordinary item
The accompanying notes are an integral part of these consolidated financial statements.
2013
2012
2011
26,039
2,265
4,614
32,918
25,222
1,585
3,014
1,370
362
31,553
1,365
330
(135)
(947)
613
(123)
490
6
(2)
4
494
–
494
135
629
(183)
446
442
4
–
446
0.55
–
–
0.55
0.55
–
–
0.55
18,494
1,910
4,256
24,660
17,959
1,220
2,739
1,236
(88)
23,066
1,594
195
238
(841)
1,186
(171)
1,015
(123)
44
(79)
936
–
936
(229)
707
(105)
602
681
(79)
–
602
0.88
(0.10)
–
0.78
0.87
(0.10)
–
0.77
20,374
1,906
4,509
26,789
19,627
1,281
2,259
1,147
(116)
24,198
2,591
233
116
(928)
2,012
(523)
1,489
(9)
3
(6)
1,483
(262)
1,221
(407)
814
(13)
801
1,069
(6)
(262)
801
1.43
(0.01)
(0.35)
1.07
1.40
(0.01)
(0.34)
1.05
Consolidated Financial Statements
121
Consolidated Statements of
Comprehensive Income
Year ended December 31,
(millions of Canadian dollars)
Earnings
Other comprehensive income/(loss), net of tax
Change in unrealized gains/(loss) on cash flow hedges
Change in unrealized gains/(loss) on net investment hedges
Other comprehensive income/(loss) from equity investees
Reclassification to earnings of realized cash flow hedges
Reclassification to earnings of unrealized cash flow hedges
Reclassification to earnings of pension plans and other postretirement benefits
amortization amounts
Actuarial gains/(loss) on pension plans and other postretirement benefits
Change in foreign currency translation adjustment
Other comprehensive income/(loss)
Comprehensive income
Comprehensive income attributable to noncontrolling interests and
redeemable noncontrolling interests
Comprehensive income attributable to Enbridge Inc.
Preference share dividends
Comprehensive income attributable to Enbridge Inc. common shareholders
The accompanying notes are an integral part of these consolidated financial statements.
2013
2012
2011
494
697
(96)
11
72
39
27
114
710
1,574
2,068
(276)
1,792
(183)
1,609
936
1,221
(176)
13
2
7
20
18
(56)
(158)
(330)
606
(165)
441
(105)
336
(582)
(19)
(17)
14
12
21
(165)
144
(592)
629
(327)
302
(13)
289
122 Enbridge Inc. 2013 Annual Report
Consolidated Statements of Changes in Equity
Year ended December 31,
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 20)
Balance at beginning of year
Preference shares issued
Balance at end of year
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
Additional paid-in capital
Balance at beginning of year
Stock-based compensation
Options exercised
Issuance of treasury stock (Note 12)
Dilution gains and other
Balance at end of year
Retained earnings
Balance at beginning of year
Earnings attributable to Enbridge Inc.
Preference share dividends
Common share dividends declared
Dividends paid to reciprocal shareholder
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 19)
Balance at end of year
Accumulated other comprehensive loss (Note 22)
Balance at beginning of year
Other comprehensive income/(loss) attributable to Enbridge Inc. common shareholders
Balance at end of year
Reciprocal sharesholding (Note 12)
Balance at beginning of year
Issuance of treasury stock
Acquisition of equity investment
Balance at end of year
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 19)
Balance at beginning of year
Earnings/(loss) attributable to noncontrolling interests
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gains/(loss) on cash flow hedges
Change in foreign currency translation adjustment
Reclassification to earnings of realized cash flow hedges
Reclassification to earnings of unrealized cash flow hedges
Comprehensive income attributable to noncontrolling interests
Distributions
Contributions
Dilution gains
Acquisitions (Note 7)
Other
Balance at end of year
Total equity
Dividends paid per common share
The accompanying notes are an integral part of these consolidated financial statements.
2013
2012
2011
3,707
1,434
5,141
4,732
582
361
69
5,744
522
28
(17)
208
5
746
3,173
629
(183)
(1,035)
19
(53)
2,550
(1,762)
1,163
(599)
(126)
40
–
(86)
13,496
3,258
(111)
166
223
4
14
407
296
(468)
922
–
–
6
4,014
17,510
1.26
1,056
2,651
3,707
3,969
388
297
78
4,732
242
26
(17)
236
35
522
3,643
707
(105)
(895)
20
(197)
3,173
(1,496)
(266)
(1,762)
(187)
61
–
(126)
10,246
3,141
241
(39)
(60)
23
13
(63)
178
(421)
382
6
(25)
(3)
3,258
13,504
1.13
125
931
1,056
3,683
–
229
57
3,969
131
18
(7)
–
100
242
3,729
814
(13)
(759)
25
(153)
3,643
(984)
(512)
(1,496)
(154)
–
(33)
(187)
7,227
2,424
416
(84)
66
(63)
4
(77)
339
(355)
735
22
(27)
3
3,141
10,368
0.98
Consolidated Financial Statements
123
Consolidated Statements of Cash Flows
2013
2012
2011
Year ended December 31,
(millions of Canadian dollars)
Operating activities
Earnings
(Earnings)/loss from discontinued operations
Depreciation and amortization
Deferred income taxes (Note 24)
Changes in unrealized (gains)/loss on derivative instruments, net
Cash distributions in excess of equity earnings
Regulatory asset write-off (Note 6)
Impairment
Other
Changes in regulatory assets and liabilities
Changes in environmental liabilities, net of recoveries (Note 29)
Changes in operating assets and liabilities (Note 27)
Cash provided by continuing operations
Cash provided by/(used in) discontinued operations (Note 10)
Investing activities
Additions to property, plant and equipment
Long-term investments
Additions to intangible assets
Acquisitions, net of cash acquired (Note 7)
Affiliate loans, net
Proceeds on sale of investments and net assets
Government grant
Changes in restricted cash
Financing activities
Net change in bank indebtedness and short-term borrowings
Net change in commercial paper and credit facility draws
Net change in Southern Lights project financing
Debenture and term note issues
Debenture and term note repayments
Repayment of acquired debt
Contributions from noncontrolling interests
Distributions to noncontrolling interests
Contributions from redeemable noncontrolling interests
Distributions to redeemable noncontrolling interests
Preference shares issued
Common shares issued
Preference 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
Cash and cash equivalents – discontinued operations
Cash and cash equivalents – continuing operations
Supplementary cash flow information
Income taxes (received)/paid
Interest paid
The accompanying notes are an integral part of these consolidated financial statements.
124 Enbridge Inc. 2013 Annual Report
494
(4)
1,370
131
1,262
355
–
6
(9)
(11)
148
(409)
3,333
8
3,341
(8,235)
(1,018)
(212)
–
8
41
–
(15)
(9,431)
(350)
1,562
(5)
2,845
(660)
–
922
(468)
92
(72)
936
79
1,236
3
665
439
–
39
109
44
(26)
(660)
2,864
10
2,874
(5,194)
(531)
(163)
(340)
8
18
–
(2)
1,221
6
1,147
365
(73)
102
262
11
11
38
(118)
401
3,373
(2)
3,371
(3,527)
(1,515)
(154)
(33)
7
–
145
(2)
(6,204)
(5,079)
412
(294)
(13)
2,199
(349)
(160)
448
(421)
213
(49)
1,428
2,634
628
(178)
(674)
5,070
20
(1,000)
1,776
776
(20)
756
107
1,097
465
(93)
(597)
4,395
(12)
1,053
723
1,776
–
1,776
267
988
224
(630)
(62)
1,604
(234)
–
873
(355)
210
(35)
926
46
(7)
(530)
2,030
25
347
376
723
–
723
(28)
955
Consolidated Statements of Financial Position
December 31,
(millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents
Restricted cash
Accounts receivable and other (Note 8)
Accounts receivable from affiliates
Inventory (Note 9)
Assets held for sale (Note 10)
Property, plant and equipment, net (Note 10)
Long-term investments (Note 12)
Deferred amounts and other assets (Note 13)
Intangible assets, net (Note 14)
Goodwill (Note 15)
Deferred income taxes (Note 24)
Liabilities and equity
Current liabilities
Bank indebtedness
Short-term borrowings (Note 17)
Accounts payable and other (Note 16)
Accounts payable to affiliates
Interest payable
Environmental liabilities (Note 29)
Current maturities of long-term debt (Note 17)
Liabilities held for sale (Note 10)
Long-term debt (Note 17)
Other long-term liabilities (Note 18)
Deferred income taxes (Note 24)
Liabilities held for sale (Note 10)
Commitments and contingencies (Note 29)
Redeemable noncontrolling interests (Note 19)
Equity
Share capital (Note 20)
Preference shares
Common shares (831 and 805 outstanding at December 31, 2013 and 2012, respectively)
Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss (Note 22)
Reciprocal shareholding (Note 12)
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 19)
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
2013
2012
756
34
4,956
65
1,115
24
6,950
42,279
4,212
2,662
1,004
445
16
1,776
19
4,014
12
779
–
6,600
33,318
3,175
2,461
817
419
10
57,568
46,800
338
374
6,664
46
228
260
2,811
7
10,728
22,357
2,938
2,925
57
479
583
5,052
–
196
107
652
–
7,069
20,203
2,541
2,483
–
39,005
32,296
1,053
1,000
5,141
5,744
746
2,550
(599)
(86)
13,496
4,014
17,510
57,568
3,707
4,732
522
3,173
(1,762)
(126)
10,246
3,258
13,504
46,800
Consolidated Financial Statements
125
Notes to the Consolidated Financial Statements
1. General Business Description
Enbridge Inc. (Enbridge or the Company) is a publicly
traded energy transportation and distribution company.
Enbridge conducts its business through five business
segments: Liquids Pipelines; Gas Distribution; Gas Pipelines,
Processing and Energy 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 consists of common carrier and contract
crude oil, natural gas liquids (NGL) and refined products
pipelines and terminals in Canada and the United States,
including Canadian Mainline, Regional Oil Sands System,
Southern Lights Pipeline, Seaway Pipeline, Spearhead
Pipeline, Feeder Pipelines and Other.
Gas Distribution
Gas Distribution consists of the Company’s natural gas utility
operations, the core of which is Enbridge Gas Distribution
Inc. (EGD) which serves residential, commercial and
industrial 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.
Gas Pipelines, Processing and Energy Services
Gas Pipelines, Processing and Energy Services consists of
investments in natural gas pipelines, gathering and processing
facilities and the Company’s energy services businesses,
along with renewable energy and transmission facilities.
Investments in natural gas pipelines include the Company’s
interests in the United States portion of the Alliance System
(Alliance Pipeline US), the Vector Pipeline (Vector) and
transmission and gathering pipelines in the Gulf of Mexico.
Investments in natural gas processing include the Company’s
interest in Aux Sable, a natural gas fractionation and
extraction business located near the terminus of the Alliance
System. The energy services businesses undertake physical
commodity marketing activities and logistical services,
refinery supply services and manage the Company’s volume
commitments on the Alliance System, Vector and other
pipeline systems.
Sponsored Investments
Sponsored Investments includes the Company’s 20.6%
(2012 - 21.8%) ownership interest in Enbridge Energy
Partners, L.P. (EEP), Enbridge’s 66.7% (2012 - 66.7%)
investment in the United States segment of the Alberta
Clipper Project through EEP and Enbridge Energy, Limited
Partnership and an overall 67.3% (2012 - 67.7%) economic
interest in Enbridge Income Fund (the Fund), held both
directly and indirectly through Enbridge Income Fund
Holdings Inc. (ENF). Enbridge, through its subsidiaries,
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, including the
Lakehead Pipeline System (Lakehead System) which is the
United States portion of the Enbridge mainline system, and
transports, gathers, processes and markets natural gas and
NGL. The primary operations of the Fund include renewable
power generation, crude oil and liquids pipeline and
storage businesses in western Canada and a 50% interest
in the Canadian portion of the Alliance System (Alliance
Pipeline Canada).
Corporate
Corporate consists of the Company’s investment in Noverco Inc.
(Noverco), new business development activities, general
corporate investments and financing costs not allocated to
the business segments.
2. Summary of Significant
Accounting Policies
These consolidated financial statements are prepared in
accordance with accounting principles generally accepted
in the United States of America (U.S. GAAP). Amounts are
stated in Canadian dollars unless otherwise noted.
The Company commenced reporting using U.S. GAAP as
its primary basis of accounting effective January 1, 2012,
including restatement of comparative periods. As a
Securities and Exchange Commission (SEC) registrant,
the Company is permitted to use U.S. GAAP for purposes
of meeting both its Canadian and United States continuous
disclosure requirements.
126 Enbridge Inc. 2013 Annual Report
Basis of Presentation and Use of Estimates
The preparation of financial statements in conformity with
U.S. 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
the preparation of the consolidated financial statements
include, but are not limited to: carrying values of regulatory
assets and liabilities (Note 6); unbilled revenues (Note 8);
allowance for doubtful accounts (Note 8); depreciation rates
and carrying value of property, plant and equipment (Note 10);
amortization rates of intangible assets (Note 14); measurement
of goodwill (Note 15); valuation of stock-based compensation
(Note 21); fair value of financial instruments (Note 23); provisions
for income taxes (Note 24); assumptions used to measure
retirement and other postretirement benefit obligations
(OPEB) (Note 25); commitments and contingencies (Note 29);
fair value of asset retirement obligations (ARO); and estimates
of losses related to environmental remediation obligations
(Note 29). Actual results could differ from these estimates.
Principles of Consolidation
The consolidated financial statements include the accounts
of Enbridge, its subsidiaries and a variable interest entity
(VIE) for which the Company is the primary beneficiary.
The consolidated financial statements also include the
accounts of any limited partnerships where the Company
represents the general partner and, based on all facts and
circumstances, controls such limited partnerships. For certain
investments where the Company retains an undivided interest
in assets and liabilities, Enbridge records its proportionate
share of assets, liabilities, revenues and expenses.
All significant intercompany accounts and transactions
are eliminated upon consolidation. Ownership interests
in subsidiaries represented by other parties that do not
control the entity are presented in the consolidated
financial statements as activities and balances attributable
to noncontrolling interests and redeemable noncontrolling
interests. Investments and entities over which the Company
exercises significant influence are accounted for using the
equity method.
Regulation
Certain of the Company’s 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 Alberta Energy Regulator, 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
U.S. 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. 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. The recognition of regulatory assets
and liabilities is based on the actions, or expected future
actions, of the regulator. 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. 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. A regulatory asset or
liability is recognized in respect of deferred income taxes
when it is expected the amounts will be recovered or settled
through future regulator-approved rates.
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 which are both capitalized based on
rates set out in a regulatory agreement. In the absence
of rate regulation, the Company would capitalize interest
using a capitalization rate based on its cost of borrowing
and the capitalized equity component, the corresponding
earnings during the construction phase and the subsequent
depreciation would not be recognized.
For certain regulated operations to which U.S. GAAP
guidance for phase-in plans applies, negotiated depreciation
rates recovered in transportation tolls may be less than the
depreciation expense calculated in accordance with U.S.
GAAP in early years of long-term contracts but recovered in
future periods when tolls exceed depreciation. Depreciation
expense on such assets is recorded in accordance with U.S.
GAAP and no deferred regulatory asset is recorded (Note 4).
With the approval of the regulator, EGD and certain
distribution operations capitalize a percentage of certain
operating costs. These operations are authorized to charge
depreciation and earn a return on the net book value of
such capitalized costs in future years. To the extent that the
regulator’s actions differ from the Company’s expectations,
Notes to the Consolidated Financial Statements
127
the timing and amount of recovery or settlement of
capitalized costs could differ significantly from those
recorded. In the absence of rate regulation, a portion of
such costs may be charged to current period earnings.
Revenue Recognition
For businesses which are not rate-regulated, revenues are
recorded when products have been delivered or services
have been performed, the amount of revenue can be
reliably measured and collectability is reasonably assured.
Customer credit worthiness is assessed prior to agreement
signing as well as throughout the contract duration. Certain
Liquids Pipelines revenues are recognized under the terms
of committed delivery contracts rather than the cash
tolls received.
Long-term take-or-pay contracts, under which shippers are
obligated to pay fixed amounts ratably over the contract
period regardless of volumes shipped, may contain make-up
rights. Make-up rights are earned by shippers when minimum
volume commitments are not utilized during the period but
under certain circumstances can be used to offset overages
in future periods, subject to expiry periods. The Company
recognizes revenues associated with make-up rights at the
earlier of when the make-up volume is shipped, the make-up
right expires or when it is determined that the likelihood that
the shipper will utilize the make-up right is remote.
For rate-regulated businesses, revenues are recognized in
a manner that is consistent with the underlying agreements
as approved by the regulators. From July 1, 2011 onward,
Canadian Mainline (excluding Lines 8 and 9) earnings are
governed by the Competitive Toll Settlement (CTS), under
which revenues are recorded when services are performed.
Effective on that date, the Company prospectively
discontinued the application of rate-regulated accounting
for those assets with the exception of flow-through income
taxes covered by a specific rate order.
For natural gas utility rate-regulated operations in Gas
Distribution, revenues are 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. Estimates are based on historical consumption
patterns and heating degree days experienced. Heating
degree days is a measure of coldness that is indicative of
volumetric requirements for natural gas utilized for heating
purposes in the Company’s distribution franchise area.
For natural gas and marketing businesses, an estimate of
revenues and commodity costs for the month of December
is included in the Consolidated Statements of Earnings for
each year based on the best available volume and price data
for the commodity delivered and received.
Derivative Instruments and Hedging
Non-qualifying Derivatives
Non-qualifying derivative instruments are used primarily
to economically hedge foreign exchange, interest rate
and commodity price earnings exposure. Non-qualifying
derivatives are measured at fair value with changes in
fair value recognized in earnings in Transportation and
other services revenues, Commodity costs, Operating
and administrative expense, Other income/(expense) and
Interest expense.
Derivatives in Qualifying Hedging Relationships
The Company uses derivative financial instruments to
manage its exposure to 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 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 its exposure
to 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 Other
comprehensive income/(loss) (OCI) and is reclassified to
earnings when the hedged item impacts earnings. 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 derivative
instruments for which hedge accounting has been
discontinued 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,
128 Enbridge Inc. 2013 Annual Report
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. The Company did not have any fair value hedges at
December 31, 2013 or 2012.
Net Investment Hedges
The Company uses net investment hedges to manage its
exposure to changes in 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.
Classification of Derivatives
The Company recognizes the fair market value of derivative
instruments on the Consolidated Statements of Financial
Position as current and long-term assets or liabilities
depending on the timing of the settlements and the resulting
cash flows associated with the instruments. Fair value
amounts related to cash flows occurring beyond one year
are classified as non-current.
Cash inflows and outflows related to derivative instruments
are classified as Operating activities on the Consolidated
Statements of Cash Flows.
Balance Sheet Offset
Assets and liabilities arising from derivative instruments
may be offset in the Consolidated Statements of Financial
Position when the Company has the legal right and intention
to settle them on a net basis.
received from the investees. To the extent an equity investee
undertakes activities necessary to commence its planned
principal operations, the Company capitalizes interest costs
associated with its investment during such period.
