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2017 Annual Report
Contents
Letter to Shareholders 1
How We Deliver Value 4
2017 Financial Highlights 5
Sustainability at Enbridge 6
Corporate Governance 7
Investor Information 8
Life Takes Energy®
Our vision is to be the leading energy delivery company in North America. We play a
critical role in enabling the economic well-being and quality of life of North Americans,
who depend on access to affordable and plentiful energy—because Life Takes Energy.
Enbridge is a North American
energy infrastructure leader
with global scale and capability.
Our three core businesses
transport and distribute oil,
natural gas and natural gas
liquids and connect North
America's growing supply
basins with key demand centers.
We strive to be an industry
leader by: creating value for our
shareholders; serving customers;
setting best practice standards
with respect to worker and
public safety, environmental
protection, community and
Indigenous relations; and
building an engaged workforce.
Norman Wells
Norman Wells
Fort St. John
Fort St. John
Zama
Zama
Peace River
Peace River
Athabasca
Athabasca
Fort
Fort
McMurray
McMurray
Cheecham
Cheecham
Edmonton
Edmonton
Hardisty
Hardisty
Kerrobert
Kerrobert
C A N AD A
Vancouver
Vancouver
Lethbridge
Lethbridge
Regina
Regina
Cromer
Cromer
Rowatt
Rowatt
Gretna
Gretna
Liquids Pipelines
Enbridge operates the world’s longest and most complex crude oil and liquids
transportation system, which moves approximately 65 percent of all U.S.-bound
Canadian exports. Our Mainline System has an operating capacity of 2.85 million
barrels per day and delivers western Canadian crude to eastern Canada, U.S. Midwest
and Gulf Coast markets.
Natural Gas Transmission and Midstream
Enbridge’s natural gas pipelines transport approximately 20 percent of all natural
gas consumed in the U.S. We connect key supply basins to markets in the U.S. East,
South and Midwest, and our transmission network extends throughout the Gulf Coast.
In Western Canada, we directly link supply areas to markets in British Columbia,
the Pacific Northwest and the U.S. Midwest.
Natural Gas Utilities
Enbridge’s natural gas utility business connects major growth centers with diverse gas
supplies. Together, Enbridge Gas Distribution (EGD) and Union Gas deliver energy to
approximately 3.7 million homes and businesses in Ontario, Quebec and New Brunswick.
North Sea
Hohe See
Hohe See
Hamburg
UNITED
KINGDOM
London
THE
NETHERLANDS
Rampion
Rampion
English Channel
Eoliennes Offshore
Eoliennes Offshore
du Calvados
du Calvados
Eoliennes Offshore
Eoliennes Offshore
des Hautes Falaises
des Hautes Falaises
BELGIUM
GERMANY
ParisParis
FRANCE
Halifax
Halifax
Fredericton
Fredericton
Parc du Banc
Parc du Banc
de Guerande
de Guerande
Enbridge has successfully built a strong Green
Power and Transmission business, with interests
in more than 2,500 megawatts (MW) of net
renewable generating capacity. We also have
an expanding offshore wind portfolio in Europe
with significant capacity for growth.
Liquids Pipeline
LNG Facility
Natural Gas Transmission Pipeline
Rail
Natural Gas Gathering Pipeline
Trucking Facility
Natural Gas Liquids Pipeline
Propane Terminal
Crude Storage or Terminal
Gas Storage Facility
NGL Storage Facility
Gas Processing Plant
Gas Distribution Service Territory
Affiliated Gas Distribution Territory
Power Transmission
Renewable Energy
Great Falls
Great Falls
Buffalo
Buffalo
Edgar
Edgar
Boise
Casper
Casper
Guernsey
Guernsey
Gurley
Gurley
U N I T E D S T A T E S
U N I T E D S T A T E S
O F A M E R I C A
O F A M E R I C A
Clearbrook
Clearbrook
Montreal
Montreal
MinotMinot
Superior
Superior
Boston
Boston
Toronto
Toronto
Westover
Westover
Buffalo
Buffalo
Chatham
Chatham
Leidy
Leidy
New York
New York
Oakford
Oakford
Philadelphia
Philadelphia
Steckman
Steckman
Ridge
Ridge
Sarnia
Sarnia
Stockbridge
Stockbridge
Channahon
Channahon
Flanagan
Flanagan
Chicago
Chicago
Toledo
Toledo
Accident
Accident
Saltville
Saltville
Salisbury
Salisbury
Patoka
Patoka
Wood
Wood
River
River
Nashville
Nashville
Cushing
Cushing
Moss Bluff
Moss Bluff
Bobcat
Bobcat
New
New
Orleans
Orleans
EganEgan
Port Arthur
Port Arthur
Houston
Houston
Orlando
Orlando
Tampa
Tampa
M E X I C O
Letter to Shareholders
The New Enbridge
Essential to our success is an ability to
continually assess our environment and
adapt to change; and over the last three
decades, Enbridge has done just that.
In the 1990’s, we purchased Enbridge Gas
Distribution as we believed in the potential
of natural gas; 20 years ago we were the
first to offer incentive tolling to better align
with our customers’ needs; and 15 years
ago we began investing in renewables,
ahead of the curve. In 2017, we changed
again: the completion of our merger with
Spectra Energy transformed Enbridge
into a North American infrastructure leader
with global scale.
With the completion of the merger, we now
have what we believe are the highest-quality
liquids and natural gas infrastructure assets
on the continent under one roof. The new
Enbridge has a much stronger and more
balanced portfolio of oil and natural gas
assets, growth opportunities and geographic
reach. Our expanded footprint provides
unmatched scale, diversity, financial
flexibility and multiple platforms for organic
growth to continue to deliver the energy
people need and want—today and for
decades to come.
This has been done as we maintain and
build on the value proposition that has
served our company and our shareholders
well: our reliable, low-risk business model,
transparent growth and a growing dividend.
Two years ago, we began a process to
transform our business by finding more
efficient and effective ways of working.
After the merger, we moved quickly to
integrate the Spectra assets and bring
The new Enbridge has a much
stronger and more balanced
portfolio of oil and natural gas
assets, growth opportunities
and geographic reach.
together 15,000 people into the new
Enbridge. We ended 2017 as one team,
working towards a common goal of
building the best energy delivery company
in North America.
2017 Review
Beyond the transaction, 2017 was a very
busy year punctuated with numerous
accomplishments and milestones.
Impressively, we put $12 billion of new
assets into service in 2017, a record
achievement in a single year, but equally
important these projects are expected to
provide strong cash flows and earnings for
decades to come. This included Sabal Trail,
a greenfield natural gas system serving the
U.S. Southeast; the Wood Buffalo Extension,
serving the Fort Hills oil sands project in
northern Alberta; and the Chapman Ranch
wind power facility in Texas. Our ability
to advance these and other projects is
the result of continued on-the-ground
engagement with local communities,
stakeholders and regulators to build
understanding and trust, which is critical to
what we do and part of our corporate DNA.
2017 Annual Report 1
Al Monaco
President &
Chief Executive Officer
Gregory L. Ebel
Chair,
Board of Directors
Forward-Looking Information
This Annual Report includes references
to forward-looking information. By its nature
this information involves certain assumptions
and expectations about future outcomes,
so we remind you it is subject to risks
and uncertainties that affect our business.
The more significant factors and risks that
might affect our future outcomes are listed
and discussed in the “Forward-Looking
Information” and risk sections of our Form 10-K
and Management’s Discussion & Analysis,
available on both sedar.com and sec.gov.
Another area of focus was to secure
funding for our capital program and to
ensure a strong balance sheet. We raised
about $14 billion of capital across the
Enbridge group of companies on favorable
terms and sold $2.6 billion of non-core
assets, surpassing our original target of
$2 billion set at the time we announced
the Spectra transaction. We also took
steps to simplify our sponsored vehicles,
which hold critical infrastructure assets.
Integration of the Spectra business is well
on track and we achieved the cost synergy
objectives we were anticipating for the
first year. With the combined strength and
earnings power of our core businesses,
contributions from new projects and cost
synergy capture, distributable cash flow per
share was $3.68, which was within the 2017
financial guidance range communicated to
investors. Finally, we increased our dividend
by 15 percent in 2017, our 23rd consecutive
year of dividend hikes.
Despite our teams’ best efforts, there were
some disappointments: upstream volume
disruptions prevented the full utilization of
our liquids Mainline; we experienced project
delays due to regulatory and permitting
challenges prevalent in our industry today;
and three years of low commodity prices
took their toll on our commodity-sensitive
businesses. Equally disappointing was
the fact that we did not realize the type of
shareholder returns that you, our owners,
have become accustomed to, and that we
expect to deliver on your behalf. We strongly
believe that as our team continues to deliver
on the benefits of the Spectra merger,
our capital expansion projects and financial
targets, our shareholders will enjoy strong
total shareholder returns.
We have clear competitive
advantages in our three
core businesses, and they
fit in our low-risk, reliable
value proposition.
In our core businesses, we moved record
volumes on our Mainline System, which
came from a combination of oil sands
supply growth and capacity optimization
initiatives undertaken by our team to
increase throughput, which benefited
our customers and our industry, too.
Our expanded gas transmission business
operated very well and delivered the results
we expected from the Spectra transaction.
Same goes for our gas distribution
businesses, where we added approximately
50,000 customers and brought a major
expansion into service, another benefit
of the Spectra deal. Importantly, we once
again delivered industry-leading safety
performance. Our 15,000 employees
performed their daily work with the utmost
focus on safety, not only for the communities
in which we operate, but also for their fellow
teammates. Shareholders could not be
better served by our employees’ long-term
dedication to safely and reliably operating
our assets. Like us, the communities where
we live and work expect us to be world-class
operators, and each year we work harder
at running our business while protecting
the public, the environment and our people.
2 Enbridge Inc.
In August 2017, we broke ground in Canada on
our Line 3 Replacement Program—the largest project
in Enbridge's history—which will enhance the safety,
operational reliability and throughput of the Mainline System.
Strategic Focus
At Enbridge, we continually look for ways
to improve our business and leverage our
strengths, which is critical to remaining
competitive in today’s environment. After we
closed the Spectra merger, we undertook
a comprehensive review of our expanded
asset base, business environment and
competitive position, with the goal
of assessing where best to allocate capital
and to establish our new three-year plan.
As a result of this review, we are very
focused on what we do best: growing
our pipeline and utility assets because
this is where we can add the most value.
Moving forward, we will place greater
emphasis on our three core businesses:
liquids pipelines and terminals; natural
gas transmission and storage; and natural
gas utilities. These three core businesses
share common characteristics:
• strategically located assets with direct
connections between North America’s
key supply areas, storage and
demand markets;
Execute our capital program
We will focus on bringing $22 billion of
secured growth projects into operation
through 2020. Our inventory of projects
includes: the Line 3 Replacement Program
that will enhance the safety, operational
reliability and throughput of the Mainline
System; the NEXUS Gas Transmission
Project, a natural gas pipeline system
connecting our Texas Eastern pipeline
in Ohio to the Union Gas Dawn hub in
Ontario; and the Valley Crossing natural
gas pipeline, which will provide gas
producers with market access to Mexico.
Strengthen our financial position
To fund growth opportunities, we’ve
designed a prudent financing plan that
provides flexibility of sources of capital and
enables us to accelerate deleveraging of
the balance sheet. As part of this, we plan
to sell $3 billion of non-core assets in 2018.
Complete integration
and transformation
We remain on track to capture the
estimated $540 million in pre-tax annual
synergies from the Spectra transaction by
2019. We have also implemented initiatives
to target top-quartile cost performance.
Position for long-term growth
We will continue to evaluate opportunities
to position Enbridge for the energy
mix of the future, including expanding our
offshore wind power generation business.
Final Thoughts
Thanks to the continued hard work and
dedication of our employees, we were
able to accomplish a great deal this past
year. We are particularly proud of how
our people came together to respond to
hurricanes Harvey and Irma. We maintained
our operations and lent a much-needed
hand in our hard-hit communities.
We would like to thank our Board of
Directors for their leadership through our
first year as the new Enbridge. In particular,
Rebecca Roberts, who is retiring from the
Board, deserves our heartfelt appreciation
for her service as a Director of Enbridge
and Enbridge Energy Partners. We are
honored and feel fortunate each day
to work with the Enbridge team and to
lead this great company.
We strongly believe that Enbridge is very
well positioned for the future. We have
talented people operating and growing
the most strategically located and critical
liquids and natural gas infrastructure and
distribution systems on the continent.
Our goal over the next three years is
to build on our strengths to become
the best-performing energy infrastructure
company in North America, and to
continue delivering long-term growth
and shareholder value.
Al Monaco
President &
Chief Executive Officer
March 12, 2018
Gregory L. Ebel
Chair,
Board of Directors
• size, scale and flexibility to meet customer
needs and compete to win new business;
• strong commercial underpinnings and
highly predictable cash flows that align
with our low-risk value proposition; and
• a large set of organic growth opportunities
that naturally extend the scope and reach
of our existing businesses.
We also decided to sell or monetize assets
that don’t have these characteristics or
don’t fit our business model. These non-core
assets, including certain unregulated
gas midstream and onshore renewable
businesses, have a value of at least
$10 billion.
2018 – 2020 Plan
and Priorities
We have set a course for the next three
years that will increase our competitiveness
and grow our business. We’re confident
the successful execution of this plan
will generate approximately 10 percent
compound annual distributable cash flow
per share growth through 2020, which
supports our ability to grow our dividend by
10 percent per year over the same period.
Our plan focuses on the following
six priorities:
Safety and operational reliability
Above all else, safety and reliability of our
operations remains our number one priority.
Maximise the value of our core business
We will focus on growing our three
core businesses—liquids pipelines, gas
transmission and gas utilities—through
optimization, extension and expansion.
We have clear competitive advantages
in these businesses, and they fit in our
low-risk, reliable value proposition.
2017 Annual Report 3
How We
Deliver Value
Enbridge’s value proposition brings together a combination
of our reliable, low-risk business model, transparent growth,
and stable and growing dividend income.
Reliable and Low Risk
Our three core businesses generate
highly reliable cash flows. Over 96 percent
of Enbridge’s earnings are underpinned
by low-risk, long-term contracts with
strong, creditworthy customers.
These long-term contracts provide
stable and reliable cash flow and earnings.
Growing Dividend
Enbridge has a consistent track record
of delivering annual dividend increases
for our shareholders, supported by
the successful execution of our secured
capital program. Our strategic footprint
will continue to allow us to invest in
new, value-add projects to support
continued dividend growth.
Transparent Growth
The strategic positioning of our assets
offers organic growth opportunities by
extending and expanding our existing
network. A key element of Enbridge’s
long-term success is the safe execution
of our secured growth capital program,
which provides a clear line of sight
to cash flow growth. We are currently
executing on a program to deliver
$22 billion of new projects over
the next three years. The additional
cash flow from these projects will
support our expected dividend growth.
Growth Capital Program
by Business Segment
$12 Billion
in-service
in 2017
$22 Billion
to be placed
into service
2018 – 2020
20-Year Dividend Growth
Canadian dollars per share
We expect to grow our
dividend by 10% per
year through 2020.
4%
14%
34%
48%
4%
14%
34%
48%
8%
12%
34%
46%
8%
$2.50
12%
$2.00
34%
$1.50
$1.00
$0.50
46%
$0.00
20-year CAGR1 = 11.2%
n Liquids pipelines
n Gas transmission & midstream
n Gas distribution
n Renewables & other
1997
2017
1 Compound Annual Growth Rate of an
investment over a specified time period.
Contractual Support
96%
TOP/COS/
CTS/Fixed Fee
4%
■ Take or pay / Cost of service
2018e EBITDA
■ Competitive Tolling
Settlement (CTS)
n Take-or-Pay (TOP)/Cost-of-Service (COS)
■ Fixed Fee
n Competitive Tolling Settlement (CTS)
n Fixed fee
■ Commodity Sensitive
n Commodity sensitive
4 Enbridge Inc.
2017 Financial
Highlights
Our 2017 financials reflect our first year as a combined company following the closure
of the Enbridge and Spectra Energy merger on February 27, 2017.
Year ended Dec. 31
millions of Canadian dollars, except per share amounts
Total assets
Earnings attributable to common shareholders
Earnings/share
Adjusted EBITDA1
Adjusted earnings1
Adjusted earnings per common share
Distributable cash flow1,2
DCF per common share
Weighted average common shares outstanding
Dividends paid/share
2017
2016
162,093
85,209
2,529
1.66
10,317
2,982
1.96
5,614
3.68
1,525
2.41
1,776
1.95
6,902
2,078
2.28
3,713
4.08
911
2.12
1 Includes adjustments for unusual, non-recurring or non-operating factors. Schedules reconciling adjusted EBITDA, adjusted earnings, adjusted earnings per common share
and distributable cash flow (DCF) are available at enbridge.com
2 Formerly referred to as Available Cash Flow From Operations (ACFFO). Calculation methodology remains unchanged.
Over the past 20 years, Enbridge has delivered 12 percent dividend per share compound
annual growth and generated total annual shareholder returns of approximately 13 percent,
compared to seven percent for the S&P/TSX Composite Index. We’ve accomplished this while
building North America's largest energy infrastructure company.
In addition to Enbridge,
our Sponsored Vehicles include
three publicly traded entities
that offer investors a variety
of attractive ways to invest in
low-risk energy infrastructure.
Enbridge Income Fund Holdings Inc. (TSX: ENF): a publicly traded
Canadian corporation that invests in low-risk energy infrastructure assets,
including the Canadian portion of Enbridge’s liquids Mainline System.
ENF pays a monthly dividend.
Spectra Energy Partners, LP (NYSE: SEP): a U.S. master limited partnership
(MLP) focused on natural gas pipelines and storage in the U.S.
Enbridge Energy Partners, L.P. (NYSE: EEP): a pure-play, liquids pipelines
MLP, which owns the U.S. portion of Enbridge's liquids Mainline System.
2017 Annual Report 5
Sustainability
at Enbridge
Our first Sustainability Report for our combined
company will be published in June 2018
and will be available at enbridge.com/sustainability
As a company that builds and
operates energy infrastructure
designed to safely and reliably
deliver the energy people
need and want over decades,
how we sustain our business
over the long term is a
question we ask ourselves
in every decision we make.
Our approach to sustainability takes
into consideration the interests of all
our stakeholders—from those who invest
in us, work for us and partner with us,
to those who live near our projects and
operations. We’re focused on identifying
the environmental, social and governance
risks and opportunities most significant
to our business and integrating them
into our strategic framework and capital
allocation decisions.
Oversight of our sustainability policies
and performance begins with our Board
of Directors and executive management.
Enbridge has dedicated policies,
management systems, teams and
senior-level accountabilities in place
to address key issues facing our
company and its stakeholders.
Safety and
Environmental Protection
We make ongoing investments to assure
the fitness of our systems and to detect
leaks. We are building a culture where
all incidents are seen as preventable and
our people are empowered and expected
to raise safety or environmental concerns.
This past year, we had no major incidents
on our systems.
$2B
We invested close to $2 billion
in the safety and integrity of our
energy delivery systems in 2017.
Stakeholder and
Indigenous Inclusion
We engage with stakeholders and
Indigenous groups in a respectful
manner with a focus on building
mutually beneficial relationships.
Our Indigenous Peoples Policy
recognizes the legal and constitutional
rights of Indigenous peoples, and
the importance of their relationship
to their traditional lands and resources.
Climate and
Energy Solutions
We are uniquely positioned to help
bring new low-carbon solutions to
scale in Canada and the U.S. We are
focused on energy efficiency and
emissions reduction across our own
operations, and we are integrating
carbon sensitivities and climate
risks in our investment decisions.
$74M
Through our engagement on the Line 3
Replacement Program, we have entered
into agreements with 56 Indigenous
communities in Canada. In 2017,
we delivered approximately $74 million
in social-economic opportunities to
Indigenous contractors or partners.
$2.9B
1,009 MW
We have committed to invest
$2.9 billion in European offshore
wind projects that will add 1,009 MW
of renewable power generation
capacity to our portfolio.
6 Enbridge Inc.
Sound Governance
Means Sound Business
We believe good governance is important
for our shareholders, our employees and our
company. We have a comprehensive system
of stewardship and accountability that meets
the requirements of all applicable rules,
regulations, standards and internal and
external policies. We continuously assess
our governance practices to build on our
strengths and improve our effectiveness.
We benefit from a diverse and highly
engaged Board of Directors who bring a
range of viewpoints, deep expertise and
strong energy-sector knowledge that helps
ensure effective oversight of our strategic
priorities and operations.
For more information about our Board of
Directors and our governance practices,
please see Enbridge Inc.’s Notice of 2018
Annual Meeting and Proxy Statement
available in the Reports & Filings section
of the Investment Center at enbridge.com
Board of Directors
As of March 12, 2018 (pictured, left to right )
J. Herb England
Catherine L. Williams
Gregory L. Ebel, Chair
Marcel R. Coutu
V. Maureen Kempston Darkes
Al Monaco
Rebecca B. Roberts
Dan C. Tutcher
Michael McShane
Michael E.J. Phelps
Pamela L. Carter
Charles W. Fischer
Clarence P. Cazalot, Jr.
2017 Annual Report 7
Investor Information
Investor Inquiries
2018 Enbridge Inc. Common Share Dividends
If you have inquiries regarding the following:
• additional financial or statistical information;
• industry and company developments;
• the latest news releases or investor
presentations; or
• any other investment-related inquiries
please contact Enbridge
Investor Relations:
Toll-free: 800-481-2804
Office: 403-231-3960
investor.relations@enbridge.com
Enbridge Inc.
200, 425 – 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
Annual Meeting
The Annual Meeting of Shareholders will be
held at the Calgary Marriott Downtown Hotel,
Kensington Room, 110 – 9 Avenue S.E., Calgary,
Alberta, Canada at 1:30 pm MT on Wednesday,
May 9, 2018. 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.
Registrar and Transfer Agent
For information relating to shareholdings,
shareholder investment plan, dividends, direct
dividend deposit, dividend re-investment
accounts and lost certificates, please contact:
AST Trust Company
P.O. Box 700, Station B
Montreal, Quebec, Canada H3B 3K3
Telephone: 800-821-2794, or
416-682-3860 outside of North America
astfinancial.com
AST Trust Company has offices in
Halifax, Toronto, Calgary and Vancouver.
Dividend
Payment date
Record date1
SPP deadline2
Q1
$0.671
Q2
$ – 4
Q3
$ – 4
Q4
$ – 4
Mar 01
Jun 01
Sep 01
Dec 01
Feb 15
May 15
Aug 15
Nov 15
Feb 22
May 25
Aug 27
Nov 26
DRIP enrollment3
Feb 08
May 08
Aug 08
Nov 08
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 The Share Purchase Plan cut-off date is five business days prior to the dividend payment date.
3 The Dividend Reinvestment Program enrollment cut-off date is five business days prior to the dividend
record date.
4 Amount will be announced as declared by the Board of Directors.
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 trading symbols:
Series A – ENB.PR.A
Series B – ENB.PR.B
Series C – ENB.PR.C
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
Series 9 – ENB.PF.A
Series 11 – ENB.PF.C
Series 13 – ENB.PF.E
Series 15 – ENB.PF.G
Series 17 – ENB.PF.I
Series 19 – ENB.PF.K
DRIP Information and How to Register
Enbridge offers a dividend reinvestment and share purchase plan (DRIP) to
enable holders of Enbridge common shares to acquire additional shares through
re-investment of the common share dividends paid quarterly, or through optional
cash payments. Dividends re-invested through Enbridge’s DRIP receive a two-percent
discount on the market price of Enbridge shares, and funds are fully invested as
fractional share ownership is permitted as part of the plan. DRIP participants are
also eligible to purchase up to an additional $5,000 in Enbridge common shares each
quarter without incurring brokerage fees; however, the two-percent discount is not
available for these additional purchases. Please contact AST toll-free (North America)
at 1-800-821-2794 or outside of North America at 1-416-682-3860 to request
enrollment forms and for further information on Enbridge’s DRIP.
Auditors
PricewaterhouseCoopers LLP
8 Enbridge Inc.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________
FORM 10-K
_______________________________
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-10934
_______________________________
ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)
_______________________________
Canada
(State or Other Jurisdiction of
Incorporation or Organization)
None
(I.R.S. Employer
Identification No.)
200, 425 - 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
(Address of Principal Executive Offices) (Zip Code)
Registrant’s telephone number, including area code (403) 231-3900
_______________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Shares
Name of each exchange on which registered
New York Stock Exchange
_______________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files).Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will
not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule
12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer
Non-Accelerated Filer
(Do not check if a smaller reporting company)
Emerging growth company
Accelerated Filer
Smaller reporting company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes
No
The aggregate market value of the registrant’s common shares held by non-affiliates computed by reference to the price at which the common
equity was last sold on June 30, 2017, was approximately US$65,416,118,124.
As at February 9, 2018, the registrant had 1,695,190,292 common shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the proxy statement for the 2018 Annual Meeting of Shareholders are incorporated by reference in Part III.
1
Page
GLOSSARY
Item 1.
PART I
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Properties
Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Selected Financial Data
Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
PART IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Exhibit Index
Signatures
7
40
48
48
48
48
49
51
52
101
105
195
195
196
196
196
196
196
196
197
198
198
203
Accumulated other comprehensive income/(loss)
Asset retirement obligations
Accounting Standards Update
British Columbia
Billion cubic feet per day
Barrels per day
Canadian L3R Program
Canadian portion of the Line 3 Replacement Program
Canadian Restructuring Plan
Transfer of Enbridge's Canadian Liquids Pipelines business, held by
EPI and Enbridge Pipelines (Athabasca) Inc., and certain Canadian
renewable energy assets to the Fund Group, which was effective on
AOCI
ARO
ASU
BC
bcf/d
bpd
ECT
EEP
EGD
EIPLP
EIS
ENF
EPI
EUB
FERC
GHG
HLBV
IDR
IJT
IR Plan
ISO
LIBOR
LMCI
LNG
MD&A
MEP
CTS
Dawn
DCP Midstream
Duke Energy
EaR
EBITDA
Flanagan South
L3R Program
Lakehead System
Enbridge
Enbridge Inc.
Earnings before interest, income taxes and depreciation and
September 1, 2015
Competitive Toll Settlement
Dawn Hub
DCP Midstream, LLC
Duke Energy Corporation
Earnings-at-Risk
amortization
Enbridge Commercial Trust
Enbridge Energy Partners, L.P.
Enbridge Gas Distribution Inc.
Enbridge Income Partners LP
Environmental Impact Statement
Enbridge Income Fund Holdings Inc.
Enbridge Pipelines Inc.
New Brunswick Energy and Utilities Board
Federal Energy Regulatory Commission
Flanagan South Pipeline
Greenhouse gas
Hypothetical Liquidation at Book Value
Incentive Distribution Rights
International Joint Tariff
EGD's Incentive Rate Plan
Incentive Stock Options
Line 3 Replacement Program
Lakehead Pipeline System
London Interbank Offered Rate
Land Matters Consultation Initiative
Liquefied natural gas
Management’s Discussion and Analysis
Midcoast Energy Partners, L.P.
2
3
Merger Transaction
Combination of Enbridge and Spectra Energy through a stock-for-
stock merger transaction which closed on February 27, 2017
MNPUC
Minnesota Public Utilities Commission
PART I
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Properties
Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial
Item 8.
Item 9.
Item 9A. Controls and Procedures
Item 9B. Other Information
Disclosure
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
PART IV
Exhibit Index
Signatures
7
40
48
48
48
48
49
51
52
101
105
195
195
196
196
196
196
196
196
197
198
198
203
Page
GLOSSARY
AOCI
ARO
ASU
BC
bcf/d
bpd
Canadian L3R Program
Canadian Restructuring Plan
CTS
Dawn
DCP Midstream
Duke Energy
EaR
EBITDA
ECT
EEP
EGD
EIPLP
EIS
Enbridge
ENF
EPI
EUB
FERC
Flanagan South
GHG
HLBV
IDR
IJT
IR Plan
ISO
L3R Program
Lakehead System
LIBOR
LMCI
LNG
MD&A
MEP
Merger Transaction
MNPUC
Accumulated other comprehensive income/(loss)
Asset retirement obligations
Accounting Standards Update
British Columbia
Billion cubic feet per day
Barrels per day
Canadian portion of the Line 3 Replacement Program
Transfer of Enbridge's Canadian Liquids Pipelines business, held by
EPI and Enbridge Pipelines (Athabasca) Inc., and certain Canadian
renewable energy assets to the Fund Group, which was effective on
September 1, 2015
Competitive Toll Settlement
Dawn Hub
DCP Midstream, LLC
Duke Energy Corporation
Earnings-at-Risk
Earnings before interest, income taxes and depreciation and
amortization
Enbridge Commercial Trust
Enbridge Energy Partners, L.P.
Enbridge Gas Distribution Inc.
Enbridge Income Partners LP
Environmental Impact Statement
Enbridge Inc.
Enbridge Income Fund Holdings Inc.
Enbridge Pipelines Inc.
New Brunswick Energy and Utilities Board
Federal Energy Regulatory Commission
Flanagan South Pipeline
Greenhouse gas
Hypothetical Liquidation at Book Value
Incentive Distribution Rights
International Joint Tariff
EGD's Incentive Rate Plan
Incentive Stock Options
Line 3 Replacement Program
Lakehead Pipeline System
London Interbank Offered Rate
Land Matters Consultation Initiative
Liquefied natural gas
Management’s Discussion and Analysis
Midcoast Energy Partners, L.P.
Combination of Enbridge and Spectra Energy through a stock-for-
stock merger transaction which closed on February 27, 2017
Minnesota Public Utilities Commission
2
3
MW
NEB
NGL
Noverco
NYSE
OCI
OEB
OPEB
OPEC
PennEast
ROE
RSU
Sabal Trail
Sandpiper
Seaway Pipeline
Secondary Offering
SEP
Spectra Energy
TCJA
Texas Eastern
the Court
the Fund
the Fund Group
TSX
the Tupper Plants
Union Gas
U.S. GAAP
U.S. L3R Program
Vector
VIE
WCSB
CONVENTIONS
Megawatts
National Energy Board
Natural gas liquids
Noverco Inc.
New York Stock Exchange
Other comprehensive income/(loss)
Ontario Energy Board
Other postretirement benefit obligations
Organization of Petroleum Exporting Countries
PennEast Pipeline Company LLC
Return on equity
Restricted Stock Units
Sabal Trail Transmission, LLC
Sandpiper Project
Seaway Crude Pipeline System
ENF's secondary offering of 17,347,750 ENF common shares to the
public on April 18, 2017
Spectra Energy Partners, LP
Spectra Energy Corp
the “Tax Cuts and Jobs Act”
Texas Eastern Transmission, L.P.
United States District Court for the District of Columbia
Enbridge Income Fund
The Fund, ECT, EIPLP and the subsidiaries and investees of EIPLP
Toronto Stock Exchange
Tupper Main and Tupper West gas plants
Union Gas Limited
Generally accepted accounting principles in the United States of
America
United States portion of the Line 3 Replacement Program
Vector Pipeline L.P.
Variable interest entities
Western Canadian Sedimentary Basin
The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. unless
the context suggests otherwise. These terms are used for convenience only and are not intended as a
precise description of any separate legal entity within Enbridge.
Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to
“dollars”, “$” or “C$” are to Canadian dollars and all references to “US$” are to United States dollars. All
amounts are provided on a before tax basis, unless otherwise stated.
FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this annual report on Form 10-K to
provide information about us and our subsidiaries and affiliates, including management’s assessment of Enbridge
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”, “likely” 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 the following: expected earnings before interest,
income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per
share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmission and Midstream,
Gas Distribution, Green Power and Transmission, and Energy Services businesses; financial strength and flexibility;
expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced
projects and projects under construction; expected in-service dates for announced projects and projects under
construction; expected capital expenditures; expected equity funding requirements for our commercially secured
growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’
ability to complete and finance projects under construction; expected closing of acquisitions and dispositions;
estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program
(Canadian L3R Program); expected expansion of the T-South System and Spruce Ridge Program; expected capacity
of the Hohe See Expansion Offshore Wind Project; expected costs in connection with Line 6A and Line 6B crude oil
releases; expected effect of Aux Sable Consent Decree; expected future actions of regulators; expected costs related
to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts;
expectations regarding the impact of the Merger Transaction including our combined scale, financial flexibility, growth
program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity
programs; the sponsored vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation;
expectations on impact of hedging program; and expectations resulting from the successful execution of our
2018-2020 Strategic Plan.
Although we believe 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 following: the expected supply of
and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural
gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labor and
construction materials; operational reliability; customer and regulatory approvals; maintenance of support and
regulatory approvals for our projects; anticipated in-service dates; weather; the realization of anticipated benefits and
synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of
integration plans; impact of the dividend policy on our future cash flows; credit ratings; capital project funding;
expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows and
estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas,
NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking
statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates,
inflation and interest rates impact the economies and business environments in which we operate and may impact
levels of demand for our 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 the impact of the Merger
Transaction on us, expected EBITDA, earnings/(loss), earnings/(loss) per share, or estimated future dividends. The
most relevant assumptions associated with forward-looking statements on announced projects and projects under
construction, including estimated completion dates and expected capital expenditures, include the following: the
availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor
and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government
and regulatory approvals on construction and in-service schedules and cost recovery regimes.
Our forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger
Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals
of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates,
4
5
MW
NEB
NGL
Noverco
NYSE
OCI
OEB
OPEB
OPEC
PennEast
ROE
RSU
Sabal Trail
Sandpiper
Seaway Pipeline
Secondary Offering
SEP
TCJA
Texas Eastern
the Court
the Fund
the Fund Group
TSX
Union Gas
U.S. GAAP
Vector
VIE
WCSB
CONVENTIONS
Megawatts
National Energy Board
Natural gas liquids
Noverco Inc.
New York Stock Exchange
Other comprehensive income/(loss)
Ontario Energy Board
Other postretirement benefit obligations
Organization of Petroleum Exporting Countries
PennEast Pipeline Company LLC
Return on equity
Restricted Stock Units
Sabal Trail Transmission, LLC
Sandpiper Project
Seaway Crude Pipeline System
public on April 18, 2017
Spectra Energy Partners, LP
ENF's secondary offering of 17,347,750 ENF common shares to the
Spectra Energy
Spectra Energy Corp
the “Tax Cuts and Jobs Act”
Texas Eastern Transmission, L.P.
United States District Court for the District of Columbia
The Fund, ECT, EIPLP and the subsidiaries and investees of EIPLP
the Tupper Plants
Tupper Main and Tupper West gas plants
Generally accepted accounting principles in the United States of
U.S. L3R Program
United States portion of the Line 3 Replacement Program
Enbridge Income Fund
Toronto Stock Exchange
Union Gas Limited
America
Vector Pipeline L.P.
Variable interest entities
Western Canadian Sedimentary Basin
The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. unless
the context suggests otherwise. These terms are used for convenience only and are not intended as a
precise description of any separate legal entity within Enbridge.
Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to
“dollars”, “$” or “C$” are to Canadian dollars and all references to “US$” are to United States dollars. All
amounts are provided on a before tax basis, unless otherwise stated.
FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this annual report on Form 10-K to
provide information about us and our subsidiaries and affiliates, including management’s assessment of Enbridge
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”, “likely” 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 the following: expected earnings before interest,
income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per
share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmission and Midstream,
Gas Distribution, Green Power and Transmission, and Energy Services businesses; financial strength and flexibility;
expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced
projects and projects under construction; expected in-service dates for announced projects and projects under
construction; expected capital expenditures; expected equity funding requirements for our commercially secured
growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’
ability to complete and finance projects under construction; expected closing of acquisitions and dispositions;
estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program
(Canadian L3R Program); expected expansion of the T-South System and Spruce Ridge Program; expected capacity
of the Hohe See Expansion Offshore Wind Project; expected costs in connection with Line 6A and Line 6B crude oil
releases; expected effect of Aux Sable Consent Decree; expected future actions of regulators; expected costs related
to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts;
expectations regarding the impact of the Merger Transaction including our combined scale, financial flexibility, growth
program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity
programs; the sponsored vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation;
expectations on impact of hedging program; and expectations resulting from the successful execution of our
2018-2020 Strategic Plan.
Although we believe 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 following: the expected supply of
and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural
gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labor and
construction materials; operational reliability; customer and regulatory approvals; maintenance of support and
regulatory approvals for our projects; anticipated in-service dates; weather; the realization of anticipated benefits and
synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of
integration plans; impact of the dividend policy on our future cash flows; credit ratings; capital project funding;
expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows and
estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas,
NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking
statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates,
inflation and interest rates impact the economies and business environments in which we operate and may impact
levels of demand for our 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 the impact of the Merger
Transaction on us, expected EBITDA, earnings/(loss), earnings/(loss) per share, or estimated future dividends. The
most relevant assumptions associated with forward-looking statements on announced projects and projects under
construction, including estimated completion dates and expected capital expenditures, include the following: the
availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor
and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government
and regulatory approvals on construction and in-service schedules and cost recovery regimes.
Our forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger
Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals
of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates,
4
5
changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and
demand for commodities, including but not limited to those risks and uncertainties discussed in this annual report on
Form 10-K and in our 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 our future course of action depends on management’s assessment of all information available at
the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly
update or revise any forward-looking statements made in this annual report on Form 10-K or otherwise, whether as a
result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or
oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary
statements.
ITEM 1. BUSINESS
PART I
Enbridge is a North American energy infrastructure company with strategic business platforms that
include an extensive network of crude oil, liquids and natural gas pipelines, regulated natural gas
distribution utilities and renewable power generation assets. We deliver an average of 2.8 million barrels
of crude oil each day through our Mainline and Express Pipeline, and account for approximately 65% of
United States-bound Canadian crude oil exports. We also move approximately 20% of all natural gas
consumed in the United States, serving key supply basins and demand markets. Our regulated utilities
serve approximately 3.7 million retail customers in Ontario, Quebec and New Brunswick. We also have
interests in more than 2,500 megawatts (MW) of net renewable power generation capacity in North
America and Europe. We have ranked on the Global 100 Most Sustainable Corporations index for the
past eight years. Our common shares trade on the Toronto Stock Exchange (TSX) and the New York
Stock Exchange (NYSE) under the symbol ENB. We were incorporated on April 13, 1970 under the
Companies Ordinance of the Northwest Territories and were continued under the Canada Business
Corporations Act on December 15, 1987.
On February 27, 2017, we announced the closing of the combination of Enbridge and Spectra Energy
Corp. (Spectra Energy) through a stock-for-stock merger transaction (the Merger Transaction).
Spectra Energy, now wholly-owned by Enbridge, is one of North America’s leading natural gas delivery
companies owning and operating a large, diversified and complementary portfolio of gas transmission,
midstream gathering and processing and distribution assets. Spectra Energy also owns and operates a
crude oil pipeline system that connects Canadian and United States producers to refineries in the United
States Rocky Mountain and Midwest regions. The combination with Spectra Energy has created the
largest energy infrastructure company in North America with an extensive portfolio of energy assets that
are well positioned to serve key supply basins and end use markets and multiple business platforms
through which to drive future growth.
A more detailed description of each of the businesses and underlying assets acquired through the Merger
Transaction is provided below under Business Segments.
CORPORATE VISION AND STRATEGY
VISION
Our vision is to be the leading energy delivery company in North America. In pursuing this vision, we play
a critical role in enabling the economic well-being and quality of life of North Americans, who depend on
access to plentiful energy. We transport, distribute and generate energy, and our primary purpose is to
deliver the energy North Americans need, in the safest, most reliable and most efficient way possible.
Among our peers, we strive to be the leader, which means not only leadership in value creation for
shareholders, but also leadership with respect to worker and public safety and environmental protection
associated with our energy delivery infrastructure, as well as in customer service, community investment
and employee satisfaction.
STRATEGY
Today, our business is balanced between oil and natural gas. The Merger Transaction combined Spectra
Energy’s natural gas transmission franchise, with our liquids pipeline business. Further, the Merger
Transaction doubled the size of our utility business and now delivers energy to more than 3.7 million
customers. This footprint provides us with scale and diversity to compete, to grow and to provide the
energy people need and want.
6
7
changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and
demand for commodities, including but not limited to those risks and uncertainties discussed in this annual report on
Form 10-K and in our 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 our future course of action depends on management’s assessment of all information available at
the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly
update or revise any forward-looking statements made in this annual report on Form 10-K or otherwise, whether as a
result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or
oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary
statements.
ITEM 1. BUSINESS
PART I
Enbridge is a North American energy infrastructure company with strategic business platforms that
include an extensive network of crude oil, liquids and natural gas pipelines, regulated natural gas
distribution utilities and renewable power generation assets. We deliver an average of 2.8 million barrels
of crude oil each day through our Mainline and Express Pipeline, and account for approximately 65% of
United States-bound Canadian crude oil exports. We also move approximately 20% of all natural gas
consumed in the United States, serving key supply basins and demand markets. Our regulated utilities
serve approximately 3.7 million retail customers in Ontario, Quebec and New Brunswick. We also have
interests in more than 2,500 megawatts (MW) of net renewable power generation capacity in North
America and Europe. We have ranked on the Global 100 Most Sustainable Corporations index for the
past eight years. Our common shares trade on the Toronto Stock Exchange (TSX) and the New York
Stock Exchange (NYSE) under the symbol ENB. We were incorporated on April 13, 1970 under the
Companies Ordinance of the Northwest Territories and were continued under the Canada Business
Corporations Act on December 15, 1987.
On February 27, 2017, we announced the closing of the combination of Enbridge and Spectra Energy
Corp. (Spectra Energy) through a stock-for-stock merger transaction (the Merger Transaction).
Spectra Energy, now wholly-owned by Enbridge, is one of North America’s leading natural gas delivery
companies owning and operating a large, diversified and complementary portfolio of gas transmission,
midstream gathering and processing and distribution assets. Spectra Energy also owns and operates a
crude oil pipeline system that connects Canadian and United States producers to refineries in the United
States Rocky Mountain and Midwest regions. The combination with Spectra Energy has created the
largest energy infrastructure company in North America with an extensive portfolio of energy assets that
are well positioned to serve key supply basins and end use markets and multiple business platforms
through which to drive future growth.
A more detailed description of each of the businesses and underlying assets acquired through the Merger
Transaction is provided below under Business Segments.
CORPORATE VISION AND STRATEGY
VISION
Our vision is to be the leading energy delivery company in North America. In pursuing this vision, we play
a critical role in enabling the economic well-being and quality of life of North Americans, who depend on
access to plentiful energy. We transport, distribute and generate energy, and our primary purpose is to
deliver the energy North Americans need, in the safest, most reliable and most efficient way possible.
Among our peers, we strive to be the leader, which means not only leadership in value creation for
shareholders, but also leadership with respect to worker and public safety and environmental protection
associated with our energy delivery infrastructure, as well as in customer service, community investment
and employee satisfaction.
STRATEGY
Today, our business is balanced between oil and natural gas. The Merger Transaction combined Spectra
Energy’s natural gas transmission franchise, with our liquids pipeline business. Further, the Merger
Transaction doubled the size of our utility business and now delivers energy to more than 3.7 million
customers. This footprint provides us with scale and diversity to compete, to grow and to provide the
energy people need and want.
6
7
Our 2018-2020 Strategic Plan (the Strategic Plan) sets a course for us for the next three years. Our
focus, as set out in our Strategic Plan, is on what we do best - growing our pipeline and utility assets, and
selling or monetizing assets that do not fit this model. Our core assets have highly predictable cash flows,
align with our low risk value proposition and are expected to create a large set of organic growth
opportunities through which to expand and extend our existing assets. With a significant amount of
growth capital already secured through 2020, project execution, cost management and maintaining our
financial strength and flexibility remain critical to our long-term success.
To achieve our objectives, we are focused on delivering on the strategic priorities outlined below.
Commitment to Safety and Operational Reliability
Safety and operational reliability remain the foundation for the Strategic Plan. The commitment to safety
and operational reliability means achieving and maintaining industry leadership in safety (process, public
and personal) and ensuring the reliability and integrity of the systems we operate in order to generate,
transport and deliver energy and to protect the environment.
Maximize Value of Core Businesses
We are re-positioning our asset mix to a pure regulated pipeline and utility business model focusing on
our core businesses: liquids pipelines and terminals; gas transmission and storage; and natural gas
distribution. Our core assets have similar characteristics:
• Strategic positioning - between key supply basins with large, growing demand markets;
• Strong commercial underpinnings - long-term contracts, established customers, strong risk-
adjusted returns; and
• Organic growth opportunities - the ability to create value by extending, expanding, repurposing,
reconfiguring and replacing assets already in the ground.
By focusing on our core businesses and a regulated pipeline and utility model, we believe we will
continue to deliver on the low-risk, reliable value proposition that has served our shareholders well over
the years.
Complete Integration and Transformation
In 2017 we made substantial progress on the integration of Spectra Energy including operations and
support functions, policies, management systems and establishment of a new, streamlined and lower cost
organizational structure soon after close of the transaction. Simultaneous capture of cost savings due to
combination synergies remain on track and slightly ahead of plan. Execution of planned synergies in 2018
and integration activities relating to information systems and other capabilities will continue. Prior to and
in conjunction with this integration, given the increasingly competitive nature of our business, we
established a target of top quartile cost performance. To achieve this, in conjunction with the integration
we launched several projects to transform various processes, organizational capabilities and information
systems infrastructure to improve how we do business and continuously drive cost efficiencies.
Integration, these transformation projects, and our focus on cost leadership represent key priorities
through the planning horizon.
Execute Capital Program
Our 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 and environmental and
regulatory compliance. Project execution is integral to our near-term financial performance and balance
sheet strength, but also to positioning the business for the long-term. Over the next three years, we plan
to spend $22 billion on previously secured organic growth opportunities within our core businesses. Our
secured capital program includes projects such as the Line 3 Replacement Program (L3R Program),
NEXUS, Valley Crossing and the Hohe See Offshore Wind Project.
Through our major projects group, we continue to build upon and enhance the key elements of our 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 transition of projects to operating units. Ensuring our project
execution costs remain competitive in any market environment is a priority.
Strengthen Financial Position
The maintenance of financial strength is crucial to our growth strategy. Our financing strategies are
designed to ensure we have sufficient financial flexibility to meet our capital requirements. To support this
objective, we develop financing plans and strategies to diversify our funding sources and maintain
substantial standby bank credit capacity and access to capital markets in both Canada and the United
States. For further discussion on our financing strategies, refer to Part II. Item 7. Management's
Discussion and Analysis and Results of Operations - Liquidity and Capital Resources.
Our funding plan is designed to sustain strong investment grade credit ratings, which are key to cost-
effectively funding future growth. We have already begun taking actions to accelerate planned
deleveraging and balance sheet strengthening, including the issuance of approximately $2 billion of new
common equity and $500 million in preferred equity financing in late 2017. Over the remainder of the
current planning horizon (2018-2020) we plan to continue to strengthen the balance sheet while building
out the balance of our secured growth program. We plan to accomplish this through issuing additional
hybrid securities, issuance of common equity through our Dividend Reinvestment Program and the sale
or monetization of non-core assets.
Consistent with our risk management policy, we have implemented a comprehensive long-term economic
hedging program to mitigate the impact of fluctuations in interest rates, foreign exchange and commodity
price on our earnings and cash flow. This economic hedging program together with ongoing management
of credit exposures to customers, suppliers and counterparties helps reinforce our reliable business
model, which is one of the key tenets of our investor value proposition. For further details, refer to Part II.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We continually assess 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 criteria
with the objective of ensuring effective deployment of capital and enduring financial strength and stability.
Secure the Longer-Term Future
A key strategic priority is the development and enhancement of strategic growth platforms from which to
secure our long-term future. We expect to benefit from a diversified set of strategic growth platforms,
including liquids and gas pipelines, an attractive portfolio of regulated natural gas distribution utilities and
a growing offshore renewable power generation business. The strength of the combined assets and
geographic footprint will generate highly transparent and predictable cash flows underpinned by high
quality commercial constructs that align closely with our investor value proposition and significant ongoing
organic growth potential.
MAINTAIN THE FOUNDATION
Uphold Enbridge Values
We adhere to a strong set of core values that govern how we conduct our business and pursue strategic
priorities, as articulated in our value statement: “Enbridge employees demonstrate integrity, safety and
respect in support of our communities, the environment and each other”. Employees are expected to
uphold these values in their interactions with each other, customers, suppliers, landowners, community
members and all others with whom we deal and ensure our business decisions are consistent with these
values. Employees and contractors are required, on an annual basis, to certify their compliance with our
Statement on Business Conduct.
8
9
Our 2018-2020 Strategic Plan (the Strategic Plan) sets a course for us for the next three years. Our
focus, as set out in our Strategic Plan, is on what we do best - growing our pipeline and utility assets, and
selling or monetizing assets that do not fit this model. Our core assets have highly predictable cash flows,
align with our low risk value proposition and are expected to create a large set of organic growth
opportunities through which to expand and extend our existing assets. With a significant amount of
growth capital already secured through 2020, project execution, cost management and maintaining our
financial strength and flexibility remain critical to our long-term success.
To achieve our objectives, we are focused on delivering on the strategic priorities outlined below.
Commitment to Safety and Operational Reliability
Safety and operational reliability remain the foundation for the Strategic Plan. The commitment to safety
and operational reliability means achieving and maintaining industry leadership in safety (process, public
and personal) and ensuring the reliability and integrity of the systems we operate in order to generate,
transport and deliver energy and to protect the environment.
Maximize Value of Core Businesses
We are re-positioning our asset mix to a pure regulated pipeline and utility business model focusing on
our core businesses: liquids pipelines and terminals; gas transmission and storage; and natural gas
distribution. Our core assets have similar characteristics:
• Strategic positioning - between key supply basins with large, growing demand markets;
• Strong commercial underpinnings - long-term contracts, established customers, strong risk-
adjusted returns; and
• Organic growth opportunities - the ability to create value by extending, expanding, repurposing,
reconfiguring and replacing assets already in the ground.
By focusing on our core businesses and a regulated pipeline and utility model, we believe we will
continue to deliver on the low-risk, reliable value proposition that has served our shareholders well over
the years.
Complete Integration and Transformation
In 2017 we made substantial progress on the integration of Spectra Energy including operations and
support functions, policies, management systems and establishment of a new, streamlined and lower cost
organizational structure soon after close of the transaction. Simultaneous capture of cost savings due to
combination synergies remain on track and slightly ahead of plan. Execution of planned synergies in 2018
and integration activities relating to information systems and other capabilities will continue. Prior to and
in conjunction with this integration, given the increasingly competitive nature of our business, we
established a target of top quartile cost performance. To achieve this, in conjunction with the integration
we launched several projects to transform various processes, organizational capabilities and information
systems infrastructure to improve how we do business and continuously drive cost efficiencies.
Integration, these transformation projects, and our focus on cost leadership represent key priorities
through the planning horizon.
Execute Capital Program
Our 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 and environmental and
regulatory compliance. Project execution is integral to our near-term financial performance and balance
sheet strength, but also to positioning the business for the long-term. Over the next three years, we plan
to spend $22 billion on previously secured organic growth opportunities within our core businesses. Our
secured capital program includes projects such as the Line 3 Replacement Program (L3R Program),
NEXUS, Valley Crossing and the Hohe See Offshore Wind Project.
Through our major projects group, we continue to build upon and enhance the key elements of our 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 transition of projects to operating units. Ensuring our project
execution costs remain competitive in any market environment is a priority.
Strengthen Financial Position
The maintenance of financial strength is crucial to our growth strategy. Our financing strategies are
designed to ensure we have sufficient financial flexibility to meet our capital requirements. To support this
objective, we develop financing plans and strategies to diversify our funding sources and maintain
substantial standby bank credit capacity and access to capital markets in both Canada and the United
States. For further discussion on our financing strategies, refer to Part II. Item 7. Management's
Discussion and Analysis and Results of Operations - Liquidity and Capital Resources.
Our funding plan is designed to sustain strong investment grade credit ratings, which are key to cost-
effectively funding future growth. We have already begun taking actions to accelerate planned
deleveraging and balance sheet strengthening, including the issuance of approximately $2 billion of new
common equity and $500 million in preferred equity financing in late 2017. Over the remainder of the
current planning horizon (2018-2020) we plan to continue to strengthen the balance sheet while building
out the balance of our secured growth program. We plan to accomplish this through issuing additional
hybrid securities, issuance of common equity through our Dividend Reinvestment Program and the sale
or monetization of non-core assets.
Consistent with our risk management policy, we have implemented a comprehensive long-term economic
hedging program to mitigate the impact of fluctuations in interest rates, foreign exchange and commodity
price on our earnings and cash flow. This economic hedging program together with ongoing management
of credit exposures to customers, suppliers and counterparties helps reinforce our reliable business
model, which is one of the key tenets of our investor value proposition. For further details, refer to Part II.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We continually assess 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 criteria
with the objective of ensuring effective deployment of capital and enduring financial strength and stability.
Secure the Longer-Term Future
A key strategic priority is the development and enhancement of strategic growth platforms from which to
secure our long-term future. We expect to benefit from a diversified set of strategic growth platforms,
including liquids and gas pipelines, an attractive portfolio of regulated natural gas distribution utilities and
a growing offshore renewable power generation business. The strength of the combined assets and
geographic footprint will generate highly transparent and predictable cash flows underpinned by high
quality commercial constructs that align closely with our investor value proposition and significant ongoing
organic growth potential.
MAINTAIN THE FOUNDATION
Uphold Enbridge Values
We adhere to a strong set of core values that govern how we conduct our business and pursue strategic
priorities, as articulated in our value statement: “Enbridge employees demonstrate integrity, safety and
respect in support of our communities, the environment and each other”. Employees are expected to
uphold these values in their interactions with each other, customers, suppliers, landowners, community
members and all others with whom we deal and ensure our business decisions are consistent with these
values. Employees and contractors are required, on an annual basis, to certify their compliance with our
Statement on Business Conduct.
8
9
LIQUIDS PIPELINES
Liquids Pipelines consists of common carrier and contract pipelines that transport crude oil, natural gas
liquids (NGL) and refined products and terminals in Canada and the United States, including the
Canadian Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Gulf
Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System and other
feeder pipelines.
Maintain Our License to Operate
Earning and sustaining the trust of our stakeholders is critical to our ability to execute on our growth plans
and ensure that our business strategy, as well as our corporate policies and management systems, are
continuously informed by the social and environmental context surrounding our projects and operations. A
key priority is to establish and maintain constructive relationships with local stakeholders over the life-
cycle of our assets. The linear nature of our energy infrastructure puts us in contact with a large number
of diverse communities, landowners and regulatory bodies across North America. Because Indigenous
communities have distinct rights, we have dedicated resources focused on Indigenous consultation and
inclusion. Early identification of local concerns enables us to respond quickly and take a proactive
approach to problem solving. Early engagement also enables us to provide expanded opportunities for
socio-economic participation through employment, training, and procurement, as well as through the
development of joint initiatives on safety, environmental and cultural protection. More broadly, our goal is
to build awareness and balanced dialogue on the role and value of the energy we deliver to our society
and economy. We communicate with different stakeholders, decision makers, customers and other
interested groups - including investors, employees and the public - about the access we provide to safe,
reliable, affordable energy.
We provide annual progress updates related to the above initiatives in our annual CSR Report which can
be found at http://csr.enbridge.com. Unless otherwise specifically stated, none of the information
contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise
part of, this Annual Report on Form 10-K.
Attract, Retain and Develop Highly Capable People
Investing in the attraction, retention and development of employees and future leaders is fundamental to
executing our growth strategy and creating sustainability for future success. We focus on enhancing the
capability of our people to maximize the potential of our organization and undertake various activities
such as offering accelerated leadership development programs, enhancing career opportunities and
building change management capabilities throughout the enterprise so that projects and initiatives
achieve intended benefits. Furthermore, we strive to maintain industry competitive compensation and
retention programs that provide both short-term and long-term performance incentives to our employees.
BUSINESS SEGMENTS
Our activities are carried out through five business segments: Liquids Pipelines; Gas Transmission and
Midstream; Gas Distribution; Green Power and Transmission; and Energy Services, as discussed below.
10
11
LIQUIDS PIPELINES
Liquids Pipelines consists of common carrier and contract pipelines that transport crude oil, natural gas
liquids (NGL) and refined products and terminals in Canada and the United States, including the
Canadian Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Gulf
Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System and other
feeder pipelines.
Maintain Our License to Operate
Earning and sustaining the trust of our stakeholders is critical to our ability to execute on our growth plans
and ensure that our business strategy, as well as our corporate policies and management systems, are
continuously informed by the social and environmental context surrounding our projects and operations. A
key priority is to establish and maintain constructive relationships with local stakeholders over the life-
cycle of our assets. The linear nature of our energy infrastructure puts us in contact with a large number
of diverse communities, landowners and regulatory bodies across North America. Because Indigenous
communities have distinct rights, we have dedicated resources focused on Indigenous consultation and
inclusion. Early identification of local concerns enables us to respond quickly and take a proactive
approach to problem solving. Early engagement also enables us to provide expanded opportunities for
socio-economic participation through employment, training, and procurement, as well as through the
development of joint initiatives on safety, environmental and cultural protection. More broadly, our goal is
to build awareness and balanced dialogue on the role and value of the energy we deliver to our society
and economy. We communicate with different stakeholders, decision makers, customers and other
interested groups - including investors, employees and the public - about the access we provide to safe,
reliable, affordable energy.
We provide annual progress updates related to the above initiatives in our annual CSR Report which can
be found at http://csr.enbridge.com. Unless otherwise specifically stated, none of the information
contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise
part of, this Annual Report on Form 10-K.
Attract, Retain and Develop Highly Capable People
Investing in the attraction, retention and development of employees and future leaders is fundamental to
executing our growth strategy and creating sustainability for future success. We focus on enhancing the
capability of our people to maximize the potential of our organization and undertake various activities
such as offering accelerated leadership development programs, enhancing career opportunities and
building change management capabilities throughout the enterprise so that projects and initiatives
achieve intended benefits. Furthermore, we strive to maintain industry competitive compensation and
retention programs that provide both short-term and long-term performance incentives to our employees.
BUSINESS SEGMENTS
Our activities are carried out through five business segments: Liquids Pipelines; Gas Transmission and
Midstream; Gas Distribution; Green Power and Transmission; and Energy Services, as discussed below.
10
11
Liquids Pipeline
Crude Storage or Terminal
Rail
Trucking Facility
EdmontonEdmontonCalgaryCalgaryHardistyHardistyNew OrleansNew OrleansBuffaloBuffaloSalisburySalisburyGurleyGurleyGuernseyGuernseyCasperCasperEdgarEdgarBuffaloBuffaloChathamChathamWestoverWestoverSarniaSarniaStockbridgeStockbridgeToledoToledoPort ArthurPort ArthurTorontoTorontoFlanaganFlanaganChannahonChannahonChicagoChicagoMontrealMontrealHoustonHoustonSuperiorSuperiorClearbrookClearbrookGretnaGretnaCromerCromerKerrobertKerrobertReginaReginaMinotMinotFortMcMurrayFortMcMurrayCheechamCheechamAthabascaAthabascaZamaZamaNorman WellsNorman WellsPatokaPatokaWood RiverWood RiverCushingCushing
MAINLINE SYSTEM
The mainline system is comprised of the Canadian Mainline and the Lakehead System. The Canadian
Mainline is a common carrier pipeline system which transports various grades of oil and other liquid
hydrocarbons within western Canada and from western Canada to the Canada/United States border near
Gretna, Manitoba and Neche, North Dakota and from the United States/Canada border near Port Huron,
Michigan and Sarnia, Ontario to eastern Canada and the northeastern United States. The Canadian
Mainline includes six adjacent pipelines, with a combined operating capacity of approximately 2.85 million
barrels per day (bpd) that connect with the Lakehead System at the Canada/United States border, as well
as five pipelines that deliver crude oil and refined products into eastern Canada and the northeastern
United States. It also includes certain related pipelines and infrastructure, including decommissioned and
deactivated pipelines. We have operated, and frequently expanded, the Canadian Mainline since 1949.
Effective September 1, 2015, the closing date of the Canadian Restructuring Plan (as defined below), we
transferred the Canadian Mainline to the Fund Group (comprising Enbridge Income Fund (the Fund),
Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries
of EIPLP) - refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Canadian Restructuring Plan. The Lakehead System is the portion of the mainline
system in the United States that continues to be managed by us through our subsidiaries, Enbridge
Energy Partners, L.P. (EEP) and Enbridge Energy, Limited Partnership. It is an interstate common carrier
pipeline system regulated by the Federal Energy Regulatory Commission (FERC), and is the primary
transporter of crude oil and liquid petroleum from Western Canada to the United States.
Competitive Toll Settlement
The Competitive Toll Settlement (CTS) is the current framework governing tolls paid for products shipped
on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis. The
10-year settlement was negotiated by representatives of Enbridge, the Canadian Association of
Petroleum Producers and shippers on the Canadian Mainline. It was approved by the National Energy
Board (NEB) on June 24, 2011 and took effect on July 1, 2011. The CTS provides for a Canadian Local
Toll (CLT) for deliveries within western Canada, which is based on the 2011 Incentive Tolling Settlement
toll, as well as an International Joint Tariff (IJT) for crude oil shipments originating in western Canada on
the Canadian Mainline and delivered into the United States, via the Lakehead System, and into eastern
Canada. These tolls are denominated in United States dollars. The IJT is designed to provide shippers on
the mainline system with a stable and competitive long-term toll, thereby preserving and enhancing
throughput on both the Canadian Mainline and the Lakehead System. The CLT and the IJT were both
established at the time of implementation of the CTS and are adjusted annually, on July 1 of each year, at
a rate equal to 75% of the Canada Gross Domestic Product at Market Price Index published by Statistics
Canada. Two years prior to the end of the term of the CTS, we and the shippers will establish a group for
the purposes of negotiating a new settlement to replace the CTS once it expires.
Although the CTS has a 10-year term, it does not require shippers to commit to certain volumes. Shippers
nominate volumes on a monthly basis and we allocate capacity to maximize the efficiency of the
Canadian Mainline.
Local tolls for service on the Lakehead System are not affected by the CTS and continue to be
established pursuant to the Lakehead System’s existing toll agreements, as described below. Under the
terms of the IJT agreement between us and EEP, the Canadian Mainline’s share of the IJT relating to
pipeline transportation of a batch from any western Canada receipt point to the United States border is
equal to the IJT 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 and is denominated in United States dollars.
Lakehead System Local Tolls
Transportation rates are governed by the FERC for deliveries from the Canada/United States border near
Neche, North Dakota and from Clearbrook, Minnesota to certain principal delivery points. The Lakehead
System periodically adjusts these transportation rates as allowed under the FERC’s index methodology
and tariff agreements, the main components of which are base rates and Facilities Surcharge
Mechanism. Base rates, the base portion of the transportation rates for the Lakehead System, are subject
to an annual adjustment which cannot exceed established ceiling rates as approved by the FERC. The
Facilities Surcharge Mechanism allows the Lakehead System to recover costs associated with certain
shipper-requested projects through an incremental surcharge in addition to the existing base rates, and is
subject to annual adjustment on April 1.
REGIONAL OIL SANDS SYSTEM
The Regional Oil Sands System includes four intra-Alberta long haul pipelines, the Athabasca Pipeline,
Waupisoo Pipeline, Woodland Pipeline and the recently completed Wood Buffalo Extension/Athabasca
Twin pipeline system as well as two large terminals: the Athabasca Terminal located north of Fort
McMurray, Alberta and the Cheecham Terminal, located south of Fort McMurray. The Regional Oil Sands
System also includes numerous laterals and related facilities which provide access for oil sands
production to the system, and a long-haul intra-Alberta pipeline that transports diluent from the Edmonton,
Alberta region into the oil sands producing regions located north and south of Fort McMurray, Alberta. The
Regional Oil Sands System currently serves twelve producing oil sands projects.
The Athabasca Pipeline is a 540-kilometer (335-mile) synthetic and heavy oil pipeline. Built in 1999, it
links the Athabasca oil sands in the Fort McMurray region to the major Alberta crude oil pipeline hub at
Hardisty, Alberta. The Athabasca Pipeline’s capacity is 570,000 bpd, depending on crude slate. We have
long-term take-or-pay and non take-or-pay agreements with multiple shippers on the Athabasca Pipeline.
Revenues are recorded based on the contract terms negotiated with the major shippers, rather than the
cash tolls collected.
In 2017, we completed the twinning of the Athabasca Pipeline and the Wood Buffalo Extension, which
were key components of our Regional Oil Sands Optimization Project. The Athabasca Pipeline Twin,
completed in January 2017, twinned the southern section of the Athabasca Pipeline with a 36-inch
diameter pipeline from Kirby Lake, Alberta to the major Alberta pipeline hub at Hardisty, Alberta. The initial
capacity of the Athabasca Pipeline Twin is 450,000 bpd and it can be further expanded in the future to
800,000 bpd through additional pumping horsepower. In December 2017, the Wood Buffalo Extension, a
36-inch diameter pipeline between Cheecham, Alberta and Kirby Lake, Alberta, went into service. The
integrated Wood Buffalo Extension and Athabasca Pipeline Twin transports diluted bitumen from multiple
oil sands producers.
The Waupisoo Pipeline is a 380-kilometer (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
originates at the Cheecham Terminal and terminates at the major Alberta pipeline hub at Edmonton. The
pipeline has a capacity of 550,000 bpd, depending on the crude slate. We have long-term take-or-pay
agreements with multiple shippers on the Waupisoo Pipeline who have collectively contracted for 80% to
90% of the capacity, subject to the timing of when shippers’ commitments commence and expire.
The Woodland Pipeline is a 50/50 joint venture between us and Imperial Oil Resources Ventures Limited
and ExxonMobil Canada Properties that was constructed in two phases. The first phase, completed in
2013, consists of a 140-kilometer (87-mile) 36-inch diameter pipeline from the Kearl oil sands mine to the
Cheecham Terminal, and service on our existing Waupisoo Pipeline from Cheecham to the Edmonton
area. The second phase extended the Woodland Pipeline south from our Cheecham Terminal to our
Edmonton Terminal. Completed in 2014, the extension involved the construction of a 385-kilometer (239-
mile) 36-inch diameter pipeline adding 379,000 bpd of capacity to the Regional Oil Sands System. The
Woodland Pipeline is anchored by long-term commitments.
12
13
MAINLINE SYSTEM
The mainline system is comprised of the Canadian Mainline and the Lakehead System. The Canadian
Mainline is a common carrier pipeline system which transports various grades of oil and other liquid
hydrocarbons within western Canada and from western Canada to the Canada/United States border near
Gretna, Manitoba and Neche, North Dakota and from the United States/Canada border near Port Huron,
Michigan and Sarnia, Ontario to eastern Canada and the northeastern United States. The Canadian
Mainline includes six adjacent pipelines, with a combined operating capacity of approximately 2.85 million
barrels per day (bpd) that connect with the Lakehead System at the Canada/United States border, as well
as five pipelines that deliver crude oil and refined products into eastern Canada and the northeastern
United States. It also includes certain related pipelines and infrastructure, including decommissioned and
deactivated pipelines. We have operated, and frequently expanded, the Canadian Mainline since 1949.
Effective September 1, 2015, the closing date of the Canadian Restructuring Plan (as defined below), we
transferred the Canadian Mainline to the Fund Group (comprising Enbridge Income Fund (the Fund),
Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries
of EIPLP) - refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Canadian Restructuring Plan. The Lakehead System is the portion of the mainline
system in the United States that continues to be managed by us through our subsidiaries, Enbridge
Energy Partners, L.P. (EEP) and Enbridge Energy, Limited Partnership. It is an interstate common carrier
pipeline system regulated by the Federal Energy Regulatory Commission (FERC), and is the primary
transporter of crude oil and liquid petroleum from Western Canada to the United States.
Competitive Toll Settlement
The Competitive Toll Settlement (CTS) is the current framework governing tolls paid for products shipped
on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis. The
10-year settlement was negotiated by representatives of Enbridge, the Canadian Association of
Petroleum Producers and shippers on the Canadian Mainline. It was approved by the National Energy
Board (NEB) on June 24, 2011 and took effect on July 1, 2011. The CTS provides for a Canadian Local
Toll (CLT) for deliveries within western Canada, which is based on the 2011 Incentive Tolling Settlement
toll, as well as an International Joint Tariff (IJT) for crude oil shipments originating in western Canada on
the Canadian Mainline and delivered into the United States, via the Lakehead System, and into eastern
Canada. These tolls are denominated in United States dollars. The IJT is designed to provide shippers on
the mainline system with a stable and competitive long-term toll, thereby preserving and enhancing
throughput on both the Canadian Mainline and the Lakehead System. The CLT and the IJT were both
established at the time of implementation of the CTS and are adjusted annually, on July 1 of each year, at
a rate equal to 75% of the Canada Gross Domestic Product at Market Price Index published by Statistics
Canada. Two years prior to the end of the term of the CTS, we and the shippers will establish a group for
the purposes of negotiating a new settlement to replace the CTS once it expires.
Although the CTS has a 10-year term, it does not require shippers to commit to certain volumes. Shippers
nominate volumes on a monthly basis and we allocate capacity to maximize the efficiency of the
Canadian Mainline.
Local tolls for service on the Lakehead System are not affected by the CTS and continue to be
established pursuant to the Lakehead System’s existing toll agreements, as described below. Under the
terms of the IJT agreement between us and EEP, the Canadian Mainline’s share of the IJT relating to
pipeline transportation of a batch from any western Canada receipt point to the United States border is
equal to the IJT 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 and is denominated in United States dollars.
Lakehead System Local Tolls
Transportation rates are governed by the FERC for deliveries from the Canada/United States border near
Neche, North Dakota and from Clearbrook, Minnesota to certain principal delivery points. The Lakehead
System periodically adjusts these transportation rates as allowed under the FERC’s index methodology
and tariff agreements, the main components of which are base rates and Facilities Surcharge
Mechanism. Base rates, the base portion of the transportation rates for the Lakehead System, are subject
to an annual adjustment which cannot exceed established ceiling rates as approved by the FERC. The
Facilities Surcharge Mechanism allows the Lakehead System to recover costs associated with certain
shipper-requested projects through an incremental surcharge in addition to the existing base rates, and is
subject to annual adjustment on April 1.
REGIONAL OIL SANDS SYSTEM
The Regional Oil Sands System includes four intra-Alberta long haul pipelines, the Athabasca Pipeline,
Waupisoo Pipeline, Woodland Pipeline and the recently completed Wood Buffalo Extension/Athabasca
Twin pipeline system as well as two large terminals: the Athabasca Terminal located north of Fort
McMurray, Alberta and the Cheecham Terminal, located south of Fort McMurray. The Regional Oil Sands
System also includes numerous laterals and related facilities which provide access for oil sands
production to the system, and a long-haul intra-Alberta pipeline that transports diluent from the Edmonton,
Alberta region into the oil sands producing regions located north and south of Fort McMurray, Alberta. The
Regional Oil Sands System currently serves twelve producing oil sands projects.
The Athabasca Pipeline is a 540-kilometer (335-mile) synthetic and heavy oil pipeline. Built in 1999, it
links the Athabasca oil sands in the Fort McMurray region to the major Alberta crude oil pipeline hub at
Hardisty, Alberta. The Athabasca Pipeline’s capacity is 570,000 bpd, depending on crude slate. We have
long-term take-or-pay and non take-or-pay agreements with multiple shippers on the Athabasca Pipeline.
Revenues are recorded based on the contract terms negotiated with the major shippers, rather than the
cash tolls collected.
In 2017, we completed the twinning of the Athabasca Pipeline and the Wood Buffalo Extension, which
were key components of our Regional Oil Sands Optimization Project. The Athabasca Pipeline Twin,
completed in January 2017, twinned the southern section of the Athabasca Pipeline with a 36-inch
diameter pipeline from Kirby Lake, Alberta to the major Alberta pipeline hub at Hardisty, Alberta. The initial
capacity of the Athabasca Pipeline Twin is 450,000 bpd and it can be further expanded in the future to
800,000 bpd through additional pumping horsepower. In December 2017, the Wood Buffalo Extension, a
36-inch diameter pipeline between Cheecham, Alberta and Kirby Lake, Alberta, went into service. The
integrated Wood Buffalo Extension and Athabasca Pipeline Twin transports diluted bitumen from multiple
oil sands producers.
The Waupisoo Pipeline is a 380-kilometer (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
originates at the Cheecham Terminal and terminates at the major Alberta pipeline hub at Edmonton. The
pipeline has a capacity of 550,000 bpd, depending on the crude slate. We have long-term take-or-pay
agreements with multiple shippers on the Waupisoo Pipeline who have collectively contracted for 80% to
90% of the capacity, subject to the timing of when shippers’ commitments commence and expire.
The Woodland Pipeline is a 50/50 joint venture between us and Imperial Oil Resources Ventures Limited
and ExxonMobil Canada Properties that was constructed in two phases. The first phase, completed in
2013, consists of a 140-kilometer (87-mile) 36-inch diameter pipeline from the Kearl oil sands mine to the
Cheecham Terminal, and service on our existing Waupisoo Pipeline from Cheecham to the Edmonton
area. The second phase extended the Woodland Pipeline south from our Cheecham Terminal to our
Edmonton Terminal. Completed in 2014, the extension involved the construction of a 385-kilometer (239-
mile) 36-inch diameter pipeline adding 379,000 bpd of capacity to the Regional Oil Sands System. The
Woodland Pipeline is anchored by long-term commitments.
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The Norlite Pipeline System (Norlite) was placed into service in May 2017, offering a new diluent supply
alternative to meet the needs of multiple producers in the Athabasca oil sands region. Norlite is a 24-inch-
diameter pipeline, originating at Enbridge’s Stonefell Terminal, in Strathcona County near Edmonton,
Alberta and terminating at Enbridge’s Fort McMurray South facility, near Fort McMurray, Alberta, with a
transfer line to Suncor's East Tank Farm. The pipeline has a capacity of approximately 218,000 bpd of
diluent, with the potential to be further expanded to approximately 465,000 bpd of capacity with the
addition of pump stations. Under an agreement with Keyera Corp. (Keyera), Norlite has the right to
access certain existing capacity on Keyera’s pipelines between Edmonton, Alberta and Stonefell, Alberta
and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30%
non-operating owner. Norlite is anchored by long-term throughput commitments from a number of oil
sands producers.
GULF COAST AND MID-CONTINENT
Gulf Coast includes Seaway and Flanagan South Pipeline (Flanagan South), Spearhead Pipeline, as well
as the Mid-Continent System comprised of Cushing Terminal and the recently sold Ozark Pipeline that is
managed by us through our subsidiary, EEP.
Seaway Pipeline
In 2011, we acquired a 50% interest in the 1,078-kilometer (670-mile) Seaway Crude Pipeline System
(Seaway Pipeline), including the 805-kilometer (500-mile), 30-inch diameter long-haul system between
Cushing, Oklahoma and Freeport, Texas, as well as the Texas City Terminal and Distribution System
which serve refineries in the Houston and Texas City areas. Seaway Pipeline also includes 8.8 million
barrels of crude oil storage tank capacity on the Texas Gulf Coast.
The flow direction of Seaway Pipeline was reversed in 2012, enabling it to transport crude from the
oversupplied hub in Cushing, Oklahoma to the Gulf Coast. Further pump station additions and
modifications were completed early 2013, increasing capacity available to shippers from an initial 150,000
bpd to up to approximately 400,000 bpd, depending on the crude slate. In late 2014, a second line, the
Seaway Pipeline Twin, was placed into service to more than double the existing capacity to 850,000 bpd.
Seaway Pipeline also includes a 161-kilometer (100-mile) pipeline from the Enterprise Crude Houston
crude oil terminal in Houston, Texas to the Port Arthur/Beaumont, Texas refining center.
Flanagan South Pipeline
Flanagan South is a 950-kilometer (590-mile), 36-inch diameter interstate crude oil pipeline that originates
at our terminal at Flanagan, Illinois and terminates in Cushing, Oklahoma. Flanagan South and
associated pumping stations were completed in the fourth quarter of 2014. Flanagan South has an initial
design capacity of approximately 600,000 bpd.
Spearhead Pipeline
Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point
on the Lakehead System to Cushing, Oklahoma. The Spearhead pipeline was originally placed into
service in 2006 and has an initial capacity of 193,300 bpd.
Mid-Continent System
The Mid-Continent System is comprised of the storage terminals at Cushing, Oklahoma and the recently
sold Ozark Pipeline. The storage terminals consist of over 80 individual storage tanks ranging in size from
78,000 to 570,000 barrels. Total storage shell capacity of Cushing Terminal is approximately 20 million
barrels. A portion of the storage facilities are used for operational purposes, while the remainder is
contracted to various crude oil market participants for their term storage requirements. Contract fees
include fixed monthly storage fees, throughput fees for receiving and delivering crude to and from
connecting pipelines and terminals, and blending fees.
In December 2016, we entered into an agreement to sell the Ozark Pipeline to a subsidiary of MPLX LP
for cash proceeds of approximately $294 million (US$220 million), including $13 million (US$10 million) in
reimbursable costs for additional capital spent by us up to the closing date of the transaction. Sale of the
Ozark Pipeline system closed on March 1, 2017.
SOUTHERN LIGHTS PIPELINE
Southern Lights Pipeline is a fully-contracted single stream pipeline that ships diluent from the Manhattan
Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and
Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. This 180,000 bpd 16/18/20-inch
diameter pipeline was placed into service in 2010. Both the Canadian portion of Southern Lights Pipeline
(Southern Lights Canada) and the United States portion of Southern Lights Pipeline (Southern Lights US)
receive 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%. Southern Lights Pipeline has
assigned 10% of the capacity (18,000 bpd) for shippers to ship uncommitted volumes.
As part of the Canadian Restructuring Plan, effective September 1, 2015, we transferred all Class B units
of Southern Lights Canada to the Fund Group. Following the closing of the Transaction, the Fund Group
holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights
Canada. We continue to indirectly own all of the Class B Units of Southern Lights US.
EXPRESS-PLATTE SYSTEM
The Express-Platte system is comprised of both the Express pipeline and the Platte pipeline, and crude
oil storage of approximately 5.6 million barrels. It is an approximate 2,736-kilometer (1,700-mile) crude oil
transportation system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois. The
Express pipeline carries crude oil to United States refining markets in the Rockies area, including
Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express
pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western
Canada to refineries in the Midwest. Express pipeline capacity is typically committed under long-term
take-or-pay contracts with shippers. A small portion of Express pipeline capacity and all of the Platte
pipeline capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually
use in a given month.
BAKKEN SYSTEM
Our Bakken assets consist of the North Dakota System and the Bakken Pipeline System. The North
Dakota System is a joint operation that includes a Canadian entity and a United States entity. The United
States portion of the North Dakota System is comprised of a crude oil gathering and interstate pipeline
transportation system servicing the Williston Basin in North Dakota and Montana, which includes the
Bakken and Three Forks formation. The gathering pipelines collect crude oil from nearly 80 different
receipt facilities located throughout western North Dakota and eastern Montana, with delivery to
Clearbrook for service on the Lakehead system or a variety of interconnecting pipeline and rail export
facilities. The United States interstate portion of the system extends from Berthold, North Dakota to the
International Boundary near North Portal, North Dakota, and connects to the Canadian entity at the
border to bring the crude oil into Cromer, Manitoba.
Tariffs on the United States portion of the North Dakota System are governed by FERC and include a
local tariff. The Canadian portion is categorized as a Group 2 pipeline, and as such its tolls are regulated
by the NEB on a complaint basis. Tolls are based on long-term take-or-pay agreements with anchor
shippers.
In February 2017, we closed a transaction to acquire a 49% equity interest in the holding company that
owns 75% of the Bakken Pipeline System from an affiliate of Energy Transfer Partners, L.P. and Sunoco
Logistics Partners, L.P. The Bakken Pipeline System connects the prolific Bakken formation in North
Dakota to markets in eastern PADD II and the United States Gulf Coast, providing customers with access
to premium markets at a competitive cost. The Bakken Pipeline System consists of the Dakota Access
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The Norlite Pipeline System (Norlite) was placed into service in May 2017, offering a new diluent supply
alternative to meet the needs of multiple producers in the Athabasca oil sands region. Norlite is a 24-inch-
diameter pipeline, originating at Enbridge’s Stonefell Terminal, in Strathcona County near Edmonton,
Alberta and terminating at Enbridge’s Fort McMurray South facility, near Fort McMurray, Alberta, with a
transfer line to Suncor's East Tank Farm. The pipeline has a capacity of approximately 218,000 bpd of
diluent, with the potential to be further expanded to approximately 465,000 bpd of capacity with the
addition of pump stations. Under an agreement with Keyera Corp. (Keyera), Norlite has the right to
access certain existing capacity on Keyera’s pipelines between Edmonton, Alberta and Stonefell, Alberta
and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30%
non-operating owner. Norlite is anchored by long-term throughput commitments from a number of oil
sands producers.
GULF COAST AND MID-CONTINENT
Gulf Coast includes Seaway and Flanagan South Pipeline (Flanagan South), Spearhead Pipeline, as well
as the Mid-Continent System comprised of Cushing Terminal and the recently sold Ozark Pipeline that is
managed by us through our subsidiary, EEP.
Seaway Pipeline
In 2011, we acquired a 50% interest in the 1,078-kilometer (670-mile) Seaway Crude Pipeline System
(Seaway Pipeline), including the 805-kilometer (500-mile), 30-inch diameter long-haul system between
Cushing, Oklahoma and Freeport, Texas, as well as the Texas City Terminal and Distribution System
which serve refineries in the Houston and Texas City areas. Seaway Pipeline also includes 8.8 million
barrels of crude oil storage tank capacity on the Texas Gulf Coast.
The flow direction of Seaway Pipeline was reversed in 2012, enabling it to transport crude from the
oversupplied hub in Cushing, Oklahoma to the Gulf Coast. Further pump station additions and
modifications were completed early 2013, increasing capacity available to shippers from an initial 150,000
bpd to up to approximately 400,000 bpd, depending on the crude slate. In late 2014, a second line, the
Seaway Pipeline Twin, was placed into service to more than double the existing capacity to 850,000 bpd.
Seaway Pipeline also includes a 161-kilometer (100-mile) pipeline from the Enterprise Crude Houston
crude oil terminal in Houston, Texas to the Port Arthur/Beaumont, Texas refining center.
Flanagan South Pipeline
Flanagan South is a 950-kilometer (590-mile), 36-inch diameter interstate crude oil pipeline that originates
at our terminal at Flanagan, Illinois and terminates in Cushing, Oklahoma. Flanagan South and
associated pumping stations were completed in the fourth quarter of 2014. Flanagan South has an initial
design capacity of approximately 600,000 bpd.
Spearhead Pipeline
Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point
on the Lakehead System to Cushing, Oklahoma. The Spearhead pipeline was originally placed into
service in 2006 and has an initial capacity of 193,300 bpd.
Mid-Continent System
The Mid-Continent System is comprised of the storage terminals at Cushing, Oklahoma and the recently
sold Ozark Pipeline. The storage terminals consist of over 80 individual storage tanks ranging in size from
78,000 to 570,000 barrels. Total storage shell capacity of Cushing Terminal is approximately 20 million
barrels. A portion of the storage facilities are used for operational purposes, while the remainder is
contracted to various crude oil market participants for their term storage requirements. Contract fees
include fixed monthly storage fees, throughput fees for receiving and delivering crude to and from
connecting pipelines and terminals, and blending fees.
In December 2016, we entered into an agreement to sell the Ozark Pipeline to a subsidiary of MPLX LP
for cash proceeds of approximately $294 million (US$220 million), including $13 million (US$10 million) in
reimbursable costs for additional capital spent by us up to the closing date of the transaction. Sale of the
Ozark Pipeline system closed on March 1, 2017.
SOUTHERN LIGHTS PIPELINE
Southern Lights Pipeline is a fully-contracted single stream pipeline that ships diluent from the Manhattan
Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and
Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. This 180,000 bpd 16/18/20-inch
diameter pipeline was placed into service in 2010. Both the Canadian portion of Southern Lights Pipeline
(Southern Lights Canada) and the United States portion of Southern Lights Pipeline (Southern Lights US)
receive 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%. Southern Lights Pipeline has
assigned 10% of the capacity (18,000 bpd) for shippers to ship uncommitted volumes.
As part of the Canadian Restructuring Plan, effective September 1, 2015, we transferred all Class B units
of Southern Lights Canada to the Fund Group. Following the closing of the Transaction, the Fund Group
holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights
Canada. We continue to indirectly own all of the Class B Units of Southern Lights US.
EXPRESS-PLATTE SYSTEM
The Express-Platte system is comprised of both the Express pipeline and the Platte pipeline, and crude
oil storage of approximately 5.6 million barrels. It is an approximate 2,736-kilometer (1,700-mile) crude oil
transportation system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois. The
Express pipeline carries crude oil to United States refining markets in the Rockies area, including
Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express
pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western
Canada to refineries in the Midwest. Express pipeline capacity is typically committed under long-term
take-or-pay contracts with shippers. A small portion of Express pipeline capacity and all of the Platte
pipeline capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually
use in a given month.
BAKKEN SYSTEM
Our Bakken assets consist of the North Dakota System and the Bakken Pipeline System. The North
Dakota System is a joint operation that includes a Canadian entity and a United States entity. The United
States portion of the North Dakota System is comprised of a crude oil gathering and interstate pipeline
transportation system servicing the Williston Basin in North Dakota and Montana, which includes the
Bakken and Three Forks formation. The gathering pipelines collect crude oil from nearly 80 different
receipt facilities located throughout western North Dakota and eastern Montana, with delivery to
Clearbrook for service on the Lakehead system or a variety of interconnecting pipeline and rail export
facilities. The United States interstate portion of the system extends from Berthold, North Dakota to the
International Boundary near North Portal, North Dakota, and connects to the Canadian entity at the
border to bring the crude oil into Cromer, Manitoba.
Tariffs on the United States portion of the North Dakota System are governed by FERC and include a
local tariff. The Canadian portion is categorized as a Group 2 pipeline, and as such its tolls are regulated
by the NEB on a complaint basis. Tolls are based on long-term take-or-pay agreements with anchor
shippers.
In February 2017, we closed a transaction to acquire a 49% equity interest in the holding company that
owns 75% of the Bakken Pipeline System from an affiliate of Energy Transfer Partners, L.P. and Sunoco
Logistics Partners, L.P. The Bakken Pipeline System connects the prolific Bakken formation in North
Dakota to markets in eastern PADD II and the United States Gulf Coast, providing customers with access
to premium markets at a competitive cost. The Bakken Pipeline System consists of the Dakota Access
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15
Pipeline and the Energy Transfer Crude Oil Pipeline projects. The Dakota Access Pipeline consists of
1,886-kilometers (1,172-miles) of 30-inch pipe from the Bakken/Three Forks production area in North
Dakota to Patoka, Illinois. Initial capacity is in excess of 470,000 bpd of crude oil with the potential to be
expanded to 570,000 bpd. The Energy Transfer Crude Oil Pipeline consists of 100-kilometers (62-miles)
of new 30-inch diameter pipe, 1,104-kilometers (686-miles) of converted 30-inch diameter pipe, and 64-
kilometers (40-miles) of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas. The
Bakken Pipeline System is anchored by long-term throughput commitments from a number of producers.
FEEDER PIPELINES AND OTHER
Feeder Pipelines and Other includes a number of liquids storage assets and pipeline systems in Canada
and the United States.
Key assets included in Feeder Pipelines and Other are the Hardisty Contract Terminal and Hardisty
Storage Caverns located near Hardisty, Alberta, a key crude oil pipeline hub in western Canada and
Southern Access Extension (SAX) pipeline which originates out of Flanagan, Illinois and delivers to
Patoka, Illinois. On July 1, 2014, Marathon executed an agreement with Enbridge to become an owner
(35%) in SAX forming the Illinois Extension Pipeline Company (IEPC). Enbridge has 65% ownership in
IEPC. SAX was placed into service December 2015 with the majority of its capacity commercially secured
under long-term take-or-pay contracts with shippers.
Feeder Pipelines and Other also includes Patoka Storage, the Toledo pipeline system and the NW
System. Patoka Storage is comprised of 4 storage tanks with 480,000 barrels of shell capacity located in
Patoka, Illinois. The Toledo pipeline system connects with the Lakehead System and delivers to Ohio and
Michigan. The majority of Toledo pipeline’s capacity is commercially secured under long-term take-or-pay
contracts with shippers. The NW System transports crude oil from Norman Wells in the Northwest
Territories to Zama, Alberta. NW System has a cost of service rate structure based on established terms
with shippers.
Feeder Pipelines and Other includes contributions from assets which were divested during 2017 and the
fourth quarter of 2016, including investments in Olympic Pipeline Company (Olympic), Eddystone Rail
and the South Prairie Region assets.
On October 19, 2017, we sold all assets related to our Eddystone rail facility to our partner Canopy in
exchange for their 25% share of the joint venture valued at $5 million. These assets primarily included the
unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania that
delivered Bakken and other light sweet crude oil to Philadelphia area refineries.
On July 31, 2017, we completed the sale of our 85% interest in Olympic, the largest refined products
pipeline in the State of Washington, to an unrelated party for $0.2 billion.
On December 1, 2016, EIPLP completed the sale of the South Prairie Region assets to an unrelated party
for cash proceeds of $1.08 billion. The South Prairie Region assets transport crude oil and NGL from
producing fields and facilities in southeastern Saskatchewan and southwestern Manitoba to Cromer,
Manitoba where products enter the mainline system to be transported to the United States or eastern
Canada.
COMPETITION
Competition may result in a reduction in demand for our services, fewer 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 available to ship western Canadian liquid hydrocarbons to markets in Canada,
the United States and internationally represent competition to our liquids pipelines network. Competition
also arises from proposed pipelines that seek to access markets currently served by our liquids pipelines,
such as proposed projects to the Gulf Coast and from proposed projects enhancing infrastructure in the
Alberta regional oil sands market. The Mid-Continent and Bakken systems also face competition from
existing competing pipelines, proposed future pipelines and existing and alternative gathering facilities.
Competition for storage facilities in the United States includes large integrated oil companies and other
midstream energy partnerships. Additionally, volatile crude price differentials and insufficient pipeline
capacity on either our or other competitor pipelines can make transportation of crude oil by rail
competitive, particularly to markets not currently serviced by pipelines.
We believe that our liquids pipelines continue to provide attractive options to producers in the Western
Canadian Sedimentary Basin (WCSB) and North Dakota due to our competitive tolls and flexibility
through our multiple delivery and storage points. Our current complement of growth projects to expand
market access and to enhance capacity on our pipeline system combined with our commitment to project
execution is expected to further provide shippers reliable and long-term competitive solutions for oil
transportation. Our existing right-of-way for the mainline system also provides a competitive advantage as
it can be difficult and costly to obtain rights of way for new pipelines traversing new areas. We also
employ long-term agreements with shippers, which also mitigate competition risk by ensuring consistent
supply to our liquids pipelines network.
SUPPLY AND DEMAND
We have 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 our infrastructure for the foreseeable future, North American and global crude oil
supply and demand fundamentals are shifting, and we have a 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.
The downturn in crude oil prices which began in 2014 has impacted our liquids pipelines’ customers, who
responded by reducing their exploration and development spending for 2016 and 2017 in higher cost
basins. However, the international market for crude oil has continued to see an increase in production
from the North American shale oil producing basins and increased production from specific Organization
of Petroleum Exporting Countries (OPEC). The West Texas Intermediate (WTI) crude price has been
strengthening from US$30 per barrel at the beginning of 2016 as the market has fought to re-balance
supply and demand. Prices began to recover in response to cuts in OPEC and non-OPEC production and
have continued to recover through 2017. The WTI crude prices averaged US$51 per barrel for 2017 and
ended the year above US$60 per barrel.
Notwithstanding the current price environment, our mainline system has thus far continued to be highly
utilized and in fact, mainline throughput as measured at the Canada/United States border at Gretna,
Manitoba saw record throughput of 2.7 million bpd in December 2017. The mainline system continues to
be subject to apportionment of heavy crude oil, as nominated volumes currently exceed capacity on
portions of the system. The impact of a low crude oil price environment on the financial performance of
our liquids pipelines business is expected to be relatively modest given the commercial arrangements
which underpin many of the pipelines that make up our liquids system and provide a significant measure
of protection against volume fluctuations. In addition, our mainline system is well positioned to continue to
provide safe and efficient transportation which will enable western Canadian and Bakken production to
reach attractive markets in the United States and eastern Canada at a competitive cost relative to other
alternatives. The fundamentals of oil sands production and low crude oil prices have caused some
sponsors to reconsider the timing of their upstream oil sands development projects. However, recently
updated forecasts continue to reflect long-term supply growth from the WCSB, although the projected
pace of growth is slower than previous forecasts as companies continue to assess the viability of certain
capital investments in the current price environment and with the ongoing uncertainty related to timing
and completion of competing pipeline systems.
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Pipeline and the Energy Transfer Crude Oil Pipeline projects. The Dakota Access Pipeline consists of
1,886-kilometers (1,172-miles) of 30-inch pipe from the Bakken/Three Forks production area in North
Dakota to Patoka, Illinois. Initial capacity is in excess of 470,000 bpd of crude oil with the potential to be
expanded to 570,000 bpd. The Energy Transfer Crude Oil Pipeline consists of 100-kilometers (62-miles)
of new 30-inch diameter pipe, 1,104-kilometers (686-miles) of converted 30-inch diameter pipe, and 64-
kilometers (40-miles) of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas. The
Bakken Pipeline System is anchored by long-term throughput commitments from a number of producers.
Feeder Pipelines and Other includes a number of liquids storage assets and pipeline systems in Canada
FEEDER PIPELINES AND OTHER
and the United States.
Key assets included in Feeder Pipelines and Other are the Hardisty Contract Terminal and Hardisty
Storage Caverns located near Hardisty, Alberta, a key crude oil pipeline hub in western Canada and
Southern Access Extension (SAX) pipeline which originates out of Flanagan, Illinois and delivers to
Patoka, Illinois. On July 1, 2014, Marathon executed an agreement with Enbridge to become an owner
(35%) in SAX forming the Illinois Extension Pipeline Company (IEPC). Enbridge has 65% ownership in
IEPC. SAX was placed into service December 2015 with the majority of its capacity commercially secured
under long-term take-or-pay contracts with shippers.
Feeder Pipelines and Other also includes Patoka Storage, the Toledo pipeline system and the NW
System. Patoka Storage is comprised of 4 storage tanks with 480,000 barrels of shell capacity located in
Patoka, Illinois. The Toledo pipeline system connects with the Lakehead System and delivers to Ohio and
Michigan. The majority of Toledo pipeline’s capacity is commercially secured under long-term take-or-pay
contracts with shippers. The NW System transports crude oil from Norman Wells in the Northwest
Territories to Zama, Alberta. NW System has a cost of service rate structure based on established terms
with shippers.
Feeder Pipelines and Other includes contributions from assets which were divested during 2017 and the
fourth quarter of 2016, including investments in Olympic Pipeline Company (Olympic), Eddystone Rail
and the South Prairie Region assets.
On October 19, 2017, we sold all assets related to our Eddystone rail facility to our partner Canopy in
exchange for their 25% share of the joint venture valued at $5 million. These assets primarily included the
unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania that
delivered Bakken and other light sweet crude oil to Philadelphia area refineries.
On July 31, 2017, we completed the sale of our 85% interest in Olympic, the largest refined products
pipeline in the State of Washington, to an unrelated party for $0.2 billion.
On December 1, 2016, EIPLP completed the sale of the South Prairie Region assets to an unrelated party
for cash proceeds of $1.08 billion. The South Prairie Region assets transport crude oil and NGL from
producing fields and facilities in southeastern Saskatchewan and southwestern Manitoba to Cromer,
Manitoba where products enter the mainline system to be transported to the United States or eastern
Canada.
COMPETITION
Competition may result in a reduction in demand for our services, fewer 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 available to ship western Canadian liquid hydrocarbons to markets in Canada,
the United States and internationally represent competition to our liquids pipelines network. Competition
also arises from proposed pipelines that seek to access markets currently served by our liquids pipelines,
such as proposed projects to the Gulf Coast and from proposed projects enhancing infrastructure in the
Alberta regional oil sands market. The Mid-Continent and Bakken systems also face competition from
existing competing pipelines, proposed future pipelines and existing and alternative gathering facilities.
Competition for storage facilities in the United States includes large integrated oil companies and other
midstream energy partnerships. Additionally, volatile crude price differentials and insufficient pipeline
capacity on either our or other competitor pipelines can make transportation of crude oil by rail
competitive, particularly to markets not currently serviced by pipelines.
We believe that our liquids pipelines continue to provide attractive options to producers in the Western
Canadian Sedimentary Basin (WCSB) and North Dakota due to our competitive tolls and flexibility
through our multiple delivery and storage points. Our current complement of growth projects to expand
market access and to enhance capacity on our pipeline system combined with our commitment to project
execution is expected to further provide shippers reliable and long-term competitive solutions for oil
transportation. Our existing right-of-way for the mainline system also provides a competitive advantage as
it can be difficult and costly to obtain rights of way for new pipelines traversing new areas. We also
employ long-term agreements with shippers, which also mitigate competition risk by ensuring consistent
supply to our liquids pipelines network.
SUPPLY AND DEMAND
We have 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 our infrastructure for the foreseeable future, North American and global crude oil
supply and demand fundamentals are shifting, and we have a 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.
The downturn in crude oil prices which began in 2014 has impacted our liquids pipelines’ customers, who
responded by reducing their exploration and development spending for 2016 and 2017 in higher cost
basins. However, the international market for crude oil has continued to see an increase in production
from the North American shale oil producing basins and increased production from specific Organization
of Petroleum Exporting Countries (OPEC). The West Texas Intermediate (WTI) crude price has been
strengthening from US$30 per barrel at the beginning of 2016 as the market has fought to re-balance
supply and demand. Prices began to recover in response to cuts in OPEC and non-OPEC production and
have continued to recover through 2017. The WTI crude prices averaged US$51 per barrel for 2017 and
ended the year above US$60 per barrel.
Notwithstanding the current price environment, our mainline system has thus far continued to be highly
utilized and in fact, mainline throughput as measured at the Canada/United States border at Gretna,
Manitoba saw record throughput of 2.7 million bpd in December 2017. The mainline system continues to
be subject to apportionment of heavy crude oil, as nominated volumes currently exceed capacity on
portions of the system. The impact of a low crude oil price environment on the financial performance of
our liquids pipelines business is expected to be relatively modest given the commercial arrangements
which underpin many of the pipelines that make up our liquids system and provide a significant measure
of protection against volume fluctuations. In addition, our mainline system is well positioned to continue to
provide safe and efficient transportation which will enable western Canadian and Bakken production to
reach attractive markets in the United States and eastern Canada at a competitive cost relative to other
alternatives. The fundamentals of oil sands production and low crude oil prices have caused some
sponsors to reconsider the timing of their upstream oil sands development projects. However, recently
updated forecasts continue to reflect long-term supply growth from the WCSB, although the projected
pace of growth is slower than previous forecasts as companies continue to assess the viability of certain
capital investments in the current price environment and with the ongoing uncertainty related to timing
and completion of competing pipeline systems.
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17
GAS TRANSMISSION & MIDSTREAM
Gas Transmission and Midstream (formerly referred to as Gas Pipelines and Processing) consists of our
investments in natural gas pipelines and gathering and processing facilities in Canada and the United States,
including US Gas Transmission, Canadian Gas Transmission and Midstream, Alliance Pipeline, US
Midstream and other assets.
Over the long term, global energy consumption is expected to continue to grow, with the growth in crude
oil demand primarily driven by emerging economies in regions outside the Organization for Economic
Cooperation and Development (OECD), mainly India and China. While OECD countries, including
Canada, the United States and western European nations, will experience population growth, the
emphasis placed on energy efficiency, conservation and a shift to lower carbon fuels, such as natural gas
and renewables, is expected to reduce crude oil demand over the long term. Accordingly, there is a
strategic opportunity for North American producers to grow production to displace foreign imports and
participate in the growing global demand outside North America.
In terms of supply, long-term global crude oil production is expected to continue to grow through 2035,
with growth in supply primarily contributed by North America, Brazil and OPEC. The expected growth in
North America is largely driven by production from the oil sands and the continued development of tight
oil plays including the Permian, Bakken and Eagle Ford formations. Growth in supply from OPEC is
primarily a result of a shift in OPEC’s strategy from ‘balancing supply’ to ‘competing for market share’ in
Asia and Europe. However, political uncertainty in certain oil producing countries, including Venezuela,
Libya, Nigeria and Iraq, increases risk in those regions’ supply growth forecasts and makes North
America one of the most secure supply sources of crude oil. As witnessed throughout 2016 and 2017,
North American supply growth can be influenced by macro-economic factors that drive down the global
crude prices. Over the longer term, North American production from tight oil plays, including the Bakken,
is expected to grow as technology continues to improve well productivity and efficiencies. The WCSB, in
Canada, is viewed as one of the world’s largest and most secure supply sources of crude oil. However,
the pace of growth in North America and level of investment in the WCSB could be tempered in future
years by a number of factors including a sustained period of low crude oil prices and corresponding
production decisions by OPEC, increasing environmental regulation, and prolonged approval processes
for new pipelines with access to tide-water for export.
In recent years, the combination of relatively flat domestic demand, growing supply and long-lead time to
build pipeline infrastructure led to a fundamental change in the North American crude oil landscape. The
inability to move increasing inland supply to tide-water markets resulted in a divergence between 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 resulted in a further discounting of
Alberta crude against WTI. With a number of market access initiatives completed by the industry in recent
years, including those introduced by us, the crude oil price differentials significantly narrowed in 2015, and
resulted in higher netbacks for producers. The capacity from these initiatives was for the most part
exhausted by the end of 2017 from growth in the Oil Sands and has resulted in crude differentials
widening once more. Canadian pipeline export capacity is expected to remain essentially full, resulting in
incremental production utilizing non-pipeline transportation services until such time as pipeline capacity is
made available. As the supply in North America continues to grow, the growth and flexibility of pipeline
infrastructure will need to keep pace with the sensitive demand and supply balance. Over the longer term,
we believe pipelines will continue to be the most cost-effective means of transportation in markets where
the differential between North American and global oil prices remain narrow. Utilization of rail to transport
crude is expected to be substantially limited to those markets not readily accessible by pipelines.
Our role in helping to address the evolving supply and demand fundamentals and alleviating price
discounts for producers and supply costs to refiners is to provide expanded pipeline capacity and
sustainable connectivity to alternative markets. As discussed in Part II. Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured
Projects, in 2017, we continue to execute our growth projects plan in furtherance of this objective.
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19
Over the long term, global energy consumption is expected to continue to grow, with the growth in crude
oil demand primarily driven by emerging economies in regions outside the Organization for Economic
Cooperation and Development (OECD), mainly India and China. While OECD countries, including
Canada, the United States and western European nations, will experience population growth, the
emphasis placed on energy efficiency, conservation and a shift to lower carbon fuels, such as natural gas
and renewables, is expected to reduce crude oil demand over the long term. Accordingly, there is a
strategic opportunity for North American producers to grow production to displace foreign imports and
participate in the growing global demand outside North America.
In terms of supply, long-term global crude oil production is expected to continue to grow through 2035,
with growth in supply primarily contributed by North America, Brazil and OPEC. The expected growth in
North America is largely driven by production from the oil sands and the continued development of tight
oil plays including the Permian, Bakken and Eagle Ford formations. Growth in supply from OPEC is
primarily a result of a shift in OPEC’s strategy from ‘balancing supply’ to ‘competing for market share’ in
Asia and Europe. However, political uncertainty in certain oil producing countries, including Venezuela,
Libya, Nigeria and Iraq, increases risk in those regions’ supply growth forecasts and makes North
America one of the most secure supply sources of crude oil. As witnessed throughout 2016 and 2017,
North American supply growth can be influenced by macro-economic factors that drive down the global
crude prices. Over the longer term, North American production from tight oil plays, including the Bakken,
is expected to grow as technology continues to improve well productivity and efficiencies. The WCSB, in
Canada, is viewed as one of the world’s largest and most secure supply sources of crude oil. However,
the pace of growth in North America and level of investment in the WCSB could be tempered in future
years by a number of factors including a sustained period of low crude oil prices and corresponding
production decisions by OPEC, increasing environmental regulation, and prolonged approval processes
for new pipelines with access to tide-water for export.
In recent years, the combination of relatively flat domestic demand, growing supply and long-lead time to
build pipeline infrastructure led to a fundamental change in the North American crude oil landscape. The
inability to move increasing inland supply to tide-water markets resulted in a divergence between 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 resulted in a further discounting of
Alberta crude against WTI. With a number of market access initiatives completed by the industry in recent
years, including those introduced by us, the crude oil price differentials significantly narrowed in 2015, and
resulted in higher netbacks for producers. The capacity from these initiatives was for the most part
exhausted by the end of 2017 from growth in the Oil Sands and has resulted in crude differentials
widening once more. Canadian pipeline export capacity is expected to remain essentially full, resulting in
incremental production utilizing non-pipeline transportation services until such time as pipeline capacity is
made available. As the supply in North America continues to grow, the growth and flexibility of pipeline
infrastructure will need to keep pace with the sensitive demand and supply balance. Over the longer term,
we believe pipelines will continue to be the most cost-effective means of transportation in markets where
the differential between North American and global oil prices remain narrow. Utilization of rail to transport
crude is expected to be substantially limited to those markets not readily accessible by pipelines.
Our role in helping to address the evolving supply and demand fundamentals and alleviating price
discounts for producers and supply costs to refiners is to provide expanded pipeline capacity and
sustainable connectivity to alternative markets. As discussed in Part II. Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured
Projects, in 2017, we continue to execute our growth projects plan in furtherance of this objective.
GAS TRANSMISSION & MIDSTREAM
Gas Transmission and Midstream (formerly referred to as Gas Pipelines and Processing) consists of our
investments in natural gas pipelines and gathering and processing facilities in Canada and the United States,
including US Gas Transmission, Canadian Gas Transmission and Midstream, Alliance Pipeline, US
Midstream and other assets.
Zama
Zama
Fort St. John
Fort St. John
Edmonton
Edmonton
Vancouver
Vancouver
Rowatt
Rowatt
Fredericton
Fredericton
Halifax
Halifax
Toronto
Toronto
Boston
Boston
Chatham
Chatham
Leidy
Leidy
Chicago
Chicago
Channahon
Channahon
Flanagan
Flanagan
Oakford
Oakford
Toledo
Toledo
New York
New York
Philadelphia
Philadelphia
Accident
Accident
Steckman
Steckman
Ridge
Ridge
Saltville
Saltville
Nashville
Nashville
Moss Bluff
Moss Bluff
Bobcat
Bobcat
New
New
Orleans
Orleans
EganEgan
Port Arthur
Port Arthur
Houston
Houston
Orlando
Orlando
Tampa
Tampa
Natural Gas Transmission Pipelines
Natural Gas Gathering Pipelines
Natural Gas Liquids Pipeline
Gas Storage Facility
NGL Storage
Gas Processing Plants
LNG Facility
Propane Terminals
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US GAS TRANSMISSION
The majority of assets that comprise US Gas Transmission were acquired through the Merger Transaction
and consist of natural gas transmission and storage assets that are held primarily through Spectra Energy
Partners, LP (SEP). US Gas Transmission includes indirect ownership interests in Texas Eastern,
Algonquin, M&N U.S., East Tennessee Natural Gas, Gulfstream, Sabal Trail, Vector Pipeline L.P. (Vector)
and certain other gas pipeline and storage assets. The US Gas Transmission business primarily provides
transmission and storage of natural gas through interstate pipeline systems for customers in various
regions of the midwestern, northeastern and southern United States.
As a result of the Merger Transaction, Enbridge held a 75% equity interest in SEP, a natural gas and
crude oil infrastructure master limited partnership. As a result of us converting all of our incentive
distribution rights (IDRs) and general partner economic interests in SEP into 172.5 million newly issued
SEP common units, we now hold a 83% equity interest in SEP. Refer to Part II. Item 7. Management's
Discussion and Analysis of Financial Conditions and Results of Operations - United States Sponsored
Vehicle Strategy. SEP owns 100% of Texas Eastern Transmission, L.P. (Texas Eastern), 92% of
Algonquin Gas Transmission, L.L.C. (Algonquin), 100% of East Tennessee Natural Gas, L.L.C. (East
Tennessee), 100% of Saltville Gas Storage Company L.L.C. (Saltville), 100% of Ozark Gas Gathering,
L.L.C. and Ozark Gas Transmission, L.L.C., 100% of Big Sandy Pipeline, L.L.C., 100% of Market Hub
Partners Holding, 100% of Bobcat Gas Storage, 78% of Maritimes & Northeast Pipeline, L.L.C. (M&N
U.S.), 50% of Southeast Supply Header, L.L.C., 50% of Steckman Ridge, L.P., 50% of Gulfstream Natural
Gas System, L.L.C. (Gulfstream) and 50% of Sabal Trail Transmission, LLC (Sabal Trail).
The Texas Eastern natural gas transmission system extends approximately 2,735-kilometers (1,700-
miles) from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New
Jersey and New York. Texas Eastern's onshore system consists of approximately 14,597-kilometers
(9,070-miles) of pipeline and associated compressor stations. Texas Eastern is also connected to four
affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas
Transmission business.
The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey
and extends approximately 402-kilometers (250-miles) through New Jersey, New York, Connecticut,
Rhode Island and Massachusetts where it connects to M&N U.S. The system consists of approximately
1,835-kilometers (1,140-miles) of pipeline with associated compressor stations.
M&N U.S. is an approximately 563-kilometer (350-mile) mainline interstate natural gas transmission
system, including associated compressor stations, which extends from northeastern Massachusetts to the
border of Canada near Baileyville, Maine. M&N U.S. is connected to the Canadian portion of the
Maritimes & Northeast Pipeline system, M&N Canada (see Gas Transmission and Midstream - Canadian
Gas Transmission and Midstream).
East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in
Tennessee and consists of two mainline systems totaling approximately 2,414-kilometers (1,500-miles) of
pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East
Tennessee has a Liquefied Natural Gas (LNG) storage facility in Tennessee and also connects to the
Saltville storage facilities in Virginia.
Gulfstream is an approximately 1,199-kilometer (745-mile) interstate natural gas transmission system,
with associated compressor stations, operated jointly by SEP and The Williams Companies, Inc.
Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of
Mexico to markets in central and southern Florida. Gulfstream is accounted for under the equity method
of accounting.
Sabal Trail provides firm natural gas transportation to Florida Power & Light Company for its power
generation needs and will deliver to Duke Energy Florida's natural gas plant currently under construction
in Florida. Facilities include a new 829-kilometer (515-mile) pipeline, laterals and various compressor
stations. The pipeline infrastructure is located in Alabama, Georgia and Florida, and adds approximately
1.1 billion cubic feet per day (bcf/d) of new capacity to access onshore shale gas supplies once approved
future expansions are completed. Sabal Trail is accounted for under the equity method of accounting.
We also hold a 60% ownership interest in Vector, which is a 560-kilometer (348-mile) pipeline that
transports 1.3 bcf/d of natural gas from Joliet, Illinois in the Chicago area to parts of Indiana, Michigan
and Ontario.
Transmission and storage services are generally provided under firm agreements where customers
reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for
fixed reservation charges that are paid monthly regardless of the actual volumes transported on the
pipelines or injected or withdrawn from our storage facilities, plus a small variable component that is
based on volumes transported, injected or withdrawn, which is intended to recover variable costs.
Interruptible transmission and storage services are also available where customers can use capacity if it
exists at the time of the request. Interruptible revenues depend on the amount of volumes transported or
stored and the associated rates for this service. Storage operations also provide a variety of other value-
added services including natural gas parking, loaning and balancing services to meet customers’ needs.
CANADIAN GAS TRANSMISSION AND MIDSTREAM
Canadian Gas Transmission and Midstream consists of natural gas pipelines, processing plants and
gathering systems, located primarily in Western Canada. Upon completion of the Merger Transaction,
Canadian Gas Transmission and Midstream now includes the Western Canada Transmission &
Processing businesses, which is comprised of British Columbia Pipeline & Field Services, M&N Canada
and certain other midstream gas pipelines, gathering, processing and storage assets.
British Columbia Pipeline and British Columbia Field Services provide fee-based natural gas transmission
and gas gathering and processing services. British Columbia Pipeline has approximately 2,816-kilometers
(1,750-miles) of transmission pipeline in British Columbia and Alberta, as well as associated mainline
compressor stations. The British Columbia Field Services business includes eight gas processing plants
located in British Columbia, associated field compressor stations and approximately 2,253-kilometers
(1,400-miles) of gathering pipelines.
M&N Canada is an approximately 885-kilometer (550-mile) interprovincial natural gas transmission
mainline system which extends from Goldboro, Nova Scotia to the United States border near Baileyville,
Maine. M&N Canada is connected to M&N U.S. - refer to Gas Transmission and Midstream - US Gas
Transmission.
Canadian Gas Transmission and Midstream also includes the wholly-owned Tupper Main and Tupper
West gas plants (the Tupper Plants) located within the Montney shale play in northeastern British
Columbia, our 71% interest in the Cabin Gas Plant located 60-kilometers (37-miles) northeast of Fort
Nelson, British Columbia in the Horn River Basin, as well as interests in the Pipestone and Sexsmith
gathering systems. We are the operator of the Tupper Plants and the Cabin Gas Plant. We have almost
100% interest in Pipestone and varying interests (55% to 100%) in Sexsmith and its related sour gas
gathering, compression and NGL handling facilities, located in the Peace River Arch region of northwest
Alberta. The primary producer and operator of Pipestone holds a nominal 0.01% interest.
The majority of transportation services provided by Canadian Gas Transmission and Midstream are under
firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual
volumes transported on the pipeline, plus a small variable component that is based on volumes
transported to recover variable costs. We also provide interruptible transmission services where
customers can use capacity if it is available at the time of request. Payments under these services are
based on volumes transported.
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21
US GAS TRANSMISSION
The majority of assets that comprise US Gas Transmission were acquired through the Merger Transaction
and consist of natural gas transmission and storage assets that are held primarily through Spectra Energy
Partners, LP (SEP). US Gas Transmission includes indirect ownership interests in Texas Eastern,
Algonquin, M&N U.S., East Tennessee Natural Gas, Gulfstream, Sabal Trail, Vector Pipeline L.P. (Vector)
and certain other gas pipeline and storage assets. The US Gas Transmission business primarily provides
transmission and storage of natural gas through interstate pipeline systems for customers in various
regions of the midwestern, northeastern and southern United States.
As a result of the Merger Transaction, Enbridge held a 75% equity interest in SEP, a natural gas and
crude oil infrastructure master limited partnership. As a result of us converting all of our incentive
distribution rights (IDRs) and general partner economic interests in SEP into 172.5 million newly issued
SEP common units, we now hold a 83% equity interest in SEP. Refer to Part II. Item 7. Management's
Discussion and Analysis of Financial Conditions and Results of Operations - United States Sponsored
Vehicle Strategy. SEP owns 100% of Texas Eastern Transmission, L.P. (Texas Eastern), 92% of
Algonquin Gas Transmission, L.L.C. (Algonquin), 100% of East Tennessee Natural Gas, L.L.C. (East
Tennessee), 100% of Saltville Gas Storage Company L.L.C. (Saltville), 100% of Ozark Gas Gathering,
L.L.C. and Ozark Gas Transmission, L.L.C., 100% of Big Sandy Pipeline, L.L.C., 100% of Market Hub
Partners Holding, 100% of Bobcat Gas Storage, 78% of Maritimes & Northeast Pipeline, L.L.C. (M&N
U.S.), 50% of Southeast Supply Header, L.L.C., 50% of Steckman Ridge, L.P., 50% of Gulfstream Natural
Gas System, L.L.C. (Gulfstream) and 50% of Sabal Trail Transmission, LLC (Sabal Trail).
The Texas Eastern natural gas transmission system extends approximately 2,735-kilometers (1,700-
miles) from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New
Jersey and New York. Texas Eastern's onshore system consists of approximately 14,597-kilometers
(9,070-miles) of pipeline and associated compressor stations. Texas Eastern is also connected to four
affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas
Transmission business.
The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey
and extends approximately 402-kilometers (250-miles) through New Jersey, New York, Connecticut,
Rhode Island and Massachusetts where it connects to M&N U.S. The system consists of approximately
1,835-kilometers (1,140-miles) of pipeline with associated compressor stations.
M&N U.S. is an approximately 563-kilometer (350-mile) mainline interstate natural gas transmission
system, including associated compressor stations, which extends from northeastern Massachusetts to the
border of Canada near Baileyville, Maine. M&N U.S. is connected to the Canadian portion of the
Maritimes & Northeast Pipeline system, M&N Canada (see Gas Transmission and Midstream - Canadian
Gas Transmission and Midstream).
East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in
Tennessee and consists of two mainline systems totaling approximately 2,414-kilometers (1,500-miles) of
pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East
Tennessee has a Liquefied Natural Gas (LNG) storage facility in Tennessee and also connects to the
Saltville storage facilities in Virginia.
Gulfstream is an approximately 1,199-kilometer (745-mile) interstate natural gas transmission system,
with associated compressor stations, operated jointly by SEP and The Williams Companies, Inc.
Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of
Mexico to markets in central and southern Florida. Gulfstream is accounted for under the equity method
of accounting.
Sabal Trail provides firm natural gas transportation to Florida Power & Light Company for its power
generation needs and will deliver to Duke Energy Florida's natural gas plant currently under construction
in Florida. Facilities include a new 829-kilometer (515-mile) pipeline, laterals and various compressor
stations. The pipeline infrastructure is located in Alabama, Georgia and Florida, and adds approximately
1.1 billion cubic feet per day (bcf/d) of new capacity to access onshore shale gas supplies once approved
future expansions are completed. Sabal Trail is accounted for under the equity method of accounting.
We also hold a 60% ownership interest in Vector, which is a 560-kilometer (348-mile) pipeline that
transports 1.3 bcf/d of natural gas from Joliet, Illinois in the Chicago area to parts of Indiana, Michigan
and Ontario.
Transmission and storage services are generally provided under firm agreements where customers
reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for
fixed reservation charges that are paid monthly regardless of the actual volumes transported on the
pipelines or injected or withdrawn from our storage facilities, plus a small variable component that is
based on volumes transported, injected or withdrawn, which is intended to recover variable costs.
Interruptible transmission and storage services are also available where customers can use capacity if it
exists at the time of the request. Interruptible revenues depend on the amount of volumes transported or
stored and the associated rates for this service. Storage operations also provide a variety of other value-
added services including natural gas parking, loaning and balancing services to meet customers’ needs.
CANADIAN GAS TRANSMISSION AND MIDSTREAM
Canadian Gas Transmission and Midstream consists of natural gas pipelines, processing plants and
gathering systems, located primarily in Western Canada. Upon completion of the Merger Transaction,
Canadian Gas Transmission and Midstream now includes the Western Canada Transmission &
Processing businesses, which is comprised of British Columbia Pipeline & Field Services, M&N Canada
and certain other midstream gas pipelines, gathering, processing and storage assets.
British Columbia Pipeline and British Columbia Field Services provide fee-based natural gas transmission
and gas gathering and processing services. British Columbia Pipeline has approximately 2,816-kilometers
(1,750-miles) of transmission pipeline in British Columbia and Alberta, as well as associated mainline
compressor stations. The British Columbia Field Services business includes eight gas processing plants
located in British Columbia, associated field compressor stations and approximately 2,253-kilometers
(1,400-miles) of gathering pipelines.
M&N Canada is an approximately 885-kilometer (550-mile) interprovincial natural gas transmission
mainline system which extends from Goldboro, Nova Scotia to the United States border near Baileyville,
Maine. M&N Canada is connected to M&N U.S. - refer to Gas Transmission and Midstream - US Gas
Transmission.
Canadian Gas Transmission and Midstream also includes the wholly-owned Tupper Main and Tupper
West gas plants (the Tupper Plants) located within the Montney shale play in northeastern British
Columbia, our 71% interest in the Cabin Gas Plant located 60-kilometers (37-miles) northeast of Fort
Nelson, British Columbia in the Horn River Basin, as well as interests in the Pipestone and Sexsmith
gathering systems. We are the operator of the Tupper Plants and the Cabin Gas Plant. We have almost
100% interest in Pipestone and varying interests (55% to 100%) in Sexsmith and its related sour gas
gathering, compression and NGL handling facilities, located in the Peace River Arch region of northwest
Alberta. The primary producer and operator of Pipestone holds a nominal 0.01% interest.
The majority of transportation services provided by Canadian Gas Transmission and Midstream are under
firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual
volumes transported on the pipeline, plus a small variable component that is based on volumes
transported to recover variable costs. We also provide interruptible transmission services where
customers can use capacity if it is available at the time of request. Payments under these services are
based on volumes transported.
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ALLIANCE PIPELINE
We have a 50% interest in the Alliance Pipeline, a 3,000-kilometer (1,864-mile) integrated, high-pressure
natural gas transmission pipeline and approximately 860-kilometers (534-miles) of lateral pipelines and
related infrastructure. Alliance Pipeline transports liquids-rich natural gas from northeast British Columbia,
northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub
downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. The majority
of transportation services provided by Alliance pipeline are under firm agreements, which provide for fixed
reservation charges that are paid monthly regardless of actual volumes transported on the pipeline.
Alliance pipeline also provides interruptible transmission services where customers can use capacity if it
is available at the time of request.
US MIDSTREAM
US Midstream consists of our Midcoast assets, including the Anadarko, East Texas, North Texas and
Texas Express NGL systems. These assets include natural gas and NGL gathering and transportation
pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL
fractionation facility. Midcoast also has rail and liquids marketing operations. During 2017, we acquired all
of the noncontrolling interests in these assets. For further information, refer to Part II. Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - United States
Sponsored Vehicle Strategy - Acquisition of Midcoast Assets and Privatization of Midcoast Energy
Partners, L.P.
US Midstream also includes our 42.7% interest in Aux Sable Liquid Products LP and Aux Sable
Midstream LLC, and a 50% interest in Aux Sable Canada LP (together, Aux Sable). Aux Sable Liquid
Products LP owns and operates an NGL extraction and fractionation plant at Channahon, Illinois, outside
Chicago, near the terminus of Alliance Pipeline. Aux Sable also owns facilities upstream of Alliance
Pipeline that facilitate deliveries of 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 and operated by Aux Sable Midstream US; and Aux Sable
Canada’s interests in the Montney area of British Columbia, comprising the Septimus Pipeline and the
Septimus and Wilder Gas Plants.
US Midstream also includes a 50% investment in DCP Midstream, LLC (DCP Midstream), which is
accounted for as an equity investment. DCP Midstream gathers, compresses, treats, processes,
transports, stores and sells natural gas. It also produces, fractionates, transports, stores and sells NGLs,
recovers and sells condensate, and trades and markets natural gas and NGLs.
OTHER
Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 11 active
natural gas gathering and transmission pipelines and two active oil pipelines, including the Heidelberg Oil
Pipeline that was placed in service in January 2016. These pipelines are located in four major corridors in
the Gulf of Mexico, extending to deepwater developments, and include almost 2,100-kilometers (1,300-
miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d.
COMPETITION
Our natural gas transmission and storage businesses compete with similar facilities that serve our supply
and market areas in the transmission and storage of natural gas. The flow pattern of natural gas is
changing across North America due to emerging supply sources and evolving demand centers, which
creates a highly competitive market to secure new growth opportunities. The principal elements of
competition are location, rates, terms of service, flexibility and reliability of service.
The natural gas transported in our business competes with other forms of energy available to our
customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Factors
that influence the demand for natural gas include price changes, the availability of natural gas and other
forms of energy, levels of business activity, long-term economic conditions, conservation, legislation,
governmental regulations, the ability to convert to alternative fuels, weather and other factors.
Competition in our business exists in all of the markets we serve. Competitors include interstate and
intrastate pipelines or their affiliates and other midstream businesses that transport, gather, treat, process
and market natural gas or NGLs. Because pipelines are generally the most efficient mode of
transportation for natural gas over land, the most significant competitors of our natural gas pipelines are
other pipeline companies. Pipelines typically compete with each other based on location, capacity,
reputation, price and reliability.
SUPPLY AND DEMAND
Global energy demand is expected to increase approximately 30 percent by 2040, according to the
International Energy Agency, driven primarily by economic growth in non-OECD countries. Natural gas
will play an important role in meeting this energy demand as gas consumption is anticipated to grow by
nearly 50 percent during this period as one of the world’s fastest growing energy sources, second only to
renewables. Globally, most natural gas demand will stem from the need for greater power generation
capacity, as natural gas is a cleaner alternative to coal, which currently has the largest market share for
power generation.
Within North America, United States natural gas demand growth is expected to be driven by the next
wave of gas-intensive petrochemical facilities which are now starting to enter service, along with power
generation, an increase in the volume of LNG exports and additional pipeline exports to Mexico. Within
Canada, natural gas demand growth is expected to be largely tied to oil sands development and growth in
gas-fired power generation. Canadian gas demand growth will be accelerated with implementation of
proposed government regulations to replace coal fired power, designed to meet emissions targets.
North American supply from tight formations continues to create a demand and supply imbalance for
natural gas and some NGL products. North American gas supply continues to be significantly impacted by
development in the northeastern United States, primarily the prolific Marcellus and Utica shales in
Appalachia. The abundance of supply from these shale plays continues to alter natural gas flow patterns
in North America, as this region has largely displaced flows from the Gulf Coast and WCSB that
historically supplied eastern markets. Similar pressures are also being felt in the Midwest United States
and southern markets.
Beyond growing Appalachian production, natural gas supply growth has been largely tied to crude oil and
NGL production. In the Permian Basin, for example, rapid expansion of crude oil drilling activity has
increased associated gas supplies from the region by approximately 2.0 bcf/d over the past two years and
growth is forecasted to continue for the next decade. Similarly, WCSB natural gas production growth has
been primarily attributable to production of NGLs, which provide strong producer netbacks. However,
growing local demand from gas-fired power generation and continued oil sands development should
stabilize WCSB natural gas economics, even as regional exports face steeper competition in Eastern
Canada and the Midwest United States.
The continued increase in North American gas production and the resulting surplus supply has limited gas
price advances, which remained largely within range throughout 2017. In response to low prices,
producers have introduced new technologies and more efficient drilling and completion techniques to
maximize production and improve break-even economics on new wells. While domestic gas demand and
growing North American gas exports provide support for future prices, abundant low cost supplies are
likely to continue to limit high prices through the next decade.
Growth in global demand for natural gas will necessitate growing LNG trade to facilitate the movement of
gas supply from producing regions to consuming regions. North America and the USGC in particular are
positioned to benefit from this trend as low-cost tight gas production from the Permian, Eagle Ford and
Appalachia continues to enable growing LNG exports. The United States exported approximately 3.0 bcf/
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ALLIANCE PIPELINE
We have a 50% interest in the Alliance Pipeline, a 3,000-kilometer (1,864-mile) integrated, high-pressure
natural gas transmission pipeline and approximately 860-kilometers (534-miles) of lateral pipelines and
related infrastructure. Alliance Pipeline transports liquids-rich natural gas from northeast British Columbia,
northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub
downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. The majority
of transportation services provided by Alliance pipeline are under firm agreements, which provide for fixed
reservation charges that are paid monthly regardless of actual volumes transported on the pipeline.
Alliance pipeline also provides interruptible transmission services where customers can use capacity if it
is available at the time of request.
US MIDSTREAM
US Midstream consists of our Midcoast assets, including the Anadarko, East Texas, North Texas and
Texas Express NGL systems. These assets include natural gas and NGL gathering and transportation
pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL
fractionation facility. Midcoast also has rail and liquids marketing operations. During 2017, we acquired all
of the noncontrolling interests in these assets. For further information, refer to Part II. Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - United States
Sponsored Vehicle Strategy - Acquisition of Midcoast Assets and Privatization of Midcoast Energy
Partners, L.P.
US Midstream also includes our 42.7% interest in Aux Sable Liquid Products LP and Aux Sable
Midstream LLC, and a 50% interest in Aux Sable Canada LP (together, Aux Sable). Aux Sable Liquid
Products LP owns and operates an NGL extraction and fractionation plant at Channahon, Illinois, outside
Chicago, near the terminus of Alliance Pipeline. Aux Sable also owns facilities upstream of Alliance
Pipeline that facilitate deliveries of 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 and operated by Aux Sable Midstream US; and Aux Sable
Canada’s interests in the Montney area of British Columbia, comprising the Septimus Pipeline and the
Septimus and Wilder Gas Plants.
US Midstream also includes a 50% investment in DCP Midstream, LLC (DCP Midstream), which is
accounted for as an equity investment. DCP Midstream gathers, compresses, treats, processes,
transports, stores and sells natural gas. It also produces, fractionates, transports, stores and sells NGLs,
recovers and sells condensate, and trades and markets natural gas and NGLs.
OTHER
Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 11 active
natural gas gathering and transmission pipelines and two active oil pipelines, including the Heidelberg Oil
Pipeline that was placed in service in January 2016. These pipelines are located in four major corridors in
the Gulf of Mexico, extending to deepwater developments, and include almost 2,100-kilometers (1,300-
miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d.
COMPETITION
Our natural gas transmission and storage businesses compete with similar facilities that serve our supply
and market areas in the transmission and storage of natural gas. The flow pattern of natural gas is
changing across North America due to emerging supply sources and evolving demand centers, which
creates a highly competitive market to secure new growth opportunities. The principal elements of
competition are location, rates, terms of service, flexibility and reliability of service.
The natural gas transported in our business competes with other forms of energy available to our
customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Factors
that influence the demand for natural gas include price changes, the availability of natural gas and other
forms of energy, levels of business activity, long-term economic conditions, conservation, legislation,
governmental regulations, the ability to convert to alternative fuels, weather and other factors.
Competition in our business exists in all of the markets we serve. Competitors include interstate and
intrastate pipelines or their affiliates and other midstream businesses that transport, gather, treat, process
and market natural gas or NGLs. Because pipelines are generally the most efficient mode of
transportation for natural gas over land, the most significant competitors of our natural gas pipelines are
other pipeline companies. Pipelines typically compete with each other based on location, capacity,
reputation, price and reliability.
SUPPLY AND DEMAND
Global energy demand is expected to increase approximately 30 percent by 2040, according to the
International Energy Agency, driven primarily by economic growth in non-OECD countries. Natural gas
will play an important role in meeting this energy demand as gas consumption is anticipated to grow by
nearly 50 percent during this period as one of the world’s fastest growing energy sources, second only to
renewables. Globally, most natural gas demand will stem from the need for greater power generation
capacity, as natural gas is a cleaner alternative to coal, which currently has the largest market share for
power generation.
Within North America, United States natural gas demand growth is expected to be driven by the next
wave of gas-intensive petrochemical facilities which are now starting to enter service, along with power
generation, an increase in the volume of LNG exports and additional pipeline exports to Mexico. Within
Canada, natural gas demand growth is expected to be largely tied to oil sands development and growth in
gas-fired power generation. Canadian gas demand growth will be accelerated with implementation of
proposed government regulations to replace coal fired power, designed to meet emissions targets.
North American supply from tight formations continues to create a demand and supply imbalance for
natural gas and some NGL products. North American gas supply continues to be significantly impacted by
development in the northeastern United States, primarily the prolific Marcellus and Utica shales in
Appalachia. The abundance of supply from these shale plays continues to alter natural gas flow patterns
in North America, as this region has largely displaced flows from the Gulf Coast and WCSB that
historically supplied eastern markets. Similar pressures are also being felt in the Midwest United States
and southern markets.
Beyond growing Appalachian production, natural gas supply growth has been largely tied to crude oil and
NGL production. In the Permian Basin, for example, rapid expansion of crude oil drilling activity has
increased associated gas supplies from the region by approximately 2.0 bcf/d over the past two years and
growth is forecasted to continue for the next decade. Similarly, WCSB natural gas production growth has
been primarily attributable to production of NGLs, which provide strong producer netbacks. However,
growing local demand from gas-fired power generation and continued oil sands development should
stabilize WCSB natural gas economics, even as regional exports face steeper competition in Eastern
Canada and the Midwest United States.
The continued increase in North American gas production and the resulting surplus supply has limited gas
price advances, which remained largely within range throughout 2017. In response to low prices,
producers have introduced new technologies and more efficient drilling and completion techniques to
maximize production and improve break-even economics on new wells. While domestic gas demand and
growing North American gas exports provide support for future prices, abundant low cost supplies are
likely to continue to limit high prices through the next decade.
Growth in global demand for natural gas will necessitate growing LNG trade to facilitate the movement of
gas supply from producing regions to consuming regions. North America and the USGC in particular are
positioned to benefit from this trend as low-cost tight gas production from the Permian, Eagle Ford and
Appalachia continues to enable growing LNG exports. The United States exported approximately 3.0 bcf/
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d of natural gas from the United States Gulf Coast at the end of 2017 with export capacity of
approximately 9.0 bcf/d scheduled to be in service by 2020. While the short term outlook for LNG
fundamentals points to a continued global oversupply, as the market absorbs the large volumes of new
supply coming online, forecasts indicate demand will exceed projected LNG supply in the early 2020s as
growing markets seek to diversify supply sources. In addition to LNG export facilities under construction,
the United States remains well positioned to serve this next round of global trade expansion. Canada is
well positioned to provide LNG export facilities, although these facilities are not likely to be in service in
the near term.
NGL production growth is increasingly linked to growing associated gas volumes related to the
development of tight oil plays such as the Permian. NGLs 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. Robust gas production has created regional supply imbalances for
some NGL products and weakened the economics of NGL extraction, although these imbalances
modestly improved over 2017 as crude prices have rebounded and NGL export capacity has expanded.
Over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental
ethane demand and exports. Ethane is the key feedstock to the United States Gulf Coast petrochemical
industry, which is among the world’s lowest-cost ethylene producing regions and is currently undergoing
significant expansion. As this new infrastructure is completed, ethane prices and resulting extraction
margins are expected to improve, reducing the amount of ethane retained in the gas stream.
In addition to ethane, the outlook for abundant propane supplies has prompted the development and
expansion of export facilities for liquefied petroleum gas. Over a few short years, the United States has
become the world’s largest liquefied petroleum gas exporter, which has helped to reduce the inventory
overhang and provide support for propane prices.
In Canada, the WCSB is well situated to capitalize on the evolving NGL fundamentals over the longer
term as the Montney and Duvernay shale plays contain significant liquids-rich resources at highly
competitive extraction costs. In response to growing regional NGL supply, several propane export
solutions are being developed to move WCSB NGLs from Western Canada to global markets.
Longer term, NGL fundamentals indicate a positive outlook for demand growth and would be further
supported with a continued recovery in crude oil prices. Consequently, the crude-to-gas price ratio is
expected to remain well above energy conversion value levels and continue to be supportive of NGL
extraction over the longer term.
In response to these evolving natural gas and NGL fundamentals, we believe we are well positioned to
provide value-added solutions to producers. We are responding to the need for regional infrastructure
with additional investment in Canadian and United States gas pipeline and midstream facilities.
24
d of natural gas from the United States Gulf Coast at the end of 2017 with export capacity of
d of natural gas from the United States Gulf Coast at the end of 2017 with export capacity of
approximately 9.0 bcf/d scheduled to be in service by 2020. While the short term outlook for LNG
approximately 9.0 bcf/d scheduled to be in service by 2020. While the short term outlook for LNG
fundamentals points to a continued global oversupply, as the market absorbs the large volumes of new
fundamentals points to a continued global oversupply, as the market absorbs the large volumes of new
supply coming online, forecasts indicate demand will exceed projected LNG supply in the early 2020s as
supply coming online, forecasts indicate demand will exceed projected LNG supply in the early 2020s as
growing markets seek to diversify supply sources. In addition to LNG export facilities under construction,
growing markets seek to diversify supply sources. In addition to LNG export facilities under construction,
the United States remains well positioned to serve this next round of global trade expansion. Canada is
the United States remains well positioned to serve this next round of global trade expansion. Canada is
well positioned to provide LNG export facilities, although these facilities are not likely to be in service in
well positioned to provide LNG export facilities, although these facilities are not likely to be in service in
the near term.
the near term.
NGL production growth is increasingly linked to growing associated gas volumes related to the
NGL production growth is increasingly linked to growing associated gas volumes related to the
development of tight oil plays such as the Permian. NGLs that can be extracted from liquids-rich gas
development of tight oil plays such as the Permian. NGLs that can be extracted from liquids-rich gas
streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial,
streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial,
commercial and other applications. Robust gas production has created regional supply imbalances for
commercial and other applications. Robust gas production has created regional supply imbalances for
some NGL products and weakened the economics of NGL extraction, although these imbalances
some NGL products and weakened the economics of NGL extraction, although these imbalances
modestly improved over 2017 as crude prices have rebounded and NGL export capacity has expanded.
modestly improved over 2017 as crude prices have rebounded and NGL export capacity has expanded.
Over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental
Over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental
ethane demand and exports. Ethane is the key feedstock to the United States Gulf Coast petrochemical
ethane demand and exports. Ethane is the key feedstock to the United States Gulf Coast petrochemical
industry, which is among the world’s lowest-cost ethylene producing regions and is currently undergoing
industry, which is among the world’s lowest-cost ethylene producing regions and is currently undergoing
significant expansion. As this new infrastructure is completed, ethane prices and resulting extraction
significant expansion. As this new infrastructure is completed, ethane prices and resulting extraction
margins are expected to improve, reducing the amount of ethane retained in the gas stream.
margins are expected to improve, reducing the amount of ethane retained in the gas stream.
In addition to ethane, the outlook for abundant propane supplies has prompted the development and
In addition to ethane, the outlook for abundant propane supplies has prompted the development and
expansion of export facilities for liquefied petroleum gas. Over a few short years, the United States has
expansion of export facilities for liquefied petroleum gas. Over a few short years, the United States has
become the world’s largest liquefied petroleum gas exporter, which has helped to reduce the inventory
become the world’s largest liquefied petroleum gas exporter, which has helped to reduce the inventory
overhang and provide support for propane prices.
overhang and provide support for propane prices.
In Canada, the WCSB is well situated to capitalize on the evolving NGL fundamentals over the longer
In Canada, the WCSB is well situated to capitalize on the evolving NGL fundamentals over the longer
term as the Montney and Duvernay shale plays contain significant liquids-rich resources at highly
term as the Montney and Duvernay shale plays contain significant liquids-rich resources at highly
competitive extraction costs. In response to growing regional NGL supply, several propane export
competitive extraction costs. In response to growing regional NGL supply, several propane export
solutions are being developed to move WCSB NGLs from Western Canada to global markets.
solutions are being developed to move WCSB NGLs from Western Canada to global markets.
Longer term, NGL fundamentals indicate a positive outlook for demand growth and would be further
supported with a continued recovery in crude oil prices. Consequently, the crude-to-gas price ratio is
expected to remain well above energy conversion value levels and continue to be supportive of NGL
extraction over the longer term.
Longer term, NGL fundamentals indicate a positive outlook for demand growth and would be further
supported with a continued recovery in crude oil prices. Consequently, the crude-to-gas price ratio is
expected to remain well above energy conversion value levels and continue to be supportive of NGL
extraction over the longer term.
In response to these evolving natural gas and NGL fundamentals, we believe we are well positioned to
In response to these evolving natural gas and NGL fundamentals, we believe we are well positioned to
provide value-added solutions to producers. We are responding to the need for regional infrastructure
provide value-added solutions to producers. We are responding to the need for regional infrastructure
with additional investment in Canadian and United States gas pipeline and midstream facilities.
with additional investment in Canadian and United States gas pipeline and midstream facilities.
GAS DISTRIBUTION
Gas Distribution consists of our natural gas utility operations, the core of which are Enbridge Gas
Distribution Inc. (EGD) and Union Gas Limited (Union Gas), which serve residential, commercial and
industrial customers, primarily located throughout Ontario. This business segment also includes natural
gas distribution activities in Quebec and New Brunswick and our investment in Noverco Inc (Noverco).
On November 2, 2017, EGD and Union Gas filed an application with the Ontario Energy Board (OEB) to
amalgamate the two utilities. If approved as filed, the application will provide a 10 year framework for the
utilities to identify and leverage best practices and implement integrated solutions. A decision is expected
in the second half of 2018.
ENBRIDGE GAS DISTRIBUTION
EGD is a rate regulated natural gas distribution utility serving approximately 2.2 million residential,
commercial and industrial customers in its franchise areas of central and eastern Ontario. In addition,
EGD currently serves areas in northern New York State through St. Lawrence Gas Company Inc. (St.
Lawrence Gas). In August 2017, EGD entered into an agreement to sell the issued and outstanding
shares of St. Lawrence Gas. The transaction is expected to close in 2018, subject to regulatory approval
and certain pre-closing conditions.
EGD also owns and operates regulated and unregulated natural gas storage facilities in Ontario. The
utility business is conducted under statutes and municipal bylaws which grant the right to operate in the
areas served. The utility operations of EGD and St. Lawrence Gas are regulated by the OEB and by the
New York State Public Service Commission, respectively.
As at December 31, 2017, EGD owned and operated a network of approximately 39,000-kilometers
(24,233-miles) of mains for the transportation and distribution of natural gas, as well as the service pipes
to transfer natural gas from mains to meters on customers' premises.
There are four principal interrelated aspects of the natural gas distribution business in which EGD is
directly involved: Distribution Service, Gas Supply, Transportation and Storage.
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d of natural gas from the United States Gulf Coast at the end of 2017 with export capacity of
d of natural gas from the United States Gulf Coast at the end of 2017 with export capacity of
approximately 9.0 bcf/d scheduled to be in service by 2020. While the short term outlook for LNG
approximately 9.0 bcf/d scheduled to be in service by 2020. While the short term outlook for LNG
fundamentals points to a continued global oversupply, as the market absorbs the large volumes of new
fundamentals points to a continued global oversupply, as the market absorbs the large volumes of new
supply coming online, forecasts indicate demand will exceed projected LNG supply in the early 2020s as
supply coming online, forecasts indicate demand will exceed projected LNG supply in the early 2020s as
growing markets seek to diversify supply sources. In addition to LNG export facilities under construction,
growing markets seek to diversify supply sources. In addition to LNG export facilities under construction,
the United States remains well positioned to serve this next round of global trade expansion. Canada is
the United States remains well positioned to serve this next round of global trade expansion. Canada is
well positioned to provide LNG export facilities, although these facilities are not likely to be in service in
well positioned to provide LNG export facilities, although these facilities are not likely to be in service in
the near term.
the near term.
NGL production growth is increasingly linked to growing associated gas volumes related to the
NGL production growth is increasingly linked to growing associated gas volumes related to the
development of tight oil plays such as the Permian. NGLs that can be extracted from liquids-rich gas
development of tight oil plays such as the Permian. NGLs that can be extracted from liquids-rich gas
streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial,
streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial,
commercial and other applications. Robust gas production has created regional supply imbalances for
commercial and other applications. Robust gas production has created regional supply imbalances for
some NGL products and weakened the economics of NGL extraction, although these imbalances
some NGL products and weakened the economics of NGL extraction, although these imbalances
modestly improved over 2017 as crude prices have rebounded and NGL export capacity has expanded.
modestly improved over 2017 as crude prices have rebounded and NGL export capacity has expanded.
Over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental
Over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental
ethane demand and exports. Ethane is the key feedstock to the United States Gulf Coast petrochemical
ethane demand and exports. Ethane is the key feedstock to the United States Gulf Coast petrochemical
industry, which is among the world’s lowest-cost ethylene producing regions and is currently undergoing
industry, which is among the world’s lowest-cost ethylene producing regions and is currently undergoing
significant expansion. As this new infrastructure is completed, ethane prices and resulting extraction
significant expansion. As this new infrastructure is completed, ethane prices and resulting extraction
margins are expected to improve, reducing the amount of ethane retained in the gas stream.
margins are expected to improve, reducing the amount of ethane retained in the gas stream.
In addition to ethane, the outlook for abundant propane supplies has prompted the development and
In addition to ethane, the outlook for abundant propane supplies has prompted the development and
expansion of export facilities for liquefied petroleum gas. Over a few short years, the United States has
expansion of export facilities for liquefied petroleum gas. Over a few short years, the United States has
become the world’s largest liquefied petroleum gas exporter, which has helped to reduce the inventory
become the world’s largest liquefied petroleum gas exporter, which has helped to reduce the inventory
overhang and provide support for propane prices.
overhang and provide support for propane prices.
In Canada, the WCSB is well situated to capitalize on the evolving NGL fundamentals over the longer
In Canada, the WCSB is well situated to capitalize on the evolving NGL fundamentals over the longer
term as the Montney and Duvernay shale plays contain significant liquids-rich resources at highly
term as the Montney and Duvernay shale plays contain significant liquids-rich resources at highly
competitive extraction costs. In response to growing regional NGL supply, several propane export
competitive extraction costs. In response to growing regional NGL supply, several propane export
solutions are being developed to move WCSB NGLs from Western Canada to global markets.
solutions are being developed to move WCSB NGLs from Western Canada to global markets.
Longer term, NGL fundamentals indicate a positive outlook for demand growth and would be further
Longer term, NGL fundamentals indicate a positive outlook for demand growth and would be further
supported with a continued recovery in crude oil prices. Consequently, the crude-to-gas price ratio is
supported with a continued recovery in crude oil prices. Consequently, the crude-to-gas price ratio is
expected to remain well above energy conversion value levels and continue to be supportive of NGL
expected to remain well above energy conversion value levels and continue to be supportive of NGL
extraction over the longer term.
extraction over the longer term.
In response to these evolving natural gas and NGL fundamentals, we believe we are well positioned to
In response to these evolving natural gas and NGL fundamentals, we believe we are well positioned to
provide value-added solutions to producers. We are responding to the need for regional infrastructure
provide value-added solutions to producers. We are responding to the need for regional infrastructure
with additional investment in Canadian and United States gas pipeline and midstream facilities.
with additional investment in Canadian and United States gas pipeline and midstream facilities.
GAS DISTRIBUTION
Gas Distribution consists of our natural gas utility operations, the core of which are Enbridge Gas
Distribution Inc. (EGD) and Union Gas Limited (Union Gas), which serve residential, commercial and
industrial customers, primarily located throughout Ontario. This business segment also includes natural
gas distribution activities in Quebec and New Brunswick and our investment in Noverco Inc (Noverco).
On November 2, 2017, EGD and Union Gas filed an application with the Ontario Energy Board (OEB) to
amalgamate the two utilities. If approved as filed, the application will provide a 10 year framework for the
utilities to identify and leverage best practices and implement integrated solutions. A decision is expected
in the second half of 2018.
ENBRIDGE GAS DISTRIBUTION
EGD is a rate regulated natural gas distribution utility serving approximately 2.2 million residential,
commercial and industrial customers in its franchise areas of central and eastern Ontario. In addition,
EGD currently serves areas in northern New York State through St. Lawrence Gas Company Inc. (St.
Lawrence Gas). In August 2017, EGD entered into an agreement to sell the issued and outstanding
shares of St. Lawrence Gas. The transaction is expected to close in 2018, subject to regulatory approval
and certain pre-closing conditions.
EGD also owns and operates regulated and unregulated natural gas storage facilities in Ontario. The
utility business is conducted under statutes and municipal bylaws which grant the right to operate in the
areas served. The utility operations of EGD and St. Lawrence Gas are regulated by the OEB and by the
New York State Public Service Commission, respectively.
As at December 31, 2017, EGD owned and operated a network of approximately 39,000-kilometers
(24,233-miles) of mains for the transportation and distribution of natural gas, as well as the service pipes
to transfer natural gas from mains to meters on customers' premises.
There are four principal interrelated aspects of the natural gas distribution business in which EGD is
directly involved: Distribution Service, Gas Supply, Transportation and Storage.
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TorontoTorontoMontrealMontrealGas Distribution Service TerritoryAffiliated Gas Distribution Territory Distribution Service
EGD's principal source of revenue arises from distribution of natural gas to customers. The services
provided to residential, commercial and industrial heating customers are primarily on a general service
basis (without a specific fixed term or fixed price contract). The services provided to larger commercial
and industrial customers are usually on an annual contract basis under firm or interruptible service
contracts.
Gas Supply
To acquire the necessary volume of natural gas to serve its customers, EGD maintains a diversified
natural gas supply portfolio. EGD's system supply natural gas contracts have pricing structures
responsive to supply and demand conditions in the North American natural gas market. The prices in
these contracts may be indexed to Alberta, Chicago or New York based prices.
Transportation
EGD relies on its long-term contracts with Union Gas, an affiliated company under common control, for
transportation of natural gas from the Dawn Hub (Dawn), the largest integrated underground storage
facility in Canada and one of the largest in North America, located in south-western Ontario, to EGD’s
major market in the Greater Toronto Area. These contracts effectively provide EGD with access to United
States sourced natural gas at Dawn. These contracts also provide transportation for natural gas received
at Dawn via Vector as well as natural gas stored at EGD’s and Union’s storage pools in the Sarnia,
Ontario area to the market area.
Storage
EGD’s business is highly seasonal as daily market demand for natural gas fluctuates with changes in
weather, with peak consumption occurring in the winter months. Utilization of storage facilities permits
EGD to take delivery of natural gas on favorable terms during off peak summer periods for subsequent
use during the winter heating season. This practice permits EGD to minimize the annual cost of
transportation of natural gas from its supply basins, assists in reducing its overall cost of natural gas
supply and adds a measure of security in the event of any short-term interruption of transportation of
natural gas to EGD's franchise area.
EGD's principal storage facilities are located in south-western Ontario, near Dawn, and have a total
working capacity of approximately 10.5 billion cubic feet (Bcf). Approximately 8.5 Bcf of the total working
capacity is available to EGD for utility operations. EGD also has a storage contract with Union Gas for 2.0
Bcf of storage capacity.
UNION GAS
Union Gas is a rate regulated natural gas distribution utility now serving approximately 1.5 million
residential, commercial and industrial customers in its franchise areas of northern, southwestern and
eastern Ontario.
Union Gas' regulated and unregulated storage and transmission business offers storage and transmission
services to customers at Dawn. It offers customers an important link in the movement of natural gas from
western Canada and United States supply basins to markets in central Canada and the northeastern
United States. The utility business is conducted under statutes and municipal by laws which grant the
right to operate in the areas served. The utility operations of Union Gas are regulated by the OEB.
As at December 31, 2017, Union Gas owned and operated a network of approximately 66,000-kilometers
(41,010-miles) of mains for the transportation and distribution of natural gas, as well as the service pipes
to transfer natural gas from mains to meters on customers' premises.
Similar to EGD, there are four principal interrelated aspects of the natural gas distribution business in
which Union Gas is directly involved: Distribution Service, Gas Supply, Transportation and Storage.
Distribution Service
Similar to EGD, Union Gas’ principal source of revenue arises from distribution of natural gas to
customers. The services provided to residential, small commercial and industrial heating customers are
primarily on a general service basis (without a specific fixed term or fixed price contract). The services
provided to larger commercial and industrial customers underpinned by firm or interruptible service
contracts.
Gas Supply
To acquire the necessary volume of natural gas to serve its customers, Union Gas maintains a diversified
natural gas supply portfolio. Union Gas' system supply natural gas contracts have pricing structures
responsive to supply and demand conditions in the North American natural gas market. The prices in
these contracts may be indexed to Alberta, Michigan and Chicago based prices.
Transportation
Union Gas’ transmission system consists of approximately 4,900-kilometers (3,045-miles) of high-
pressure pipeline and five mainline compressor stations. Key pipeline interconnects in Canada and the
United States enabled Union Gas to deliver approximately 774 Bcf of gas through Union Gas’
transmission system in 2017. Union Gas’ transmission system also links an extensive network of
underground storage pools at Dawn to major Canadian and United States markets. There are multiple
pipelines providing access to Dawn. Customers can purchase both firm and interruptible transportation
services on the Union Gas system. As the supply of natural gas in areas close to Ontario continues to
grow, there is an increased demand to access these diverse supplies at Dawn and transport them along
the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern United
States. To secure the continued reliable delivery of natural gas and to serve a growing demand for natural
gas, Union Gas has invested $1.5 billion between 2015 and 2017 to expand the Dawn-Parkway natural
gas transmission system. This has increased the takeaway capacity from Dawn to approximately 20
percent or from 6.3 bcf/d in 2014 to more than 7.5 bcf/d in 2017. A substantial amount of Union Gas’
transportation revenue is generated by fixed annual demand charges, with the average length of a long-
term contract being approximately 11 years, with the longest remaining contract term being 15 years.