Other Investments
Generally, the Company classifies equity investments in
entities over which it does not exercise significant influence
and that do not trade on an actively quoted market as other
investments carried at cost. Financial assets in this category
are initially recorded at fair value with no subsequent
re-measurement. Any investments which do trade on an
active market are classified as available for sale investments
measured at fair value through OCI. Dividends received from
investments carried at cost are recognized in earnings when
the right to receive payment is established.
Noncontrolling Interests
Noncontrolling interests represent ownership interests
attributable to third parties in certain consolidated
subsidiaries, limited partnerships and VIEs. The portion of
equity in entities not owned by the Company is reflected
as noncontrolling interests within the equity section of
the Consolidated Statements of Financial Position and, in
the case of redeemable noncontrolling interests, within
the mezzanine section of the Consolidated Statements of
Financial Position between long-term liabilities and equity.
The Fund’s noncontrolling interest holders have the option
to redeem the Fund trust units for cash, subject to certain
limitations. Redeemable noncontrolling interests are
recognized at the maximum redemption value of the trust
units held by third parties, which references the market
price of ENF common shares. On a quarterly basis, changes
in estimated redemption values are reflected as a charge or
credit to retained earnings.
Transaction Costs
Income Taxes
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 as Deferred amounts and other assets. These costs are
amortized using the effective interest rate method over the
life of the related debt instrument.
Equity Investments
Equity investments over which the Company exercises
significant influence, but does not have controlling financial
interests, are accounted for using the equity method. Equity
investments are initially measured at cost and are adjusted
for the Company’s proportionate share of undistributed
equity earnings or loss. Equity investments are increased
for contributions made to and decreased for distributions
The liability method of accounting for income taxes is
followed. Deferred 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. Deferred income tax assets and
liabilities are measured using the tax rate that is expected
to apply when the temporary differences reverse. Any interest
and/or penalty incurred related to tax is reflected in
Income taxes.
Foreign Currency Transactions and Translation
Foreign currency transactions are those transactions
whose terms are denominated in a currency other than the
currency of the primary economic environment in which
the Company or a reporting subsidiary operates, referred
to as the functional currency. Transactions denominated
in foreign currencies are translated into the functional
Notes to the Consolidated Financial Statements
129
currency using the exchange rate prevailing at the date of
transaction. Monetary assets and liabilities denominated in
foreign currencies are translated to the functional currency
using the rate of exchange in effect at the balance sheet
date. Exchange gains and losses resulting from translation
of monetary assets and liabilities are included in the
Consolidated Statements of Earnings in the period in which
they arise.
Gains and losses arising from translation of foreign operations’
functional currencies to the Company’s Canadian dollar
presentation currency are included in the cumulative
translation adjustment component of AOCI and are recognized
in earnings upon sale of the foreign operation. Asset and
liability accounts are translated at the exchange rates in effect
on the balance sheet date, while revenues and expenses are
translated using monthly average exchange rates.
Cash and Cash Equivalents
Cash and cash equivalents include short-term investments with
a term to maturity of three months or less when purchased.
Restricted Cash
Cash and cash equivalents that are restricted as to
withdrawal or usage, in accordance with specific customer
agreements, are presented as Restricted cash on the
Consolidated Statements of Financial Position.
Loans and Receivables
Affiliate long-term notes receivable are measured at
amortized cost using the effective interest rate method, net
of any impairment losses recognized. Accounts receivable
and other are measured at cost.
Allowance for Doubtful Accounts
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.
Inventory
Inventory is comprised of natural gas in storage held in
EGD and crude oil and natural gas held primarily by energy
services businesses. Natural gas in storage in EGD 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 as a liability for future
refund or as an asset for collection as approved by the OEB.
Other commodities inventory is recorded at the lower of
cost, as determined on a weighted average basis, or market
value. Upon disposition, other commodities inventory
is recorded to Commodity costs in the Consolidated
Statements of Earnings at the weighted average cost of
inventory, including any adjustments recorded to reduce
inventory to market value.
Property, Plant and Equipment
Property, plant and equipment is recorded at historical cost.
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
future benefit. The Company capitalizes interest incurred
during construction for non rate-regulated assets. For rate-
regulated assets, 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.
Two primary methods of depreciation are utilized.
For distinct assets, depreciation is generally provided on
a straight-line basis over the estimated useful lives of the
assets commencing when the asset is placed in service.
For largely homogeneous groups of assets with comparable
useful lives, the pool method of accounting for property,
plant and equipment is followed whereby similar assets 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.
Deferred Amounts and Other Assets
Deferred amounts and other assets primarily include:
costs which regulatory authorities have permitted, or are
expected to permit, to be recovered through future rates
including deferred income taxes; contractual receivables
under the terms of long-term delivery contracts; derivative
financial instruments; and deferred financing costs. Deferred
financing costs are amortized using the effective interest
method over the term of the related debt and are recorded
in Interest expense.
Intangible Assets
Intangible assets consist primarily of acquired long-term
transportation or power purchase agreements, natural gas
supply opportunities and certain software costs. Natural gas
supply opportunities are growth opportunities, identified
upon acquisition, present in gas producing zones where
certain of EEP’s gas systems are located. The Company
capitalizes costs incurred during the application development
stage of internal use software projects. Intangible assets are
amortized on a straight-line basis over their expected lives,
commencing when the asset is available for use.
130 Enbridge Inc. 2013 Annual Report
Goodwill
Goodwill represents the excess of the purchase price over
the fair value of net identifiable assets on acquisition of
a business. The carrying value of goodwill, which is not
amortized, is assessed for impairment annually, or more
frequently if events or changes in circumstances arise that
suggest the carrying value of goodwill may be impaired.
For the purposes of impairment testing, reporting units
are identified as business operations within an operating
segment. The Company has the option to first assess
qualitative factors to determine whether it is necessary
to perform the two-step goodwill impairment test. If the
two-step goodwill impairment test is performed, the first
step involves determining the fair value of the Company’s
reporting units inclusive of goodwill and comparing those
values to the carrying value of each reporting unit. If the
carrying value of a reporting unit, including allocated
goodwill, exceeds its fair value, goodwill impairment is
measured as the excess of the carrying amount of the
reporting unit’s allocated goodwill over the implied fair value
of the goodwill based on the fair value of the reporting unit’s
assets and liabilities.
Impairment
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.
With respect to investments in debt and equity securities,
the Company assesses at each balance sheet date whether
there is objective evidence that a financial asset is impaired
by completing a quantitative or qualitative analysis of factors
impacting the investment. 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 other financial assets, the Company assesses
the assets for impairment when it no longer has reasonable
assurance of timely collection. If evidence of impairment
is noted, the Company reduces the value of the financial
asset to its estimated realizable amount, determined using
discounted expected future cash flows.
Asset Retirement Obligations
ARO associated with the retirement of long-lived assets are
measured at fair value and recognized as Other long-term
liabilities in the period in which 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. ARO 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 the majority of the Company’s assets, it is not
possible to make a reasonable estimate of ARO due to the
indeterminate timing and scope of the asset retirements.
Retirement and Postretirement 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 estimates of future salary
levels, other cost escalations, retirement ages of employees
and other actuarial factors including discount rates and
mortality. For the Liquids Pipelines and Gas Distribution
pension plans (collectively, the Canadian Plans), in 2013 new
mortality assumptions were adopted by the Company for
measurement of the December 31, 2013 benefit obligations,
moving from the tables previously issued by the Canadian
Institute of Actuaries to the proposed revised tables.
The Company determines discount rates by reference to rates
of high-quality long-term corporate bonds with maturities
that approximate the timing of future payments the Company
anticipates making under each of the respective plans.
During the year ended December 31, 2012, the Company
refined the methodology by which it determines discount
rates for its Canadian Plans, in particular, refining the method
by which it estimates spreads for bonds with longer term
maturities. Pension cost is charged to earnings and includes:
• Cost of pension plan benefits provided in exchange for
employee services rendered during the year;
• Amortization of the 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.
Notes to the Consolidated Financial Statements
131
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, changes in headcount 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 invested
asset mix within the pension plans. 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 OPEB other than pensions,
including group health care and life insurance benefits for
eligible retirees, their spouses and qualified dependents.
The cost of such benefits is accrued during the years in
which employees render service.
The overfunded or underfunded status of defined benefit
pension and OPEB plans is recognized as Deferred amounts
and other assets or Other long-term liabilities, respectively,
on the Consolidated Statements of Financial Position.
A plan’s funded status is measured as the difference between
the fair value of plan assets and the plan’s projected benefit
obligation. Any unrecognized actuarial gains and losses and
prior service costs and credits that arise during the period
are recognized as a component of OCI, net of tax.
Certain regulated utility operations of the Company
expect to recover pension expense in future rates and
therefore record a corresponding regulatory asset to the
extent such recovery is deemed to be probable. For years
prior to 2012, a regulatory asset related to EGD’s OPEB
obligation was not recorded given recovery in rates was
not probable. Commencing in 2012, pursuant to a specific
rate order allowing EGD to recover OPEB costs determined
on an accrual basis in rates, a corresponding regulatory
asset was recognized. In the absence of rate regulation,
regulatory balances would not be recorded and pension and
OPEB costs would be charged to earnings and OCI on an
accrual basis.
Stock-based Compensation
Incentive Stock Options (ISO) granted are recorded using the
fair value method. Under this method, compensation expense
is measured at the grant date based on the fair value of the
ISO granted as calculated by the Black-Scholes-Merton model
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 Additional paid-in capital.
Balances in Additional paid-in capital are transferred to Share
capital when the options are exercised.
Performance based stock options (PBSO) granted are recorded
using the fair value method. Under this method, compensation
expense is measured at the grant date based on the fair value
of the PBSO granted as calculated by the Bloomberg barrier
option valuation model and is recognized over the vesting
period with a corresponding credit to Additional paid-in capital.
The options become exercisable when both performance
targets and time vesting requirements have been met. Balances
in Additional paid-in capital are transferred to Share capital
when the options are exercised.
Performance Stock Units (PSU) and Restricted Stock
Units (RSU) are cash settled awards for which the related
liability is remeasured each reporting period. PSU vest at
the completion of a three-year term and RSU vest at the
completion of a 35-month term. During the vesting term,
compensation expense is recorded based on the number
of units outstanding and the current market price of the
Company’s shares with an offset to Accounts payable and
other or to Other long-term liabilities. The value of the PSU
is also dependent on the Company’s performance relative to
performance targets set out under the plan.
Commitments, Contingencies and
Environmental Liabilities
The Company expenses or capitalizes, as appropriate,
expenditures for ongoing compliance with environmental
regulations that relate to past or current operations.
The Company expenses costs incurred for remediation
of existing environmental contamination caused by past
operations that do not benefit future periods by preventing
or eliminating future contamination. The Company records
liabilities for environmental matters when assessments
indicate that remediation efforts are probable and the costs
can be reasonably estimated. Estimates of environmental
liabilities are based on currently available facts, existing
technology and presently enacted laws and regulations
taking into consideration the likely effects of inflation and
other factors. These amounts also consider prior experience
in remediating contaminated sites, other companies’
clean-up experience and data released by government
organizations. The Company’s estimates are subject to
revision in future periods based on actual costs or new
information and are included in Environmental liabilities and
Other long-term liabilities in the Consolidated Statements
of Financial Position at their undiscounted amounts. There is
always a potential of incurring additional costs in connection
with environmental liabilities due to variations in any or all
of the categories described above, including modified or
revised requirements from regulatory agencies, in addition to
fines and penalties, as well as expenditures associated with
litigation and settlement of claims. The Company evaluates
recoveries from insurance coverage separately from the
liability and, when recovery is probable, the Company
records and reports an asset separately from the associated
liability in the Consolidated Statements of Financial Position.
132 Enbridge Inc. 2013 Annual Report
Liabilities for other commitments and contingencies are
recognized when, after fully analyzing available information,
the Company determines it is either probable that an asset
has been impaired, or that a liability has been incurred,
and the amount of impairment or loss can be reasonably
estimated. When a range of probable loss can be estimated,
the Company recognizes the most likely amount, or if no
amount is more likely than another, the minimum of the
range of probable loss is accrued. The Company expenses
legal costs associated with loss contingencies as such costs
are incurred.
3. Changes in Accounting
Policies
Adoption of New Standards
Balance Sheet Offsetting
Effective January 1, 2013, the Company adopted Accounting
Standards Update (ASU) 2011-11 and ASU 2013-01, which
require enhanced disclosures on the effect or potential effect
of netting arrangements on an entity’s financial position.
As the adoption of these updates impacted disclosure only,
there was no impact to the Company’s consolidated financial
position for the current or prior periods presented.
Accumulated Other Comprehensive Income
Effective January 1, 2013, the Company adopted ASU
2013-02, which requires enhanced disclosures on amounts
reclassified out of AOCI. As the adoption of this update
impacted disclosure only, there was no impact to the
Company’s consolidated financial statements for the
current or prior periods presented.
Presentation of Unrecognized Tax Benefits
Effective December 31, 2013, the Company elected to
early adopt ASU 2013-11, which requires presentation of
unrecognized tax benefits as a reduction to a deferred tax
asset for a net operating loss carryforward unless specific
conditions exist. There was no material impact to the
consolidated financial statements for the current or prior
periods presented as a result of adopting this update.
Future Accounting Policy Changes
Obligations Resulting from Joint and Several
Liability Arrangements
ASU 2013-04 was issued in February 2013 and provides
both measurement and disclosure guidance for obligations
with fixed amounts at a reporting date resulting from joint
and several liability arrangements. The adoption of the
pronouncement is not anticipated to have a material impact
on the Company’s consolidated financial statements.
This accounting update is effective for annual and interim
periods beginning after December 15, 2013 and is to be
applied retrospectively.
Parent’s Accounting for the Cumulative
Translation Adjustment
ASU 2013-05 was issued in March 2013 and provides
guidance on the timing of release of the cumulative
translation adjustment into net income when a disposition
or ownership change occurs related to an investment
in a foreign entity or a business within a foreign entity.
The adoption of the pronouncement is not anticipated
to have a material impact on the Company’s consolidated
financial statements. This accounting update is effective
for annual and interim periods beginning after
December 15, 2013 and is to be applied prospectively.
4. Revision of Prior Period
Financial Statements
In connection with the preparation of the Company’s
consolidated financial statements for the three months
ended March 31, 2013, an error was identified in the manner
in which the Company recorded deferred regulatory assets
associated with the difference between depreciation
expense calculated in accordance with U.S. GAAP and
negotiated depreciation rates recovered in transportation
tolls for certain of its regulated operations. Further, to the
extent the deferred regulatory asset gave rise to temporary
differences, an offsetting regulatory asset with respect
to deferred income taxes was also recognized. During the
three months ended September 30, 2013, the Company
identified that certain intercompany commodity sales and
commodity purchase transactions within Energy Services
were not appropriately eliminated upon consolidation.
This presentation matter had no effect on the margin,
earnings or cash flows for any prior period.
In accordance with accounting guidance found in Accounting
Standards Codification (ASC) 250-10 (SEC Staff Accounting
Bulletin No. 99, Materiality), the Company assessed the
materiality of these errors and concluded that they were
not material to any of the Company’s previously issued
consolidated financial statements. In accordance with
guidance found in ASC 250-10 (SEC Staff Accounting Bulletin
No. 108, Considering the Effects of Prior Year Misstatements
when Quantifying Misstatements in Current Year Financial
Statements), the Company revised its comparative
consolidated financial statements to correct the effects of
these matters. These non-cash revisions do not impact cash
flows for any prior period.
The following tables present the effect of these corrections
on individual line items within the Company’s Consolidated
Statements of Earnings and Consolidated Statements of
Notes to the Consolidated Financial Statements
133
Financial Position. The effects which flow through to the individual line items of Earnings, Depreciation
and amortization, Cash distributions in excess of equity earnings, Deferred income taxes, Changes
in regulatory assets and liabilities and Changes in operating assets and liabilities of the Consolidated
Statements of Cash Flows are not significant and have no net effect on the Company’s cash flows from
operating activities.
The previously reported figures presented below exclude the effect of any subsequent presentation
changes associated with discontinued operations. Comparative figures as at December 31, 2012 and for
the years ended December 31, 2012 and 2011 have been revised throughout these financial statements
as necessary to reflect these revisions.
(millions of Canadian dollars,except per share amounts)
Commodity sales
Transportation and other services revenues
Commodity costs
Depreciation and amortization
Income from equity investments
Income taxes expense
Earnings
Earnings attributable to noncontrolling
interests and redeemable
noncontrolling interests
Earnings attributable to Enbridge Inc.