Storage
Union Gas’ underground natural gas storage facilities have a working capacity of approximately 165 Bcf
in 25 underground facilities located in depleted gas fields. Union Gas’ storage pools give customers
access to all Dawn storage capacity and deliverability. Dawn's configuration provides flexibility for
injections, withdrawals and cycling. Customers can purchase both firm and interruptible storage services
at Dawn. Dawn offers customers a wide range of market choices and options with easy access to
upstream and downstream markets. During 2017, Dawn provided storage, balancing, gas loans,
transport, exchange and peaking services to over 140 counterparties.
A substantial amount of Union Gas’ storage revenue is generated by fixed annual demand charges, with
the average length of a long-term contract being approximately five years, with the longest remaining
contract term being 19 years.
NOVERCO
We own 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 Energir
LP, formerly known as Gaz Metro Limited Partnership, 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 our Common Shares.
26
27
Distribution Service
EGD's principal source of revenue arises from distribution of natural gas to customers. The services
provided to residential, commercial and industrial heating customers are primarily on a general service
basis (without a specific fixed term or fixed price contract). The services provided to larger commercial
and industrial customers are usually on an annual contract basis under firm or interruptible service
contracts.
Gas Supply
To acquire the necessary volume of natural gas to serve its customers, EGD maintains a diversified
natural gas supply portfolio. EGD's system supply natural gas contracts have pricing structures
responsive to supply and demand conditions in the North American natural gas market. The prices in
these contracts may be indexed to Alberta, Chicago or New York based prices.
Transportation
EGD relies on its long-term contracts with Union Gas, an affiliated company under common control, for
transportation of natural gas from the Dawn Hub (Dawn), the largest integrated underground storage
facility in Canada and one of the largest in North America, located in south-western Ontario, to EGD’s
major market in the Greater Toronto Area. These contracts effectively provide EGD with access to United
States sourced natural gas at Dawn. These contracts also provide transportation for natural gas received
at Dawn via Vector as well as natural gas stored at EGD’s and Union’s storage pools in the Sarnia,
Ontario area to the market area.
Storage
EGD’s business is highly seasonal as daily market demand for natural gas fluctuates with changes in
weather, with peak consumption occurring in the winter months. Utilization of storage facilities permits
EGD to take delivery of natural gas on favorable terms during off peak summer periods for subsequent
use during the winter heating season. This practice permits EGD to minimize the annual cost of
transportation of natural gas from its supply basins, assists in reducing its overall cost of natural gas
supply and adds a measure of security in the event of any short-term interruption of transportation of
natural gas to EGD's franchise area.
EGD's principal storage facilities are located in south-western Ontario, near Dawn, and have a total
working capacity of approximately 10.5 billion cubic feet (Bcf). Approximately 8.5 Bcf of the total working
capacity is available to EGD for utility operations. EGD also has a storage contract with Union Gas for 2.0
Bcf of storage capacity.
UNION GAS
eastern Ontario.
Union Gas is a rate regulated natural gas distribution utility now serving approximately 1.5 million
residential, commercial and industrial customers in its franchise areas of northern, southwestern and
Union Gas' regulated and unregulated storage and transmission business offers storage and transmission
services to customers at Dawn. It offers customers an important link in the movement of natural gas from
western Canada and United States supply basins to markets in central Canada and the northeastern
United States. The utility business is conducted under statutes and municipal by laws which grant the
right to operate in the areas served. The utility operations of Union Gas are regulated by the OEB.
As at December 31, 2017, Union Gas owned and operated a network of approximately 66,000-kilometers
(41,010-miles) of mains for the transportation and distribution of natural gas, as well as the service pipes
to transfer natural gas from mains to meters on customers' premises.
Similar to EGD, there are four principal interrelated aspects of the natural gas distribution business in
which Union Gas is directly involved: Distribution Service, Gas Supply, Transportation and Storage.
Distribution Service
Similar to EGD, Union Gas’ principal source of revenue arises from distribution of natural gas to
customers. The services provided to residential, small commercial and industrial heating customers are
primarily on a general service basis (without a specific fixed term or fixed price contract). The services
provided to larger commercial and industrial customers underpinned by firm or interruptible service
contracts.
Gas Supply
To acquire the necessary volume of natural gas to serve its customers, Union Gas maintains a diversified
natural gas supply portfolio. Union Gas' system supply natural gas contracts have pricing structures
responsive to supply and demand conditions in the North American natural gas market. The prices in
these contracts may be indexed to Alberta, Michigan and Chicago based prices.
Transportation
Union Gas’ transmission system consists of approximately 4,900-kilometers (3,045-miles) of high-
pressure pipeline and five mainline compressor stations. Key pipeline interconnects in Canada and the
United States enabled Union Gas to deliver approximately 774 Bcf of gas through Union Gas’
transmission system in 2017. Union Gas’ transmission system also links an extensive network of
underground storage pools at Dawn to major Canadian and United States markets. There are multiple
pipelines providing access to Dawn. Customers can purchase both firm and interruptible transportation
services on the Union Gas system. As the supply of natural gas in areas close to Ontario continues to
grow, there is an increased demand to access these diverse supplies at Dawn and transport them along
the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern United
States. To secure the continued reliable delivery of natural gas and to serve a growing demand for natural
gas, Union Gas has invested $1.5 billion between 2015 and 2017 to expand the Dawn-Parkway natural
gas transmission system. This has increased the takeaway capacity from Dawn to approximately 20
percent or from 6.3 bcf/d in 2014 to more than 7.5 bcf/d in 2017. A substantial amount of Union Gas’
transportation revenue is generated by fixed annual demand charges, with the average length of a long-
term contract being approximately 11 years, with the longest remaining contract term being 15 years.
Storage
Union Gas’ underground natural gas storage facilities have a working capacity of approximately 165 Bcf
in 25 underground facilities located in depleted gas fields. Union Gas’ storage pools give customers
access to all Dawn storage capacity and deliverability. Dawn's configuration provides flexibility for
injections, withdrawals and cycling. Customers can purchase both firm and interruptible storage services
at Dawn. Dawn offers customers a wide range of market choices and options with easy access to
upstream and downstream markets. During 2017, Dawn provided storage, balancing, gas loans,
transport, exchange and peaking services to over 140 counterparties.
A substantial amount of Union Gas’ storage revenue is generated by fixed annual demand charges, with
the average length of a long-term contract being approximately five years, with the longest remaining
contract term being 19 years.
NOVERCO
We own 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 Energir
LP, formerly known as Gaz Metro Limited Partnership, 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 our Common Shares.
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27
OTHER GAS DISTRIBUTION AND STORAGE
Other Gas Distribution and Storage includes natural gas distribution utility operations in the Provinces of
New Brunswick and Quebec.
Enbridge Gas New Brunswick Inc. operates the natural gas distribution franchise in the Province of New
Brunswick, has approximately 11,800 customers and is regulated by the New Brunswick Energy and
Utilities Board (EUB).
Gazifere is one of two distributors in Quebec serving more than 40,000 residential, commercial,
institutional and industrial customers. Gazifere is regulated by the Quebec Regie de l’energie.
GREEN POWER & TRANSMISSION
Green Power and Transmission consists of our investments in renewable energy assets and transmission
facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities
and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United
States primarily in Colorado, Texas, Indiana and West Virginia. We also have assets under development
located in Europe.
28
29
OTHER GAS DISTRIBUTION AND STORAGE
Other Gas Distribution and Storage includes natural gas distribution utility operations in the Provinces of
New Brunswick and Quebec.
Enbridge Gas New Brunswick Inc. operates the natural gas distribution franchise in the Province of New
Brunswick, has approximately 11,800 customers and is regulated by the New Brunswick Energy and
Utilities Board (EUB).
Gazifere is one of two distributors in Quebec serving more than 40,000 residential, commercial,
institutional and industrial customers. Gazifere is regulated by the Quebec Regie de l’energie.
GREEN POWER & TRANSMISSION
Green Power and Transmission consists of our investments in renewable energy assets and transmission
facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities
and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United
States primarily in Colorado, Texas, Indiana and West Virginia. We also have assets under development
located in Europe.
Irish Sea
North Sea
UNITED
KINGDOM
London
Brighton
and Hove
English Channel
Amsterdam
THE
NETHERLANDS
Brussels
Cologne
FRANCE
BELGIUM
GERMANY
Edmonton
Edmonton
Lethbridge
Lethbridge
Great Falls
Great Falls
Boise
Montreal
Montreal
Toronto
Toronto
Chicago
Chicago
Houston
Houston
29
Power Transmission
Renewable Energy
Offshore Wind in Development
28
Green Power and Transmission includes approximately 2,500 MW of net operating renewable and
alternative energy sources. Of this amount, approximately 930 MW of net power generating capacity
comes from wind farms located in the provinces of Alberta, Ontario and Quebec and approximately 1,040
MW of net power generating capacity comes from wind farms located in the states of Colorado, Texas,
Indiana and West Virginia, including the 249 MW Chapman Ranch Wind Project (Chapman Ranch) in
Texas, which was placed into service in late October 2017. The vast majority of the power produced from
these wind farms is sold under long-term power purchase agreements. We also have three solar facilities
located in Ontario and a solar facility located in Nevada, with 100 MW and 50 MW, respectively, of net
power generating capacity. Also included in Green Power and Transmission is the Montana-Alberta Tie-
Line, our first power transmission asset, a 300 MW transmission line from Great Falls, Montana to
Lethbridge, Alberta.
In June 2017, we announced an additional 112 MW of investment in the partnership that holds the 610
MW Hohe See Offshore Wind Project in Germany, where we have an effective 50% interest. Earlier in
2016, we announced the acquisition of Chapman Ranch, as well as the acquisition of a 50% interest in a
French offshore wind development company, Éolien Maritime France SAS. Chapman Ranch was
subsequently placed into service in late October 2017. In late 2015, we announced acquisitions of the
103-MW New Creek Wind Project in West Virginia and a 24.9% interest in the 400 MW Rampion Offshore
Wind Project in the United Kingdom. Including these acquisitions, we have invested over $5 billion in
renewable power generation and transmission since 2002.
Competition
Our Green Power and Transmission assets operate in the North American and European power markets,
which are subject to competition and the supply and demand balance for power in the provinces and
states in which they operate. The renewable energy market sector includes large utilities and small
independent power producers, which are expected to aggressively compete with us for project
development opportunities.
Supply and Demand
The power generation and transmission network in North America is expected to undergo significant
growth over the next 20 years. On the demand side, North American economic growth over the longer
term is expected to drive growing electricity demand, although continued efficiency gains are expected to
make the economy less energy-intensive and temper demand growth. On the supply side, impending
legislation in Canada is expected to accelerate the retirement of aging coal-fired generation plants,
resulting in a requirement for significant new generation capacity. While coal and nuclear facilities will
continue to be core components of 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.
North American wind and solar resources fundamentals remain strong. In the United States, there is over
85 gigawatts (GW) of installed wind power capacity and in Canada over 12 GW of installed wind power
capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered
to be some of the best in the world for large-scale solar plants and the United States currently has over
35 GW of installed solar photovoltaic capacity. In late 2015, the United States passed legislation
extending the availability of certain Federal tax incentives which have supported the profitability of wind
and solar projects. However, 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 that are not in close proximity to
markets. In the near-term, uncertainty over the availability of tax or other government incentives in various
jurisdictions, the ability to secure long-term power purchase agreements through government or investor-
owned power authorities and low market prices of electricity 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.
In Europe, the future outlook for renewable energy, especially from offshore wind in countries with long
coastlines and densely populated areas, is very positive. According to the European Wind Energy
Association, by 2030, wind energy capacity in Europe is expected to be 320 GW, including 66 GW of
offshore capacity. There is also wide public support for carbon reduction targets and broader adoption of
renewable generation across all governmental levels. Furthermore, governments in Europe are seeking
to rationalize the contribution of nuclear power to the overall energy mix, which has resulted in an
increased focus on alternative sources such as large scale offshore wind.
ENERGY SERVICES
The Energy Services businesses in Canada and the United States undertake physical commodity
marketing activity and logistical services, oversee refinery supply services and manage our volume
commitments on various pipeline systems.
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 Marketing Inc.
(Tidal). We transact at many North American market hubs and provides our customers with various
services, including transportation, storage, supply management, hedging programs and product
exchanges. Tidal 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. Tidal also provides natural gas and power
marketing services, including marketing natural gas to optimize commitments on certain natural gas
pipelines. Additionally, Tidal provides natural gas supply, transportation, balancing and storage for third
parties, leveraging its natural gas marketing expertise and access to transportation capacity.
Competition
Energy Services earnings are generated from arbitrage opportunities which, by their nature, can be
replicated by other competitors. An increase in market participants entering into similar arbitrage
transactions could have an impact on our earnings. Our efforts to mitigate competition risk includes
diversification of our marketing business by trading at the majority of major hubs in North America and
establishing long-term relationships with clients.
ELIMINATIONS AND OTHER
Eliminations and Other includes operating and administrative costs and foreign exchange costs which are
not allocated to business segments. Eliminations and Other also includes new business development
activities and general corporate investments.
INSURANCE
Our operations are subject to many hazards inherent in our industry. Our assets may experience physical
damage as a result of an accident or natural disaster. These hazards can also cause personal injury and
loss of life, severe damage to and destruction of property and equipment, pollution or environmental
damage, and suspension of operations. We maintain a comprehensive insurance program for us, our
subsidiaries and our affiliates. This program includes insurance coverage in types and amounts and with
terms and conditions that are generally consistent with coverage customary for our industry.
Although we believe our current coverage is adequate for our purposes, we have in the past had
occurrences that led to losses exceeding our then-applicable coverage limits, and there is no assurance
30
31
Green Power and Transmission includes approximately 2,500 MW of net operating renewable and
alternative energy sources. Of this amount, approximately 930 MW of net power generating capacity
comes from wind farms located in the provinces of Alberta, Ontario and Quebec and approximately 1,040
MW of net power generating capacity comes from wind farms located in the states of Colorado, Texas,
Indiana and West Virginia, including the 249 MW Chapman Ranch Wind Project (Chapman Ranch) in
Texas, which was placed into service in late October 2017. The vast majority of the power produced from
these wind farms is sold under long-term power purchase agreements. We also have three solar facilities
located in Ontario and a solar facility located in Nevada, with 100 MW and 50 MW, respectively, of net
power generating capacity. Also included in Green Power and Transmission is the Montana-Alberta Tie-
Line, our first power transmission asset, a 300 MW transmission line from Great Falls, Montana to
Lethbridge, Alberta.
In June 2017, we announced an additional 112 MW of investment in the partnership that holds the 610
MW Hohe See Offshore Wind Project in Germany, where we have an effective 50% interest. Earlier in
2016, we announced the acquisition of Chapman Ranch, as well as the acquisition of a 50% interest in a
French offshore wind development company, Éolien Maritime France SAS. Chapman Ranch was
subsequently placed into service in late October 2017. In late 2015, we announced acquisitions of the
103-MW New Creek Wind Project in West Virginia and a 24.9% interest in the 400 MW Rampion Offshore
Wind Project in the United Kingdom. Including these acquisitions, we have invested over $5 billion in
renewable power generation and transmission since 2002.
Competition
Our Green Power and Transmission assets operate in the North American and European power markets,
which are subject to competition and the supply and demand balance for power in the provinces and
states in which they operate. The renewable energy market sector includes large utilities and small
independent power producers, which are expected to aggressively compete with us for project
development opportunities.
Supply and Demand
The power generation and transmission network in North America is expected to undergo significant
growth over the next 20 years. On the demand side, North American economic growth over the longer
term is expected to drive growing electricity demand, although continued efficiency gains are expected to
make the economy less energy-intensive and temper demand growth. On the supply side, impending
legislation in Canada is expected to accelerate the retirement of aging coal-fired generation plants,
resulting in a requirement for significant new generation capacity. While coal and nuclear facilities will
continue to be core components of 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.
North American wind and solar resources fundamentals remain strong. In the United States, there is over
85 gigawatts (GW) of installed wind power capacity and in Canada over 12 GW of installed wind power
capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered
to be some of the best in the world for large-scale solar plants and the United States currently has over
35 GW of installed solar photovoltaic capacity. In late 2015, the United States passed legislation
extending the availability of certain Federal tax incentives which have supported the profitability of wind
and solar projects. However, 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 that are not in close proximity to
markets. In the near-term, uncertainty over the availability of tax or other government incentives in various
jurisdictions, the ability to secure long-term power purchase agreements through government or investor-
owned power authorities and low market prices of electricity 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
30
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.
In Europe, the future outlook for renewable energy, especially from offshore wind in countries with long
coastlines and densely populated areas, is very positive. According to the European Wind Energy
Association, by 2030, wind energy capacity in Europe is expected to be 320 GW, including 66 GW of
offshore capacity. There is also wide public support for carbon reduction targets and broader adoption of
renewable generation across all governmental levels. Furthermore, governments in Europe are seeking
to rationalize the contribution of nuclear power to the overall energy mix, which has resulted in an
increased focus on alternative sources such as large scale offshore wind.
ENERGY SERVICES
The Energy Services businesses in Canada and the United States undertake physical commodity
marketing activity and logistical services, oversee refinery supply services and manage our volume
commitments on various pipeline systems.
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 Marketing Inc.
(Tidal). We transact at many North American market hubs and provides our customers with various
services, including transportation, storage, supply management, hedging programs and product
exchanges. Tidal 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. Tidal also provides natural gas and power
marketing services, including marketing natural gas to optimize commitments on certain natural gas
pipelines. Additionally, Tidal provides natural gas supply, transportation, balancing and storage for third
parties, leveraging its natural gas marketing expertise and access to transportation capacity.
Competition
Energy Services earnings are generated from arbitrage opportunities which, by their nature, can be
replicated by other competitors. An increase in market participants entering into similar arbitrage
transactions could have an impact on our earnings. Our efforts to mitigate competition risk includes
diversification of our marketing business by trading at the majority of major hubs in North America and
establishing long-term relationships with clients.
ELIMINATIONS AND OTHER
Eliminations and Other includes operating and administrative costs and foreign exchange costs which are
not allocated to business segments. Eliminations and Other also includes new business development
activities and general corporate investments.
INSURANCE
Our operations are subject to many hazards inherent in our industry. Our assets may experience physical
damage as a result of an accident or natural disaster. These hazards can also cause personal injury and
loss of life, severe damage to and destruction of property and equipment, pollution or environmental
damage, and suspension of operations. We maintain a comprehensive insurance program for us, our
subsidiaries and our affiliates. This program includes insurance coverage in types and amounts and with
terms and conditions that are generally consistent with coverage customary for our industry.
Although we believe our current coverage is adequate for our purposes, we have in the past had
occurrences that led to losses exceeding our then-applicable coverage limits, and there is no assurance
31
that the same may not happen in the future. In the unlikely event that multiple insurable incidents which in
aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage
will be allocated among our entities on an equitable basis based on an insurance allocation agreement
among us and our subsidiaries.
We are also subject to numerous environmental laws and regulations affecting many aspects of our
present and future operations, including air emissions, water quality, wastewater discharges, solid waste
and hazardous waste. These laws and regulations generally require us to obtain and comply with a wide
variety of environmental licenses, permits, inspections and other approvals.
OPERATIONAL AND ECONOMIC REGULATION
LIQUIDS PIPELINES
Operational Regulation
Operational regulation risks relate to compliance with applicable operational rules and regulations
mandated by governments or applicable regulatory authorities, breaches of which could result in fines,
penalties, operating restrictions and an overall increase in operating and compliance costs.
Regulatory scrutiny over the integrity of liquids pipeline assets has the potential to increase operating
costs or limit future projects. Potential regulatory changes could have an impact on our future earnings
and the cost related to the construction of new projects. We believe operational regulation risk is mitigated
by active monitoring and consulting on potential regulatory requirement changes with the respective
regulators or through industry associations. We also develop robust response plans to regulatory changes
or enforcement actions. While we believe the safe and reliable operation of our 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 us.
In the United States, our interstate pipeline operations are subject to pipeline safety laws and regulations
administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the United
States Department of Transportation (DOT). These laws and regulations require us to comply with a
significant set of requirements for the design, construction, maintenance and operation of our interstate
pipelines. These laws and regulations, among other things, include requirements to monitor and maintain
the integrity of our pipelines. The regulations determine the pressures at which our pipelines can operate.
PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum
allowable operating pressure, and to improve and expand integrity management processes. Additionally,
PHMSA will establish standards for storage facilities. There remains uncertainty as to how these
standards will be implemented, but it is expected that the changes will impose additional costs on new
pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation,
pipeline failures or failures to comply with applicable regulations could result in reduction of allowable
operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines.
Should any of these risks materialize, it may have an adverse effect on our operations, earnings, financial
condition and cash flows.
In Canada, our pipeline operations are subject to pipeline safety regulations overseen by the NEB or
provincial regulators. Applicable legislation and regulation require us to comply with a significant set of
requirements for the design, construction, maintenance and operation of our pipelines. Among other
obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our
pipelines.
As in the United States, several legislative changes addressing pipeline safety in Canada have recently
come into force. The changes evidence an increased focus on the implementation of management
systems to address key areas such as emergency management, integrity management, safety, security
and environmental protection. Other legislative changes have created authority for the NEB to impose
administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as
to impose financial requirements for future abandonment and major pipeline releases.
In particular, in the United States, compliance with major Clean Air Act regulatory programs is likely to
cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our
operations, install pollution control equipment, and otherwise assure compliance. Some states in which
we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under
the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from
75 parts per billion (ppb) to 70 ppb, which may require states to implement additional emissions
regulations. The precise nature of these compliance obligations at each of our facilities has not been
finally determined and may depend in part on future regulatory changes. In addition, compliance with new
and emerging environmental regulatory programs is likely to significantly increase our operating costs
compared to historical levels.
In the United States, climate change action is evolving at state, regional and federal levels. The Supreme
Court decision in Massachusetts v. EPA in 2007 established that greenhouse gas (GHG) emissions were
pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently
subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally
subject to limits on emissions of GHGs, (except to the extent that some GHGs consist of volatile organic
compounds and nitrous oxides that are subject to emission limits). In addition, a number of provinces and
states have joined regional GHG initiatives, and a number are developing their own programs that would
mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly
focusing on the emission of methane associated with natural gas development and transmission as a
source of GHG emissions. However, as the key details of future GHG restrictions and compliance
mechanisms remain undefined, the likely future effects on our business are highly uncertain.
For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the
United States. While federal GHG related regulatory design details remain forthcoming, provincial
authorities have been actively pursuing related initiatives.
Failure to comply with environmental regulations may result in the imposition of fines, penalties and
injunctive measures affecting our operating assets. In addition, changes in environmental laws and
regulations or the enactment of new environmental laws or regulations could result in a material increase
in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain all
required environmental regulatory approvals for our operating assets or development projects. If there is
a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with
them, or if environmental laws or regulations change or are administered in a more stringent manner, the
operations of facilities or the development of new facilities could be prevented, delayed or become
subject to additional costs. We expect that costs we incur to comply with environmental regulations in the
future will have a significant effect on our earnings and cash flows.
Due to the speculative outlook regarding any United States federal and state policies, we cannot estimate
the potential effect of proposed GHG policies on our future consolidated results of operations, financial
position or cash flows. However, such legislation or regulation could materially increase our operating
costs, require material capital expenditures or create additional permitting, which could delay proposed
construction projects.
Economic Regulation
Our liquids pipelines also face economic regulatory risk. Broadly defined, economic regulation risk is the
risk that governments or regulatory agencies change or reject proposed or existing commercial
arrangements including permits and regulatory approvals for new projects. The Canadian Mainline,
Lakehead System and other liquids pipelines are subject to the actions of various regulators, including the
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33
that the same may not happen in the future. In the unlikely event that multiple insurable incidents which in
aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage
will be allocated among our entities on an equitable basis based on an insurance allocation agreement
among us and our subsidiaries.
We are also subject to numerous environmental laws and regulations affecting many aspects of our
present and future operations, including air emissions, water quality, wastewater discharges, solid waste
and hazardous waste. These laws and regulations generally require us to obtain and comply with a wide
variety of environmental licenses, permits, inspections and other approvals.
OPERATIONAL AND ECONOMIC REGULATION
LIQUIDS PIPELINES
Operational Regulation
Operational regulation risks relate to compliance with applicable operational rules and regulations
mandated by governments or applicable regulatory authorities, breaches of which could result in fines,
penalties, operating restrictions and an overall increase in operating and compliance costs.
Regulatory scrutiny over the integrity of liquids pipeline assets has the potential to increase operating
costs or limit future projects. Potential regulatory changes could have an impact on our future earnings
and the cost related to the construction of new projects. We believe operational regulation risk is mitigated
by active monitoring and consulting on potential regulatory requirement changes with the respective
regulators or through industry associations. We also develop robust response plans to regulatory changes
or enforcement actions. While we believe the safe and reliable operation of our 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 us.
In the United States, our interstate pipeline operations are subject to pipeline safety laws and regulations
administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the United
States Department of Transportation (DOT). These laws and regulations require us to comply with a
significant set of requirements for the design, construction, maintenance and operation of our interstate
pipelines. These laws and regulations, among other things, include requirements to monitor and maintain
the integrity of our pipelines. The regulations determine the pressures at which our pipelines can operate.
PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum
allowable operating pressure, and to improve and expand integrity management processes. Additionally,
PHMSA will establish standards for storage facilities. There remains uncertainty as to how these
standards will be implemented, but it is expected that the changes will impose additional costs on new
pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation,
pipeline failures or failures to comply with applicable regulations could result in reduction of allowable
operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines.
Should any of these risks materialize, it may have an adverse effect on our operations, earnings, financial
condition and cash flows.
In Canada, our pipeline operations are subject to pipeline safety regulations overseen by the NEB or
provincial regulators. Applicable legislation and regulation require us to comply with a significant set of
requirements for the design, construction, maintenance and operation of our pipelines. Among other
obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our
pipelines.
As in the United States, several legislative changes addressing pipeline safety in Canada have recently
come into force. The changes evidence an increased focus on the implementation of management
systems to address key areas such as emergency management, integrity management, safety, security
and environmental protection. Other legislative changes have created authority for the NEB to impose
administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as
to impose financial requirements for future abandonment and major pipeline releases.
In particular, in the United States, compliance with major Clean Air Act regulatory programs is likely to
cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our
operations, install pollution control equipment, and otherwise assure compliance. Some states in which
we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under
the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from
75 parts per billion (ppb) to 70 ppb, which may require states to implement additional emissions
regulations. The precise nature of these compliance obligations at each of our facilities has not been
finally determined and may depend in part on future regulatory changes. In addition, compliance with new
and emerging environmental regulatory programs is likely to significantly increase our operating costs
compared to historical levels.
In the United States, climate change action is evolving at state, regional and federal levels. The Supreme
Court decision in Massachusetts v. EPA in 2007 established that greenhouse gas (GHG) emissions were
pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently
subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally
subject to limits on emissions of GHGs, (except to the extent that some GHGs consist of volatile organic
compounds and nitrous oxides that are subject to emission limits). In addition, a number of provinces and
states have joined regional GHG initiatives, and a number are developing their own programs that would
mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly
focusing on the emission of methane associated with natural gas development and transmission as a
source of GHG emissions. However, as the key details of future GHG restrictions and compliance
mechanisms remain undefined, the likely future effects on our business are highly uncertain.
For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the
United States. While federal GHG related regulatory design details remain forthcoming, provincial
authorities have been actively pursuing related initiatives.
Failure to comply with environmental regulations may result in the imposition of fines, penalties and
injunctive measures affecting our operating assets. In addition, changes in environmental laws and
regulations or the enactment of new environmental laws or regulations could result in a material increase
in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain all
required environmental regulatory approvals for our operating assets or development projects. If there is
a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with
them, or if environmental laws or regulations change or are administered in a more stringent manner, the
operations of facilities or the development of new facilities could be prevented, delayed or become
subject to additional costs. We expect that costs we incur to comply with environmental regulations in the
future will have a significant effect on our earnings and cash flows.
Due to the speculative outlook regarding any United States federal and state policies, we cannot estimate
the potential effect of proposed GHG policies on our future consolidated results of operations, financial
position or cash flows. However, such legislation or regulation could materially increase our operating
costs, require material capital expenditures or create additional permitting, which could delay proposed
construction projects.
Economic Regulation
Our liquids pipelines also face economic regulatory risk. Broadly defined, economic regulation risk is the
risk that governments or regulatory agencies change or reject proposed or existing commercial
arrangements including permits and regulatory approvals for new projects. The Canadian Mainline,
Lakehead System and other liquids pipelines are subject to the actions of various regulators, including the
32
33
NEB and FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting of
commercial arrangements, including decisions by regulators on the applicable tariff structure or changes
in interpretations of existing regulations by courts or regulators, could have an adverse effect on our
revenues and earnings. Delays in regulatory approvals on projects such as our L3R Program, could result
in cost escalations and construction delays, which also negatively impact our operations.
We believe that economic regulatory risk is reduced through the negotiation of long-term agreements with
shippers that govern the majority of our liquids pipeline assets. We also involve our legal and regulatory
teams in the review of new projects to ensure compliance with applicable regulations as well as in the
establishment of tariffs and tolls on new and existing pipelines. However, despite our efforts to mitigate
economic regulation risk, there remains a risk that a regulator could overturn long-term agreements that
we have entered into with shippers or deny the approval and permits for new projects.
GAS TRANSMISSION & MIDSTREAM
Operational Regulation
The span of regulatory risks that apply to the Liquids Pipeline business as described above under Liquids
Pipelines also applies to the Gas Transmission and Midstream business. Additionally, most of our United
States gas transmission operations are regulated by the FERC. The FERC regulates natural gas
transmission in United States interstate commerce including the establishment of rates for services. The
FERC also regulates the construction of United States interstate natural gas pipelines and storage
facilities, including the extension, enlargement and abandonment of facilities. In addition, certain
operations are subject to oversight by state regulatory commissions. To the extent that the natural gas
intrastate pipelines that transport or store natural gas in interstate commerce provide services under
Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. The FERC may
propose and implement new rules and regulations affecting interstate natural gas transmission and
storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect
certain transmission of gas by intrastate pipelines.
Our SEP and DCP Midstream operations are subject to the jurisdiction of the Environmental Protection
Agency and various other federal, state and local environmental agencies. Our United States interstate
natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also
subject to the regulations of the DOT concerning pipeline safety.
The intrastate natural gas and NGL pipelines owned by us and DCP Midstream are subject to state
regulation. The natural gas gathering and processing activities of DCP Midstream are not subject to
FERC regulation.
Our Canadian operations are governed by various federal and provincial agencies with respect to pipeline
safety, including the NEB and the Transportation Safety Board, the British Columbia Oil and Gas
Commission, the Alberta Energy Regulator and the Ontario Technical Standards and Safety Authority.
Our Canadian natural gas transmission and distribution operations and approximately two-thirds of the
storage operations in Canada are subject to regulation by the NEB or the provincial agencies in Canada,
such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and
conditions of service, the construction of additional facilities and acquisitions. Our British Columbia
Pipeline and British Columbia Field Services business in western Canada is regulated by the NEB
pursuant to a framework for light-handed regulation under which the NEB acts on a complaints-basis for
rates associated with that business. Similarly, the rates charged by our Canadian Gas Transmission and
Midstream operations for gathering and processing services in western Canada are regulated on a
complaints-basis by applicable provincial regulators.
GAS DISTRIBUTION
Economic Regulation
Our gas distribution utility operations are regulated by the OEB and the EUB among others. Regulators’
future actions may differ from current expectations, or future legislative changes may impact the
regulatory environments in which we operate. 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.
We seek to mitigate economic regulation risk. We retain dedicated professional staff and maintain strong
relationships with customers, intervenors and regulators. The terms of rate negotiations are reviewed by
our legal, regulatory and finance teams.
Enbridge Gas Distribution
Distribution rates are set under a five-year customized incentive rate plan (IR Plan) approved in 2014 and
provide a level of stability by having a long-term agreement with the OEB which allows us to recover our
expected capital investments under the agreement, as well as an opportunity to earn above the OEB
allowed ROE. Under the customized IR Plan, we are permitted to recover, with OEB approval, certain
costs that were beyond management control, but that were necessary for the maintenance of our
services. The customized IR Plan also includes a mechanism to reassess the customized IR Plan and
return to cost of service if there are significant and unanticipated developments that threaten the
sustainability of the customized IR Plan.
Union Gas
Distribution rates, beginning in 2014, are set under a five-year incentive regulation framework using price
cap methodology. The price cap framework establishes new rates at the beginning of each year through
the use of a pricing formula rather than through the examination of revenue and cost forecasts. The
framework allows for annual inflationary rate increases, offset by a productivity factor, as well as rate
increases or decreases in the small volume customer classes where use declines or increases, and
certain adjustments to base rates. Further, it allows for the continued pass-through of gas commodity,
upstream transportation and demand side management costs, the additional pass-through of costs
associated with major capital investments and certain fuel variances, an allowance for unexpected cost
changes that are outside of management’s control, and equal sharing of tax changes between Union Gas
and customers, and finally an opportunity to earn above the OEB allowed ROE.
Environmental Regulation
Our workers, operations and facilities are subject to municipal, provincial and federal legislation which
regulate the protection of the environment and the health and safety of workers. For the environment,
primarily this includes the regulation of discharges to air, land and water; the management and disposal of
solid and hazardous waste, and contaminated soil and groundwater; and the assessment of
contaminated sites.
The operation of our gas distribution system and gas facilities comes with risk of incidents, abnormal
operating conditions or other unplanned events that could result in spills or emissions to the environment
that could exceed permitted levels. These events could result in injuries to workers or the public, fines,
penalties, adverse impacts to the environment in which we operate within, and/or property damage. We
could also incur future liability for environmental (soil and groundwater) contamination associated with
past and present site activities.
In addition to the operation of the gas distribution system, we also operate unregulated operations
including small oil and brine production and storage facilities in southwestern Ontario. Environmental risk
associated with these facilities is the possibility of spills, releases or leaks. In the event of an incident
(spill), remediation of the affected area would be required. There would also be potential for fines, orders
34
35
NEB and FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting of
commercial arrangements, including decisions by regulators on the applicable tariff structure or changes
in interpretations of existing regulations by courts or regulators, could have an adverse effect on our
revenues and earnings. Delays in regulatory approvals on projects such as our L3R Program, could result
in cost escalations and construction delays, which also negatively impact our operations.
We believe that economic regulatory risk is reduced through the negotiation of long-term agreements with
shippers that govern the majority of our liquids pipeline assets. We also involve our legal and regulatory
teams in the review of new projects to ensure compliance with applicable regulations as well as in the
establishment of tariffs and tolls on new and existing pipelines. However, despite our efforts to mitigate
economic regulation risk, there remains a risk that a regulator could overturn long-term agreements that
we have entered into with shippers or deny the approval and permits for new projects.
GAS TRANSMISSION & MIDSTREAM
Operational Regulation
The span of regulatory risks that apply to the Liquids Pipeline business as described above under Liquids
Pipelines also applies to the Gas Transmission and Midstream business. Additionally, most of our United
States gas transmission operations are regulated by the FERC. The FERC regulates natural gas
transmission in United States interstate commerce including the establishment of rates for services. The
FERC also regulates the construction of United States interstate natural gas pipelines and storage
facilities, including the extension, enlargement and abandonment of facilities. In addition, certain
operations are subject to oversight by state regulatory commissions. To the extent that the natural gas
intrastate pipelines that transport or store natural gas in interstate commerce provide services under
Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. The FERC may
propose and implement new rules and regulations affecting interstate natural gas transmission and
storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect
certain transmission of gas by intrastate pipelines.
Our SEP and DCP Midstream operations are subject to the jurisdiction of the Environmental Protection
Agency and various other federal, state and local environmental agencies. Our United States interstate
natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also
subject to the regulations of the DOT concerning pipeline safety.
The intrastate natural gas and NGL pipelines owned by us and DCP Midstream are subject to state
regulation. The natural gas gathering and processing activities of DCP Midstream are not subject to
FERC regulation.
Our Canadian operations are governed by various federal and provincial agencies with respect to pipeline
safety, including the NEB and the Transportation Safety Board, the British Columbia Oil and Gas
Commission, the Alberta Energy Regulator and the Ontario Technical Standards and Safety Authority.
Our Canadian natural gas transmission and distribution operations and approximately two-thirds of the
storage operations in Canada are subject to regulation by the NEB or the provincial agencies in Canada,
such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and
conditions of service, the construction of additional facilities and acquisitions. Our British Columbia
Pipeline and British Columbia Field Services business in western Canada is regulated by the NEB
pursuant to a framework for light-handed regulation under which the NEB acts on a complaints-basis for
rates associated with that business. Similarly, the rates charged by our Canadian Gas Transmission and
Midstream operations for gathering and processing services in western Canada are regulated on a
complaints-basis by applicable provincial regulators.
GAS DISTRIBUTION
Economic Regulation
Our gas distribution utility operations are regulated by the OEB and the EUB among others. Regulators’
future actions may differ from current expectations, or future legislative changes may impact the
regulatory environments in which we operate. 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.
We seek to mitigate economic regulation risk. We retain dedicated professional staff and maintain strong
relationships with customers, intervenors and regulators. The terms of rate negotiations are reviewed by
our legal, regulatory and finance teams.
Enbridge Gas Distribution
Distribution rates are set under a five-year customized incentive rate plan (IR Plan) approved in 2014 and
provide a level of stability by having a long-term agreement with the OEB which allows us to recover our
expected capital investments under the agreement, as well as an opportunity to earn above the OEB
allowed ROE. Under the customized IR Plan, we are permitted to recover, with OEB approval, certain
costs that were beyond management control, but that were necessary for the maintenance of our
services. The customized IR Plan also includes a mechanism to reassess the customized IR Plan and
return to cost of service if there are significant and unanticipated developments that threaten the
sustainability of the customized IR Plan.
Union Gas
Distribution rates, beginning in 2014, are set under a five-year incentive regulation framework using price
cap methodology. The price cap framework establishes new rates at the beginning of each year through
the use of a pricing formula rather than through the examination of revenue and cost forecasts. The
framework allows for annual inflationary rate increases, offset by a productivity factor, as well as rate
increases or decreases in the small volume customer classes where use declines or increases, and
certain adjustments to base rates. Further, it allows for the continued pass-through of gas commodity,
upstream transportation and demand side management costs, the additional pass-through of costs
associated with major capital investments and certain fuel variances, an allowance for unexpected cost
changes that are outside of management’s control, and equal sharing of tax changes between Union Gas
and customers, and finally an opportunity to earn above the OEB allowed ROE.
Environmental Regulation
Our workers, operations and facilities are subject to municipal, provincial and federal legislation which
regulate the protection of the environment and the health and safety of workers. For the environment,
primarily this includes the regulation of discharges to air, land and water; the management and disposal of
solid and hazardous waste, and contaminated soil and groundwater; and the assessment of
contaminated sites.
The operation of our gas distribution system and gas facilities comes with risk of incidents, abnormal
operating conditions or other unplanned events that could result in spills or emissions to the environment
that could exceed permitted levels. These events could result in injuries to workers or the public, fines,
penalties, adverse impacts to the environment in which we operate within, and/or property damage. We
could also incur future liability for environmental (soil and groundwater) contamination associated with
past and present site activities.
In addition to the operation of the gas distribution system, we also operate unregulated operations
including small oil and brine production and storage facilities in southwestern Ontario. Environmental risk
associated with these facilities is the possibility of spills, releases or leaks. In the event of an incident
(spill), remediation of the affected area would be required. There would also be potential for fines, orders
34
35
or charges under environmental legislation, and potential third-party liability claims by affected land
owners.
EMPLOYEES
The gas distribution system and our other operations must maintain a number of environmental approvals
and permits from governmental authorities to operate. As a result, these facilities and the distribution
network are subject to periodic inspection. An Annual Written Summary Report is submitted to the Ontario
Ministry of Environment and Climate Change (MOECC) to demonstrate we are in good standing in
relation to its Environmental Compliance Approvals. Failure to maintain regulatory compliance could
result in operational interruptions, fines, penalties, and/or orders for additional pollution control technology
or environmental remediation, etc. As environmental requirements and regulations become more
stringent, the cost to maintain compliance and the time required to obtain approvals has consistently
increased.
Ontario commenced a cap and trade system on January 1, 2017. Under the cap and trade regulation,
EGD and Union Gas (together, the Utilities) are required to purchase emission allowances or credits for
most of our customers’ use of natural gas as well as for emissions from our own operations. This process
is complex and requires ongoing monitoring of the carbon market and related climate change and carbon
policies not only in Ontario but also in other newly linked jurisdictions as at January 1, 2018 - namely
California and Quebec. This linkage which has been enabled in Ontario with various GHG reporting and
cap and trade regulation amendments over the course of 2017 will create a larger and more liquid market
for carbon allowances and credits, which may help to keep compliance costs for our customers down.
However, non-compliance or unexpected policy changes may cause significant changes to the cost of
maintaining compliance and needs to be closely monitored to ensure impacts are understood.
As required by the OEB Cap and Trade Framework, the Utilities each submitted 2017 Compliance Plans,
which subsequently received supportive endorsement and approval of cost recovery in 2017 rates. The
Utilities are in the process of defending their individually filed 2018 Compliance Plans. The OEB approved
use of the 2017 final rate for recovery of 2018 cap and trade compliance costs until determined otherwise.
Further, the OEB Cap and Trade Framework identifies that the Utilities are expected to file 2019/2020
Compliance Plans as well as an Annual Report summarizing 2017 results by August 1, 2018. The
Compliance Plans detail how the Utilities will meet their respective carbon compliance obligations through
carbon allowance and/or offset procurement as well as through customer and facility abatement projects
that may be deemed cost effective. By creating prudent and thoughtful plans and executing with
excellence, the Utilities can best mitigate the risk of cost disallowance.
As with previous years, in 2017 the Utilities each reported GHG emissions to the Ontario MOECC,
Environment and Climate Change Canada, and a number of voluntary reporting programs. Emissions
from Ontario combustion sources were verified in detail by a third party accredited verifier with no material
discrepancies found. Additionally, operational emissions from venting, fugitive and natural gas distribution
emissions were reported to the MOECC for the first time in 2017 in accordance with O. Reg. 143/16 -
Quantification, Reporting, and Verification of Greenhouse Gas Emissions Regulation standard
quantification methods ON. 350 and ON. 400, respectively. The Utilities continue to monitor developments
and attend stakeholder consultations in Ontario.
The Utilities utilize emissions data management processes and systems to help with the data capture and
mandatory and voluntary reporting needs. Quantification methodologies and emission factors will
continually be updated in the system as required. Each Utility publicly reports its GHG emissions and has
developed internal procedures for more frequent monthly Cap and Trade related GHG reporting.
Collectively, the Utilities continue to work with industry associations to refine quantification methodologies
and emissions factors, as well as best management practices to minimize emissions. The Utilities plans to
reduce emissions in 2018 are outlined in the Facility Abatement Plan within their respective Compliance
Plans.
We had approximately 12,700 employees as at December 31, 2017, including approximately 8,500
employees in Canada. Approximately 1,800 of our employees are subject to collective bargaining
agreements governing their employment with us. Approximately 48% of those employees are covered
under agreements that either have expired or will expire by December 31, 2018. We are currently going
through the process of collective bargaining in respect to the expired or expiring contracts. We have
mature working relationships with our labor unions and the parties have traditionally committed
themselves to the achievement of renewal agreements without a work stoppage.
EXECUTIVES AND OTHER OFFICERS
The following table sets forth information regarding our executive and other officers.
Name
Al Monaco
Age
Position
President & Chief Executive Officer
John K. Whelen
Executive Vice President & Chief Financial Officer
Cynthia L. Hansen
Executive Vice President, Utilities & Power Operations
D. Guy Jarvis
Byron C. Neiles
Robert R. Rooney
William T. Yardley
Vern D. Yu
Allen C. Capps
Executive Vice President, Liquids Pipelines
Executive Vice President, Corporate Services
Executive Vice President & Chief Legal Officer
Executive Vice President & President, Gas Transmission
& Midstream
Executive Vice President & Chief Development Officer
Vice President & Chief Accounting Officer
58
58
53
54
52
61
53
51
47
Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. He is also a
member of the Enbridge Board of Directors. Prior to being appointed President of Enbridge, Mr. Monaco
served as President, Gas Pipelines, Green Energy & International with responsibility for the growth and
operations of our gas pipelines, including the gas gathering and processing operations in the United
States, our gulf coast offshore assets and our investments in Alliance, Vector and Aux Sable, as well as
our International business development and investment activities and Green Energy.
John K. Whelen was appointed Executive Vice President and Chief Financial Officer of Enbridge on
October 15, 2014. Previously our Senior Vice President and Controller, Mr. Whelen retained executive
leadership for our financial reporting function, while assuming responsibility for our tax and treasury
functions. Mr. Whelen has been part of the Enbridge team since 1992, when he assumed the Manager of
Treasury role at Consumers Gas (now EGD).
Cynthia L. Hansen was appointed Executive Vice President, Utilities and Power Operations, on February
27, 2017. Ms. Hansen is responsible for the overall leadership and operations of EGD and Union Gas, as
well as Enbridge Gas New Brunswick Inc. and Gazifère. She also holds responsibility for the operations
of our power generating assets, which currently include renewable energy investments in wind, solar,
geothermal and hydroelectric, as well as waste heat recovery facilities and power transmission lines
owned in whole or in part by us.
D. Guy Jarvis was appointed Executive Vice President, Liquids Pipelines and Major Projects on May 2,
2016. Mr. Jarvis has been President of our Liquids Pipelines group since March 1, 2014, with
responsibility for all of our crude oil and liquids pipeline businesses across North America. Mr. Jarvis
previously held the title of Chief Commercial Officer for Liquids Pipelines, with responsibility for strategic
36
37
or charges under environmental legislation, and potential third-party liability claims by affected land
EMPLOYEES
owners.
The gas distribution system and our other operations must maintain a number of environmental approvals
and permits from governmental authorities to operate. As a result, these facilities and the distribution
network are subject to periodic inspection. An Annual Written Summary Report is submitted to the Ontario
Ministry of Environment and Climate Change (MOECC) to demonstrate we are in good standing in
relation to its Environmental Compliance Approvals. Failure to maintain regulatory compliance could
result in operational interruptions, fines, penalties, and/or orders for additional pollution control technology
or environmental remediation, etc. As environmental requirements and regulations become more
stringent, the cost to maintain compliance and the time required to obtain approvals has consistently
increased.
Ontario commenced a cap and trade system on January 1, 2017. Under the cap and trade regulation,
EGD and Union Gas (together, the Utilities) are required to purchase emission allowances or credits for
most of our customers’ use of natural gas as well as for emissions from our own operations. This process
is complex and requires ongoing monitoring of the carbon market and related climate change and carbon
policies not only in Ontario but also in other newly linked jurisdictions as at January 1, 2018 - namely
California and Quebec. This linkage which has been enabled in Ontario with various GHG reporting and
cap and trade regulation amendments over the course of 2017 will create a larger and more liquid market
for carbon allowances and credits, which may help to keep compliance costs for our customers down.
However, non-compliance or unexpected policy changes may cause significant changes to the cost of
maintaining compliance and needs to be closely monitored to ensure impacts are understood.
As required by the OEB Cap and Trade Framework, the Utilities each submitted 2017 Compliance Plans,
which subsequently received supportive endorsement and approval of cost recovery in 2017 rates. The
Utilities are in the process of defending their individually filed 2018 Compliance Plans. The OEB approved
use of the 2017 final rate for recovery of 2018 cap and trade compliance costs until determined otherwise.
Further, the OEB Cap and Trade Framework identifies that the Utilities are expected to file 2019/2020
Compliance Plans as well as an Annual Report summarizing 2017 results by August 1, 2018. The
Compliance Plans detail how the Utilities will meet their respective carbon compliance obligations through
carbon allowance and/or offset procurement as well as through customer and facility abatement projects
that may be deemed cost effective. By creating prudent and thoughtful plans and executing with
excellence, the Utilities can best mitigate the risk of cost disallowance.
As with previous years, in 2017 the Utilities each reported GHG emissions to the Ontario MOECC,
Environment and Climate Change Canada, and a number of voluntary reporting programs. Emissions
from Ontario combustion sources were verified in detail by a third party accredited verifier with no material
discrepancies found. Additionally, operational emissions from venting, fugitive and natural gas distribution
emissions were reported to the MOECC for the first time in 2017 in accordance with O. Reg. 143/16 -
Quantification, Reporting, and Verification of Greenhouse Gas Emissions Regulation standard
quantification methods ON. 350 and ON. 400, respectively. The Utilities continue to monitor developments
and attend stakeholder consultations in Ontario.
The Utilities utilize emissions data management processes and systems to help with the data capture and
mandatory and voluntary reporting needs. Quantification methodologies and emission factors will
continually be updated in the system as required. Each Utility publicly reports its GHG emissions and has
developed internal procedures for more frequent monthly Cap and Trade related GHG reporting.
Collectively, the Utilities continue to work with industry associations to refine quantification methodologies
and emissions factors, as well as best management practices to minimize emissions. The Utilities plans to
reduce emissions in 2018 are outlined in the Facility Abatement Plan within their respective Compliance
Plans.
We had approximately 12,700 employees as at December 31, 2017, including approximately 8,500
employees in Canada. Approximately 1,800 of our employees are subject to collective bargaining
agreements governing their employment with us. Approximately 48% of those employees are covered
under agreements that either have expired or will expire by December 31, 2018. We are currently going
through the process of collective bargaining in respect to the expired or expiring contracts. We have
mature working relationships with our labor unions and the parties have traditionally committed
themselves to the achievement of renewal agreements without a work stoppage.
EXECUTIVES AND OTHER OFFICERS
The following table sets forth information regarding our executive and other officers.
Name
Al Monaco
John K. Whelen
Cynthia L. Hansen
D. Guy Jarvis
Byron C. Neiles
Robert R. Rooney
William T. Yardley
Vern D. Yu
Allen C. Capps
Age
58
Position
President & Chief Executive Officer
58
53
54
52
61
53
51
47
Executive Vice President & Chief Financial Officer
Executive Vice President, Utilities & Power Operations
Executive Vice President, Liquids Pipelines
Executive Vice President, Corporate Services
Executive Vice President & Chief Legal Officer
Executive Vice President & President, Gas Transmission
& Midstream
Executive Vice President & Chief Development Officer
Vice President & Chief Accounting Officer
Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. He is also a
member of the Enbridge Board of Directors. Prior to being appointed President of Enbridge, Mr. Monaco
served as President, Gas Pipelines, Green Energy & International with responsibility for the growth and
operations of our gas pipelines, including the gas gathering and processing operations in the United
States, our gulf coast offshore assets and our investments in Alliance, Vector and Aux Sable, as well as
our International business development and investment activities and Green Energy.
John K. Whelen was appointed Executive Vice President and Chief Financial Officer of Enbridge on
October 15, 2014. Previously our Senior Vice President and Controller, Mr. Whelen retained executive
leadership for our financial reporting function, while assuming responsibility for our tax and treasury
functions. Mr. Whelen has been part of the Enbridge team since 1992, when he assumed the Manager of
Treasury role at Consumers Gas (now EGD).
Cynthia L. Hansen was appointed Executive Vice President, Utilities and Power Operations, on February
27, 2017. Ms. Hansen is responsible for the overall leadership and operations of EGD and Union Gas, as
well as Enbridge Gas New Brunswick Inc. and Gazifère. She also holds responsibility for the operations
of our power generating assets, which currently include renewable energy investments in wind, solar,
geothermal and hydroelectric, as well as waste heat recovery facilities and power transmission lines
owned in whole or in part by us.
D. Guy Jarvis was appointed Executive Vice President, Liquids Pipelines and Major Projects on May 2,
2016. Mr. Jarvis has been President of our Liquids Pipelines group since March 1, 2014, with
responsibility for all of our crude oil and liquids pipeline businesses across North America. Mr. Jarvis
previously held the title of Chief Commercial Officer for Liquids Pipelines, with responsibility for strategic
36
37
and integrated services, customer service, finance, and business and market development. Prior to Mr.
Jarvis' work in Liquids Pipelines, he served as President, Gas Distribution, providing overall leadership to
EGD, as well as Enbridge Gas New Brunswick Inc. and Gazifère.
Byron C. Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles
has oversight of our Information Technology, Human Resources, Real Estate & Workplace Services,
Supply Chain Management, Enterprise Safety and Operational Reliability, and aviation groups. Mr. Neiles
had previously held the role of Senior Vice President, Major Projects, Enterprise Safety and Operational
Reliability, and had been Senior Vice President of Major Projects since November 2011, after joining our
Major Projects group in April 2008.
Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017.
Mr. Rooney leads our legal team across the organization, as well as Public Affairs and Communications
(including Corporate Social Responsibility).
William T. Yardley was named Executive Vice President and President of Gas Transmission and
Midstream on February 27, 2017. Mr. Yardley is also the President and Chairman of the Board of SEP.
Mr. Yardley, based in Houston, was previously President of Spectra Energy’s United States Transmission
and Storage business, leading the business development, project execution, operations and environment,
health and safety efforts associated with Spectra Energy’s United States portfolio of assets.
Vern D. Yu was appointed Executive Vice President and Chief Development Officer on May 2, 2016. Mr.
Yu leads our Corporate Development team in driving growth opportunities, while also establishing capital
allocation parameters and portfolio mix. Mr. Yu also provides executive oversight to our Energy Services
group, Tidal Energy. Previously, Mr. Yu served as Senior Vice President, Corporate Planning and Chief
Development Officer. He has been the lead of our Corporate Development team since July 1, 2014.
Allen C. Capps is the Vice President and Chief Accounting Officer of Enbridge. Mr. Capps is responsible
for our accounting operations and financial reporting functions, including internal and external financial
reports. Prior to assuming his current role in 2017, Mr. Capps served as Vice President and Controller of
Spectra Energy, responsible for the financial accounting and reporting functions.
ADDITIONAL INFORMATION
Additional information about us is available on our website at www.enbridge.com, on SEDAR at
www.sedar.com and on EDGAR at www.sec.gov. The aforementioned information is made available in
accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by
reference into this Annual Report on Form 10-K. We make available free of charge, through our website,
annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and
amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as well as proxy statements, as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the SEC. Reports, proxy statements and other
information filed with the SEC may also be obtained through the SEC’s website (www.sec.gov) or by
visiting the Public Reference Room of the SEC at 100 F Street, N.E., Washington D.C. 20549 or calling
the SEC at 1-800-SEC-0330.
ENBRIDGE ENERGY PARTNERS, L.P. AND ENBRIDGE ENERGY MANAGEMENT, L.L.C.
Additional information about EEP and Enbridge Energy Management, L.L.C. can be found in their Annual
Reports on Form 10-Ks that have been filed with the SEC. These documents contain detailed disclosure
with respect to EEP and Enbridge Energy Management, L.L.C., respectively, and are publicly available on
EDGAR at www.sec.gov. No part of the Form10-Ks filed by EEP and Enbridge Energy Management,
L.L.C. are, unless otherwise specifically stated, incorporated by reference into this Annual Report on
Form 10-K.
ENBRIDGE GAS DISTRIBUTION INC.
Additional information about EGD can be found in its annual information form, financial statements and
management's discussion and analysis (MD&A) for the year ended December 31, 2017 which have been
filed with the securities commissions or similar authorities in each of the provinces of Canada. These
documents contain detailed disclosure with respect to EGD and are publicly available on SEDAR at
www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by
reference into this Annual Report on Form 10-K.
ENBRIDGE INCOME FUND
Additional information about the Fund can be found in its annual information form, financial statements
and MD&A as well as the financial statements and MD&A of EIPLP for the year ended December 31,
2017 which have been filed with the securities commissions or similar authorities in each of the provinces
of Canada. These documents contain detailed disclosure with respect to the Fund and are publicly
available on SEDAR at www.sedar.com under the Fund's profile. These documents are not, unless
otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE INCOME FUND HOLDINGS INC.
Additional information about ENF can be found in its annual information form, financial statements and
MD&A for the year ended December 31, 2017 which have been filed with the securities commissions or
similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with
respect to ENF and are publicly available on SEDAR at www.sedar.com. These documents are not,
unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE PIPELINES INC.
Additional information about EPI can be found in its annual information form, financial statements and
MD&A for the year ended December 31, 2017 which have been filed with the securities commissions or
similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with
respect to EPI and are publicly available on SEDAR at www.sedar.com. These documents are not, unless
otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
SPECTRA ENERGY PARTNERS, L.P.
Additional information about SEP can be found in its Annual Report on Form10-K that has been filed with
the SEC. This document contains detailed disclosure with respect to SEP, and is publicly available on
EDGAR at www.sec.gov. No part of the Form 10-K filed by SEP is, unless otherwise specifically stated,
incorporated by reference into this Annual Report on Form 10-K.
UNION GAS LIMITED
Additional information about Union Gas can be found in its annual information form, financial statements
and MD&A for the year ended December 31, 2017 which have been filed with the securities commissions
or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure
with respect to Union Gas and are publicly available on SEDAR at www.sedar.com. These documents are
not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
WESTCOAST ENERGY INC.
Additional information about Westcoast Energy Inc. can be found in its annual information form, financial
statements and MD&A for the year ended December 31, 2017 which have been filed with the securities
commissions or similar authorities in each of the provinces of Canada. These documents contain detailed
disclosure with respect to Westcoast Energy Inc. and are publicly available on SEDAR at www.sedar.com.
These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual
Report on Form 10-K.
38
39
and integrated services, customer service, finance, and business and market development. Prior to Mr.
Jarvis' work in Liquids Pipelines, he served as President, Gas Distribution, providing overall leadership to
EGD, as well as Enbridge Gas New Brunswick Inc. and Gazifère.
Byron C. Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles
has oversight of our Information Technology, Human Resources, Real Estate & Workplace Services,
Supply Chain Management, Enterprise Safety and Operational Reliability, and aviation groups. Mr. Neiles
had previously held the role of Senior Vice President, Major Projects, Enterprise Safety and Operational
Reliability, and had been Senior Vice President of Major Projects since November 2011, after joining our
Major Projects group in April 2008.
Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017.
Mr. Rooney leads our legal team across the organization, as well as Public Affairs and Communications
(including Corporate Social Responsibility).
William T. Yardley was named Executive Vice President and President of Gas Transmission and
Midstream on February 27, 2017. Mr. Yardley is also the President and Chairman of the Board of SEP.
Mr. Yardley, based in Houston, was previously President of Spectra Energy’s United States Transmission
and Storage business, leading the business development, project execution, operations and environment,
health and safety efforts associated with Spectra Energy’s United States portfolio of assets.
Vern D. Yu was appointed Executive Vice President and Chief Development Officer on May 2, 2016. Mr.
Yu leads our Corporate Development team in driving growth opportunities, while also establishing capital
allocation parameters and portfolio mix. Mr. Yu also provides executive oversight to our Energy Services
group, Tidal Energy. Previously, Mr. Yu served as Senior Vice President, Corporate Planning and Chief
Development Officer. He has been the lead of our Corporate Development team since July 1, 2014.
Allen C. Capps is the Vice President and Chief Accounting Officer of Enbridge. Mr. Capps is responsible
for our accounting operations and financial reporting functions, including internal and external financial
reports. Prior to assuming his current role in 2017, Mr. Capps served as Vice President and Controller of
Spectra Energy, responsible for the financial accounting and reporting functions.
ADDITIONAL INFORMATION
Additional information about us is available on our website at www.enbridge.com, on SEDAR at
www.sedar.com and on EDGAR at www.sec.gov. The aforementioned information is made available in
accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by
reference into this Annual Report on Form 10-K. We make available free of charge, through our website,
annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and
amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as well as proxy statements, as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the SEC. Reports, proxy statements and other
information filed with the SEC may also be obtained through the SEC’s website (www.sec.gov) or by
visiting the Public Reference Room of the SEC at 100 F Street, N.E., Washington D.C. 20549 or calling
the SEC at 1-800-SEC-0330.
ENBRIDGE ENERGY PARTNERS, L.P. AND ENBRIDGE ENERGY MANAGEMENT, L.L.C.
Additional information about EEP and Enbridge Energy Management, L.L.C. can be found in their Annual
Reports on Form 10-Ks that have been filed with the SEC. These documents contain detailed disclosure
with respect to EEP and Enbridge Energy Management, L.L.C., respectively, and are publicly available on
EDGAR at www.sec.gov. No part of the Form10-Ks filed by EEP and Enbridge Energy Management,
L.L.C. are, unless otherwise specifically stated, incorporated by reference into this Annual Report on
Form 10-K.
ENBRIDGE GAS DISTRIBUTION INC.
Additional information about EGD can be found in its annual information form, financial statements and
management's discussion and analysis (MD&A) for the year ended December 31, 2017 which have been
filed with the securities commissions or similar authorities in each of the provinces of Canada. These
documents contain detailed disclosure with respect to EGD and are publicly available on SEDAR at
www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by
reference into this Annual Report on Form 10-K.
ENBRIDGE INCOME FUND
Additional information about the Fund can be found in its annual information form, financial statements
and MD&A as well as the financial statements and MD&A of EIPLP for the year ended December 31,
2017 which have been filed with the securities commissions or similar authorities in each of the provinces
of Canada. These documents contain detailed disclosure with respect to the Fund and are publicly
available on SEDAR at www.sedar.com under the Fund's profile. These documents are not, unless
otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE INCOME FUND HOLDINGS INC.
Additional information about ENF can be found in its annual information form, financial statements and
MD&A for the year ended December 31, 2017 which have been filed with the securities commissions or
similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with
respect to ENF and are publicly available on SEDAR at www.sedar.com. These documents are not,
unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE PIPELINES INC.
Additional information about EPI can be found in its annual information form, financial statements and
MD&A for the year ended December 31, 2017 which have been filed with the securities commissions or
similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with
respect to EPI and are publicly available on SEDAR at www.sedar.com. These documents are not, unless
otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
SPECTRA ENERGY PARTNERS, L.P.
Additional information about SEP can be found in its Annual Report on Form10-K that has been filed with
the SEC. This document contains detailed disclosure with respect to SEP, and is publicly available on
EDGAR at www.sec.gov. No part of the Form 10-K filed by SEP is, unless otherwise specifically stated,
incorporated by reference into this Annual Report on Form 10-K.
UNION GAS LIMITED
Additional information about Union Gas can be found in its annual information form, financial statements
and MD&A for the year ended December 31, 2017 which have been filed with the securities commissions
or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure
with respect to Union Gas and are publicly available on SEDAR at www.sedar.com. These documents are
not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
WESTCOAST ENERGY INC.
Additional information about Westcoast Energy Inc. can be found in its annual information form, financial
statements and MD&A for the year ended December 31, 2017 which have been filed with the securities
commissions or similar authorities in each of the provinces of Canada. These documents contain detailed
disclosure with respect to Westcoast Energy Inc. and are publicly available on SEDAR at www.sedar.com.
These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual
Report on Form 10-K.
38
39
ITEM 1A. RISK FACTORS
Execution of our capital projects subjects us to various regulatory, development, operational and
market risks that may affect our financial results.
Our ability to successfully execute the development of our organic growth projects is subject to various
regulatory, development, operational and market risks, including:
•
•
•
•
•
•
•
•
the ability to obtain necessary approvals and permits from governments and regulatory agencies
on a timely basis and on acceptable terms and to maintain those issued approvals and permits
and satisfy the terms and conditions imposed therein;
potential changes in federal, state, provincial and local statutes and regulations, including
environmental requirements, that may prevent a project from proceeding or increase the
anticipated cost of the project;
impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and
on acceptable terms;
opposition to our projects by third parties, including special interest groups;
the availability of skilled labor, equipment and materials to complete projects;
the ability to construct projects within anticipated costs, including the risk of cost overruns
resulting from inflation or increased costs of equipment, materials or labor, contractor or supplier
non-performance, weather, geologic conditions or other factors beyond our control, that may be
material;
general economic factors that affect the demand for our projects; and
the ability to raise financing for these capital projects.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated
cost. Recent projects that have experienced delays include the United States portion of the L3R Program
(U.S. L3R Program) and NEXUS. In the fourth quarter of 2016, we determined Northern Gateway could
not proceed as envisioned. New projects may not achieve their expected investment return, which could
affect our financial results, and hinder our ability to secure future projects.
Cyber-attacks or security breaches could adversely affect our business, operations or financial
results.
Our business is dependent upon information systems and other digital technologies for controlling our
plants and pipelines, processing transactions and summarizing and reporting results of operations. The
secure processing, maintenance and transmission of information is critical to our operations. A security
breach of our network or systems could result in improper operation of our assets, potentially including
delays in the delivery or availability of our customers’ products, contamination or degradation of the
products we transport, store or distribute, or releases of hydrocarbon products for which we could be held
liable. Furthermore, we collect and store sensitive data in the ordinary course of our business, including
personal identification information of our employees as well as our proprietary business information and
that of our customers, suppliers, investors and other stakeholders. We have a cyber-security controls
framework in place which has been derived from the National Institute of Standards and Technology
Cyber-security Framework and International Organization for Standardization 27001 standards. We
monitor our control effectiveness in an increasing threat landscape and continuously take action to
improve our security posture. We have implemented a 7X24 security operations center to monitor, detect
and investigate any anomalous activity in our network together with an incident response process that we
test on a monthly basis. We conduct independent cyber-security audits and penetration tests on a regular
basis to test that our preventative and detective controls are working as designed. Despite our security
measures, our information systems may become the target of cyber-attacks or security breaches
(including employee error, malfeasance or other breaches), which could compromise our network or
systems and result in the release or loss of the information stored therein, misappropriation of assets,
disruption to our operations or damage to our facilities. Our current insurance coverage programs do not
contain specific coverage for cyber-attacks or security breaches. As a result of a cyber-attack or security
breach, we could also be liable under laws that protect the privacy of personal information, subject to
regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our
products and services, or incur additional costs for remediation and modification or enhancement of our
information systems to prevent future occurrences, all of which could adversely affect our business,
operations or financial results.
Changes in our reputation with stakeholders, special interest groups, political leadership, the
media or other entities could have negative impacts on our business, operations or financial
results.
There could be negative impacts on our business, operations or financial results due to changes in our
reputation with stakeholders, special interest groups (including non-governmental organizations), political
leadership, the media or other entities. Public opinion may be influenced by certain media and special
interest groups’ negative portrayal of the industry in which we operate as well as their opposition to
development projects, such as the Bakken Pipeline System. Potential impacts of a negative public
opinion may include:
loss of business;
•
•
•
•
•
•
loss of ability to secure growth opportunities;
delays in project execution;
legal action;
increased regulatory oversight or delays in regulatory approval; and
loss of ability to hire and retain top talent.
We are also exposed to the risk of higher costs, delays or even project cancellations due to increasing
pressure on governments and regulators by special interest groups. 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, we 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.
Pipeline operations involve numerous risks that may adversely affect our business and financial
results.
Operation of complex pipeline systems, gathering, treating, storing and processing operations involves
many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the
breakdown or failure of equipment or processes, the performance of the facilities below expected levels of
capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes,
floods, landslides or other similar events beyond our control. These types of catastrophic events could
result in loss of human life, significant damage to property, environmental pollution and impairment of our
operations, any of which could also result in substantial losses for which insurance may not be sufficient
or available and for which we may bear a part or all of the cost. We have experienced such events in the
past, including in 2010 on Lines 6A and 6B Lakehead System. which is discussed in Part II. Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and
Other Updates. In addition, we could be subject to significant fines and penalties from regulators in
connection with such events. Environmental incidents could also lead to an increased cost of operating
and insuring our assets, thereby negatively impacting earnings. An environmental incident could have
lasting reputational impacts to us and could impact our ability to work with various stakeholders. For
pipeline and storage assets located near populated areas, including residential communities, commercial
business centers, industrial sites and other public gathering locations, the level of damage resulting from
these catastrophic events could be greater.
40
41
ITEM 1A. RISK FACTORS
Execution of our capital projects subjects us to various regulatory, development, operational and
market risks that may affect our financial results.
Our ability to successfully execute the development of our organic growth projects is subject to various
regulatory, development, operational and market risks, including:
the ability to obtain necessary approvals and permits from governments and regulatory agencies
on a timely basis and on acceptable terms and to maintain those issued approvals and permits
and satisfy the terms and conditions imposed therein;
potential changes in federal, state, provincial and local statutes and regulations, including
environmental requirements, that may prevent a project from proceeding or increase the
anticipated cost of the project;
on acceptable terms;
impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and
opposition to our projects by third parties, including special interest groups;
the availability of skilled labor, equipment and materials to complete projects;
the ability to construct projects within anticipated costs, including the risk of cost overruns
resulting from inflation or increased costs of equipment, materials or labor, contractor or supplier
non-performance, weather, geologic conditions or other factors beyond our control, that may be
material;
general economic factors that affect the demand for our projects; and
the ability to raise financing for these capital projects.
•
•
•
•
•
•
•
•
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated
cost. Recent projects that have experienced delays include the United States portion of the L3R Program
(U.S. L3R Program) and NEXUS. In the fourth quarter of 2016, we determined Northern Gateway could
not proceed as envisioned. New projects may not achieve their expected investment return, which could
affect our financial results, and hinder our ability to secure future projects.
Cyber-attacks or security breaches could adversely affect our business, operations or financial
results.
Our business is dependent upon information systems and other digital technologies for controlling our
plants and pipelines, processing transactions and summarizing and reporting results of operations. The
secure processing, maintenance and transmission of information is critical to our operations. A security
breach of our network or systems could result in improper operation of our assets, potentially including
delays in the delivery or availability of our customers’ products, contamination or degradation of the
products we transport, store or distribute, or releases of hydrocarbon products for which we could be held
liable. Furthermore, we collect and store sensitive data in the ordinary course of our business, including
personal identification information of our employees as well as our proprietary business information and
that of our customers, suppliers, investors and other stakeholders. We have a cyber-security controls
framework in place which has been derived from the National Institute of Standards and Technology
Cyber-security Framework and International Organization for Standardization 27001 standards. We
monitor our control effectiveness in an increasing threat landscape and continuously take action to
improve our security posture. We have implemented a 7X24 security operations center to monitor, detect
and investigate any anomalous activity in our network together with an incident response process that we
test on a monthly basis. We conduct independent cyber-security audits and penetration tests on a regular
basis to test that our preventative and detective controls are working as designed. Despite our security
measures, our information systems may become the target of cyber-attacks or security breaches
(including employee error, malfeasance or other breaches), which could compromise our network or
systems and result in the release or loss of the information stored therein, misappropriation of assets,
disruption to our operations or damage to our facilities. Our current insurance coverage programs do not
contain specific coverage for cyber-attacks or security breaches. As a result of a cyber-attack or security
breach, we could also be liable under laws that protect the privacy of personal information, subject to
regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our
products and services, or incur additional costs for remediation and modification or enhancement of our
information systems to prevent future occurrences, all of which could adversely affect our business,
operations or financial results.
Changes in our reputation with stakeholders, special interest groups, political leadership, the
media or other entities could have negative impacts on our business, operations or financial
results.
There could be negative impacts on our business, operations or financial results due to changes in our
reputation with stakeholders, special interest groups (including non-governmental organizations), political
leadership, the media or other entities. Public opinion may be influenced by certain media and special
interest groups’ negative portrayal of the industry in which we operate as well as their opposition to
development projects, such as the Bakken Pipeline System. Potential impacts of a negative public
opinion may include:
•
•
•
•
•
•
loss of business;
loss of ability to secure growth opportunities;
delays in project execution;
legal action;
increased regulatory oversight or delays in regulatory approval; and
loss of ability to hire and retain top talent.
We are also exposed to the risk of higher costs, delays or even project cancellations due to increasing
pressure on governments and regulators by special interest groups. 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, we 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.
Pipeline operations involve numerous risks that may adversely affect our business and financial
results.
Operation of complex pipeline systems, gathering, treating, storing and processing operations involves
many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the
breakdown or failure of equipment or processes, the performance of the facilities below expected levels of
capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes,
floods, landslides or other similar events beyond our control. These types of catastrophic events could
result in loss of human life, significant damage to property, environmental pollution and impairment of our
operations, any of which could also result in substantial losses for which insurance may not be sufficient
or available and for which we may bear a part or all of the cost. We have experienced such events in the
past, including in 2010 on Lines 6A and 6B Lakehead System. which is discussed in Part II. Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and
Other Updates. In addition, we could be subject to significant fines and penalties from regulators in
connection with such events. Environmental incidents could also lead to an increased cost of operating
and insuring our assets, thereby negatively impacting earnings. An environmental incident could have
lasting reputational impacts to us and could impact our ability to work with various stakeholders. For
pipeline and storage assets located near populated areas, including residential communities, commercial
business centers, industrial sites and other public gathering locations, the level of damage resulting from
these catastrophic events could be greater.
40
41
Our assets vary in age and were constructed over many decades which may cause our inspection,
maintenance or repair costs to increase in the future.
Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived
assets, and pipeline construction and coating techniques have changed over time. Depending on the era
of construction, some assets require more frequent inspections, which could result in increased
maintenance or repair expenditures in the future. Any significant increase in these expenditures could
adversely affect our business, operations or financial results.
A service interruption could have a significant impact on our operations, and negatively impact
financial results, relationships with stakeholders and our reputation.
A service interruption due to a major power disruption or curtailment of commodity supply could have a
significant impact on our operations and negatively impact financial results, relationships with
stakeholders and our reputation. Specifically, for Gas Distribution, any prolonged interruptions would
ultimately impact gas distribution customers. Service interruptions that impact our crude oil transportation
services can negatively impact shippers’ operations and earnings as they are dependent on our services
to move their product to market or fulfill their own contractual arrangements.
Our operations involve safety risks to the public and to our workers and contractors.
Several of our pipelines and distribution systems and related assets are operated in close proximity to
populated areas and a major incident could result in injury to members of the public. In addition, given the
natural hazards inherent in our operations, our workers and contractors are subject to personal safety
risks. A public safety incident or an injury to our workers or contractors could result in reputational
damage to us, material repair costs or increased costs of operating and insuring our assets.
Our transformation projects may fail to fully deliver anticipated results.
We launched projects in 2016 to transform various processes, capabilities and reporting systems
infrastructure to continuously improve effectiveness and efficiency across the organization.
Transformation project risk is the risk that modernization projects carried out by us and our subsidiaries
do not fully deliver anticipated results due to insufficiently addressing the risks associated with project
execution and change management. This could result in negative financial, operational and reputational
impacts.
An impairment of our assets, including goodwill, property, plant, and equipment, intangible
assets, and/or equity method investments, could reduce our earnings.
GAAP requires us to test certain assets for impairment on either an annual basis or when events or
circumstances occur which indicate that the carrying value of such assets might be impaired. The
outcome of such testing could result in impairments of our assets including our goodwill, property, plant
and equipment, intangible assets, and/or equity method investments. Additionally, any asset
monetizations could result in impairments if such assets are sold or otherwise exchanged for amounts
less than their carrying value. If we determine that an impairment has occurred, we would be required to
take an immediate noncash charge to earnings.
There are utilization risks in respect to our assets.
In respect to our Liquids Pipeline assets, we are exposed to throughput risk under the CTS on the
Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets,
such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our
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 our assets. Market fundamentals, such as commodity prices and price
differentials, weather, gasoline price and consumption, alternative energy sources and global supply
disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid
hydrocarbons transported on our pipelines.
In respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to
change as a result of the development of non-conventional shale gas supplies. The increase in natural
gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift
occurred to extraction of gas in richer, wet gas areas with higher NGL content which depressed activity in
dry fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some
areas, which can adversely affect our revenues and earnings.
In respect to our Gas Distribution assets, customers are billed on a combination of both fixed charge and
volumetric basis and EGD and Union Gas' ability to collect their respective total revenue requirement (the
cost of providing service, including a reasonable return to the utility) 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 and Union Gas' respective 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 continue to place downward pressure on
consumption. In addition, conservation efforts by customers may further contribute to a decline in annual
average consumption. EGD and Union Gas have deferral accounts approved by the OEB that provide
regulatory protection against the margin impacts associated with declining annual average consumption
due to efficiencies and customers’ conservation efforts. 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. Even in those circumstances where EGD and Union Gas
each attains their respective total forecast distribution volume, they may not earn their respective
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. EGD and Union Gas each remain at risk for
the actual versus forecast large volume contract commercial and industrial volumes.