Earnings attributable to Enbridge Inc.
common shareholders
Earnings per common share attributable
to Enbridge Inc. common shareholders
Diluted earnings per common share
attributable to Enbridge Inc.
common shareholders
Year ended December 31, 2012
Year ended December 31, 2011
As
Previously
Reported
19,101
4,295
18,566
1,206
160
(128)
943
(228)
715
610
0.79
Adjustment
As Revised
As
Previously
Reported
Adjustment
As Revised
(607)
(7)
(607)
36
35
1
(7)
(1)
(8)
(8)
(0.01)
18,494
4,288
17,959
1,242
195
(127)
936
(229)
707
602
0.78
20,611
4,536
19,864
1,112
210
(526)
1,242
(409)
833
820
1.09
(237)
(8)
(237)
42
23
6
(21)
2
(19)
(19)
(0.02)
20,374
4,528
19,627
1,154
233
(520)
1,221
(407)
814
801
1.07
0.78
(0.01)
0.77
1.08
(0.03)
1.05
As at December 31, 2012
As
Previously
Reported
3,386
2,622
2,601
3,464
(1,799)
Adjustment
As Revised
(211)
(161)
(118)
(291)
37
3,175
2,461
2,483
3,173
(1,762)
(millions of Canadian dollars)
Long-term investments
Deferred amounts and other assets
Deferred income tax liabilities
Retained earnings
Accumulated other comprehensive loss
134 Enbridge Inc. 2013 Annual Report
5. Segmented Information
Year ended December 31, 2013
(millions of Canadian dollars)
Revenues
Liquids
Pipelines
Gas
Distribution
Gas
Pipelines,
Processing
and Energy
Services
2,272
2,741
20,310
Commodity and gas distribution costs
–
(1,585)
(20,244)
Operating and administrative
Depreciation and amortization
Environmental costs, net of recoveries
Income from equity investments
Other income/(expense)
Interest income/(expense)
Income taxes recovery/(expense)
Earnings/(loss) from continuing operations
Discontinued operations
Earnings from discontinued operations
before income taxes
Income taxes from discontinued operations
Earnings from discontinued operations
(1,006)
(429)
(79)
758
118
39
(319)
(165)
431
–
–
–
(534)
(321)
–
301
–
20
(160)
(32)
129
–
–
–
Earnings/(loss)
431
129
(Earnings)/loss attributable to
noncontrolling interests and
redeemable noncontrolling interests
Preference share dividends
Earnings/(loss) attributable to
Enbridge Inc. common shareholders
Additions to property, plant and equipment4
Total assets
(4)
–
427
4,360
20,950
–
–
129
533
7,942
(221)
(75)
–
(230)
154
39
(81)
50
(68)
6
(2)
4
(64)
–
–
(64)
744
7,015
Sponsored
Investments
Corporate1 Consolidated
7,595
(4,978)
(1,226)
(530)
(283)
578
56
37
(409)
(133)
129
–
–
–
–
–
(27)
(15)
–
(42)
2
(270)
22
157
(131)
–
–
–
129
(131)
139
–
268
2,565
18,527
–
(183)
(314)
34
3,134
32,918
(26,807)
(3,014)
(1,370)
(362)
1,365
330
(135)
(947)
(123)
490
6
(2)
4
494
135
(183)
446
8,236
57,568
Notes to the Consolidated Financial Statements
135
Liquids2
Pipelines2
Gas
Distribution
Gas2,3
Pipelines,2,3
2Processing2,3
and Energy2,3
Services2,3
2,445
2,438
13,106
(1,220)
(13,676)
Sponsored2
Investments2 Corporate1,3 Consolidated
6,671
(4,283)
(1,076)
(431)
88
969
55
49
(397)
(169)
507
–
–
–
–
–
(51)
(13)
–
(64)
(47)
80
20
(13)
(24)
–
–
–
507
(24)
(224)
–
283
1,886
15,648
–
(105)
(129)
4
3,263
24,660
(19,179)
(2,739)
(1,236)
88
1,594
195
238
(841)
(171)
1,015
(123)
44
(79)
936
(229)
(105)
602
5,195
46,800
(142)
(57)
–
(769)
141
33
(50)
269
(376)
(123)
44
(79)
(455)
(1)
–
(456)
933
(528)
(336)
–
354
–
83
(164)
(66)
207
–
–
–
–
–
207
445
701
207
7,416
5,349
–
(942)
(399)
–
1,104
46
(7)
(250)
(192)
701
–
–
–
(4)
–
697
1,927
15,124
Year ended December 31, 2012
(millions of Canadian dollars)
Revenues
Commodity and gas distribution costs
Operating and administrative
Depreciation and amortization
Environmental costs, net of recoveries
Income/(loss) from equity investments
Other income/(expense)
Interest income/(expense)
Income taxes recovery/(expense)
Earnings/(loss) from continuing operations
Discontinued operations
Loss from discontinued operations
before income taxes
Income taxes recovery from
discontinued operations
Loss from discontinued operations
Earnings/(loss)
Earnings attributable to
noncontrolling interests and
redeemable noncontrolling interests
Preference share dividends
Earnings/(loss) attributable to
Enbridge Inc. common shareholders
Additions to property, plant and equipment4
Total assets
136 Enbridge Inc. 2013 Annual Report
Year ended December 31, 2011
(millions of Canadian dollars)
Revenues
Commodity and gas distribution costs
Operating and administrative
Depreciation and amortization
Environmental costs, net of recoveries
Income/(loss) from equity investments
Other income/(expense)
Interest expense
Income taxes recovery/(expense)
Earnings/(loss) from continuing operations
Discontinued operations
Loss from discontinued operations
before income taxes
Income taxes recovery from
discontinued operations
Loss from discontinued operations
Earnings/(loss) before extraordinary loss
Extraordinary loss, net of tax
Earnings/(loss)
Earnings attributable to
noncontrolling interests and
redeemable noncontrolling interests
Preference share dividends
Earnings/(loss) attributable to
Enbridge Inc. common shareholders
Additions to property, plant and equipment4
Liquids2
Pipelines2
Gas
Distribution
Gas2,3
Pipelines,2,3
2Processing2,3
and Energy2,3
Services2,3
1,934
2,516
13,343
–
(752)
(364)
–
818
5
31
(256)
(125)
473
–
–
–
473
–
473
(3)
–
470
909
(1,282)
(12,814)
(508)
(320)
–
406
–
(12)
(166)
(54)
174
–
–
–
174
(262)
(88)
–
–
(88)
478
(116)
(68)
–
345
179
39
(56)
(178)
329
(9)
3
(6)
323
–
323
(1)
–
322
959
Sponsored2
Investments2 Corporate1,3 Consolidated
8,996
(6,812)
(847)
(383)
116
1,070
54
68
(350)
(171)
671
–
–
–
671
–
671
(403)
–
268
1,157
–
–
(36)
(12)
–
(48)
(5)
(10)
(100)
5
(158)
–
–
–
(158)
–
(158)
–
(13)
(171)
27
26,789
(20,908)
(2,259)
(1,147)
116
2,591
233
116
(928)
(523)
1,489
(9)
3
(6)
1,483
(262)
1,221
(407)
(13)
801
3,530
1
2
3
4
Included within the Corporate segment was Interest income of $443 million (2012 - $336 million; 2011 - $239 million) charged to other operating segments.
In December 2012 and October 2011, certain crude oil storage and renewable energy assets were transferred to the Fund within the Sponsored Investments segment.
Earnings from the assets prior to the date of transfer of $33 million (2011 - $71 million) have not been reclassified among segments for presentation purposes.
Due to a change in organizational structure, effective January 1, 2013, for the year ended December 31, 2012 earnings of $1 million (2011 - nil) and additions to property,
plant and equipment of $108 million (2011 - nil) were reclassified from the Corporate segment to the Gas Pipelines, Processing and Energy Services segment.
Includes allowance for equity funds used during construction.
The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2).
Geographic Information
Revenues1
Year ended December 31,
(millions of Canadian dollars)
Canada
United States
1
Revenues are based on the country of origin of the product or service sold.
Property, Plant and Equipment
December 31,
(millions of Canadian dollars)
Canada
United States
2013
2012
2011
12,690
20,228
32,918
11,629
13,031
24,660
11,852
14,937
26,789
2013
2012
22,865
19,414
42,279
19,293
14,025
33,318
Notes to the Consolidated Financial Statements
137
6. Financial Statement Effects
of Rate Regulation
General Information on Rate Regulation and its
Economic Effects
A number of businesses within the Company are subject to
regulation. The Company’s significant regulated businesses
and related accounting impacts are described below.
Canadian Mainline
Canadian Mainline includes the Canadian portion of the
mainline system and is subject to regulation by the NEB.
Canadian Mainline tolls (excluding Lines 8 and 9) are currently
governed by the 10-year CTS, which establishes a Canadian
Local Toll for all volumes shipped on the Canadian Mainline
and an International Joint Tariff for all volumes shipped
from western Canadian receipt points to delivery points on
the Lakehead System and delivery points on the Canadian
Mainline downstream of the Lakehead System. The CTS was
negotiated with shippers in accordance with NEB guidelines,
was approved by the NEB in June 2011 and took effect
July 1, 2011. Under the CTS, a regulatory asset is recognized
to offset deferred income taxes as a NEB rate order
governing flow-through income tax treatment permits future
recovery. No other material regulatory assets or liabilities are
recognized under the terms of the CTS.
Prior to July 1, 2011, the effective date of the CTS, the
Incentive Tolling Settlement (ITS) defined the methodology
for calculation of tolls on the core component of the Canadian
Mainline. Toll adjustments for variances from requirements
defined in the ITS were filed annually with the regulator for
approval, and regulatory assets and liabilities were recognized
to the extent amounts were recoverable from or payable
to customers through future rates. Surcharges were also
determined for a number of system expansion components and
were added to the base toll determined for the core system.
Southern Lights
The United States portion of the Southern Lights Pipeline
(Southern Lights US) is regulated by the FERC and the
Canadian portion of the Southern Lights Pipeline (Southern
Lights Canada) is regulated by the NEB. Shippers on
the Southern Lights Pipeline are subject to long-term
transportation contracts under a cost of service toll
methodology. Toll adjustments are filed annually with the
regulators. Tariffs provide for recovery of all operating and
debt financing costs, plus a pre-determined after-tax rate of
return on equity (ROE) of 10%. Southern Lights 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. For the year ended December 31, 2013, rates were set
pursuant to an OEB approved settlement agreement and
decision (the 2013 Settlement) related to its 2013 cost of
service rate application. The 2013 Settlement retained the
previous deemed equity level but provided for an increase
in the allowed ROE. The 2013 Settlement further retained
the flow-through nature of the cost of natural gas supply
and several other cost categories. The earnings sharing
mechanism, which was previously in effect under revenue cap
incentive regulation (IR), did not apply to the 2013 Settlement.
Prior to 2013, EGD operated under an IR mechanism,
calculated on a revenue per customer basis, with the OEB
for a five-year period between 2008 and 2012. Under the
IR mechanism, the Company was allowed to earn and fully
retain 100 basis points (bps) over the base return. Any return
over 100 bps was required to be shared with customers on
an equal basis.
EGD’s after-tax rate of return on common equity embedded
in rates was 8.9% for the year ended December 31, 2013
(2012 - 8.4%) based on a 36% deemed common equity
component of capital for regulatory purposes (2012 - 36%).
The 2013 Settlement established the right to recover
an existing OPEB liability of approximately $89 million
($63 million after-tax) over a 20-year time period
commencing in 2013. The gain was presented within Other
income/(expense) on the Consolidated Statements of
Earnings for the year ended December 31, 2012. The 2013
Settlement further provided for OPEB and pension costs,
determined on an accrual basis, to be recovered in rates.
In July 2013, EGD filed an application with the OEB for the
setting of rates through a customized IR mechanism for
the period of 2014 through 2018. A decision is anticipated
by the second quarter of 2014.
Enbridge Gas New Brunswick
Enbridge Gas New Brunswick (EGNB) is regulated by the
EUB and currently sets tolls at the lower of market-based
or cost of service rates. As at December 31, 2011, EGNB
discontinued rate-regulated accounting due to amendments
in the rate setting methodology enacted by the Government
of New Brunswick, and consequently wrote-off a deferred
regulatory asset of $180 million and a regulatory asset with
respect to capitalized operating costs of $103 million, net
of an income tax recovery of $21 million. The write-off of
$262 million, net of tax, was presented as an extraordinary
loss on the Consolidated Statements of Earnings for the
year ended December 31, 2011.
138 Enbridge Inc. 2013 Annual Report
Financial Statement Effects
Accounting for rate-regulated activities has resulted in the recognition of the following significant
regulatory assets and liabilities:
December 31,
(millions of Canadian dollars)
Regulatory assets/(liabilities)
Liquids Pipelines
Deferred income taxes1
Tolling deferrals2
Recoverable income taxes3
Gas Distribution
Deferred income taxes4
Transaction services deferral5
Future removal and site restoration reserves6
Pension plans and OPEB7
Sponsored Investments
Deferred income taxes1
Transportation revenue adjustments8
2013
2012
727
(36)
42
214
(51)
(929)
94
28
33
598
(33)
40
201
(26)
(882)
212
39
19
1
2
3
4
5
6
The asset represents the regulatory offset to deferred income tax liabilities that are expected to be recovered under flow-through income tax treatment. The recovery
period depends on future reversal of temporary differences.
The liability reflects net tax benefits expected to be refunded through future transportation tolls on Southern Lights Canada. The balance is expected to accumulate
for approximately nine years before being refunded through tolls.
The asset represents future revenues to be collected from shippers for Southern Lights US to recover federal income taxes payable on the equity component of
AFUDC. The recovery period is approximately 30 years.
The asset represents the regulatory offset to deferred income tax liabilities to the extent that deferred income taxes are expected to be recovered or refunded
through regulator-approved rates. The recovery period depends on future temporary differences. Deferred income taxes in Gas Distribution are excluded from the
rate base and do not earn a return on equity.
The transaction services deferral represents the customer portion of additional earnings generated from optimization of storage and pipeline capacity. The balance
is expected to be refunded to customers in the following year.
The future removal and site restoration reserves balance results from amounts collected from customers by certain businesses, with the approval of the regulator,
to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on
property, plant and equipment. The balance represents the amount that has been collected from customers, net of actual costs expended on removal and site
restoration. The settlement of this balance will occur as future removal and site restoration costs are incurred.
7
The pension plans and OPEB balances represent the regulatory offset to pension plan and OPEB obligations to the extent the amounts are expected to be collected
from customers in future rates. An OPEB balance of $89 million is being collected over a 20-year period which commenced in 2013, whereas the settlement period
for the pension regulatory asset is not determinable. The balances are excluded from the rate base and do not earn a return on equity.
8
Transportation revenue adjustments are the cumulative differences between actual expenses incurred and estimated expenses included in transportation tolls.
Transportation revenue adjustments are not included in the rate base. The recovery period is approximately five years and dependent on shipper throughput levels.
Other Items Affected by Rate Regulation
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
With the approval of regulators, certain operations capitalize a percentage of certain operating costs.
These operations are 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 operating costs
would be charged to earnings in the year incurred.
EGD entered into a consulting contract relating to asset management initiatives. The majority of the
costs, primarily consulting fees, are being capitalized to gas mains in accordance with regulatory
approval. At December 31, 2013, cumulative costs relating to this consulting contract of $154 million
(2012 - $144 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, some of these costs would be
charged to earnings in the year incurred.
Notes to the Consolidated Financial Statements
139
7. Acquisitions and Dispositions
Acquisitions
Silver State North Solar Project
On March 22, 2012, Enbridge acquired a 100% interest in the Silver State North Solar Project (Silver
State), a solar farm located in Nevada for cash consideration of $195 million (US$190 million). Silver State
expanded the Company’s renewable energy business. Revenues and earnings of $10 million and $1 million,
respectively, were recognized in the year ended December 31, 2012. No revenues or earnings were
recognized in any prior period as the solar project commenced operations in the second quarter of 2012.
Silver State is included within the Gas Pipelines, Processing and Energy Services segment.
March 22,
(millions of Canadian dollars)
Fair value of net assets acquired:
Accounts receivable and other1
Property, plant and equipment
Purchase price:
Cash
2012
54
141
195
195
1
The Company acquired the right to apply for a $54 million (US$55 million) United States Treasury grant under a program which reimburses eligible applicants for a
portion of costs related to installing specified renewable energy property. The grant, which was applied for subsequent to commercial operations, was received in
October 2012.
Tonbridge Power Inc.
On October 13, 2011, Enbridge acquired 100% of the 36 million outstanding common shares of
Tonbridge Power Inc. (Tonbridge), an independent company engaged in constructing an electric
transmission line between Montana and Alberta, for $20 million in cash at a price of $0.54 per share.
Tonbridge was included within the Corporate segment upon acquisition and was subsequently
reclassified to the Gas Pipelines, Processing and Energy Services segment effective January 1, 2013,
due to a change in organizational structure.
October 13,
(millions of Canadian dollars)
Fair value of net assets acquired:
Working capital deficiency
Property, plant and equipment
Intangible assets
Long-term debt
Other long-term liabilities
Purchase price:
Cash (net of $15 million cash acquired)
2011
(5)
196
17
(182)
(21)
5
5
No revenues from Tonbridge were recognized in 2011 as the transmission line was not in service. A net
loss of $1 million was recognized in earnings for the period from October 13, 2011 to December 31, 2011
related to operating and administrative expense. An unaudited proforma net loss of $38 million, including
$6 million of transaction costs, would have been recognized in earnings in 2011 had the acquisition
occurred on January 1, 2011.
140 Enbridge Inc. 2013 Annual Report
In October 2011, the Company acquired the remaining
10% interest in Talbot Windfarm, LP (Talbot) for $28 million,
increasing its ownership interest to 100%. The Company’s
interest in Talbot was consolidated and presented within the
Gas Pipelines, Processing and Energy Services segment until
such time as it was transferred to the Fund in October 2011.
Unaudited proforma consolidated revenues and earnings
that give effect to all of the Company’s other acquisitions
as if they had occurred as of January 1 in the year of
acquisition are not presented as the information would not
be materially different from the information presented in the
accompanying Consolidated Statements of Earnings.
Other Acquisitions and Dispositions
In November 2013, EEP sold one of its non-core
liquids assets, a storage facility in Kansas, to a third
party for $41 million (US$40 million). A gain of $18 million
(US$17 million) was presented within Other income/
(expense) on the Consolidated Statements of Earnings.
In November 2012, Enbridge acquired certain sour gas
gathering and compression facilities located in the Peace
River Arch region of northwest Alberta (collectively,
Pipestone and Sexsmith) for a purchase price of $118 million,
which has been fully allocated to Property, plant and
equipment. Pipestone and Sexsmith are currently in service
or under construction and are presented within the Gas
Pipelines, Processing and Energy Services segment.
In May 2012, Enbridge acquired the remaining 10%
interest in the Greenwich Wind Energy Project (Greenwich)
through Greenwich Windfarm, LP, for cash consideration
of $27 million, increasing its ownership interest to 100%.
The Company’s interest in Greenwich was consolidated and
presented within the Gas Pipelines, Processing and Energy
Services segment until such time as it was transferred to
the Fund in December 2012 (Note 19).
Notes to the Consolidated Financial Statements
141
8. Accounts Receivable and Other
December 31,
(millions of Canadian dollars)
Unbilled revenues
Trade receivables
Taxes receivable
Regulatory assets
Short-term portion of derivative assets (Note 23)
Prepaid expenses and deposits
Current deferred income taxes (Note 24)
Dividends receivable
Other
Allowance for doubtful accounts
Pursuant to a Receivables Purchase Agreement (the Receivables Agreement), certain trade and
accrued receivables (the Receivables) have been sold by certain of EEP’s subsidiaries to an Enbridge
wholly-owned special purpose entity (SPE). The Receivables owned by the SPE are not available to
Enbridge except through its 100% ownership in such SPE. The Receivables Agreement, as amended
on September 20, 2013 and again on December 2, 2013, provides for subsequent purchases to occur
on a monthly basis through to December 2016; however, the accumulated purchases net of collections
cannot exceed US$450 million at any one point. As at December 31, 2013, the value of trade and
accrued receivables outstanding owned by the SPE totalled US$380 million ($404 million).
9. Inventory
December 31,
(millions of Canadian dollars)
Natural gas
Other commodities
Commodity costs on the Consolidated Statements of Earnings included non-cash charges of $4 million
(2012 - $10 million; 2011 - $9 million) for the year ended December 31, 2013 to reduce the cost basis of
inventory to market value.