In respect to our Green Power and Transmission assets, earnings from these 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 Power and Transmission projects
are predicted using long-term historical data, wind and solar resources are subject to natural variation
from year to year and from season to season. Any prolonged reduction in wind or solar resources at any
of the Green Power and Transmission facilities could lead to decreased earnings and cash flows for us.
Additionally, inefficiencies or interruptions of Green Power and Transmission facilities due to operational
disturbances or outages resulting from weather conditions or other factors, could also impact earnings.
Power produced from Green Power and Transmission assets is also often sold to a single counterparty
under power purchase agreements or other long-term pricing arrangements. In this respect, the
performance of the Green Power and Transmission assets is dependent on each counterparty performing
its contractual obligations under the power purchase agreements or pricing arrangement applicable to it.
We rely on access to short-term and long-term capital markets to finance capital requirements and
support liquidity needs, and cost effective access to those markets can be affected, particularly if
we or our rated subsidiaries are unable to maintain an investment-grade credit rating.
A significant portion of our consolidated asset base is financed with debt. The maturity and repayment
profile of debt used to finance investments often does not correlate to cash flows from assets.
Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity
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43
Our assets vary in age and were constructed over many decades which may cause our inspection,
maintenance or repair costs to increase in the future.
Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived
assets, and pipeline construction and coating techniques have changed over time. Depending on the era
of construction, some assets require more frequent inspections, which could result in increased
maintenance or repair expenditures in the future. Any significant increase in these expenditures could
adversely affect our business, operations or financial results.
A service interruption could have a significant impact on our operations, and negatively impact
financial results, relationships with stakeholders and our reputation.
A service interruption due to a major power disruption or curtailment of commodity supply could have a
significant impact on our operations and negatively impact financial results, relationships with
stakeholders and our reputation. Specifically, for Gas Distribution, any prolonged interruptions would
ultimately impact gas distribution customers. Service interruptions that impact our crude oil transportation
services can negatively impact shippers’ operations and earnings as they are dependent on our services
to move their product to market or fulfill their own contractual arrangements.
Our operations involve safety risks to the public and to our workers and contractors.
Several of our pipelines and distribution systems and related assets are operated in close proximity to
populated areas and a major incident could result in injury to members of the public. In addition, given the
natural hazards inherent in our operations, our workers and contractors are subject to personal safety
risks. A public safety incident or an injury to our workers or contractors could result in reputational
damage to us, material repair costs or increased costs of operating and insuring our assets.
Our transformation projects may fail to fully deliver anticipated results.
We launched projects in 2016 to transform various processes, capabilities and reporting systems
infrastructure to continuously improve effectiveness and efficiency across the organization.
Transformation project risk is the risk that modernization projects carried out by us and our subsidiaries
do not fully deliver anticipated results due to insufficiently addressing the risks associated with project
execution and change management. This could result in negative financial, operational and reputational
impacts.
An impairment of our assets, including goodwill, property, plant, and equipment, intangible
assets, and/or equity method investments, could reduce our earnings.
GAAP requires us to test certain assets for impairment on either an annual basis or when events or
circumstances occur which indicate that the carrying value of such assets might be impaired. The
outcome of such testing could result in impairments of our assets including our goodwill, property, plant
and equipment, intangible assets, and/or equity method investments. Additionally, any asset
monetizations could result in impairments if such assets are sold or otherwise exchanged for amounts
less than their carrying value. If we determine that an impairment has occurred, we would be required to
take an immediate noncash charge to earnings.
There are utilization risks in respect to our assets.
In respect to our Liquids Pipeline assets, we are exposed to throughput risk under the CTS on the
Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets,
such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our
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 our assets. Market fundamentals, such as commodity prices and price
differentials, weather, gasoline price and consumption, alternative energy sources and global supply
disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid
hydrocarbons transported on our pipelines.
In respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to
change as a result of the development of non-conventional shale gas supplies. The increase in natural
gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift
occurred to extraction of gas in richer, wet gas areas with higher NGL content which depressed activity in
dry fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some
areas, which can adversely affect our revenues and earnings.
In respect to our Gas Distribution assets, customers are billed on a combination of both fixed charge and
volumetric basis and EGD and Union Gas' ability to collect their respective total revenue requirement (the
cost of providing service, including a reasonable return to the utility) 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 and Union Gas' respective 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 continue to place downward pressure on
consumption. In addition, conservation efforts by customers may further contribute to a decline in annual
average consumption. EGD and Union Gas have deferral accounts approved by the OEB that provide
regulatory protection against the margin impacts associated with declining annual average consumption
due to efficiencies and customers’ conservation efforts. 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. Even in those circumstances where EGD and Union Gas
each attains their respective total forecast distribution volume, they may not earn their respective
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. EGD and Union Gas each remain at risk for
the actual versus forecast large volume contract commercial and industrial volumes.
In respect to our Green Power and Transmission assets, earnings from these 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 Power and Transmission projects
are predicted using long-term historical data, wind and solar resources are subject to natural variation
from year to year and from season to season. Any prolonged reduction in wind or solar resources at any
of the Green Power and Transmission facilities could lead to decreased earnings and cash flows for us.
Additionally, inefficiencies or interruptions of Green Power and Transmission facilities due to operational
disturbances or outages resulting from weather conditions or other factors, could also impact earnings.
Power produced from Green Power and Transmission assets is also often sold to a single counterparty
under power purchase agreements or other long-term pricing arrangements. In this respect, the
performance of the Green Power and Transmission assets is dependent on each counterparty performing
its contractual obligations under the power purchase agreements or pricing arrangement applicable to it.
We rely on access to short-term and long-term capital markets to finance capital requirements and
support liquidity needs, and cost effective access to those markets can be affected, particularly if
we or our rated subsidiaries are unable to maintain an investment-grade credit rating.
A significant portion of our consolidated asset base is financed with debt. The maturity and repayment
profile of debt used to finance investments often does not correlate to cash flows from assets.
Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity
42
43
for capital requirements not satisfied by cash flows from operations and to fund investments originally
financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by
various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-
grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be
required to pay a higher interest rate in future financings and our potential pool of investors and funding
sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings
and/or letters of credit at various entities. These facilities typically include financial covenants and failure
to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper
or letters of credit or borrowing under the revolving credit facility, which could affect cash flows or restrict
business. Furthermore, if our short-term debt rating were to be downgraded, access to the commercial
paper market could be significantly limited. Although this would not affect our ability to draw under our
credit facilities, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement
our strategy may be affected. Restrictions on our ability to access financial markets may also affect our
ability to execute our business plan as scheduled. An inability to access capital may limit our ability to
pursue improvements or acquisitions that we may otherwise rely on for future growth. Any downgrade or
other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing
higher or access to funding sources more limited, which in turn could increase our need to provide
liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and
borrowing availability of the consolidated group.
Our forecasted assumptions may not materialize as expected on our expansion projects,
acquisitions and divestitures.
We evaluate 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 our profits.
We may not be able to sell assets or, if we are able to sell assets, to raise a sufficient amount of
capital from such asset sales. In addition, the timing to enter into and close any asset sales could
be significantly different than our expected timeline.
We are planning to monetize certain assets to execute on our strategic priority to focus on core assets
and to accelerate debt reduction and provide capital for capital and investment expenditures. Given the
commodity markets, financial markets, and other challenges currently facing the energy sector, our
competitors may also engage in asset sales leading to lower demand for the assets we wish to sell. We
may not be able to sell the assets we identify for sale on favorable terms or at all. If we are able to sell
assets, the timing of the receipt of the asset sale proceeds may not align with the timing of our capital
requirements. A failure to raise sufficient capital from asset sales or a misalignment of the timing of capital
raised and capital funding needs could have an adverse impact on our business, financial condition,
results of operations, and cash flows.
Our operations are subject to pipeline safety laws and regulations, compliance with which may
require significant capital expenditures, increase our cost of operations and affect or limit our
business plans.
Many of our operations are regulated. The nature and degree of regulation and legislation affecting
energy companies in Canada and the United States have changed significantly in past years and further
substantial changes may occur.
On February 8, 2018, the Government of Canada introduced legislation to revise the process for
assessing major resource projects. At this time, we are reviewing the proposed regulatory reforms and the
effect upon us and our subsidiaries, whether adverse or favorable, if such legislation is passed in its
current or revised form, is currently uncertain.
Compliance with legislative changes may impose additional costs on new pipeline projects as well as on
existing operations. Failure to comply with applicable regulations could result in a number of
consequences which may have an adverse effect on our operations, earnings, financial condition and
cash flows.
Our operations are subject to numerous environmental laws and regulations, compliance with
which may require significant capital expenditures, increase our cost of operations and affect or
limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present
and future operations, including air emissions, water quality, wastewater discharges, solid waste and
hazardous waste.
Failure to comply with environmental laws and regulations may result in the imposition of fines, penalties
and injunctive measures affecting our operating assets. In addition, changes in environmental laws and
regulations or the enactment of new environmental laws or regulations could result in a material increase
in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain all
required environmental regulatory approvals for our operating assets or development projects. If there is
a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with
them, or if environmental laws or regulations change or are administered in a more stringent manner, the
operations of facilities or the development of new facilities could be prevented, delayed or become
subject to additional costs. We expect that costs we incur to comply with environmental regulations in the
future will have a significant effect on our earnings and cash flows.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our
customers are rated investment-grade, are otherwise considered creditworthy or provide us security to
satisfy credit concerns. A significant amount of our credit exposures for transmission, storage, and
gathering and processing services are with customers who have an investment-grade rating (or the
equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what
extent our business would be impacted by deteriorating conditions in the economy, including possible
declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas and
oil producers may be the primary customer, our credit exposure with below investment-grade customers
may increase. It is possible that customer payment defaults, if significant, could adversely affect our
earnings and cash flows.
Our business requires the retention and recruitment of a skilled workforce, and difficulties
recruiting and retaining our workforce could result in a failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including
engineers, technical personnel and other professionals. We and our affiliates compete with other
companies in the energy industry for this skilled workforce. If we are unable to retain current employees
and/or recruit new employees of comparable knowledge and experience, our business could be
negatively impacted. In addition, we could experience increased allocated costs to retain and recruit
these professionals.
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45
for capital requirements not satisfied by cash flows from operations and to fund investments originally
financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by
various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-
grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be
required to pay a higher interest rate in future financings and our potential pool of investors and funding
sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings
and/or letters of credit at various entities. These facilities typically include financial covenants and failure
to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper
or letters of credit or borrowing under the revolving credit facility, which could affect cash flows or restrict
business. Furthermore, if our short-term debt rating were to be downgraded, access to the commercial
paper market could be significantly limited. Although this would not affect our ability to draw under our
credit facilities, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement
our strategy may be affected. Restrictions on our ability to access financial markets may also affect our
ability to execute our business plan as scheduled. An inability to access capital may limit our ability to
pursue improvements or acquisitions that we may otherwise rely on for future growth. Any downgrade or
other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing
higher or access to funding sources more limited, which in turn could increase our need to provide
liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and
borrowing availability of the consolidated group.
Our forecasted assumptions may not materialize as expected on our expansion projects,
acquisitions and divestitures.
We evaluate 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 our profits.
We may not be able to sell assets or, if we are able to sell assets, to raise a sufficient amount of
capital from such asset sales. In addition, the timing to enter into and close any asset sales could
be significantly different than our expected timeline.
We are planning to monetize certain assets to execute on our strategic priority to focus on core assets
and to accelerate debt reduction and provide capital for capital and investment expenditures. Given the
commodity markets, financial markets, and other challenges currently facing the energy sector, our
competitors may also engage in asset sales leading to lower demand for the assets we wish to sell. We
may not be able to sell the assets we identify for sale on favorable terms or at all. If we are able to sell
assets, the timing of the receipt of the asset sale proceeds may not align with the timing of our capital
requirements. A failure to raise sufficient capital from asset sales or a misalignment of the timing of capital
raised and capital funding needs could have an adverse impact on our business, financial condition,
results of operations, and cash flows.
Our operations are subject to pipeline safety laws and regulations, compliance with which may
require significant capital expenditures, increase our cost of operations and affect or limit our
business plans.
Many of our operations are regulated. The nature and degree of regulation and legislation affecting
energy companies in Canada and the United States have changed significantly in past years and further
substantial changes may occur.
On February 8, 2018, the Government of Canada introduced legislation to revise the process for
assessing major resource projects. At this time, we are reviewing the proposed regulatory reforms and the
effect upon us and our subsidiaries, whether adverse or favorable, if such legislation is passed in its
current or revised form, is currently uncertain.
Compliance with legislative changes may impose additional costs on new pipeline projects as well as on
existing operations. Failure to comply with applicable regulations could result in a number of
consequences which may have an adverse effect on our operations, earnings, financial condition and
cash flows.
Our operations are subject to numerous environmental laws and regulations, compliance with
which may require significant capital expenditures, increase our cost of operations and affect or
limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present
and future operations, including air emissions, water quality, wastewater discharges, solid waste and
hazardous waste.
Failure to comply with environmental laws and regulations may result in the imposition of fines, penalties
and injunctive measures affecting our operating assets. In addition, changes in environmental laws and
regulations or the enactment of new environmental laws or regulations could result in a material increase
in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain all
required environmental regulatory approvals for our operating assets or development projects. If there is
a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with
them, or if environmental laws or regulations change or are administered in a more stringent manner, the
operations of facilities or the development of new facilities could be prevented, delayed or become
subject to additional costs. We expect that costs we incur to comply with environmental regulations in the
future will have a significant effect on our earnings and cash flows.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our
customers are rated investment-grade, are otherwise considered creditworthy or provide us security to
satisfy credit concerns. A significant amount of our credit exposures for transmission, storage, and
gathering and processing services are with customers who have an investment-grade rating (or the
equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what
extent our business would be impacted by deteriorating conditions in the economy, including possible
declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas and
oil producers may be the primary customer, our credit exposure with below investment-grade customers
may increase. It is possible that customer payment defaults, if significant, could adversely affect our
earnings and cash flows.
Our business requires the retention and recruitment of a skilled workforce, and difficulties
recruiting and retaining our workforce could result in a failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including
engineers, technical personnel and other professionals. We and our affiliates compete with other
companies in the energy industry for this skilled workforce. If we are unable to retain current employees
and/or recruit new employees of comparable knowledge and experience, our business could be
negatively impacted. In addition, we could experience increased allocated costs to retain and recruit
these professionals.
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45
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and
resolutions adverse to us could adversely affect our financial results.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot
predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution
of some of the matters in which we are involved could require additional expenditures, in excess of
established reserves, over an extended period of time and in a range of amounts that could adversely
affect our financial results.
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of
war, and other civil unrest or activism could adversely affect our business, operations or financial
results.
Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism
may have significant effects on general economic conditions, fluctuations in consumer confidence and
spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks,
rumors or threats of war, actual conflicts involving the United States, or Canada, or military or trade
disruptions may significantly affect our operations and those of our customers. Strategic targets, such as
energy related assets, may be at greater risk of future attacks than other targets in the United States and
Canada. In addition, increased environmental activism against pipeline construction and operation could
potentially result in work delays, reduced demand for our products and services, increased legislation or
denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy
prices could result in government-imposed price controls. It is possible that any of these occurrences, or a
combination of them, could adversely affect our business, operations or financial results.
Our Liquids Pipelines results may be adversely affected by commodity prices.
Current oil sands production is very robust and is expected to grow in the future as producers actively
improve the competitiveness of their existing projects; however, prolonged low prices negatively impact
producers' balance sheets and their ability to invest. Sanctioned projects due to come on stream in the
next 24 months are not as sensitive to short-term declines in crude oil prices, as investment commitments
have already been made. A protracted long-term outlook for low crude oil prices could result in delay or
cancellation of future projects. Wide commodity price basis between Western Canada and global
tidewater markets have also negatively impacted producer netbacks and margins in the past years that
largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada
and North Dakota operating at capacity.
The tight oil plays of Western Canada and the Bakken region of North Dakota have short cycle break-
even time horizons, typically less than 24 months, and high decline rates that can be well managed
through active hedging programs and are positioned to react quickly at market signals. Accordingly,
during periods of comparatively low prices, drilling programs, unsupported by hedging programs, will be
reduced and as such supply growth from tight oil basins may be lower, which may impact volumes on our
pipeline systems.
Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our
cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure,
we likely will be prevented from realizing the full benefits of price increases above the level of the hedges.
Our hedging activities can result in substantial losses if hedging arrangements are imperfect or ineffective
and our hedging policies and procedures are not followed properly or do not work as intended. Further,
hedging contracts are subject to the credit risk that the other party may prove unable or unwilling to
perform its obligations under the contracts, particularly during periods of weak and volatile economic
conditions. In addition, certain of the financial instruments we use to hedge our commodity risk exposures
must be accounted for on a mark-to-market basis. This causes periodic earnings volatility due to
fluctuations in commodity prices.
Our Energy Services results may be adversely affected by commodity price volatility.
Energy Services generates margin by capitalizing on quality, time and location differentials when
opportunities arise. Volatility in commodity prices due to changing marketing conditions could limit margin
opportunities and impede Energy Services' ability to cover capacity commitments. Furthermore,
commodity prices could have negative earnings and cash flow impacts if the cost of the commodity is
greater than resale prices achieved by us.
Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our
risk management policies could adversely affect our business, operations or financial results.
We use derivative financial instruments to manage the risks associated with movements in foreign
exchange rates, interest rates, commodity prices and our share price to reduce volatility to our cash flows.
Based on our risk management policies, all of our derivative financial instruments are associated with an
underlying asset, liability and/or forecasted transaction. We do not enter into transactions with the
objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate
all risk of unauthorized trading and other speculative activity. Although this activity is monitored
independently by our risk management function, we remain exposed to the risk of non-compliance with
our risk management policies. We can provide no assurance that our risk management function will
detect and prevent all unauthorized trading and other violations of our risk management policies and
procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such
violations could adversely affect our business, operations or financial results.
The effects of United States Government policies on trade relations between Canada and the
United States are uncertain.
The United States Government has continued interest in renegotiating and altering the North American
Free Trade Agreement (NAFTA) with Canada and Mexico. NAFTA provides protection against tariffs,
duties and other charges or fees and assures access by the signatories. The NAFTA negotiations have
introduced a level of uncertainty in the energy markets. The outcome of the NAFTA negotiations could
result in new rules or its collapse which may be disruptive to energy markets, and could jeopardize our
ability to remain competitive and have a significant impact on us.
Our Gas Transmission and Midstream results may be adversely affected by commodity price
volatility and risks associated with our hedging activities.
The effect of comprehensive United States tax reform legislation on us, whether adverse or
favorable, is uncertain.
Our exposure to commodity price volatility is inherent to part of our natural gas processing activities. We
employ a disciplined hedging program to manage this direct commodity price risk. Because we are not
fully hedged, we may be adversely impacted by commodity price exposure on the commodities we
receive in-kind as payment for our gathering, processing, treating and transportation services. As a result
of our unhedged exposure and the pricing of our hedge positions, a substantial decline in the prices of
these commodities could adversely affect our financial results.
On December 22, 2017, President Trump signed into law H.R. 1, “An Act to provide for reconciliation
pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018” (informally titled
the Tax Cuts and Jobs Act). The effect of the Tax Cuts and Jobs Act on us, our subsidiaries and our
shareholders, whether adverse or favorable, is uncertain, but will become more clear as additional
guidance is issued.
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47
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and
resolutions adverse to us could adversely affect our financial results.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot
predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution
of some of the matters in which we are involved could require additional expenditures, in excess of
established reserves, over an extended period of time and in a range of amounts that could adversely
affect our financial results.
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of
war, and other civil unrest or activism could adversely affect our business, operations or financial
results.
Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism
may have significant effects on general economic conditions, fluctuations in consumer confidence and
spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks,
rumors or threats of war, actual conflicts involving the United States, or Canada, or military or trade
disruptions may significantly affect our operations and those of our customers. Strategic targets, such as
energy related assets, may be at greater risk of future attacks than other targets in the United States and
Canada. In addition, increased environmental activism against pipeline construction and operation could
potentially result in work delays, reduced demand for our products and services, increased legislation or
denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy
prices could result in government-imposed price controls. It is possible that any of these occurrences, or a
combination of them, could adversely affect our business, operations or financial results.
Our Liquids Pipelines results may be adversely affected by commodity prices.
Current oil sands production is very robust and is expected to grow in the future as producers actively
improve the competitiveness of their existing projects; however, prolonged low prices negatively impact
producers' balance sheets and their ability to invest. Sanctioned projects due to come on stream in the
next 24 months are not as sensitive to short-term declines in crude oil prices, as investment commitments
have already been made. A protracted long-term outlook for low crude oil prices could result in delay or
cancellation of future projects. Wide commodity price basis between Western Canada and global
tidewater markets have also negatively impacted producer netbacks and margins in the past years that
largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada
and North Dakota operating at capacity.
The tight oil plays of Western Canada and the Bakken region of North Dakota have short cycle break-
even time horizons, typically less than 24 months, and high decline rates that can be well managed
through active hedging programs and are positioned to react quickly at market signals. Accordingly,
during periods of comparatively low prices, drilling programs, unsupported by hedging programs, will be
reduced and as such supply growth from tight oil basins may be lower, which may impact volumes on our
pipeline systems.
Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our
cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure,
we likely will be prevented from realizing the full benefits of price increases above the level of the hedges.
Our hedging activities can result in substantial losses if hedging arrangements are imperfect or ineffective
and our hedging policies and procedures are not followed properly or do not work as intended. Further,
hedging contracts are subject to the credit risk that the other party may prove unable or unwilling to
perform its obligations under the contracts, particularly during periods of weak and volatile economic
conditions. In addition, certain of the financial instruments we use to hedge our commodity risk exposures
must be accounted for on a mark-to-market basis. This causes periodic earnings volatility due to
fluctuations in commodity prices.
Our Energy Services results may be adversely affected by commodity price volatility.
Energy Services generates margin by capitalizing on quality, time and location differentials when
opportunities arise. Volatility in commodity prices due to changing marketing conditions could limit margin
opportunities and impede Energy Services' ability to cover capacity commitments. Furthermore,
commodity prices could have negative earnings and cash flow impacts if the cost of the commodity is
greater than resale prices achieved by us.
Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our
risk management policies could adversely affect our business, operations or financial results.
We use derivative financial instruments to manage the risks associated with movements in foreign
exchange rates, interest rates, commodity prices and our share price to reduce volatility to our cash flows.
Based on our risk management policies, all of our derivative financial instruments are associated with an
underlying asset, liability and/or forecasted transaction. We do not enter into transactions with the
objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate
all risk of unauthorized trading and other speculative activity. Although this activity is monitored
independently by our risk management function, we remain exposed to the risk of non-compliance with
our risk management policies. We can provide no assurance that our risk management function will
detect and prevent all unauthorized trading and other violations of our risk management policies and
procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such
violations could adversely affect our business, operations or financial results.
The effects of United States Government policies on trade relations between Canada and the
United States are uncertain.
The United States Government has continued interest in renegotiating and altering the North American
Free Trade Agreement (NAFTA) with Canada and Mexico. NAFTA provides protection against tariffs,
duties and other charges or fees and assures access by the signatories. The NAFTA negotiations have
introduced a level of uncertainty in the energy markets. The outcome of the NAFTA negotiations could
result in new rules or its collapse which may be disruptive to energy markets, and could jeopardize our
ability to remain competitive and have a significant impact on us.
Our Gas Transmission and Midstream results may be adversely affected by commodity price
volatility and risks associated with our hedging activities.
The effect of comprehensive United States tax reform legislation on us, whether adverse or
favorable, is uncertain.
Our exposure to commodity price volatility is inherent to part of our natural gas processing activities. We
employ a disciplined hedging program to manage this direct commodity price risk. Because we are not
fully hedged, we may be adversely impacted by commodity price exposure on the commodities we
receive in-kind as payment for our gathering, processing, treating and transportation services. As a result
of our unhedged exposure and the pricing of our hedge positions, a substantial decline in the prices of
these commodities could adversely affect our financial results.
On December 22, 2017, President Trump signed into law H.R. 1, “An Act to provide for reconciliation
pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018” (informally titled
the Tax Cuts and Jobs Act). The effect of the Tax Cuts and Jobs Act on us, our subsidiaries and our
shareholders, whether adverse or favorable, is uncertain, but will become more clear as additional
guidance is issued.
46
47
ITEM 1B. UNRESOLVED STAFF COMMENTS
PART II
None.
ITEM 2. PROPERTIES
Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are
included in Item 1. Business.
In general, our systems are located on land owned by others and are operated under easements and
rights-of-way, licenses, leases or permits that have been granted by private land owners, First Nations,
Native American Tribes, public authorities, railways or public utilities. Our liquids systems have pumping
stations, tanks, terminals and certain other facilities that are located on land that is owned by us and/or
used by us under easements, licenses, leases or permits. Additionally, our natural gas systems have
natural gas compressor stations, processing plants and treating plants, the vast majority of which are
located on land that is owned by us, with the remainder used by us under easements, leases or permits.
Titles to our properties acquired in our liquids and natural gas systems are subject to encumbrances in
some cases. We believe that none of these burdens should materially detract from the value of these
properties or materially interfere with their use in the operation of our business.
ITEM 3. LEGAL PROCEEDINGS
We are involved in various legal and administrative proceedings and litigation arising in the ordinary
course of business. The outcome of these matters is not predictable at this time. However, we believe that
the ultimate resolution of these matters will not have a material adverse effect on our financial condition,
results of operations or cash flows in future periods. Refer to Part II. Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion
of other legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Our common stock is traded on the TSX and NYSE under the symbol “ENB.” As at January 31, 2018,
there were approximately 96,107 holders of record of our common stock. A substantially greater number
of holders of our common stock are "street name" or beneficial holders, whose shares are held by banks,
brokers and other financial institutions.
Common Stock Data by Quarter
Canadian dollars):
The following table indicates the intra-day high and low prices of our common stock on the TSX (in
Stock Price Range
The following table indicates the intra-day high and low prices of our common stock on the NYSE (in U.S.
dollars):
2017
High
Low
2016
High
Low
2017
High
Low
2016
High
Low
Q1
Q2
Q3
Q4
Dividends
$
$
US$
US$
Q1
58.28
53.87
51.31
40.03
Q1
44.52
40.25
39.40
27.43
Stock Price Range
Q2
57.75
49.61
55.05
48.73
Q2
42.92
37.37
43.39
37.02
2017
0.583
0.610
0.610
0.610
Q3
53.00
48.98
59.19
50.76
Q3
42.31
39.01
45.77
38.58
Q4
52.59
43.91
59.18
53.91
Q4
42.10
34.39
45.09
39.70
2016
0.530
0.530
0.530
0.530
The following table indicates the dividends paid per common share (in Canadian dollars):
Consistent with our objective of delivering annual cash dividend increases, we announced a quarterly
dividend of $0.671 per common share payable on March 1, 2018, which represents a 10 percent increase
from the prior quarterly rate. We expect to continue our policy of paying regular cash dividends. The
declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will
depend upon many factors, including the financial condition, earnings and capital requirements of our
operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory
constraints and other factors deemed relevant by our Board of Directors.
48
49
ITEM 1B. UNRESOLVED STAFF COMMENTS
PART II
None.
ITEM 2. PROPERTIES
included in Item 1. Business.
Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are
In general, our systems are located on land owned by others and are operated under easements and
rights-of-way, licenses, leases or permits that have been granted by private land owners, First Nations,
Native American Tribes, public authorities, railways or public utilities. Our liquids systems have pumping
stations, tanks, terminals and certain other facilities that are located on land that is owned by us and/or
used by us under easements, licenses, leases or permits. Additionally, our natural gas systems have
natural gas compressor stations, processing plants and treating plants, the vast majority of which are
located on land that is owned by us, with the remainder used by us under easements, leases or permits.
Titles to our properties acquired in our liquids and natural gas systems are subject to encumbrances in
some cases. We believe that none of these burdens should materially detract from the value of these
properties or materially interfere with their use in the operation of our business.
ITEM 3. LEGAL PROCEEDINGS
We are involved in various legal and administrative proceedings and litigation arising in the ordinary
course of business. The outcome of these matters is not predictable at this time. However, we believe that
the ultimate resolution of these matters will not have a material adverse effect on our financial condition,
results of operations or cash flows in future periods. Refer to Part II. Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion
of other legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Our common stock is traded on the TSX and NYSE under the symbol “ENB.” As at January 31, 2018,
there were approximately 96,107 holders of record of our common stock. A substantially greater number
of holders of our common stock are "street name" or beneficial holders, whose shares are held by banks,
brokers and other financial institutions.
Common Stock Data by Quarter
The following table indicates the intra-day high and low prices of our common stock on the TSX (in
Canadian dollars):
2017
High
Low
2016
High
Low
$
$
Stock Price Range
Q1
58.28
53.87
51.31
40.03
Q2
57.75
49.61
55.05
48.73
Q3
53.00
48.98
59.19
50.76
Q4
52.59
43.91
59.18
53.91
The following table indicates the intra-day high and low prices of our common stock on the NYSE (in U.S.
dollars):
2017
High
Low
2016
High
Low
US$
US$
Stock Price Range
Q1
44.52
40.25
39.40
27.43
Q2
42.92
37.37
43.39
37.02
Q3
42.31
39.01
45.77
38.58
Dividends
The following table indicates the dividends paid per common share (in Canadian dollars):
Q1
Q2
Q3
Q4
2017
0.583
0.610
0.610
0.610
Q4
42.10
34.39
45.09
39.70
2016
0.530
0.530
0.530
0.530
Consistent with our objective of delivering annual cash dividend increases, we announced a quarterly
dividend of $0.671 per common share payable on March 1, 2018, which represents a 10 percent increase
from the prior quarterly rate. We expect to continue our policy of paying regular cash dividends. The
declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will
depend upon many factors, including the financial condition, earnings and capital requirements of our
operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory
constraints and other factors deemed relevant by our Board of Directors.
48
49
Securities Authorized for Issuance Under Equity Compensation Plans
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
Securities Authorized for Issuance Under Equity Compensation Plans
the SEC relating to our 2018 annual meeting of shareholders.
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
Recent Sales of Unregistered Equity Securities
On November 29, 2017, we entered into a private placement for common shares with three institutional
Recent Sales of Unregistered Equity Securities
investors. The issuance price was $44.84, with gross proceeds of $1.5 billion. We issued 33,456,003
On November 29, 2017, we entered into a private placement for common shares with three institutional
common shares in reliance on Rule 506(b) of Regulation S. The proceeds were used to pay down short-
investors. The issuance price was $44.84, with gross proceeds of $1.5 billion. We issued 33,456,003
term indebtedness pending reinvestment in capital projects.
common shares in reliance on Rule 506(b) of Regulation S. The proceeds were used to pay down short-
term indebtedness pending reinvestment in capital projects.
On December 11, 2017, we issued 20,000,000 of Series 19 Preference Shares in Canada pursuant to a
prospectus supplement to our Canadian base shelf prospectus in reliance on Regulation S. Please refer
On December 11, 2017, we issued 20,000,000 of Series 19 Preference Shares in Canada pursuant to a
to Item 7 - Outstanding Share Data for further discussion of the transaction.
prospectus supplement to our Canadian base shelf prospectus in reliance on Regulation S. Please refer
to Item 7 - Outstanding Share Data for further discussion of the transaction.
Issuer Purchases of Equity Securities
None.
Issuer Purchases of Equity Securities
None.
Stock Performance Graph
The following graph reflects the comparative changes in the value from January 1, 2013 through
Stock Performance Graph
December 31, 2017 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the
The following graph reflects the comparative changes in the value from January 1, 2013 through
S&P/TSX Composite index and (3) the peer group index (comprising CU, FTS, IPL, PPL, TRP, D, DTE,
December 31, 2017 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the
ETE, EPD, KMI, MMP, NI, OKE, PCG, PAA, SRE and WMB). The amounts included in the table were
S&P/TSX Composite index and (3) the peer group index (comprising CU, FTS, IPL, PPL, TRP, D, DTE,
calculated assuming the reinvestment of dividends at the time dividends were paid.
ETE, EPD, KMI, MMP, NI, OKE, PCG, PAA, SRE and WMB). The amounts included in the table were
calculated assuming the reinvestment of dividends at the time dividends were paid.
Total Shareholder Return
January 1, 2013 – December 31, 2017
$220
$200
$180
$160
$140
$120
$100
$80
Jan
13
Apr
Jul
Oct
Jan
14
Apr
Jul
Oct
Jan
15
Apr
Jul
Oct
Jan
16
Apr
Jul
Oct
Jan
17
Apr
Jul
Oct
Enbridge Inc.
S&P/TSX Composite
Peer Group
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and
Supplementary Data.
(millions of Canadian dollars, except per share amounts)
Consolidated Statements of Earnings
Operating revenues
Operating income
Earnings/(loss) from continuing operations
(Earnings)/loss attributable to noncontrolling interests
and redeemable noncontrolling interests
Earnings attributable to controlling interests
Earnings/(loss) attributable to common shareholders
Common Stock Data
Earnings/(loss) per common share
Basic
Diluted
Dividends paid per common share
(millions of Canadian dollars)
Consolidated Statements of Financial Position
Long-term debt including capital leases, less current
Total assets2
portion
Years Ended December 31,
20171
20161
20151
2014
2013
$44,378 $34,560 $33,794 $37,641 $32,918
1,571
3,266
2,581
2,309
1,862
(159)
3,200
1,562
1,365
490
(407)
(240)
2,859
2,529
2,069
1,776
410
251
(37)
(203)
1,405
1,154
1.66
1.65
2.41
1.95
1.93
2.12
(0.04)
(0.04)
1.86
1.39
1.37
1.40
20171
December 31,
20161
20151
2014
2013
135
629
446
0.55
0.55
1.26
$162,093 $85,209 $84,154 $72,280 $57,196
60,865
36,494
39,391
33,423
22,357
1 Our Consolidated Statements of Earnings and Consolidated Statements of Financial Position data reflect the following
acquisitions, dispositions and impairment:
2017 - Spectra Merger Transaction, acquisition of public interest in Midcoast Energy Partners, L.P. and other impairment
2016 - Sandpiper Project impairment, gain on disposition of South Prairie Region assets, Tupper Plants acquisition and other
2015 - Goodwill impairment
2 We combined Cash and cash equivalents and other amounts previously presented as Bank indebtedness where the
corresponding bank accounts are subject to pooling arrangements.
Enbridge Inc.
S&P/ TSX Composite
Enbridge Inc.
Peer Group1
S&P/ TSX Composite
1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.
Peer Group1
1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.
100.00
100.00
100.00
100.00
100.00
100.00
2013
110.93
2013
112.99
110.93
126.35
112.99
126.35
December 31,
December 31,
2015
116.80
2015
114.53
116.80
121.45
114.53
121.45
2014
146.76
2014
124.92
146.76
158.17
124.92
158.17
January 1,
2013
January 1,
2013
2016
149.53
2016
138.67
149.53
158.82
138.67
158.82
2017
136.37
2017
151.28
136.37
163.06
151.28
163.06
50
50
51
Securities Authorized for Issuance Under Equity Compensation Plans
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
Securities Authorized for Issuance Under Equity Compensation Plans
the SEC relating to our 2018 annual meeting of shareholders.
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
Recent Sales of Unregistered Equity Securities
On November 29, 2017, we entered into a private placement for common shares with three institutional
Recent Sales of Unregistered Equity Securities
investors. The issuance price was $44.84, with gross proceeds of $1.5 billion. We issued 33,456,003
On November 29, 2017, we entered into a private placement for common shares with three institutional
common shares in reliance on Rule 506(b) of Regulation S. The proceeds were used to pay down short-
investors. The issuance price was $44.84, with gross proceeds of $1.5 billion. We issued 33,456,003
term indebtedness pending reinvestment in capital projects.
common shares in reliance on Rule 506(b) of Regulation S. The proceeds were used to pay down short-
term indebtedness pending reinvestment in capital projects.
On December 11, 2017, we issued 20,000,000 of Series 19 Preference Shares in Canada pursuant to a
prospectus supplement to our Canadian base shelf prospectus in reliance on Regulation S. Please refer
On December 11, 2017, we issued 20,000,000 of Series 19 Preference Shares in Canada pursuant to a
to Item 7 - Outstanding Share Data for further discussion of the transaction.
prospectus supplement to our Canadian base shelf prospectus in reliance on Regulation S. Please refer
to Item 7 - Outstanding Share Data for further discussion of the transaction.
Issuer Purchases of Equity Securities
Issuer Purchases of Equity Securities
None.
None.
Stock Performance Graph
The following graph reflects the comparative changes in the value from January 1, 2013 through
Stock Performance Graph
December 31, 2017 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the
The following graph reflects the comparative changes in the value from January 1, 2013 through
S&P/TSX Composite index and (3) the peer group index (comprising CU, FTS, IPL, PPL, TRP, D, DTE,
December 31, 2017 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the
ETE, EPD, KMI, MMP, NI, OKE, PCG, PAA, SRE and WMB). The amounts included in the table were
S&P/TSX Composite index and (3) the peer group index (comprising CU, FTS, IPL, PPL, TRP, D, DTE,
calculated assuming the reinvestment of dividends at the time dividends were paid.
ETE, EPD, KMI, MMP, NI, OKE, PCG, PAA, SRE and WMB). The amounts included in the table were
calculated assuming the reinvestment of dividends at the time dividends were paid.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and
Supplementary Data.
(millions of Canadian dollars, except per share amounts)
Consolidated Statements of Earnings
Operating revenues
Operating income
Earnings/(loss) from continuing operations
(Earnings)/loss attributable to noncontrolling interests
and redeemable noncontrolling interests
Earnings attributable to controlling interests
Earnings/(loss) attributable to common shareholders
Common Stock Data
Earnings/(loss) per common share
Basic
Diluted
Dividends paid per common share
Years Ended December 31,
2014
20161
20151
20171
2013
$44,378 $34,560 $33,794 $37,641 $32,918
1,365
490
1,862
(159)
2,581
2,309
3,200
1,562
1,571
3,266
(407)
2,859
2,529
(240)
2,069
1,776
410
251
(37)
(203)
1,405
1,154
1.66
1.65
2.41
20171
1.95
1.93
2.12
(0.04)
(0.04)
1.86
1.39
1.37
1.40
December 31,
20161
20151
2014
2013
135
629
446
0.55
0.55
1.26
(millions of Canadian dollars)
Consolidated Statements of Financial Position
Total assets2
Long-term debt including capital leases, less current
portion
$162,093 $85,209 $84,154 $72,280 $57,196
60,865
36,494
39,391
33,423
22,357
1 Our Consolidated Statements of Earnings and Consolidated Statements of Financial Position data reflect the following
acquisitions, dispositions and impairment:
2017 - Spectra Merger Transaction, acquisition of public interest in Midcoast Energy Partners, L.P. and other impairment
2016 - Sandpiper Project impairment, gain on disposition of South Prairie Region assets, Tupper Plants acquisition and other
2015 - Goodwill impairment
2 We combined Cash and cash equivalents and other amounts previously presented as Bank indebtedness where the
corresponding bank accounts are subject to pooling arrangements.
Enbridge Inc.
S&P/ TSX Composite
Enbridge Inc.
Peer Group1
S&P/ TSX Composite
Peer Group1
1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.
1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.
January 1,
2013
January 1,
100.00
2013
100.00
100.00
100.00
100.00
100.00
2013
110.93
2013
112.99
110.93
126.35
112.99
126.35
December 31,
December 31,
2015
116.80
2015
114.53
116.80
121.45
114.53
121.45
2014
146.76
2014
124.92
146.76
158.17
124.92
158.17
2016
149.53
2016
138.67
149.53
158.82
138.67
158.82
2017
136.37
2017
151.28
136.37
163.06
151.28
163.06
50
50
51
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITIONS AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion and analysis of our financial condition and results of operations is based on and
should be read in conjunction with "Forward-Looking Information", Part I. Item 1A. Risk Factors and our
consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial
Statements and Supplementary Data of this Annual Report on Form 10-K.
We are a Canadian company and a North American leader in delivering energy. As a transporter of
energy, we operate, in Canada and the United States, the world’s longest crude oil and liquids
transportation system. Following the combination of Enbridge and Spectra Energy Corp. (Spectra Energy)
through a stock-for-stock merger transaction on February 27, 2017 (the Merger Transaction), we are also
a leader in the natural gas transmission and midstream business moving approximately 20% of all natural
gas in the United States, serving key supply basins and markets. As a distributor of energy, we own and
operate Canada’s largest natural gas distribution company and provide distribution services in Ontario,
Quebec and New Brunswick. As a generator of energy, we have interests in approximately 3,500
megawatts (MW) (2,500 MW net) of renewable and alternative energy generating capacity which is
operating, secured or under construction, and we continue to expand our interests in wind, solar and
geothermal power.
DOMESTIC ISSUER REPORTING REQUIREMENTS
Effective January 1, 2018, we began to comply with the Securities and Exchange Commission reporting
requirements applicable to United States domestic issuers and, accordingly, we are filing our annual
report on Form 10-K for the year ended December 31, 2017 and regular periodic reports under both
Canadian and United States law thereafter.
MERGER WITH SPECTRA ENERGY
On February 27, 2017, we announced the closing of the Merger Transaction.
Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of
Enbridge for each share of Spectra Energy common stock they held. Upon closing of the Merger
Transaction, Enbridge shareholders owned approximately 57% of the combined company and Spectra
Energy shareholders owned approximately 43%.
Spectra Energy, which we now wholly-own, is one of North America’s leading natural gas delivery
companies owning and operating a large, diversified and complementary portfolio of gas transmission,
midstream gathering and processing and distribution assets. Spectra Energy also owns and operates a
crude oil pipeline system that connects Canadian and United States producers to refineries in the United
States Rocky Mountain and Midwest regions. Our combination with Spectra Energy has created the
largest energy infrastructure company in North America with an extensive portfolio of energy assets that
are well positioned to serve key supply basins and end use markets and multiple business platforms
through which to drive future growth.
A more detailed description of each of the businesses and underlying assets acquired through the Merger
Transaction is provided under Part I. Item 1. Business. The results of operations from assets acquired
through the Merger Transaction are included in our financial statements and in this management's
discussion and analysis (MD&A) on a prospective basis from the closing date of the Merger Transaction.
Subsequent to the completion of the Merger Transaction, our activities continue to be carried out through
five business segments: Liquids Pipelines; Gas Transmission and Midstream (previously known as Gas
Pipelines and Processing); Gas Distribution; Green Power and Transmission; and Energy Services.
Effective February 27, 2017, as a result of the Merger Transaction:
•
Liquids Pipelines also includes results from the operation of the Express-Platte System;
• Gas Transmission and Midstream also includes Spectra Energy’s United States Storage and
Transmission Assets, Canadian Pipeline & Field Services, Canadian Gas Transmission and
Midstream and Maritimes & Northeast U.S. and Canada businesses, as well as the results of the
Company’s 50% interest in DCP Midstream, LLC (DCP Midstream); and
• Gas Distribution also includes results from the operation of Union Gas Limited (Union Gas).
UNITED STATES TAX REFORM
On December 22, 2017, the United States enacted the “Tax Cuts and Jobs Act” (TCJA). Substantially all
of the provisions in the TCJA are effective for taxation years beginning after December 31, 2017. The
TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code),
including amendments which significantly change the taxation of individuals and business entities, and
includes specific provisions related to regulated public utilities which includes our various regulated gas
pipeline businesses. The most significant changes that impact us, included in the TCJA, are reductions in
the corporate federal income tax rate from 35% to 21%, and several technical provisions including,
among others, a onetime deemed repatriation or “toll” tax on undistributed earnings and profits of US
controlled foreign affiliates, including Canadian subsidiaries. The specific provisions related to regulated
public utilities in the TCJA generally allow for the continued deductibility of interest expense, the
elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, and
the continuance of certain rate normalization requirements for accelerated depreciation benefits. For
other operations, immediate full expensing of capital expenditures placed into service after September 27,
2017 and before January 1, 2023 (before January 1, 2024 for qualified long production period property)
will be available under the TCJA. Inversely to the regulated public utility operations, interest deductions
will be more restrictive for other operations as existing interest expense limitations are broadened to apply
to all interest paid and the allowable deduction is reduced from 50% to 30% of adjusted taxable income.
Changes in the Code from the TCJA had a material impact on our consolidated financial statements as at
and for the year ended December 31, 2017. Under generally accepted accounting principles in the United
States of America (U.S. GAAP), the tax effects of changes in tax laws must be recognized in the period in
which the law is enacted, or December 22, 2017 for the TCJA. Thus, at the date of enactment, our
deferred tax liability was re-measured based upon the new tax rate. For some of our gas pipeline entities
with regulated cost of service rate mechanisms, the change in the deferred tax liability is offset by a
regulatory liability. In the event of a future rate case, and subject to further regulatory guidance, we
anticipate that the regulatory liability may be required to be amortized over the remaining useful life of the
affected assets and would be one of many factors to be considered in establishing go forward rates. For
all other operations, the change in the deferred tax liability is recorded as an adjustment to our deferred
tax provision.
While certain elements of the TCJA require clarification through more detailed regulation or interpretive
guidance, based on the information and guidance available and our analysis (including computations of
income tax effects) completed to date, at this time, we do not expect that the TCJA will have a material
economic impact on us going forward.
For additional information, refer to Item 8. Financial Statements and Supplementary Data - Note 24.
Income Taxes.
52
53
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITIONS AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion and analysis of our financial condition and results of operations is based on and
should be read in conjunction with "Forward-Looking Information", Part I. Item 1A. Risk Factors and our
consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial
Statements and Supplementary Data of this Annual Report on Form 10-K.
We are a Canadian company and a North American leader in delivering energy. As a transporter of
energy, we operate, in Canada and the United States, the world’s longest crude oil and liquids
transportation system. Following the combination of Enbridge and Spectra Energy Corp. (Spectra Energy)
through a stock-for-stock merger transaction on February 27, 2017 (the Merger Transaction), we are also
a leader in the natural gas transmission and midstream business moving approximately 20% of all natural
gas in the United States, serving key supply basins and markets. As a distributor of energy, we own and
operate Canada’s largest natural gas distribution company and provide distribution services in Ontario,
Quebec and New Brunswick. As a generator of energy, we have interests in approximately 3,500
megawatts (MW) (2,500 MW net) of renewable and alternative energy generating capacity which is
operating, secured or under construction, and we continue to expand our interests in wind, solar and
geothermal power.
DOMESTIC ISSUER REPORTING REQUIREMENTS
Effective January 1, 2018, we began to comply with the Securities and Exchange Commission reporting
requirements applicable to United States domestic issuers and, accordingly, we are filing our annual
report on Form 10-K for the year ended December 31, 2017 and regular periodic reports under both
Canadian and United States law thereafter.
MERGER WITH SPECTRA ENERGY
On February 27, 2017, we announced the closing of the Merger Transaction.
Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of
Enbridge for each share of Spectra Energy common stock they held. Upon closing of the Merger
Transaction, Enbridge shareholders owned approximately 57% of the combined company and Spectra
Energy shareholders owned approximately 43%.
Spectra Energy, which we now wholly-own, is one of North America’s leading natural gas delivery
companies owning and operating a large, diversified and complementary portfolio of gas transmission,
midstream gathering and processing and distribution assets. Spectra Energy also owns and operates a
crude oil pipeline system that connects Canadian and United States producers to refineries in the United
States Rocky Mountain and Midwest regions. Our combination with Spectra Energy has created the
largest energy infrastructure company in North America with an extensive portfolio of energy assets that
are well positioned to serve key supply basins and end use markets and multiple business platforms
through which to drive future growth.
A more detailed description of each of the businesses and underlying assets acquired through the Merger
Transaction is provided under Part I. Item 1. Business. The results of operations from assets acquired
through the Merger Transaction are included in our financial statements and in this management's
discussion and analysis (MD&A) on a prospective basis from the closing date of the Merger Transaction.
Subsequent to the completion of the Merger Transaction, our activities continue to be carried out through
five business segments: Liquids Pipelines; Gas Transmission and Midstream (previously known as Gas
Pipelines and Processing); Gas Distribution; Green Power and Transmission; and Energy Services.
Effective February 27, 2017, as a result of the Merger Transaction:
•
Liquids Pipelines also includes results from the operation of the Express-Platte System;
• Gas Transmission and Midstream also includes Spectra Energy’s United States Storage and
Transmission Assets, Canadian Pipeline & Field Services, Canadian Gas Transmission and
Midstream and Maritimes & Northeast U.S. and Canada businesses, as well as the results of the
Company’s 50% interest in DCP Midstream, LLC (DCP Midstream); and
• Gas Distribution also includes results from the operation of Union Gas Limited (Union Gas).
UNITED STATES TAX REFORM
On December 22, 2017, the United States enacted the “Tax Cuts and Jobs Act” (TCJA). Substantially all
of the provisions in the TCJA are effective for taxation years beginning after December 31, 2017. The
TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code),
including amendments which significantly change the taxation of individuals and business entities, and
includes specific provisions related to regulated public utilities which includes our various regulated gas
pipeline businesses. The most significant changes that impact us, included in the TCJA, are reductions in
the corporate federal income tax rate from 35% to 21%, and several technical provisions including,
among others, a onetime deemed repatriation or “toll” tax on undistributed earnings and profits of US
controlled foreign affiliates, including Canadian subsidiaries. The specific provisions related to regulated
public utilities in the TCJA generally allow for the continued deductibility of interest expense, the
elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, and
the continuance of certain rate normalization requirements for accelerated depreciation benefits. For
other operations, immediate full expensing of capital expenditures placed into service after September 27,
2017 and before January 1, 2023 (before January 1, 2024 for qualified long production period property)
will be available under the TCJA. Inversely to the regulated public utility operations, interest deductions
will be more restrictive for other operations as existing interest expense limitations are broadened to apply
to all interest paid and the allowable deduction is reduced from 50% to 30% of adjusted taxable income.
Changes in the Code from the TCJA had a material impact on our consolidated financial statements as at
and for the year ended December 31, 2017. Under generally accepted accounting principles in the United
States of America (U.S. GAAP), the tax effects of changes in tax laws must be recognized in the period in
which the law is enacted, or December 22, 2017 for the TCJA. Thus, at the date of enactment, our
deferred tax liability was re-measured based upon the new tax rate. For some of our gas pipeline entities
with regulated cost of service rate mechanisms, the change in the deferred tax liability is offset by a
regulatory liability. In the event of a future rate case, and subject to further regulatory guidance, we
anticipate that the regulatory liability may be required to be amortized over the remaining useful life of the
affected assets and would be one of many factors to be considered in establishing go forward rates. For
all other operations, the change in the deferred tax liability is recorded as an adjustment to our deferred
tax provision.
While certain elements of the TCJA require clarification through more detailed regulation or interpretive
guidance, based on the information and guidance available and our analysis (including computations of
income tax effects) completed to date, at this time, we do not expect that the TCJA will have a material
economic impact on us going forward.
For additional information, refer to Item 8. Financial Statements and Supplementary Data - Note 24.
Income Taxes.
52
53
UNITED STATES SPONSORED VEHICLE STRATEGY
In 2017, we continued the ongoing evaluation of our investment in our United States sponsored vehicles,
and alternatives to such investment, and we completed or announced certain strategic reviews and
transactions. We intend to review our United States sponsored vehicle strategy on a continuing basis.
From time to time, we may formulate plans or proposals with respect to such matters and hold
discussions with or make formal proposals to the board of directors of the sponsored vehicles or other
third parties. These plans or proposals may, subject to price, market and general economic and fiscal
conditions and other factors, include potential consolidations, acquisition or sale of assets or securities,
changes to capital structure or other transactions.
On April 28, 2017, we announced the completion of a strategic review of Enbridge Energy Partners, L.P.
(EEP). The following actions, together with the measures announced in January 2017 and disclosed in
our 2016 annual MD&A, have been taken to date to enhance EEP’s value proposition to its unitholders
and to us:
Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.
On April 27, 2017, we completed our previously-announced merger through which we privatized Midcoast
Energy Partners, L.P. (MEP) by acquiring all of the outstanding publicly-held common units of MEP,
through a wholly-owned subsidiary, for total consideration of approximately US$170 million.
On June 28, 2017, through a wholly-owned subsidiary, we acquired all of EEP’s interest in the MEP gas
gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of
MEP of US$953 million.
As a result of the above transactions, we now own 100% of the MEP gas gathering and processing
business.
Finalization of Bakken Pipeline System Joint Funding Agreement
On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy
Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System). On April 27, 2017, we entered
into a joint funding arrangement with EEP whereby we own 75% and EEP owns 25% of the combined
27.6% effective interest in the Bakken Pipeline System (our jointly held interest). Under this arrangement,
EEP has retained a five-year option to acquire from us an additional 20% interest of the jointly held
interest. On finalization of this joint funding arrangement, EEP repaid the outstanding balance on its US
$1.5 billion credit agreement with us, which it had drawn upon to fund the initial purchase.
EEP Strategic Restructuring Actions
On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by us at face value
of US$1.2 billion through the issuance of 64.3 million Class A common units to us. Further, we irrevocably
waived all of our rights associated with our ownership of 66.1 million Class D units and 1,000 Incentive
Distribution Units (IDUs) of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units
are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US
$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable
waiver was effective with respect to distributions declared with a record date after April 27, 2017. In
connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US
$0.583 per unit to US$0.35 per unit.
The irrevocable waiver of the Class D units and IDUs, the redemption of the Series 1 Preferred Units and
the reduction in the quarterly distributions will result in a lower contribution of earnings from EEP. This
lower contribution will be partially offset by an increased contribution of earnings as a result of our
increased ownership in the Class A common units post restructuring.
Restructuring of SEP Incentive Distribution Rights
On January 22, 2018, Enbridge and Spectra Energy Partners, LP (SEP) announced the execution of a
definitive agreement, resulting in us converting all of our incentive distribution rights (IDRs) and general
partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the
transaction, all of the IDRs have been eliminated. We now hold a non-economic general partner interest
in SEP and own approximately 403 million of SEP common units, representing approximately 83% of
SEP's outstanding common units.
ASSET MONETIZATION
In conjunction with the announcement of the Merger Transaction in September 2016, we announced our
intention to divest $2 billion of assets over the ensuing 12 months in order to further strengthen our post-
combination balance sheet and enhance the financial flexibility of the combined entity. With the
completion of the Secondary Offering noted below, the Ozark pipeline system sale, the Olympic refined
products pipeline sale and other divestitures completed in 2016 and previously disclosed, we exceeded
the $2 billion monetization target established on announcement of the Merger Transaction.
On April 18, 2017, Enbridge Income Fund Holdings Inc. (ENF) completed a secondary offering of
17,347,750 ENF common shares to the public at a price of $33.15 per share, for gross proceeds to us of
approximately $0.6 billion (the Secondary Offering). To effect the Secondary Offering, we exchanged
21,657,617 Enbridge Income Fund (Fund) units we owned for an equivalent amount of ENF common
shares. In order to maintain our 19.9% ownership interest in ENF, we retained 4,309,867 of the common
shares we received in the exchange, and sold the balance to the public through the Secondary Offering.
We used the proceeds from the Secondary Offering to pay down short-term debt, pending reinvestment in
our growing portfolio of secured projects. Upon closing of the Secondary Offering, our total economic
interest in ENF decreased from 86.9% to 84.6%.
On November 29, 2017, we finalized our 2018-2020 Strategic Plan and announced that we have
identified a further $10 billion of non-core assets, of which a minimum of $3 billion we intend to sell or
monetize in 2018. As a result of the announcement, we are in the process of selling certain assets within
the US Midstream business of our Gas Transmission and Midstream segment. Refer to Item 8. Financial
Statements and Supplementary Data - Note 7. Acquisitions and Dispositions.
ALBERTA CLIPPER (LINE 67) PRESIDENTIAL PERMIT
On October 16, 2017, we received a Presidential permit for Line 67, following a nearly five-year process
of review. Line 67 currently operates under an existing Presidential permit that was issued by the State
Department in 2009 and the 2017 Presidential permit authorizes us to fully utilize Line 67's capacity
across the United States/Canada border.
Line 67 is a key component of our mainline system, which United States refineries rely on to provide vital
products to consumers across the Midwest United States.
For additional information on Line 67, refer to Growth Projects - Commercially Secured Projects - Liquids
Pipelines - Lakehead System Mainline Expansion.
54
55
UNITED STATES SPONSORED VEHICLE STRATEGY
In 2017, we continued the ongoing evaluation of our investment in our United States sponsored vehicles,
and alternatives to such investment, and we completed or announced certain strategic reviews and
transactions. We intend to review our United States sponsored vehicle strategy on a continuing basis.
From time to time, we may formulate plans or proposals with respect to such matters and hold
discussions with or make formal proposals to the board of directors of the sponsored vehicles or other
third parties. These plans or proposals may, subject to price, market and general economic and fiscal
conditions and other factors, include potential consolidations, acquisition or sale of assets or securities,
changes to capital structure or other transactions.
On April 28, 2017, we announced the completion of a strategic review of Enbridge Energy Partners, L.P.
(EEP). The following actions, together with the measures announced in January 2017 and disclosed in
our 2016 annual MD&A, have been taken to date to enhance EEP’s value proposition to its unitholders
and to us:
Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.
On April 27, 2017, we completed our previously-announced merger through which we privatized Midcoast
Energy Partners, L.P. (MEP) by acquiring all of the outstanding publicly-held common units of MEP,
through a wholly-owned subsidiary, for total consideration of approximately US$170 million.
On June 28, 2017, through a wholly-owned subsidiary, we acquired all of EEP’s interest in the MEP gas
gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of
MEP of US$953 million.
business.
As a result of the above transactions, we now own 100% of the MEP gas gathering and processing
Finalization of Bakken Pipeline System Joint Funding Agreement
On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy
Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System). On April 27, 2017, we entered
into a joint funding arrangement with EEP whereby we own 75% and EEP owns 25% of the combined
27.6% effective interest in the Bakken Pipeline System (our jointly held interest). Under this arrangement,
EEP has retained a five-year option to acquire from us an additional 20% interest of the jointly held
interest. On finalization of this joint funding arrangement, EEP repaid the outstanding balance on its US
$1.5 billion credit agreement with us, which it had drawn upon to fund the initial purchase.
EEP Strategic Restructuring Actions
On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by us at face value
of US$1.2 billion through the issuance of 64.3 million Class A common units to us. Further, we irrevocably
waived all of our rights associated with our ownership of 66.1 million Class D units and 1,000 Incentive
Distribution Units (IDUs) of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units
are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US
$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable
waiver was effective with respect to distributions declared with a record date after April 27, 2017. In
connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US
$0.583 per unit to US$0.35 per unit.
The irrevocable waiver of the Class D units and IDUs, the redemption of the Series 1 Preferred Units and
the reduction in the quarterly distributions will result in a lower contribution of earnings from EEP. This
lower contribution will be partially offset by an increased contribution of earnings as a result of our
increased ownership in the Class A common units post restructuring.
Restructuring of SEP Incentive Distribution Rights
On January 22, 2018, Enbridge and Spectra Energy Partners, LP (SEP) announced the execution of a
definitive agreement, resulting in us converting all of our incentive distribution rights (IDRs) and general
partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the
transaction, all of the IDRs have been eliminated. We now hold a non-economic general partner interest
in SEP and own approximately 403 million of SEP common units, representing approximately 83% of
SEP's outstanding common units.
ASSET MONETIZATION
In conjunction with the announcement of the Merger Transaction in September 2016, we announced our
intention to divest $2 billion of assets over the ensuing 12 months in order to further strengthen our post-
combination balance sheet and enhance the financial flexibility of the combined entity. With the
completion of the Secondary Offering noted below, the Ozark pipeline system sale, the Olympic refined
products pipeline sale and other divestitures completed in 2016 and previously disclosed, we exceeded
the $2 billion monetization target established on announcement of the Merger Transaction.
On April 18, 2017, Enbridge Income Fund Holdings Inc. (ENF) completed a secondary offering of
17,347,750 ENF common shares to the public at a price of $33.15 per share, for gross proceeds to us of
approximately $0.6 billion (the Secondary Offering). To effect the Secondary Offering, we exchanged
21,657,617 Enbridge Income Fund (Fund) units we owned for an equivalent amount of ENF common
shares. In order to maintain our 19.9% ownership interest in ENF, we retained 4,309,867 of the common
shares we received in the exchange, and sold the balance to the public through the Secondary Offering.
We used the proceeds from the Secondary Offering to pay down short-term debt, pending reinvestment in
our growing portfolio of secured projects. Upon closing of the Secondary Offering, our total economic
interest in ENF decreased from 86.9% to 84.6%.
On November 29, 2017, we finalized our 2018-2020 Strategic Plan and announced that we have
identified a further $10 billion of non-core assets, of which a minimum of $3 billion we intend to sell or
monetize in 2018. As a result of the announcement, we are in the process of selling certain assets within
the US Midstream business of our Gas Transmission and Midstream segment. Refer to Item 8. Financial
Statements and Supplementary Data - Note 7. Acquisitions and Dispositions.
ALBERTA CLIPPER (LINE 67) PRESIDENTIAL PERMIT
On October 16, 2017, we received a Presidential permit for Line 67, following a nearly five-year process
of review. Line 67 currently operates under an existing Presidential permit that was issued by the State
Department in 2009 and the 2017 Presidential permit authorizes us to fully utilize Line 67's capacity
across the United States/Canada border.
Line 67 is a key component of our mainline system, which United States refineries rely on to provide vital
products to consumers across the Midwest United States.
For additional information on Line 67, refer to Growth Projects - Commercially Secured Projects - Liquids
Pipelines - Lakehead System Mainline Expansion.
54
55
CANADIAN RESTRUCTURING PLAN
Effective September 1, 2015, under an agreement with the Fund and ENF, Enbridge transferred its
Canadian Liquids Pipelines business, held by Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines
(Athabasca) Inc. (EPAI), and certain Canadian renewable energy assets to the Fund Group (comprising
the Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries of
EIPLP) for consideration valued at $30.4 billion plus incentive distribution and performance rights (the
Canadian Restructuring Plan). The consideration that we received included $18.7 billion of units in the
Fund Group, comprised of $3 billion of Fund units and $15.7 billion of equity units of EIPLP, in which the
Fund has an interest. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion.
RESULTS OF OPERATIONS
(millions of Canadian dollars, except per share amounts)
Segment earnings before interest, income taxes and
depreciation and amortization
Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Eliminations and Other
Depreciation and amortization
Interest expense
Income tax recovery/(expense)
(Earnings)/loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Preference share dividends
Earnings/(loss) attributable to common shareholders
Earnings/(loss) per common share
Diluted earnings/(loss) per common share
Year ended
December 31,
2017
2016
2015
6,395
(1,269)
1,390
372
(263)
(337)
(3,163)
(2,556)
2,697
(407)
(330)
2,529
1.66
1.65
4,926
464
831
344
(183)
(101)
(2,240)
(1,590)
(142)
(240)
(293)
1,776
1.95
1.93
3,033
43
763
363
324
(867)
(2,024)
(1,624)
(170)
410
(288)
(37)
(0.04)
(0.04)
EARNINGS/(LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS
Year ended December 31, 2017 compared with year ended December 31, 2016
Earnings Attributable to Common Shareholders for the year ended December 31, 2017 were positively
impacted by contributions of approximately $2,574 million from new assets following the completion of the
Merger Transaction.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
Earnings Attributable to Common Shareholders decreased by $151 million due to certain unusual,
infrequent or other factors, primarily explained by the following:
•
a loss of $4,391 million ($2,753 million after-tax attributable to us) and related goodwill
impairment of $102 million resulting from the classification of certain assets as held for sale and
the subsequent measurement at the lower of their carrying value or fair value less costs to sell,
refer to Item 8. Financial Statements and Supplementary Data - Note 7. Acquisitions and
Dispositions;
•
employee severance and restructuring costs of $354 million ($273 million after-tax attributable to
us) in 2017, compared with $82 million in the corresponding 2016 period, related to a corporate
reorganization initiative and the Merger Transaction, refer to Merger with Spectra Energy;
•
project development and transaction costs of $205 million ($155 after-tax attributable to us) in
2017, compared with $86 million in the corresponding 2016 period, related to the Merger
Transaction, refer to Merger with Spectra Energy;
•
the absence of a gain of $850 million ($520 million after-tax attributable to us) recorded in 2016
related to the disposition of the South Prairie Region assets, as discussed below; partially offset
by
Income Taxes;
•
a non-cash, $1,936 million income tax benefit ($2,045 million federal tax recovery net of a $109
million state deferred tax expense) due to the enactment of the TCJA by the United States in
December 2017, refer to Item 8. Financial Statements and Supplementary Data - Note 24.
•
a non-cash, unrealized derivative fair value gain of $1,109 million in 2017 ($624 million after-tax
attributable to us), compared with $543 million ($459 million after-tax attributable to us) in the
corresponding 2016 period reflecting net fair value gains and losses arising from changes in the
mark-to-market value of derivative financial instruments used to manage foreign exchange and
commodity prices risks; and
•
the absence of cumulative asset impairment charges of $1,561 million ($456 million after-tax
attributable to us) recorded in 2016 related to EEP's Sandpiper Project, the Northern Gateway
Project and Eddystone Rail, as discussed below.
We have a comprehensive long-term economic hedging program to mitigate interest rate, foreign
exchange and commodity price risks which creates volatility in short-term earnings through the
recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge
these risks. Over the long term, we believe our hedging program supports the reliable cash flows and
dividend growth upon which our investors value proposition is based.
After taking into consideration the factors above, the remaining $1,670 million decrease is primarily
explained by the following significant business factors:
increased depreciation and amortization expense primarily resulting from a significant number of
new assets placed into service in 2017;
increased interest expense primarily resulting from the settlement of certain pre-issuance hedges;
increased earnings attributable to noncontrolling interests and redeemable noncontrolling
interests in 2017, compared with the corresponding 2016 period. The increase was driven by
higher earnings attributable to noncontrolling interests in EEP during 2017 as a result of the EEP
•
•
•
strategic restructuring actions;
56
57
CANADIAN RESTRUCTURING PLAN
Effective September 1, 2015, under an agreement with the Fund and ENF, Enbridge transferred its
Canadian Liquids Pipelines business, held by Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines
(Athabasca) Inc. (EPAI), and certain Canadian renewable energy assets to the Fund Group (comprising
the Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries of
EIPLP) for consideration valued at $30.4 billion plus incentive distribution and performance rights (the
Canadian Restructuring Plan). The consideration that we received included $18.7 billion of units in the
Fund Group, comprised of $3 billion of Fund units and $15.7 billion of equity units of EIPLP, in which the
Fund has an interest. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion.
RESULTS OF OPERATIONS
(millions of Canadian dollars, except per share amounts)
Segment earnings before interest, income taxes and
depreciation and amortization
Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Eliminations and Other
Depreciation and amortization
Interest expense
Income tax recovery/(expense)
(Earnings)/loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Preference share dividends
Earnings/(loss) attributable to common shareholders
Earnings/(loss) per common share
Diluted earnings/(loss) per common share
Year ended
December 31,
2017
2016
2015
6,395
(1,269)
1,390
372
(263)
(337)
(3,163)
(2,556)
2,697
(407)
(330)
2,529
1.66
1.65
4,926
3,033
464
831
344
(183)
(101)
(2,240)
(1,590)
(142)
(240)
(293)
1,776
1.95
1.93
43
763
363
324
(867)
(2,024)
(1,624)
(170)
410
(288)
(37)
(0.04)
(0.04)
EARNINGS/(LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS
Year ended December 31, 2017 compared with year ended December 31, 2016
Earnings Attributable to Common Shareholders for the year ended December 31, 2017 were positively
impacted by contributions of approximately $2,574 million from new assets following the completion of the
Merger Transaction.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
Earnings Attributable to Common Shareholders decreased by $151 million due to certain unusual,
infrequent or other factors, primarily explained by the following:
•
•
•
•
•
•
•
a loss of $4,391 million ($2,753 million after-tax attributable to us) and related goodwill
impairment of $102 million resulting from the classification of certain assets as held for sale and
the subsequent measurement at the lower of their carrying value or fair value less costs to sell,
refer to Item 8. Financial Statements and Supplementary Data - Note 7. Acquisitions and
Dispositions;
employee severance and restructuring costs of $354 million ($273 million after-tax attributable to
us) in 2017, compared with $82 million in the corresponding 2016 period, related to a corporate
reorganization initiative and the Merger Transaction, refer to Merger with Spectra Energy;
project development and transaction costs of $205 million ($155 after-tax attributable to us) in
2017, compared with $86 million in the corresponding 2016 period, related to the Merger
Transaction, refer to Merger with Spectra Energy;
the absence of a gain of $850 million ($520 million after-tax attributable to us) recorded in 2016
related to the disposition of the South Prairie Region assets, as discussed below; partially offset
by
a non-cash, $1,936 million income tax benefit ($2,045 million federal tax recovery net of a $109
million state deferred tax expense) due to the enactment of the TCJA by the United States in
December 2017, refer to Item 8. Financial Statements and Supplementary Data - Note 24.
Income Taxes;
a non-cash, unrealized derivative fair value gain of $1,109 million in 2017 ($624 million after-tax
attributable to us), compared with $543 million ($459 million after-tax attributable to us) in the
corresponding 2016 period reflecting net fair value gains and losses arising from changes in the
mark-to-market value of derivative financial instruments used to manage foreign exchange and
commodity prices risks; and
the absence of cumulative asset impairment charges of $1,561 million ($456 million after-tax
attributable to us) recorded in 2016 related to EEP's Sandpiper Project, the Northern Gateway
Project and Eddystone Rail, as discussed below.
We have a comprehensive long-term economic hedging program to mitigate interest rate, foreign
exchange and commodity price risks which creates volatility in short-term earnings through the
recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge
these risks. Over the long term, we believe our hedging program supports the reliable cash flows and
dividend growth upon which our investors value proposition is based.
After taking into consideration the factors above, the remaining $1,670 million decrease is primarily
explained by the following significant business factors:
•
•
•
increased depreciation and amortization expense primarily resulting from a significant number of
new assets placed into service in 2017;
increased interest expense primarily resulting from the settlement of certain pre-issuance hedges;
increased earnings attributable to noncontrolling interests and redeemable noncontrolling
interests in 2017, compared with the corresponding 2016 period. The increase was driven by
higher earnings attributable to noncontrolling interests in EEP during 2017 as a result of the EEP
strategic restructuring actions;
56
57
•
•
•
•
the absence of earnings from certain assets that were divested since the third quarter of 2016;
partially offset by
strong contributions from our Liquids Pipelines segment due to higher throughput primarily
attributable to capacity optimization initiatives implemented in 2017 which significantly reduced
heavy crude oil apportionment allowing incremental heavy crude oil barrels to be shipped;
contributions from new Liquids Pipelines assets placed into service in 2017; and
increased earnings from our Gas Transmission and Midstream segment in 2017 due to favorable
seasonal firm revenue and a full year of contributions from assets acquired in 2016.
Lower earnings per common share for 2017, compared with the corresponding 2016 period, is primarily
due to the increase in common shares from the issuance of approximately 33 million common shares in
December 2017 in a private placement offering, the issuance of approximately 691 million common
shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of
approximately 75 million common shares in 2016 through the public offering of 56 million common shares
in the first quarter of 2016, and ongoing quarterly issuances under our Dividend Reinvestment Program.
Additional earnings from the assets acquired in the Merger Transaction were offset by certain unusual,
infrequent or other factors, as discussed above.
Year ended December 31, 2016 compared with year ended December 31, 2015
Earnings Attributable to Common Shareholders increased by $1,601 million due to certain unusual,
infrequent or other factors, primarily explained by the following:
•
•
•
•
•
•
a gain of $850 million ($520 million after-tax attributable to us) within the Liquids Pipelines
segment related to the disposition of the South Prairie Region assets in December 2016;
a non-cash, unrealized derivative fair value gain of $543 million in 2016, compared with a $2,017
million unrealized derivative fair value loss in the corresponding 2015 period reflecting net fair
value gains and losses arising from changes in the mark-to-market value of derivative financial
instruments used to manage foreign exchange and commodity price risks;
the absence of a goodwill impairment charge of $440 million ($167 million after-tax attributable to
us) recognized in the second quarter of 2015 related to EEP’s natural gas and natural gas liquids
(NGL) businesses as a result of the prolonged decline in commodity prices which reduced
producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas
and NGL pipelines and processing systems; partially offset by
an impairment charge of $1,004 million ($81 million after-tax attributable to us) in 2016, including
related project costs, on EEP's Sandpiper Project resulting from the withdrawal of regulatory
applications for the project in September 2016 that were pending with the Minnesota Public
Utilities Commission (MNPUC);
an impairment charge of $373 million ($272 million after-tax attributable to us) related to the
Northern Gateway Project recorded in the fourth quarter of 2016, after the Canadian Federal
Government directed the National Energy Board (NEB) to dismiss our Northern Gateway Project
application and rescind the Certificates of Public Convenience and Necessity for the project; and
an impairment charge of $184 million ($108 million after-tax attributable to us) recorded in 2016
related to our 75% joint venture interest in Eddystone Rail, located in the Philadelphia,
Pennsylvania area. Demand for Eddystone Rail services declined as a result of a significant
decrease in Bakken crude oil and West Africa/Brent crude oil and increased competition in the
region.
After taking into consideration the factors above, the remaining $212 million increase is primarily
explained by the following significant business factors:
•
•
strong contributions from our Liquids Pipelines segment which benefited from a number of new
assets that were placed into service in 2015;
throughput growth period over period on the Canadian Mainline, Lakehead Pipeline System
(Lakehead System) and Regional Oil Sands System primarily due to strong oil sands production
growth in western Canada enabled by completed pipeline expansion projects;
•
contributions from the United States Gulf Coast and Mid-Continent systems in 2016, attributable
to increased transportation revenues mainly resulting from an increase in the level of committed
take-or-pay volumes on the Flanagan South Pipeline (Flanagan South);
•
contributions from Enbridge Offshore Pipelines' Heidelberg Oil Pipeline (Heidelberg Pipeline)
which was placed into service in January 2016 and Canadian Gas Transmission and Midstream’s
Tupper Main and Tupper West gas plants (the Tupper Plants) which were acquired on April 1,
2016; partially offset by
•
higher earnings attributable to noncontrolling interests and redeemable noncontrolling interests in
2016 compared with 2015 driven by stronger operating performance at EEP as a result of
stronger contributions from its liquids business;
•
the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which
led to a temporary shutdown of certain of our upstream pipelines and terminal facilities resulting
in a disruption of service on our Regional Oil Sands System with corresponding impacts into and
out of our downstream pipelines, including Canadian Mainline and the Lakehead System;
•
a combination of a lower average International Joint Tariff (IJT) Residual Benchmark Toll and a
lower foreign exchange hedge rate period over period used to convert Canadian Mainline United
States dollar toll revenues to Canadian dollars;
•
the performance of the United States portion of the Bakken Pipeline System where contributions
decreased period over period primarily due to a lower surcharge on tolls subject to annual
adjustment;
expiration of contracts;
NGL market; and
•
•
•
lower contributions in 2016 from EEP’s Berthold rail facility as a result of declining volumes on
the compression of certain crude oil location and quality differentials and the impact of a weaker
depreciation and amortization expense increased period over period primarily as a result of a
significant number of new assets placed into service in 2016.
REVENUES
We generate revenues from three primary sources: transportation and other services, gas distribution
sales and commodity sales. Transportation and other services revenues are earned from our crude oil
and natural gas pipeline transportation businesses and also include power production revenues from our
portfolio of renewable and power generation assets. For our transportation assets operating under
market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for
transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of
the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in
accordance with tolls established by the regulator, and in most cost-of-service based arrangements are
reflective of our cost to provide the service plus a regulator-approved rate of return. Higher transportation
and other services revenues reflected increased throughput on our core liquids pipeline assets combined
with the incremental revenues associated with assets placed into service over the past two years.
Gas distribution sales revenues are recognized in a manner consistent with the underlying rate-setting
mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are
primarily driven by volumes delivered, which vary with weather and customer composition and utilization,
as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates
and does not ultimately impact earnings due to its flow-through nature.
Commodity sales of $26,286 million, $22,816 million and $23,842 million for the year ended
December 31, 2017, 2016 and 2015, respectively, were generated primarily through our Energy Services
operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas,
power and NGLs to generate a margin, which is typically a small fraction of gross revenue. While sales
revenue generated from these operations are impacted by commodity prices, net margins and earnings
are relatively insensitive to commodity prices and reflect activity levels which are driven by differences in
commodity prices between locations, grades and points in time, rather than on absolute prices. Any
residual commodity margin risk is closely monitored and managed. Revenues from these operations
58
59
•
•
•
•
•
•
•
•
the absence of earnings from certain assets that were divested since the third quarter of 2016;
partially offset by
strong contributions from our Liquids Pipelines segment due to higher throughput primarily
attributable to capacity optimization initiatives implemented in 2017 which significantly reduced
heavy crude oil apportionment allowing incremental heavy crude oil barrels to be shipped;
contributions from new Liquids Pipelines assets placed into service in 2017; and
increased earnings from our Gas Transmission and Midstream segment in 2017 due to favorable
seasonal firm revenue and a full year of contributions from assets acquired in 2016.
Lower earnings per common share for 2017, compared with the corresponding 2016 period, is primarily
due to the increase in common shares from the issuance of approximately 33 million common shares in
December 2017 in a private placement offering, the issuance of approximately 691 million common
shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of
approximately 75 million common shares in 2016 through the public offering of 56 million common shares
in the first quarter of 2016, and ongoing quarterly issuances under our Dividend Reinvestment Program.
Additional earnings from the assets acquired in the Merger Transaction were offset by certain unusual,
infrequent or other factors, as discussed above.
Year ended December 31, 2016 compared with year ended December 31, 2015
Earnings Attributable to Common Shareholders increased by $1,601 million due to certain unusual,
infrequent or other factors, primarily explained by the following:
a gain of $850 million ($520 million after-tax attributable to us) within the Liquids Pipelines
segment related to the disposition of the South Prairie Region assets in December 2016;
a non-cash, unrealized derivative fair value gain of $543 million in 2016, compared with a $2,017
million unrealized derivative fair value loss in the corresponding 2015 period reflecting net fair
value gains and losses arising from changes in the mark-to-market value of derivative financial
instruments used to manage foreign exchange and commodity price risks;
•
the absence of a goodwill impairment charge of $440 million ($167 million after-tax attributable to
us) recognized in the second quarter of 2015 related to EEP’s natural gas and natural gas liquids
(NGL) businesses as a result of the prolonged decline in commodity prices which reduced
producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas
and NGL pipelines and processing systems; partially offset by
•
an impairment charge of $1,004 million ($81 million after-tax attributable to us) in 2016, including
related project costs, on EEP's Sandpiper Project resulting from the withdrawal of regulatory
applications for the project in September 2016 that were pending with the Minnesota Public
Utilities Commission (MNPUC);
•
an impairment charge of $373 million ($272 million after-tax attributable to us) related to the
Northern Gateway Project recorded in the fourth quarter of 2016, after the Canadian Federal
Government directed the National Energy Board (NEB) to dismiss our Northern Gateway Project
application and rescind the Certificates of Public Convenience and Necessity for the project; and
•
an impairment charge of $184 million ($108 million after-tax attributable to us) recorded in 2016
related to our 75% joint venture interest in Eddystone Rail, located in the Philadelphia,
Pennsylvania area. Demand for Eddystone Rail services declined as a result of a significant
decrease in Bakken crude oil and West Africa/Brent crude oil and increased competition in the
region.
After taking into consideration the factors above, the remaining $212 million increase is primarily
explained by the following significant business factors:
strong contributions from our Liquids Pipelines segment which benefited from a number of new
assets that were placed into service in 2015;
throughput growth period over period on the Canadian Mainline, Lakehead Pipeline System
(Lakehead System) and Regional Oil Sands System primarily due to strong oil sands production
growth in western Canada enabled by completed pipeline expansion projects;
•
•
•
•
•
•
•
•
•
contributions from the United States Gulf Coast and Mid-Continent systems in 2016, attributable
to increased transportation revenues mainly resulting from an increase in the level of committed
take-or-pay volumes on the Flanagan South Pipeline (Flanagan South);
contributions from Enbridge Offshore Pipelines' Heidelberg Oil Pipeline (Heidelberg Pipeline)
which was placed into service in January 2016 and Canadian Gas Transmission and Midstream’s
Tupper Main and Tupper West gas plants (the Tupper Plants) which were acquired on April 1,
2016; partially offset by
higher earnings attributable to noncontrolling interests and redeemable noncontrolling interests in
2016 compared with 2015 driven by stronger operating performance at EEP as a result of
stronger contributions from its liquids business;
the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which
led to a temporary shutdown of certain of our upstream pipelines and terminal facilities resulting
in a disruption of service on our Regional Oil Sands System with corresponding impacts into and
out of our downstream pipelines, including Canadian Mainline and the Lakehead System;
a combination of a lower average International Joint Tariff (IJT) Residual Benchmark Toll and a
lower foreign exchange hedge rate period over period used to convert Canadian Mainline United
States dollar toll revenues to Canadian dollars;
the performance of the United States portion of the Bakken Pipeline System where contributions
decreased period over period primarily due to a lower surcharge on tolls subject to annual
adjustment;
lower contributions in 2016 from EEP’s Berthold rail facility as a result of declining volumes on
expiration of contracts;
the compression of certain crude oil location and quality differentials and the impact of a weaker
NGL market; and
depreciation and amortization expense increased period over period primarily as a result of a
significant number of new assets placed into service in 2016.
REVENUES
We generate revenues from three primary sources: transportation and other services, gas distribution
sales and commodity sales. Transportation and other services revenues are earned from our crude oil
and natural gas pipeline transportation businesses and also include power production revenues from our
portfolio of renewable and power generation assets. For our transportation assets operating under
market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for
transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of
the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in
accordance with tolls established by the regulator, and in most cost-of-service based arrangements are
reflective of our cost to provide the service plus a regulator-approved rate of return. Higher transportation
and other services revenues reflected increased throughput on our core liquids pipeline assets combined
with the incremental revenues associated with assets placed into service over the past two years.
Gas distribution sales revenues are recognized in a manner consistent with the underlying rate-setting
mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are
primarily driven by volumes delivered, which vary with weather and customer composition and utilization,
as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates
and does not ultimately impact earnings due to its flow-through nature.
Commodity sales of $26,286 million, $22,816 million and $23,842 million for the year ended
December 31, 2017, 2016 and 2015, respectively, were generated primarily through our Energy Services
operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas,
power and NGLs to generate a margin, which is typically a small fraction of gross revenue. While sales
revenue generated from these operations are impacted by commodity prices, net margins and earnings
are relatively insensitive to commodity prices and reflect activity levels which are driven by differences in
commodity prices between locations, grades and points in time, rather than on absolute prices. Any
residual commodity margin risk is closely monitored and managed. Revenues from these operations
58
59
depend on activity levels, which vary from year-to-year depending on market conditions and commodity
prices.
•
the absence of a gain of $850 million recorded in 2016 related to the sale of non-core South
Prairie Region assets.
Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign
exchange and commodity price contracts used to manage exposures from movements in foreign
exchange rates and commodity prices. The mark-to-market accounting creates volatility and impacts the
comparability of revenues in the short-term, but we believe over the long-term, the economic hedging
program supports reliable cash flows and dividend growth.
DIVIDENDS
We have paid common share dividends in every year since we became a publicly traded company in
1953. In November 2017, we announced a 10% increase in our quarterly dividend to $0.671 per common
share, or $2.684 annualized, effective with the dividend payable on March 1, 2018.
BUSINESS SEGMENTS
Effective December 31, 2017, we changed our segment-level profit measure to EBITDA from the previous
measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and
Processing segment to Gas Transmission and Midstream. The presentation of the prior years' tables has
been revised in order to align with the current presentation.
LIQUIDS PIPELINES
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
EBITDA increased by $1,177 million due to certain unusual, infrequent or other factors, primarily
2017
2016
2015
explained by the following:
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization
6,395
4,926
3,033
to manage foreign exchange and commodity price risks;
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $285 million of contributions
from new assets following the completion of the Merger Transaction.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
EBITDA increased by $1,312 million due to certain unusual, infrequent or other factors, primarily
explained by the following:
•
•
•
•
•
a non-cash, unrealized gain of $875 million in 2017 compared with $474 million in 2016 reflecting
net fair value gains and losses arising from changes in the mark-to-market value of derivative
financial instruments used to manage foreign exchange and commodity price risks;
the absence of an impairment charge of $1,004 million recorded in 2016, including related project
costs, on EEP's Sandpiper Project resulting from the withdrawal of the regulatory applications in
September 2016 that were pending with the MNPUC;
the absence of an impairment charge of $373 million recorded in 2016 related to the Northern
Gateway Project due to our conclusion that the project could not proceed as envisioned as a
result of the Federal Government's decision to dismiss the application for Certificate of Public
Convenience and Necessity;
the absence of an impairment charge of $184 million recorded in 2016 related to our 75% joint
venture interest in Eddystone Rail attributable to market conditions which impacted volumes at
the rail facility;
a gain of $72 million on sale of pipe partially offset by project wind-down costs related to EEP’s
Sandpiper Project; partially offset by
60
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
After taking into consideration the factors above, the remaining $128 million decrease is primarily
explained by the following significant business factors:
a lower contribution of $46 million from Mid-Continent assets primarily due to lower contracted
storage revenues and the sale of the Ozark Pipeline system in the first quarter of 2017;
a lower contribution of $76 million resulting from the sale of the South Prairie Region assets in
December 2016;
higher Lakehead System operating costs including costs to implement EEP’s signed settlement
agreement regarding the Lines 6A and 6B crude oil releases (the Consent Decree) approved by
the United States Department of Justice (DOJ) in May 2017;
the unfavorable effect of translating United States dollar EBITDA at a lower United States to
Canadian dollar average exchange rate (Average Exchange Rate) as compared with 2016,
inclusive of the impact of settlements under our foreign exchange hedging program; partially
offset by
contributions of from new assets placed into service including the Regional Oil Sands
Optimization Project and the Norlite Pipeline System and the acquisition of a minority interest in
the Bakken Pipeline System that went into service in June 2017; and
higher Canadian Mainline and Lakehead System throughput period over period resulting from
capacity optimization initiatives.
Year ended December 31, 2016 compared with year ended December 31, 2015
•
a non-cash, unrealized gain of $474 million in 2016 compared with an unrealized loss of $1,500
million in 2015 reflecting net fair value gains and losses on derivative financial instruments used
a gain of $850 million in 2016 related to the sale of non-core South Prairie Region assets;
the absence of an impairment charge of $86 million recorded in 2015 related to EEP's Berthold
rail facility due to contracts that were not renewed beyond 2016;
hydrostatic testing recoveries of $15 million in 2016 compared with charges of $72 million in
2015; partially offset by
an impairment charge of $1,004 million in 2016, including related project costs, on EEP's
Sandpiper Project resulting from the withdrawal of the regulatory applications in September 2016
that were pending with the MNPUC;
•
an impairment charge of $373 million in 2016 related to the Northern Gateway Project due to our
conclusion that the project could not proceed as envisioned as a result of the Federal
Government's decision to dismiss the application for Certificate of Public Convenience and
Necessity;
an impairment charge of $184 million in 2016 related to our 75% joint venture interest in
Eddystone Rail attributable to market conditions which impacted volumes at the rail facility; and
the absence of a gain of $91 million recorded in 2015 related to the sale of non-core assets.
After taking into consideration the factors above, the remaining $716 million increase is primarily
explained by the following significant business factors:
higher throughput period over period resulting from strong oil sands production in western
Canada enabled by pipeline capacity expansion projects placed into service in 2015;
increased transportation revenues in 2016 resulting from an increase in the level of committed
take-or-pay volumes on Flanagan South;
the favorable effect of translating United States dollar earnings at a higher Average Exchange
Rate in 2016, inclusive of the impact of settlements under our foreign exchange hedging program;
partially offset by
61
depend on activity levels, which vary from year-to-year depending on market conditions and commodity
prices.
•
the absence of a gain of $850 million recorded in 2016 related to the sale of non-core South
Prairie Region assets.
Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign
exchange and commodity price contracts used to manage exposures from movements in foreign
exchange rates and commodity prices. The mark-to-market accounting creates volatility and impacts the
comparability of revenues in the short-term, but we believe over the long-term, the economic hedging
program supports reliable cash flows and dividend growth.
DIVIDENDS
We have paid common share dividends in every year since we became a publicly traded company in
1953. In November 2017, we announced a 10% increase in our quarterly dividend to $0.671 per common
share, or $2.684 annualized, effective with the dividend payable on March 1, 2018.
BUSINESS SEGMENTS
Effective December 31, 2017, we changed our segment-level profit measure to EBITDA from the previous
measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and
Processing segment to Gas Transmission and Midstream. The presentation of the prior years' tables has
been revised in order to align with the current presentation.
LIQUIDS PIPELINES
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization
2017
2016
2015
6,395
4,926
3,033
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $285 million of contributions
from new assets following the completion of the Merger Transaction.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
EBITDA increased by $1,312 million due to certain unusual, infrequent or other factors, primarily
explained by the following:
•
a non-cash, unrealized gain of $875 million in 2017 compared with $474 million in 2016 reflecting
net fair value gains and losses arising from changes in the mark-to-market value of derivative
financial instruments used to manage foreign exchange and commodity price risks;
•
the absence of an impairment charge of $1,004 million recorded in 2016, including related project
costs, on EEP's Sandpiper Project resulting from the withdrawal of the regulatory applications in
September 2016 that were pending with the MNPUC;
•
the absence of an impairment charge of $373 million recorded in 2016 related to the Northern
Gateway Project due to our conclusion that the project could not proceed as envisioned as a
result of the Federal Government's decision to dismiss the application for Certificate of Public
Convenience and Necessity;
•
the absence of an impairment charge of $184 million recorded in 2016 related to our 75% joint
venture interest in Eddystone Rail attributable to market conditions which impacted volumes at
•
a gain of $72 million on sale of pipe partially offset by project wind-down costs related to EEP’s
the rail facility;
Sandpiper Project; partially offset by
After taking into consideration the factors above, the remaining $128 million decrease is primarily
explained by the following significant business factors:
•
•
•
•
•
•
a lower contribution of $46 million from Mid-Continent assets primarily due to lower contracted
storage revenues and the sale of the Ozark Pipeline system in the first quarter of 2017;
a lower contribution of $76 million resulting from the sale of the South Prairie Region assets in
December 2016;
higher Lakehead System operating costs including costs to implement EEP’s signed settlement
agreement regarding the Lines 6A and 6B crude oil releases (the Consent Decree) approved by
the United States Department of Justice (DOJ) in May 2017;
the unfavorable effect of translating United States dollar EBITDA at a lower United States to
Canadian dollar average exchange rate (Average Exchange Rate) as compared with 2016,
inclusive of the impact of settlements under our foreign exchange hedging program; partially
offset by
contributions of from new assets placed into service including the Regional Oil Sands
Optimization Project and the Norlite Pipeline System and the acquisition of a minority interest in
the Bakken Pipeline System that went into service in June 2017; and
higher Canadian Mainline and Lakehead System throughput period over period resulting from
capacity optimization initiatives.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $1,177 million due to certain unusual, infrequent or other factors, primarily
explained by the following:
•
•
•
•
•
•
•
•
a non-cash, unrealized gain of $474 million in 2016 compared with an unrealized loss of $1,500
million in 2015 reflecting net fair value gains and losses on derivative financial instruments used
to manage foreign exchange and commodity price risks;
a gain of $850 million in 2016 related to the sale of non-core South Prairie Region assets;
the absence of an impairment charge of $86 million recorded in 2015 related to EEP's Berthold
rail facility due to contracts that were not renewed beyond 2016;
hydrostatic testing recoveries of $15 million in 2016 compared with charges of $72 million in
2015; partially offset by
an impairment charge of $1,004 million in 2016, including related project costs, on EEP's
Sandpiper Project resulting from the withdrawal of the regulatory applications in September 2016
that were pending with the MNPUC;
an impairment charge of $373 million in 2016 related to the Northern Gateway Project due to our
conclusion that the project could not proceed as envisioned as a result of the Federal
Government's decision to dismiss the application for Certificate of Public Convenience and
Necessity;
an impairment charge of $184 million in 2016 related to our 75% joint venture interest in
Eddystone Rail attributable to market conditions which impacted volumes at the rail facility; and
the absence of a gain of $91 million recorded in 2015 related to the sale of non-core assets.
After taking into consideration the factors above, the remaining $716 million increase is primarily
explained by the following significant business factors:
•
•
•
higher throughput period over period resulting from strong oil sands production in western
Canada enabled by pipeline capacity expansion projects placed into service in 2015;
increased transportation revenues in 2016 resulting from an increase in the level of committed
take-or-pay volumes on Flanagan South;
the favorable effect of translating United States dollar earnings at a higher Average Exchange
Rate in 2016, inclusive of the impact of settlements under our foreign exchange hedging program;
partially offset by
60
61
2015
2016
2017
•
the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which
led to a temporary shutdown of certain of our upstream pipelines and terminal facilities resulting
in a disruption of service.
GAS TRANSMISSION AND MIDSTREAM
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND
Supplemental information on Liquids Pipelines EBITDA for the years ended December 31, 2017, 2016
and 2015 is provided below.
December 31,
(United States dollars per barrel)
IJT Benchmark Toll1
$4.07
Lakehead System Local Toll2
$2.44
Canadian Mainline IJT Residual Benchmark Toll3
$1.63
1 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, 2015, this toll increased from US$4.02 to US$4.07. Effective July 1, 2016, this toll
decreased to US$4.05. Effective July 1, 2017, this toll increased to US$4.07.
$4.05
$2.58
$1.47
$4.07
$2.43
$1.64
2 The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois.
Effective April 1, 2015, the Lakehead System Local Toll decreased from US$2.49 to US$2.39 and effective July 1, 2015, this toll
increased to US$2.44. Effective April 1, 2016, this toll increased to US$2.61 and effective July 1, 2016, this toll decreased to US
$2.58. Effective April 1, 2017, this toll decreased to US$2.43.
3 The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna,
Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll.
Effective April 1, 2015, this toll increased from US$1.53 to US$1.63. Effective April 1, 2016, this toll decreased to US$1.46,
coinciding with the revised Lakehead System Local Toll. Effective July 1, 2016, this toll increased to US$1.47. Effective April 1,
2017, this toll increased to US$1.62, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2017, this toll
increased to US$1.64.
Throughput Volume
(thousands of barrels per day (bpd))
Canadian Mainline1
2017
2016
2015
Q1
Q2
Q3
Q4 Full Year
2,593
2,543
2,210
2,449
2,242
2,073
2,492
2,353
2,212
2,586
2,481
2,243
2,530
2,405
2,185
Lakehead System2
2,673
2017
2,574
2016
2015
2,315
1 Average throughput volume represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern
2,620
2,495
2,338
2,724
2,624
2,388
2,604
2,440
2,208
2,748
2,735
2,330
Canada deliveries originating from western Canada.
2 Average throughput volume represents mainline system deliveries to the United States midwest and eastern Canada.
Average Exchange Rate
(United States dollar to Canadian dollar)
2017
2016
2015
Q1
1.32
1.37
1.24
Q2
1.34
1.29
1.23
Q3
1.25
1.31
1.31
Q4 Full Year
1.27
1.33
1.34
1.30
1.32
1.28
62
63
AMORTIZATION
(millions of Canadian dollars)
amortization
Earnings/(loss) before interest, income taxes and depreciation and
2017
2016
2015
(1,269)
464
43
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $2,557 million of contributions
from new assets following the completion of the Merger Transaction. When compared to pre-merger
results from the prior year, operating results from the new assets include higher earnings primarily from
business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas
Eastern Transmission.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
EBITDA was negatively impacted by $4,287 million due to certain unusual, infrequent or other market
factors primarily explained by the following:
•
a loss of $4,391 million and related goodwill impairment of $102 million resulting from the
classification of certain United States Midstream assets as held for sale and the subsequent
measurement at the lower of their carrying value or fair value less costs to sell, refer to Item 8.
Financial Statements and Supplementary Data - Note 7. Acquisitions and Dispositions; partially
offset by
•
a non-cash, unrealized loss of $1 million in 2017 compared with $139 million in 2016 reflecting
net fair value gains and losses arising from the change in the mark-to-market of derivative
financial instruments used to manage foreign exchange and commodity price risk.
After taking into consideration the factors above, the remaining $3 million decrease is primarily explained
by the following significant business factors:
lower earnings of $127 million period over period due to lower commodity prices which impacted
production volume in areas served by some of our US Midstream assets; partially offset by
increased earnings of $19 million period over period from our Alliance joint venture due to
favorable seasonal firm revenues that resulted from wider basis differentials;
increased earnings of $16 million due to a full year of contributions from the Tupper Plants that
were acquired in April 2016;
increased fractionation margins of $45 million period over period driven by higher NGL prices and
increased demand from our Aux Sable joint venture; and
increased earnings of $41 million period over period from our Offshore assets driven by higher
volumes and higher earnings from certain joint venture pipelines.
•
•
•
•
•
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $370 million due to certain unusual, infrequent or other market factors primarily
explained by the following:
•
the absence of a goodwill impairment charge of $440 million recorded in 2015 related to our
United States natural gas and NGL businesses due to a prolonged decline in commodity prices
which reduced producers' expected drilling programs and negatively impacted volumes on our
natural gas and NGL systems; partially offset by
•
a non-cash, unrealized loss of $139 million in 2016 compared with $77 million in 2015 reflecting
net fair value gains and losses arising from the change in the mark-to-market of derivative
financial instruments used to manage foreign exchange and commodity price risk.
•
the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which
led to a temporary shutdown of certain of our upstream pipelines and terminal facilities resulting
in a disruption of service.
Supplemental information on Liquids Pipelines EBITDA for the years ended December 31, 2017, 2016
and 2015 is provided below.
December 31,
(United States dollars per barrel)
IJT Benchmark Toll1
Lakehead System Local Toll2
2017
$4.07
$2.43
$1.64
2016
2015
$4.05
$2.58
$1.47
$4.07
$2.44
$1.63
Canadian Mainline IJT Residual Benchmark Toll3
1 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, 2015, this toll increased from US$4.02 to US$4.07. Effective July 1, 2016, this toll
decreased to US$4.05. Effective July 1, 2017, this toll increased to US$4.07.
2 The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois.
Effective April 1, 2015, the Lakehead System Local Toll decreased from US$2.49 to US$2.39 and effective July 1, 2015, this toll
increased to US$2.44. Effective April 1, 2016, this toll increased to US$2.61 and effective July 1, 2016, this toll decreased to US
$2.58. Effective April 1, 2017, this toll decreased to US$2.43.
3 The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna,
Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll.
Effective April 1, 2015, this toll increased from US$1.53 to US$1.63. Effective April 1, 2016, this toll decreased to US$1.46,
coinciding with the revised Lakehead System Local Toll. Effective July 1, 2016, this toll increased to US$1.47. Effective April 1,
2017, this toll increased to US$1.62, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2017, this toll
increased to US$1.64.
Throughput Volume
(thousands of barrels per day (bpd))
Canadian Mainline1
Lakehead System2
Average Exchange Rate
(United States dollar to Canadian dollar)
2017
2016
2015
2017
2016
2015
2017
2016
2015
Q1
Q2
Q3
Q4 Full Year
2,593
2,543
2,210
2,748
2,735
2,330
2,449
2,242
2,073
2,604
2,440
2,208
2,492
2,353
2,212
2,620
2,495
2,338
2,586
2,481
2,243
2,724
2,624
2,388
2,530
2,405
2,185
2,673
2,574
2,315
Q1
1.32
1.37
1.24
Q2
1.34
1.29
1.23
Q3
1.25
1.31
1.31
Q4 Full Year
1.27
1.33
1.34
1.30
1.32
1.28
1 Average throughput volume represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern
Canada deliveries originating from western Canada.
2 Average throughput volume represents mainline system deliveries to the United States midwest and eastern Canada.
GAS TRANSMISSION AND MIDSTREAM
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND
AMORTIZATION
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and
amortization
2017
2016
2015
(1,269)
464
43
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $2,557 million of contributions
from new assets following the completion of the Merger Transaction. When compared to pre-merger
results from the prior year, operating results from the new assets include higher earnings primarily from
business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas
Eastern Transmission.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
EBITDA was negatively impacted by $4,287 million due to certain unusual, infrequent or other market
factors primarily explained by the following:
•
•
a loss of $4,391 million and related goodwill impairment of $102 million resulting from the
classification of certain United States Midstream assets as held for sale and the subsequent
measurement at the lower of their carrying value or fair value less costs to sell, refer to Item 8.
Financial Statements and Supplementary Data - Note 7. Acquisitions and Dispositions; partially
offset by
a non-cash, unrealized loss of $1 million in 2017 compared with $139 million in 2016 reflecting
net fair value gains and losses arising from the change in the mark-to-market of derivative
financial instruments used to manage foreign exchange and commodity price risk.
After taking into consideration the factors above, the remaining $3 million decrease is primarily explained
by the following significant business factors:
•
•
•
•
•
lower earnings of $127 million period over period due to lower commodity prices which impacted
production volume in areas served by some of our US Midstream assets; partially offset by
increased earnings of $19 million period over period from our Alliance joint venture due to
favorable seasonal firm revenues that resulted from wider basis differentials;
increased earnings of $16 million due to a full year of contributions from the Tupper Plants that
were acquired in April 2016;
increased fractionation margins of $45 million period over period driven by higher NGL prices and
increased demand from our Aux Sable joint venture; and
increased earnings of $41 million period over period from our Offshore assets driven by higher
volumes and higher earnings from certain joint venture pipelines.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $370 million due to certain unusual, infrequent or other market factors primarily
explained by the following:
•
•
the absence of a goodwill impairment charge of $440 million recorded in 2015 related to our
United States natural gas and NGL businesses due to a prolonged decline in commodity prices
which reduced producers' expected drilling programs and negatively impacted volumes on our
natural gas and NGL systems; partially offset by
a non-cash, unrealized loss of $139 million in 2016 compared with $77 million in 2015 reflecting
net fair value gains and losses arising from the change in the mark-to-market of derivative
financial instruments used to manage foreign exchange and commodity price risk.
62
63
After taking into consideration the factors above, the remaining $51 million increase is primarily explained
by the following significant business factors:
•
•
•
•
operational efficiencies achieved in 2016 on Alliance Pipeline due to lower operating costs;
contributions from the Heidelberg Pipeline which was placed into service in January 2016;
contributions from the Tupper Plants acquired in April 2016; partially offset by
unfavorable market conditions in 2016 resulting from lower volumes due to reduced drilling by
producers on our United States Midstream assets.
GAS DISTRIBUTION
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization
2017
2016
2015
1,390
831
763
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $545 million of contributions
from Union Gas following the completion of the Merger Transaction. When compared to pre-merger
results from prior years, Union Gas' operating results benefited mainly from higher transportation revenue
from the Dawn-Parkway expansion projects, increased storage optimization and increases in delivery
rates, partially offset by higher operating costs.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
EBITDA increased by $14 million due to certain unusual, infrequent and other business factors, primarily
explained by the following:
•
a non-cash, unrealized gain of $16 million in 2017 compared with an unrealized loss of $6 million
in 2016 arising from the change in the mark-to-market value of Noverco Inc.'s (Noverco)
derivative financial instruments;
• warmer than normal weather experienced during 2017 which negatively impacted EBITDA by $15
million compared with $18 million in 2016; partially offset by
the absence of other regulatory adjustments at Noverco of $17 million recorded in 2016.
•
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $11 million due to certain unusual, infrequent and other market factors, primarily
explained by the following:
• warmer than normal weather experienced during 2016 which negatively impacted EBITDA by $18
million compared with colder than normal weather during 2015 of $15 million; partially offset by
other regulatory adjustments at Noverco of $17 million recorded in 2016 compared with $6 million
in 2015.
•
After taking into consideration the factors above, the remaining $79 million increase is primarily explained
by the following significant business factor:
•
higher distribution charges arising from growth in rate base, including customer growth in excess
of expectations embedded in rates.
GREEN POWER AND TRANSMISSION
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
(millions of Canadian dollars)
amortization
Earnings before interest, income taxes and depreciation and
2017
2016
2015
372
344
363
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA increased by $4 million due to certain unusual, infrequent and other factors, primarily explained
by the following:
the absence of an investment impairment loss of $13 million recorded in 2016; partially offset by
a $9 million loss that resulted from the sale of an investment.
After taking into consideration the factors above, the remaining $24 million increase is primarily explained
by the following significant business factors:
stronger wind resources of $12 million at Canadian and United States wind farms period over
contributions of $9 million from new United States wind projects placed into service in 2016 and
•
•
•
•
period; and
2017.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $13 million due to an unusual and infrequent investment impairment loss in 2016.
After taking into consideration the factor above, the remaining $6 million decrease is primarily explained
by the following significant business factors:
•
disruptions at certain eastern Canadian wind farms in the first quarter and fourth quarter of 2016
due to weather conditions which caused a higher degree of icing on wind turbine blades;
• weaker wind resources experienced at certain facilities in Canada period over period; partially
offset by
•
stronger wind resources at United States wind farms during the second half of 2016.
64
65
After taking into consideration the factors above, the remaining $51 million increase is primarily explained
by the following significant business factors:
•
•
•
•
operational efficiencies achieved in 2016 on Alliance Pipeline due to lower operating costs;
contributions from the Heidelberg Pipeline which was placed into service in January 2016;
contributions from the Tupper Plants acquired in April 2016; partially offset by
unfavorable market conditions in 2016 resulting from lower volumes due to reduced drilling by
producers on our United States Midstream assets.
GAS DISTRIBUTION
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
(millions of Canadian dollars)
amortization
Earnings before interest, income taxes and depreciation and
2017
2016
2015
1,390
831
763
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $545 million of contributions
from Union Gas following the completion of the Merger Transaction. When compared to pre-merger
results from prior years, Union Gas' operating results benefited mainly from higher transportation revenue
from the Dawn-Parkway expansion projects, increased storage optimization and increases in delivery
rates, partially offset by higher operating costs.
After taking into consideration the contribution of additional earnings from the Merger Transaction,
EBITDA increased by $14 million due to certain unusual, infrequent and other business factors, primarily
explained by the following:
•
a non-cash, unrealized gain of $16 million in 2017 compared with an unrealized loss of $6 million
in 2016 arising from the change in the mark-to-market value of Noverco Inc.'s (Noverco)
derivative financial instruments;
• warmer than normal weather experienced during 2017 which negatively impacted EBITDA by $15
million compared with $18 million in 2016; partially offset by
•
the absence of other regulatory adjustments at Noverco of $17 million recorded in 2016.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $11 million due to certain unusual, infrequent and other market factors, primarily
explained by the following:
• warmer than normal weather experienced during 2016 which negatively impacted EBITDA by $18
million compared with colder than normal weather during 2015 of $15 million; partially offset by
•
other regulatory adjustments at Noverco of $17 million recorded in 2016 compared with $6 million
in 2015.
After taking into consideration the factors above, the remaining $79 million increase is primarily explained
by the following significant business factor:
of expectations embedded in rates.
•
higher distribution charges arising from growth in rate base, including customer growth in excess
GREEN POWER AND TRANSMISSION
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization
2017
2016
2015
372
344
363
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA increased by $4 million due to certain unusual, infrequent and other factors, primarily explained
by the following:
•
•
the absence of an investment impairment loss of $13 million recorded in 2016; partially offset by
a $9 million loss that resulted from the sale of an investment.
After taking into consideration the factors above, the remaining $24 million increase is primarily explained
by the following significant business factors:
•
•
stronger wind resources of $12 million at Canadian and United States wind farms period over
period; and
contributions of $9 million from new United States wind projects placed into service in 2016 and
2017.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $13 million due to an unusual and infrequent investment impairment loss in 2016.
After taking into consideration the factor above, the remaining $6 million decrease is primarily explained
by the following significant business factors:
•
disruptions at certain eastern Canadian wind farms in the first quarter and fourth quarter of 2016
due to weather conditions which caused a higher degree of icing on wind turbine blades;
• weaker wind resources experienced at certain facilities in Canada period over period; partially
offset by
stronger wind resources at United States wind farms during the second half of 2016.
•
64
65
ENERGY SERVICES
ELIMINATIONS AND OTHER
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND
AMORTIZATION
2017
2016
2015
(millions of Canadian dollars)
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and
amortization
(263)
(183)
324
EBITDA from Energy Services is dependent on market conditions and results achieved in one period may
not be indicative of results to be achieved in future periods.
Year ended December 31, 2017 compared with year ended December 31, 2016
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA increased by $2 million due to certain unusual, infrequent or other factors, primarily explained by
the following:
•
a non-cash, unrealized loss of $200 million in 2017 compared with $205 million in 2016 reflecting
the revaluation of financial derivatives used to manage the profitability of transportation and
storage transactions and exposure to movements in commodity prices.
After taking into consideration the factors above, the remaining $82 million decrease is primarily
explained by the following significant business factor:
• weaker performance from Energy Services’ Canadian and United States operations due to the
compression of certain crude oil and NGL location and quality differentials in 2017 which limited
opportunities to generate profitable margins.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $477 million due to certain unusual, infrequent or other factors, primarily explained
by the following:
•
a non-cash, unrealized loss of $205 million in 2016 compared with an unrealized gain of $264
million in 2015 reflecting the revaluation of financial derivatives used to manage the profitability of
transportation and storage transactions and exposure to movements in commodity prices.
After taking into consideration the factor above, the remaining $30 million decrease is primarily explained
by the following significant business factor:
• weaker performance from Energy Services’ Canadian and United States operations due to the
compression of certain crude oil and NGL location and quality differentials in 2016 which limited
opportunities to generate profitable margins.
LOSS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
Loss before interest, income taxes and depreciation and amortization
(101)
(867)
2016
2015
2017
(337)
Eliminations and Other includes operating and administrative costs and the impact of foreign exchange
hedge settlements which are not allocated to business segments. Eliminations and Other also includes
new business development activities, general corporate investments and a portion of the synergies
achieved thus far on integration of corporate functions in relation to the Merger Transaction.
•
•
•
•
•
•
•
EBITDA decreased by $315 million due to certain unusual, infrequent and other factors, primarily
explained by the following:
project development and transaction costs of $197 million incurred in 2017 compared with $81
million in 2016 related to the Merger Transaction;
employee severance and restructuring costs of $292 million in 2017 compared with $92 million in
2016 related to a corporate reorganization initiative and the Merger Transaction; partially offset by
a non-cash, unrealized intercompany foreign exchange loss of $29 million in 2017 compared with
$43 million in 2016 under our foreign exchange risk management program.
After taking into consideration the factors above, the remaining $79 million increase is primarily explained
by the following significant business factor:
•
a realized loss of $173 million in 2017 compared with $281 million in 2016 related to settlements
under our foreign exchange risk management program.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $854 million due to certain unusual, infrequent and other factors, primarily
explained by the following:
a non-cash, unrealized gain of $417 million in 2016 compared with an unrealized loss of $694
million in 2015 resulting from our foreign exchange hedging program; partially offset by
a non-cash, unrealized intercompany foreign exchange loss of $43 million in 2016 compared with
project development and transaction costs of $81 million incurred in 2016 in relation to the Merger
employee severances costs of $92 million in 2016 compared with $47 million in 2015 related to a
a gain of $131 million in 2015;
Transaction; and
corporate reorganization initiative.
After taking into consideration the factors above, the remaining $88 million decrease is primarily
explained by the following significant business factor:
•
a realized loss of $281 million in 2016 compared with $203 million in 2015 related to settlements
under our foreign exchange risk management program.
66
67
ENERGY SERVICES
AMORTIZATION
(millions of Canadian dollars)
amortization
Earnings/(loss) before interest, income taxes and depreciation and
2017
2016
2015
(263)
(183)
324
EBITDA from Energy Services is dependent on market conditions and results achieved in one period may
not be indicative of results to be achieved in future periods.
EBITDA increased by $2 million due to certain unusual, infrequent or other factors, primarily explained by
the following:
•
a non-cash, unrealized loss of $200 million in 2017 compared with $205 million in 2016 reflecting
the revaluation of financial derivatives used to manage the profitability of transportation and
storage transactions and exposure to movements in commodity prices.
After taking into consideration the factors above, the remaining $82 million decrease is primarily
explained by the following significant business factor:
• weaker performance from Energy Services’ Canadian and United States operations due to the
compression of certain crude oil and NGL location and quality differentials in 2017 which limited
opportunities to generate profitable margins.
Year ended December 31, 2016 compared with year ended December 31, 2015
by the following:
•
a non-cash, unrealized loss of $205 million in 2016 compared with an unrealized gain of $264
million in 2015 reflecting the revaluation of financial derivatives used to manage the profitability of
transportation and storage transactions and exposure to movements in commodity prices.
After taking into consideration the factor above, the remaining $30 million decrease is primarily explained
by the following significant business factor:
• weaker performance from Energy Services’ Canadian and United States operations due to the
compression of certain crude oil and NGL location and quality differentials in 2016 which limited
opportunities to generate profitable margins.
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND
LOSS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
ELIMINATIONS AND OTHER
(millions of Canadian dollars)
Loss before interest, income taxes and depreciation and amortization
2017
(337)
2016
2015
(101)
(867)
Eliminations and Other includes operating and administrative costs and the impact of foreign exchange
hedge settlements which are not allocated to business segments. Eliminations and Other also includes
new business development activities, general corporate investments and a portion of the synergies
achieved thus far on integration of corporate functions in relation to the Merger Transaction.
Year ended December 31, 2017 compared with year ended December 31, 2016
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA decreased by $315 million due to certain unusual, infrequent and other factors, primarily
explained by the following:
•
•
•
project development and transaction costs of $197 million incurred in 2017 compared with $81
million in 2016 related to the Merger Transaction;
employee severance and restructuring costs of $292 million in 2017 compared with $92 million in
2016 related to a corporate reorganization initiative and the Merger Transaction; partially offset by
a non-cash, unrealized intercompany foreign exchange loss of $29 million in 2017 compared with
$43 million in 2016 under our foreign exchange risk management program.
After taking into consideration the factors above, the remaining $79 million increase is primarily explained
by the following significant business factor:
•
a realized loss of $173 million in 2017 compared with $281 million in 2016 related to settlements
under our foreign exchange risk management program.
EBITDA decreased by $477 million due to certain unusual, infrequent or other factors, primarily explained
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $854 million due to certain unusual, infrequent and other factors, primarily
explained by the following:
•
•
•
•
a non-cash, unrealized gain of $417 million in 2016 compared with an unrealized loss of $694
million in 2015 resulting from our foreign exchange hedging program; partially offset by
a non-cash, unrealized intercompany foreign exchange loss of $43 million in 2016 compared with
a gain of $131 million in 2015;
project development and transaction costs of $81 million incurred in 2016 in relation to the Merger
Transaction; and
employee severances costs of $92 million in 2016 compared with $47 million in 2015 related to a
corporate reorganization initiative.
After taking into consideration the factors above, the remaining $88 million decrease is primarily
explained by the following significant business factor:
•
a realized loss of $281 million in 2016 compared with $203 million in 2015 related to settlements
under our foreign exchange risk management program.
66
67
GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
A key element of our corporate strategy is the successful execution of our growth capital program. In
2017, we successfully placed into service approximately $12 billion of growth projects across several
business units and we expect to place a further $22 billion of commercially secured projects into service
through 2020.
The following table summarizes the status of our commercially secured projects, organized by business
segment:
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1 Norlite Pipeline System (the
Fund Group)
2 Bakken Pipeline System
(EEP)3
3 Regional Oil Sands
Optimization Project (the Fund
Group)
4
Lakehead System Mainline
Expansion - Line 61 (EEP)4
5 Canadian Line 3 Replacement
Program (the Fund Group)
6 U.S. Line 3 Replacement
Program (EEP)4
7 Other - Canada
Enbridge's
Ownership
Interest
Estimated
Capital Cost1
Expenditures
to Date2
Expected
In-Service
Date
Status
70%
$1.3 billion
$1.1 billion
Complete
In service
27.6% US$1.5 billion
US$1.5 billion
Complete
In service
100%
$2.6 billion
$2.3 billion
Complete
In service
100% US$0.4 billion
US$0.4 billion
100%
$5.3 billion
$2.3 billion
100% US$2.9 billion
US$0.7 billion
100%
$0.2 billion
$0.2 billion
Substantially
complete
Under
construction
Under
construction
Various
stages
2H - 2019
2H - 2019
2H - 2019
2018
GAS TRANSMISSION & MIDSTREAM
8 Sabal Trail (SEP)5
50% US$1.6 billion
US$1.5 billion
Complete
In service
9 Access South, Adair
Southwest and Lebanon
Extension (SEP)5
10 Atlantic Bridge (SEP)5
11 NEXUS (SEP)5
12 Reliability and Maintainability
Project5
13 Valley Crossing Pipeline5
100% US$0.5 billion
US$0.3 billion
Complete
In service
100% US$0.5 billion
US$0.3 billion
Under Q4 - 2018
construction
50% US$1.3 billion
US$0.6 billion
Under Q3 - 2018
construction
100%
$0.5 billion
$0.4 billion
Under Q3 - 2018
construction
100% US$1.5 billion
US$1.1 billion
Under Q4 - 2018
14 Spruce Ridge Program5
100%
$0.5 billion
$0.1 billion
15 T-South Expansion Program5
100%
$1.0 billion
No significant
16 Other - United States5
100% US$1.9 billion
expenditures to date
US$1.0 billion
17 Other - Canada5
100%
$0.9 billion
$0.7 billion
construction
Pre-
construction
Pre-
construction
Various
stages
Various
stages
2019
2020
2017-2019
2017-2018
GAS DISTRIBUTION
18
2017 Dawn-Parkway
Expansion5
100%
$0.6 billion
$0.6 billion
Complete
In service
19 Panhandle Reinforcement
100%
$0.3 billion
$0.2 billion
Complete
In service
Project5
68
69
GREEN POWER & TRANSMISSION
20 Chapman Ranch Wind Project
100% US$0.4 billion
US$0.3 billion
Complete
In service
21 Rampion Offshore Wind
24.9%
$0.8 billion
$0.6 billion
Under Q2 - 2018
Project
22 Hohe See Offshore Wind
Project and Expansion
(£0.37 billion)
(£0.3 billion)
construction
50%
$2.1 billion
$0.5 billion
Pre-
2H - 2019
(€1.34 billion)
(€0.4 billion)
construction
1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate,
the amounts reflect our share of joint venture projects.
2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2017.
3 On February 15, 2017, EEP acquired an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $2.0
billion (US$1.5 billion). On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns
75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System.
4 The Lakehead System Mainline Expansion project is funded 75% by Enbridge and 25% by EEP, and the project will be operated
by EEP on a cost-of-service basis. The U.S. L3R Program is being funded 99% by Enbridge and 1% by EEP.
5 Project acquired as part of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.
Risks related to the development and completion of growth projects are described under Part I. Item 1A.
Risk Factors.
LIQUIDS PIPELINES
The following commercially secured growth projects were placed into service in 2017:
• Norlite Pipeline System (the Fund Group) - a diluent pipeline originating from our Stonefell
Terminal and terminating at our Fort McMurray South facility, with a transfer line to Suncor's East
Tank Farm. The project provides an initial capacity of approximately 218,000 bpd, with the potential to
be further expanded to approximately 465,000 bpd with the addition of pump stations. The project
was placed into commercial service on May 1, 2017.
• Bakken Pipeline System (EEP) - a pipeline system that transports crude oil from the Bakken
formation in North Dakota to markets in eastern PADD II, and the United States Gulf Coast. The
system's initial capacity is approximately 470,000 bpd of crude oil and has the potential to be
expanded to 570,000 bpd. The system was placed into service on June 1, 2017.
• Regional Oil Sands Optimization Project (the Fund Group) - the Athabasca Pipeline Twin portion
of the project, which includes twinning of the southern section of the crude oil Athabasca Pipeline
from Kirby Lake, Alberta to the crude oil hub at Hardisty, Alberta provides an initial capacity of
approximately 450,000 bpd, with the potential to be further expanded to approximately 800,000 bpd.
This portion of the project was placed into service on January 1, 2017. The Wood Buffalo Extension
portion of the project includes a crude oil pipeline expansion between Cheecham, Alberta and Kirby
Lake, Alberta that provides an initial capacity of approximately 635,000 bpd, with the potential to be
further expanded to approximately 800,000 bpd. This portion of the project was placed into service on
December 1, 2017.
•
JACOS Hangingstone Project (the Fund Group) - a crude oil pipeline connecting the Japan
Canada Oil Sands Limited (JACOS) Hangingstone project site to our existing Cheecham Terminal
that provides an initial capacity of approximately 40,000 bpd. The project was placed into service on
August 29, 2017.
2019:
The following commercially secured growth projects are expected to be placed into service in 2018 and
• Lakehead System Mainline Expansion (EEP) - the remaining scope of the project includes the
Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois that will increase
capacity from 950,000 bpd to 1,200,000 bpd, which was substantially completed in June of 2017. We
currently anticipate an in-service date in the second half of 2019 for this phase to more closely align
GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
A key element of our corporate strategy is the successful execution of our growth capital program. In
2017, we successfully placed into service approximately $12 billion of growth projects across several
business units and we expect to place a further $22 billion of commercially secured projects into service
The following table summarizes the status of our commercially secured projects, organized by business
through 2020.
segment:
Enbridge's
Ownership
Interest
Estimated
Capital Cost1
Expenditures
to Date2
Expected
In-Service
Date
Status
1 Norlite Pipeline System (the
70%
$1.3 billion
$1.1 billion
Complete
In service
2 Bakken Pipeline System
27.6% US$1.5 billion
US$1.5 billion
Complete
In service
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
Fund Group)
(EEP)3
Group)
3 Regional Oil Sands
Optimization Project (the Fund
4
Lakehead System Mainline
Expansion - Line 61 (EEP)4
Program (the Fund Group)
6 U.S. Line 3 Replacement
Program (EEP)4
9 Access South, Adair
Southwest and Lebanon
Extension (SEP)5
10 Atlantic Bridge (SEP)5
11 NEXUS (SEP)5
Project5
13 Valley Crossing Pipeline5
5 Canadian Line 3 Replacement
100%
$5.3 billion
$2.3 billion
Under
2H - 2019
100% US$0.4 billion
US$0.4 billion
Substantially
2H - 2019
100% US$2.9 billion
US$0.7 billion
Under
2H - 2019
7 Other - Canada
100%
$0.2 billion
$0.2 billion
2018
GAS TRANSMISSION & MIDSTREAM
8 Sabal Trail (SEP)5
50% US$1.6 billion
US$1.5 billion
Complete
In service
100% US$0.5 billion
US$0.3 billion
Complete
In service
100% US$0.5 billion
US$0.3 billion
Under Q4 - 2018
50% US$1.3 billion
US$0.6 billion
Under Q3 - 2018
12 Reliability and Maintainability
100%
$0.5 billion
$0.4 billion
Under Q3 - 2018
100% US$1.5 billion
US$1.1 billion
Under Q4 - 2018
14 Spruce Ridge Program5
100%
$0.5 billion
$0.1 billion
15 T-South Expansion Program5
100%
$1.0 billion
No significant
16 Other - United States5
100% US$1.9 billion
US$1.0 billion
expenditures to date
construction
17 Other - Canada5
100%
$0.9 billion
$0.7 billion
2019
2020
Various
stages
Various
stages
2017-2019
2017-2018
GAS DISTRIBUTION
18
2017 Dawn-Parkway
Expansion5
Project5
19 Panhandle Reinforcement
100%
$0.3 billion
$0.2 billion
Complete
In service
100%
$0.6 billion
$0.6 billion
Complete
In service
complete
construction
construction
Various
stages
construction
construction
construction
construction
construction
Pre-
Pre-
GREEN POWER & TRANSMISSION
20 Chapman Ranch Wind Project
100% US$0.4 billion
US$0.3 billion
Complete
In service
21 Rampion Offshore Wind
Project
22 Hohe See Offshore Wind
Project and Expansion
24.9%
50%
$0.8 billion
(£0.37 billion)
$2.1 billion
(€1.34 billion)
$0.6 billion
(£0.3 billion)
$0.5 billion
(€0.4 billion)
Under Q2 - 2018
construction
Pre-
construction
2H - 2019
1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate,
the amounts reflect our share of joint venture projects.
2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2017.
3 On February 15, 2017, EEP acquired an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $2.0
billion (US$1.5 billion). On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns
75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System.
4 The Lakehead System Mainline Expansion project is funded 75% by Enbridge and 25% by EEP, and the project will be operated
by EEP on a cost-of-service basis. The U.S. L3R Program is being funded 99% by Enbridge and 1% by EEP.
5 Project acquired as part of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.
Risks related to the development and completion of growth projects are described under Part I. Item 1A.
Risk Factors.
100%
$2.6 billion
$2.3 billion
Complete
In service
LIQUIDS PIPELINES
The following commercially secured growth projects were placed into service in 2017:
• Norlite Pipeline System (the Fund Group) - a diluent pipeline originating from our Stonefell
Terminal and terminating at our Fort McMurray South facility, with a transfer line to Suncor's East
Tank Farm. The project provides an initial capacity of approximately 218,000 bpd, with the potential to
be further expanded to approximately 465,000 bpd with the addition of pump stations. The project
was placed into commercial service on May 1, 2017.
• Bakken Pipeline System (EEP) - a pipeline system that transports crude oil from the Bakken
formation in North Dakota to markets in eastern PADD II, and the United States Gulf Coast. The
system's initial capacity is approximately 470,000 bpd of crude oil and has the potential to be
expanded to 570,000 bpd. The system was placed into service on June 1, 2017.
• Regional Oil Sands Optimization Project (the Fund Group) - the Athabasca Pipeline Twin portion
of the project, which includes twinning of the southern section of the crude oil Athabasca Pipeline
from Kirby Lake, Alberta to the crude oil hub at Hardisty, Alberta provides an initial capacity of
approximately 450,000 bpd, with the potential to be further expanded to approximately 800,000 bpd.
This portion of the project was placed into service on January 1, 2017. The Wood Buffalo Extension
portion of the project includes a crude oil pipeline expansion between Cheecham, Alberta and Kirby
Lake, Alberta that provides an initial capacity of approximately 635,000 bpd, with the potential to be
further expanded to approximately 800,000 bpd. This portion of the project was placed into service on
December 1, 2017.
•
JACOS Hangingstone Project (the Fund Group) - a crude oil pipeline connecting the Japan
Canada Oil Sands Limited (JACOS) Hangingstone project site to our existing Cheecham Terminal
that provides an initial capacity of approximately 40,000 bpd. The project was placed into service on
August 29, 2017.
The following commercially secured growth projects are expected to be placed into service in 2018 and
2019:
• Lakehead System Mainline Expansion (EEP) - the remaining scope of the project includes the
Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois that will increase
capacity from 950,000 bpd to 1,200,000 bpd, which was substantially completed in June of 2017. We
currently anticipate an in-service date in the second half of 2019 for this phase to more closely align
68
69
with the anticipated in-service date for the Line 3 Replacement Program (U.S. L3R Program). For
additional updates on the project, refer to Growth Projects - Regulatory Matters.
• Canadian Line 3 Replacement Program (the Fund Group) - replacement of the existing Line 3
crude oil pipeline between Hardisty, Alberta and Gretna, Manitoba. The L3R Program will not provide
an increase in the overall capacity of the mainline system, but will restore approximately 370,000 bpd
and supports the safety and operational reliability of the overall system, enhances flexibility and will
allow us to optimize throughput from western Canada into Superior, Wisconsin. The L3R Program is
expected to achieve the original capacity of approximately 760,000 bpd. Construction commenced in
early August 2017. For additional updates on the project, refer to Growth Projects - Regulatory
Matters.
• United States Line 3 Replacement Program (EEP) - replacement of the existing Line 3 crude oil
pipeline between Neche, North Dakota and Superior, Wisconsin. The U.S. L3R Program, along with
the Canadian L3R Program discussed above, will support the safety and operational reliability of the
mainline system, enhance system flexibility, and allow the Company and EEP to optimize throughput
on the mainline. The L3R Program is expected to achieve the original capacity of approximately
760,000 bpd. Construction commenced on the Wisconsin portion of the U.S. L3R Program in late
June 2017 and will be substantially complete in February 2018. For additional updates on the project,
refer to Growth Projects - Regulatory Matters.
70
71
with the anticipated in-service date for the Line 3 Replacement Program (U.S. L3R Program). For
additional updates on the project, refer to Growth Projects - Regulatory Matters.
Norman
Norman
Wells
Wells
• Canadian Line 3 Replacement Program (the Fund Group) - replacement of the existing Line 3
crude oil pipeline between Hardisty, Alberta and Gretna, Manitoba. The L3R Program will not provide
an increase in the overall capacity of the mainline system, but will restore approximately 370,000 bpd
and supports the safety and operational reliability of the overall system, enhances flexibility and will
allow us to optimize throughput from western Canada into Superior, Wisconsin. The L3R Program is
expected to achieve the original capacity of approximately 760,000 bpd. Construction commenced in
early August 2017. For additional updates on the project, refer to Growth Projects - Regulatory
Matters.
• United States Line 3 Replacement Program (EEP) - replacement of the existing Line 3 crude oil
pipeline between Neche, North Dakota and Superior, Wisconsin. The U.S. L3R Program, along with
the Canadian L3R Program discussed above, will support the safety and operational reliability of the
mainline system, enhance system flexibility, and allow the Company and EEP to optimize throughput
on the mainline. The L3R Program is expected to achieve the original capacity of approximately
760,000 bpd. Construction commenced on the Wisconsin portion of the U.S. L3R Program in late
June 2017 and will be substantially complete in February 2018. For additional updates on the project,
refer to Growth Projects - Regulatory Matters.
CANADA
Zama
Zama
Fort McMurray
Fort McMurray
Cheecham
Cheecham
Edmonton
Edmonton
Hardisty
Hardisty
5
Fort McMurray
Fort McMurray
8
9
Cheecham
Cheecham
5
3
11
1
6
10
3
Edmonton
Edmonton
4
7
Hardisty
Hardisty
Clearbrook
Clearbrook
6
Superior
Superior
Montreal
Montreal
4
Sarnia
Sarnia
Toronto
Toronto
Buffalo
Buffalo
Chicago
Chicago
Toledo
Toledo
Patoka
Patoka
Wood
Wood
River
River
Minot
2
Cushing
Cushing
UNITED S TATE S
UNITED S TATES
OF AM ERICA
OF AM ERICA
M
E
X
I
C
0
Houston
Houston
New Orleans
New Orleans
Assets in Operation
Projects Placed into Service in 2017
Growth Projects
70
71
GAS TRANSMISSION AND MIDSTREAM
The following commercially secured growth projects were placed into service in 2017:
• Sabal Trail (SEP) - a natural gas pipeline connecting Alexander City, Alabama to the Central Florida
Hub in Kissimmee, Florida that provides capacity of approximately 1.1 billion cubic feet per day
(bcf/d) of new capacity to access onshore shale gas supplies once approved future expansions are
completed. Facilities include a new 749-kilometer (465-mile) pipeline, laterals and various
compressor stations. The project was placed into service on July 3, 2017.
• Access South, Adair Southwest and Lebanon Extension (SEP) - natural gas pipeline extensions
connecting the Appalachian region of the United States to markets in the Midwest and Southeast
regions of the United States. The combined projects provide an initial capacity of 622 million cubic
feet per day (mmcf/d) of gas to customers in Ohio, Kentucky and Mississippi. The Lebanon extension
was placed into service early, on August 1, 2017 and the majority of the Access and Adair portions of
the project were placed in service in November 2017 with the final 20 mmcf/d expected to be placed
in service in the first quarter of 2018.
The following commercially secured growth projects are expected to be placed into service in 2018 to
2020:
• Atlantic Bridge (SEP) - expansion of SEP’s Algonquin Gas Transmission systems to transport 133
mmcf/d of natural gas to the New England Region. The expansion primarily consists of the
replacement of a natural gas pipeline, meter station additions, compression additions in Connecticut,
and a new compressor station in Massachusetts. The Connecticut portion of the project was placed
into service in the fourth quarter of 2017. The remainder of the project is expected to be in-service
during the fourth quarter of 2018.
• NEXUS (SEP) - a natural gas pipeline system connecting SEP’s Texas Eastern pipeline system in
Ohio to the Union Gas Dawn hub in Ontario, via Vector Pipeline L.P., that will provide capacity of up
to approximately 1.5 bcf/d. The project received a Notice to Proceed from the Federal Energy
Regulatory Commission (FERC) in August 2017 and construction activities have commenced.
• Reliability and Maintainability Project - a natural gas pipeline project designed to enhance the
performance of the southern segment of the British Columbia Pipeline system to accommodate the
increased base load on the system. The project involves adding new compressor units at three
compressor stations along the pipeline system as well as upgrading existing pipeline crossovers and
adding new crossovers at key locations. During 2017, six crossovers were placed into service.
• Valley Crossing Pipeline - a natural gas pipeline connecting the Agua Dulce hub in Texas to an
offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The
project will help Mexico meet its growing gas fired electric generation needs by providing capacity of
up to approximately 2.6 bcf/d.
• Spruce Ridge Program - natural gas pipeline expansion of Westcoast Energy Inc.’s British Columbia
Pipeline in northern British Columbia, which consists of the Aitken Creek Looping project and the
Spruce Ridge Expansion project. The combined projects will provide additional capacity of up to 402
mmcf/d.
• T-South Expansion Program - natural gas pipeline expansion of Westcoast Energy Inc.’s T-South
system that will provide additional capacity of approximately 190 mmcf/d into the Huntington/Sumas
market at the United States/Canada border.
72
73
GAS TRANSMISSION AND MIDSTREAM
The following commercially secured growth projects were placed into service in 2017:
• Sabal Trail (SEP) - a natural gas pipeline connecting Alexander City, Alabama to the Central Florida
Hub in Kissimmee, Florida that provides capacity of approximately 1.1 billion cubic feet per day
(bcf/d) of new capacity to access onshore shale gas supplies once approved future expansions are
completed. Facilities include a new 749-kilometer (465-mile) pipeline, laterals and various
compressor stations. The project was placed into service on July 3, 2017.
• Access South, Adair Southwest and Lebanon Extension (SEP) - natural gas pipeline extensions
connecting the Appalachian region of the United States to markets in the Midwest and Southeast
regions of the United States. The combined projects provide an initial capacity of 622 million cubic
feet per day (mmcf/d) of gas to customers in Ohio, Kentucky and Mississippi. The Lebanon extension
was placed into service early, on August 1, 2017 and the majority of the Access and Adair portions of
the project were placed in service in November 2017 with the final 20 mmcf/d expected to be placed
in service in the first quarter of 2018.
The following commercially secured growth projects are expected to be placed into service in 2018 to
2020:
• Atlantic Bridge (SEP) - expansion of SEP’s Algonquin Gas Transmission systems to transport 133
mmcf/d of natural gas to the New England Region. The expansion primarily consists of the
replacement of a natural gas pipeline, meter station additions, compression additions in Connecticut,
and a new compressor station in Massachusetts. The Connecticut portion of the project was placed
into service in the fourth quarter of 2017. The remainder of the project is expected to be in-service
during the fourth quarter of 2018.
• NEXUS (SEP) - a natural gas pipeline system connecting SEP’s Texas Eastern pipeline system in
Ohio to the Union Gas Dawn hub in Ontario, via Vector Pipeline L.P., that will provide capacity of up
to approximately 1.5 bcf/d. The project received a Notice to Proceed from the Federal Energy
Regulatory Commission (FERC) in August 2017 and construction activities have commenced.
• Reliability and Maintainability Project - a natural gas pipeline project designed to enhance the
performance of the southern segment of the British Columbia Pipeline system to accommodate the
increased base load on the system. The project involves adding new compressor units at three
compressor stations along the pipeline system as well as upgrading existing pipeline crossovers and
adding new crossovers at key locations. During 2017, six crossovers were placed into service.
• Valley Crossing Pipeline - a natural gas pipeline connecting the Agua Dulce hub in Texas to an
offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The
project will help Mexico meet its growing gas fired electric generation needs by providing capacity of
up to approximately 2.6 bcf/d.
• Spruce Ridge Program - natural gas pipeline expansion of Westcoast Energy Inc.’s British Columbia
Pipeline in northern British Columbia, which consists of the Aitken Creek Looping project and the
Spruce Ridge Expansion project. The combined projects will provide additional capacity of up to 402
mmcf/d.
• T-South Expansion Program - natural gas pipeline expansion of Westcoast Energy Inc.’s T-South
system that will provide additional capacity of approximately 190 mmcf/d into the Huntington/Sumas
market at the United States/Canada border.
14
12
15
Vancouver
Vancouver
Calgary
Calgary
CANADA
Superior
Superior
Montreal
Montreal
Halifax
Halifax
10
UNITED STATES
UNITED STATES
OF AMERICA
OF AMERICA
Chicago
Chicago
Cushing
Cushing
M
E
X
I
C
0
Houston
Houston
13
New Orleans
New Orleans
Toronto
Toronto
Sarnia
Sarnia
Boston
Boston
New York
New York
9
11
8
Assets in Operation
Projects Placed into Service in 2017
Growth Projects
Gas Plants in Operation
72
73
GAS DISTRIBUTION
In addition to normal course investment to support customer additions, the following commercially
secured growth projects were placed into service in 2017:
•
2017 Dawn-Parkway Expansion - the expansion of the existing Dawn-Parkway pipeline system,
which provides transportation service from Dawn to the Greater Toronto Area, through the addition of
new compressors at each of the Dawn, Lobo and Bright compressor stations in Ontario. The project
provides additional capacity of approximately 419 mmcf/d and was placed into service in October
2017.
• Panhandle Reinforcement Project - the expansion of the existing Panhandle pipeline from Dawn to
the Dover transmission station in Chatham-Kent, Ontario. The project serves firm demand growth in
southwestern Ontario and was placed into service in November 2017.
2019:
Montreal
Montreal
Toronto
Toronto
Sarnia
Sarnia
18
19
GREEN POWER AND TRANSMISSION
The following commercially secured growth project was placed into service in 2017:
• Chapman Ranch Wind Project - a wind project that consists of 81 Acciona Windpower North
America, LLC (Acciona) turbines located in Nueces County, Texas which generate approximately 249-
MW of power and were placed into service on October 25, 2017. Acciona provides turbine operations
and maintenance services under a five-year fixed-price contract with an option to extend. The project
is backed by a 12-year power offtake agreement.
The following commercially secured growth projects are expected to be placed into service in 2018 and
• Rampion Offshore Wind Project - a wind project located off the Sussex coast in the United
Kingdom, consisting of 116 turbines, which will generate approximately 400-MW when complete. We
hold an effective 24.9% interest, United Kingdom’s Green Investment Bank plc holds a 25% interest
and E.ON SE holds the remaining 50.1% interest in the project, which was developed and is being
constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE. The Rampion
Offshore Wind Project is backed by revenues from the United Kingdom’s fixed-price Renewable
Obligation certificates program and a 15-year power purchase agreement. The project generated first
power in November 2017 and is currently in the commissioning phase.
• Hohe See Offshore Wind Project and Expansion - a wind project located in the North Sea, off the
coast of Germany that will generate approximately 497-MW, with an additional 112-MW from the
expansion. The Hohe See Offshore Wind Project and Expansion will be constructed under fixed-price
engineering, procurement, construction and installation contracts, which have been secured with key
suppliers. The Hohe See Project and Expansion is backed by a government legislated 20-year
revenue support mechanism.
74
75
GAS DISTRIBUTION
In addition to normal course investment to support customer additions, the following commercially
secured growth projects were placed into service in 2017:
•
2017 Dawn-Parkway Expansion - the expansion of the existing Dawn-Parkway pipeline system,
which provides transportation service from Dawn to the Greater Toronto Area, through the addition of
new compressors at each of the Dawn, Lobo and Bright compressor stations in Ontario. The project
provides additional capacity of approximately 419 mmcf/d and was placed into service in October
2017.
• Panhandle Reinforcement Project - the expansion of the existing Panhandle pipeline from Dawn to
the Dover transmission station in Chatham-Kent, Ontario. The project serves firm demand growth in
southwestern Ontario and was placed into service in November 2017.
GREEN POWER AND TRANSMISSION
The following commercially secured growth project was placed into service in 2017:
• Chapman Ranch Wind Project - a wind project that consists of 81 Acciona Windpower North
America, LLC (Acciona) turbines located in Nueces County, Texas which generate approximately 249-
MW of power and were placed into service on October 25, 2017. Acciona provides turbine operations
and maintenance services under a five-year fixed-price contract with an option to extend. The project
is backed by a 12-year power offtake agreement.
The following commercially secured growth projects are expected to be placed into service in 2018 and
2019:
• Rampion Offshore Wind Project - a wind project located off the Sussex coast in the United
Kingdom, consisting of 116 turbines, which will generate approximately 400-MW when complete. We
hold an effective 24.9% interest, United Kingdom’s Green Investment Bank plc holds a 25% interest
and E.ON SE holds the remaining 50.1% interest in the project, which was developed and is being
constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE. The Rampion
Offshore Wind Project is backed by revenues from the United Kingdom’s fixed-price Renewable
Obligation certificates program and a 15-year power purchase agreement. The project generated first
power in November 2017 and is currently in the commissioning phase.
• Hohe See Offshore Wind Project and Expansion - a wind project located in the North Sea, off the
coast of Germany that will generate approximately 497-MW, with an additional 112-MW from the
expansion. The Hohe See Offshore Wind Project and Expansion will be constructed under fixed-price
engineering, procurement, construction and installation contracts, which have been secured with key
suppliers. The Hohe See Project and Expansion is backed by a government legislated 20-year
revenue support mechanism.
74
75
North Sea
22
The following projects have been announced by us, but have not yet met our criteria to be classified as
OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
Irish Sea
14
12
15
Vancouver
Vancouver
Calgary
Calgary
Calgary
Calgary
CANADA
CAN ADA
UNITED
KINGDOM
London
Brighton
and Hove
21
English Channel
Amsterdam
THE
NETHERLANDS
Brussels
Cologne
FRANCE
BELGIUM GERMANY
Superior
Superior
Superior
Superior
Montreal
Montreal
Halifax
Halifax
Montreal
Montreal
10
Toronto
Toronto
Sarnia
Sarnia
Toronto
Toronto
Boston
Boston
Chicago
Chicago
Sarnia
Sarnia
Chicago
Chicago
11
Toledo
Toledo
9
New York
New York
UNITED STATES
UNITED STATES
OF AMERICA
OF AMERICA
UNITE D STATE S
UNITE D STATE S
OF AME RICA
OF AME RICA
DenverDenver
Las Vegas
Las Vegas
Cushing
Cushing
Cushing
Cushing
New Orleans
New Orleans
8
M
E
X
M
I
C
E
0
X
I
C
0
Houston
Houston
13
Houston
Houston
20
Power Transmission in Operation
Wind Assets in Operation
Solar Assets in Operation
Growth Projects—Wind
commercially secured:
LIQUIDS PIPELINES
• Gray Oak Pipeline Project - a 385,000 bpd pipeline system to provide producers and other shippers
the opportunity to secure crude oil transportation from West Texas to the destination markets
of Corpus Christi, Freeport, and Houston, Texas with connectivity to over 3 million bpd of refining
capacity and multiple dock facilities capable of crude oil exports. The project is a joint development
with Phillips 66 and would be placed into service during the second half of 2019 depending on
shipper interest expressed in the recently closed open season.
GAS TRANSMISSION AND MIDSTREAM
• Gulf Coast Express Pipeline Project - a natural gas pipeline connecting the Waha, Texas area to
Agua Dulce, Texas that will provide capacity up to approximately 1.7 bcf/d. The project is a joint
development between our equity investment DCP Midstream, Kinder Morgan Texas Pipeline LLC and
an affiliate of Targa Resources Corp, and is expected to be placed into service during the second half
of 2019, subject to obtaining sufficient shipper commitments.
• Alliance Pipeline Expansion Project - Alliance Pipeline announced a non-binding request for
expressions of interest for additional transportation service on the Alliance Pipeline Canada and
Alliance Pipeline US systems. Alliance Pipeline continues to engage with interested parties and
assess the addition of more compression facilities along the system in order to increase throughput
capacity by up to 500 mmcf/d. The projected in-service date for the potential capacity expansion is
the second half of 2021.
• Access Northeast - Access Northeast is a project that will bring affordable energy to New England
consumers. Natural gas pipeline capacity scarcity and system reliability remains a primary issue for
New England and one that must be resolved for the region to meet its energy supply needs. The
project's partners continue to pursue a viable commercial and operational model to provide natural
gas to the region.
GREEN POWER AND TRANSMISSION
• Éolien Maritime France SAS - a 50% interest in Éolien Maritime France SAS (EMF), a French
offshore wind development company, which is co-owned by EDF Energies Nouvelles, a subsidiary of
Électricité de France S.A. EMF holds licenses for three large-scale offshore wind farms off the coast
of France that would generate approximately 1,428 MW. The development of these projects is subject
to a final investment decision and regulatory approvals, the timing of which is not yet certain.
We also have a large portfolio of additional projects under development that have not yet progressed to
the point of public announcement.
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77
OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
The following projects have been announced by us, but have not yet met our criteria to be classified as
commercially secured:
LIQUIDS PIPELINES
• Gray Oak Pipeline Project - a 385,000 bpd pipeline system to provide producers and other shippers
the opportunity to secure crude oil transportation from West Texas to the destination markets
of Corpus Christi, Freeport, and Houston, Texas with connectivity to over 3 million bpd of refining
capacity and multiple dock facilities capable of crude oil exports. The project is a joint development
with Phillips 66 and would be placed into service during the second half of 2019 depending on
shipper interest expressed in the recently closed open season.
GAS TRANSMISSION AND MIDSTREAM
• Gulf Coast Express Pipeline Project - a natural gas pipeline connecting the Waha, Texas area to
Agua Dulce, Texas that will provide capacity up to approximately 1.7 bcf/d. The project is a joint
development between our equity investment DCP Midstream, Kinder Morgan Texas Pipeline LLC and
an affiliate of Targa Resources Corp, and is expected to be placed into service during the second half
of 2019, subject to obtaining sufficient shipper commitments.
• Alliance Pipeline Expansion Project - Alliance Pipeline announced a non-binding request for
expressions of interest for additional transportation service on the Alliance Pipeline Canada and
Alliance Pipeline US systems. Alliance Pipeline continues to engage with interested parties and
assess the addition of more compression facilities along the system in order to increase throughput
capacity by up to 500 mmcf/d. The projected in-service date for the potential capacity expansion is
the second half of 2021.
• Access Northeast - Access Northeast is a project that will bring affordable energy to New England
consumers. Natural gas pipeline capacity scarcity and system reliability remains a primary issue for
New England and one that must be resolved for the region to meet its energy supply needs. The
project's partners continue to pursue a viable commercial and operational model to provide natural
gas to the region.
GREEN POWER AND TRANSMISSION
• Éolien Maritime France SAS - a 50% interest in Éolien Maritime France SAS (EMF), a French
offshore wind development company, which is co-owned by EDF Energies Nouvelles, a subsidiary of
Électricité de France S.A. EMF holds licenses for three large-scale offshore wind farms off the coast
of France that would generate approximately 1,428 MW. The development of these projects is subject
to a final investment decision and regulatory approvals, the timing of which is not yet certain.
We also have a large portfolio of additional projects under development that have not yet progressed to
the point of public announcement.
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77
CAPITAL MARKET ACCESS
We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf
prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when
market conditions are attractive. In accordance with our funding plan, we completed the following
(in millions of Canadian dollars, unless stated otherwise)
Type of Issuance
issuances in 2017:
Entity
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Common shares (via share exchange*)
Common shares (by private placement)
Fixed-to-floating rate subordinated notes
Preference shares
Floating rate notes
Medium-term notes
US$ Floating rate notes
US$ Senior notes
US$ Fixed-to-floating rate subordinated notes
Enbridge Income Fund Holdings Inc. Common shares
Enbridge Income Fund Holdings Inc. Common shares (Secondary offering by Enbridge)
Enbridge Gas Distribution Inc. (EGD) Medium-term notes
Spectra Energy Partners, LP
Union Gas Limited
Floating rate notes
Medium-term notes
* In connection with the Merger Transaction
On January 9, 2018, Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP,
completed an offering of US$800 million of senior notes, which consisted of two US$400 million tranches
with fixed interest rates of 3.50% and 4.15% which mature in 2028 and 2048, respectively.
Amount
37,429
1,500
500
1,650
750
1,200
US$1,000
US$1,200
US$1,400
575
575
300
500
US$400
GROWTH PROJECTS - REGULATORY MATTERS
Lakehead System Mainline Expansion (EEP)
On October 16, 2017, the United States Department of State issued a Presidential permit to EEP to
operate Line 67 at its design capacity of 888,889 bpd at the international border of the United States and
Canada near Neche, North Dakota.
Canadian Line 3 Replacement Program (the Fund Group)
In December 2016, the Manitoba Metis Federation (MMF) and the Association of Manitoba Chiefs (AMC)
applied to the Federal Court of Appeal for leave, which was subsequently granted, to judicially review the
Government of Canada’s decision to approve the Canadian L3R Program. On July 4, 2017, the MMF
discontinued its judicial review application. On October 25, 2017, the AMC discontinued its judicial review
application. As a result, no further challenges to the Government of Canada's decision to approve the
Canadian L3R Program may be brought by any party.
All required pre-construction filings have been approved by the NEB.
United States Line 3 Replacement Program (EEP)
EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in
Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route
Permit) from the MNPUC. The MNPUC found both the Certificate of Need and Route Permit applications
for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the MNPUC issued a
written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental
Impact Statement (EIS) before the filing of intervenor testimony in the Certificate of Need and Route
Permit processes. The DOC issued the final EIS on August 17, 2017. The MNPUC determined the final
EIS to be inadequate in four specific areas on December 7, 2017. The DOC provided a supplemental EIS
on February 12, 2018, and the MNPUC will determine its adequacy in the second quarter of 2018. In the
parallel Certificate of Need and Route Permit dockets, public and evidentiary hearings were held at
locations along the proposed route and in Saint Paul, Minnesota from September to November 2017 and
are now complete. The MNPUC is expected to vote on the Certificate of Need and Route Permit at the
end of the second quarter of 2018.
LIQUIDITY AND CAPITAL RESOURCES
The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in
light of the significant number and size of capital projects currently secured or under development. Access
to timely funding from capital markets could be limited by factors outside our 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, we actively manage financial plans and strategies to ensure we
maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we
generally expect to utilize cash from operations together with commercial paper issuance and/or credit
facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance
capital expenditures, fund debt retirements and pay common and preference share dividends. We target
to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of
banks and financial institutions to enable us to fund all anticipated requirements for approximately one
year without accessing the capital markets.
Our financing plan is regularly updated to reflect evolving capital requirements and financial market
conditions and identifies a variety of potential sources of debt and equity funding alternatives, including
utilization of our sponsored vehicles. For additional information, refer to Sponsored Vehicles below.
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79
GROWTH PROJECTS - REGULATORY MATTERS
Lakehead System Mainline Expansion (EEP)
On October 16, 2017, the United States Department of State issued a Presidential permit to EEP to
operate Line 67 at its design capacity of 888,889 bpd at the international border of the United States and
Canada near Neche, North Dakota.
Canadian Line 3 Replacement Program (the Fund Group)
In December 2016, the Manitoba Metis Federation (MMF) and the Association of Manitoba Chiefs (AMC)
applied to the Federal Court of Appeal for leave, which was subsequently granted, to judicially review the
Government of Canada’s decision to approve the Canadian L3R Program. On July 4, 2017, the MMF
discontinued its judicial review application. On October 25, 2017, the AMC discontinued its judicial review
application. As a result, no further challenges to the Government of Canada's decision to approve the
Canadian L3R Program may be brought by any party.
All required pre-construction filings have been approved by the NEB.
United States Line 3 Replacement Program (EEP)
EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in
Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route
Permit) from the MNPUC. The MNPUC found both the Certificate of Need and Route Permit applications
for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the MNPUC issued a
written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental
Impact Statement (EIS) before the filing of intervenor testimony in the Certificate of Need and Route
Permit processes. The DOC issued the final EIS on August 17, 2017. The MNPUC determined the final
EIS to be inadequate in four specific areas on December 7, 2017. The DOC provided a supplemental EIS
on February 12, 2018, and the MNPUC will determine its adequacy in the second quarter of 2018. In the
parallel Certificate of Need and Route Permit dockets, public and evidentiary hearings were held at
locations along the proposed route and in Saint Paul, Minnesota from September to November 2017 and
are now complete. The MNPUC is expected to vote on the Certificate of Need and Route Permit at the
end of the second quarter of 2018.