2013
2012
2,773
1,215
200
54
385
123
120
26
98
2,289
677
123
–
383
132
167
26
266
(38)
4,956
(49)
4,014
2013
2012
527
588
1,115
448
331
779
142 Enbridge Inc. 2013 Annual Report
10. Property, Plant and Equipment
December 31,
(millions of Canadian dollars)
Liquids Pipelines
Pipeline
Pumping equipment, buildings, tanks and other
Land and right-of-way
Under construction
Accumulated depreciation
Gas Distribution
Gas mains, services and other
Land and right-of-way
Under construction
Accumulated depreciation
Gas Pipelines, Processing and Energy Services
Pipeline
Wind turbines, solar panels and other
Power transmission1
Land and right-of-way
Under construction1
Accumulated depreciation
Sponsored Investments
Pipeline
Pumping equipment, buildings, tanks and other
Wind turbines, solar panels and other
Land and right-of-way
Under construction
Accumulated depreciation
Corporate
Other1
Under construction1
Accumulated depreciation
Weighted Average
Depreciation Rate
2013
2012
2.6%
3.0%
2.2%
–
3.8%
1.1%
–
3.5%
4.4%
2.1%
4.3%
–
2.9%
3.2%
3.7%
2.3%
–
12.7%
–
8,974
6,248
253
4,846
20,321
(3,838)
16,483
8,020
79
179
8,278
(2,074)
6,204
1,013
1,092
384
6
1,233
3,728
(344)
3,384
8,979
5,381
2,243
755
2,201
19,559
(3,429)
16,130
84
36
120
(42)
78
8,249
5,094
225
1,675
15,243
(3,432)
11,811
7,583
79
102
7,764
(1,912)
5,852
544
519
29
6
1,761
2,859
(350)
2,509
6,890
4,787
1,544
642
2,002
15,865
(2,770)
13,095
76
12
88
(37)
51
1
Due to a change in organizational structure effective January 1, 2013, Property, plant and equipment of $313 million were reclassified from the Corporate segment
to the Gas Pipelines and Energy Services segment for the year ended December 31, 2012.
42,279
33,318
Depreciation expense for the year ended December 31, 2013 was $1,282 million (2012 - $1,174 million;
2011 - $1,089 million).
Notes to the Consolidated Financial Statements
143
Gas Pipelines, Processing and Energy Services
Discontinued Operations
During the fourth quarter of 2013, Enbridge concluded it
would seek to dispose of certain assets within the Stingray
corridor and entered into negotiations with an unrelated
third party. As a result, at December 31, 2013, the related
assets and liabilities were classified as held for sale and
were measured at the lower of their carrying amount and
estimated fair value less cost to sell which did not result in
a fair value adjustment. The results of operations including
revenues of $26 million (2012 - $32 million, 2011 - $19 million)
and related cash flows have been presented as discontinued
operations for the year ended December 31, 2013, with the
prior year comparative figures reclassified. These amounts
are included in the Gas Pipelines, Processing and Energy
Services segment. The Company expects to complete the
sale in the first quarter of 2014.
Impairment
In December 2012, the Company recorded an impairment
charge of $166 million ($105 million after-tax) related to
certain of its Enbridge Offshore Pipelines (Offshore) assets,
predominantly located within the Stingray and Garden Banks
corridors in the Gulf of Mexico. The Company had been
pursuing alternative uses for these assets; however, due to
changing competitive conditions in the fourth quarter of
2012, the Company concluded that such alternatives were no
longer likely to proceed. In addition, unique to these assets
is their significant reliance on natural gas production from
shallow water areas of the Gulf of Mexico which have been
challenged by macro-economic factors including prevalence
of onshore shale gas production, hurricane disruptions,
additional regulation and the low natural gas commodity
price environment.
The impairment charge was based on the amount by
which the carrying values of the assets exceeded fair
value, determined using expected discounted future
cash flows, and was presented within Operating and
administrative expense on the Consolidated Statements of
Earnings. The charge was inclusive of $50 million related to
abandonment costs which were reasonably determined given
the expected timing and scope of certain asset retirements.
A portion of the impairment charge was subsequently
reclassified to discontinued operations as noted below.
144 Enbridge Inc. 2013 Annual Report
11. Variable Interest Entity
The Fund is an unincorporated open-ended trust established by a trust indenture under the laws of
the Province of Alberta and is considered a VIE by virtue of its capital structure. The Company is the
primary beneficiary of the Fund through its combined 67.3% (2012 - 67.7%; 2011 - 69.2%) economic
interest, held indirectly through a common investment in ENF, a direct common trust unit investment
in the Fund and a preferred unit investment in a wholly-owned subsidiary of the Fund. Enbridge also
serves in the capacity of Manager of ENF, the Fund and its subsidiaries.
The summarized impact of the Company’s interest in the Fund on earnings, cash flows and financial
position is presented below. Earnings include the results of operations of certain assets acquired by
the Fund from wholly-owned subsidiaries of Enbridge from the dates of acquisition of October 2011
and December 2012 (Note 19). Earnings, cash flows and financial position information exclude the effect
of intercompany transactions.
Year ended December 31,
(millions of Canadian dollars)
Revenues
Operating and administrative expense
Depreciation and amortization
Income from equity investments
Interest expense
Income taxes
Earnings
Loss attributable to noncontrolling interest
Earnings attributable to Enbridge
Cash Flows
Cash provided by operating activities
Cash used in investing activities
Cash provided by/(used in) financing activities
Increase/(decrease) in cash and cash equivalents
December 31,
(millions of Canadian dollars)
Current assets
Property, plant and equipment, net
Long-term investments
Deferred amounts and other assets
Current liabilities
Long-term debt
Other long-term liabilities
Deferred income taxes
Net assets before noncontrolling interests
2013
2012
2011
403
(126)
(130)
57
(91)
(27)
86
24
110
260
(98)
(323)
(161)
288
(83)
(87)
54
(68)
(35)
69
12
81
200
(160)
1,495
1,535
146
(66)
(47)
57
(32)
(21)
37
9
46
137
(95)
381
423
2013
2012
84
2,317
227
130
(388)
224
2,390
215
145
(250)
(1,364)
(1,864)
(26)
(426)
554
(22)
(404)
434
Notes to the Consolidated Financial Statements
145
12. Long-term Investments
December 31,
(millions of Canadian dollars)
Equity Investments
Joint Ventures
Liquids Pipelines
Chicap Pipeline
Mustang Pipeline
Seaway Pipeline
Gas Pipelines, Processing and Energy Services
Offshore – various joint ventures
Vector
Alliance Pipeline US
Aux Sable
Other
Sponsored Investments
Alliance Pipeline Canada
Texas Express Pipeline
Other
Other Equity Investments
Corporate
Noverco Common Shares
Other
Other Long-Term Investments
Corporate
Noverco Preferred Shares
Other
Ownership
Interest
2013
2012
43.8%
30.0%
50.0%
29
23
27
21
2,048
1,385
22.0% – 74.3%
60.0%
50.0%
42.7% – 50.0%
33.3% – 70.0%
50.0%
35.0%
50.0%
38.9%
16.3% – 49.99%
401
125
201
306
11
165
396
62
–
56
287
102
391
130
181
266
10
179
183
35
–
55
246
66
4,212
3,175
Equity investments include the unamortized excess of the purchase price over the underlying net book
value of the investees’ assets at the purchase date which is comprised of $680 million (2012 - $636 million)
in Goodwill and $517 million (2012 - $493 million) in amortizable assets.
Joint Ventures
Summarized combined financial information of the Company’s interest in unconsolidated equity
investments in joint ventures is as follows:
2013
2012
2011
1,212
(371)
(268)
(175)
4
(74)
328
956
(236)
(244)
(159)
4
(81)
240
827
(138)
(200)
(158)
(3)
(87)
241
Year ended December 31,
(millions of Canadian dollars)
Revenues
Commodity costs
Operating and administrative expense
Depreciation and amortization
Other income/(expense)
Interest expense
Earnings before income taxes
146 Enbridge Inc. 2013 Annual Report
December 31,
(millions of Canadian dollars)
Current assets
Property, plant and equipment, net
Deferred amounts and other assets
Intangible assets, net
Goodwill
Current liabilities
Long-term debt
Other long-term liabilities
Net assets
Alliance Pipeline
2013
2012
366
4,050
35
75
680
(395)
(994)
(50)
299
3,192
26
74
639
(333)
(895)
(194)
3,767
2,808
Certain assets of Alliance Pipeline Canada are pledged as collateral to Alliance Pipeline Canada lenders
and to the lenders of Alliance Pipeline US. As well, certain assets of Alliance Pipeline US are pledged as
collateral to Alliance Pipeline US lenders and to the lenders of Alliance Pipeline Canada.
Other Equity Investments
Noverco
At December 31, 2013, Enbridge owned an equity interest in Noverco through ownership of 38.9%
(2012 - 38.9%; 2011 - 38.9%) of its common shares and an investment in preferred shares. The preferred
shares are entitled to a cumulative preferred dividend based on the average yield of Government of
Canada bonds maturing in 10 years plus a range of 4.3% to 4.4%.
At December 31, 2013, Noverco owned an approximate 3.9% (2012 - 6.0%; 2011 - 8.9%) reciprocal
shareholding in common shares of Enbridge. The change in reciprocal shareholding compared with
prior years reflected the sale of Enbridge common shares by Noverco in 2012 and 2013. Through
secondary offerings, Noverco sold 22.5 million Enbridge common shares in 2012 and a further 15 million
common shares in 2013. Enbridge’s share of the net after-tax proceeds of $297 million and $248 million
were received as dividends from Noverco in May 2012 and June 2013, respectively. The transactions
were recognized as issuances of treasury stock on the Consolidated Statements of Changes in Equity
and as an operating activity on the Consolidated Statements of Cash Flows.
As a result of Noverco’s reciprocal shareholding in Enbridge common shares, the Company has an
indirect pro-rata interest of 1.5% (2012 - 2.1%; 2011 - 3.5%) in its own shares. Both the equity investment
in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $86 million
at December 31, 2013 (2012 - $126 million; 2011 - $187 million). Noverco records dividends paid by the
Company as dividend income and the Company eliminates these dividends from its equity 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.
Notes to the Consolidated Financial Statements
147
13. Deferred Amounts and Other Assets
December 31,
(millions of Canadian dollars)
Regulatory assets
Long-term portion of derivative assets (Note 23)
Affiliate long-term note receivable (Note 28)
Contractual receivables
Deferred financing costs
Other
2013
2012
1,172
1,123
413
185
356
135
401
408
182
303
127
318
2,662
2,461
At December 31, 2013, deferred amounts of $307 million (2012 - $265 million) were subject to amortization
and are presented net of accumulated amortization of $159 million (2012 - $123 million). Amortization
expense for the year ended December 31, 2013 was $34 million (2012 - $25 million; 2011 - $20 million).
14. Intangible Assets
December 31, 2013
(millions of Canadian dollars)
Software
Natural gas supply opportunities
Power purchase agreements
Transportation agreements
Other
December 31, 2012
(millions of Canadian dollars)
Software
Natural gas supply opportunities
Power purchase agreements
Transportation agreements
Other
Weighted Average
Amortization Rate
Cost
Accumulated
Amortization
13.2%
3.7%
4.0%
3.7%
4.0%
825
311
87
53
64
241
65
7
15
8
Net
584
246
80
38
56
1,340
336
1,004
Weighted Average
Amortization Rate
Cost
Accumulated
Amortization
11.9%
3.8%
4.7%
2.9%
5.6%
622
291
85
50
20
1,068
180
50
4
13
4
251
Net
442
241
81
37
16
817
Total amortization expense for intangible assets was $82 million (2012 - $64 million; 2011 - $58 million)
for the year ended December 31, 2013. The Company expects aggregate amortization expense for the
years ending December 31, 2014 through 2018 of $93 million, $83 million, $73 million, $65 million and
$57 million, respectively.
148 Enbridge Inc. 2013 Annual Report
15. Goodwill
(millions of Canadian dollars)
Balance at January 1, 2012
Transfer of assets to the Fund
Foreign exchange and other
Balance at December 31, 2012
Foreign exchange and other
Balance at December 31, 2013
Liquids
Pipelines
Gas
Distribution
Gas
Pipelines,
Processing
and Energy
Services
Sponsored
Investments
Corporate Consolidated
48
(29)
3
22
1
23
–
–
–
–
–
–
30
–
(17)
13
1
14
362
29
(7)
384
24
408
–
–
–
–
–
–
440
–
(21)
419
26
445
The Company did not recognize any goodwill impairments for the years ended December 31, 2013 and 2012.
16. 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
2013
2012
3,577
300
1,188
837
211
176
65
310
2,729
123
568
1,075
86
206
69
196
6,664
5,052
Notes to the Consolidated Financial Statements
149
17. Debt
December 31,
(millions of Canadian dollars)
Liquids Pipelines
Debentures
Medium-term notes1
Southern Lights project financing2
Commercial paper and credit facility draws
Other3
Gas Distribution
Debentures
Medium-term notes
Commercial paper and credit facility draws
Sponsored Investments
Junior subordinated notes4
Medium-term notes
Senior notes5
Commercial paper and credit facility draws6
Corporate
United States dollar term notes7
Medium-term notes
Commercial paper and credit facility draws8
Other9
Total debt
Current maturities
Short-term borrowings10
Long-term debt
Weighted Average
Interest Rate
Maturity
2013
2012
8.2%
4.8%
2.7%
2024
2015 – 2043
2014
9.9%
5.3%
2024
2014 – 2050
8.1%
3.9%
6.3%
2067
2014 – 2023
2014 – 2040
4.2%
4.6%
2015 – 2023
2015 – 2042
200
2,985
1,480
266
11
85
2,702
374
425
1,615
4,201
717
2,393
4,518
3,598
(28)
25,542
(2,811)
(374)
200
2,435
1,413
25
12
85
2,295
590
398
1,615
4,129
1,405
1,094
4,268
1,488
(14)
21,438
(652)
(583)
22,357
20,203
1
2
3
4
5
6
7
8
9
Included in medium-term notes is $100 million with a maturity date of 2112.
2013 - $352 million and US$1,061 million (2012 - $357 million and US$1,061 million).
Primarily capital lease obligations.
2013 - US$400 million (2012 - US$400 million).
2013 - US$3,950 million (2012 - US$4,150 million).
2013 - $41 million and US$635 million (2012 - $250 million and US$1,160 million).
2013 - US$2,250 million (2012 - US$1,100 million).
2013 - $2,476 million and US$1,055 million (2012 - $1,140 million and US$350 million).
Primarily debt discount.
10 Weighted average interest rate - 1.1% (2012 - 1.1%).
For the years ending December 31, 2014 through 2018, debenture and term note maturities
are $1,330 million, $931 million, $1,393 million, $952 million, $960 million, respectively, and
$13,562 million thereafter. The Company’s debentures and term notes bear interest at fixed rates
and interest obligations for the years ending December 31, 2014 through 2018 are $1,138 million,
$1,088 million, $1,063 million, $988 million and $851 million, respectively. At December 31, 2013 and
2012, all debt is unsecured except for the Southern Lights project financing which is collateralized
by the Southern Lights project assets of approximately $2,680 million (2012 - $2,565 million).
150 Enbridge Inc. 2013 Annual Report
Interest Expense
Year ended December 31,
(millions of Canadian dollars)
Debentures and term notes
Commercial paper and credit facility draws
Southern Lights project financing
Capitalized
Credit Facilities
(millions of Canadian dollars)
Liquids Pipelines
Gas Distribution
Sponsored Investments
Corporate
2013
2012
2011
1,123
34
40
(250)
947
986
33
38
(216)
841
891
74
38
(75)
928
December 31, 2013
December 31, 2012
Maturity
Dates2
Total
Facilities
Draws3
Available
Total Facilities
2015
2014 – 2019
2015 – 2018
2015 – 2018
300
713
4,781
11,805
17,599
1,570
19,169
266
382
809
3,651
5,108
1,498
6,606
34
331
3,972
8,154
12,491
72
12,563
300
712
3,162
9,108
13,282
1,484
14,766
Southern Lights project financing1
2014 – 2015
Total credit facilities
1
2
3
Total facilities inclusive of $63 million for debt service reserve letters of credit.
Total facilities include $35 million in demand facilities with no specified maturity date.
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
Credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and
draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial
paper programs and the Company has the option to extend the facilities, which are currently set to
mature from 2014 to 2018.
Commercial paper and credit facility draws, net of short-term borrowings, of $4,580 million (2012 -
$2,925 million) are supported by the availability of long-term committed credit facilities and therefore
have been classified as long-term debt.
18. Other Long-Term Liabilities
December 31,
(millions of Canadian dollars)
Future removal and site restoration liabilities (Note 6)
Derivative liabilities (Note 23)
Pension and OPEB liabilities (Note 25)
Other
2013
2012
929
1,395
264
350
882
763
573
323
2,938
2,541
Notes to the Consolidated Financial Statements
151
19. Noncontrolling Interests
December 31,
(millions of Canadian dollars)
EEP
Enbridge Energy Management, L.L.C. (EEM)
EGD preferred shares
Other
2013
2012
2,810
1,079
100
25
2,636
498
100
24
4,014
3,258
Noncontrolling interests in EEP represented the 79.4% (2012 - 78.2%) interest in EEP held by public
unitholders, as well as interests of third parties in subsidiaries of EEP, including Midcoast Energy
Partners, L.P. (MEP). The increase in noncontrolling interests in EEP included contributions of
$372 million (US$355 million) received from an initial public offering (IPO) of MEP. In May 2013, EEP
formed MEP, which at the time was EEP’s wholly owned subsidiary, and transferred approximately
39% of its ownership interest in EEP’s natural gas and NGL midstream business to MEP. In November
2013, MEP completed the IPO whereby a total of 21.3 million MEP’s Class A common units were issued
(including 2.8 million Class A common units issued pursuant to the exercise of the underwriters’ over-
allotment option in December 2013) representing approximately 46% limited partner interest in MEP.
During the year ended December 31, 2013, EEP also distributed $463 million (2012 - $419 million;
2011 - $353 million) to its noncontrolling interest holders in line with EEP’s objective to make quarterly
distributions in an amount equal to its available cash, as defined in its partnership agreement and as
approved by EEP’s Board of Directors.
During the year ended December 31, 2012, EEP completed a listed share issuance, in which the
Company did not participate, resulting in an increase in the noncontrolling interests from 77.0% to
78.2%. The listed share issuance during the year ended December 31, 2012 resulted in contributions
of $382 million (2011 - $695 million) from noncontrolling interest holders.
Noncontrolling interests in EEM represented the 88.3% (2012 - 83.2%) of the listed shares of EEM not
held by the Company. The increase in noncontrolling interests reflected the issuance of listed shares in
2013 in which the Company did not participate and which resulted in contributions of $523 million from
noncontrolling interest holders.
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 preferred shares have no fixed maturity date
and have floating adjustable cash dividends that are payable at 80% of the prime rate. EGD may, at is
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, 2013, no preferred shares have been redeemed.
Redeemable Noncontrolling Interests
Year ended December 31,
(millions of Canadian dollars)
Balance at beginning of year
Loss
Other comprehensive income/(loss)
Change in unrealized gains/(loss) on cash flow hedges, net of tax
Comprehensive loss
Distributions to unitholders
Contributions from unitholders
Redemption value adjustment
Balance at end of year
2013
2012
2011
1,000
(24)
4
(20)
(72)
92
53
640
(12)
(1)
(13)
(49)
225
197
1,053
1,000
362
(9)
(3)
(12)
(33)
170
153
640
152 Enbridge Inc. 2013 Annual Report
Redeemable noncontrolling interests in the Fund at December 31, 2013 represented 68.6%
(2012 - 67.7%; 2011 - 64.6%) of interests in the Fund’s trust units that are held by third parties. During the
year ended December 31, 2013, the Fund completed a unit issuance in which the Company did not
participate, resulting in an increase in the redeemable noncontrolling interests from 67.7% to 68.6%.
This resulted in contributions of $92 million from redeemable noncontrolling interest holders.
In December 2012, the Fund acquired Greenwich, Amherstburg and Tilbury solar energy projects,
Hardisty Caverns and Hardisty Contract Terminals from Enbridge and wholly-owned subsidiaries of
Enbridge for proceeds of $1.2 billion. In October 2011, the Fund acquired the Ontario Wind, Sarnia Solar
and Talbot Wind energy projects from a wholly-owned subsidiary of Enbridge for $1.2 billion. In both
cases, ordinary trust units were issued by the Fund to partially finance these acquisitions, resulting in
an increase in interests held by third parties in 2012 and 2011 and contributions from noncontrolling
unitholders of $225 million and $170 million, respectively.
Distributions to noncontrolling unitholders were made on a monthly basis for the years ended
December 31, 2013, 2012 and 2011 in line with the Fund’s objective of distributing a high proportion
of its cash available for distribution, as approved by its Board of Trustees.
20. Share Capital
The authorized share capital of the Company consists of an unlimited number of common shares with
no par value and an unlimited number of preference shares.
Common Shares
December 31,
2013
2012
2011
Number
of Shares
Amount
Number
of Shares
Amount
Number
of Shares
Amount
(millions of Canadian dollars; number of common shares in millions)
Balance at beginning of year
Common Shares issued1
Dividend Reinvestment and Share Purchase Plan (DRIP)
Shares issued on exercise of stock options
805
13
8
5
4,732
582
361
69
781
10
8
6
3,969
770
3,683
388
297
78
–
7
4
–
229
57
Balance at end of year
831
5,744
805
4,732
781
3,969
1
Gross proceeds - $600 million (2012 - $400 million); net issuance costs - $18 million (2012 - $12 million).
Preference Shares
December 31,
(millions of Canadian dollars; number of preference shares in millions)
2013
2012
2011
Number
of Shares
Amount
Number
of Shares
Amount
Number
of Shares
Amount
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J
Preference Shares, Series L
Preference Shares, Series N
Preference Shares, Series P
Preference Shares, Series R
Preference Shares, Series 1
Preference Shares, Series 3
Preference Shares, Series 5
Preference Shares, Series 7
Issuance costs
Balance at end of year
5
20
18
20
14
8
16
18
16
16
16
24
8
10
125
500
450
500
350
199
411
450
400
400
411
600
206
250
5
20
18
20
14
8
16
18
16
16
–
–
–
–
125
500
450
500
350
199
411
450
400
400
–
–
–
–
5
20
18
–
–
–
–
–
–
–
–
–
–
–
125
500
450
–
–
–
–
–
–
–
–
–
–
–
(111)
5,141
(78)
3,707
(19)
1,056
Notes to the Consolidated Financial Statements
153
Characteristics of the preference shares are as follows:
(Canadian dollars unless otherwise stated)
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J
Preference Shares, Series L
Preference Shares, Series N
Preference Shares, Series P
Preference Shares, Series R
Preference Shares, Series 1
Preference Shares, Series 3
Preference Shares, Series 5
Preference Shares, Series 75
Initial
Yield
Dividend1
Per Share Base2
Redemption2
Value2
Redemption and2,3
Conversion2,3
Option Date2,3
Right to3,4
Convert3,4
Into3,4
5.5%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
4.4%
4.4%
$1.375
$1.000
$1.000
$1.000
$1.000
US$1.000
US$1.000
$1.000
$1.000
$1.000
US$1.000
$1.000
US$1.100
$1.100
$25
$25
$25
$25
$25
US$25
US$25
$25
$25
$25
US$25
–
June 1, 2017
March 1, 2018
June 1, 2018
September 1, 2018
June 1, 2017
September 1, 2017
December 1, 2018
March 1, 2019
June 1, 2019
June 1, 2018
$25
September 1, 2019
US$25
$25
March 1, 2019
March 1, 2019
–
Series C
Series E
Series G
Series I
Series K
Series M
Series O
Series Q
Series S
Series 2
Series 4
Series 6
Series 8
1
2
The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company.
Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company may at its option, redeem
all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date
and on every fifth anniversary thereafter.
3
The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on the
Conversion Option Date and every fifth anniversary thereafter.
4 Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day
Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S),
2.4% (Series 4) or 2.6% (Series 8)); or US$25 x (number of days in quarter/365) x (three-month United States Government treasury bill rate + 3.1% (Series K),
3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6)).
5
A cash dividend of $0.2381 per share will be payable on March 1, 2014 to Series 7 preference shareholders. The regular quarterly dividend of $0.275 per share
will begin in the second quarter of 2014.
Earnings per Common Share
Earnings per common share is calculated by dividing earnings attributable 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 15 million (2012 - 20 million; 2011 - 25 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
2013
2012
2011
806
11
817
772
13
785
751
10
761
For the year ended December 31, 2013, 6,327,500 anti-dilutive stock options (2012 - 5,733,000; 2011 -
48,000) with a weighted average exercise price of $44.85 (2012 - $38.32; 2011 - $32.02) were excluded
from the diluted earnings per share calculation.
154 Enbridge Inc. 2013 Annual Report
Stock Split
Effective May 25, 2011, a two-for-one split of the common shares of the Company was completed.
All references to the number of shares outstanding, earnings per common share, diluted earnings
per common share, dividends per common share and outstanding option information have been
retroactively restated to reflect the impact of the stock split.
Dividend Reinvestment and Share Purchase Plan
Under the DRIP, 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 DRIP 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.
21. Stock Option and Stock Unit Plans
The Company maintains four long-term incentive compensation plans: the ISO Plan, the PBSO Plan, the
PSU Plan and the RSU Plan. A maximum of 60 million common shares were reserved for issuance under
the 2002 ISO plan, of which 47 million have been issued to date. A further 52 million common shares
have been reserved for issuance for the 2007 ISO and PBSO plans, of which seven million have been
exercised and issued from treasury 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 ISO to purchase common shares at the market price on the grant date.
ISO vest in equal annual installments over a four-year period and expire 10 years after the issue date.
December 31, 2013
(options in thousands; intrinsic value in millions of Canadian dollars)
Options outstanding at beginning of year
Options granted
Options exercised1
Options cancelled or expired
Options outstanding at end of year
Options vested at end of year2
Number
27,368
6,369
(3,948)
(187)
29,602
15,151
Weighted
Average
Exercise Price
Weighted
Average
Remaining
Contractual Life
(years)
Aggregate
Intrinsic Value
25.69
44.85
20.10
30.99
30.52
23.12
6.7
5.2
425
330
1
2
The total intrinsic value of ISO exercised during the year ended December 31, 2013 was $98 million (2012 - $130 million; 2011 - $68 million) and cash received on
exercise was $24 million (2012 - $69 million; 2011 - $56 million).
The total fair value of options vested under the ISO Plan during the year ended December 31, 2013 was $22 million (2012 - $19 million; 2011 - $17 million).
Notes to the Consolidated Financial Statements
155
Weighted average assumptions used to determine the fair value of ISO granted using the Black-
Scholes-Merton 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 volatility3
Expected dividend yield4
Risk-free interest rate5
2013
5.27
5
17.4%
2.8%
1.2%
2012
4.81
5
19.7%
3.0%
1.3%
2011
4.19
6
18.6%
3.4%
2.9%
1
Options granted to United States employees are based on New York Stock Exchange prices. The option value and assumptions shown are based on a weighted
average of the United States and the Canadian options. The fair values per option were $5.15 (2012 - $4.65; 2011 - $4.01) for Canadian employees and US$5.63
(2012 - US$5.58; 2011 - US$5.11) 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 and consideration of the implied volatility observable in call option
values near the grant date.
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 United States Treasury Bond Yields.
2
3
4
5
Compensation expense recorded for the year ended December 31, 2013 for ISO was $27 million
(2012 - $23 million; 2011 - $16 million). At December 31, 2013, unrecognized compensation cost
related to non-vested stock-based compensation arrangements granted under the ISO Plan was
$37 million. The cost is expected to be fully recognized over a weighted average period of
approximately three years.
Performance Based Stock Options
PBSO are granted to executive officers and become exercisable when both performance targets and
time vesting requirements have been met. PBSO were granted on August 15, 2007, February 19, 2008 and
August 15, 2012 under the 2007 plan. All performance targets for the 2007 and 2008 grants have been
met. The time vesting requirements were fulfilled evenly over a five-year period ending on August 15, 2012
with the options being exercisable until August 15, 2015. Time vesting requirements for the 2012 grant will
be fulfilled evenly over a five-year term, ending August 15, 2017. The 2012 grant’s performance targets
are based on the Company’s share price and must be met by February 15, 2019 or the options expire.
If targets are met by February 15, 2019, the options are exercisable until August 15, 2020.
December 31, 2013
(options in thousands; intrinsic value in millions of Canadian dollars)
Options outstanding at beginning of year
Options exercised1
Options outstanding at end of year
Options vested at end of year2
Number
6,704
(2,331)
4,373
830
Weighted
Average
Exercise Price
Weighted
Average
Remaining
Contractual Life
(years)
Aggregate
Intrinsic Value
29.56
18.29
35.56
19.44
5.7
1.6
41
21
1
2
The total intrinsic value of PBSO exercised during the year ended December 31, 2013 was $62 million (2012 - $20 million; 2011 - $2 million) and cash received on
exercise was $28 million (2012 - $12 million; 2011 - $3 million).
The total fair value of options vested under the PBSO Plan during the year ended December 31, 2013 was nil (2012 - $1 million; 2011 - $2 million).
156 Enbridge Inc. 2013 Annual Report
2012
4.25
8
16.1%
2.8%
1.6%
Assumptions used to determine the fair value of PBSO granted 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 volatility2
Expected dividend yield3
Risk-free interest rate4
1
2
3
4
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.
Compensation expense recorded for the year ended December 31, 2013 for PBSO was $3 million
(2012 - $2 million; 2011 - $2 million). At December 31, 2013, unrecognized compensation cost related
to non-vested stock-based compensation arrangements granted under the PBSO Plan was $11 million.
The cost is expected to be fully recognized over a weighted average period of approximately four years.
Performance Stock Units
The Company has a PSU Plan for executives 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 for 20 days prior to the
maturity of the grant 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 2011, 2012 and 2013 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 earnings per share, adjusted for unusual,
non-operating or non-recurring items, relative to targets established at the time of grant. To calculate
the 2013 expense, multipliers of two, based upon multiplier estimates at December 31, 2013, were used
for each of the 2011, 2012 and 2013 PSU grants.
December 31, 2013
(Units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year
Units granted
Units matured1
Dividend reinvestment
Units outstanding at end of year
Weighted
Average
Remaining
Contractual Life
(years)
Aggregate
Intrinsic Value
1.5
54
Number
652
259
(346)
26
591
1
The total amount paid during the year ended December 31, 2013 for PSU was $48 million (2012 - $25 million; 2011 - $17 million).
Compensation expense recorded for the year ended December 31, 2013 for PSU was $25 million
(2012 - $49 million; 2011 - $42 million). As at December 31, 2013, unrecognized compensation expense
related to non-vested units granted under the PSU Plan was $26 million and is expected to be fully
recognized over a weighted average period of approximately two years.
Notes to the Consolidated Financial Statements
157
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 for 20 days prior to the maturity of the grant multiplied by the units
outstanding on the maturity date.
December 31, 2013
(Units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year
Units granted
Units cancelled
Units matured1
Dividend reinvestment
Units outstanding at end of year
Weighted
Average
Remaining
Contractual Life
(years)
Aggregate
Intrinsic Value
1.5
84
Number
1,819
920
(36)
(953)
78
1,828
1
The total amount paid during the year ended December 31, 2013 for RSU was $41 million (2012 - $37 million; 2011 - $39 million).
Compensation expense recorded for the year ended December 31, 2013 for RSU was $36 million
(2012 - $32 million; 2011 - $31 million). As at December 31, 2013, unrecognized compensation expense
related to non-vested units granted under the RSU Plan was $46 million and is expected to be fully
recognized over a weighted average period of approximately two years.
22. Components of Accumulated Other Comprehensive Loss
Changes in AOCI attributable to Enbridge common shareholders for the years ended December 31, 2013,
2012 and 2011, are as follows:
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and OPEB
Total
(621)
474
(1,265)
707
(111)
487
134
(1)
(8)
–
832
(176)
(36)
(212)
(1)
–
–
–
–
–
–
–
–
(111)
487
15
–
15
378
–
–
–
(26)
11
–
–
–
–
11
–
–
–
(324)
(1,762)
165
1,259
–
–
–
36
201
(51)
(9)
(60)
(183)
134
(1)
(8)
36
1,420
(212)
(45)
(257)
(599)
(778)
(15)
(millions of Canadian dollars)
Balance at January 1, 2013
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive (income)/loss
reclassified to earnings
Interest rate contracts1
Commodity contracts2
Foreign exchange contracts3
Amortization of pension and OPEB
actuarial loss and prior service costs5
Tax impact
Income tax on amounts retained in AOCI
Income tax on amounts reclassified
to earnings
Balance at December 31, 2013
158 Enbridge Inc. 2013 Annual Report
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and OPEB
Total
(1,167)
(28)
(286)
(1,496)
(millions of Canadian dollars)
Balance at January 1, 2012
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive (income)/loss
reclassified to earnings
Interest rate contracts1
Commodity contracts2
Foreign exchange contracts3
Other contracts4
Amortization of pension and OPEB
actuarial loss and prior service costs5
Tax impact
Income tax on amounts retained in AOCI
Income tax on amounts reclassified
to earnings
(476)
(172)
(17)
(4)
1
2
–
(190)
36
9
45
461
16
–
–
–
–
–
16
(3)
–
(3)
Balance at December 31, 2012
(621)
474
(1,265)
(millions of Canadian dollars)
Balance at January 1, 2011
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive (income)/loss
reclassified to earnings
Interest rate contracts1
Commodity contracts2
Foreign exchange contracts3
Other contracts4
Amortization of pension and OPEB
actuarial loss and prior service costs5
Tax impact
Income tax on amounts retained in AOCI
Income tax on amounts reclassified
to earnings
Balance at December 31, 2011
51
43
1
(2)
–
(563)
161
(8)
153
(476)
–
–
–
–
–
(21)
2
–
2
(98)
–
–
–
–
–
(98)
–
–
–
78
–
–
–
–
–
78
–
–
–
7
–
–
–
–
–
7
(5)
–
(5)
(26)
(75)
(322)
–
–
–
–
23
(52)
19
(5)
14
(17)
(4)
1
2
23
(317)
47
4
51
(324)
(1,762)
(11)
(20)
–
–
–
–
–
(20)
3
–
3
(142)
(984)
(229)
(848)
–
–
–
–
29
(200)
64
(8)
56
51
43
1
(2)
29
(726)
230
(16)
214
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and OPEB
Total
(66)
480
(1,245)
(656)
(21)
461
(1,167)
(28)
(286)
(1,496)
1
2
3
4
5
Reported within Interest expense in the Consolidated Statements of Earnings.
Reported within Commodity costs in the Consolidated Statements of Earnings.
Reported within Other income/(expense) in the Consolidated Statements of Earnings.
Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
These components are included in the computation of net periodic pension costs and are reported within
Operating and administrative expense in the Consolidated Statements of Earnings.
Notes to the Consolidated Financial Statements
159
23. Risk Management and
Financial Instruments
variability on select forecast term debt issuances through
2018. A total of $10,419 million of future fixed rate term debt
issuances have been hedged at an average swap rate of 3.8%.
Market Price Risk
The Company’s earnings, cash flows and OCI are subject
to movements in foreign exchange rates, interest rates,
commodity prices and the Company’s share price
(collectively, market price risk). Formal risk management
policies, processes and systems have been designed to
mitigate these risks.
The following summarizes the types of market price risks to
which the Company is exposed and the risk management
instruments used to mitigate them. The Company uses a
combination of qualifying and non-qualifying derivative
instruments to manage the risks noted below.
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 investments and
subsidiaries, and certain revenues denominated in United
States dollars and certain expenses denominated in Euros.
The Company has implemented a policy where it
economically hedges a minimum level of foreign currency
denominated earnings exposures identified over a five-
year forecast horizon. 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 Company uses a combination
of qualifying and non-qualifying derivative instruments to
manage variability in cash flows arising from its United States
dollar investments and subsidiaries, and primarily non-
qualifying derivative instruments to manage variability arising
from certain revenues denominated in United States dollars.
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, primarily commercial paper. Pay fixed-
receive floating 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 impact of short-term interest rate volatility on
interest expense through 2017 through execution of floating
to fixed interest rate swaps with an average swap rate of 1.5%.
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 program to
significantly mitigate its exposure to long-term interest rate
The Company also monitors its debt portfolio mix of fixed
and variable rate debt instruments to maintain a consolidated
portfolio of debt which stays within its Board of Directors
approved policy limit of a maximum of 25% floating rate debt
as a percentage of total debt outstanding. The Company
uses primarily qualifying derivative instruments to manage
interest rate risk.
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 and investments, as well as through
the activities of its energy services subsidiaries. These
commodities include natural gas, crude oil, power and NGL.
The Company employs financial derivative instruments
to fix a portion of the variable price exposures that arise
from physical transactions involving these commodities.
The Company uses primarily non-qualifying derivative
instruments to manage commodity price risk.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to
changes in the Company’s share price. The Company has
exposure to its own common share price through the issuance
of various forms of stock-based compensation, which affect
earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to manage
the earnings volatility derived from one form of stock-based
compensation, restricted stock units. The Company uses
a combination of qualifying and non-qualifying derivative
instruments to manage equity price risk.
Total Derivative Instruments
The following table summarizes the Statements of Financial
Position location and carrying value of the Company’s
derivative instruments. The Company did not have any
outstanding fair value hedges at December 31, 2013 or 2012.
The Company generally has a policy of entering into individual
International Swaps and Derivatives Association, Inc. (ISDA)
agreements, or other similar derivative agreements, with the
majority of its derivative counterparties. These agreements
provide for the net settlement of derivative instruments
outstanding with specific counterparties in the event of
bankruptcy or other significant credit event, and would
reduce the Company’s credit risk exposure on derivative
asset positions outstanding with the counterparties in these
particular circumstances. The following table also summarizes
the maximum potential settlement in the event of these
specific circumstances. All amounts are presented gross in
the Consolidated Statements of Financial Position.