LIQUIDITY AND CAPITAL RESOURCES
The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in
light of the significant number and size of capital projects currently secured or under development. Access
to timely funding from capital markets could be limited by factors outside our 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, we actively manage financial plans and strategies to ensure we
maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we
generally expect to utilize cash from operations together with commercial paper issuance and/or credit
facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance
capital expenditures, fund debt retirements and pay common and preference share dividends. We target
to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of
banks and financial institutions to enable us to fund all anticipated requirements for approximately one
year without accessing the capital markets.
Our financing plan is regularly updated to reflect evolving capital requirements and financial market
conditions and identifies a variety of potential sources of debt and equity funding alternatives, including
utilization of our sponsored vehicles. For additional information, refer to Sponsored Vehicles below.
CAPITAL MARKET ACCESS
We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf
prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when
market conditions are attractive. In accordance with our funding plan, we completed the following
issuances in 2017:
Type of Issuance
Entity
(in millions of Canadian dollars, unless stated otherwise)
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Income Fund Holdings Inc. Common shares
Enbridge Income Fund Holdings Inc. Common shares (Secondary offering by Enbridge)
Enbridge Gas Distribution Inc. (EGD) Medium-term notes
Floating rate notes
Spectra Energy Partners, LP
Medium-term notes
Union Gas Limited
* In connection with the Merger Transaction
Common shares (via share exchange*)
Common shares (by private placement)
Preference shares
Fixed-to-floating rate subordinated notes
Floating rate notes
Medium-term notes
US$ Fixed-to-floating rate subordinated notes
US$ Floating rate notes
US$ Senior notes
Amount
37,429
1,500
500
1,650
750
1,200
US$1,000
US$1,200
US$1,400
575
575
300
US$400
500
On January 9, 2018, Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP,
completed an offering of US$800 million of senior notes, which consisted of two US$400 million tranches
with fixed interest rates of 3.50% and 4.15% which mature in 2028 and 2048, respectively.
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79
Credit Facilities, Ratings and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access
to funds through committed bank credit facilities and actively manage our bank funding sources to
optimize pricing and other terms. The following table provides details of our committed credit facilities at
December 31, 2017.
2017
Total
Facilities
Draws1
Available
Maturity
December 31,
(millions of Canadian dollars)
Enbridge Inc.2
Enbridge (U.S.) Inc.
Enbridge Energy Partners, L.P.3
Enbridge Gas Distribution Inc.
Enbridge Income Fund
Enbridge Pipelines (Southern Lights) L.L.C.
Enbridge Pipelines Inc.
Enbridge Southern Lights LP
Spectra Energy Partners, LP4,5
Union Gas Limited5
Westcoast Energy Inc.5
Total committed credit facilities
1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
2 Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020,
2019-2022
2019
2019-2022
2019
2020
2019
2019
2019
2022
2021
2021
2,737
490
1,820
972
766
—
1,438
—
2,824
485
—
11,532
7,353
3,590
3,289
1,016
1,500
25
3,000
5
3,133
700
400
24,011
4,616
3,100
1,469
44
734
25
1,562
5
309
215
400
12,479
respectively.
3 Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020,
respectively.
4 Includes $421 million (US$336 million) of commitments that expire in 2021.
5 Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction. For additional information,
refer to Merger with Spectra Energy.
During the first quarter of 2017, Enbridge established a five-year, term credit facility for $239 million
(¥20,000 million) with a syndicate of Japanese banks. Principal and interest on this facility have been
converted to United States dollars using a cross currency interest rate swap.
In addition to the committed credit facilities noted above, we have $792 million of uncommitted demand
facilities, of which $518 million were unutilized as at December 31, 2017. As at December 31, 2016, we
had $335 million of uncommitted credit facilities, of which $177 million were unutilized.
Our net available liquidity of $12,959 million at December 31, 2017 was inclusive of $480 million of
unrestricted cash and cash equivalents as reported on the Consolidated Statements of Financial Position.
Our credit facility agreements and term debt indentures include standard events of default and covenant
provisions whereby accelerated repayment and/or termination of the agreements may result if we were to
default on payment or violate certain covenants. As at December 31, 2017, we were in compliance with
all debt covenants and expect to continue to comply with such covenants.
Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable
business model have enabled us to manage our credit profile. We actively monitor and manage 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 on 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, 2017, our debt
capitalization ratio was 48.3% compared with 61.8% as at December 31, 2016. The improvement in the
ratio reflected an increase in equity that resulted from the Merger Transaction.
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81
During 2017, our credit ratings were affirmed as follows:
• DBRS Limited confirmed our issuer rating and medium-term notes and unsecured debentures
rating of BBB (high), fixed-to-floating subordinated notes rating of BBB (low), preference share
rating of Pfd-3 (high) and commercial paper rating of R-2 (high), and changed their rating outlook
from under review with developing implications to stable.
• Standard & Poor’s Rating Services (S&P) affirmed our corporate credit rating and senior
unsecured debt rating of BBB+, preference share rating of P-2 (low) and commercial paper rating
of A-1 (low), and reaffirmed a stable outlook. S&P also affirmed our global overall short-term
rating of A-2.
•
In June 2017, we obtained Fitch long-term issuer default rating and senior unsecured debt rating
of BBB+, preference share rating of BBB-, junior subordinated note rating of BBB-, and short-term
and commercial paper rating of F2 with a stable rating outlook.
• On December 22, 2017, Moody’s Investor Services, Inc. downgraded our issuer and senior
unsecured ratings from Baa2 to Baa3, subordinated rating from Ba1 to Ba2, preference share
rating from Ba1 to Ba2, commercial paper rating for Enbridge (U.S.) Inc. from P-2 to P-3, and
changed the outlook on all of these ratings from negative to stable.
We invest surplus cash in short-term investment grade money market instruments with highly creditworthy
counterparties. Short-term investments were $70 million as at December 31, 2017 compared with $800
million as at December 31, 2016. The higher short-term investment balances at the end of 2016 reflect
the temporary investment of a portion of the proceeds of capital markets offerings undertaken by us in the
fourth quarter of 2016, pending its redeployment in our growth capital program.
There are no material restrictions on our cash. Total restricted cash of $107 million includes EGD’s and
Union Gas’ receipt of cash from the Government of Ontario to fund its Green Investment Fund program.
In addition, our restricted cash includes cash collateral and amounts received in respect of specific
shipper commitments. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally
not readily accessible by us until distributions are declared and paid by these entities, which occurs
quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by
certain foreign subsidiaries may not be readily accessible for alternative uses by us.
Excluding current maturities of long-term debt, at December 31, 2017 and 2016 we had a negative
working capital position of $2,538 million and $456 million, respectively. In both periods, the major
contributing factor to the negative working capital position was the ongoing funding of our growth capital
program.
To address this negative working capital position, we maintain significant liquidity in the form of committed
credit facilities and other sources as previously discussed, which enable the funding of liabilities as they
become due. As at December 31, 2017 and 2016, our net available liquidity totaled $12,959 million and
$14,274 million, respectively, on a consolidated basis. It is anticipated that any current maturities of long-
term debt will be refinanced upon maturity.
Credit Facilities, Ratings and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access
to funds through committed bank credit facilities and actively manage our bank funding sources to
optimize pricing and other terms. The following table provides details of our committed credit facilities at
December 31, 2017.
December 31,
(millions of Canadian dollars)
Enbridge Inc.2
Enbridge (U.S.) Inc.
Enbridge Energy Partners, L.P.3
Enbridge Gas Distribution Inc.
Enbridge Income Fund
Enbridge Pipelines Inc.
Enbridge Southern Lights LP
Spectra Energy Partners, LP4,5
Union Gas Limited5
Westcoast Energy Inc.5
Total committed credit facilities
Enbridge Pipelines (Southern Lights) L.L.C.
2019-2022
2019-2022
2019
2019
2020
2019
2019
2019
2022
2021
2021
Maturity
Facilities
Draws1
Available
Total
7,353
3,590
3,289
1,016
1,500
25
3,000
5
3,133
700
400
2017
2,737
490
1,820
972
766
—
1,438
—
2,824
485
—
4,616
3,100
1,469
1,562
44
734
25
5
309
215
400
1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
2 Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020,
24,011
11,532
12,479
respectively.
respectively.
3 Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020,
4 Includes $421 million (US$336 million) of commitments that expire in 2021.
5 Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction. For additional information,
refer to Merger with Spectra Energy.
During the first quarter of 2017, Enbridge established a five-year, term credit facility for $239 million
(¥20,000 million) with a syndicate of Japanese banks. Principal and interest on this facility have been
converted to United States dollars using a cross currency interest rate swap.
In addition to the committed credit facilities noted above, we have $792 million of uncommitted demand
facilities, of which $518 million were unutilized as at December 31, 2017. As at December 31, 2016, we
had $335 million of uncommitted credit facilities, of which $177 million were unutilized.
Our net available liquidity of $12,959 million at December 31, 2017 was inclusive of $480 million of
unrestricted cash and cash equivalents as reported on the Consolidated Statements of Financial Position.
Our credit facility agreements and term debt indentures include standard events of default and covenant
provisions whereby accelerated repayment and/or termination of the agreements may result if we were to
default on payment or violate certain covenants. As at December 31, 2017, we were in compliance with
all debt covenants and expect to continue to comply with such covenants.
Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable
business model have enabled us to manage our credit profile. We actively monitor and manage 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 on 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, 2017, our debt
capitalization ratio was 48.3% compared with 61.8% as at December 31, 2016. The improvement in the
ratio reflected an increase in equity that resulted from the Merger Transaction.
During 2017, our credit ratings were affirmed as follows:
• DBRS Limited confirmed our issuer rating and medium-term notes and unsecured debentures
rating of BBB (high), fixed-to-floating subordinated notes rating of BBB (low), preference share
rating of Pfd-3 (high) and commercial paper rating of R-2 (high), and changed their rating outlook
from under review with developing implications to stable.
• Standard & Poor’s Rating Services (S&P) affirmed our corporate credit rating and senior
unsecured debt rating of BBB+, preference share rating of P-2 (low) and commercial paper rating
of A-1 (low), and reaffirmed a stable outlook. S&P also affirmed our global overall short-term
rating of A-2.
In June 2017, we obtained Fitch long-term issuer default rating and senior unsecured debt rating
of BBB+, preference share rating of BBB-, junior subordinated note rating of BBB-, and short-term
and commercial paper rating of F2 with a stable rating outlook.
•
• On December 22, 2017, Moody’s Investor Services, Inc. downgraded our issuer and senior
unsecured ratings from Baa2 to Baa3, subordinated rating from Ba1 to Ba2, preference share
rating from Ba1 to Ba2, commercial paper rating for Enbridge (U.S.) Inc. from P-2 to P-3, and
changed the outlook on all of these ratings from negative to stable.
We invest surplus cash in short-term investment grade money market instruments with highly creditworthy
counterparties. Short-term investments were $70 million as at December 31, 2017 compared with $800
million as at December 31, 2016. The higher short-term investment balances at the end of 2016 reflect
the temporary investment of a portion of the proceeds of capital markets offerings undertaken by us in the
fourth quarter of 2016, pending its redeployment in our growth capital program.
There are no material restrictions on our cash. Total restricted cash of $107 million includes EGD’s and
Union Gas’ receipt of cash from the Government of Ontario to fund its Green Investment Fund program.
In addition, our restricted cash includes cash collateral and amounts received in respect of specific
shipper commitments. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally
not readily accessible by us until distributions are declared and paid by these entities, which occurs
quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by
certain foreign subsidiaries may not be readily accessible for alternative uses by us.
Excluding current maturities of long-term debt, at December 31, 2017 and 2016 we had a negative
working capital position of $2,538 million and $456 million, respectively. In both periods, the major
contributing factor to the negative working capital position was the ongoing funding of our growth capital
program.
To address this negative working capital position, we maintain significant liquidity in the form of committed
credit facilities and other sources as previously discussed, which enable the funding of liabilities as they
become due. As at December 31, 2017 and 2016, our net available liquidity totaled $12,959 million and
$14,274 million, respectively, on a consolidated basis. It is anticipated that any current maturities of long-
term debt will be refinanced upon maturity.
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SOURCES AND USES OF CASH
December 31,
(millions of Canadian dollars)
Operating activities
Investing activities
Financing activities
Effect of translation of foreign denominated cash and cash
equivalents
Increase/(decrease) in cash and cash equivalents
2017
2016
2015
6,584
(11,002)
3,476
(72)
(1,014)
5,211
(5,192)
840
(19)
840
4,571
(7,933)
3,074
143
(145)
Significant sources and uses of cash for the years ended December 31, 2017 and 2016 are summarized
below:
Operating Activities
2017
• The growth in cash flow delivered by operations in 2017 is a reflection of the positive operating
factors discussed under Results of Operations, which primarily included contributions from new
assets of approximately $2,574 million following the completion of the Merger Transaction.
• For the year ended, partially offsetting the increase in cash flows from operating activities are
transaction costs in connection with the Merger Transaction, as well as employee severance
costs in relation to our enterprise-wide reduction of workforce.
• Changes in operating assets and liabilities to $314 million from $358 million for the years ended
December 31, 2017 and 2016, respectively, reflected negative working capital in each of those
years. Our operating assets and liabilities fluctuate in the normal course due to various factors
including fluctuations in commodity prices and activity levels within the Energy Services and Gas
Distribution segments, the timing of tax payments, as well as timing of cash receipts and
payments.
2016
• The growth in cash flow delivered by operations in 2016 was a reflection of the positive operating
factors discussed under Results of Operations, which primarily included stronger contributions
from the Liquids Pipelines segment, partially offset by higher financing costs resulting from the
incurrence of incremental debt to fund asset growth and the impact of refinancing construction
debt with longer-term debt financing.
• Changes in operating assets and liabilities included within operating activities were $358 million
for the year ended December 31, 2016 compared with $645 million for the comparative 2015
year. Our operating assets and liabilities fluctuate in the normal course due to various factors
including fluctuations in commodity prices and activity levels within the Energy Services and Gas
Distribution segments, the timing of tax payments, general variations in activity levels within our
businesses, as well as timing of cash receipts and payments.
Investing Activities
We continue with the execution of our growth capital program which is further described in Growth
Projects – Commercially Secured Projects. The timing of project approval, construction and in-service
dates impacts the timing of cash requirements.
A summary of additions to property, plant and equipment for the years ended December 31, 2017, 2016
and 2015 is set out below:
Year ended December 31,
(millions of Canadian dollars)
Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Eliminations and Other
Total capital expenditures
2017
2016
2015
3,956
5,882
2,797
3,883
1,177
321
1
108
8,287
176
713
251
—
32
385
858
68
—
80
5,128
7,273
2017
2016
• The increase in cash used in investing activities was primarily attributable to capital expenditures
of $8,287 million compared with $5,128 million for the comparable period, which include capital
expenditures on assets and growth projects acquired through the Merger Transaction, and
increased investment in equity investments. During the first half of 2017, we paid cash
consideration of $2.0 billion (US $1.5 billion) for the acquisition of an interest in the Bakken
Pipeline System. In addition, we also made an equity investment of $0.5 billion in connection with
our 50% interest in the Hohe See Offshore Wind Project.
• The above increase in cash usage was partially offset by cash acquired in the Merger Transaction
in the first quarter of 2017, proceeds from the disposition of the Ozark Pipeline, Sandpiper Project
and Olympic Pipeline in 2017.
• The timing of projects approval, construction and in-service dates impacted the timing of cash
requirements. For the year ended December 31, 2016, additions to property, plant and equipment
resulted in cash expenditures of $5,128 million compared with $7,273 million for the year ended
December 31, 2015. The year-over-year decrease reflected the successful completion of growth
projects in 2015, including the Edmonton to Hardisty Expansion, Southern Access Extension and
phases of the Eastern Access Program.
• Also contributing to the decrease in year-over-year cash used in investing activities were
proceeds received from disposition of assets. For the year ended December 31, 2016, proceeds
from dispositions were $1,379 million compared with $146 million for the year ended
December 31, 2015. The majority of the proceeds in 2016 related to the sale of the South Prairie
Region assets completed in December 2016.
• Partially offsetting the above factors was higher spending in 2016 for acquisitions. During the
second quarter of 2016, we made an initial equity investment in and advanced an affiliate loan to
acquire a 50% interest in a French offshore wind development company and fund the ongoing
development costs of that company.
Financing Activities
2017
The increase in net cash generated from financing activities resulted from the following factors:
• We issued a series of medium term fixed and floating rate notes, the proceeds of which were
used to repay maturing term notes and credit facilities and to finance growth capital programs.
For the year ended 2017, proceeds from term note issuances were primarily used to repay credit
facilities and redeem tender offers for Spectra Energy’s outstanding senior unsecured notes as
discussed in Liquidity and Capital Resources - Capital Market Access.
• The change in cash generated from financing activities reflected overall higher cash contributions
from redeemable noncontrolling interests of $1,178 million compared with $591 million in the
comparable period attributable to our holdings in ENF equity. Cash contributions were also higher
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83
2017
2016
2015
6,584
(11,002)
3,476
(72)
(1,014)
5,211
(5,192)
840
(19)
840
4,571
(7,933)
3,074
143
(145)
SOURCES AND USES OF CASH
December 31,
(millions of Canadian dollars)
Operating activities
Investing activities
Financing activities
equivalents
below:
2017
Operating Activities
Effect of translation of foreign denominated cash and cash
Increase/(decrease) in cash and cash equivalents
Significant sources and uses of cash for the years ended December 31, 2017 and 2016 are summarized
• The growth in cash flow delivered by operations in 2017 is a reflection of the positive operating
factors discussed under Results of Operations, which primarily included contributions from new
assets of approximately $2,574 million following the completion of the Merger Transaction.
• For the year ended, partially offsetting the increase in cash flows from operating activities are
transaction costs in connection with the Merger Transaction, as well as employee severance
costs in relation to our enterprise-wide reduction of workforce.
• Changes in operating assets and liabilities to $314 million from $358 million for the years ended
December 31, 2017 and 2016, respectively, reflected negative working capital in each of those
years. Our operating assets and liabilities fluctuate in the normal course due to various factors
including fluctuations in commodity prices and activity levels within the Energy Services and Gas
Distribution segments, the timing of tax payments, as well as timing of cash receipts and
payments.
2016
• The growth in cash flow delivered by operations in 2016 was a reflection of the positive operating
factors discussed under Results of Operations, which primarily included stronger contributions
from the Liquids Pipelines segment, partially offset by higher financing costs resulting from the
incurrence of incremental debt to fund asset growth and the impact of refinancing construction
debt with longer-term debt financing.
• Changes in operating assets and liabilities included within operating activities were $358 million
for the year ended December 31, 2016 compared with $645 million for the comparative 2015
year. Our operating assets and liabilities fluctuate in the normal course due to various factors
including fluctuations in commodity prices and activity levels within the Energy Services and Gas
Distribution segments, the timing of tax payments, general variations in activity levels within our
businesses, as well as timing of cash receipts and payments.
Investing Activities
We continue with the execution of our growth capital program which is further described in Growth
Projects – Commercially Secured Projects. The timing of project approval, construction and in-service
dates impacts the timing of cash requirements.
A summary of additions to property, plant and equipment for the years ended December 31, 2017, 2016
and 2015 is set out below:
Year ended December 31,
(millions of Canadian dollars)
Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Eliminations and Other
Total capital expenditures
2017
2017
2016
2015
2,797
3,883
1,177
321
1
108
8,287
3,956
176
713
251
—
32
5,128
5,882
385
858
68
—
80
7,273
• The increase in cash used in investing activities was primarily attributable to capital expenditures
of $8,287 million compared with $5,128 million for the comparable period, which include capital
expenditures on assets and growth projects acquired through the Merger Transaction, and
increased investment in equity investments. During the first half of 2017, we paid cash
consideration of $2.0 billion (US $1.5 billion) for the acquisition of an interest in the Bakken
Pipeline System. In addition, we also made an equity investment of $0.5 billion in connection with
our 50% interest in the Hohe See Offshore Wind Project.
• The above increase in cash usage was partially offset by cash acquired in the Merger Transaction
in the first quarter of 2017, proceeds from the disposition of the Ozark Pipeline, Sandpiper Project
and Olympic Pipeline in 2017.
2016
• The timing of projects approval, construction and in-service dates impacted the timing of cash
requirements. For the year ended December 31, 2016, additions to property, plant and equipment
resulted in cash expenditures of $5,128 million compared with $7,273 million for the year ended
December 31, 2015. The year-over-year decrease reflected the successful completion of growth
projects in 2015, including the Edmonton to Hardisty Expansion, Southern Access Extension and
phases of the Eastern Access Program.
• Also contributing to the decrease in year-over-year cash used in investing activities were
proceeds received from disposition of assets. For the year ended December 31, 2016, proceeds
from dispositions were $1,379 million compared with $146 million for the year ended
December 31, 2015. The majority of the proceeds in 2016 related to the sale of the South Prairie
Region assets completed in December 2016.
• Partially offsetting the above factors was higher spending in 2016 for acquisitions. During the
second quarter of 2016, we made an initial equity investment in and advanced an affiliate loan to
acquire a 50% interest in a French offshore wind development company and fund the ongoing
development costs of that company.
Financing Activities
2017
The increase in net cash generated from financing activities resulted from the following factors:
• We issued a series of medium term fixed and floating rate notes, the proceeds of which were
used to repay maturing term notes and credit facilities and to finance growth capital programs.
For the year ended 2017, proceeds from term note issuances were primarily used to repay credit
facilities and redeem tender offers for Spectra Energy’s outstanding senior unsecured notes as
discussed in Liquidity and Capital Resources - Capital Market Access.
• The change in cash generated from financing activities reflected overall higher cash contributions
from redeemable noncontrolling interests of $1,178 million compared with $591 million in the
comparable period attributable to our holdings in ENF equity. Cash contributions were also higher
82
83
for noncontrolling interests, which now include noncontrolling interests acquired through the
Merger Transaction, which is more than offset by the increase in distributions to noncontrolling
interests. The increase in distributions to noncontrolling interests was primarily attributable to the
acquired assets, which were partially offset by the decrease in distributions resulting from the
EEP strategic restructuring discussed under United States Sponsored Vehicle Strategy.
• Cash provided from financing activities further increased as we completed the issuance of 33.5
million common shares for gross proceeds of approximately $1.5 billion along with the issuance
of 4 million preferred shares for gross proceeds of $0.5 billion.
• For the year ended 2017, the above increases in cash were partially offset by $227 million paid to
acquire all of the outstanding publicly-held common units of MEP during the second quarter of
2017, as well as higher cash received from the issuance of common shares in the first quarter of
2016, as a result of the issuance of 56 million common shares in March 2016.
• Finally, our common share dividend payments increased in the first half of 2017, primarily due to
the increase in the common share dividend rate effective March 2017, as well as higher number
of common shares outstanding as a result of the issuance of approximately 75 million common
shares in 2016 and 691 million common shares issued in connection with the Merger Transaction.
In addition, we paid $414 million in common share dividends to the shareholders of Spectra
Energy. These dividends were declared before the closing of the Merger Transaction but were
paid after the closing of the Merger Transaction.
2016
• Our financing requirements decreased for the year ended December 31, 2016 compared with
December 31, 2015, primarily reflecting lower expenditures on growth capital projects and the
proceeds of asset sales. Our funding requirements are a reflection of the timing of various growth
projects.
In 2016, our overall debt decreased by $149 million compared with an overall increase in debt of
$3,663 million in 2015. The decrease was mainly due to lower debt requirements resulting from
the timing of completion of various growth projects and other sources of funds, primarily the
proceeds from our common share issuance in March 2016, which were partly utilized to reduce
drawn credit facilities and outstanding commercial paper draws.
•
• The increase in common share dividends paid in 2016 was attributable to the increase in the
common share dividend rate effective March 2016 and a higher number of common shares
outstanding primarily as a result of the common share issuance noted above.
• Distributions to redeemable noncontrolling interests in the Fund Group increased during 2016
compared with the corresponding 2015 period mainly due to a higher per share distribution rate
and a larger number of public shares outstanding in ENF. Higher distributions to noncontrolling
interests in EEP reflected an increase to the per unit distribution in the first half of 2016 as well as
the effects of a strengthening United States dollar versus the Canadian dollar.
Since July 2011, we have issued 310 million preference shares for gross proceeds of approximately $7.8
Preference Share Issuances
billion with the following characteristics.
Gross Proceeds
Dividend Rate
Dividend1,9
(Canadian dollars, unless otherwise stated)
—
3-month treasury bill
plus 2.400%
$500 million
3.42%
$0.85360
June 1, 2022
Series C
Per Share
Base
Redemption
Value2
Redemption
and Conversion
Option Date2,3
Right to
Convert
Into3,4
4.89% US$1.22160
4.96% US$1.23972
US$25
US$25
4.00% US$1.00000
4.00%
$1.00000
4.40% US$1.10000
US$25
$25
US$25
4.00%
4.00%
4.00%
4.00%
4.00%
4.00%
4.40%
4.40%
4.40%
4.40%
4.40%
5.15%
4.90%
—
$1.00000
$1.00000
$1.00000
$1.00000
$1.00000
$1.00000
$1.10000
$1.10000
$1.10000
$1.10000
$1.10000
$1.28750
$1.22500
$25
$25
$25
$25
$25
$25
$25
$25
$25
$25
$25
$25
$25
$25
$25
June 1, 2022
March 1, 2018
June 1, 2018
September 1, 2018
June 1, 2022
September 1, 2022
December 1, 2018
March 1, 2019
June 1, 2019
June 1, 2018
September 1, 2019
March 1, 2019
March 1, 2019
December 1, 2019
March 1, 2020
June 1, 2020
September 1, 2020
March 1, 2022
March 1, 2023
Series B
Series E
Series G
Series I
Series K
Series M
Series O
Series Q
Series S
Series 2
Series 4
Series 6
Series 8
Series 10
Series 12
Series 14
Series 16
Series 18
Series 20
$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
$275 million
$500 million
$350 million
$275 million
$750 million
$500 million
Series B5
Series C5
Series D6
Series F
Series H
Series J7
Series L7
Series N
Series P
Series R
Series 1
Series 3
Series 5
Series 7
Series 9
Series 11
Series 13
Series 15
Series 17
Series 198
feature.
1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board. With the exception
of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption
and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate,
when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this
2 Preference Shares, Series A may be redeemed any time at our option. For all other series of Preference Shares, we may, at our
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 a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an
ascribed issue price equal to the Base Redemption Value.
4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect 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), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7%
(Series 16), 4.1% (Series 18) or 3.2% (Series 20); 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 On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares
based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount
for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual
dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount
for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on
December 1, 2017, due to reset on a quarterly basis following the issuance thereof.
6 On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on
March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D
fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less
than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were
tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E
Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference
Shares will be increased to $0.27875 from $0.25000, due to the reset of the annual dividend rate on every fifth anniversary of the
date of issuance of the Series D Preference Shares.
7 No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates,
respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US
$0.30540 from US$0.25000 on June 1, 2017, and to US$0.30993 from US$0.25000 on September 1, 2017, respectively, due to
the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference
Shares.
84
85
for noncontrolling interests, which now include noncontrolling interests acquired through the
Merger Transaction, which is more than offset by the increase in distributions to noncontrolling
interests. The increase in distributions to noncontrolling interests was primarily attributable to the
acquired assets, which were partially offset by the decrease in distributions resulting from the
EEP strategic restructuring discussed under United States Sponsored Vehicle Strategy.
• Cash provided from financing activities further increased as we completed the issuance of 33.5
million common shares for gross proceeds of approximately $1.5 billion along with the issuance
of 4 million preferred shares for gross proceeds of $0.5 billion.
• For the year ended 2017, the above increases in cash were partially offset by $227 million paid to
acquire all of the outstanding publicly-held common units of MEP during the second quarter of
2017, as well as higher cash received from the issuance of common shares in the first quarter of
2016, as a result of the issuance of 56 million common shares in March 2016.
• Finally, our common share dividend payments increased in the first half of 2017, primarily due to
the increase in the common share dividend rate effective March 2017, as well as higher number
of common shares outstanding as a result of the issuance of approximately 75 million common
shares in 2016 and 691 million common shares issued in connection with the Merger Transaction.
In addition, we paid $414 million in common share dividends to the shareholders of Spectra
Energy. These dividends were declared before the closing of the Merger Transaction but were
paid after the closing of the Merger Transaction.
2016
projects.
• Our financing requirements decreased for the year ended December 31, 2016 compared with
December 31, 2015, primarily reflecting lower expenditures on growth capital projects and the
proceeds of asset sales. Our funding requirements are a reflection of the timing of various growth
•
In 2016, our overall debt decreased by $149 million compared with an overall increase in debt of
$3,663 million in 2015. The decrease was mainly due to lower debt requirements resulting from
the timing of completion of various growth projects and other sources of funds, primarily the
proceeds from our common share issuance in March 2016, which were partly utilized to reduce
drawn credit facilities and outstanding commercial paper draws.
• The increase in common share dividends paid in 2016 was attributable to the increase in the
common share dividend rate effective March 2016 and a higher number of common shares
outstanding primarily as a result of the common share issuance noted above.
• Distributions to redeemable noncontrolling interests in the Fund Group increased during 2016
compared with the corresponding 2015 period mainly due to a higher per share distribution rate
and a larger number of public shares outstanding in ENF. Higher distributions to noncontrolling
interests in EEP reflected an increase to the per unit distribution in the first half of 2016 as well as
the effects of a strengthening United States dollar versus the Canadian dollar.
Preference Share Issuances
Since July 2011, we have issued 310 million preference shares for gross proceeds of approximately $7.8
billion with the following characteristics.
Per Share
Base
Redemption
Value2
Redemption
and Conversion
Option Date2,3
Right to
Convert
Into3,4
$25
June 1, 2022
Series C
Gross Proceeds
Dividend Rate
Dividend1,9
(Canadian dollars, unless otherwise stated)
Series B5
$500 million
—
—
$25
Series B
$0.85360
June 1, 2022
$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
$275 million
$500 million
$350 million
$275 million
$750 million
$500 million
3.42%
3-month treasury bill
plus 2.400%
$1.00000
4.00%
$1.00000
4.00%
4.00%
$1.00000
4.89% US$1.22160
4.96% US$1.23972
$1.00000
4.00%
$1.00000
4.00%
4.00%
$1.00000
4.00% US$1.00000
4.00%
$1.00000
4.40% US$1.10000
$1.10000
4.40%
$1.10000
4.40%
$1.10000
4.40%
$1.10000
4.40%
$1.10000
4.40%
$1.28750
5.15%
$1.22500
4.90%
Series C5
Series D6
Series E
Series G
Series F
Series I
Series H
Series J7
Series K
Series L7
Series M
Series O
Series N
Series Q
Series P
Series S
Series R
Series 2
Series 1
Series 4
Series 3
Series 6
Series 5
Series 8
Series 7
Series 10
Series 9
Series 12
Series 11
Series 14
Series 13
Series 16
Series 15
Series 18
Series 17
Series 198
Series 20
1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board. With the exception
of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption
and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate,
when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this
feature.
March 1, 2018
June 1, 2018
September 1, 2018
June 1, 2022
September 1, 2022
December 1, 2018
March 1, 2019
June 1, 2019
June 1, 2018
September 1, 2019
March 1, 2019
March 1, 2019
December 1, 2019
March 1, 2020
June 1, 2020
September 1, 2020
March 1, 2022
March 1, 2023
$25
$25
$25
US$25
US$25
$25
$25
$25
US$25
$25
US$25
$25
$25
$25
$25
$25
$25
$25
2 Preference Shares, Series A may be redeemed any time at our option. For all other series of Preference Shares, we may, at our
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 a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an
ascribed issue price equal to the Base Redemption Value.
4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect 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), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7%
(Series 16), 4.1% (Series 18) or 3.2% (Series 20); 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 On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares
based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount
for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual
dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount
for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on
December 1, 2017, due to reset on a quarterly basis following the issuance thereof.
6 On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on
March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D
fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less
than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were
tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E
Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference
Shares will be increased to $0.27875 from $0.25000, due to the reset of the annual dividend rate on every fifth anniversary of the
date of issuance of the Series D Preference Shares.
7 No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates,
respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US
$0.30540 from US$0.25000 on June 1, 2017, and to US$0.30993 from US$0.25000 on September 1, 2017, respectively, due to
the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference
Shares.
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85
8 On December 11, 2017, 20 million Series 19 Preferred Shares, inclusive of 4 million Series 19 Preferred Shares issued on full
exercise of the underwriters' option, were issued for gross proceeds of $500 million.
9 For dividends declared, see Liquidity and Capital Resources – Sources and Uses of Cash – Dividend Reinvestment and Share
Purchase Plan.
Common Share Issuances
On December 7, 2017, we completed the issuance of 33.5 million common shares for gross proceeds of
approximately $1.5 billion. The proceeds were used to reduce short-term indebtedness pending
reinvestment in secured capital projects.
On February 27, 2017, we completed the issuance of 691 million common shares with a value of $37.4
billion in exchange for shares of Spectra Energy in connection with the Merger Transaction. For further
information, see Merger with Spectra Energy and Item 8. Financial Statements and Supplementary Data -
Note 7. Acquisitions and Dispositions.
On March 1, 2016, we completed the issuance of 56.5 million common shares for gross proceeds of
approximately $2.3 billion, inclusive of the shares issued on exercise of the full amount of the
underwriters’ over-allotment option to purchase an additional 7.4 million common shares. The proceeds
were used to reduce short-term indebtedness pending reinvestment in secured capital projects.
Dividend Reinvestment and Share Purchase Plan
Participants in our Dividend Reinvestment and Share Purchase Plan (DRIP) receive a 2% discount on the
purchase of common shares with reinvested dividends. For the years ended December 31, 2017 and
2016, total dividends paid were $3,562 million and $1,945 million, respectively, of which $2,336 million
and $1,150 million, respectively, were paid in cash and reflected in financing activities. The remaining
$1,226 million and $795 million, respectively, of dividends paid were reinvested pursuant to the DRIP and
resulted in the issuance of common shares rather than a cash payment. For the years ended
December 31, 2017 and 2016, 34.4% and 40.9%, respectively, of total dividends paid were reinvested
through the DRIP. In addition to amounts paid in cash and reflected in financing activities for the year
ended December 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders prior
to the Merger Transaction that were paid after the Merger Transaction.
Our Board of Directors has declared the following quarterly dividends. All dividends are payable on
March 1, 2018 to shareholders of record on February 15, 2018.
Common Shares
Preference Shares, Series A
Preference Shares, Series B1
Preference Shares, Series C2
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J3
Preference Shares, Series L4
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
Preference Shares, Series 9
Preference Shares, Series 11
Preference Shares, Series 13
Preference Shares, Series 15
Preference Shares, Series 17
Preference Shares, Series 19
$0.67100
$0.34375
$0.21340
$0.20342
$0.25000
$0.25000
$0.25000
US$0.30540
US$0.30993
$0.25000
$0.25000
$0.25000
US$0.25000
$0.25000
US$0.27500
$0.27500
$0.27500
$0.27500
$0.27500
$0.27500
$0.32188
$0.26850
1 The quarterly dividend amount of Series B was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the
annual dividend on every fifth anniversary of the date of issuance of the Series B Preference Shares.
2 The quarterly dividend amount of Series C was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342
on December 1, 2017, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
3 The quarterly dividend amount of Series J was increased to US$0.30540 from US$0.25000 on June 1, 2017, due to the reset of
the annual dividend on every fifth anniversary of the date of issuance of the Series J Preference Shares.
4 The quarterly dividend amount of Series L was increased to US$0.30993 from US$0.25000 on September 1, 2017, due to the
reset of the annual dividend on every fifth anniversary of the date of issuance of the Series L Preference Shares.
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87
8 On December 11, 2017, 20 million Series 19 Preferred Shares, inclusive of 4 million Series 19 Preferred Shares issued on full
exercise of the underwriters' option, were issued for gross proceeds of $500 million.
9 For dividends declared, see Liquidity and Capital Resources – Sources and Uses of Cash – Dividend Reinvestment and Share
Purchase Plan.
Common Share Issuances
On December 7, 2017, we completed the issuance of 33.5 million common shares for gross proceeds of
approximately $1.5 billion. The proceeds were used to reduce short-term indebtedness pending
reinvestment in secured capital projects.
On February 27, 2017, we completed the issuance of 691 million common shares with a value of $37.4
billion in exchange for shares of Spectra Energy in connection with the Merger Transaction. For further
information, see Merger with Spectra Energy and Item 8. Financial Statements and Supplementary Data -
Note 7. Acquisitions and Dispositions.
On March 1, 2016, we completed the issuance of 56.5 million common shares for gross proceeds of
approximately $2.3 billion, inclusive of the shares issued on exercise of the full amount of the
underwriters’ over-allotment option to purchase an additional 7.4 million common shares. The proceeds
were used to reduce short-term indebtedness pending reinvestment in secured capital projects.
Dividend Reinvestment and Share Purchase Plan
Participants in our Dividend Reinvestment and Share Purchase Plan (DRIP) receive a 2% discount on the
purchase of common shares with reinvested dividends. For the years ended December 31, 2017 and
2016, total dividends paid were $3,562 million and $1,945 million, respectively, of which $2,336 million
and $1,150 million, respectively, were paid in cash and reflected in financing activities. The remaining
$1,226 million and $795 million, respectively, of dividends paid were reinvested pursuant to the DRIP and
resulted in the issuance of common shares rather than a cash payment. For the years ended
December 31, 2017 and 2016, 34.4% and 40.9%, respectively, of total dividends paid were reinvested
through the DRIP. In addition to amounts paid in cash and reflected in financing activities for the year
ended December 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders prior
to the Merger Transaction that were paid after the Merger Transaction.
Our Board of Directors has declared the following quarterly dividends. All dividends are payable on
March 1, 2018 to shareholders of record on February 15, 2018.
Common Shares
Preference Shares, Series A
Preference Shares, Series B1
Preference Shares, Series C2
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J3
Preference Shares, Series L4
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
Preference Shares, Series 9
Preference Shares, Series 11
Preference Shares, Series 13
Preference Shares, Series 15
Preference Shares, Series 17
Preference Shares, Series 19
1 The quarterly dividend amount of Series B was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the
$0.67100
$0.34375
$0.21340
$0.20342
$0.25000
$0.25000
$0.25000
US$0.30540
US$0.30993
$0.25000
$0.25000
$0.25000
US$0.25000
$0.25000
US$0.27500
$0.27500
$0.27500
$0.27500
$0.27500
$0.27500
$0.32188
$0.26850
annual dividend on every fifth anniversary of the date of issuance of the Series B Preference Shares.
2 The quarterly dividend amount of Series C was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342
on December 1, 2017, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
3 The quarterly dividend amount of Series J was increased to US$0.30540 from US$0.25000 on June 1, 2017, due to the reset of
the annual dividend on every fifth anniversary of the date of issuance of the Series J Preference Shares.
4 The quarterly dividend amount of Series L was increased to US$0.30993 from US$0.25000 on September 1, 2017, due to the
reset of the annual dividend on every fifth anniversary of the date of issuance of the Series L Preference Shares.
86
87
SPONSORED VEHICLES
We utilize Sponsored Vehicles to diversify our access to capital and enhance our costs of funds. When
market conditions are supportive, we may also seek to raise capital and monetize the value of existing
assets through drop-down transactions with our Sponsored Vehicles.
SEP
The Fund Group
Economic interest as at December 31,
Distributions received by us for the year ended
December 31,
2017
82.5%
2016
86.9%
2015
89.2%
$1,539 million
$1,555 million
$601 million
Common Unit Issuance
On December 7, 2017, ENF completed the issuance of 20,683,900 common shares, inclusive of
2,697,900 common shares issued on full exercise of the underwriters' over-allotment option, at a price of
$27.80 for a gross proceeds of $575 million. The proceeds will be used to repay short-term indebtedness
and fund growth projects associated with the Fund's Canadian liquids pipeline assets.
On April 18, 2017, ENF completed the Secondary Offering of 17,347,750 common shares to the public at
a price of $33.15 per share, for gross proceeds of approximately $575 million. For further information,
refer to Asset Monetization.
Restructuring
In September 2015, we completed the Canadian Restructuring Plan. For further details, refer to Canadian
Restructuring Plan.
EEP
Economic interest as at December 31,
Distributions received by us for the year ended
December 31,1
2017
34.6%
2016
35.3%
2015
35.7%
US$713 million US$573 million US$499 million
1 Includes distributions for our ownership interest in EEP and distributions from direct ownership in its jointly funded projects.
Strategic Review
In 2017, we continued the ongoing evaluation of our investment in EEP. For additional information, refer
to United States Sponsored Vehicle Strategy.
Common Unit Issuance
In March 2015, EEP completed the issuance of eight million Class A common units for gross proceeds of
approximately US$294 million before underwriting discounts and commissions and offering expenses. We
did not participate in the issuance; however, we made a capital contribution of US$6 million to maintain
our 2% general partner interest in EEP. EEP used the proceeds from the offering to fund a portion of its
capital expansion projects and for general partnership purposes.
Alberta Clipper Drop Down
In January 2015, we completed the drop down of our 66.7% interest in the United States segment of the
Alberta Clipper Pipeline to EEP. Aggregate consideration for the transaction was US$1 billion, consisting
of approximately US$694 million of Class E equity units issued to us by EEP and the repayment of
approximately US$306 million of indebtedness owed to us.
Economic interest as at December 31,
Distributions received by us for the year ended
December 31,
2017
83%
US$738 million
2016
—
—
2015
—
—
The Merger Transaction
As a result of the Merger Transaction, we acquired a 75% economic interest in SEP. For further
information, refer to Merger with Spectra Energy.
Share Issuances
During the year ended December 31, 2017, SEP issued 3,991,977 million common units under its at-the-
market program for total proceeds of US$171 million.
Restructuring of Incentive Distribution Rights
Refer to United States Sponsored Vehicle Strategy - Restructuring of SEP Incentive Distribution Rights.
OFF-BALANCE SHEET ARRANGEMENTS
We enter into guarantee arrangements in the normal course of business to facilitate commercial
transactions with third parties. These arrangements include financial guarantees, stand-by letters of
credit, debt guarantees, surety bonds and indemnifications. See Item 8. Financial Statements and
supplementary data - Note 29. Guarantees for further discussion of guarantee arrangements.
Most of the guarantee arrangements that we enter into enhance the credit standings of certain
subsidiaries, non-consolidated entities or less than 100%-owned entities, enabling them to conduct
business. As such, these guarantee arrangements involve elements of performance and credit risk which
are not included on our Consolidated Statements of Financial Position. The possibility of us having to
honor our contingencies is largely dependent upon the future operations of our subsidiaries, investees
and other third parties, or the occurrence of certain future events. Issuance of these guarantee
arrangements is not required for the majority of our operations.
We do not have material off-balance sheet financing entities or structures, except for normal operating
lease arrangements, guarantee arrangements and financings entered into by our equity investments. For
additional information on these commitments, see Item 8. Financial Statements and supplementary data -
Note 28. Commitments and Contingencies and Note 29. Guarantees.
We do not have material off-balance sheet arrangements that have or are reasonably likely to have a
current or future effect on our financial condition, changes in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or capital resources.
88
89
SPONSORED VEHICLES
We utilize Sponsored Vehicles to diversify our access to capital and enhance our costs of funds. When
market conditions are supportive, we may also seek to raise capital and monetize the value of existing
assets through drop-down transactions with our Sponsored Vehicles.
The Fund Group
Economic interest as at December 31,
Distributions received by us for the year ended
December 31,
2017
82.5%
2016
86.9%
2015
89.2%
$1,539 million
$1,555 million
$601 million
Common Unit Issuance
On December 7, 2017, ENF completed the issuance of 20,683,900 common shares, inclusive of
2,697,900 common shares issued on full exercise of the underwriters' over-allotment option, at a price of
$27.80 for a gross proceeds of $575 million. The proceeds will be used to repay short-term indebtedness
and fund growth projects associated with the Fund's Canadian liquids pipeline assets.
On April 18, 2017, ENF completed the Secondary Offering of 17,347,750 common shares to the public at
a price of $33.15 per share, for gross proceeds of approximately $575 million. For further information,
In September 2015, we completed the Canadian Restructuring Plan. For further details, refer to Canadian
refer to Asset Monetization.
Restructuring
Restructuring Plan.
EEP
Economic interest as at December 31,
Distributions received by us for the year ended
December 31,1
2017
34.6%
2016
35.3%
2015
35.7%
US$713 million US$573 million US$499 million
1 Includes distributions for our ownership interest in EEP and distributions from direct ownership in its jointly funded projects.
In 2017, we continued the ongoing evaluation of our investment in EEP. For additional information, refer
to United States Sponsored Vehicle Strategy.
Strategic Review
Common Unit Issuance
In March 2015, EEP completed the issuance of eight million Class A common units for gross proceeds of
approximately US$294 million before underwriting discounts and commissions and offering expenses. We
did not participate in the issuance; however, we made a capital contribution of US$6 million to maintain
our 2% general partner interest in EEP. EEP used the proceeds from the offering to fund a portion of its
capital expansion projects and for general partnership purposes.
Alberta Clipper Drop Down
In January 2015, we completed the drop down of our 66.7% interest in the United States segment of the
Alberta Clipper Pipeline to EEP. Aggregate consideration for the transaction was US$1 billion, consisting
of approximately US$694 million of Class E equity units issued to us by EEP and the repayment of
approximately US$306 million of indebtedness owed to us.
SEP
Economic interest as at December 31,
Distributions received by us for the year ended
December 31,
2017
83%
US$738 million
2016
—
—
2015
—
—
The Merger Transaction
As a result of the Merger Transaction, we acquired a 75% economic interest in SEP. For further
information, refer to Merger with Spectra Energy.
Share Issuances
During the year ended December 31, 2017, SEP issued 3,991,977 million common units under its at-the-
market program for total proceeds of US$171 million.
Restructuring of Incentive Distribution Rights
Refer to United States Sponsored Vehicle Strategy - Restructuring of SEP Incentive Distribution Rights.
OFF-BALANCE SHEET ARRANGEMENTS
We enter into guarantee arrangements in the normal course of business to facilitate commercial
transactions with third parties. These arrangements include financial guarantees, stand-by letters of
credit, debt guarantees, surety bonds and indemnifications. See Item 8. Financial Statements and
supplementary data - Note 29. Guarantees for further discussion of guarantee arrangements.
Most of the guarantee arrangements that we enter into enhance the credit standings of certain
subsidiaries, non-consolidated entities or less than 100%-owned entities, enabling them to conduct
business. As such, these guarantee arrangements involve elements of performance and credit risk which
are not included on our Consolidated Statements of Financial Position. The possibility of us having to
honor our contingencies is largely dependent upon the future operations of our subsidiaries, investees
and other third parties, or the occurrence of certain future events. Issuance of these guarantee
arrangements is not required for the majority of our operations.
We do not have material off-balance sheet financing entities or structures, except for normal operating
lease arrangements, guarantee arrangements and financings entered into by our equity investments. For
additional information on these commitments, see Item 8. Financial Statements and supplementary data -
Note 28. Commitments and Contingencies and Note 29. Guarantees.
We do not have material off-balance sheet arrangements that have or are reasonably likely to have a
current or future effect on our financial condition, changes in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or capital resources.
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89
CONTRACTUAL OBLIGATIONS
Payments due under contractual obligations over the next five years and thereafter are as follows:
October 12, 2017 Eddystone Rail moved to dismiss the latest version of defendants’ counterclaims. The
defendants’ chances of success on their counterclaims cannot be predicted at this time.
Less than
After
5 years
Total
1 year 1-3 years 3-5 years
As at December 31, 2017
(millions of Canadian dollars)
Annual debt maturities1,2
Interest obligations2,3
Operating leases4
Capital leases
Pension obligations5
Long-term contracts6
Other long-term liabilities7
Total contractual obligations
1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes
short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt
facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments
could be materially different than presented above.
62,927
42,083
1,151
35
162
14,718
—
121,076
12,995
4,415
198
10
—
4,000
—
21,618
11,344
3,794
184
4
—
2,448
—
17,774
2,831
2,485
106
9
162
4,182
—
9,775
35,757
31,389
663
12
—
4,088
—
71,909
2 Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017.
3 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.
4 Includes land leases.
5 Assumes only required payments will be made into the pension plans in 2018. Contributions are made in accordance with
independent actuarial valuations as at December 31, 2017. Contributions, including discretionary payments, may vary pending
future benefit design and asset performance.
6 Included within long-term contracts, in the table, above are contracts that we have signed for the purchase of services, pipe and
other materials totaling $2,609 million which are expected to be paid over the next five years. Also consists of the following
purchase obligations: gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments
(Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP).
7 We are unable to estimate deferred income taxes (Item 8. Financial Statements and supplementary data - Note 24. Income
Taxes) since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. We are
also unable to estimate asset retirement obligations (Item 8. Financial Statements and supplementary data - Note 18. Asset
Retirement Obligations), environmental liabilities (Item 8. Financial Statements and supplementary data - Note 28. Commitments
and Contingencies) and hedges payable (Item 8. Financial Statements and supplementary data - Note 23. Risk Management and
Financial Instruments) due to the uncertainty as to the amount and, or, timing of when cash payments will be required.
LEGAL AND OTHER UPDATES
LIQUIDS PIPELINES
Renewal of Line 5 Easement
On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians
(the Band) issued a press release indicating that the Band had passed a resolution not to renew its
interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within our
mainline system. The Band’s resolution calls for decommissioning and removal of the pipeline from all
Bad River tribal lands and watershed and could impact our ability to operate the pipeline on the
Reservation. Since the Band passed the resolution, the parties have agreed to ongoing discussions with
the objective of understanding and resolving the Band’s concerns on a long-term basis.
Eddystone Rail Legal Matter
In February 2017, Eddystone Rail filed an action against several defendants in the United States District
Court for the Eastern District of Pennsylvania. Eddystone Rail alleges that the defendants transferred
valuable assets from Eddystone Rail’s counterparty in a maritime contract, so as to avoid outstanding
obligations to Eddystone Rail. Eddystone Rail is seeking payment of compensatory and punitive damages
in excess of US$140 million. Eddystone Rail’s chances of success in connection with the above noted
action cannot be predicted and it is possible that Eddystone Rail may not recover any of the amounts
sought. On July 19, 2017, the defendants’ motions to dismiss Eddystone Rail’s claims were denied.
Defendants have filed Answers and Counterclaims, which together with subsequent amendments, seek
damages from Eddystone Rail in excess of US$32 million. Eddystone filed a motion to dismiss the
counterclaims and defendants amended their Answer and Counterclaims on September 21, 2017. On
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91
Dakota Access Pipeline
As noted previously under United States Sponsored Vehicle Strategy - Finalization of Bakken Pipeline
System Joint Funding Agreement, our investment in the Bakken Pipeline System is inclusive of the
Dakota Access Pipeline. In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux
Tribe (the Tribes) filed motions with the United States District Court for the District of Columbia (the Court)
contesting the validity of the process used by the United States Army Corps of Engineers (Army Corps) to
permit the Dakota Access Pipeline. The plaintiffs requested the Court order the operator to shut down the
pipeline until the appropriate regulatory process is completed.
On June 14, 2017, the Court ruled that the Army Corps did not sufficiently weigh the degree to which the
project's effects would be highly controversial, and the Army Corps failed to adequately consider the
impact of an oil spill on the hunting and fishing rights of the Tribes and on environmental justice. The
Court ordered the Army Corps to reconsider those components of its environmental analysis. On October
11, 2017, the Court issued an order that allows the Dakota Access Pipeline to continue operating while
the Army Corps completes the additional environmental review required by the Court's June 14, 2017
order and the Court ordered the Dakota Access Pipeline to implement certain interim measures pending
the Army Corps' supplemental analysis.
Lakehead System Lines 6A and 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. Further, on September 9, 2010, a release of crude oil from Line 6A of EEP’s
Lakehead System was reported in an industrial area of Romeoville, Illinois.
As at December 31, 2017, EEP’s cumulative cost estimate for the Line 6B crude oil release remains at
US$1.2 billion ($195 million after-tax attributable to us) including those costs that were considered
probable and that could be reasonably estimated at December 31, 2017. As at December 31, 2017,
EEP's remaining estimated liability is approximately US$62 million.
Insurance Recoveries
EEP is included in the comprehensive insurance program that is maintained by us for our subsidiaries
and affiliates. As at December 31, 2017, EEP has recorded total insurance recoveries of US$547 million
($80 million after-tax attributable to us) for the Line 6B crude oil release out of the US$650 million
applicable limit. Of the remaining US$103 million coverage limit, US$85 million was the subject matter of
a lawsuit against one particular insurer. In March 2015, we reached an agreement with that insurer to
submit the US$85 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a
decision that was not favorable to us. As a result, EEP will not receive any additional insurance recoveries
in connection with the Line 6B crude oil release.
Legal and Regulatory Proceedings
A number of United States governmental agencies and regulators initiated investigations into the Line 6B
crude oil release. As at December 31, 2017, there are no claims pending against us, EEP or their affiliates
in United States state courts in connection with the Line 6B crude oil release.
We have accrued a provision for future legal costs and probable losses associated with the Line 6B crude
oil release as described above.
Line 6B Fines and Penalties
discussed below.
As at December 31, 2017, EEP’s total estimated costs related to the Line 6B crude oil release include US
$69 million in previously paid fines and penalties, which includes fines and penalties paid to the DOJ as
CONTRACTUAL OBLIGATIONS
Payments due under contractual obligations over the next five years and thereafter are as follows:
October 12, 2017 Eddystone Rail moved to dismiss the latest version of defendants’ counterclaims. The
defendants’ chances of success on their counterclaims cannot be predicted at this time.
As at December 31, 2017
(millions of Canadian dollars)
Annual debt maturities1,2
Interest obligations2,3
Operating leases4
Capital leases
Pension obligations5
Long-term contracts6
Other long-term liabilities7
Total contractual obligations
Less than
Total
1 year 1-3 years 3-5 years
62,927
42,083
1,151
35
162
14,718
—
121,076
2,831
2,485
106
9
162
4,182
—
9,775
12,995
4,415
198
10
—
4,000
—
21,618
11,344
3,794
184
4
—
—
2,448
17,774
After
5 years
35,757
31,389
663
12
—
4,088
—
71,909
1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes
short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt
facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments
could be materially different than presented above.
2 Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017.
3 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.
4 Includes land leases.
5 Assumes only required payments will be made into the pension plans in 2018. Contributions are made in accordance with
independent actuarial valuations as at December 31, 2017. Contributions, including discretionary payments, may vary pending
future benefit design and asset performance.
6 Included within long-term contracts, in the table, above are contracts that we have signed for the purchase of services, pipe and
other materials totaling $2,609 million which are expected to be paid over the next five years. Also consists of the following
purchase obligations: gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments
(Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP).
7 We are unable to estimate deferred income taxes (Item 8. Financial Statements and supplementary data - Note 24. Income
Taxes) since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. We are
also unable to estimate asset retirement obligations (Item 8. Financial Statements and supplementary data - Note 18. Asset
Retirement Obligations), environmental liabilities (Item 8. Financial Statements and supplementary data - Note 28. Commitments
and Contingencies) and hedges payable (Item 8. Financial Statements and supplementary data - Note 23. Risk Management and
Financial Instruments) due to the uncertainty as to the amount and, or, timing of when cash payments will be required.
LEGAL AND OTHER UPDATES
LIQUIDS PIPELINES
Renewal of Line 5 Easement
On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians
(the Band) issued a press release indicating that the Band had passed a resolution not to renew its
interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within our
mainline system. The Band’s resolution calls for decommissioning and removal of the pipeline from all
Bad River tribal lands and watershed and could impact our ability to operate the pipeline on the
Reservation. Since the Band passed the resolution, the parties have agreed to ongoing discussions with
the objective of understanding and resolving the Band’s concerns on a long-term basis.
Eddystone Rail Legal Matter
In February 2017, Eddystone Rail filed an action against several defendants in the United States District
Court for the Eastern District of Pennsylvania. Eddystone Rail alleges that the defendants transferred
valuable assets from Eddystone Rail’s counterparty in a maritime contract, so as to avoid outstanding
obligations to Eddystone Rail. Eddystone Rail is seeking payment of compensatory and punitive damages
in excess of US$140 million. Eddystone Rail’s chances of success in connection with the above noted
action cannot be predicted and it is possible that Eddystone Rail may not recover any of the amounts
sought. On July 19, 2017, the defendants’ motions to dismiss Eddystone Rail’s claims were denied.
Defendants have filed Answers and Counterclaims, which together with subsequent amendments, seek
damages from Eddystone Rail in excess of US$32 million. Eddystone filed a motion to dismiss the
counterclaims and defendants amended their Answer and Counterclaims on September 21, 2017. On
Dakota Access Pipeline
As noted previously under United States Sponsored Vehicle Strategy - Finalization of Bakken Pipeline
System Joint Funding Agreement, our investment in the Bakken Pipeline System is inclusive of the
Dakota Access Pipeline. In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux
Tribe (the Tribes) filed motions with the United States District Court for the District of Columbia (the Court)
contesting the validity of the process used by the United States Army Corps of Engineers (Army Corps) to
permit the Dakota Access Pipeline. The plaintiffs requested the Court order the operator to shut down the
pipeline until the appropriate regulatory process is completed.
On June 14, 2017, the Court ruled that the Army Corps did not sufficiently weigh the degree to which the
project's effects would be highly controversial, and the Army Corps failed to adequately consider the
impact of an oil spill on the hunting and fishing rights of the Tribes and on environmental justice. The
Court ordered the Army Corps to reconsider those components of its environmental analysis. On October
11, 2017, the Court issued an order that allows the Dakota Access Pipeline to continue operating while
the Army Corps completes the additional environmental review required by the Court's June 14, 2017
order and the Court ordered the Dakota Access Pipeline to implement certain interim measures pending
the Army Corps' supplemental analysis.
Lakehead System Lines 6A and 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. Further, on September 9, 2010, a release of crude oil from Line 6A of EEP’s
Lakehead System was reported in an industrial area of Romeoville, Illinois.
As at December 31, 2017, EEP’s cumulative cost estimate for the Line 6B crude oil release remains at
US$1.2 billion ($195 million after-tax attributable to us) including those costs that were considered
probable and that could be reasonably estimated at December 31, 2017. As at December 31, 2017,
EEP's remaining estimated liability is approximately US$62 million.
Insurance Recoveries
EEP is included in the comprehensive insurance program that is maintained by us for our subsidiaries
and affiliates. As at December 31, 2017, EEP has recorded total insurance recoveries of US$547 million
($80 million after-tax attributable to us) for the Line 6B crude oil release out of the US$650 million
applicable limit. Of the remaining US$103 million coverage limit, US$85 million was the subject matter of
a lawsuit against one particular insurer. In March 2015, we reached an agreement with that insurer to
submit the US$85 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a
decision that was not favorable to us. As a result, EEP will not receive any additional insurance recoveries
in connection with the Line 6B crude oil release.
Legal and Regulatory Proceedings
A number of United States governmental agencies and regulators initiated investigations into the Line 6B
crude oil release. As at December 31, 2017, there are no claims pending against us, EEP or their affiliates
in United States state courts in connection with the Line 6B crude oil release.
We have accrued a provision for future legal costs and probable losses associated with the Line 6B crude
oil release as described above.
Line 6B Fines and Penalties
As at December 31, 2017, EEP’s total estimated costs related to the Line 6B crude oil release include US
$69 million in previously paid fines and penalties, which includes fines and penalties paid to the DOJ as
discussed below.
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91
Consent Decree
On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division,
approved EEP’s signed settlement agreement with the United States Environmental Protection Agency
and the DOJ regarding the Lines 6A and 6B crude oil releases (the Consent Decree). On June 15, 2017,
we made a total payment of US$68 million as required by the Consent Decree, which reflects US$61
million for the civil penalty for the Line 6B release, US$1 million for the Line 6A release, and US$6 million
for past removal costs and interest.
Seaway Pipeline Regulatory Matters
Seaway Crude Pipeline System (Seaway Pipeline) filed an application for market-based rates in
December 2011 and refiled in December 2014. Several parties filed comments in opposition alleging that
the application should be denied because Seaway Pipeline has market power in both its receipt and
destination markets. On December 1, 2016, the Administrative Law Judge issued its decision which
concluded that the Commission should grant the application of Seaway Pipeline for authority to charge
market-based rates. The parties filed briefs during the first quarter of 2017 to defend the Administrative
Law Judge's decision and to respond to criticisms of that decision. The Commissioners will now review
the entire record and issue a decision. There is no timeline for the FERC to act and issue a decision.
GAS TRANSMISSION AND MIDSTREAM
Aux Sable Environmental Protection Agency Matter
On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to a NGL supply
agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While
the final outcome of this action cannot be predicted with certainty, at this time management believes that
the ultimate resolution of this action will not have a material impact on our consolidated financial position
or results of operations.
Sabal Trail FERC Certificate Review
Sierra Club and two other non-governmental organizations filed a Petition for Review of Sabal Trail’s
FERC certificate on September 20, 2016 in the D.C. Circuit Court of Appeals. On August 22, 2017, the
D.C. Circuit issued an opinion denying one of the petitions, and granting the other petition in part,
vacating the certificates, and remanding the case to FERC to supplement the environmental impact
statement for the project to estimate the quantity of green-house gases to be released into the
environment by the gas-fired generation plants in Florida that will consume the gas transported by Sabal
Trail. The court withheld issuance of the mandate requiring vacatur of the certificate until seven days after
the disposition of any timely petition for rehearing. On October 6, 2017, Sabal Trail and FERC each filed
timely petitions for rehearing. On January 31, 2018, the court denied FERC’s and Sabal Trail’s petitions
for rehearing. Absent a stay, the court’s mandate could have issued on February 7, 2018. However, on
February 2, 2018, Sabal Trail filed with FERC a request for expedited issuance of its order on remand or,
alternatively, temporary emergency certificates to permit continued operation of the pipeline absent a stay
of the court’s mandate. On February 5, 2018, FERC issued its final supplemental environmental impact
statement in compliance with the D.C. Circuit decision. In addition, on February 6, 2018, FERC filed a
motion with the court requesting a 45-day stay of the mandate, and stated in its motion that it intends to
issue the order on remand within 45 days. Sabal Trail filed a motion with the court requesting a 90-day
stay of the mandate. The February 6, 2018 motions automatically stay the issuance of the court’s
mandate until the later of seven days after the court denies the motions or the expiration of any stay
granted by the court. Both motions are pending.
TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in
our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
OTHER LITIGATION
We and our 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 our consolidated financial position or results of
operations.
CRITICAL ACCOUNTING ESTIMATES
Our consolidated financial statements are prepared in accordance with accounting principles generally
accepted in the United States, which require management to make estimates, judgments and
assumptions that affect the amounts reported in our consolidated financial statements and accompanying
notes. In making judgments and estimates, management relies on external information and observable
conditions, where possible, supplemented by internal analysis as required. We believe our most critical
accounting policies and estimates discussed below have an impact across the various segments of our
business.
Business Combinations
We apply the provisions of Accounting Standards Codification 805 Business Combinations in accounting
for our acquisitions. The acquired long-lived assets and intangible assets and assumed liabilities are
recorded at their estimated fair values at the date of acquisition. Goodwill represents the excess of the
purchase price over the fair value of net assets. While we use our best estimates and assumptions to
accurately value assets acquired and liabilities assumed at the date of acquisition, as well as any
contingent consideration, our estimates are inherently uncertain and subject to refinement. During the
measurement period, which may be up to one year from the acquisition date, we record adjustments to
the assets acquired and liabilities assumed with the corresponding offset to goodwill. Upon the conclusion
of the measurement period or final determination of values of assets acquired or liabilities assumed,
whichever comes first, any subsequent adjustments are recorded to our consolidated statements of
operations.
Accounting for business combinations requires significant judgment, estimates and assumptions at the
acquisition date. In developing estimates of fair values at the acquisition date, we utilize a variety of
factors including market data, historical and future expected cash flows, growth rates and discount rates.
The subjective nature of our assumptions increases the risk associated with estimates surrounding the
projected performance of the acquired entity.
On February 27, 2017, we acquired Spectra Energy for a purchase price of $37.5 billion. In determining
the valuation of tangible assets acquired, we applied the cost, market and income approaches. For
intangible assets acquired, we used an income approach which included cash flow projections based on
historical performance, terms found in contracts and assumptions on expected renewals. Discount rates
used in the valuation were also developed using a weighted-average cost of capital based on risks
specific to respective assets and returns that an investor would likely require given the expected cash
flows, timing and risk.
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Consent Decree
On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division,
approved EEP’s signed settlement agreement with the United States Environmental Protection Agency
and the DOJ regarding the Lines 6A and 6B crude oil releases (the Consent Decree). On June 15, 2017,
we made a total payment of US$68 million as required by the Consent Decree, which reflects US$61
million for the civil penalty for the Line 6B release, US$1 million for the Line 6A release, and US$6 million
for past removal costs and interest.
Seaway Pipeline Regulatory Matters
Seaway Crude Pipeline System (Seaway Pipeline) filed an application for market-based rates in
December 2011 and refiled in December 2014. Several parties filed comments in opposition alleging that
the application should be denied because Seaway Pipeline has market power in both its receipt and
destination markets. On December 1, 2016, the Administrative Law Judge issued its decision which
concluded that the Commission should grant the application of Seaway Pipeline for authority to charge
market-based rates. The parties filed briefs during the first quarter of 2017 to defend the Administrative
Law Judge's decision and to respond to criticisms of that decision. The Commissioners will now review
the entire record and issue a decision. There is no timeline for the FERC to act and issue a decision.
GAS TRANSMISSION AND MIDSTREAM
Aux Sable Environmental Protection Agency Matter
On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to a NGL supply
agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While
the final outcome of this action cannot be predicted with certainty, at this time management believes that
the ultimate resolution of this action will not have a material impact on our consolidated financial position
or results of operations.
Sabal Trail FERC Certificate Review
Sierra Club and two other non-governmental organizations filed a Petition for Review of Sabal Trail’s
FERC certificate on September 20, 2016 in the D.C. Circuit Court of Appeals. On August 22, 2017, the
D.C. Circuit issued an opinion denying one of the petitions, and granting the other petition in part,
vacating the certificates, and remanding the case to FERC to supplement the environmental impact
statement for the project to estimate the quantity of green-house gases to be released into the
environment by the gas-fired generation plants in Florida that will consume the gas transported by Sabal
Trail. The court withheld issuance of the mandate requiring vacatur of the certificate until seven days after
the disposition of any timely petition for rehearing. On October 6, 2017, Sabal Trail and FERC each filed
timely petitions for rehearing. On January 31, 2018, the court denied FERC’s and Sabal Trail’s petitions
for rehearing. Absent a stay, the court’s mandate could have issued on February 7, 2018. However, on
February 2, 2018, Sabal Trail filed with FERC a request for expedited issuance of its order on remand or,
alternatively, temporary emergency certificates to permit continued operation of the pipeline absent a stay
of the court’s mandate. On February 5, 2018, FERC issued its final supplemental environmental impact
statement in compliance with the D.C. Circuit decision. In addition, on February 6, 2018, FERC filed a
motion with the court requesting a 45-day stay of the mandate, and stated in its motion that it intends to
issue the order on remand within 45 days. Sabal Trail filed a motion with the court requesting a 90-day
stay of the mandate. The February 6, 2018 motions automatically stay the issuance of the court’s
mandate until the later of seven days after the court denies the motions or the expiration of any stay
granted by the court. Both motions are pending.
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in
our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
TAX MATTERS
OTHER LITIGATION
We and our 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 our consolidated financial position or results of
operations.
CRITICAL ACCOUNTING ESTIMATES
Our consolidated financial statements are prepared in accordance with accounting principles generally
accepted in the United States, which require management to make estimates, judgments and
assumptions that affect the amounts reported in our consolidated financial statements and accompanying
notes. In making judgments and estimates, management relies on external information and observable
conditions, where possible, supplemented by internal analysis as required. We believe our most critical
accounting policies and estimates discussed below have an impact across the various segments of our
business.
Business Combinations
We apply the provisions of Accounting Standards Codification 805 Business Combinations in accounting
for our acquisitions. The acquired long-lived assets and intangible assets and assumed liabilities are
recorded at their estimated fair values at the date of acquisition. Goodwill represents the excess of the
purchase price over the fair value of net assets. While we use our best estimates and assumptions to
accurately value assets acquired and liabilities assumed at the date of acquisition, as well as any
contingent consideration, our estimates are inherently uncertain and subject to refinement. During the
measurement period, which may be up to one year from the acquisition date, we record adjustments to
the assets acquired and liabilities assumed with the corresponding offset to goodwill. Upon the conclusion
of the measurement period or final determination of values of assets acquired or liabilities assumed,
whichever comes first, any subsequent adjustments are recorded to our consolidated statements of
operations.
Accounting for business combinations requires significant judgment, estimates and assumptions at the
acquisition date. In developing estimates of fair values at the acquisition date, we utilize a variety of
factors including market data, historical and future expected cash flows, growth rates and discount rates.
The subjective nature of our assumptions increases the risk associated with estimates surrounding the
projected performance of the acquired entity.
On February 27, 2017, we acquired Spectra Energy for a purchase price of $37.5 billion. In determining
the valuation of tangible assets acquired, we applied the cost, market and income approaches. For
intangible assets acquired, we used an income approach which included cash flow projections based on
historical performance, terms found in contracts and assumptions on expected renewals. Discount rates
used in the valuation were also developed using a weighted-average cost of capital based on risks
specific to respective assets and returns that an investor would likely require given the expected cash
flows, timing and risk.
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Goodwill Impairment
We assess our goodwill for impairment at least annually unless events or changes in circumstances
indicate that it is more likely than not that the fair value of a reporting unit is below its carrying value. For
the purposes of impairment testing, reporting units are identified as business operations within an
operating segment. We have the option to first assess qualitative factors to determine whether it is
necessary to perform the quantitative goodwill impairment test. If the quantitative goodwill impairment test
is performed, we determine the fair value of our reporting units inclusive of goodwill and compare 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 at the amount by which the
reporting unit’s carrying value exceeds its fair value.
We also apply significant judgement when identifying the composition of disposal groups and determining
which disposal groups meet the definition of a business. If the composition of disposal groups were to
change as a result of a change in our marketing plans or a new agreement with a buyer, this could create
a difference in the amount of goodwill allocated to assets held for sale. During 2017, we impaired $102
million of goodwill allocated to assets held for sale.
For the year ended December 31, 2017, we elected to perform a qualitative assessment to test the
goodwill acquired from the acquisition of Spectra Energy for impairment. We assessed macroeconomic
conditions, industry and market considerations, cost factors and overall financial performance to
determine whether it is more likely than not that the fair value of each of our reporting units is less than its
carrying amount. Other than as discussed above, our goodwill impairment analysis performed as at
December 31, 2017, did not result in an impairment charge.
Effective in the quarter ended December 31, 2017, we have elected to move the annual review of the
goodwill balance from October 1 to April 1 to better align with the preparation and review of our business
plan, which is used in the test. The change does not delay, accelerate or avoid an impairment charge.
Asset Impairment
We evaluate the recoverability of our property, plant and equipment when events or circumstances such
as economic obsolescence, business climate, legal or regulatory changes, or other factors indicate we
may not recover the carrying amount of our assets. We continually monitor our businesses, the market
and business environments to identify indicators that could suggest an asset may not be recoverable. If it
is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the
asset, we will assess the fair value of the asset. 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
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.
Assets held for sale
We classify assets as held for sale when management commits to a formal plan to actively market an
asset or a group of assets and when management believes it is probable the sale of the assets will occur
within one year. We measure assets classified as held for sale at the lower of their carrying value and
their estimated fair value less costs to sell.
We are in the process of selling certain midstream assets within our gas transmission and midstream
segment. Given the state of the divestiture plan for these assets, as at December 31, 2017, we classified
them as held for sale and measured them at the lower of their carrying value and fair value less costs to
sell, which resulted in a loss of $4.4 billion ($2.8 billion after-tax). We determined the fair value of these
assets held for sale using present value techniques which required us to make projections and
assumptions regarding future cash flows, discount rates, inflation rates and growth rates, which were
impacted by prolonged decline in commodity prices and deteriorating business performance. These
projections and assumptions are subject to uncertainty and could be negatively impacted by changes in
market conditions, asset performance, legal environment, and other factors.
Regulatory Accounting
Certain of our businesses are subject to regulation by various authorities, including but not limited to, the
NEB, the FERC, the Alberta Energy Regulator, the New Brunswick Energy and Utilities Board, La Régie
de l’Energie du Québec 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. Key determinants in the ratemaking process are:
• Costs of providing service, including depreciation expense;
• Allowed rate of return, including the equity component of the capital structure and related income
taxes; and
• Contract and volume throughput assumptions.
The allowed rate of return is determined in accordance with the applicable regulatory model and may
impact our profitability. The rates for a number of our projects are based on a cost-of-service recovery
model that follows the regulators’ authoritative guidance. Under the cost-of-service tolling methodology,
we calculate tolls based on forecast volumes and cost. A difference between forecast and actual results
causes an over or under recovery in any given year. 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 or expected to be
paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative
(LMCI).
To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery
or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate
regulation, we 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.
As at December 31, 2017 and 2016, our regulatory assets totaled $3,477 million and $1,865 million,
respectively, and significant regulatory liabilities totaled $2,366 million and $844 million, respectively.
Depreciation
Depreciation of property, plant and equipment, our largest asset with a net book value at December 31,
2017 and 2016, of $90,711 million and $64,284 million, respectively, is charged in accordance with two
primary methods. 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 is followed
whereby similar assets are grouped and depreciated as a pool. When group assets are retired or
otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to
accumulated depreciation.
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 our assets including the level of development,
exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by
our pipelines as well as the demand for crude oil and natural gas and the integrity of our 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 our business segments. For
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Goodwill Impairment
We assess our goodwill for impairment at least annually unless events or changes in circumstances
indicate that it is more likely than not that the fair value of a reporting unit is below its carrying value. For
the purposes of impairment testing, reporting units are identified as business operations within an
operating segment. We have the option to first assess qualitative factors to determine whether it is
necessary to perform the quantitative goodwill impairment test. If the quantitative goodwill impairment test
is performed, we determine the fair value of our reporting units inclusive of goodwill and compare 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 at the amount by which the
reporting unit’s carrying value exceeds its fair value.
We also apply significant judgement when identifying the composition of disposal groups and determining
which disposal groups meet the definition of a business. If the composition of disposal groups were to
change as a result of a change in our marketing plans or a new agreement with a buyer, this could create
a difference in the amount of goodwill allocated to assets held for sale. During 2017, we impaired $102
million of goodwill allocated to assets held for sale.
For the year ended December 31, 2017, we elected to perform a qualitative assessment to test the
goodwill acquired from the acquisition of Spectra Energy for impairment. We assessed macroeconomic
conditions, industry and market considerations, cost factors and overall financial performance to
determine whether it is more likely than not that the fair value of each of our reporting units is less than its
carrying amount. Other than as discussed above, our goodwill impairment analysis performed as at
December 31, 2017, did not result in an impairment charge.
Effective in the quarter ended December 31, 2017, we have elected to move the annual review of the
goodwill balance from October 1 to April 1 to better align with the preparation and review of our business
plan, which is used in the test. The change does not delay, accelerate or avoid an impairment charge.
Asset Impairment
We evaluate the recoverability of our property, plant and equipment when events or circumstances such
as economic obsolescence, business climate, legal or regulatory changes, or other factors indicate we
may not recover the carrying amount of our assets. We continually monitor our businesses, the market
and business environments to identify indicators that could suggest an asset may not be recoverable. If it
is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the
asset, we will assess the fair value of the asset. 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
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.
Assets held for sale
We classify assets as held for sale when management commits to a formal plan to actively market an
asset or a group of assets and when management believes it is probable the sale of the assets will occur
within one year. We measure assets classified as held for sale at the lower of their carrying value and
their estimated fair value less costs to sell.
We are in the process of selling certain midstream assets within our gas transmission and midstream
segment. Given the state of the divestiture plan for these assets, as at December 31, 2017, we classified
them as held for sale and measured them at the lower of their carrying value and fair value less costs to
sell, which resulted in a loss of $4.4 billion ($2.8 billion after-tax). We determined the fair value of these
assets held for sale using present value techniques which required us to make projections and
assumptions regarding future cash flows, discount rates, inflation rates and growth rates, which were
impacted by prolonged decline in commodity prices and deteriorating business performance. These
projections and assumptions are subject to uncertainty and could be negatively impacted by changes in
market conditions, asset performance, legal environment, and other factors.