160 Enbridge Inc. 2013 Annual Report
December 31, 2013
(millions of Canadian dollars)
Accounts receivable and other (Note 8)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Deferred amounts and other assets (Note 13)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Accounts payable and other (Note 16)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other long-term liabilities (Note 18)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net derivative asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as Net
Investment
Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as Presented
Amounts
Available
for Offset
Total Net
Derivative
Instruments
16
171
4
2
193
7
249
9
1
266
(2)
(387)
(14)
(403)
(4)
(68)
(2)
(74)
17
(35)
(3)
3
(18)
11
–
–
–
11
33
–
–
–
33
(4)
–
–
(4)
(31)
–
–
51
12
114
4
181
27
1
86
–
114
(69)
(16)
(345)
(430)
(435)
(1)
(854)
78
183
118
6
385
67
250
95
1
413
(75)
(403)
(359)
(837)
(470)
(69)
(856)
(31)
(1,290)
(1,395)
9
–
–
–
9
(426)
(4)
(999)
4
(400)
(39)
(1,002)
7
(1,425)
(1,434)
(26)
(27)
(64)
–
(117)
(62)
(47)
(67)
–
(176)
26
45
64
135
62
29
67
158
–
–
–
–
–
52
156
54
6
268
5
203
28
1
237
(49)
(358)
(295)
(702)
(408)
(40)
(789)
(1,237)
(400)
(39)
(1,002)
7
(1,434)
Notes to the Consolidated Financial Statements
161
December 31, 2012
(millions of Canadian dollars)
Accounts receivable and other (Note 8)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Deferred amounts and other assets (Note 13)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Accounts payable and other (Note 16)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other long-term liabilities (Note 18)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net derivative asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as Net
Investment
Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as Presented
Amounts
Available
for Offset
Total Net
Derivative
Instruments
4
7
9
3
23
11
18
1
2
32
(5)
(673)
(3)
(681)
(41)
(290)
(2)
(333)
(31)
(938)
5
5
(959)
16
–
–
–
16
79
–
–
–
79
–
–
–
–
(5)
–
–
(5)
90
–
–
–
90
210
9
119
6
344
225
12
59
1
297
(100)
–
(294)
(394)
(23)
(15)
(387)
(425)
312
6
(503)
7
(178)
230
16
128
9
383
315
30
60
3
408
(105)
(673)
(297)
(1,075)
(69)
(305)
(389)
(763)
371
(932)
(498)
12
(1,047)
(101)
(9)
(28)
–
(138)
(40)
(25)
(32)
–
(97)
101
9
28
138
40
25
32
97
–
–
–
–
–
129
7
100
9
245
275
5
28
3
311
(4)
(664)
(269)
(937)
(29)
(280)
(357)
(666)
371
(932)
(498)
12
(1,047)
The following table summarizes the maturity and notional principal or quantity outstanding related to
the Company’s derivative instruments.
December 31, 2013
2014
2015
2016
2017
2018
Thereafter
Foreign exchange contracts - United States dollar
forwards - purchase (millions of United States dollars)
Foreign exchange contracts - United States dollar
forwards - sell (millions of United States dollars)
Foreign exchange contracts - Euro forwards -
purchase (millions of Euros)
Interest rate contracts - short term borrowings
(millions of Canadian dollars)
Interest rate contracts - long term debt
(millions of Canadian dollars)
Equity contracts (millions of Canadian dollars)
Commodity contracts - natural gas (billions of cubic feet)
Commodity contracts - crude oil (millions of barrels)
Commodity contracts - NGL (millions of barrels)
Commodity contracts - power (megawatt hours (MWH))
710
25
25
413
2
4
2,795
2,751
2,323
2,557
1,649
3,771
5
28
–
–
5,007
5,210
5,030
3,965
5,736
1,779
1,814
1,090
40
17
(34)
(10)
55
41
(8)
(29)
(2)
5
–
10
(23)
–
20
–
11
(18)
–
40
–
274
–
–
46
(9)
–
30
–
267
–
–
–
–
–
8
162 Enbridge Inc. 2013 Annual Report
December 31, 2012
2013
2014
2015
2016
2017
Thereafter
Foreign exchange contracts - United States dollar
forwards - purchase (millions of United States dollars)
Foreign exchange contracts - United States dollar
forwards - sell (millions of United States dollars)
Foreign exchange contracts - Euro forwards -
purchase (millions of Euros)
Interest rate contracts - short term borrowings
(millions of Canadian dollars)
Interest rate contracts - long term debt
(millions of Canadian dollars)
Equity contracts (millions of Canadian dollars)
Commodity contracts - natural gas (billions of cubic feet)
Commodity contracts - crude oil (millions of barrels)
Commodity contracts - NGL (millions of barrels)
Commodity contracts - power (MWH)
558
468
25
25
413
2,088
2,402
2,751
2,323
2,557
6
–
–
–
–
3,644
3,591
3,455
3,157
2,841
4,590
3,055
1,760
1,142
39
55
37
1
51
36
19
38
2
67
–
10
29
–
48
–
10
23
–
63
–
–
11
18
–
83
6
158
–
171
–
–
3
9
–
66
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, before the effect of
income taxes.
Year ended December 31,
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Net investment hedges
Foreign exchange contracts
Amount of gains/(loss) reclassified from AOCI to earnings (effective portion)
Foreign exchange contracts1
Interest rate contracts2
Commodity contracts3
Other contracts4
Amount of gains/(loss) reclassified from AOCI to earnings (ineffective portion and amount
excluded from effectiveness testing)
Interest rate contracts2
Commodity contracts3
1
2
3
4
Reported within Other income/(expense) in the Consolidated Statements of Earnings.
Reported within Interest expense in the Consolidated Statements of Earnings.
Reported within Commodity costs in the Consolidated Statements of Earnings.
Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
2013
2012
2011
56
814
(9)
(2)
(81)
778
(8)
107
1
–
100
51
(3)
48
(12)
(46)
52
(3)
1
(8)
1
(1)
(3)
2
(1)
23
(3)
20
(22)
(724)
72
6
(26)
(694)
1
(10)
(55)
(2)
(66)
11
5
16
Notes to the Consolidated Financial Statements
163
The Company estimates that $135 million of AOCI 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 in effect 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 48 months at December 31, 2013.
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)
Foreign exchange contracts1
Interest rate contracts2
Commodity contracts3
Other contracts4
Total unrealized derivative fair value gains/(loss)
2013
2012
2011
(738)
(10)
(496)
(3)
(1,247)
120
(2)
(765)
(2)
(649)
(179)
9
280
4
114
1
2
3
Reported within Transportation and other services revenues (2013 - $352 million loss; 2012 - $150 million gain; 2011 - $77 million loss) and Other income/(expense)
(2013 - $386 million loss; 2012 - $30 million loss; 2011 - $102 million loss) in the Consolidated Statements of Earnings.
Reported within Interest expense in the Consolidated Statements of Earnings.
Reported within Transportation and other services revenues (2013 - $375 million loss; 2012 - $681 million loss; 2011 - $216 million gain), Commodity costs
(2013 - $35 million loss; 2012 - $21 million loss; 2011 - $61 million gain) and Operating and administrative expense (2013 - $86 million loss; 2012 - $63 million loss;
2011 - $3 million gain) in the Consolidated Statements of Earnings.
4
Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
Liquidity Risk
Liquidity risk is the risk the Company will not be able to meet its financial obligations, including
commitments and guarantees, as they become due. In order to manage this risk, the Company
forecasts cash requirements over a 12 month rolling time period 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
long-term debt, which includes debentures and medium-term notes. The Company maintains current
shelf prospectuses with 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 with a diversified group of banks
and institutions which, if necessary, enables the Company to fund all anticipated requirements for
approximately one year without accessing the capital markets. The Company is in compliance with all
the terms and conditions of its committed credit facilities at December 31, 2013. 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 (Note 17).
Credit Risk
Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from
the possibility that a counterparty will default on its contractual obligations. The Company enters into
risk management transactions primarily 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.
164 Enbridge Inc. 2013 Annual Report
The Company had group credit concentrations and maximum credit exposure, with respect to
derivative instruments, in the following counterparty segments:
December 31,
(millions of Canadian dollars)
Canadian financial institutions
United States financial institutions
European financial institutions
Other1
2013
2012
230
227
192
97
746
306
129
244
128
807
1
Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at December 31, 2013, the Company had provided letters of credit totalling $81 million in lieu of
providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements.
The Company held $18 million of cash collateral on derivative asset exposures at December 31, 2013
and held no cash collateral at December 31, 2012.
Gross derivative balances have been presented without the effects of collateral posted. Derivative
assets are adjusted for non-performance risk of the Company’s counterparties using their credit
default swap spread rates, and are reflected in the fair value. For derivative liabilities, the Company’s
non-performance risk is considered in the valuation.
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.
Within Gas Distribution, credit risk 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.
Fair Value Measurements
The Company’s financial assets and liabilities measured at fair value on a recurring basis include derivative
instruments. The Company also discloses the fair value of other financial instruments not measured at fair
value. The fair value of financial instruments reflects the Company’s best estimates of market value based
on generally accepted valuation techniques or models and are 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.
Notes to the Consolidated Financial Statements
165
Fair Value of Financial Instruments
Level 3
The Company categorizes its derivative instruments
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 derivatives 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 a derivative 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 derivatives used to mitigate the risk of
crude oil price fluctuations.
Level 2
Level 2 includes derivative valuations determined using
directly or indirectly observable inputs other than quoted
prices included within Level 1. Derivatives 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. Derivatives 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.
The Company has also categorized the fair value of its held
to maturity preferred share investment and long-term debt
as Level 2. The fair value of the Company’s held to maturity
preferred share investment is primarily based on the yield of
certain Government of Canada bonds. The fair value of the
Company’s long-term debt is based on quoted market prices
for instruments of similar yield, credit risk and tenor.
Level 3 includes derivative valuations based on inputs which
are less observable, unavailable or where the observable
data does not support a significant portion of the derivatives’
fair value. Generally, Level 3 derivatives 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
derivatives based on extrapolation of observable future
prices and rates. Derivatives valued using Level 3 inputs
primarily include long-dated derivative power contracts and
NGL and natural gas contracts, basis swaps, commodity
swaps, power and energy swaps, as well as options.
The Company does not have any other financial instruments
categorized in Level 3.
The Company uses the most observable inputs available
to estimate the fair value of its derivatives. When possible,
the Company estimates the fair value of its derivatives
based on quoted market prices. If quoted market prices
are not available, the Company uses estimates from
third party brokers. For non-exchange traded derivatives
classified in Levels 2 and 3, the Company uses standard
valuation techniques to calculate the estimated fair value.
These methods include discounted cash flows for forwards
and swaps and Black-Scholes-Merton pricing models for
options. Depending on the type of derivative and nature of the
underlying risk, the Company uses observable market prices
(interest, foreign exchange, commodity and share price) and
volatility as primary inputs to these valuation techniques.
Finally, the Company considers its own credit default swap
spread as well as the credit default swap spreads associated
with its counterparties in its estimation of fair value.
166 Enbridge Inc. 2013 Annual Report
Fair Value of Derivatives
The Company has categorized its derivative assets and liabilities measured at fair value as follows:
December 31, 2013
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Long-term derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Long-term derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net financial asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments
–
–
6
–
6
–
–
–
–
–
–
–
(9)
(9)
–
–
–
–
–
–
(3)
–
(3)
78
183
42
6
309
67
250
72
1
390
(75)
(403)
(248)
(726)
(470)
(69)
(701)
(1,240)
(400)
(39)
(835)
7
(1,267)
–
–
70
–
70
–
–
23
–
23
–
–
(102)
(102)
–
–
(155)
(155)
–
–
(164)
–
(164)
78
183
118
6
385
67
250
95
1
413
(75)
(403)
(359)
(837)
(470)
(69)
(856)
(1,395)
(400)
(39)
(1,002)
7
(1,434)
Notes to the Consolidated Financial Statements
167
December 31, 2012
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Long-term derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Long-term derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net financial asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments
–
–
3
–
3
–
–
–
–
–
–
–
(9)
(9)
–
–
–
–
–
–
(6)
–
(6)
230
16
7
9
262
315
30
51
3
399
(105)
(673)
(212)
(990)
(69)
(305)
(314)
(688)
371
(932)
(468)
12
(1,017)
–
–
118
–
118
–
–
9
–
9
–
–
(76)
(76)
–
–
(75)
(75)
–
–
(24)
–
(24)
230
16
128
9
383
315
30
60
3
408
(105)
(673)
(297)
(1,075)
(69)
(305)
(389)
(763)
371
(932)
(498)
12
(1,047)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative
instruments were as follows:
December 31, 2013
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas
Crude
NGL
Power
Commodity contracts - physical1
Natural gas
Crude
NGL
Power
Commodity options2
Natural gas
NGL
Fair
Value
Unobservable Input
Minimum
Price
Maximum
Price
Weighted
Average
Price
4
1
(8)
Forward gas price
Forward crude price
Forward NGL price
(141)
Forward power price
(22)
(10)
4
(1)
2
7
(164)
Forward gas price
Forward crude price
Forward NGL price
Forward power price
Option volatility
Option volatility
3.64
67.52
1.00
43.50
3.36
64.73
0.02
32.40
25%
22%
5.18
103.86
2.26
67.67
5.29
113.19
2.68
38.98
31%
44%
4.37
$/mmbtu3
72.84
1.53
57.62
$/barrel
$/gallon
$/MWH
4.18
$/mmbtu3
$/barrel
$/gallon
$/MWH
92.15
1.59
35.07
28%
31%
1
Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2 Commodity options contracts are valued using an option model valuation technique.
3 One million British thermal units (mmbtu).
168 Enbridge Inc. 2013 Annual Report
If adjusted, the significant unobservable inputs disclosed in the previous table would have a direct
impact on the fair value of the Company’s Level 3 derivative instruments. The significant unobservable
inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity
prices and, for option contracts, price volatility. Changes in forward commodity prices could result
in significantly different fair values for the Company’s Level 3 derivatives. Changes in price volatility
would change the value of the option contracts. Generally speaking, a change in the estimate of
forward commodity prices is unrelated to a change in the estimate of price volatility.
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/(liability) at beginning of period
Total gains/(loss)
Included in earnings1
Included in OCI
Settlements
Level 3 net derivative liability at end of period
2013
2012
(24)
(100)
–
(40)
(164)
32
(69)
13
–
(24)
1
Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
The Company’s policy is to recognize transfers as of the last day of the reporting period. There were no
transfers between levels as at December 31, 2013 or 2012.
Fair Value of Other Financial Instruments
The Company recognizes equity investments in other entities not categorized as held to maturity at
fair value, with changes in fair value recorded in OCI, unless actively quoted prices are not available for
fair value measurement in which case these investments are recorded at cost. The carrying value of all
equity investments recognized at cost totalled $103 million at December 31, 2013 (2012 - $66 million).
The Company has a held to maturity preferred share investment carried at its amortized cost of
$287 million at December 31, 2013 (2012 - $246 million). These preferred shares are entitled to a
cumulative preferred dividend based on the average yield of Government of Canada bonds maturing
in greater than 10 years plus a range of 4.3% to 4.4%. At December 31, 2013, the fair value of this
preferred share investment approximates its face value of $580 million (2012 - $580 million).
At December 31, 2013, the Company’s long-term debt had a carrying value of $25,168 million
(2012 - $20,855 million) and a fair value of $27,469 million (2012 - $24,809 million).
Notes to the Consolidated Financial Statements
169
24. Income Taxes
Income Tax Rate Reconciliation
Year ended December 31,
(millions of Canadian dollars)
Earnings before income taxes, discontinued operations and extraordinary loss
Canadian federal statutory income tax rate
Expected federal taxes at statutory rate
Increase/(decrease) resulting from:
Provincial and state income taxes
Foreign and other statutory rate differentials1
Effects of rate-regulated accounting
Foreign allowable interest deductions
Part VI.1 tax, net of federal Part I deduction2
Intercompany sale of investment3
Noncontrolling interests
Other4
Income taxes on earnings before discontinued operations and extraordinary loss
Effective income tax rate
2013
2012
2011
613
15%
92
(1)
45
(55)
(39)
23
–
26
32
123
20.0%
1,186
15%
178
2,012
16.5%
332
97
(69)
(38)
(24)
19
33
(32)
7
171
126
130
(15)
(19)
1
59
(62)
(29)
523
14.4%
26.0%
1
2
3
The effective income tax rate for 2012 reflected significant losses relating to certain risk management activities in the Company’s United States operations and the
higher United States federal statutory rate over the Canadian federal statutory rate. The losses did not persist to the same extent in 2013.
Represents Part VI.1 tax on preference share dividend distributions, net of an allowed federal deduction. For 2013, this tax was presented net of an $11 million
federal tax recovery related to changes to tax law enacted during the year.
In December 2012 and October 2011, Enbridge and certain wholly-owned subsidiaries of Enbridge sold certain assets to the Fund. As these transactions occurred
between entities under common control of the Company, the intercompany gains realized as a result of these transfers were eliminated, although tax expense of
$56 million and $98 million remained as a charge to earnings in 2012 and 2011, respectively, of which the federal tax component was $33 million and $59 million.
The Company retains the benefit of cash taxes paid in the form of increased tax basis of its investment in the underlying entities; however, accounting recognition
of such benefit is not permitted until such time as the entities are sold outside of the consolidated group.
4 Other for 2013 includes $55 million related to the federal component of the tax effect of adjustments related to prior periods.
Comparative figures within the income tax reconciliation for 2012 and 2011 have been revised to
conform to the presentation followed for the current year. In 2013, a preferable presentation format
was adopted which calculates expected taxes using a federal statutory rate as opposed to a combined
federal and provincial rate. This format is preferable as it is more commonly used by companies
following U.S. GAAP.
Components of Pretax Earnings and Income Taxes
Year ended December 31,
(millions of Canadian dollars)
Earnings before income taxes, discontinued operations and extraordinary loss
Canada
United States
Other
Current income taxes
Canada
United States
Other
Deferred income taxes
Canada
United States
Income taxes on earnings before discontinued operations and extraordinary loss
170 Enbridge Inc. 2013 Annual Report
2013
2012
2011
193
132
288
613
(30)
18
4
(8)
31
100
131
123
1,037
(58)
207
1,186
130
35
3
168
160
(157)
3
171
683
1,196
133
2,012
194
(30)
(6)
158
30
335
365
523
Components of Deferred Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences of differences
between carrying amounts of assets and liabilities and their respective tax bases. Major components
of deferred income tax assets and liabilities are:
December 31,
(millions of Canadian dollars)
Deferred income tax liabilities
Property, plant and equipment
Investments
Regulatory assets
Other
Total deferred income tax liabilities
Deferred income tax assets
Financial instruments
Pension and OPEB plans
Loss carryforwards
Other
Total deferred income tax assets
Less valuation allowance
Total deferred income tax assets, net
Net deferred income tax liabilities
Presented as follows:
Assets
Accounts receivable and other (Note 8)
Deferred income taxes
Total deferred income tax assets
Liabilities
Deferred income taxes
Total deferred income tax liabilities
Net deferred income tax liabilities
2013
2012
(1,984)
(1,226)
(248)
(115)
(1,289)
(1,397)
(221)
(144)
(3,573)
(3,051)
487
128
129
68
812
(28)
784
380
180
161
51
772
(27)
745
(2,789)
(2,306)
120
16
136
(2,925)
(2,925)
(2,789)
167
10
177
(2,483)
(2,483)
(2,306)
Valuation allowances have been established for certain loss and credit carryforwards that reduce
deferred income tax assets to an amount that will more likely than not be realized.
As at December 31, 2013, the Company recognized the benefit of unused tax loss carryforwards of
$322 million (2012 - $183 million) in Canada which start to expire in 2029 and beyond.
As at December 31, 2013, the Company recognized the benefit of unused tax loss carryforwards
of $34 million (2012 - $222 million) in the United States which expire in 2032.
The Company has not provided for deferred income taxes on $573 million (2012 - $548 million) of
foreign subsidiaries’ undistributed earnings as at December 31, 2013 as such earnings are intended to
be indefinitely reinvested in the operations of these foreign subsidiaries. Upon distribution of these
earnings in the form of dividends or otherwise, the Company would be subject to income taxes in the
United States. It is not practicable to determine the income tax liability that might be incurred if these
earnings were to be distributed.
The Company and one or more of its subsidiaries are subject to taxation in Canada, the United States
and other foreign jurisdictions. The material jurisdictions in which the Company is subject to potential
examinations include the United States (federal and Texas) and Canada (federal, Alberta, Ontario and
Quebec). The Company’s 2006 and 2008 to 2013 taxation years are still open for audit in Canadian
jurisdictions, whereas 2009 to 2013 taxation years are open for audit in United States jurisdictions.
The Company is not currently under examination for income tax matters in any jurisdiction where it
is subject to income tax.
Notes to the Consolidated Financial Statements
171
Unrecognized Tax Benefits
Year ended December 31,
(millions of Canadian dollars)
Unrecognized tax benefits at beginning of year
Gross increases for tax positions of current year
Gross increases/(decreases) for tax positions of prior years
Reduction for lapse of statute of limitations
Unrecognized tax benefits at end of year
2013
2012
54
10
(14)
(4)
46
18
38
3
(5)
54
The unrecognized tax benefits as at December 31, 2013, if recognized, would affect the Company’s
effective income tax rate. The gross increases for tax positions taken in the current year are in respect
of the computation of Texas Margin Tax. The gross decreases for tax positions of prior years largely
relates to filing positions that were based on substantively enacted legislation pertaining to Part VI.1 tax
that became enacted in the second quarter of 2013.
The Company recognizes accrued interest and penalties related to unrecognized tax benefits as a
component of Income taxes. Income tax expense for the year ended December 31, 2013 included
a $5 million recovery (2012 - $1 million expense; 2011 - $1 million expense) of interest and penalties.
The recovery of interest and penalties is substantially attributed to interest that was previously accrued
on a filing position that is now statute-barred. As at December 31, 2013, interest and penalties of
$5 million (2012 - $10 million) have been accrued.
25. Retirement and Postretirement Benefits
Pension Plans
The Company has three registered pension plans which provide either defined benefit or defined
contribution pension benefits, or both, to employees of the Company. 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.
A measurement date of December 31, 2013 was used to determine the plan assets and accrued benefit
obligation for the Canadian and United States plans.
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.
In 2013, the mortality assumptions were revised for the Canadian Plans resulting in an increase
to pension liabilities of $58 million. 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
Liquids Pipelines
Gas Distribution
United States Plan
Effective Date of Most Recently
Filed Actuarial Valuation
Effective Date of Next
Required Actuarial Valuation
December 31, 2012
September 1, 2013
January 1, 2013
December 31, 2013
September 1, 2016
January 1, 2014
172 Enbridge Inc. 2013 Annual Report
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.
Other Postretirement Benefits
OPEB primarily includes supplemental health and dental, health spending account and life insurance
coverage for qualifying retired employees.
Benefit Obligations and Funded Status
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
Employees’ contributions
Actuarial (gains)/loss
Benefits paid
Effect of foreign exchange rate changes
Other
Benefit obligation at end of year
Change in plan assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer's contributions
Employees' contributions
Benefits paid
Effect of foreign exchange rate changes
Other
Fair value of plan assets at end of year1
Underfunded status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities (Note 18)
Pension
OPEB
2013
2012
2013
2012
1,879
1,686
103
79
–
(110)
(75)
19
8
84
74
–
106
(64)
(5)
(2)
1,903
1,879
1,500
1,355
200
155
–
(75)
13
6
117
97
–
(64)
(3)
(2)
1,799
(104)
1,500
(379)
6
–
(110)
(104)
–
–
(379)
(379)
261
9
11
1
(40)
(7)
6
(1)
240
62
8
12
1
(7)
5
–
81
243
8
10
1
14
(8)
(2)
(5)
261
54
5
13
1
(8)
(1)
(2)
62
(159)
(199)
–
(5)
(154)
(159)
–
(5)
(194)
(199)
1
Assets of $27 million (2012 - $19 million) are held by the Company in trust accounts that back non-registered supplemental pension plans benefitting United States
plan participants. Due to United States tax regulations, these assets are not restricted from creditors and therefore the Company is unable to include these balances
in plan assets for accounting purposes. However, these assets are committed for the future settlement of non-registered supplemental pension plan obligations
included in the underfunded status as at the end of the year.
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
Pension
2012
4.2%
3.7%
2013
5.0%
3.7%
2011
4.5%
3.5%
OPEB
2013
4.9%
2012
4.0%
2011
4.4%
Notes to the Consolidated Financial Statements
173
Net Benefit Costs Recognized
Year ended December 31,
(millions of Canadian dollars)
Benefits earned during the year
Interest cost on projected benefit obligations
Expected return on plan assets
Amortization of prior service costs
Amortization of actuarial loss
Net defined benefit costs on an accrual basis
Defined contribution benefit costs
Net benefit cost recognized in the Consolidated
Statements of Earnings
Amount recognized in OCI:
Net actuarial (gains)/loss1
Net prior service cost/(credit)2
Total amount recognized in OCI
Total amount recognized in Comprehensive income
Pension
OPEB
2013
2012
2011
2013
2012
2011
103
79
(103)
1
52
132
4
136
(158)
–
(158)
(22)
84
74
(93)
2
51
118
4
122
42
–
42
164
61
73
(92)
2
25
69
4
73
172
–
172
245
9
11
(4)
–
2
18
–
18
(45)
2
(43)
(25)
8
10
(3)
–
2
17
–
17
10
–
10
27
6
11
(3)
1
1
16
–
16
29
(1)
28
44
1
2
Unamortized actuarial losses included in AOCI, before tax, were $246 million (2012 - $388 million) relating to the pension plans and $11 million (2012 - $60 million)
relating to OPEB at December 31, 2013.
Unamortized prior service costs included in AOCI, before tax, were $6 million (2012 - $4 million) relating to OPEB at December 31, 2013.
The Company estimates that approximately $12 million related to pension plans and $1 million related
to OPEB at December 31, 2013 will be reclassified from AOCI into earnings in the next 12 months.
Regulatory adjustments are recorded in the Consolidated Statements of Earnings, the Consolidated
Statements of Comprehensive Income and the Consolidated Statements of Financial Position to reflect
the difference between pension expense for accounting purposes and pension expense for ratemaking
purposes. Offsetting regulatory assets or liabilities are recorded to the extent pension or OPEB costs
or gains are expected to be collected from or refunded to customers in future rates (Note 6). For the
year ended December 31, 2013, an offsetting regulatory asset of $3 million (2012 - $22 million) has
been recorded to the extent pension and OPEB costs are expected to be collected from customers in
future rates.
The weighted average assumptions made in the measurement of the cost of the pension plans and
OPEB are as follows:
Year ended December 31,
Discount rate
Average rate of return on pension plan assets
Average rate of salary increases
Pension
2012
4.5%
7.1%
3.5%
2013
4.2%
6.7%
3.7%
2011
5.6%
7.3%
3.5%
OPEB
2012
4.4%
6.0%
2013
4.0%
6.0%
2011
5.6%
6.0%
174 Enbridge Inc. 2013 Annual Report
Medical Cost Trends
The assumed rates for the next year used to measure the expected cost of benefits are as follows:
Canadian Plans
Drugs
Other Medical
United States Plan
Medical Cost Trend
Rate Assumption for
Next Fiscal Year
Ultimate Medical
Cost Trend Rate
Assumption
Year in which Ultimate
Medical Cost Trend Rate
Assumption is Achieved
8.3%
4.5%
7.4%
4.5%
–
4.5%
2029
–
2030
A 1% increase in the assumed medical care trend rate would result in an increase of $30 million in
the benefit obligation and an increase of $2 million in benefit and interest costs. A 1% decrease in the
assumed medical care trend rate would result in a decrease of $25 million in the benefit obligation and
a decrease of $2 million in benefit and interest costs.
Plan Assets
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.
Expected Rate of Return on Plan Assets
Year ended December 31,
Canadian Plans
United States Plans
Target Mix for Plan Assets
Equity securities
Fixed income securities
Other
Pension
OPEB
2013
6.6%
7.2%
2012
6.9%
7.3%
2013
2012
6.0%
6.0%
Canadian Plans
Liquids Pipelines Plan
Gas Distribution Plan
United States Plan
62.5%
30.0%
7.5%
53.5%
40.0%
6.5%
62.5%
30.0%
7.5%
Major Categories of Plan Assets
Plan assets are invested primarily in readily marketable investments with constraints on the credit
quality of fixed income securities. As at December 31, 2013, the pension assets were invested 58.0%
(2012 - 59.1%) in equity securities, 31.0% (2012 - 32.4%) in fixed income securities and 11.0% (2012 - 8.5%)
in other. The OPEB assets were invested 59.3% (2012 - 58.1%) in equity securities, 38.3% (2012 - 35.5%)
in fixed income securities and 2.4% (2012 - 6.4%) in other.
The following table summarizes the Company’s pension financial instruments at fair value. Non-financial
instruments with a carrying value of $1 million asset (2012 - $15 million liability) and refundable tax assets
of $85 million (2012 - $76 million) have been excluded from the table below.
Notes to the Consolidated Financial Statements
175
December 31,
(millions of Canadian dollars)
Pension
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
United States equity securities
Global equity securities
Canadian equity funds
United States equity funds
Global equity funds
Infrastructure4
Real estate5
Forward currency contracts
OPEB
Cash and cash equivalents
Fixed income securities
United States government and
government agency bonds
Equity
United States equity funds
Global equity funds
2013
2012
Level 11 Level 22 Level 33
Total
Level 11 Level 22 Level 33
Total
42
99
3
216
167
69
128
32
11
216
152
310
–
–
–
2
31
24
24
–
–
4
–
–
–
–
–
–
–
33
111
–
–
(6)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
50
76
–
–
–
–
–
42
44
99
7
216
167
69
128
32
11
216
185
421
50
76
(6)
2
31
24
24
87
–
196
152
45
190
24
9
64
60
255
–
–
–
4
22
17
–
–
–
4
–
–
2
–
–
–
39
26
159
–
–
(2)
–
–
19
–
–
–
–
–
–
–
–
–
–
–
–
–
61
24
–
–
–
–
–
44
87
4
196
152
47
190
24
9
103
86
414
61
24
(2)
4
22
36
–
1
2
3
4
5
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 the investments in Bentall Kennedy Prime Canadian Property Fund Ltd and AEW Core Property Trust are established through the use of valuation models.
Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were
as follows:
December 31,
(millions of Canadian dollars)
Balance at beginning of year
Unrealized and realized gains
Purchases and settlements, net
Balance at end of year
Plan Contributions by the Company
Year ended December 31,
(millions of Canadian dollars)
Total contributions
Contributions expected to be paid in 2014
176 Enbridge Inc. 2013 Annual Report
2013
2012
85
7
34
126
68
11
6
85
Pension
OPEB
2013
2012
2013
2012
155
152
97
12
11
13
Benefits Expected to be Paid by the Company
Year ended December 31,
(millions of Canadian dollars)
2014
2015
2016
2017
2018 2019 – 2023
Expected future benefit payments
80
85
90
95
101
591
26. Other Income/(Expense)
Year ended December 31,
(millions of Canadian dollars)
Net foreign currency gains/(loss)
Allowance for equity funds used during construction
Interest income on affiliate loans
Interest income
Noverco preferred shares dividend income
Gain on disposition (Note 7)
OPEB recovery (Note 6)
Other
2013
2012
2011
(272)
1
23
4
40
18
–
51
71
1
20
7
42
–
89
8
(135)
238
48
3
17
3
30
–
–
15
116
27. Changes in Operating Assets and Liabilities
Year ended December 31,
(millions of Canadian dollars)
Accounts receivable and other
Accounts receivable from affiliates
Inventory
Deferred amounts and other assets
Accounts payable and other
Accounts payable to affiliates
Interest payable
Other long-term liabilities
2013
2012
2011
(789)
(53)
(315)
(25)
832
46
25
(130)
(409)
(122)
43
42
(380)
(319)
(48)
15
109
(660)
121
(17)
93
(322)
421
41
7
57
401
28. Related Party Transactions
All related party transactions are provided in the normal course of business and, unless otherwise
noted, are measured at the exchange amount, which is the amount of consideration established and
agreed to by the related parties.
Vector, 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 were $6 million for the year
ended December 31, 2013 (2012 - $6 million; 2011 - $6 million).
Certain wholly-owned subsidiaries within Gas Distribution and Gas Pipelines, Processing and Energy
Services have transportation commitments with several joint venture affiliates that are accounted
for using the equity method. Total amounts charged for transportation services for the year ended
December 31, 2013 were $222 million (2012 - $127 million; 2011 - $106 million).
Additionally, certain wholly-owned subsidiaries within Gas Pipelines, Processing and Energy Services
made natural gas purchases of $99 million (2012 - $15 million; 2011 - nil) and sales of $10 million
(2012 - $7 million; 2011 - $5 million) with several joint venture affiliates during the year ended
December 31, 2013.
Notes to the Consolidated Financial Statements
177
Long-Term Note Receivable from Affiliate
Amounts receivable from affiliates include a series of loans
to Vector totalling $181 million (2012 - $178 million), included
in Deferred amounts and other assets, which require
quarterly interest payments at annual interest rates ranging
from 3% to 8%.
29. Commitments and
Contingencies
Commitments
The Company has signed contracts that primarily relate to
the purchase of services, pipe and other materials, as well as
transportation, totalling $10,232 million which are expected
to be paid within the next five years and $3,115 million in total
for years thereafter.
Minimum future payments under operating leases are
estimated at $817 million in aggregate. Estimated annual
lease payments for the years ending December 31, 2014
through 2018 are $116 million, $111 million, $108 million,
$98 million and $52 million, respectively, and $332 million
thereafter. Total rental expense for operating leases,
included in Operating and administrative expense, were
$49 million, $31 million and $28 million for the years ended
December 31, 2013, 2012 and 2011, respectively.
Environmental Liabilities
As at December 31, 2013, the Company had $260 million
(2012 - $107 million) included in current liabilities and
$27 million (2012 - $18 million) included in Other long-term
liabilities which have been accrued for costs incurred
primarily to address remediation of contaminated sites,
asbestos containing materials, management of hazardous
waste material disposal, outstanding air quality measures
for certain liquids and natural gas assets and known fines
or penalties.
Enbridge Energy Partners, L.P.
Enbridge holds an approximate 20.6% (2012 - 21.8%;
2011 - 23.0%) combined direct and indirect ownership
interest in EEP, which is consolidated with noncontrolling
interests within the Sponsored Investments segment.
Lakehead System Line 14 Crude Oil Release
On July 27, 2012, a release of crude oil was detected on Line
14 of EEP’s Lakehead System near Grand Marsh, Wisconsin.
The estimated volume of oil released was approximately
1,700 barrels. EEP received a Corrective Action Order
(CAO) from the Pipeline and Hazardous Materials Safety
Administration (PHMSA) on July 30, 2012, followed by an
amended CAO on August 1, 2012. Upon restart of Line 14 on
August 7, 2012, PHMSA restricted the operating pressure
to 80% of the pressure in place at the time immediately
prior to the incident. During the fourth quarter of 2013, EEP
received approval from the PHMSA to remove the pressure
restrictions and to return to normal operating pressures
for a period of 12 months. In December 2014, the PHMSA
will again consider the status of the pipeline in light of
information they acquire throughout 2014.
The total estimated cost for the Line 14 crude oil release
remains at approximately US$10 million ($1 million after-
tax attributable to Enbridge), inclusive of approximately
US$2 million of lost revenue and excluding any fines and
penalties. Despite the efforts EEP has made to ensure the
reasonableness of its estimate, changes to the estimated
amounts associated with this release are possible as more
reliable information becomes available. EEP will be pursuing
claims under Enbridge’s comprehensive insurance policy,
although it does not expect any recoveries to be significant.
Lakehead System Lines 6A and 6B Crude Oil Releases
Line 6B Crude Oil Release
On July 26, 2010, a release of crude oil on Line 6B of EEP’s
Lakehead System was reported near Marshall, Michigan.
EEP estimates that approximately 20,000 barrels of crude
oil were leaked at the site, a portion of which reached the
Talmadge Creek, a waterway that feeds the Kalamazoo
River. The released crude oil affected approximately 61
kilometres (38 miles) of shoreline along the Talmadge Creek
and Kalamazoo River waterways, including residential areas,
businesses, farmland and marshland between Marshall and
downstream of Battle Creek, Michigan. In response to the
release, a unified command structure was established under
the jurisdiction of the Environmental Protection Agency
(EPA), the Michigan Department of Natural Resources and
Environment and other federal, state and local agencies.
As at December 31, 2013, EEP’s total cost estimate for the
Line 6B crude oil release was US$1,122 million ($181 million
after-tax attributable to Enbridge) which is an increase of
US$302 million ($44 million after-tax attributable to Enbridge)
compared to the December 31, 2012 estimate. This total
estimate is before insurance recoveries and excludes
additional fines and penalties other than US$30 million
discussed below. On March 14, 2013, EEP received an order
from the EPA (the Order) which defined the scope requiring
additional containment and active recovery of submerged oil
relating to the Line 6B crude oil release. EEP submitted its initial
proposed work plan required by the EPA on April 4, 2013 and
resubmitted the work plan on April 23, 2013. The EPA approved
the Submerged Oil Recovery and Assessment (SORA) work
plan with modification on May 8, 2013. EEP incorporated
the modification and submitted an approved SORA on
May 13, 2013. The Order states the work must be completed by
December 31, 2013. EEP has currently completed substantially
178 Enbridge Inc. 2013 Annual Report
all of the SORA, with the exception of required dredging in
and around Morrow Lake and its delta. EEP is in the process
of working with the EPA to ensure this work is completed
as soon as reasonably possible, inclusive of obtaining the
necessary state and local permitting that is required and
considering weather conditions.
Transportation Safety Board publicly posted their final
report related to the Line 6A crude oil release that occurred
in Romeoville, Illinois, which states the probable cause of
the crude oil release was erosion caused by a leaking water
pipe resulting from an improperly installed third-party water
service line below EEP’s oil pipeline.