Regulatory Accounting
Certain of our businesses are subject to regulation by various authorities, including but not limited to, the
NEB, the FERC, the Alberta Energy Regulator, the New Brunswick Energy and Utilities Board, La Régie
de l’Energie du Québec 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. Key determinants in the ratemaking process are:
• Costs of providing service, including depreciation expense;
• Allowed rate of return, including the equity component of the capital structure and related income
taxes; and
• Contract and volume throughput assumptions.
The allowed rate of return is determined in accordance with the applicable regulatory model and may
impact our profitability. The rates for a number of our projects are based on a cost-of-service recovery
model that follows the regulators’ authoritative guidance. Under the cost-of-service tolling methodology,
we calculate tolls based on forecast volumes and cost. A difference between forecast and actual results
causes an over or under recovery in any given year. 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 or expected to be
paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative
(LMCI).
To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery
or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate
regulation, we 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.
As at December 31, 2017 and 2016, our regulatory assets totaled $3,477 million and $1,865 million,
respectively, and significant regulatory liabilities totaled $2,366 million and $844 million, respectively.
Depreciation
Depreciation of property, plant and equipment, our largest asset with a net book value at December 31,
2017 and 2016, of $90,711 million and $64,284 million, respectively, is charged in accordance with two
primary methods. 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 is followed
whereby similar assets are grouped and depreciated as a pool. When group assets are retired or
otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to
accumulated depreciation.
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 our assets including the level of development,
exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by
our pipelines as well as the demand for crude oil and natural gas and the integrity of our 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 our business segments. For
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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.
Postretirement Benefits
We maintain pension plans, which provide defined benefit and/or defined contribution pension benefits
and other postretirement benefits (OPEB) to eligible retirees. Pension costs and obligations for the
defined benefit pension plans 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 level, other cost escalations, retirement ages of employees and other actuarial
factors including discount rates and mortality. We determine discount rates by reference to rates of high-
quality long-term corporate bonds with maturities that approximate the timing of future payments we
anticipate making under each of the respective plans. These assumptions are reviewed annually by our
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 expectation by $174 million and $19 million for the years ended
December 31, 2017 and 2016, respectively, as disclosed in Part II. Item 8. Financial Statements and
Supplementary Data - Note 25 Pension and Other Postretirement Benefits. 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, 2017 Consolidated Financial
Statements of a 0.5% change in key pension and OPEB assumptions.
Goodwill
(millions of Canadian dollars)
Pension
Decrease in discount rate
Decrease in expected return on assets
Decrease in rate of salary increase
OPEB
Decrease in discount rate
Decrease in expected return on assets
Canada
United States
Obligation
Expense
Obligation
Expense
255
—
(56)
27
—
26
12
(13)
1
—
71
—
(9)
18
—
3
5
(2)
(1)
1
Contingent Liabilities
Provisions for claims filed against us 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 our financial results and certain
subsidiaries and investments are detailed in Part II. Item 8. Financial Statements and Supplementary
Data - Note 28 Commitments and Contingencies. In addition, any unasserted claims that later may
become evident could have a material impact on our financial results and certain subsidiaries and
investments.
Asset Retirement Obligations
Asset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at
fair value and recognized as Accounts payable and other or 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. Discount rates used to present value the expected future cash flows range
from 2.5% to 11.0% and 1.7% to 11.0% for the years ended December 31, 2017 and 2016, respectively.
ARO is 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. Our estimates of retirement costs could change as a result of
changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, there is
96
insufficient data or information to reasonably determine the timing of settlement for estimating the fair
value of the 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.
In 2009, the NEB issued a decision related to the LMCI, which required holders of an authorization to
operate a pipeline under the NEB Act to file a proposed process and mechanism to set aside funds to pay
for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The
NEB’s decision stated that while pipeline companies are ultimately responsible for the full costs of
abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable
from the users of the pipeline upon approval by the NEB. Following the NEB’s final approval of the
collection mechanism and the set-aside mechanism for LMCI, we began collecting and setting aside
funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trust
in accordance with the NEB decision. The funds collected from shippers are reported within
Transportation and other services revenues and Restricted long-term investments. Concurrently, we
reflect the future abandonment cost as an increase to Operating and administrative expense and Other
long-term liabilities.
CHANGES IN ACCOUNTING POLICIES
We previously performed our annual goodwill impairment test on October 1 of each fiscal year. Beginning
with the quarter ended December 31, 2017, we moved the annual goodwill impairment test from October
1 to April 1 to better align with the preparation and review of our business plan, which is used in the test.
The change does not delay, accelerate or avoid an impairment charge.
ADOPTION OF NEW STANDARDS
Simplifying the Measurement of Goodwill Impairment
Effective January 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 and applied
the standard on a prospective basis. Under the new guidance, goodwill impairment will now be the
amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed
the carrying amount of goodwill. We applied this standard as at December 31, 2017 in the measurement
of the goodwill impairment relating to the gas midstream reporting unit.
Clarifying the Definition of a Business in an Acquisition
Effective January 1, 2017, we early adopted ASU 2017-01 on a prospective basis. The new standard was
issued with the objective of adding guidance to assist entities with evaluating whether transactions should
be accounted for as acquisitions (disposals) of assets or businesses. This accounting update was applied
to acquisitions and dispositions that occurred in the year.
Accounting for Intra-Entity Asset Transfers
Effective January 1, 2017, we early adopted ASU 2016-16 on a modified retrospective basis. The new
standard was issued with the intent of improving the accounting for the income tax consequences of intra-
entity asset transfers other than inventory. Under the new guidance, an entity should recognize the
income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer
occurs. The adoption of the pronouncement did not have a material impact on our consolidated financial
statements.
Improvements to Employee Share-Based Payment Accounting
Effective January 1, 2017, we adopted ASU 2016-09 and applied certain amendments on a modified
retrospective basis with the remaining amendments applied on a prospective basis. The new standard
was issued with the intent of simplifying and improving several aspects of accounting for share-based
payment transactions including the income tax consequences, classification of awards as either equity or
97
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.
Postretirement Benefits
We maintain pension plans, which provide defined benefit and/or defined contribution pension benefits
and other postretirement benefits (OPEB) to eligible retirees. Pension costs and obligations for the
defined benefit pension plans 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 level, other cost escalations, retirement ages of employees and other actuarial
factors including discount rates and mortality. We determine discount rates by reference to rates of high-
quality long-term corporate bonds with maturities that approximate the timing of future payments we
anticipate making under each of the respective plans. These assumptions are reviewed annually by our
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 expectation by $174 million and $19 million for the years ended
December 31, 2017 and 2016, respectively, as disclosed in Part II. Item 8. Financial Statements and
Supplementary Data - Note 25 Pension and Other Postretirement Benefits. 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, 2017 Consolidated Financial
Statements of a 0.5% change in key pension and OPEB assumptions.
(millions of Canadian dollars)
Pension
Decrease in discount rate
Decrease in expected return on assets
Decrease in rate of salary increase
OPEB
Decrease in discount rate
Decrease in expected return on assets
Contingent Liabilities
Canada
United States
Obligation
Expense
Obligation
Expense
255
—
(56)
27
—
26
12
(13)
1
—
71
—
(9)
18
—
3
5
(2)
(1)
1
Provisions for claims filed against us 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 our financial results and certain
subsidiaries and investments are detailed in Part II. Item 8. Financial Statements and Supplementary
Data - Note 28 Commitments and Contingencies. In addition, any unasserted claims that later may
become evident could have a material impact on our financial results and certain subsidiaries and
investments.
Asset Retirement Obligations
Asset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at
fair value and recognized as Accounts payable and other or 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. Discount rates used to present value the expected future cash flows range
from 2.5% to 11.0% and 1.7% to 11.0% for the years ended December 31, 2017 and 2016, respectively.
ARO is 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. Our estimates of retirement costs could change as a result of
changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, there is
insufficient data or information to reasonably determine the timing of settlement for estimating the fair
value of the 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.
In 2009, the NEB issued a decision related to the LMCI, which required holders of an authorization to
operate a pipeline under the NEB Act to file a proposed process and mechanism to set aside funds to pay
for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The
NEB’s decision stated that while pipeline companies are ultimately responsible for the full costs of
abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable
from the users of the pipeline upon approval by the NEB. Following the NEB’s final approval of the
collection mechanism and the set-aside mechanism for LMCI, we began collecting and setting aside
funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trust
in accordance with the NEB decision. The funds collected from shippers are reported within
Transportation and other services revenues and Restricted long-term investments. Concurrently, we
reflect the future abandonment cost as an increase to Operating and administrative expense and Other
long-term liabilities.
CHANGES IN ACCOUNTING POLICIES
Goodwill
We previously performed our annual goodwill impairment test on October 1 of each fiscal year. Beginning
with the quarter ended December 31, 2017, we moved the annual goodwill impairment test from October
1 to April 1 to better align with the preparation and review of our business plan, which is used in the test.
The change does not delay, accelerate or avoid an impairment charge.
ADOPTION OF NEW STANDARDS
Simplifying the Measurement of Goodwill Impairment
Effective January 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 and applied
the standard on a prospective basis. Under the new guidance, goodwill impairment will now be the
amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed
the carrying amount of goodwill. We applied this standard as at December 31, 2017 in the measurement
of the goodwill impairment relating to the gas midstream reporting unit.
Clarifying the Definition of a Business in an Acquisition
Effective January 1, 2017, we early adopted ASU 2017-01 on a prospective basis. The new standard was
issued with the objective of adding guidance to assist entities with evaluating whether transactions should
be accounted for as acquisitions (disposals) of assets or businesses. This accounting update was applied
to acquisitions and dispositions that occurred in the year.
Accounting for Intra-Entity Asset Transfers
Effective January 1, 2017, we early adopted ASU 2016-16 on a modified retrospective basis. The new
standard was issued with the intent of improving the accounting for the income tax consequences of intra-
entity asset transfers other than inventory. Under the new guidance, an entity should recognize the
income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer
occurs. The adoption of the pronouncement did not have a material impact on our consolidated financial
statements.
Improvements to Employee Share-Based Payment Accounting
Effective January 1, 2017, we adopted ASU 2016-09 and applied certain amendments on a modified
retrospective basis with the remaining amendments applied on a prospective basis. The new standard
was issued with the intent of simplifying and improving several aspects of accounting for share-based
payment transactions including the income tax consequences, classification of awards as either equity or
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liabilities, and classification on the statement of cash flows. The adoption of the pronouncement did not
have a material impact on our consolidated financial statements.
applied on a retrospective basis for the statement of earnings presentation component and a prospective
basis for the capitalization component. We do not expect the adoption of this accounting update to have a
Simplifying the Embedded Derivatives Analysis for Debt Instruments
Effective January 1, 2017, we adopted ASU 2016-06 on a modified retrospective basis. The new
guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or
put options. The adoption of the pronouncement did not have a material impact on our consolidated
financial statements.
FUTURE ACCOUNTING POLICY CHANGES
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
ASU 2018-02 was issued in February 2018 to address a specific consequence of the TCJA. This
accounting update allows a reclassification from accumulated other comprehensive income to retained
earnings for stranded tax effects resulting from TCJA. The amendments eliminate the stranded tax effects
that were created as a result of the reduction of historical U.S. federal corporate income tax rate to the
newly enacted U.S. federal corporate income tax rate. The accounting update is effective January 1,
2019, with early adoption permitted, and is to be applied either in the period of adoption or retrospectively
to each period in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA
is recognized. We are currently assessing the impact of the new standard on the consolidated financial
statements.
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk
management activities and the resulting hedge accounting reflected in the financial statements. The
accounting update allows cash flow hedging of contractually specified components in financial and non-
financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and
hedging instruments’ fair value changes will be recorded in the same income statement line as the
hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be
performed at any time before the end of the quarter in which the hedge is designated. After initial
quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The
accounting update is effective January 1, 2019 and is to be applied on a modified retrospective basis. We
are currently assessing the impact of the new standard on our consolidated financial statements.
Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and
when it should be applied to a change to the terms or conditions of a share based payment award.
Under the new guidance, modification accounting is required for all changes to share based payment
awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the
vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a
debt instrument has not changed. The accounting update is effective January 1, 2018 and will be applied
on a prospective basis. We do not expect the adoption of this accounting update to have a material
impact on our consolidated financial statements.
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the
earliest call date for certain callable debt securities held at a premium. The accounting update is effective
January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the
impact of the new standard on our consolidated financial statements.
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the
components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s
sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net
benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be
material impact on our consolidated financial statements.
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition
guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of
nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for
derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is
effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the
adoption of this accounting update to have a material impact on our consolidated financial statements.
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and
presentation of changes in restricted cash and restricted cash equivalents within the statement of cash
flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be
included within cash and cash equivalents when reconciling the opening and closing period amounts
shown on the statement of cash flows. We currently present the changes in restricted cash and restricted
cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting
update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the
presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash
equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented.
Simplifying Cash Flow Classification
ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain
cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new
guidance addresses eight specific presentation issues. The accounting update is effective January 1,
2018 and will be applied on a retrospective basis. We assessed each of the eight specific presentation
issues and the adoption of this ASU does not have a material impact on our consolidated financial
statements.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more
useful information about the expected credit losses on financial instruments and other commitments to
extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss
methodology for recognizing credit losses that delays the recognition until it is probable a loss has been
incurred. The accounting update adds a new impairment model, known as the current expected credit
loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an
entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting
Standards Board believes will result in more timely recognition of such losses. We are currently assessing
the impact of the new standard on our consolidated financial statements. The accounting update is
effective January 1, 2020.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability
among organizations. It requires lessees of operating lease arrangements to recognize lease assets and
lease liabilities on the statement of financial position and disclose additional key information about lease
agreements. The accounting update also replaces the current definition of a lease and requires that an
arrangement be recognized as a lease when a customer has the right to obtain substantially all of the
economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are
currently gathering a complete inventory of our lease contracts in order to assess the impact of the new
standard on our consolidated financial statements. The accounting update is effective January 1, 2019
and will be applied using a modified retrospective approach.
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liabilities, and classification on the statement of cash flows. The adoption of the pronouncement did not
have a material impact on our consolidated financial statements.
Simplifying the Embedded Derivatives Analysis for Debt Instruments
Effective January 1, 2017, we adopted ASU 2016-06 on a modified retrospective basis. The new
guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or
put options. The adoption of the pronouncement did not have a material impact on our consolidated
financial statements.
FUTURE ACCOUNTING POLICY CHANGES
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
ASU 2018-02 was issued in February 2018 to address a specific consequence of the TCJA. This
accounting update allows a reclassification from accumulated other comprehensive income to retained
earnings for stranded tax effects resulting from TCJA. The amendments eliminate the stranded tax effects
that were created as a result of the reduction of historical U.S. federal corporate income tax rate to the
newly enacted U.S. federal corporate income tax rate. The accounting update is effective January 1,
2019, with early adoption permitted, and is to be applied either in the period of adoption or retrospectively
to each period in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA
is recognized. We are currently assessing the impact of the new standard on the consolidated financial
statements.
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk
management activities and the resulting hedge accounting reflected in the financial statements. The
accounting update allows cash flow hedging of contractually specified components in financial and non-
financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and
hedging instruments’ fair value changes will be recorded in the same income statement line as the
hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be
performed at any time before the end of the quarter in which the hedge is designated. After initial
quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The
accounting update is effective January 1, 2019 and is to be applied on a modified retrospective basis. We
are currently assessing the impact of the new standard on our consolidated financial statements.
Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and
when it should be applied to a change to the terms or conditions of a share based payment award.
Under the new guidance, modification accounting is required for all changes to share based payment
awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the
vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a
debt instrument has not changed. The accounting update is effective January 1, 2018 and will be applied
on a prospective basis. We do not expect the adoption of this accounting update to have a material
impact on our consolidated financial statements.
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the
earliest call date for certain callable debt securities held at a premium. The accounting update is effective
January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the
impact of the new standard on our consolidated financial statements.
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the
components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s
sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net
benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be
applied on a retrospective basis for the statement of earnings presentation component and a prospective
basis for the capitalization component. We do not expect the adoption of this accounting update to have a
material impact on our consolidated financial statements.
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition
guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of
nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for
derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is
effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the
adoption of this accounting update to have a material impact on our consolidated financial statements.
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and
presentation of changes in restricted cash and restricted cash equivalents within the statement of cash
flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be
included within cash and cash equivalents when reconciling the opening and closing period amounts
shown on the statement of cash flows. We currently present the changes in restricted cash and restricted
cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting
update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the
presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash
equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented.
Simplifying Cash Flow Classification
ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain
cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new
guidance addresses eight specific presentation issues. The accounting update is effective January 1,
2018 and will be applied on a retrospective basis. We assessed each of the eight specific presentation
issues and the adoption of this ASU does not have a material impact on our consolidated financial
statements.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more
useful information about the expected credit losses on financial instruments and other commitments to
extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss
methodology for recognizing credit losses that delays the recognition until it is probable a loss has been
incurred. The accounting update adds a new impairment model, known as the current expected credit
loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an
entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting
Standards Board believes will result in more timely recognition of such losses. We are currently assessing
the impact of the new standard on our consolidated financial statements. The accounting update is
effective January 1, 2020.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability
among organizations. It requires lessees of operating lease arrangements to recognize lease assets and
lease liabilities on the statement of financial position and disclose additional key information about lease
agreements. The accounting update also replaces the current definition of a lease and requires that an
arrangement be recognized as a lease when a customer has the right to obtain substantially all of the
economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are
currently gathering a complete inventory of our lease contracts in order to assess the impact of the new
standard on our consolidated financial statements. The accounting update is effective January 1, 2019
and will be applied using a modified retrospective approach.
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Recognition and Measurement of Financial Assets and Liabilities
ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition,
measurement, presentation and disclosure of financial assets and liabilities. Investments in equity
securities, excluding equity method and consolidated investments, are no longer classified as trading or
available-for-sale securities. All investments in equity securities with readily determinable fair values are
classified as investments at fair value through net income. Investments in equity securities without readily
determinable fair values are measured using the fair value measurement alternative and are recorded at
cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly
transactions for an identical or similar investment of the same issuer. Investments in equity securities
measured using the fair value measurement alternative are reviewed for indicators of impairment each
reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price.
The accounting update is effective January 1, 2018 and applied on a prospective basis. We do not expect
the adoption of this accounting update to have a material impact on our consolidated financial statements.
Revenue from Contracts with Customers
ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability
of revenue recognition practices across entities and industries. The new standard establishes a single,
principles-based five-step model to be applied to all contracts with customers and introduces new and
enhanced disclosure requirements. It also requires the use of more estimates and judgments than the
present standards in addition to additional disclosures. The new standard is effective January 1, 2018.
The new standard permits either a full retrospective method of adoption with restatement of all prior
periods presented, or a modified retrospective method with the cumulative effect of applying the new
standard recognized as an adjustment to opening retained earnings in the period of adoption. We have
decided to adopt the new standard using the modified retrospective method.
We have reviewed our revenue contracts in order to evaluate the effect of the new standard on our
revenue recognition practices. Based on our assessment to-date, the adoption of the new standard will
have the following impact to our financial statements:
• A change in presentation in the Gas Distribution business related to payments to customers
under the earnings sharing mechanism which are currently shown as an expense in the
Consolidated Statements of Earnings. Under the new standard, these payments will be reflected
as a reduction of revenue.
• Estimates of variable consideration, required under the new standard for certain Liquids
Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue
contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue
contracts, may result in changes to the pattern or timing of revenue recognition for those
contracts.
• Non-cash consideration received in the form of a percentage of the products derived from
processing natural gas in the Gas Transmission and Midstream business was previously
accounted for as revenue when the commodity was sold to third parties. Under the new standard,
the non-cash consideration will be accounted for as revenue when processing services are
performed. The commodity will continue to be accounted for as revenue when it is subsequently
sold to third parties. The impact of this change will be an increase in costs and revenues due to
the recognition of this non-cash consideration.
• Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission
and Midstream business whereby Enbridge purchases natural gas at the wellhead, then
processes and subsequently sells the gas, was previously presented as revenue. Under the new
standard, processing fees charged on natural gas purchased by Enbridge are presented as a
reduction of commodity costs upon the transfer of control of the natural gas at the wellhead.
• Revenue from certain contracts in the Gas Transmission and Midstream business that provide for
Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting
processed natural gas and/or NGLs as payment for processing services rendered, commonly
referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously
presented on a gross basis whereby Enbridge recorded one hundred percent of the value of the
natural gas and products sold as revenue, with the cost of the natural gas purchased recorded as
commodity cost. Under the new standard only Enbridge’s share of the products retained and sold
is presented as revenue and no commodity cost is recorded.
• Certain payments received from customers to offset the cost of constructing assets required to
provide services to those customers, referred to as Contributions in Aid of Construction (CIAC)
were previously recorded as reductions of property, plant and equipment regardless of whether
the amounts were imposed by regulation or negotiated. Under the new standard, negotiated
CIACs are deemed to be advance payments for services and must be recognized as revenue
when those future services are provided. Negotiated CIACs will be accounted for as deferred
revenue and recognized over the term of the associated revenue contract.
Upon adoption, we will recognize the significant cumulative effect of initially applying the new standard as
an increase in the opening balance of retained deficit of approximately $120 million, an increase in
property, plant and equipment of $130 million and an increase in deferred revenue of $120 million, subject
to final determination, as at January 1, 2018. The adoption of the new standard will also result in changes
in classification between Revenue and Commodity costs as discussed above.
We have also developed and tested processes to generate the disclosures which will be required under
the new standard commencing in the first quarter of 2018.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
Our earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign
exchange rates, interest rates, commodity prices and our share price.
The following summarizes the types of market risks to which we are exposed and the risk management
instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative
instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that
are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI
are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A
combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign
currency denominated revenues and expenses, and to manage variability in cash flows. We hedge
certain net investments in United States dollar denominated investments and subsidiaries using foreign
currency derivatives and United States dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing
of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are
used to hedge against the effect of future interest rate movements. We have implemented a program to
significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of
floating to fixed interest rate swaps with an average swap rate of 2.6%.
As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that
arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are
used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program
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Recognition and Measurement of Financial Assets and Liabilities
ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition,
measurement, presentation and disclosure of financial assets and liabilities. Investments in equity
securities, excluding equity method and consolidated investments, are no longer classified as trading or
available-for-sale securities. All investments in equity securities with readily determinable fair values are
classified as investments at fair value through net income. Investments in equity securities without readily
determinable fair values are measured using the fair value measurement alternative and are recorded at
cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly
transactions for an identical or similar investment of the same issuer. Investments in equity securities
measured using the fair value measurement alternative are reviewed for indicators of impairment each
reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price.
The accounting update is effective January 1, 2018 and applied on a prospective basis. We do not expect
the adoption of this accounting update to have a material impact on our consolidated financial statements.
Revenue from Contracts with Customers
ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability
of revenue recognition practices across entities and industries. The new standard establishes a single,
principles-based five-step model to be applied to all contracts with customers and introduces new and
enhanced disclosure requirements. It also requires the use of more estimates and judgments than the
present standards in addition to additional disclosures. The new standard is effective January 1, 2018.
The new standard permits either a full retrospective method of adoption with restatement of all prior
periods presented, or a modified retrospective method with the cumulative effect of applying the new
standard recognized as an adjustment to opening retained earnings in the period of adoption. We have
decided to adopt the new standard using the modified retrospective method.
We have reviewed our revenue contracts in order to evaluate the effect of the new standard on our
revenue recognition practices. Based on our assessment to-date, the adoption of the new standard will
have the following impact to our financial statements:
• A change in presentation in the Gas Distribution business related to payments to customers
under the earnings sharing mechanism which are currently shown as an expense in the
Consolidated Statements of Earnings. Under the new standard, these payments will be reflected
as a reduction of revenue.
• Estimates of variable consideration, required under the new standard for certain Liquids
Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue
contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue
contracts, may result in changes to the pattern or timing of revenue recognition for those
contracts.
• Non-cash consideration received in the form of a percentage of the products derived from
processing natural gas in the Gas Transmission and Midstream business was previously
accounted for as revenue when the commodity was sold to third parties. Under the new standard,
the non-cash consideration will be accounted for as revenue when processing services are
performed. The commodity will continue to be accounted for as revenue when it is subsequently
sold to third parties. The impact of this change will be an increase in costs and revenues due to
the recognition of this non-cash consideration.
• Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission
and Midstream business whereby Enbridge purchases natural gas at the wellhead, then
processes and subsequently sells the gas, was previously presented as revenue. Under the new
standard, processing fees charged on natural gas purchased by Enbridge are presented as a
reduction of commodity costs upon the transfer of control of the natural gas at the wellhead.
• Revenue from certain contracts in the Gas Transmission and Midstream business that provide for
Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting
processed natural gas and/or NGLs as payment for processing services rendered, commonly
referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously
presented on a gross basis whereby Enbridge recorded one hundred percent of the value of the
natural gas and products sold as revenue, with the cost of the natural gas purchased recorded as
commodity cost. Under the new standard only Enbridge’s share of the products retained and sold
is presented as revenue and no commodity cost is recorded.
• Certain payments received from customers to offset the cost of constructing assets required to
provide services to those customers, referred to as Contributions in Aid of Construction (CIAC)
were previously recorded as reductions of property, plant and equipment regardless of whether
the amounts were imposed by regulation or negotiated. Under the new standard, negotiated
CIACs are deemed to be advance payments for services and must be recognized as revenue
when those future services are provided. Negotiated CIACs will be accounted for as deferred
revenue and recognized over the term of the associated revenue contract.
Upon adoption, we will recognize the significant cumulative effect of initially applying the new standard as
an increase in the opening balance of retained deficit of approximately $120 million, an increase in
property, plant and equipment of $130 million and an increase in deferred revenue of $120 million, subject
to final determination, as at January 1, 2018. The adoption of the new standard will also result in changes
in classification between Revenue and Commodity costs as discussed above.
We have also developed and tested processes to generate the disclosures which will be required under
the new standard commencing in the first quarter of 2018.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
Our earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign
exchange rates, interest rates, commodity prices and our share price.
The following summarizes the types of market risks to which we are exposed and the risk management
instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative
instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that
are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI
are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A
combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign
currency denominated revenues and expenses, and to manage variability in cash flows. We hedge
certain net investments in United States dollar denominated investments and subsidiaries using foreign
currency derivatives and United States dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing
of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are
used to hedge against the effect of future interest rate movements. We have implemented a program to
significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of
floating to fixed interest rate swaps with an average swap rate of 2.6%.
As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that
arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are
used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program
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within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via
execution of fixed to floating interest rate swaps with an average swap rate of 2.2%.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of
anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against
the effect of future interest rate movements. We have assumed a program within some of our subsidiaries
to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via
execution of floating to fixed interest rate swaps with an average swap rate of 3.1%.
We also monitor our debt portfolio mix of fixed and variable rate debt instruments to maintain a
consolidated portfolio of debt within the Board of Directors approved policy limit of a maximum of 25%
floating rate debt as a percentage of total debt outstanding. Effective January 1, 2018, the Board of
Directors approved a policy limit increase of a maximum of 30% floating rate debt as a percentage of total
debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.
Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership
interests in certain assets and investments, as well as through the activities of our energy services
subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and
physical derivative instruments to fix a portion of the variable price exposures that arise from physical
transactions involving these commodities. We use primarily non-qualifying derivative instruments to
manage commodity price risk.
Emission Allowance Price Risk
Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission
allowances that our gas distribution business is required to purchase for itself and most of its customers
to meet GHG compliance obligations under the Ontario Cap and Trade framework. Similar to the gas
supply procurement framework, the OEB's framework for emission allowance procurement allows
recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure
to our 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. We use equity derivatives
to manage the earnings volatility derived from 1 form of stock-based compensation, restricted share units.
We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.
Market Risk Management
We have a Risk Policy to minimize the likelihood that adverse earnings impacts arising from movements
in market prices will exceed a defined risk tolerance. We identify and measure all material market risks
including commodity price risks, interest rate risks, foreign exchange risk, emission allowance price risk
and equity price risk using a standardized measurement methodology. Our market risk metric
consolidates the exposure after accounting for the impact of offsetting risks and limits the consolidated
earnings volatility arising from market related risks to an acceptable approved risk tolerance threshold.
We use Earnings-at-Risk (EaR), a statistically derived measurement, to quantify losses that could
potentially result from adverse market price movements over a one month holding period for price
sensitive non-derivative exposures and for derivative instruments we hold or issue as recorded on the
balance sheet as at December 31, 2017. EaR assumes no further mitigating actions are taken to hedge
or otherwise minimize exposures. The selection of a one month holding period reflects the mix of price
risk sensitive assets at Enbridge. EaR calculates the annual earnings impact of market price movements
over a one month period assuming no action is taken to hedge or otherwise mitigate exposures. As a
practical matter, a large portion of Enbridge’s exposure could be hedged or unwound in a much shorter
period if required to mitigate the risks.
102
The consolidated EaR policy limit for Enbridge is 5% of its forward 12 month forecast normalized
earnings. EaR incorporates a Monte Carlo simulation, a 97.5 percent confidence level, a risk
measurement horizon of one year (forward looking), a holding period of one month, and includes financial
derivative instruments, other financial instruments, commodity derivative instruments, other commodity
and executory contracts, positions and earnings or cash flows from anticipated transactions. EaR at
December 31, 2017 and 2016 is 1.7% and 2.8% or $68 million and $59 million, respectively.
Effective January 1, 2018, the Board of Directors approved to change the market risk metric to Cash-
Flows-at-Risk (CFaR) and the consolidated CFaR limit will be 3.5% of forward 12 month normalized cash
flow. The policy change will align the market risk metric with other key results metrics in the organization.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments
and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a
12 month rolling time period to determine whether sufficient funds will be available and maintain
substantial capacity under our committed bank lines of credit to address any contingencies. Our 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. We also maintain 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, we maintain sufficient liquidity through committed credit facilities
with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated
requirements for approximately one year without accessing the capital markets. We are in compliance
with all the terms and conditions of our committed credit facility agreements and term debt indentures as
at December 31, 2017. As a result, all credit facilities are available to us and the banks are obligated to
fund and have been funding us under the terms of the facilities.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a
counterparty will default on its contractual obligations. In order to mitigate this risk, we enter 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, netting arrangements, and ongoing monitoring of counterparty credit exposure using
external credit rating services and other analytical tools.
We generally have a policy of entering into individual International Swaps and Derivatives
Association, Inc. agreements or other similar derivative agreements with the majority of our financial
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 events, and
reduces our credit risk exposure on financial derivative asset positions outstanding with the
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 EGD and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base
and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively
monitor the financial strength of large industrial customers and, in select cases, have obtained additional
security to minimize the risk of default on receivables. Generally, we classify and provide for receivables
older than 20 days as past due. The maximum exposure to credit risk related to non-derivative financial
assets is their carrying value.
103
within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via
execution of fixed to floating interest rate swaps with an average swap rate of 2.2%.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of
anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against
the effect of future interest rate movements. We have assumed a program within some of our subsidiaries
to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via
execution of floating to fixed interest rate swaps with an average swap rate of 3.1%.
We also monitor our debt portfolio mix of fixed and variable rate debt instruments to maintain a
consolidated portfolio of debt within the Board of Directors approved policy limit of a maximum of 25%
floating rate debt as a percentage of total debt outstanding. Effective January 1, 2018, the Board of
Directors approved a policy limit increase of a maximum of 30% floating rate debt as a percentage of total
debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.
Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership
interests in certain assets and investments, as well as through the activities of our energy services
subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and
physical derivative instruments to fix a portion of the variable price exposures that arise from physical
transactions involving these commodities. We use primarily non-qualifying derivative instruments to
manage commodity price risk.
Emission Allowance Price Risk
Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission
allowances that our gas distribution business is required to purchase for itself and most of its customers
to meet GHG compliance obligations under the Ontario Cap and Trade framework. Similar to the gas
supply procurement framework, the OEB's framework for emission allowance procurement allows
recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure
to our 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. We use equity derivatives
to manage the earnings volatility derived from 1 form of stock-based compensation, restricted share units.
We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.
Market Risk Management
We have a Risk Policy to minimize the likelihood that adverse earnings impacts arising from movements
in market prices will exceed a defined risk tolerance. We identify and measure all material market risks
including commodity price risks, interest rate risks, foreign exchange risk, emission allowance price risk
and equity price risk using a standardized measurement methodology. Our market risk metric
consolidates the exposure after accounting for the impact of offsetting risks and limits the consolidated
earnings volatility arising from market related risks to an acceptable approved risk tolerance threshold.
We use Earnings-at-Risk (EaR), a statistically derived measurement, to quantify losses that could
potentially result from adverse market price movements over a one month holding period for price
sensitive non-derivative exposures and for derivative instruments we hold or issue as recorded on the
balance sheet as at December 31, 2017. EaR assumes no further mitigating actions are taken to hedge
or otherwise minimize exposures. The selection of a one month holding period reflects the mix of price
risk sensitive assets at Enbridge. EaR calculates the annual earnings impact of market price movements
over a one month period assuming no action is taken to hedge or otherwise mitigate exposures. As a
practical matter, a large portion of Enbridge’s exposure could be hedged or unwound in a much shorter
period if required to mitigate the risks.
102
The consolidated EaR policy limit for Enbridge is 5% of its forward 12 month forecast normalized
earnings. EaR incorporates a Monte Carlo simulation, a 97.5 percent confidence level, a risk
measurement horizon of one year (forward looking), a holding period of one month, and includes financial
derivative instruments, other financial instruments, commodity derivative instruments, other commodity
and executory contracts, positions and earnings or cash flows from anticipated transactions. EaR at
December 31, 2017 and 2016 is 1.7% and 2.8% or $68 million and $59 million, respectively.
Effective January 1, 2018, the Board of Directors approved to change the market risk metric to Cash-
Flows-at-Risk (CFaR) and the consolidated CFaR limit will be 3.5% of forward 12 month normalized cash
flow. The policy change will align the market risk metric with other key results metrics in the organization.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments
and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a
12 month rolling time period to determine whether sufficient funds will be available and maintain
substantial capacity under our committed bank lines of credit to address any contingencies. Our 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. We also maintain 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, we maintain sufficient liquidity through committed credit facilities
with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated
requirements for approximately one year without accessing the capital markets. We are in compliance
with all the terms and conditions of our committed credit facility agreements and term debt indentures as
at December 31, 2017. As a result, all credit facilities are available to us and the banks are obligated to
fund and have been funding us under the terms of the facilities.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a
counterparty will default on its contractual obligations. In order to mitigate this risk, we enter 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, netting arrangements, and ongoing monitoring of counterparty credit exposure using
external credit rating services and other analytical tools.
We generally have a policy of entering into individual International Swaps and Derivatives
Association, Inc. agreements or other similar derivative agreements with the majority of our financial
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 events, and
reduces our credit risk exposure on financial derivative asset positions outstanding with the
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 EGD and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base
and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively
monitor the financial strength of large industrial customers and, in select cases, have obtained additional
security to minimize the risk of default on receivables. Generally, we classify and provide for receivables
older than 20 days as past due. The maximum exposure to credit risk related to non-derivative financial
assets is their carrying value.
103
FAIR VALUE MEASUREMENTS
The most observable inputs available are used to estimate the fair value of its derivatives. When possible,
we estimate the fair value of our derivatives based on quoted market prices from exchanges. If quoted
market prices are not available, we use estimates from third party brokers. For non-exchange traded
derivatives classified in Levels 2 and 3, we use 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,
we use observable market prices (interest rates, foreign exchange rates, commodity prices and share
prices, as applicable) and volatility as primary inputs to these valuation techniques. Finally, we consider
our own credit default swap spread, as well as the credit default swap spreads associated with our
counterparties, in our estimation of fair value.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Shareholders and Directors of Enbridge Inc.
Opinions on the consolidated financial statements and internal control over financial reporting
We have audited the accompanying consolidated statements of financial position of Enbridge Inc. and its
subsidiaries (the “Company”) as of December 31, 2017 and December 31, 2016, and the related
consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each
of the three years in the period ended December 31, 2017, including the related notes (collectively
referred to as the “consolidated financial statements”). We also have audited the Company's internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control
- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material
respects, the consolidated financial position of the Company as of December 31, 2017 and December 31,
2016, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2017 in conformity with accounting principles generally accepted in the United
States of America. Also in our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control
- Integrated Framework (2013) issued by the COSO.
Basis for opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining
effective internal control over financial reporting, and for its assessment of the effectiveness of internal
control over financial reporting, included in the Management’s Annual Report on Internal Control over
Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s
consolidated financial statements and on the Company’s internal control over financial reporting based on
our audits. We are a public accounting firm registered with the Public Company Accounting Oversight
Board (United States) (PCAOB) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that
we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of
material misstatement of the consolidated financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also
included evaluating the accounting principles used and significant estimates made by management, as
well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the circumstances. We believe that our
audits provide a reasonable basis for our opinions.
104
105
FAIR VALUE MEASUREMENTS
The most observable inputs available are used to estimate the fair value of its derivatives. When possible,
we estimate the fair value of our derivatives based on quoted market prices from exchanges. If quoted
market prices are not available, we use estimates from third party brokers. For non-exchange traded
derivatives classified in Levels 2 and 3, we use 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,
we use observable market prices (interest rates, foreign exchange rates, commodity prices and share
prices, as applicable) and volatility as primary inputs to these valuation techniques. Finally, we consider
our own credit default swap spread, as well as the credit default swap spreads associated with our
counterparties, in our estimation of fair value.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Shareholders and Directors of Enbridge Inc.
Opinions on the consolidated financial statements and internal control over financial reporting
We have audited the accompanying consolidated statements of financial position of Enbridge Inc. and its
subsidiaries (the “Company”) as of December 31, 2017 and December 31, 2016, and the related
consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each
of the three years in the period ended December 31, 2017, including the related notes (collectively
referred to as the “consolidated financial statements”). We also have audited the Company's internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control
- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material
respects, the consolidated financial position of the Company as of December 31, 2017 and December 31,
2016, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2017 in conformity with accounting principles generally accepted in the United
States of America. Also in our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control
- Integrated Framework (2013) issued by the COSO.
Basis for opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining
effective internal control over financial reporting, and for its assessment of the effectiveness of internal
control over financial reporting, included in the Management’s Annual Report on Internal Control over
Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s
consolidated financial statements and on the Company’s internal control over financial reporting based on
our audits. We are a public accounting firm registered with the Public Company Accounting Oversight
Board (United States) (PCAOB) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that
we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of
material misstatement of the consolidated financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also
included evaluating the accounting principles used and significant estimates made by management, as
well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the circumstances. We believe that our
audits provide a reasonable basis for our opinions.
104
105
Definition and limitations 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 consolidated 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 consolidated 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 consolidated financial
statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta
February 16, 2018
We have served as the Company’s auditor since 1949.
CONSOLIDATED STATEMENTS OF EARNINGS
ENBRIDGE INC.
Year ended December 31,
(millions of Canadian dollars, except per share amounts)
2017
2016
2015
Impairment of long-lived assets (Note 7 and Note 10)
Impairment of goodwill (Note 7 and Note 15)
Operating revenues
Commodity sales
Gas distribution sales
Transportation and other services
Total operating revenues
Operating expenses
Commodity costs
Gas distribution costs
Operating and administrative
Depreciation and amortization
Total operating expenses
Operating income
Income from equity investments (Note 12)
Other income/(expense)
Net foreign currency gain/(loss)
Gain on dispositions
Other
Interest expense (Note 17)
Earnings before income taxes
Income tax recovery/(expense) (Note 24)
Earnings/(loss)
(Earnings)/loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Earnings attributable to controlling interests
Preference share dividends
Earnings/(loss) attributable to common shareholders
Earnings/(loss) per common share attributable to common
shareholders (Note 5)
shareholders (Note 5)
Diluted earnings/(loss) per common share attributable to common
The accompanying notes are an integral part of these consolidated financial statements.
26,065
22,409
22,949
26,286
4,215
13,877
44,378
2,572
6,442
3,163
4,463
102
42,807
1,571
1,102
237
16
199
(2,556)
569
2,697
3,266
(407)
2,859
(330)
2,529
1.66
1.65
22,816
2,486
9,258
34,560
1,596
4,358
2,240
1,376
—
31,979
2,581
428
91
848
93
(1,590)
2,451
(142)
2,309
(240)
2,069
(293)
1,776
1.95
1.93
23,842
3,096
6,856
33,794
2,292
4,131
2,024
96
440
31,932
1,862
475
(884)
94
88
11
(1,624)
(170)
(159)
410
251
(288)
(37)
(0.04)
(0.04)
106
107
Definition and limitations 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 consolidated 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 consolidated 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 consolidated financial
statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta
February 16, 2018
We have served as the Company’s auditor since 1949.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS
Year ended December 31,
(millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales
Gas distribution sales
Transportation and other services
Total operating revenues
Operating expenses
Commodity costs
Gas distribution costs
Operating and administrative
Depreciation and amortization
Impairment of long-lived assets (Note 7 and Note 10)
Impairment of goodwill (Note 7 and Note 15)
Total operating expenses
Operating income
Income from equity investments (Note 12)
Other income/(expense)
Net foreign currency gain/(loss)
Gain on dispositions
Other
Interest expense (Note 17)
Earnings before income taxes
Income tax recovery/(expense) (Note 24)
Earnings/(loss)
(Earnings)/loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Earnings attributable to controlling interests
Preference share dividends
Earnings/(loss) attributable to common shareholders
Earnings/(loss) per common share attributable to common
shareholders (Note 5)
Diluted earnings/(loss) per common share attributable to common
shareholders (Note 5)
The accompanying notes are an integral part of these consolidated financial statements.
2017
2016
2015
26,286
4,215
13,877
44,378
26,065
2,572
6,442
3,163
4,463
102
42,807
1,571
1,102
237
16
199
(2,556)
569
2,697
3,266
(407)
2,859
(330)
2,529
1.66
1.65
22,816
2,486
9,258
34,560
22,409
1,596
4,358
2,240
1,376
—
31,979
2,581
428
91
848
93
(1,590)
2,451
(142)
2,309
(240)
2,069
(293)
1,776
1.95
1.93
23,842
3,096
6,856
33,794
22,949
2,292
4,131
2,024
96
440
31,932
1,862
475
(884)
94
88
(1,624)
11
(170)
(159)
410
251
(288)
(37)
(0.04)
(0.04)
106
107
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31,
(millions of Canadian dollars)
Earnings/(loss)
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges
Change in unrealized gain/(loss) on net investment hedges
Other comprehensive income/(loss) from equity investees
Reclassification to earnings of (gain)/loss on cash flow hedges
Reclassification to earnings of pension and other postretirement
benefits amounts
Actuarial gain/(loss) on pension plans and other postretirement
benefits
Foreign currency translation adjustments
Other comprehensive income/(loss), net of tax
Comprehensive income
Comprehensive (income)/loss attributable to noncontrolling interests
and redeemable noncontrolling interests
Comprehensive income attributable to controlling interests
Preference share dividends
Comprehensive income/(loss) attributable to common shareholders
The accompanying notes are an integral part of these consolidated financial statements.
2017
2016
2015
3,266
2,309
(21)
490
(27)
313
19
8
(3,060)
(2,278)
988
(160)
828
(330)
498
(138)
166
—
116
17
(34)
(712)
(585)
1,724
(229)
1,495
(293)
1,202
(159)
198
(903)
30
(559)
21
51
3,347
2,185
2,026
292
2,318
(288)
2,030
108
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
ENBRIDGE INC.
2017
2016
2015
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
Common shares issued in Merger Transaction (Note 7)
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
(Note 7)
Options exercised
Enbridge Energy Company Inc. common control transaction
Drop down of interest to Enbridge Energy Partners, L.P. (Note 19)
Dilution gain/(loss) and other (Note 19)
Balance at end of year
Retained earnings/(deficit)
Balance at beginning of year
Earnings attributable to controlling interests
Preference share dividends
Common share dividends declared
Dividends paid to reciprocal shareholder
Fair value of outstanding earned stock-based compensation from Merger Transaction
Reversal of cumulative redemption value adjustment attributable to Enbridge
Commercial Trust (Note 19)
Redemption value adjustment attributable to redeemable noncontrolling interests
Adjustment for the recognition of unutilized tax deductions for stock based compensation
(Note 19)
expense
Other
Balance at end of year
Adjustment relating to equity method investment
Accumulated other comprehensive income/(loss) (Note 22)
Balance at beginning of year
Other comprehensive income/(loss) attributable to common shareholders, net of tax
Balance at end of year
Reciprocal shareholding
Balance at beginning of year (Note 12)
Issuance of treasury stock
Balance at end of year (Note 12)
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 gain on cash flow hedges
Foreign currency translation adjustments
Reclassification to earnings of (gain)/loss on cash flow hedges
Comprehensive income/(loss) attributable to noncontrolling interests
Noncontrolling interests resulting from Merger Transaction (Note 7)
Enbridge Energy Company, Inc. common control transaction
Distributions
Contributions
Deconsolidation of Sabal Trail Transmission, LLC
Drop down of interest to Enbridge Energy Partners, L.P.
Dilution gain/(loss)
Disposition of Olympic Pipeline
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.
109
7,255
492
7,747
10,492
1,500
37,429
1,226
90
50,737
3,399
82
77
(95)
76
—
(345)
3,194
(716)
2,859
(330)
(4,702)
30
—
292
41
—
58
(2,468)
1,058
(2,031)
(973)
(102)
—
(102)
58,135
577
232
15
(431)
139
(277)
(45)
8,955
(343)
(839)
832
(2,318)
—
832
(24)
(30)
7,597
65,732
2.41
3,399
3,301
6,515
740
7,255
7,391
2,241
—
795
65
10,492
3,301
(24)
41
—
—
—
81
142
2,069
(293)
(1,945)
26
—
(686)
—
(29)
—
(716)
1,632
(574)
1,058
(83)
(19)
(102)
1,300
(28)
4
(44)
(28)
40
—
—
—
28
—
—
—
—
(720)
(3)
577
21,963
2.12
6,515
—
6,515
6,669
—
—
646
76
7,391
2,549
35
—
(19)
—
218
518
1,571
251
(288)
(1,596)
22
541
(359)
—
—
—
142
(435)
2,067
1,632
(83)
—
(83)
2,015
(407)
161
273
(319)
115
(292)
—
—
(680)
615
—
(304)
(53)
—
(1)
1,300
20,198
1.86
21,386
18,898
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
ENBRIDGE INC.
Year ended December 31,
(millions of Canadian dollars)
Earnings/(loss)
2017
2016
2015
3,266
2,309
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges
Change in unrealized gain/(loss) on net investment hedges
Other comprehensive income/(loss) from equity investees
Reclassification to earnings of (gain)/loss on cash flow hedges
Reclassification to earnings of pension and other postretirement
Actuarial gain/(loss) on pension plans and other postretirement
benefits amounts
benefits
Foreign currency translation adjustments
Other comprehensive income/(loss), net of tax
Comprehensive income
Comprehensive (income)/loss attributable to noncontrolling interests
and redeemable noncontrolling interests
Comprehensive income attributable to controlling interests
Preference share dividends
Comprehensive income/(loss) attributable to common shareholders
The accompanying notes are an integral part of these consolidated financial statements.
(21)
490
(27)
313
19
8
(3,060)
(2,278)
988
(160)
828
(330)
498
(138)
166
—
116
17
(34)
(712)
(585)
1,724
(229)
1,495
(293)
1,202
(159)
198
(903)
30
(559)
21
51
3,347
2,185
2,026
292
2,318
(288)
2,030
108
ENBRIDGE INC.
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
Common shares issued in Merger Transaction (Note 7)
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
Fair value of outstanding earned stock-based compensation from Merger Transaction
(Note 7)
Options exercised
Enbridge Energy Company Inc. common control transaction
Drop down of interest to Enbridge Energy Partners, L.P. (Note 19)
Dilution gain/(loss) and other (Note 19)
Balance at end of year
Retained earnings/(deficit)
Balance at beginning of year
Earnings attributable to controlling interests
Preference share dividends
Common share dividends declared
Dividends paid to reciprocal shareholder
Reversal of cumulative redemption value adjustment attributable to Enbridge
Commercial Trust (Note 19)
Redemption value adjustment attributable to redeemable noncontrolling interests
(Note 19)
Adjustment for the recognition of unutilized tax deductions for stock based compensation
expense
Adjustment relating to equity method investment
Other
Balance at end of year
Accumulated other comprehensive income/(loss) (Note 22)
Balance at beginning of year
Other comprehensive income/(loss) attributable to common shareholders, net of tax
Balance at end of year
Reciprocal shareholding
Balance at beginning of year (Note 12)
Issuance of treasury stock
Balance at end of year (Note 12)
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 gain on cash flow hedges
Foreign currency translation adjustments
Reclassification to earnings of (gain)/loss on cash flow hedges
Comprehensive income/(loss) attributable to noncontrolling interests
Noncontrolling interests resulting from Merger Transaction (Note 7)
Enbridge Energy Company, Inc. common control transaction
Distributions
Contributions
Deconsolidation of Sabal Trail Transmission, LLC
Drop down of interest to Enbridge Energy Partners, L.P.
Dilution gain/(loss)
Disposition of Olympic Pipeline
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.
109
2017
2016
2015
7,255
492
7,747
10,492
1,500
37,429
1,226
90
50,737
3,399
82
77
(95)
76
—
(345)
3,194
(716)
2,859
(330)
(4,702)
30
—
292
41
—
58
(2,468)
1,058
(2,031)
(973)
(102)
—
(102)
58,135
577
232
15
(431)
139
(277)
(45)
8,955
(343)
(839)
832
(2,318)
—
832
(24)
(30)
7,597
65,732
2.41
6,515
740
7,255
7,391
2,241
—
795
65
10,492
3,301
41
—
(24)
—
—
81
3,399
142
2,069
(293)
(1,945)
26
—
(686)
—
(29)
—
(716)
1,632
(574)
1,058
(83)
(19)
(102)
21,386
1,300
(28)
4
(44)
40
—
(28)
—
—
(720)
28
—
—
—
—
(3)
577
21,963
2.12
6,515
—
6,515
6,669
—
—
646
76
7,391
2,549
35
—
(19)
—
218
518
3,301
1,571
251
(288)
(1,596)
22
541
(359)
—
—
—
142
(435)
2,067
1,632
(83)
—
(83)
18,898
2,015
(407)
161
273
(319)
115
(292)
—
—
(680)
615
—
(304)
(53)
—
(1)
1,300
20,198
1.86
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,
(millions of Canadian dollars)
Operating activities
Earnings/(loss)
Adjustments to reconcile earnings/(loss) to net cash provided by operating
activities:
Depreciation and amortization
Deferred income tax expense
Changes in unrealized (gain)/loss on derivative instruments, net (Note 23)
Earnings from equity investments
Distributions from equity investments
Impairment
(Gain)/loss on dispositions
Hedge ineffectiveness (Note 23)
Inventory revaluation allowance
Unrealized intercompany foreign exchange (gain)/loss
Other
Changes in environmental liabilities, net of recoveries
Changes in operating assets and liabilities (Note 26)
Net cash provided by operating activities
Investing activities
Capital expenditures
Joint venture financing
Long-term investments
Distributions from equity investments in excess of cumulative earnings
Restricted long-term investments
Additions to intangible assets
Purchases of held-to-maturity securities
Proceeds from sales and maturities of held-to-maturity securities
Purchase of available-for-sale securities
Proceeds from sales and maturities of available-for-sale securities
Acquisitions
Cash acquired in Merger Transaction (Note 7)
Proceeds from dispositions
Reimbursement of capital expenditures
Affiliate loans, net
Changes in restricted cash
Net cash used in investing activities
Financing activities
Net change in short-term borrowings (Note 2)
Net change in commercial paper and credit facility draws
Debenture and term note issues, net of issue costs
Debenture and term note repayments
Purchase of interest in consolidated subsidiary
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
Net cash provided by financing activities
Effect of translation of foreign denominated cash and cash equivalents
Net increase/(decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Supplementary cash flow information
Cash paid for income taxes
Cash paid for interest, net of amount capitalized
Property, plant and equipment non-cash accruals
The accompanying notes are an integral part of these consolidated financial statements.
110
2017
2016
2015
3,266
2,309
(159)
3,163
(2,877)
(1,242)
(1,102)
1,264
4,565
(120)
(55)
56
28
50
(98)
(314)
6,584
(8,287)
(25)
(3,525)
125
(54)
(789)
(529)
584
(136)
99
—
682
628
212
(22)
35
(11,002)
721
(1,249)
9,483
(5,054)
(227)
832
(919)
1,178
(247)
489
1,549
(330)
(2,750)
3,476
(72)
(1,014)
1,494
480
172
2,668
889
2,240
43
(509)
(656)
827
1,620
(848)
61
245
43
198
(4)
(358)
5,211
(5,128)
(1)
(467)
—
(46)
(127)
—
—
—
—
(644)
—
1,379
—
(118)
(40)
(5,192)
(248)
(2,297)
4,080
(1,946)
—
28
(720)
591
(202)
737
2,260
(293)
(1,150)
840
(19)
840
654
1,494
194
1,820
773
2,024
7
2,373
(483)
727
536
(94)
(20)
410
(131)
69
(43)
(645)
4,571
(7,273)
—
(622)
—
(49)
(101)
—
—
—
—
(106)
—
146
—
59
13
(7,933)
(487)
1,507
3,767
(1,023)
—
615
(680)
670
(114)
—
57
(288)
(950)
3,074
143
(145)
799
654
80
1,835
1,222
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
ENBRIDGE INC.
2017
2016
(millions of Canadian dollars; number of shares in millions)
December 31,
Assets
Current assets
Cash and cash equivalents (Note 2)
Restricted cash
Accounts receivable and other (Note 8)
Accounts receivable from affiliates
Inventory (Note 9)
Property, plant and equipment, net (Note 10)
Long-term investments (Note 12)
Restricted long-term investments (Note 13)
Deferred amounts and other assets
Intangible assets, net (Note 14)
Goodwill (Note 15)
Deferred income taxes (Note 24)
Total assets
Liabilities and equity
Current liabilities
Short-term borrowings (Note 17)
Accounts payable and other (Note 16)
Accounts payable to affiliates
Interest payable
Environmental liabilities
Current portion of long-term debt (Note 17)
Long-term debt (Note 17)
Other long-term liabilities
Deferred income taxes (Note 24)
Commitments and contingencies (Note 28)
Redeemable noncontrolling interests (Note 19)
Equity
Share capital (Note 20)
Preference shares
Common shares (1,695 and 943 outstanding at December 31, 2017 and
December 31, 2016, respectively)
Additional paid-in capital
Deficit
Reciprocal shareholding
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 19)
Accumulated other comprehensive income/(loss) (Note 22)
Total liabilities and equity
Variable Interest Entities (Note 11)
The accompanying notes are an integral part of these consolidated financial statements.
111
480
107
7,053
47
1,528
9,215
90,711
16,644
267
6,442
3,267
34,457
1,090
162,093
1,444
9,478
157
634
40
2,871
14,624
60,865
7,510
9,295
92,294
4,067
7,747
50,737
3,194
(2,468)
(973)
(102)
58,135
7,597
65,732
162,093
1,494
4,978
68
14
1,233
7,787
64,284
6,836
90
3,391
1,573
78
1,170
85,209
351
7,295
122
333
142
4,100
12,343
36,494
4,981
6,036
59,854
3,392
7,255
10,492
3,399
(716)
1,058
(102)
21,386
577
21,963
85,209
CONSOLIDATED STATEMENTS OF CASH FLOWS
ENBRIDGE INC.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
December 31,
(millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents (Note 2)
Restricted cash
Accounts receivable and other (Note 8)
Accounts receivable from affiliates
Inventory (Note 9)
Property, plant and equipment, net (Note 10)
Long-term investments (Note 12)
Restricted long-term investments (Note 13)
Deferred amounts and other assets
Intangible assets, net (Note 14)
Goodwill (Note 15)
Deferred income taxes (Note 24)
Total assets
Liabilities and equity
Current liabilities
Short-term borrowings (Note 17)
Accounts payable and other (Note 16)
Accounts payable to affiliates
Interest payable
Environmental liabilities
Current portion of long-term debt (Note 17)
Long-term debt (Note 17)
Other long-term liabilities
Deferred income taxes (Note 24)
Commitments and contingencies (Note 28)
Redeemable noncontrolling interests (Note 19)
Equity
Share capital (Note 20)
Preference shares
Common shares (1,695 and 943 outstanding at December 31, 2017 and
December 31, 2016, respectively)
Additional paid-in capital
Deficit
Accumulated other comprehensive income/(loss) (Note 22)
Reciprocal shareholding
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 19)
Total liabilities and equity
Variable Interest Entities (Note 11)
The accompanying notes are an integral part of these consolidated financial statements.
111
2017
2016
480
107
7,053
47
1,528
9,215
90,711
16,644
267
6,442
3,267
34,457
1,090
162,093
1,444
9,478
157
634
40
2,871
14,624
60,865
7,510
9,295
92,294
4,067
7,747
50,737
3,194
(2,468)
(973)
(102)
58,135
7,597
65,732
162,093
1,494
68
4,978
14
1,233
7,787
64,284
6,836
90
3,391
1,573
78
1,170
85,209
351
7,295
122
333
142
4,100
12,343
36,494
4,981
6,036
59,854
3,392
7,255
10,492
3,399
(716)
1,058
(102)
21,386
577
21,963
85,209
Adjustments to reconcile earnings/(loss) to net cash provided by operating
Changes in unrealized (gain)/loss on derivative instruments, net (Note 23)
Year ended December 31,
(millions of Canadian dollars)
Operating activities
Earnings/(loss)
activities:
Depreciation and amortization
Deferred income tax expense
Earnings from equity investments
Distributions from equity investments
Impairment
(Gain)/loss on dispositions
Hedge ineffectiveness (Note 23)
Inventory revaluation allowance
Unrealized intercompany foreign exchange (gain)/loss
Other
Changes in environmental liabilities, net of recoveries
Changes in operating assets and liabilities (Note 26)
Net cash provided by operating activities
Investing activities
Capital expenditures
Joint venture financing
Long-term investments
Distributions from equity investments in excess of cumulative earnings
Restricted long-term investments
Additions to intangible assets
Purchases of held-to-maturity securities
Proceeds from sales and maturities of held-to-maturity securities
Purchase of available-for-sale securities
Proceeds from sales and maturities of available-for-sale securities
Acquisitions
Cash acquired in Merger Transaction (Note 7)
Proceeds from dispositions
Reimbursement of capital expenditures
Affiliate loans, net
Changes in restricted cash
Net cash used in investing activities
Financing activities
Net change in short-term borrowings (Note 2)
Net change in commercial paper and credit facility draws
Debenture and term note issues, net of issue costs
Debenture and term note repayments
Purchase of interest in consolidated subsidiary
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
Net cash provided by financing activities
Effect of translation of foreign denominated cash and cash equivalents
Net increase/(decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Supplementary cash flow information
Cash paid for income taxes
Cash paid for interest, net of amount capitalized
Property, plant and equipment non-cash accruals
The accompanying notes are an integral part of these consolidated financial statements.
110
2017
2016
2015
3,266
2,309
(159)
3,163
(2,877)
(1,242)
(1,102)
1,264
4,565
(120)
(55)
56
28
50
(98)
(314)
6,584
(8,287)
(25)
(3,525)
125
(54)
(789)
(529)
584
(136)
99
—
682
628
212
(22)
35
721
(1,249)
9,483
(5,054)
(227)
832
(919)
1,178
(247)
489
1,549
(330)
(2,750)
3,476
(72)
(1,014)
1,494
480
172
2,668
889
(11,002)
(5,128)
(7,273)
2,240
43
(509)
(656)
827
1,620
(848)
61
245
43
198
(4)
(358)
5,211
(1)
(467)
—
(46)
(127)
—
—
—
—
—
—
(644)
1,379
(118)
(40)
(5,192)
(248)
(2,297)
4,080
(1,946)
—
28
(720)
591
(202)
737
2,260
(293)
(1,150)
840
(19)
840
654
1,494
194
1,820
773
2,024
7
2,373
(483)
727
536
(94)
(20)
410
(131)
69
(43)
(645)
4,571
(622)
—
—
(49)
(101)
—
—
—
—
(106)
—
146
—
59
13
(7,933)
(487)
1,507
3,767
(1,023)
—
615
(680)
670
(114)
—
57
(288)
(950)
3,074
143
(145)
799
654
80
1,835
1,222
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
INDEX
1. BUSINESS OVERVIEW
1. Business Overview
2. Significant Accounting Policies
3. Changes in Accounting Policies
4. Segmented Information
5. Earnings per Common Share
6. Regulatory Matters
7. Acquisitions and Dispositions
8. Accounts Receivable and Other
9.
Inventory
10. Property, Plant and Equipment
11. Variable Interest Entities
12. Long-Term Investments
13. Restricted Long-Term Investments
14.
Intangible Assets
15. Goodwill
16. Accounts Payable and Other
17. Debt
18. Asset Retirement Obligations
19. Noncontrolling Interests
20. Share Capital
21. Stock Option and Stock Unit Plans
22. Components of Accumulated Other Comprehensive Income/(Loss)
23. Risk Management and Financial Instruments
24.
Income Taxes
25. Pension and Other Postretirement Benefits
26. Changes in Operating Assets and Liabilities
27. Related Party Transactions
28. Commitments and Contingencies
29. Guarantees
30. Subsequent Events
31. Quarterly Financial Data
Page
113
114
123
128
130
130
133
139
139
139
140
145
147
148
149
150
151
155
156
159
162
164
166
178
181
188
189
190
192
194
194
The terms “we,” “our,” “us” and “Enbridge” as used in this report refer collectively to Enbridge Inc. and its
subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are
not intended as a precise description of any separate legal entity within Enbridge Inc.
Enbridge is a publicly traded energy transportation and distribution company. We conduct our business
through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution;
Green Power and Transmission; and Energy Services. These reporting segments are strategic business
units established by senior management to facilitate the achievement of our long-term objectives, to aid in
resource allocation decisions and to assess operational performance.
LIQUIDS PIPELINES
Liquids Pipelines consists of common carrier and contract pipelines that transport crude oil, natural gas
liquids (NGL) and refined products and terminals in Canada and the United States, including Canadian
Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Mid-Continent and
Gulf Coast, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and
Other.
GAS TRANSMISSION AND MIDSTREAM
Gas Transmission and Midstream, formerly referred to as Gas Pipelines and Processing, consists of
investments in natural gas pipelines and gathering and processing facilities. Investments in natural gas
pipelines include our interests in US Gas Transmission, Canadian Gas Transmission and Midstream,
Alliance Pipeline, US Midstream and Other. Investments in natural gas processing include our interest in
Aux Sable, a natural gas extraction and fractionation business located near the terminus of the Alliance
Pipeline; Canadian Gas Transmission and Midstream assets located in northeast British Columbia and
northwest Alberta; and DCP Midstream, LLC (DCP Midstream) assets located primarily in Texas and
Oklahoma.
GAS DISTRIBUTION
Gas Distribution consists of our natural gas utility operations, the core of which are Enbridge Gas
Distribution Inc. (EGD) and Union Gas Limited (Union Gas), which serves residential, commercial and
industrial customers, primarily located in Ontario. This business segment also includes our investment in
Noverco Inc. (Noverco) and Other Gas Distribution and Storage.
GREEN POWER AND TRANSMISSION
Green Power and Transmission consists of our investments in renewable energy assets and transmission
facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities
and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United
States primarily in Colorado, Texas, Indiana and West Virginia. We also have assets under development
The Energy Services businesses in Canada and the United States undertake physical commodity
marketing activity and logistical services, oversee refinery supply services and manage our volume
located in Europe.
ENERGY SERVICES
commitments on various pipeline systems.
ELIMINATIONS AND OTHER
In addition to the segments noted above, Eliminations and Other includes operating and administrative
costs and foreign exchange costs which are not allocated to business segments. Also included in
Eliminations and Other are new business development activities, general corporate investments and
elimination of transactions between segments required to present financial performance and financial
position on a consolidated basis.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS OVERVIEW
INDEX
1. Business Overview
2. Significant Accounting Policies
3. Changes in Accounting Policies
4. Segmented Information
5. Earnings per Common Share
6. Regulatory Matters
7. Acquisitions and Dispositions
8. Accounts Receivable and Other
9.
Inventory
10. Property, Plant and Equipment
11. Variable Interest Entities
12. Long-Term Investments
13. Restricted Long-Term Investments
14.
Intangible Assets
15. Goodwill
16. Accounts Payable and Other
17. Debt
18. Asset Retirement Obligations
19. Noncontrolling Interests
20. Share Capital
21. Stock Option and Stock Unit Plans
22. Components of Accumulated Other Comprehensive Income/(Loss)
23. Risk Management and Financial Instruments
24.
Income Taxes
25. Pension and Other Postretirement Benefits
26. Changes in Operating Assets and Liabilities
27. Related Party Transactions
28. Commitments and Contingencies
29. Guarantees
30. Subsequent Events
31. Quarterly Financial Data
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The terms “we,” “our,” “us” and “Enbridge” as used in this report refer collectively to Enbridge Inc. and its
subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are
not intended as a precise description of any separate legal entity within Enbridge Inc.
Enbridge is a publicly traded energy transportation and distribution company. We conduct our business
through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution;
Green Power and Transmission; and Energy Services. These reporting segments are strategic business
units established by senior management to facilitate the achievement of our long-term objectives, to aid in
resource allocation decisions and to assess operational performance.
LIQUIDS PIPELINES
Liquids Pipelines consists of common carrier and contract pipelines that transport crude oil, natural gas
liquids (NGL) and refined products and terminals in Canada and the United States, including Canadian
Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Mid-Continent and
Gulf Coast, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and
Other.
GAS TRANSMISSION AND MIDSTREAM
Gas Transmission and Midstream, formerly referred to as Gas Pipelines and Processing, consists of
investments in natural gas pipelines and gathering and processing facilities. Investments in natural gas
pipelines include our interests in US Gas Transmission, Canadian Gas Transmission and Midstream,
Alliance Pipeline, US Midstream and Other. Investments in natural gas processing include our interest in
Aux Sable, a natural gas extraction and fractionation business located near the terminus of the Alliance
Pipeline; Canadian Gas Transmission and Midstream assets located in northeast British Columbia and
northwest Alberta; and DCP Midstream, LLC (DCP Midstream) assets located primarily in Texas and
Oklahoma.
GAS DISTRIBUTION
Gas Distribution consists of our natural gas utility operations, the core of which are Enbridge Gas
Distribution Inc. (EGD) and Union Gas Limited (Union Gas), which serves residential, commercial and
industrial customers, primarily located in Ontario. This business segment also includes our investment in
Noverco Inc. (Noverco) and Other Gas Distribution and Storage.
GREEN POWER AND TRANSMISSION
Green Power and Transmission consists of our investments in renewable energy assets and transmission
facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities
and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United
States primarily in Colorado, Texas, Indiana and West Virginia. We also have assets under development
located in Europe.
ENERGY SERVICES
The Energy Services businesses in Canada and the United States undertake physical commodity
marketing activity and logistical services, oversee refinery supply services and manage our volume
commitments on various pipeline systems.
ELIMINATIONS AND OTHER
In addition to the segments noted above, Eliminations and Other includes operating and administrative
costs and foreign exchange costs which are not allocated to business segments. Also included in
Eliminations and Other are new business development activities, general corporate investments and
elimination of transactions between segments required to present financial performance and financial
position on a consolidated basis.
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ACQUISITION OF SPECTRA ENERGY CORP
On February 27, 2017, Enbridge and Spectra Energy Corp (Spectra Energy) combined in a stock-for-
stock merger transaction (the Merger Transaction) for a purchase price of $37.5 billion. Under the terms
of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each
share of Spectra Energy common stock that they owned, giving us 100% ownership of Spectra Energy.
Please refer to Note 7 - Acquisitions and Dispositions for further discussion of the transaction.
CANADIAN RESTRUCTURING PLAN
Effective September 1, 2015, under an agreement with Enbridge Income Fund (the Fund) and Enbridge
Income Fund Holdings Inc. (ENF), Enbridge transferred its Canadian Liquids Pipelines business, held by
Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian
renewable energy assets to the Fund Group (comprising the Fund, Enbridge Commercial Trust (ECT),
Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) for consideration valued at $30.4
billion plus incentive distribution and performance rights (the Canadian Restructuring Plan). The
consideration that we received included $18.7 billion of units in the Fund Group, comprised of $3 billion of
Fund units and $15.7 billion of equity units of EIPLP, in which the Fund has an interest. The Fund Group
also assumed debt of EPI and EPAI of approximately $11.7 billion.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements are prepared in accordance with generally accepted accounting
principles in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless
otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use
U.S. GAAP for purposes of meeting both our Canadian and United States continuous disclosure
requirements.
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); purchase price
allocations (Note 7); unbilled revenues; depreciation rates and carrying value of property, plant and
equipment (Note 10); amortization rates of intangible assets (Note 14); measurement of goodwill (Note 15); fair
value of asset retirement obligations (ARO) (Note 18); 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 28); and estimates of losses related to environmental remediation obligations (Note 28). Actual results
could differ from these estimates.
Effective September 30, 2017, we combined Cash and cash equivalents and amounts previously
presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling
arrangements. As at December 31, 2017, $0.6 billion (December 31, 2016 - $0.6 billion) of Bank
indebtedness has been combined within Cash and cash equivalents in our Consolidated Statements of
Financial Position. Net cash provided by financing activities in the Consolidated Statements of Cash
Flows for the years ended December 31, 2016 and 2015 have decreased by $0.3 billion and increased by
$0.1 billion, respectively, to reflect this change.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include our accounts and accounts of our subsidiaries and variable
interest entities (VIEs) for which we are the primary beneficiary. A VIE is a legal entity that does not have
sufficient equity at risk to finance its activities without additional subordinated financial support or is
structured such that equity investors lack the ability to make significant decisions relating to the entity’s
operations through voting rights or do not substantively participate in the gains and losses of the entity.
Upon inception of a contractual agreement, we perform an assessment to determine whether the
arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The
primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the
entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the
VIE entity that could potentially be significant to the VIE. Where we conclude that we are the primary
beneficiary of a VIE, we will consolidate the accounts of that VIE. We assess all variable interests in the
entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors
that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards
sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We
assess the primary beneficiary determination for a VIE on an ongoing basis, as there are changes in the
facts and circumstances related to a VIE. The consolidated financial statements also include the accounts
of any limited partnerships where we represent the general partner and, based on all facts and
circumstances, control such limited partnerships, unless the limited partner has substantive participating
rights or substantive kick-out rights. For certain investments where we retain an undivided interest in
assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. If
an entity is determined to not be a VIE, the voting interest entity model will be applied.
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 we exercise significant
influence are accounted for using the equity method.
As a result of the Canadian Restructuring Plan, ECT, our subsidiary, determines its equity investment
earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the
HLBV method to its equity method investments where cash distributions, including both preference and
residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a
calculation is prepared at each balance sheet date to determine the amount that ECT would receive if
EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash
to the investors. The difference between the calculated liquidation distribution amounts at the beginning
and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s
share of the earnings or losses from the equity investment for the period.
While ECT and EIPLP are both consolidated in these financial statements, the use of the HLBV method
by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s
Consolidated Statements of Earnings. We continue to recognize Redeemable noncontrolling interests on
the Consolidated Statements of Financial Position at the maximum redemption value of the trust units
held by third parties, which references the market price of ENF common shares.
REGULATION
Certain parts of our 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), the Ontario Energy Board (OEB)
and La Régie de l’Energie du Québec. 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 or expected to be paid to cover future abandonment costs in relation to the
NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred
amounts and other assets and current regulatory assets are recorded in Accounts receivable and other.
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ACQUISITION OF SPECTRA ENERGY CORP
On February 27, 2017, Enbridge and Spectra Energy Corp (Spectra Energy) combined in a stock-for-
stock merger transaction (the Merger Transaction) for a purchase price of $37.5 billion. Under the terms
of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each
share of Spectra Energy common stock that they owned, giving us 100% ownership of Spectra Energy.
Please refer to Note 7 - Acquisitions and Dispositions for further discussion of the transaction.
CANADIAN RESTRUCTURING PLAN
Effective September 1, 2015, under an agreement with Enbridge Income Fund (the Fund) and Enbridge
Income Fund Holdings Inc. (ENF), Enbridge transferred its Canadian Liquids Pipelines business, held by
Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian
renewable energy assets to the Fund Group (comprising the Fund, Enbridge Commercial Trust (ECT),
Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) for consideration valued at $30.4
billion plus incentive distribution and performance rights (the Canadian Restructuring Plan). The
consideration that we received included $18.7 billion of units in the Fund Group, comprised of $3 billion of
Fund units and $15.7 billion of equity units of EIPLP, in which the Fund has an interest. The Fund Group
also assumed debt of EPI and EPAI of approximately $11.7 billion.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements are prepared in accordance with generally accepted accounting
principles in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless
otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use
U.S. GAAP for purposes of meeting both our Canadian and United States continuous disclosure
requirements.
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); purchase price
allocations (Note 7); unbilled revenues; depreciation rates and carrying value of property, plant and
equipment (Note 10); amortization rates of intangible assets (Note 14); measurement of goodwill (Note 15); fair
value of asset retirement obligations (ARO) (Note 18); 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 28); and estimates of losses related to environmental remediation obligations (Note 28). Actual results
could differ from these estimates.
Effective September 30, 2017, we combined Cash and cash equivalents and amounts previously
presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling
arrangements. As at December 31, 2017, $0.6 billion (December 31, 2016 - $0.6 billion) of Bank
indebtedness has been combined within Cash and cash equivalents in our Consolidated Statements of
Financial Position. Net cash provided by financing activities in the Consolidated Statements of Cash
Flows for the years ended December 31, 2016 and 2015 have decreased by $0.3 billion and increased by
$0.1 billion, respectively, to reflect this change.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include our accounts and accounts of our subsidiaries and variable
interest entities (VIEs) for which we are the primary beneficiary. A VIE is a legal entity that does not have
sufficient equity at risk to finance its activities without additional subordinated financial support or is
structured such that equity investors lack the ability to make significant decisions relating to the entity’s
operations through voting rights or do not substantively participate in the gains and losses of the entity.
Upon inception of a contractual agreement, we perform an assessment to determine whether the
arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The
primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the
entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the
VIE entity that could potentially be significant to the VIE. Where we conclude that we are the primary
beneficiary of a VIE, we will consolidate the accounts of that VIE. We assess all variable interests in the
entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors
that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards
sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We
assess the primary beneficiary determination for a VIE on an ongoing basis, as there are changes in the
facts and circumstances related to a VIE. The consolidated financial statements also include the accounts
of any limited partnerships where we represent the general partner and, based on all facts and
circumstances, control such limited partnerships, unless the limited partner has substantive participating
rights or substantive kick-out rights. For certain investments where we retain an undivided interest in
assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. If
an entity is determined to not be a VIE, the voting interest entity model will be applied.
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 we exercise significant
influence are accounted for using the equity method.
As a result of the Canadian Restructuring Plan, ECT, our subsidiary, determines its equity investment
earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the
HLBV method to its equity method investments where cash distributions, including both preference and
residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a
calculation is prepared at each balance sheet date to determine the amount that ECT would receive if
EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash
to the investors. The difference between the calculated liquidation distribution amounts at the beginning
and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s
share of the earnings or losses from the equity investment for the period.
While ECT and EIPLP are both consolidated in these financial statements, the use of the HLBV method
by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s
Consolidated Statements of Earnings. We continue to recognize Redeemable noncontrolling interests on
the Consolidated Statements of Financial Position at the maximum redemption value of the trust units
held by third parties, which references the market price of ENF common shares.
REGULATION
Certain parts of our 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), the Ontario Energy Board (OEB)
and La Régie de l’Energie du Québec. 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 or expected to be paid to cover future abandonment costs in relation to the
NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred
amounts and other assets and current regulatory assets are recorded in Accounts receivable and other.