Of the US$302 million increase compared with
December 31, 2012 related to the Line 6B crude oil release,
US$280 million is primarily related to additional work
required by the Order including further refinement and
definition of the additional dredging scope per the Order
and all associated environmental, permitting, waste removal
and other related costs, as well as increased dredge activity
in and around Morrow Lake and the delta area. The actual
costs incurred may differ from the foregoing estimate as EEP
completes the work plan with the EPA related to the Order
and works with other regulatory agencies to assure its work
plan complies with their requirements. Any such incremental
costs will not be recovered under EEP’s insurance policies as
the costs for the incident at December 31, 2013 exceeded the
limits of the Company’s insurance coverage. The remaining
increase of US$22 million reflected an estimate of the minimum
amount of civil penalties EEP may be assessed under the
Clean Water Act of the United States (Clean Water Act) in
respect of the Line 6B crude oil release.
Expected losses associated with the Line 6B crude oil
release included those costs that were considered probable
and that could be reasonably estimated at December 31, 2013.
Despite the efforts EEP has made to ensure the reasonableness
of its estimates, there continues to be the potential for EEP
to incur additional costs in connection with this crude oil
release due to variations in any or all of the cost categories,
including modified or revised requirements from regulatory
agencies, in addition to fines and penalties and expenditures
associated with litigation and settlement of claims.
Line 6A Crude Oil Release
A release of crude oil from Line 6A of EEP’s Lakehead
System was reported in an industrial area of Romeoville,
Illinois on September 9, 2010. EEP estimates that
approximately 9,000 barrels of crude oil were released, of
which approximately 1,400 barrels were removed from the
pipeline as part of the repair. Some of the released crude
oil went onto a roadway, into a storm sewer, a waste water
treatment facility and then into a nearby retention pond.
All but a small amount of the crude oil was recovered.
EEP completed excavation and replacement of the pipeline
segment and returned it to service on September 17, 2010.
EEP continues to monitor the areas affected by the crude
oil release from Line 6A of its Lakehead System for any
additional requirements; however, the cleanup, remediation
and restoration of the areas affected by the release have
been completed. On October 21, 2013, the National
The total estimated cost for the Line 6A crude oil release
remains at approximately US$48 million ($7 million after-
tax attributable to Enbridge), before insurance recoveries
and excluding fines and penalties. These costs included
emergency response, environmental remediation and
cleanup activities with the crude oil release. EEP is pursuing
recovery of the costs associated with the Line 6A crude
oil release from third parties; however, there can be no
assurance that any such recovery will be obtained.
Insurance Recoveries
EEP is included in the comprehensive insurance program
that is maintained by Enbridge for its subsidiaries and
affiliates which renews throughout the year. On May 1 of
each year, EEP’s insurance program is up for renewal and
includes commercial liability insurance coverage that is
consistent with coverage considered customary for its
industry and includes coverage for environmental incidents
such as those incurred for the crude oil releases from Lines
6A and 6B, excluding costs for fines and penalties.
The claims for the crude oil release for Line 6B are covered
by Enbridge’s comprehensive insurance policy that
expired on April 30, 2011, which had an aggregate limit
of US$650 million for pollution liability. Based on EEP’s
remediation spending through December 31, 2013,
Enbridge and its affiliates have exceeded the limits of their
coverage under this insurance policy. Additionally, fines
and penalties would not be covered under the existing
insurance policy. For the years ended December 31, 2013
and 2012, EEP recognized US$42 million ($6 million after-tax
attributable to Enbridge) and US$170 million ($24 million
after-tax attributable to Enbridge), respectively, of insurance
recoveries as reductions to Environmental costs in the
Consolidated Statements of Earnings. As at December 31, 2013,
EEP has recorded total insurance recoveries of US$547 million
($80 million after-tax attributable to Enbridge) for the Line
6B crude oil release, out of the US$650 million aggregate
limit. EEP will record receivables for additional amounts it
claims for recovery pursuant to its insurance policies during
the period it deems recovery to be probable. In March 2013,
the Company filed a lawsuit against one insurer who is
disputing recovery eligibility for Line 6B costs. While the
Company believes outstanding claims are covered under
the policy, there can be no assurance that the Company
will prevail in this lawsuit.
Notes to the Consolidated Financial Statements
179
Effective May 1, 2013, Enbridge renewed its comprehensive
property and liability insurance programs, under which EEP
is insured through April 30, 2014, with a current liability
aggregate limit of US$685 million, including sudden and
accidental pollution liability. In the unlikely event multiple
insurable incidents occur which exceed coverage limits within
the same insurance period, the total insurance coverage will
be allocated among the Enbridge entities on an equitable
basis based on an insurance allocation agreement EEP has
entered into with Enbridge and another Enbridge subsidiary.
Legal and Regulatory Proceedings
A number of United States governmental agencies and
regulators have initiated investigations into the Lines 6A and
6B crude oil releases. Approximately 30 actions or claims are
pending against Enbridge, EEP or their affiliates in United States
federal and state courts in connection with the Line 6B crude
oil release, including direct actions and actions seeking class
status. Based on the current status of these cases, the Company
does not expect the outcome of these actions to be material.
As at December 31, 2013, included in EEP’s estimated costs
related to the Line 6B crude oil release is US$30 million in
fines and penalties. Of this amount, US$3.7 million related
to civil penalties assessed by PHMSA that EEP paid during
the third quarter of 2012. The total also included an amount
of US$22 million related to civil penalties EEP expects to be
required to pay under the Clean Water Act. While no final fine or
penalty has been assessed or agreed to date, EEP believes that,
based on the best information available at this time, the US$22
million represents an estimate of the minimum amount which
may be assessed, excluding costs of injunctive relief, if any,
that may be agreed to with the relevant governmental agencies.
Given the complexity of settlement negotiations, which EEP
expects will continue, and the limited information available to
assess the matter, EEP is unable to reasonably estimate the final
penalty which might be incurred or to reasonably estimate a
range of outcomes at this time. Discussions with governmental
agencies regarding fines and penalties are ongoing.
One claim related to Line 6A crude oil release has been
filed against Enbridge, EEP or their affiliates by the State of
Illinois in the Illinois state court in connection with this crude
oil release, and the parties are currently operating under an
agreed interim order.
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 Legal and Regulatory Proceedings
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
180 Enbridge Inc. 2013 Annual Report
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.
30. Guarantees
The Company 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.
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.
The Company has also agreed to indemnify the Fund for
certain liabilities relating to environmental matters arising
from operations prior to the transfer of certain crude oil
storage assets to the Fund in 2012.
In the normal course of conducting business, the Company
enters into agreements which indemnify third parties.
Examples include indemnifying counterparties pursuant to
sale agreements for assets or businesses in matters such as
breaches of representations, warranties or covenants, loss
or damages to property, environmental liabilities, changes
in laws, valuation differences, litigation and contingent
liabilities. 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.
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 indemnification
provisions. While 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. The indemnifications and guarantees
have not had, and are not reasonably likely to have, a material
effect on the Company’s financial condition, changes in
financial condition, earnings, liquidity, capital expenditures
or capital resources.
Glossary
AFUDC
allowance for funds used
during construction
Alliance
Alliance System
Ajax Plant
Ajax Cryogenic Processing Plant
AOCI
bcf/d
bpd
CLT
CSR
CTS
EECI
EELP
EEM
EEP
EGD
accumulated other comprehensive
income/(loss)
billion cubic feet per day
barrels per day
Canadian Local Toll
corporate social responsibility
Competitive Toll Settlement
Enbridge Energy Company, Inc.
Enbridge Energy, Limited Partnership
Enbridge Energy Management, L.L.C.
Enbridge Energy Partners, L.P.
Enbridge Gas Distribution Inc.
EGNB
Enbridge Gas New Brunswick Inc.
Enbridge
Enbridge Inc.
Enbridge Income Fund Holdings Inc.
Enbridge Pipelines Inc.
MD&A
MEP
mmcf/d
MW
MWH
NEB
NGL
OCI
OEB
Management’s Discussion
and Analysis
Midcoast Energy Partners, L.P.
million cubic feet per day
megawatts
megawatt hours
National Energy Board
natural gas liquids
other comprehensive income/(loss)
Ontario Energy Board
Offshore
Enbridge Offshore Pipelines
OPEB
ORM
PBSO
PHMSA
PPA
PSU
ROE
RSU
other postretirement benefits
Operational Risk Management
performance based stock options
Pipeline and Hazardous Materials
Safety Administration
power purchase agreement
performance stock units
return on equity
restricted stock units
ENF
EPI
EUB
FERC
GP
IJT
IR
ISO
ITS
JRP
New Brunswick Energy and Utilities Board
Seaway Pipeline Seaway Crude Pipeline System
Federal Energy Regulatory Commission
SEC
Securities and Exchange Commission
general partner
the Company
Enbridge Inc.
International Joint Tariff
the Fund
Enbridge Income Fund
incentive regulation
incentive stock options
incentive tolling settlement
Joint Review Panel
U.S. GAAP
WCSB
WRGGS
accounting principles generally accepted
in the United States of America
Western Canadian Sedimentary Basin
Walker Ridge Gas Gathering System
Glossary 181
Five-Year Consolidated Highlights
20131
20121
20111
20101
20092
(millions of Canadian dollars; per share amounts in Canadian dollars)
Earnings attributable to common shareholders
Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing and Energy Services
Sponsored Investments
Corporate
Earnings per common share3
Diluted earnings per common share3
Adjusted earnings
Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing and Energy Services
Sponsored Investments
Corporate
Adjusted earnings per common share3,4
Cash flow data
Cash provided by operating activities
Cash used in investing activities
Cash provided by financing activities
Dividends
Common share dividends declared
Dividends paid per common share3
Shares outstanding (millions)
Weighted average common shares outstanding3
Diluted weighted average common shares outstanding3
427
129
(64)
268
(314)
446
0.55
0.55
770
176
203
313
(28)
1,434
1.78
3,341
(9,431)
5,070
1,035
1.26
806
817
697
207
(456)
283
(129)
602
0.78
0.77
655
176
176
264
(30)
1,241
1.61
2,874
(6,204)
4,395
895
1.13
772
785
470
(88)
322
268
(171)
801
1.07
1.05
501
173
180
243
(16)
1,081
1.44
3,371
(5,079)
2,030
759
0.98
751
761
512
150
132
96
40
930
1.26
1.24
492
162
130
204
(25)
963
1.30
445
186
428
141
355
1,555
2.13
2.12
454
154
116
151
(20)
855
1.17
1,877
(3,902)
1,957
2,017
(3,306)
1,082
648
0.85
741
748
555
0.74
728
733
1
2
Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP.
Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP.
3 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.
4
Adjusted earnings represent earnings attributable 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 not have any standardized meaning prescribed by generally accepted accounting principles. For more
information on non-GAAP measures see page 43.
182 Enbridge Inc. 2013 Annual Report
Five-Year Consolidated Highlights
20131
20121
20111
20101
20092
(millions of Canadian dollars; per share amounts in Canadian dollars)
Common share trading (TSX)3
High
Low
Close
Volume (millions)
Financial ratios
Return on average equity4
Return on average capital employed5
Debt to debt plus total equity6
Dividend payout ratio7
Operating data
Liquids Piplines – Average deliveries (thousands of barrels per day)
Canadian Mainline8
Regional Oil Sands System9
Spearhead Pipeline
Gas Distribution – Enbridge Gas Distribution (EGD)
Volumes (billions of cubic feet)
Number of active customers (thousands)10
Heating degree days11
Actual
Forecast based on normal weather
Gas Pipelines, Processing and Energy Services – Average
throughput volume (millions of cublic feet per day)
Alliance Pipeline US
Vector Pipeline
Enbridge Offshore Pipelines
49.17
41.74
46.41
342
3.5%
3.2%
58.2%
70.8%
1,737
533
172
434
2,065
3,746
3,668
1,565
1,494
1,412
43.05
35.39
43.02
365
6.4%
3.5%
60.2%
70.2%
38.17
27.05
38.09
396
11.5%
4.5%
64.8%
68.1%
1,646
1,554
414
151
395
2,032
3,194
3,532
1,553
1,534
1,540
334
82
426
1,997
3,597
3,602
1,564
1,525
1,595
29.13
23.02
28.14
461
14.4%
5.1%
67.1%
65.4%
1,537
291
144
409
1,963
3,466
3,546
1,600
1,456
1,962
24.46
17.60
24.32
457
22.2%
8.9%
64.0%
63.0%
1,562
259
121
408
1,937
3,767
3,514
1,601
1,334
2,037
1
2
Financial ratios have been calculated using information from financial statements prepared in accordance with U.S. GAAP.
Financial ratios have been calculated using information from financial statements prepared in accordance with Canadian GAAP.
3 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.
4
5
6
7
Earnings applicable to common shareholders divided by average shareholder’s equity.
Sum of after-tax earnings and after-tax interest expense, divided by weighted average capital employed. Capital employed is equal to the sum of equity,
EGD preferred shares, deferred 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 total equity inclusive of noncontrolling interests and redeemable
noncontrolling interests.
Dividends per common share divided by adjusted earnings per common share.
8 Canadian Mainline includes deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries originating from western Canada.
9
Volumes are for the Athabasca mainline and the Waupisoo Pipeline and exclude laterals on the Regional Oil Sands System.
10 Number of active customers is the number of natural gas consuming EGD customers at the end of the period.
11 Heating degree days 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 period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius.
The figures given are those accumulated in the Greater Toronto Area.
Five-Year Consolidated Highlights
183
Investor Information
Common and Preference Shares
The Common Shares of Enbridge Inc. trade in Canada
on the Toronto Stock Exchange and in the United States on
the New York Stock Exchange under the trading symbol
‘‘ENB’’. The Preference Shares of Enbridge Inc. trade in
Canada on the Toronto Stock Exchange under the following
trading symbols:
Series A – ENB.PR.A
Series B – ENB.PR.B
Series D – ENB.PR.D
Series F – ENB.PR.F
Series H – ENB.PR.H
Series J – ENB.PR.U
Series L – ENB.PF.U
Series N – ENB.PR.N
Series P – ENB.PR.P
Series R – ENB.PR.T
Series 1 – ENB.PR.V
Series 3 – ENB.PR.Y
Series 5 – ENB.PF.V
Series 7 – ENB.PR.J
2014 Enbridge Inc. Common Share Dividends
Q1
Q2
Q3
Q4
Co-Registrar and Co-Transfer Agent
in the United States
Computershare
480 Washington Blvd.
Jersey City, New Jersey
U.S.A. 07310
Registrar and Transfer Agent in Canada
For information relating to shareholdings, shareholder
investment plan, dividends, direct dividend deposit, dividend
re-investment accounts and lost certificates please contact:
CST Trust Company
P.O. Box 700
Station B
Montreal, Quebec H3B 3K3
Toll free: 800.387.0825
canstockta.com
Dividend
$0.35
$ – 4
$ – 4
$ – 4
Payment date
Mar 01
Jun 01
Sep 01 Dec 01
CST Trust Company also has offices in Halifax, Toronto,
Calgary and Vancouver.
Record date 1
Feb 14 May 15 Aug 15 Nov 14
Dividend Reinvestment and Share Purchase Plan
SPP deadline 2
Feb 24 May 26 Aug 25 Nov 24
DRIP enrollment 3
Feb 07 May 08 Aug 08 Nov 07
1
Dividend record dates for Common Shares are generally February 15, May 15,
August 15 and November 15 in each year unless the 15th falls on a Saturday
or Sunday.
2
3
4
The Share Purchase Plan cut-off date is five business days prior to the dividend
payment date.
The Dividend Reinvestment Program enrollment cut-off date is five business
days prior to the dividend record date.
Amount will be announced as declared by the Board of Directors.
Auditors
PricewaterhouseCoopers LLP
Registered Office
Enbridge Inc.
3000, 425 – 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
Telephone: 403.231.3900
Facsimile: 403.231.3920
enbridge.com
Enbridge Inc. offers a Dividend Reinvestment and Share
Purchase Plan that enables shareholders to reinvest their
cash dividends in Common Shares and to make additional
cash payments for purchases at the market price. Effective
with dividends payable on March 1, 2008, participants
in the Plan will receive a two percent discount on the
purchase of common shares with reinvested dividends.
Details may be obtained from the Investor Information
section of the Enbridge website at or by contacting
CST Trust Company directly.
New York Stock Exchange Disclosure Differences
As a foreign private issuer, Enbridge Inc. is required to
disclose any significant ways in which its corporate
governance practices differ from those followed by
United States companies under NYSE listing standards.
This disclosure can be obtained from the U.S. Compliance
subsection of the Corporate Governance section of the
Enbridge website at enbridge.com
Form 40-F
The Company files annually with the United States Securities
and Exchange Commission a report known as the Annual
Report on Form 40-F. A link to the Form 40-F is available
on the ‘‘Investor Documents and Filings’’ subsection of the
‘‘Financial Information’’ section of our website.
184 Enbridge Inc. 2013 Annual Report
Annual Meeting
The Annual Meeting of Shareholders will be held in
the Ballroom at the Metropolitan Conference Centre,
Calgary, Alberta at 1:30 p.m. MDT on Wednesday,
May 7, 2014. A live audio webcast of the meeting will
be available at 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.
Investor Inquiries
If you have inquiries regarding the following:
• Additional financial or statistical information;
• Industry and company developments;
• Latest news releases or investor presentations; or
• Any other investment-related inquiries
please contact Enbridge Investor Relations
Adam McKnight
Director, Investor Relations
Office: 403.266.7922
Toll free: 800.481.2804
adam.mcknight@enbridge.com
Enbridge Inc., a Canadian company, is a North
American leader in delivering energy and one of
the Global 100 Most Sustainable Corporations in
the World. As a transporter of energy, Enbridge
operates in Canada and the U.S., the world’s
longest crude oil and liquids transportation system.
The Company also has a significant and growing
involvement in natural gas gathering, transmission
and midstream businesses, and an increasing
involvement in power generation and transmission.
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 generator of energy, Enbridge
has interests in more than 1,800 megawatts of
renewable and alternative energy generating
capacity and is expanding its interests in wind
and solar energy and geothermal. Enbridge
employs approximately 10,000 people, primarily
in Canada and the U.S. and is ranked as one of
Canada’s Greenest Employers and one of the
Top 100 Companies to Work for in Canada.
Enbridge’s common shares trade on the Toronto
and New York stock exchanges under the symbol
ENB. For more information, visit enbridge.com
.
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Enbridge is committed to reducing its impact on the environment in every way,
including the production of this publication. This report was printed entirely
on FSC® Certified paper containing 100% post-consumer recycled fibre and is
manufactured using biogas and wind energy.
Operational Reliability Review
In 2013, we published our first Operational Reliability
Review, which is available at enbridge.com/orr
Corporate Social Responsibility Report
Enbridge publishes an annual Corporate Social
Responsibility report. The report is available online at
csr.enbridge.com
Online Annual Report
You can read our 2013 Annual Report online at
enbridge.com/ar2013
3000, 425 – 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
Telephone: 403.231.3900
Facsimile: 403.231.3920
Toll free: 800.481.2804
enbridge.com