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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 we identify
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 our expectations, the timing and amount of recovery or settlement of regulatory balances could differ
significantly from those recorded. In the absence of rate regulation, we 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,
we would capitalize interest using a capitalization rate based on its cost of borrowing, whereas 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 6).
With the approval of the applicable regulator, EGD, Union Gas and certain distribution operations
capitalize a percentage of specified 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 our expectations, 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 that 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 revenues from liquids and gas pipeline businesses 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 rateably 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. We
recognize 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.
Certain offshore pipeline transportation contracts require Enbridge to provide transportation services for
the life of the underlying producing fields. Under these arrangements, shippers pay Enbridge a fixed
monthly toll for a defined period of time which may be shorter than the estimated reserve life of the
underlying producing fields, resulting in a contract period which extends past the period of cash collection.
Fixed monthly toll revenues are recognized ratably over the committed volume made available to
shippers throughout the contract period, regardless of when cash is received. For the years ended
December 31, 2017, 2016 and 2015, cash received net of revenue recognized for contracts under make-
up rights and similar deferred revenue arrangements was $196 million, $249 million, and $61 million,
respectively.
For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying
agreements as approved by the regulators. 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 our distribution franchise area. Since July 1, 2011,
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, we
prospectively discontinued the application of rate-regulated accounting for those assets with the
exception of flow-through income taxes covered by specific rate orders.
For our energy marketing contracts, 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
We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign
exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is
optional and requires Enbridge 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. We present the earnings effects of hedging items with the hedged transaction. Derivatives
in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net
We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange
rates, interest rates and certain compensation tied to our 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
investment hedges.
Cash Flow Hedges
in which they occur.
Fair Value Hedges
We use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the
hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability
that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be
effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases
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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 we identify
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 our expectations, the timing and amount of recovery or settlement of regulatory balances could differ
significantly from those recorded. In the absence of rate regulation, we 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,
we would capitalize interest using a capitalization rate based on its cost of borrowing, whereas 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 6).
With the approval of the applicable regulator, EGD, Union Gas and certain distribution operations
capitalize a percentage of specified 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 our expectations, 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 that 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 revenues from liquids and gas pipeline businesses 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 rateably 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. We
recognize 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.
Certain offshore pipeline transportation contracts require Enbridge to provide transportation services for
the life of the underlying producing fields. Under these arrangements, shippers pay Enbridge a fixed
monthly toll for a defined period of time which may be shorter than the estimated reserve life of the
underlying producing fields, resulting in a contract period which extends past the period of cash collection.
Fixed monthly toll revenues are recognized ratably over the committed volume made available to
shippers throughout the contract period, regardless of when cash is received. For the years ended
December 31, 2017, 2016 and 2015, cash received net of revenue recognized for contracts under make-
up rights and similar deferred revenue arrangements was $196 million, $249 million, and $61 million,
respectively.
For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying
agreements as approved by the regulators. 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 our distribution franchise area. Since July 1, 2011,
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, we
prospectively discontinued the application of rate-regulated accounting for those assets with the
exception of flow-through income taxes covered by specific rate orders.
For our energy marketing contracts, 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
We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign
exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is
optional and requires Enbridge 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. We present the earnings effects of hedging items with the hedged transaction. Derivatives
in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net
investment hedges.
Cash Flow Hedges
We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange
rates, interest rates and certain compensation tied to our 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
We use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the
hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability
that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be
effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases
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to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the
hedged item is recognized in earnings over the remaining life of the hedged item.
Net Investment Hedges
Gains and losses arising from translation of net investment in foreign operations from their functional
currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation
adjustments (CTA). We designate foreign currency derivatives and United States dollar denominated debt
as hedges of net investments in United States dollar denominated foreign operations. As a result, the
effective portion of the change in the fair value of the foreign currency derivatives as well as the
translation of United States dollar denominated debt are reflected in OCI and any ineffectiveness is
reflected in current period earnings. Amounts recognized previously in Accumulated other comprehensive
income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment
resulting from disposal of a foreign operation.
Classification of Derivatives
We recognize the fair market value of derivative instruments on the Consolidated Statements of Financial
Position as current and non-current 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 we have the legal right and intention to settle them on a net basis.
Transaction Costs
Transaction costs are incremental costs directly related to the acquisition of a financial asset or the
issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account
for these costs as a deduction from Long-term debt on the Statements of Financial Position. These costs
are amortized using the effective interest rate method over the term of the related debt instrument and are
recorded in Interest expense.
EQUITY INVESTMENTS
Equity investments over which we exercise significant influence, but do not have controlling financial
interests, are accounted for using the equity method. Equity investments are initially measured at cost
and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments
are increased for contributions made to and decreased for distributions received from the investees. To
the extent an equity investee undertakes activities necessary to commence its planned principal
operations, we capitalize interest costs associated with its investment during such period.
RESTRICTED LONG-TERM INVESTMENTS
Long-term investments that are restricted as to withdrawal or usage, for the purposes of the NEB’s LMCI,
are presented as Restricted long-term investments on the Consolidated Statements of Financial Position.
OTHER INVESTMENTS
Generally, we classify equity investments in entities over which we do 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 not owned by us in such entities 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.
The use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling
interests reported on our Consolidated Statements of Earnings.
INCOME TAXES
Income taxes are accounted for using the liability method. 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. For our regulated
operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or
liability, respectively, to the extent taxes can be recovered through rates. 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 Enbridge or a reporting subsidiary
operates, referred to as the functional currency. Transactions denominated in foreign currencies are
translated into the functional 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 our Canadian
dollar presentation currency are included in the CTA 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
Cash and cash equivalents include short-term investments with a term to maturity of three months or less
exchange rates.
CASH AND CASH EQUIVALENTS
when purchased.
RESTRICTED CASH
Position.
LOANS AND RECEIVABLES
Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific
commercial arrangements, are presented as Restricted cash on the Consolidated Statements of Financial
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.
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to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the
hedged item is recognized in earnings over the remaining life of the hedged item.
Net Investment Hedges
Gains and losses arising from translation of net investment in foreign operations from their functional
currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation
adjustments (CTA). We designate foreign currency derivatives and United States dollar denominated debt
as hedges of net investments in United States dollar denominated foreign operations. As a result, the
effective portion of the change in the fair value of the foreign currency derivatives as well as the
translation of United States dollar denominated debt are reflected in OCI and any ineffectiveness is
reflected in current period earnings. Amounts recognized previously in Accumulated other comprehensive
income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment
resulting from disposal of a foreign operation.
Classification of Derivatives
We recognize the fair market value of derivative instruments on the Consolidated Statements of Financial
Position as current and non-current 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 we have the legal right and intention to settle them on a net basis.
Transaction Costs
Transaction costs are incremental costs directly related to the acquisition of a financial asset or the
issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account
for these costs as a deduction from Long-term debt on the Statements of Financial Position. These costs
are amortized using the effective interest rate method over the term of the related debt instrument and are
recorded in Interest expense.
EQUITY INVESTMENTS
Equity investments over which we exercise significant influence, but do not have controlling financial
interests, are accounted for using the equity method. Equity investments are initially measured at cost
and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments
are increased for contributions made to and decreased for distributions received from the investees. To
the extent an equity investee undertakes activities necessary to commence its planned principal
operations, we capitalize interest costs associated with its investment during such period.
RESTRICTED LONG-TERM INVESTMENTS
Long-term investments that are restricted as to withdrawal or usage, for the purposes of the NEB’s LMCI,
are presented as Restricted long-term investments on the Consolidated Statements of Financial Position.
OTHER INVESTMENTS
Generally, we classify equity investments in entities over which we do 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 not owned by us in such entities 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.
The use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling
interests reported on our Consolidated Statements of Earnings.
INCOME TAXES
Income taxes are accounted for using the liability method. 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. For our regulated
operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or
liability, respectively, to the extent taxes can be recovered through rates. 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 Enbridge or a reporting subsidiary
operates, referred to as the functional currency. Transactions denominated in foreign currencies are
translated into the functional 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 our Canadian
dollar presentation currency are included in the CTA 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
commercial arrangements, 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.
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ALLOWANCE FOR DOUBTFUL ACCOUNTS
Allowance for doubtful accounts is determined based on collection history. When we have 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.
NATURAL GAS IMBALANCES
The Consolidated Statements of Financial Position include in-kind balances as a result of differences in
gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind,
changes in the balances do not have an effect on our Consolidated Statements of Earnings or
Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural
gas market index prices as at the balance sheet dates.
INVENTORY
Inventory is comprised of natural gas in storage held in EGD and Union Gas, and crude oil and natural
gas held primarily by energy services businesses in the Energy Services segment. Natural gas in storage
in EGD and Union Gas 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 on 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. We
capitalize 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 group assets are retired or otherwise disposed of, gains and losses are
generally 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; and derivative financial
instruments.
INTANGIBLE ASSETS
Intangible assets consist primarily of certain software costs, customer relationships and emission
allowances. We capitalize costs incurred during the application development stage of internal use
software projects. Customer relationships represent the underlying relationship from long-term
agreements with customers that are capitalized upon acquisition. Emission allowances, which are
recorded at their original cost, are purchased in order to meet greenhouse gas (GHG) compliance
obligations. Intangible assets are generally amortized on a straight-line basis over their expected lives,
commencing when the asset is available for use, with the exception of emission allowances, which are
not amortized as they will be used to satisfy compliance obligations as they come due.
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.
We perform our annual review for impairment at the reporting unit level, which is identified by assessing
whether the components of our operating segments constitute businesses for which discrete information
is available, whether segment management regularly reviews the operating results of those components
and whether the economic and regulatory characteristics are similar. We determined that our reporting
units are equivalent to our reportable segments, with the exception of the gas transmission and gas
midstream reportable segment which is divided at the component level into two reporting units. We have
the option to first assess qualitative factors to determine whether it is necessary to perform the
quantitative goodwill impairment test. The quantitative goodwill impairment test involves determining the
fair value of our reporting units 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 at the amount by which the reporting unit’s carrying value exceeds its fair value.
This amount should not exceed the carrying amount of goodwill.
IMPAIRMENT
We review the carrying values of our 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, we calculate fair value based on the discounted cash flows and write the assets down to the
extent that the carrying value exceeds the fair value.
With respect to investments in debt and equity securities, we assess 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 objective evidence of impairment, we value the
expected discounted cash flows using observable market inputs and determine 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, we assess the assets for impairment when there is no longer
reasonable assurance of timely collection. If evidence of impairment is noted, we reduce 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
Accounts payable and other or 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.
AROs are added to the carrying value of the associated asset and depreciated over the asset’s useful life.
The corresponding liability is accreted over time through charges to earnings and is reduced by actual
costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of
changes in cost estimates and regulatory requirements.
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ALLOWANCE FOR DOUBTFUL ACCOUNTS
Allowance for doubtful accounts is determined based on collection history. When we have 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.
NATURAL GAS IMBALANCES
The Consolidated Statements of Financial Position include in-kind balances as a result of differences in
gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind,
changes in the balances do not have an effect on our Consolidated Statements of Earnings or
Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural
gas market index prices as at the balance sheet dates.
INVENTORY
Inventory is comprised of natural gas in storage held in EGD and Union Gas, and crude oil and natural
gas held primarily by energy services businesses in the Energy Services segment. Natural gas in storage
in EGD and Union Gas 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 on 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. We
capitalize 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 group assets are retired or otherwise disposed of, gains and losses are
generally 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; and derivative financial
instruments.
INTANGIBLE ASSETS
Intangible assets consist primarily of certain software costs, customer relationships and emission
allowances. We capitalize costs incurred during the application development stage of internal use
software projects. Customer relationships represent the underlying relationship from long-term
agreements with customers that are capitalized upon acquisition. Emission allowances, which are
recorded at their original cost, are purchased in order to meet greenhouse gas (GHG) compliance
obligations. Intangible assets are generally amortized on a straight-line basis over their expected lives,
commencing when the asset is available for use, with the exception of emission allowances, which are
not amortized as they will be used to satisfy compliance obligations as they come due.
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.
We perform our annual review for impairment at the reporting unit level, which is identified by assessing
whether the components of our operating segments constitute businesses for which discrete information
is available, whether segment management regularly reviews the operating results of those components
and whether the economic and regulatory characteristics are similar. We determined that our reporting
units are equivalent to our reportable segments, with the exception of the gas transmission and gas
midstream reportable segment which is divided at the component level into two reporting units. We have
the option to first assess qualitative factors to determine whether it is necessary to perform the
quantitative goodwill impairment test. The quantitative goodwill impairment test involves determining the
fair value of our reporting units 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 at the amount by which the reporting unit’s carrying value exceeds its fair value.
This amount should not exceed the carrying amount of goodwill.
IMPAIRMENT
We review the carrying values of our 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, we calculate fair value based on the discounted cash flows and write the assets down to the
extent that the carrying value exceeds the fair value.
With respect to investments in debt and equity securities, we assess 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 objective evidence of impairment, we value the
expected discounted cash flows using observable market inputs and determine 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, we assess the assets for impairment when there is no longer
reasonable assurance of timely collection. If evidence of impairment is noted, we reduce 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
Accounts payable and other or 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.
AROs are added to the carrying value of the associated asset and depreciated over the asset’s useful life.
The corresponding liability is accreted over time through charges to earnings and is reduced by actual
costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of
changes in cost estimates and regulatory requirements.
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RETIREMENT AND POSTRETIREMENT BENEFITS
We maintain 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.
We use mortality tables issued by the Society of Actuaries in the United States (revised in 2016) and the
Canadian Institute of Actuaries tables (revised in 2014) to measure our benefit obligations of our United
States pension plan (the United States Plan) and our Canadian pension plans (the Canadian Plans),
respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds
with maturities that approximate the timing of future payments we anticipate making under each of the
respective plans. Pension cost is charged to earnings and includes:
• Cost of pension plan benefits provided in exchange for employee services rendered during the
year;
•
Interest cost of pension plan obligations;
• Expected return on pension plan assets;
• 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; and
• Amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the
greater of the accrued benefit obligation or the fair value of plan assets, over the expected
average remaining service life of the active employee group covered by the plans.
Actuarial gains and losses arise from the difference between the actual and expected rate of return on
plan assets for that period or from changes in actuarial assumptions used to determine the accrued
benefit obligation, including discount rate, 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 Enbridge are expensed in the period in which the
contribution occurs.
We also provide 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, Accounts payable and other or Other long-term liabilities, 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 Enbridge record regulatory adjustments to reflect the difference
between pension expense and OPEB costs for accounting purposes and the pension expense and OPEB
costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent
pension expense or OPEB costs are expected to be collected from or refunded to customers,
respectively, in future rates. 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.
Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each
reporting period. RSUs 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 Enbridge’s
shares with an offset to Accounts payable and other or to Other long-term liabilities.
COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental
regulations that relate to past or current operations. We expense costs incurred for remediation of existing
environmental contamination caused by past operations that do not benefit future periods by preventing
or eliminating future contamination. We record 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. Our 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. We evaluate recoveries from insurance coverage
separately from the liability and, when recovery is probable, we record and report an asset separately
from the associated liability in the Consolidated Statements of Financial Position.
Liabilities for other commitments and contingencies are recognized when, after fully analyzing available
information, we determine 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, we recognize the most likely amount, or if no amount is more likely than another,
the minimum of the range of probable loss is accrued. We expense legal costs associated with loss
contingencies as such costs are incurred.
3. CHANGES IN ACCOUNTING POLICIES
CHANGES IN ACCOUNTING POLICIES
Goodwill
We previously performed our annual goodwill impairment test on October 1 of each fiscal year. Beginning
with the quarter ended December 31, 2017, we moved the annual goodwill impairment test from October
1 to April 1 to better align with the preparation and review of our business plan, which is used in the test.
The change does not delay, accelerate or avoid an impairment charge.
ADOPTION OF NEW STANDARDS
Simplifying the Measurement of Goodwill Impairment
Effective January 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 and applied
the standard on a prospective basis. Under the new guidance, goodwill impairment will now be the
amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed
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RETIREMENT AND POSTRETIREMENT BENEFITS
We maintain 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.
We use mortality tables issued by the Society of Actuaries in the United States (revised in 2016) and the
Canadian Institute of Actuaries tables (revised in 2014) to measure our benefit obligations of our United
States pension plan (the United States Plan) and our Canadian pension plans (the Canadian Plans),
respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds
with maturities that approximate the timing of future payments we anticipate making under each of the
respective plans. Pension cost is charged to earnings and includes:
• Cost of pension plan benefits provided in exchange for employee services rendered during the
year;
•
Interest cost of pension plan obligations;
• Expected return on pension plan assets;
• 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; and
• Amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the
greater of the accrued benefit obligation or the fair value of plan assets, over the expected
average remaining service life of the active employee group covered by the plans.
Actuarial gains and losses arise from the difference between the actual and expected rate of return on
plan assets for that period or from changes in actuarial assumptions used to determine the accrued
benefit obligation, including discount rate, 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 Enbridge are expensed in the period in which the
contribution occurs.
We also provide 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, Accounts payable and other or Other long-term liabilities, 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 Enbridge record regulatory adjustments to reflect the difference
between pension expense and OPEB costs for accounting purposes and the pension expense and OPEB
costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent
pension expense or OPEB costs are expected to be collected from or refunded to customers,
respectively, in future rates. 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.
Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each
reporting period. RSUs 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 Enbridge’s
shares with an offset to Accounts payable and other or to Other long-term liabilities.
COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental
regulations that relate to past or current operations. We expense costs incurred for remediation of existing
environmental contamination caused by past operations that do not benefit future periods by preventing
or eliminating future contamination. We record 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. Our 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. We evaluate recoveries from insurance coverage
separately from the liability and, when recovery is probable, we record and report an asset separately
from the associated liability in the Consolidated Statements of Financial Position.
Liabilities for other commitments and contingencies are recognized when, after fully analyzing available
information, we determine 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, we recognize the most likely amount, or if no amount is more likely than another,
the minimum of the range of probable loss is accrued. We expense legal costs associated with loss
contingencies as such costs are incurred.
3. CHANGES IN ACCOUNTING POLICIES
CHANGES IN ACCOUNTING POLICIES
Goodwill
We previously performed our annual goodwill impairment test on October 1 of each fiscal year. Beginning
with the quarter ended December 31, 2017, we moved the annual goodwill impairment test from October
1 to April 1 to better align with the preparation and review of our business plan, which is used in the test.
The change does not delay, accelerate or avoid an impairment charge.
ADOPTION OF NEW STANDARDS
Simplifying the Measurement of Goodwill Impairment
Effective January 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 and applied
the standard on a prospective basis. Under the new guidance, goodwill impairment will now be the
amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed
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the carrying amount of goodwill. We applied this standard as at December 31, 2017 in the measurement
of the goodwill impairment relating to the gas midstream reporting unit (Note 15).
Clarifying the Definition of a Business in an Acquisition
Effective January 1, 2017, we early adopted ASU 2017-01 on a prospective basis. The new standard was
issued with the objective of adding guidance to assist entities with evaluating whether transactions should
be accounted for as acquisitions (disposals) of assets or businesses. This accounting update was applied
to acquisitions and dispositions that occurred in the year.
Accounting for Intra-Entity Asset Transfers
Effective January 1, 2017, we early adopted ASU 2016-16 on a modified retrospective basis. The new
standard was issued with the intent of improving the accounting for the income tax consequences of intra-
entity asset transfers other than inventory. Under the new guidance, an entity should recognize the
income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer
occurs. The adoption of the pronouncement did not have a material impact on our consolidated financial
statements.
Improvements to Employee Share-Based Payment Accounting
Effective January 1, 2017, we adopted ASU 2016-09 and applied certain amendments on a modified
retrospective basis with the remaining amendments applied on a prospective basis. The new standard
was issued with the intent of simplifying and improving several aspects of accounting for share-based
payment transactions including the income tax consequences, classification of awards as either equity or
liabilities, and classification on the statement of cash flows. The adoption of the pronouncement did not
have a material impact on our consolidated financial statements.
Simplifying the Embedded Derivatives Analysis for Debt Instruments
Effective January 1, 2017, we adopted ASU 2016-06 on a modified retrospective basis. The new
guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or
put options. The adoption of the pronouncement did not have a material impact on our consolidated
financial statements.
FUTURE ACCOUNTING POLICY CHANGES
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
ASU 2018-02 was issued in February 2018 to address a specific consequence of the Tax Cuts and Jobs
Act (TCJA). This accounting update allows a reclassification from accumulated other comprehensive
income to retained earnings for stranded tax effects resulting from TCJA. The amendments eliminate the
stranded tax effects that were created as a result of the reduction of historical U.S. federal corporate
income tax rate to the newly enacted U.S. federal corporate income tax rate. The accounting update is
effective January 1, 2019, with early adoption permitted, and is to be applied either in the period of
adoption or retrospectively to each period in which the effect of the change in the U.S. federal corporate
income tax rate in the TCJA is recognized. We are currently assessing the impact of the new standard on
the consolidated financial statements.
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk
management activities and the resulting hedge accounting reflected in the financial statements. The
accounting update allows cash flow hedging of contractually specified components in financial and non-
financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and
hedging instruments’ fair value changes will be recorded in the same income statement line as the
hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be
performed at any time before the end of the quarter in which the hedge is designated. After initial
quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The
accounting update is effective January 1, 2019 and is to be applied on a modified retrospective basis. We
are currently assessing the impact of the new standard on our consolidated financial statements.
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Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and
Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and
when it should be applied to a change to the terms or conditions of a share based payment award.
when it should be applied to a change to the terms or conditions of a share based payment award.
Under the new guidance, modification accounting is required for all changes to share based payment
Under the new guidance, modification accounting is required for all changes to share based payment
awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the
awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the
vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a
vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a
debt instrument has not changed. The accounting update is effective January 1, 2018 and will be applied
debt instrument has not changed. The accounting update is effective January 1, 2018 and will be applied
on a prospective basis. We do not expect the adoption of this accounting update to have a material
on a prospective basis. We do not expect the adoption of this accounting update to have a material
impact on our consolidated financial statements.
impact on our consolidated financial statements.
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the
earliest call date for certain callable debt securities held at a premium. The accounting update is effective
earliest call date for certain callable debt securities held at a premium. The accounting update is effective
January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the
January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the
impact of the new standard on our consolidated financial statements.
impact of the new standard on our consolidated financial statements.
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the
components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s
components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s
sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net
sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net
benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be
benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be
applied on a retrospective basis for the statement of earnings presentation component and a prospective
applied on a retrospective basis for the statement of earnings presentation component and a prospective
basis for the capitalization component. We do not expect the adoption of this accounting update to have a
basis for the capitalization component. We do not expect the adoption of this accounting update to have a
material impact on our consolidated financial statements.
material impact on our consolidated financial statements.
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition
guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of
guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of
nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for
nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for
derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is
derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is
effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the
effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the
adoption of this accounting update to have a material impact on our consolidated financial statements.
adoption of this accounting update to have a material impact on our consolidated financial statements.
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and
presentation of changes in restricted cash and restricted cash equivalents within the statement of cash
presentation of changes in restricted cash and restricted cash equivalents within the statement of cash
flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be
flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be
included within cash and cash equivalents when reconciling the opening and closing period amounts
included within cash and cash equivalents when reconciling the opening and closing period amounts
shown on the statement of cash flows. We currently present the changes in restricted cash and restricted
shown on the statement of cash flows. We currently present the changes in restricted cash and restricted
cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting
cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting
update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the
update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the
presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash
presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash
equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented.
equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented.
Simplifying Cash Flow Classification
ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain
Simplifying Cash Flow Classification
ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain
cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new
cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new
guidance addresses eight specific presentation issues. The accounting update is effective January 1,
guidance addresses eight specific presentation issues. The accounting update is effective January 1,
2018 and will be applied on a retrospective basis. We assessed each of the eight specific presentation
2018 and will be applied on a retrospective basis. We assessed each of the eight specific presentation
issues and the adoption of this ASU does not have a material impact on our consolidated financial
issues and the adoption of this ASU does not have a material impact on our consolidated financial
statements.
statements.
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the carrying amount of goodwill. We applied this standard as at December 31, 2017 in the measurement
of the goodwill impairment relating to the gas midstream reporting unit (Note 15).
Clarifying the Definition of a Business in an Acquisition
Effective January 1, 2017, we early adopted ASU 2017-01 on a prospective basis. The new standard was
issued with the objective of adding guidance to assist entities with evaluating whether transactions should
be accounted for as acquisitions (disposals) of assets or businesses. This accounting update was applied
to acquisitions and dispositions that occurred in the year.
Accounting for Intra-Entity Asset Transfers
Effective January 1, 2017, we early adopted ASU 2016-16 on a modified retrospective basis. The new
standard was issued with the intent of improving the accounting for the income tax consequences of intra-
entity asset transfers other than inventory. Under the new guidance, an entity should recognize the
income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer
occurs. The adoption of the pronouncement did not have a material impact on our consolidated financial
statements.
Improvements to Employee Share-Based Payment Accounting
Effective January 1, 2017, we adopted ASU 2016-09 and applied certain amendments on a modified
retrospective basis with the remaining amendments applied on a prospective basis. The new standard
was issued with the intent of simplifying and improving several aspects of accounting for share-based
payment transactions including the income tax consequences, classification of awards as either equity or
liabilities, and classification on the statement of cash flows. The adoption of the pronouncement did not
have a material impact on our consolidated financial statements.
Simplifying the Embedded Derivatives Analysis for Debt Instruments
Effective January 1, 2017, we adopted ASU 2016-06 on a modified retrospective basis. The new
guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or
put options. The adoption of the pronouncement did not have a material impact on our consolidated
financial statements.
FUTURE ACCOUNTING POLICY CHANGES
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
ASU 2018-02 was issued in February 2018 to address a specific consequence of the Tax Cuts and Jobs
Act (TCJA). This accounting update allows a reclassification from accumulated other comprehensive
income to retained earnings for stranded tax effects resulting from TCJA. The amendments eliminate the
stranded tax effects that were created as a result of the reduction of historical U.S. federal corporate
income tax rate to the newly enacted U.S. federal corporate income tax rate. The accounting update is
effective January 1, 2019, with early adoption permitted, and is to be applied either in the period of
adoption or retrospectively to each period in which the effect of the change in the U.S. federal corporate
income tax rate in the TCJA is recognized. We are currently assessing the impact of the new standard on
the consolidated financial statements.
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk
management activities and the resulting hedge accounting reflected in the financial statements. The
accounting update allows cash flow hedging of contractually specified components in financial and non-
financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and
hedging instruments’ fair value changes will be recorded in the same income statement line as the
hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be
performed at any time before the end of the quarter in which the hedge is designated. After initial
quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The
accounting update is effective January 1, 2019 and is to be applied on a modified retrospective basis. We
are currently assessing the impact of the new standard on our consolidated financial statements.
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Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and
Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and
when it should be applied to a change to the terms or conditions of a share based payment award.
Under the new guidance, modification accounting is required for all changes to share based payment
when it should be applied to a change to the terms or conditions of a share based payment award.
awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the
Under the new guidance, modification accounting is required for all changes to share based payment
awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the
vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a
vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a
debt instrument has not changed. The accounting update is effective January 1, 2018 and will be applied
on a prospective basis. We do not expect the adoption of this accounting update to have a material
debt instrument has not changed. The accounting update is effective January 1, 2018 and will be applied
impact on our consolidated financial statements.
on a prospective basis. We do not expect the adoption of this accounting update to have a material
impact on our consolidated financial statements.
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
earliest call date for certain callable debt securities held at a premium. The accounting update is effective
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the
earliest call date for certain callable debt securities held at a premium. The accounting update is effective
January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the
impact of the new standard on our consolidated financial statements.
January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the
impact of the new standard on our consolidated financial statements.
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the
components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s
components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s
sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net
benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be
sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net
benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be
applied on a retrospective basis for the statement of earnings presentation component and a prospective
applied on a retrospective basis for the statement of earnings presentation component and a prospective
basis for the capitalization component. We do not expect the adoption of this accounting update to have a
material impact on our consolidated financial statements.
basis for the capitalization component. We do not expect the adoption of this accounting update to have a
material impact on our consolidated financial statements.
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition
guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of
nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for
guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of
derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is
nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for
derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is
effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the
adoption of this accounting update to have a material impact on our consolidated financial statements.
effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the
adoption of this accounting update to have a material impact on our consolidated financial statements.
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and
presentation of changes in restricted cash and restricted cash equivalents within the statement of cash
presentation of changes in restricted cash and restricted cash equivalents within the statement of cash
flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be
included within cash and cash equivalents when reconciling the opening and closing period amounts
flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be
included within cash and cash equivalents when reconciling the opening and closing period amounts
shown on the statement of cash flows. We currently present the changes in restricted cash and restricted
shown on the statement of cash flows. We currently present the changes in restricted cash and restricted
cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting
cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting
update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the
presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash
update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the
equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented.
presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash
equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented.
Simplifying Cash Flow Classification
ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain
Simplifying Cash Flow Classification
ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain
cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new
cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new
guidance addresses eight specific presentation issues. The accounting update is effective January 1,
guidance addresses eight specific presentation issues. The accounting update is effective January 1,
2018 and will be applied on a retrospective basis. We assessed each of the eight specific presentation
issues and the adoption of this ASU does not have a material impact on our consolidated financial
2018 and will be applied on a retrospective basis. We assessed each of the eight specific presentation
statements.
issues and the adoption of this ASU does not have a material impact on our consolidated financial
statements.
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Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more
useful information about the expected credit losses on financial instruments and other commitments to
extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss
methodology for recognizing credit losses that delays the recognition until it is probable a loss has been
incurred. The accounting update adds a new impairment model, known as the current expected credit
loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an
entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting
Standards Board believes will result in more timely recognition of such losses. We are currently assessing
the impact of the new standard on our consolidated financial statements. The accounting update is
effective January 1, 2020.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability
among organizations. It requires lessees of operating lease arrangements to recognize lease assets and
lease liabilities on the statement of financial position and disclose additional key information about lease
agreements. The accounting update also replaces the current definition of a lease and requires that an
arrangement be recognized as a lease when a customer has the right to obtain substantially all of the
economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are
currently gathering a complete inventory of our lease contracts in order to assess the impact of the new
standard on our consolidated financial statements. The accounting update is effective January 1, 2019
and will be applied using a modified retrospective approach.
Recognition and Measurement of Financial Assets and Liabilities
ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition,
measurement, presentation and disclosure of financial assets and liabilities. Investments in equity
securities, excluding equity method and consolidated investments, are no longer classified as trading or
available-for-sale securities. All investments in equity securities with readily determinable fair values are
classified as investments at fair value through net income. Investments in equity securities without readily
determinable fair values are measured using the fair value measurement alternative and are recorded at
cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly
transactions for an identical or similar investment of the same issuer. Investments in equity securities
measured using the fair value measurement alternative are reviewed for indicators of impairment each
reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price.
The accounting update is effective January 1, 2018 and applied on a prospective basis. We do not expect
the adoption of this accounting update to have a material impact on our consolidated financial statements.
Revenue from Contracts with Customers
ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability
of revenue recognition practices across entities and industries. The new standard establishes a single,
principles-based five-step model to be applied to all contracts with customers and introduces new and
enhanced disclosure requirements. It also requires the use of more estimates and judgments than the
present standards in addition to additional disclosures. The new standard is effective January 1, 2018.
The new standard permits either a full retrospective method of adoption with restatement of all prior
periods presented, or a modified retrospective method with the cumulative effect of applying the new
standard recognized as an adjustment to opening retained earnings in the period of adoption. We have
decided to adopt the new standard using the modified retrospective method.
We have reviewed our revenue contracts in order to evaluate the effect of the new standard on our
revenue recognition practices. Based on our assessment to-date, the adoption of the new standard will
have the following impact to our financial statements:
• A change in presentation in the Gas Distribution business related to payments to customers
under the earnings sharing mechanism which are currently shown as an expense in the
Consolidated Statements of Earnings. Under the new standard, these payments will be reflected
as a reduction of revenue.
• Estimates of variable consideration, required under the new standard for certain Liquids
Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue
contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue
contracts, may result in changes to the pattern or timing of revenue recognition for those
contracts.
• Non-cash consideration received in the form of a percentage of the products derived from
processing natural gas in the Gas Transmission and Midstream business was previously
accounted for as revenue when the commodity was sold to third parties. Under the new standard,
the non-cash consideration will be accounted for as revenue when processing services are
performed. The commodity will continue to be accounted for as revenue when it is subsequently
sold to third parties. The impact of this change will be an increase in costs and revenues due to
the recognition of this non-cash consideration.
• Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission
and Midstream business whereby Enbridge purchases natural gas at the wellhead, then
processes and subsequently sells the gas, was previously presented as revenue. Under the new
standard, processing fees charged on natural gas purchased by Enbridge are presented as a
reduction of commodity costs upon the transfer of control of the natural gas at the wellhead.
• Revenue from certain contracts in the Gas Transmission and Midstream business that provide for
Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting
processed natural gas and/or NGLs as payment for processing services rendered, commonly
referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously
presented on a gross basis whereby Enbridge recorded one hundred percent of the value of the
natural gas and products sold as revenue, with the cost of the natural gas purchased recorded as
commodity cost. Under the new standard only Enbridge’s share of the products retained and sold
is presented as revenue and no commodity cost is recorded.
• Certain payments received from customers to offset the cost of constructing assets required to
provide services to those customers, referred to as Contributions in Aid of Construction (CIAC)
were previously recorded as reductions of property, plant and equipment regardless of whether
the amounts were imposed by regulation or negotiated. Under the new standard, negotiated
CIACs are deemed to be advance payments for services and must be recognized as revenue
when those future services are provided. Negotiated CIACs will be accounted for as deferred
revenue and recognized over the term of the associated revenue contract.
Upon adoption, we will recognize the significant cumulative effect of initially applying the new standard as
an increase in the opening balance of retained deficit of approximately $120 million, an increase in
property, plant and equipment of $130 million and an increase in deferred revenue of $120 million, subject
to final determination, as at January 1, 2018. The adoption of the new standard will also result in changes
in classification between Revenue and Commodity costs as discussed above.
We have also developed and tested processes to generate the disclosures which will be required under
the new standard commencing in the first quarter of 2018.
126
127
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more
useful information about the expected credit losses on financial instruments and other commitments to
extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss
methodology for recognizing credit losses that delays the recognition until it is probable a loss has been
incurred. The accounting update adds a new impairment model, known as the current expected credit
loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an
entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting
Standards Board believes will result in more timely recognition of such losses. We are currently assessing
the impact of the new standard on our consolidated financial statements. The accounting update is
effective January 1, 2020.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability
among organizations. It requires lessees of operating lease arrangements to recognize lease assets and
lease liabilities on the statement of financial position and disclose additional key information about lease
agreements. The accounting update also replaces the current definition of a lease and requires that an
arrangement be recognized as a lease when a customer has the right to obtain substantially all of the
economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are
currently gathering a complete inventory of our lease contracts in order to assess the impact of the new
standard on our consolidated financial statements. The accounting update is effective January 1, 2019
and will be applied using a modified retrospective approach.
Recognition and Measurement of Financial Assets and Liabilities
ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition,
measurement, presentation and disclosure of financial assets and liabilities. Investments in equity
securities, excluding equity method and consolidated investments, are no longer classified as trading or
available-for-sale securities. All investments in equity securities with readily determinable fair values are
classified as investments at fair value through net income. Investments in equity securities without readily
determinable fair values are measured using the fair value measurement alternative and are recorded at
cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly
transactions for an identical or similar investment of the same issuer. Investments in equity securities
measured using the fair value measurement alternative are reviewed for indicators of impairment each
reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price.
The accounting update is effective January 1, 2018 and applied on a prospective basis. We do not expect
the adoption of this accounting update to have a material impact on our consolidated financial statements.
Revenue from Contracts with Customers
ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability
of revenue recognition practices across entities and industries. The new standard establishes a single,
principles-based five-step model to be applied to all contracts with customers and introduces new and
enhanced disclosure requirements. It also requires the use of more estimates and judgments than the
present standards in addition to additional disclosures. The new standard is effective January 1, 2018.
The new standard permits either a full retrospective method of adoption with restatement of all prior
periods presented, or a modified retrospective method with the cumulative effect of applying the new
standard recognized as an adjustment to opening retained earnings in the period of adoption. We have
decided to adopt the new standard using the modified retrospective method.
We have reviewed our revenue contracts in order to evaluate the effect of the new standard on our
revenue recognition practices. Based on our assessment to-date, the adoption of the new standard will
have the following impact to our financial statements:
• A change in presentation in the Gas Distribution business related to payments to customers
under the earnings sharing mechanism which are currently shown as an expense in the
Consolidated Statements of Earnings. Under the new standard, these payments will be reflected
as a reduction of revenue.
• Estimates of variable consideration, required under the new standard for certain Liquids
Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue
contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue
contracts, may result in changes to the pattern or timing of revenue recognition for those
contracts.
• Non-cash consideration received in the form of a percentage of the products derived from
processing natural gas in the Gas Transmission and Midstream business was previously
accounted for as revenue when the commodity was sold to third parties. Under the new standard,
the non-cash consideration will be accounted for as revenue when processing services are
performed. The commodity will continue to be accounted for as revenue when it is subsequently
sold to third parties. The impact of this change will be an increase in costs and revenues due to
the recognition of this non-cash consideration.
• Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission
and Midstream business whereby Enbridge purchases natural gas at the wellhead, then
processes and subsequently sells the gas, was previously presented as revenue. Under the new
standard, processing fees charged on natural gas purchased by Enbridge are presented as a
reduction of commodity costs upon the transfer of control of the natural gas at the wellhead.
• Revenue from certain contracts in the Gas Transmission and Midstream business that provide for
Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting
processed natural gas and/or NGLs as payment for processing services rendered, commonly
referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously
presented on a gross basis whereby Enbridge recorded one hundred percent of the value of the
natural gas and products sold as revenue, with the cost of the natural gas purchased recorded as
commodity cost. Under the new standard only Enbridge’s share of the products retained and sold
is presented as revenue and no commodity cost is recorded.
• Certain payments received from customers to offset the cost of constructing assets required to
provide services to those customers, referred to as Contributions in Aid of Construction (CIAC)
were previously recorded as reductions of property, plant and equipment regardless of whether
the amounts were imposed by regulation or negotiated. Under the new standard, negotiated
CIACs are deemed to be advance payments for services and must be recognized as revenue
when those future services are provided. Negotiated CIACs will be accounted for as deferred
revenue and recognized over the term of the associated revenue contract.
Upon adoption, we will recognize the significant cumulative effect of initially applying the new standard as
an increase in the opening balance of retained deficit of approximately $120 million, an increase in
property, plant and equipment of $130 million and an increase in deferred revenue of $120 million, subject
to final determination, as at January 1, 2018. The adoption of the new standard will also result in changes
in classification between Revenue and Commodity costs as discussed above.
We have also developed and tested processes to generate the disclosures which will be required under
the new standard commencing in the first quarter of 2018.
126
127
4. SEGMENTED INFORMATION
Effective December 31, 2017, we changed our segment-level profit measure to Earnings before interest,
income taxes and depreciation and amortization from the previous measure of Earnings before interest
and income taxes. We also renamed the Gas Pipelines and Processing segment to Gas Transmission
and Midstream. The presentation of the prior years' tables has been revised in order to align with the
current presentation.
Segmented information for the years ended December 31, 2017, 2016 and 2015 are as follows:
Year ended December 31, 2017
(millions of Canadian dollars)
Revenues
Commodity and gas distribution
costs
Operating and administrative
Impairment of long-lived assets
Impairment of goodwill
Income/(loss) from equity
investments
Other income/(expense)
Earnings/(loss) before interest,
income tax expense, and
depreciation and amortization
Depreciation and amortization
Interest expense
Income tax recovery
Earnings
Capital expenditures1
Total assets
Year ended December 31, 2016
(millions of Canadian dollars)
Revenues
Commodity and gas distribution
costs
Operating and administrative
Impairment of long-lived assets
Income/(loss) from equity
investments
Other income/(expense)
Earnings/(loss) before interest,
income tax expense, and
depreciation and amortization
Depreciation and amortization
Interest expense
Income tax expense
Earnings
Capital expenditures1
Total assets
Gas
Transmission
and
Midstream
Liquids
Pipelines
Gas
Distribution
Green Power
and
Transmission
Energy
Services
Eliminations
and Other Consolidated
8,913
(18)
(2,949)
—
—
416
33
7,067
4,992
534
23,282
(2,834)
(1,756)
(4,463)
(102)
653
166
(2,689)
(960)
—
—
23
24
— (23,508)
(163)
—
—
6
(5)
(47)
—
—
8
2
(410)
412
(567)
—
—
(4)
232
6,395
(1,269)
1,390
372
(263)
(337)
2,799
63,881
4,016
60,745
1,177
25,956
321
6,289
1
2,514
108
2,708
44,378
(28,637)
(6,442)
(4,463)
(102)
1,102
452
6,288
(3,163)
(2,556)
2,697
3,266
8,422
162,093
Gas
Transmission
and
Midstream
Liquids
Pipelines
Gas
Distribution
Green Power
and
Transmission
Energy
Services
Eliminations
and Other Consolidated
8,176
(12)
(2,908)
(1,365)
194
841
4,926
2,877
2,976
502
20,364
(2,206)
(1,653)
5
(20,473)
(446)
(11)
223
27
464
(553)
—
12
49
831
(173)
—
2
8
(63)
—
(3)
(8)
(335)
334
(215)
—
—
115
344
(183)
(101)
3,957
52,007
176
11,182
713
10,132
251
5,571
—
1,951
32
4,366
34,560
(24,005)
(4,358)
(1,376)
428
1,032
6,281
(2,240)
(1,590)
(142)
2,309
5,129
85,209
Year ended December 31, 2015
Midstream
Distribution
Transmission
and Other Consolidated
Transmission
Gas
and
Liquids
Pipelines
Green Power
Gas
and
Energy
Services
Eliminations
(millions of Canadian dollars)
Revenues
costs
Commodity and gas distribution
Operating and administrative
Impairment of long-lived assets
Impairment of goodwill
Income/(loss) from equity
investments
Other income/(expense)
Earnings/(loss) before interest,
income tax expense, and
depreciation and amortization
Depreciation and amortization
Interest expense
Income tax expense
Loss
Capital expenditures1
3,803
3,609
498
20,842
(2,349)
(536)
—
—
(10)
49
4
(20,443)
(143)
—
—
2
2
(66)
—
—
(9)
—
5,589
(9)
(2,748)
(80)
—
296
(15)
3,033
(3,002)
(506)
(16)
(440)
200
4
43
(547)
558
(132)
—
—
(4)
(742)
763
363
324
(867)
33,794
(25,241)
(4,131)
(96)
(440)
475
(702)
3,659
(2,024)
(1,624)
(170)
(159)
7,275
1 Includes allowance for equity funds used during construction.
5,884
385
858
68
—
80
The measurement basis for preparation of segmented information is consistent with the significant
accounting policies (Note 2).
Our largest non-affiliated customer accounted for approximately 11.8%, 18.0%, and 21.8% of our third-
party revenues for the years ended December 31, 2017, 2016 and 2015, respectively. A second customer
accounted for approximately 10.4% of our third-party revenues for the year ended December 31, 2016. A
third customer accounted for approximately 10.8% of our third-party revenues for the year ended
December 31, 2015. Revenues from these three customers are primarily reported in the Energy Services
Earnings attributable to common shareholders for the year ended December 31, 2015 were increased by
an out-of-period adjustment of $71 million in respect of an overstatement of deferred income tax expense
segment.
OUT-OF-PERIOD ADJUSTMENT
in 2013 and 2014.
GEOGRAPHIC INFORMATION
Revenues1
Year ended December 31,
(millions of Canadian dollars)
Canada
United States
Property, Plant and Equipment1
December 31,
(millions of Canadian dollars)
Canada
United States
1 Revenues are based on the country of origin of the product or service sold.
2017
2016
2015
18,076
26,302
44,378
12,470
22,090
34,560
11,087
22,707
33,794
2017
2016
46,025
44,686
90,711
32,008
32,276
64,284
128
129
1 Amounts are based on the location where the assets are held.
4. SEGMENTED INFORMATION
Effective December 31, 2017, we changed our segment-level profit measure to Earnings before interest,
income taxes and depreciation and amortization from the previous measure of Earnings before interest
and income taxes. We also renamed the Gas Pipelines and Processing segment to Gas Transmission
and Midstream. The presentation of the prior years' tables has been revised in order to align with the
current presentation.
Segmented information for the years ended December 31, 2017, 2016 and 2015 are as follows:
Transmission
Gas
and
Liquids
Pipelines
Green Power
Gas
and
Energy
Eliminations
Midstream
Distribution
Transmission
Services
and Other Consolidated
Year ended December 31, 2017
(millions of Canadian dollars)
Revenues
costs
Commodity and gas distribution
Operating and administrative
Impairment of long-lived assets
Impairment of goodwill
Income/(loss) from equity
investments
Other income/(expense)
Earnings/(loss) before interest,
income tax expense, and
depreciation and amortization
Depreciation and amortization
Interest expense
Income tax recovery
Earnings
Capital expenditures1
Total assets
Year ended December 31, 2016
(millions of Canadian dollars)
Revenues
costs
Commodity and gas distribution
Operating and administrative
Impairment of long-lived assets
Income/(loss) from equity
investments
Other income/(expense)
Earnings/(loss) before interest,
income tax expense, and
depreciation and amortization
Depreciation and amortization
Interest expense
Income tax expense
Earnings
Capital expenditures1
Total assets
8,913
(18)
(2,949)
—
—
416
33
7,067
4,992
534
23,282
(2,834)
(1,756)
(4,463)
(102)
653
166
(2,689)
(960)
—
—
23
24
— (23,508)
(163)
—
—
6
(5)
(47)
—
—
8
2
6,395
(1,269)
1,390
372
(263)
(337)
2,799
63,881
4,016
60,745
1,177
25,956
321
6,289
1
2,514
108
2,708
Transmission
Gas
and
Liquids
Pipelines
Green Power
Gas
and
Energy
Eliminations
Midstream
Distribution
Transmission
Services
and Other Consolidated
2,877
2,976
502
20,364
(1,653)
(553)
—
12
49
5
(20,473)
(173)
—
2
8
(63)
—
(3)
(8)
8,176
(12)
(2,908)
(1,365)
194
841
4,926
(2,206)
(446)
(11)
223
27
464
831
344
(183)
(101)
3,957
52,007
176
11,182
713
10,132
251
5,571
—
1,951
32
4,366
(410)
412
(567)
—
—
(4)
232
(335)
334
(215)
—
—
115
44,378
(28,637)
(6,442)
(4,463)
(102)
1,102
452
6,288
(3,163)
(2,556)
2,697
3,266
8,422
162,093
34,560
(24,005)
(4,358)
(1,376)
428
1,032
6,281
(2,240)
(1,590)
(142)
2,309
5,129
85,209
Gas
Transmission
and
Midstream
Liquids
Pipelines
Gas
Distribution
Green Power
and
Transmission
Energy
Services
Eliminations
and Other Consolidated
Year ended December 31, 2015
(millions of Canadian dollars)
Revenues
Commodity and gas distribution
costs
Operating and administrative
Impairment of long-lived assets
Impairment of goodwill
Income/(loss) from equity
investments
Other income/(expense)
Earnings/(loss) before interest,
income tax expense, and
depreciation and amortization
5,589
(9)
(2,748)
(80)
—
296
(15)
3,033
3,803
3,609
498
20,842
(3,002)
(2,349)
4
(20,443)
(506)
(16)
(440)
200
4
43
(536)
—
—
(10)
49
763
(143)
—
—
2
2
(66)
—
—
(9)
—
(547)
558
(132)
—
—
(4)
(742)
363
324
(867)
Depreciation and amortization
Interest expense
Income tax expense
Loss
Capital expenditures1
1 Includes allowance for equity funds used during construction.
5,884
385
858
68
—
80
33,794
(25,241)
(4,131)
(96)
(440)
475
(702)
3,659
(2,024)
(1,624)
(170)
(159)
7,275
The measurement basis for preparation of segmented information is consistent with the significant
accounting policies (Note 2).
Our largest non-affiliated customer accounted for approximately 11.8%, 18.0%, and 21.8% of our third-
party revenues for the years ended December 31, 2017, 2016 and 2015, respectively. A second customer
accounted for approximately 10.4% of our third-party revenues for the year ended December 31, 2016. A
third customer accounted for approximately 10.8% of our third-party revenues for the year ended
December 31, 2015. Revenues from these three customers are primarily reported in the Energy Services
segment.
OUT-OF-PERIOD ADJUSTMENT
Earnings attributable to common shareholders for the year ended December 31, 2015 were increased by
an out-of-period adjustment of $71 million in respect of an overstatement of deferred income tax expense
in 2013 and 2014.
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 Equipment1
December 31,
(millions of Canadian dollars)
Canada
United States
1 Amounts are based on the location where the assets are held.
2017
2016
2015
18,076
26,302
44,378
12,470
22,090
34,560
11,087
22,707
33,794
2017
2016
46,025
44,686
90,711
32,008
32,276
64,284
128
129
5. EARNINGS PER COMMON SHARE
BASIC
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 common
shares outstanding has been reduced by our pro-rata weighted average interest in our own common
shares of 13 million as at December 31, 2017 and 2016, and 12 million as at December 31, 2015
resulting from our reciprocal investment in Noverco.
DILUTED
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.
Weighted average shares outstanding used to calculate basic and diluted earnings per share are as
follows:
December 31,
(number of shares in millions)
Weighted average shares outstanding
Effect of dilutive options
Diluted weighted average shares outstanding
2017
1,525
7
1,532
2016
2015
911
7
918
847
—
847
For the years ended December 31, 2017, 2016 and 2015, 14,271,615, 10,803,672 and 36,005,043,
respectively, of anti-dilutive stock options with a weighted average exercise price of $56.71, $52.92 and
$40.26, respectively, were excluded from the diluted earnings per common share calculation.
6. REGULATORY MATTERS
GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS
We record assets and liabilities that result from the regulated ratemaking process that would not be
recorded under GAAP for non-regulated entities. See Note 2 for further discussion.
A number of our businesses are subject to regulation by the NEB. We also collect and set aside funds to
cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s
regulatory requirements under LMCI (Note 13). Amounts expected to be paid to cover future abandonment
costs are recognized as long-term regulatory liabilities. Our significant regulated businesses and other
related accounting impacts, are described below.
Liquids Pipelines
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.
Southern Lights Pipeline
The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian
portion of the Southern Lights Pipeline 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 allowable 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.
Gas Transmission and Midstream
British Columbia Pipeline and British Columbia Field Services
Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the
current income tax payable and do not include accruals for deferred income tax. However, as income
taxes become payable as a result of the reversal of timing differences that created the deferred income
taxes, it is expected that transportation and field services tolls will be adjusted to recover these taxes.
Since most of these timing differences are related to property, plant and equipment costs, this recovery is
expected to occur over the life of those assets.
Spectra Energy Partners, LP
SEP's gas transmission and storage services are regulated by the FERC. Current rates are governed by
the applicable FERC-approved natural gas tariff while fee-based gathering services are governed by the
applicable state oil and gas commissions.
For information related to regulatory assets acquired in the Merger Transaction for Union Gas, British
Columbia (BC) Pipelines, BC Field Services and SEP, refer to Note 7 - Acquisitions and Dispositions.
Gas Distribution
Enbridge Gas Distribution Inc.
EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31,
2017 and 2016 were set in accordance with parameters established by the customized incentive rate plan
(IR Plan). The customized IR Plan, inclusive of the requested capital investment amounts and an
incentive mechanism providing the opportunity to earn above the allowed ROE, was approved, with
modifications, by the OEB in 2014. The approved customized IR Plan is for establishing rates for 2014
through 2018.
As part of the customized IR Plan, the OEB approved the adoption of a new approach for determining net
salvage percentages to be included within EGD’s approved depreciation rates, as compared with the
traditional approach previously employed. The new approach results in lower net salvage percentages for
EGD, and therefore lowers depreciation rates and future removal and site restoration reserves. The
customized IR Plan also includes an earnings sharing mechanism, whereby any return over the allowed
rate of return for a given year under the customized IR Plan will be shared equally with customers. Within
annual rate proceedings for 2015 through 2018, the customized requires allowed revenues, and
corresponding rates, to be updated annually for select items.
EGD’s after-tax rate of return on common equity embedded in rates was 8.8% and 9.2% for the years
ended December 31, 2017 and 2016, respectively, based on a 36% deemed common equity component
of capital for regulatory purposes, in both years.
Union Gas Limited
Union Gas is regulated by the OEB. Union Gas's distribution rates beginning January 1, 2014 are set
under a five-year incentive regulation framework. The incentive regulation framework establishes new
rates at the beginning of each year through the use of a pricing formula rather than through the
examination of revenue and cost forecasts.
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5. EARNINGS PER COMMON SHARE
BASIC
DILUTED
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 common
shares outstanding has been reduced by our pro-rata weighted average interest in our own common
shares of 13 million as at December 31, 2017 and 2016, and 12 million as at December 31, 2015
resulting from our 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.
Weighted average shares outstanding used to calculate basic and diluted earnings per share are as
follows:
December 31,
(number of shares in millions)
Weighted average shares outstanding
Effect of dilutive options
Diluted weighted average shares outstanding
2017
1,525
7
1,532
2016
2015
911
7
918
847
—
847
For the years ended December 31, 2017, 2016 and 2015, 14,271,615, 10,803,672 and 36,005,043,
respectively, of anti-dilutive stock options with a weighted average exercise price of $56.71, $52.92 and
$40.26, respectively, were excluded from the diluted earnings per common share calculation.
6. REGULATORY MATTERS
GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS
We record assets and liabilities that result from the regulated ratemaking process that would not be
recorded under GAAP for non-regulated entities. See Note 2 for further discussion.
A number of our businesses are subject to regulation by the NEB. We also collect and set aside funds to
cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s
regulatory requirements under LMCI (Note 13). Amounts expected to be paid to cover future abandonment
costs are recognized as long-term regulatory liabilities. Our significant regulated businesses and other
related accounting impacts, are described below.
Liquids Pipelines
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.
Southern Lights Pipeline
The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian
portion of the Southern Lights Pipeline 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 allowable 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.
Gas Transmission and Midstream
British Columbia Pipeline and British Columbia Field Services
Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the
current income tax payable and do not include accruals for deferred income tax. However, as income
taxes become payable as a result of the reversal of timing differences that created the deferred income
taxes, it is expected that transportation and field services tolls will be adjusted to recover these taxes.
Since most of these timing differences are related to property, plant and equipment costs, this recovery is
expected to occur over the life of those assets.
Spectra Energy Partners, LP
SEP's gas transmission and storage services are regulated by the FERC. Current rates are governed by
the applicable FERC-approved natural gas tariff while fee-based gathering services are governed by the
applicable state oil and gas commissions.
For information related to regulatory assets acquired in the Merger Transaction for Union Gas, British
Columbia (BC) Pipelines, BC Field Services and SEP, refer to Note 7 - Acquisitions and Dispositions.
Gas Distribution
Enbridge Gas Distribution Inc.
EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31,
2017 and 2016 were set in accordance with parameters established by the customized incentive rate plan
(IR Plan). The customized IR Plan, inclusive of the requested capital investment amounts and an
incentive mechanism providing the opportunity to earn above the allowed ROE, was approved, with
modifications, by the OEB in 2014. The approved customized IR Plan is for establishing rates for 2014
through 2018.
As part of the customized IR Plan, the OEB approved the adoption of a new approach for determining net
salvage percentages to be included within EGD’s approved depreciation rates, as compared with the
traditional approach previously employed. The new approach results in lower net salvage percentages for
EGD, and therefore lowers depreciation rates and future removal and site restoration reserves. The
customized IR Plan also includes an earnings sharing mechanism, whereby any return over the allowed
rate of return for a given year under the customized IR Plan will be shared equally with customers. Within
annual rate proceedings for 2015 through 2018, the customized requires allowed revenues, and
corresponding rates, to be updated annually for select items.
EGD’s after-tax rate of return on common equity embedded in rates was 8.8% and 9.2% for the years
ended December 31, 2017 and 2016, respectively, based on a 36% deemed common equity component
of capital for regulatory purposes, in both years.
Union Gas Limited
Union Gas is regulated by the OEB. Union Gas's distribution rates beginning January 1, 2014 are set
under a five-year incentive regulation framework. The incentive regulation framework establishes new
rates at the beginning of each year through the use of a pricing formula rather than through the
examination of revenue and cost forecasts.
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131
The incentive regulation framework includes an earnings sharing mechanism that permits Union Gas to
fully retain the return on common equity from utility operations up to 9.93%, share 50% of any earnings
between 9.93% and 10.93% with customers, and share 90% of any earnings above 10.93% with
customers. Union Gas's approved after-tax return on common equity is fixed at 8.93% for the five-year
incentive regulation term.
Enbridge Gas New Brunswick Inc.
Enbridge Gas New Brunswick Inc. is regulated by the EUB. The current rates are set, as prescribed by
legislation for 2018 and 2019. In 2020 all rates will be set by cost-of-service methodology.
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 taxes
Tolling deferrals
Recoverable income taxes
Pipeline future abandonment costs1
Gas Transmission and Midstream
Deferred income taxes
Regulatory liability related to income taxes2
Other
Gas Distribution
Deferred income taxes
Purchased gas variance3
Pension plans and OPEB4
Constant dollar net salvage adjustment
Future removal and site restoration reserves
Site restoration clearance adjustment
Other
Recovery/Refund
Period Ends
2017
2016
Various
2018
Through 2030
Various
Various
Various
Various
Various
Various
Various
2018
Various
Various
Various
1,492
(34)
46
(141)
717
(1,078)
(16)
1,000
51
102
38
(1,066)
(31)
31
1,270
(37)
51
(88)
—
—
—
385
5
116
38
(606)
(109)
(4)
1 Funds collected are included in Restricted long-term investments (Note 13).
2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation dated December 22,
2017.
3 Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD and
Union Gas have been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12-
month basis via the Quarterly Rate Adjustment Mechanism process.
4 The balances are excluded from the rate base and do not earn an ROE.
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 and 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 specified 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 services 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. As at
December 31, 2017 and 2016, the net book value of these costs included in gas mains in Property, plant
and equipment, net was $118 million and $125 million, respectively. In the absence of rate regulation
accounting, some of these costs would be charged to earnings in the year incurred.
7. ACQUISITIONS AND DISPOSITIONS
ACQUISITIONS
Spectra Energy Corp
On February 27, 2017, Enbridge and Spectra Energy combined in the Merger Transaction for a purchase
price of $37.5 billion. Under the terms of the Merger Transaction, Spectra Energy shareholders received
0.984 shares of Enbridge for each share of Spectra Energy common stock that they owned, giving us
100% ownership of Spectra Energy.
Consideration offered to complete the Merger Transaction included 691 million common shares of
Enbridge at US$41.34 per share, based on the February 24, 2017 closing price on the New York Stock
Exchange (NYSE), for a total value of $37,429 million in common shares issued to Spectra Energy
shareholders, plus approximately $3 million in cash in lieu of any fractional shares, and 3.5 million share
options with a fair value of $77 million, that were exchanged for Spectra Energy’s outstanding stock
compensation awards.
Spectra Energy, through its subsidiaries and equity affiliates, owns and operates a large and diversified
portfolio of complementary natural gas-related energy assets and is one of North America’s leading
natural gas infrastructure companies. Spectra Energy also owns and operates a crude oil pipeline system
that connects Canadian and United States producers to refineries in the United States Rocky Mountain
and Midwest regions. The combination brings together two highly complementary platforms to create
North America’s largest energy infrastructure company and meaningfully enhances customer optionality,
positioning us for long-term growth opportunities, and strengthening our balance sheet.
The Merger Transaction has been accounted for as a business combination under the acquisition method
of accounting as prescribed by Accounting Standards Codification (ASC) 805 Business Combinations.
The acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair
values at the date of acquisition.
The purchase price allocation has been completed as at December 31, 2017, along with the allocation of
goodwill to reporting units (Note 15). Our reporting units are equivalent to our identified segments with the
exception of the Gas Transmission and Midstream segment, which is composed of two reporting units:
gas transmission and gas midstream.
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133
The incentive regulation framework includes an earnings sharing mechanism that permits Union Gas to
fully retain the return on common equity from utility operations up to 9.93%, share 50% of any earnings
between 9.93% and 10.93% with customers, and share 90% of any earnings above 10.93% with
customers. Union Gas's approved after-tax return on common equity is fixed at 8.93% for the five-year
incentive regulation term.
Enbridge Gas New Brunswick Inc.
Enbridge Gas New Brunswick Inc. is regulated by the EUB. The current rates are set, as prescribed by
legislation for 2018 and 2019. In 2020 all rates will be set by cost-of-service methodology.
Accounting for rate-regulated activities has resulted in the recognition of the following significant
FINANCIAL STATEMENT EFFECTS
regulatory assets and liabilities:
December 31,
(millions of Canadian dollars)
Regulatory assets/(liabilities)
Liquids Pipelines
Deferred income taxes
Tolling deferrals
Recoverable income taxes
Pipeline future abandonment costs1
Gas Transmission and Midstream
Deferred income taxes
Regulatory liability related to income taxes2
Other
Gas Distribution
Deferred income taxes
Purchased gas variance3
Pension plans and OPEB4
Constant dollar net salvage adjustment
Future removal and site restoration reserves
Site restoration clearance adjustment
Recovery/Refund
Period Ends
2017
2016
Various
2018
Through 2030
Various
Various
Various
Various
Various
Various
Various
2018
Various
Various
Various
1,492
(34)
46
(141)
717
(1,078)
(16)
1,000
51
102
38
(1,066)
(31)
31
1,270
(37)
51
(88)
—
—
—
385
5
116
38
(606)
(109)
(4)
Other
2017.
1 Funds collected are included in Restricted long-term investments (Note 13).
2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation dated December 22,
3 Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD and
Union Gas have been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12-
month basis via the Quarterly Rate Adjustment Mechanism process.
4 The balances are excluded from the rate base and do not earn an ROE.
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 and 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 specified 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 services 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. As at
December 31, 2017 and 2016, the net book value of these costs included in gas mains in Property, plant
and equipment, net was $118 million and $125 million, respectively. In the absence of rate regulation
accounting, some of these costs would be charged to earnings in the year incurred.
7. ACQUISITIONS AND DISPOSITIONS
ACQUISITIONS
Spectra Energy Corp
On February 27, 2017, Enbridge and Spectra Energy combined in the Merger Transaction for a purchase
price of $37.5 billion. Under the terms of the Merger Transaction, Spectra Energy shareholders received
0.984 shares of Enbridge for each share of Spectra Energy common stock that they owned, giving us
100% ownership of Spectra Energy.
Consideration offered to complete the Merger Transaction included 691 million common shares of
Enbridge at US$41.34 per share, based on the February 24, 2017 closing price on the New York Stock
Exchange (NYSE), for a total value of $37,429 million in common shares issued to Spectra Energy
shareholders, plus approximately $3 million in cash in lieu of any fractional shares, and 3.5 million share
options with a fair value of $77 million, that were exchanged for Spectra Energy’s outstanding stock
compensation awards.
Spectra Energy, through its subsidiaries and equity affiliates, owns and operates a large and diversified
portfolio of complementary natural gas-related energy assets and is one of North America’s leading
natural gas infrastructure companies. Spectra Energy also owns and operates a crude oil pipeline system
that connects Canadian and United States producers to refineries in the United States Rocky Mountain
and Midwest regions. The combination brings together two highly complementary platforms to create
North America’s largest energy infrastructure company and meaningfully enhances customer optionality,
positioning us for long-term growth opportunities, and strengthening our balance sheet.
The Merger Transaction has been accounted for as a business combination under the acquisition method
of accounting as prescribed by Accounting Standards Codification (ASC) 805 Business Combinations.
The acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair
values at the date of acquisition.
The purchase price allocation has been completed as at December 31, 2017, along with the allocation of
goodwill to reporting units (Note 15). Our reporting units are equivalent to our identified segments with the
exception of the Gas Transmission and Midstream segment, which is composed of two reporting units:
gas transmission and gas midstream.
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133
The following table summarizes the estimated fair values that were assigned to the net assets of Spectra
Energy:
February 27,
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)
Property, plant and equipment, net (b)
Restricted long-term investments
Long-term investments (c)
Deferred amounts and other assets (d)
Intangible assets, net (e)
Current liabilities (a)
Long-term debt (d)
Other long-term liabilities
Deferred income taxes (b)
Noncontrolling interests (f)
Goodwill (g)
Purchase price:
Common shares
Cash
Fair value of outstanding earned stock compensation awards recorded
in Additional paid-in capital
2017
2,432
33,555
144
5,000
2,390
1,288
(3,982)
(21,444)
(1,983)
(7,670)
(8,877)
853
36,656
37,509
37,429
3
77
37,509
a) Accounts receivable is comprised primarily of customer trade receivables and natural gas
imbalances. As such, the fair value of accounts receivable approximates the net carrying value of
$1,174 million. The gross amount due of $1,190 million, of which $16 million is not expected to be
collected, is included in current assets.
During the fourth quarter of 2017, we identified certain transactions that were not reflected in the
purchase price equation. This resulted in a $67 million and $548 million increase in current assets
and current liabilities, respectively, and a $481 million decrease in long-term debt.
b) We have applied the valuation methodologies described in ASC 820 Fair Value Measurements
and Disclosures, to value the property, plant and equipment purchased. The fair value of Spectra
Energy’s rate-regulated property, plant and equipment was determined using a market participant
perspective, which is their carrying amount. The fair value of the remaining non-regulated property,
plant and equipment was determined primarily using variations of the income approach, which is
based on the present value of the future after-tax cash flows attributable to each non-regulated
asset. Some of the more significant assumptions inherent in the development of the values, from
the perspective of a market participant, include, but are not limited to, the amount and timing of
projected future cash flows (including revenue and profitability); the discount rate selected to
measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the
competitive trends impacting the asset; and customer turnover.
During the third quarter of 2017, Spectra Energy's right-of-way agreements were reclassified from
intangible assets to property, plant and equipment to conform the presentation of these
agreements with our accounting policy pertaining to rights-of-way. The purchase price allocation
above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There
is no change in the amortization period for the right-of-way agreements as a result of this
reclassification.
During the fourth quarter of 2017, we finalized our fair value measurement of the BC Pipeline &
Field Services businesses, which resulted in decreases to property, plant and equipment of $1,955
million and deferred income tax liabilities of $661 million as at February 27, 2017.
c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream,
Gulfstream Natural Gas System, L.L.C., Nexus Gas Transmission, LLC (Nexus), Steckman Ridge
LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity
interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was
determined using an income approach.
d) Fair value of long-term debt was determined based on the current underlying Government of
Canada and United States Treasury interest rates on the corresponding bonds, as well as an
implied credit spread based on current market conditions and resulted in an increase in the book
value of debt of $1.5 billion. The fair value adjustment to long-term debt related to rate-regulated
entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in
the Consolidated Statements of Financial Position.
During the fourth quarter of 2017, deferred amounts and other assets decreased by $530 million
as at February 27, 2017 due to the finalization of BC Pipelines & Field Services' fair value
measurement, as discussed under (b) above.
During the fourth quarter of 2017, we identified certain transactions that were not reflected in the
purchase price equation. This resulted in a $481 million decrease in long-term debt, as discussed
under (a) above.
e) Intangible assets primarily consist of customer relationships in the non-regulated business, which
represent the underlying relationship from long-term agreements with customers that are
capitalized upon acquisition, determined using the income approach. Intangible assets are
amortized on a straight-line basis over their expected lives.
During the third quarter of 2017, intangible assets decreased by $830 million as at February 27,
2017 due to a reclassification to property, plant and equipment, as discussed under (b) above.
The fair value of intangible assets acquired through the Merger Transaction, by major classes is as
follows:
As at February 27, 2017
(millions of Canadian dollars)
Customer relationships1
Project agreement2
Software
Other
Weighted Average
Amortization Rate
3.7%
4.0%
11.1%
4.2%
Fair
Value
739
105
329
115
1,288
1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition.
2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and
Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership
interest in Sabal Trail Transmission, LLC (Sabal Trail), as certain milestones of the project are met. Amortization of the
intangible asset began on July 3, 2017, when Sabal Trail was placed into service (Note 12).
f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million
SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US
$44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast
Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the
134
135
2017
2,432
33,555
144
5,000
2,390
1,288
(3,982)
(21,444)
(1,983)
(7,670)
(8,877)
853
36,656
37,509
37,429
3
77
37,509
The following table summarizes the estimated fair values that were assigned to the net assets of Spectra
Energy:
February 27,
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)
Property, plant and equipment, net (b)
Restricted long-term investments
Long-term investments (c)
Deferred amounts and other assets (d)
Intangible assets, net (e)
Current liabilities (a)
Long-term debt (d)
Other long-term liabilities
Deferred income taxes (b)
Noncontrolling interests (f)
Goodwill (g)
Purchase price:
Common shares
Cash
Fair value of outstanding earned stock compensation awards recorded
in Additional paid-in capital
a) Accounts receivable is comprised primarily of customer trade receivables and natural gas
imbalances. As such, the fair value of accounts receivable approximates the net carrying value of
$1,174 million. The gross amount due of $1,190 million, of which $16 million is not expected to be
collected, is included in current assets.
During the fourth quarter of 2017, we identified certain transactions that were not reflected in the
purchase price equation. This resulted in a $67 million and $548 million increase in current assets
and current liabilities, respectively, and a $481 million decrease in long-term debt.
b) We have applied the valuation methodologies described in ASC 820 Fair Value Measurements
and Disclosures, to value the property, plant and equipment purchased. The fair value of Spectra
Energy’s rate-regulated property, plant and equipment was determined using a market participant
perspective, which is their carrying amount. The fair value of the remaining non-regulated property,
plant and equipment was determined primarily using variations of the income approach, which is
based on the present value of the future after-tax cash flows attributable to each non-regulated
asset. Some of the more significant assumptions inherent in the development of the values, from
the perspective of a market participant, include, but are not limited to, the amount and timing of
projected future cash flows (including revenue and profitability); the discount rate selected to
measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the
competitive trends impacting the asset; and customer turnover.
During the third quarter of 2017, Spectra Energy's right-of-way agreements were reclassified from
intangible assets to property, plant and equipment to conform the presentation of these
agreements with our accounting policy pertaining to rights-of-way. The purchase price allocation
above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There
is no change in the amortization period for the right-of-way agreements as a result of this
reclassification.
During the fourth quarter of 2017, we finalized our fair value measurement of the BC Pipeline &
Field Services businesses, which resulted in decreases to property, plant and equipment of $1,955
million and deferred income tax liabilities of $661 million as at February 27, 2017.
c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream,
Gulfstream Natural Gas System, L.L.C., Nexus Gas Transmission, LLC (Nexus), Steckman Ridge
LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity
interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was
determined using an income approach.
d) Fair value of long-term debt was determined based on the current underlying Government of
Canada and United States Treasury interest rates on the corresponding bonds, as well as an
implied credit spread based on current market conditions and resulted in an increase in the book
value of debt of $1.5 billion. The fair value adjustment to long-term debt related to rate-regulated
entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in
the Consolidated Statements of Financial Position.
During the fourth quarter of 2017, deferred amounts and other assets decreased by $530 million
as at February 27, 2017 due to the finalization of BC Pipelines & Field Services' fair value
measurement, as discussed under (b) above.
During the fourth quarter of 2017, we identified certain transactions that were not reflected in the
purchase price equation. This resulted in a $481 million decrease in long-term debt, as discussed
under (a) above.
e) Intangible assets primarily consist of customer relationships in the non-regulated business, which
represent the underlying relationship from long-term agreements with customers that are
capitalized upon acquisition, determined using the income approach. Intangible assets are
amortized on a straight-line basis over their expected lives.
During the third quarter of 2017, intangible assets decreased by $830 million as at February 27,
2017 due to a reclassification to property, plant and equipment, as discussed under (b) above.
The fair value of intangible assets acquired through the Merger Transaction, by major classes is as
follows:
As at February 27, 2017
(millions of Canadian dollars)
Customer relationships1
Project agreement2
Software
Other
Weighted Average
Amortization Rate
3.7%
4.0%
11.1%
4.2%
Fair
Value
739
105
329
115
1,288
1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition.
2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and
Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership
interest in Sabal Trail Transmission, LLC (Sabal Trail), as certain milestones of the project are met. Amortization of the
intangible asset began on July 3, 2017, when Sabal Trail was placed into service (Note 12).
f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million
SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US
$44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast
Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the
134
135
underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas
and Westcoast Energy Inc.
The final purchase price allocation was as follows:
During the third quarter of 2017, we finalized our fair value measurement of Sabal Trail, which
resulted in an increase to noncontrolling interests of $85 million as at February 27, 2017.
g) We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the
Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors
that contributed to the goodwill include the opportunity to expand our natural gas pipelines
segment, the potential for cost and supply chain optimization synergies, existing assembled assets
and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and
other intangibles not separately identifiable because they are inextricably linked to the provision of
regulated utility service and the enhanced scale and geographic diversity which provide greater
optionality and platforms for future growth.
During the third quarter of 2017, goodwill increased by $85 million as at February 27, 2017 due to
the finalization of the fair value measurement of Sabal Trail as discussed under (f) above.
During the fourth quarter of 2017, goodwill increased by $1,824 million as at February 27, 2017
due to the finalization of the fair value measurement of BC Pipelines & Field Services as discussed
under (b) above.
Acquisition-related expenses incurred to date were approximately $231 million. Costs incurred for the
years ended December 31, 2017 and 2016 of $180 million and $51 million, respectively, are included in
Operating and administrative expense in the Consolidated Statements of Earnings.
Upon completion of the Merger Transaction, we began consolidating Spectra Energy. Since the closing
date of February 27, 2017 through December 31, 2017, Spectra Energy has generated approximately
$5,740 million in revenues and $2,574 million in earnings.
Our supplemental pro forma consolidated financial information for the years ended December 31, 2017
and 2016, including the results of operations for Spectra Energy as if the Merger Transaction had been
completed on January 1, 2016 are as follows:
Year ended December 31,
(unaudited; millions of Canadian dollars)
40,934
Revenues
Earnings attributable to common shareholders1
2,820
1 Merger Transaction costs of $180 million (after-tax $131 million) were excluded from earnings for the year ended December 31,
45,669
2,902
2017
2016
2017.
Tupper Main and Tupper West
On April 1, 2016, we acquired the Tupper Main and Tupper West gas plants and associated pipelines (the
Tupper Plants) located in northeastern BC for cash consideration of $539 million. The purchase price for
the Tupper Plants was equal to the fair value of identifiable net assets acquired and accordingly, we did
not recognize any goodwill as part of the acquisition. Transaction costs incurred by us totaled
approximately $1 million and are included in Operating and administrative expense in the Consolidated
Statements of Earnings. The Tupper Plants are a part of our Gas Transmission and Midstream segment.
Since the closing date through December 31, 2016, the Tupper Plants generated approximately $33
million in revenues and $22 million in earnings before interest and income taxes. If the acquisition had
closed on January 1, 2016, the Consolidated Statements of Earnings for the year ended December 31,
2016 would have shown revenues of $44 million and earnings before interest and income taxes of $28
million.
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137
April 1,
(millions of Canadian dollars)
Fair value of net assets acquired:
Property, plant and equipment
Intangible assets
Purchase price:
Cash
OTHER ACQUISITIONS
Chapman Ranch Wind Project
2016
288
251
539
539
On September 9, 2016, we acquired a 100% interest in the 249 megawatt (MW) Chapman Ranch Wind
Project (Chapman Ranch) located in Texas for cash consideration of $65 million (US$50 million), of which
$62 million (US$48 million) was allocated to property, plant and equipment and the balance allocated to
Intangible assets. On November 2, 2016, we invested a further $40 million (US$30 million) in Chapman
Ranch, of which $23 million (US$17 million) was related to Property, plant and equipment and the balance
related to Intangible assets. There would have been no effect on our earnings if the transaction had
occurred on January 1, 2016 as the project was under construction and had not generated revenues to
date. Chapman Ranch is a part of our Green Power and Transmission segment.
New Creek Wind Project
In November 2015, we acquired a 100% interest in the 103 MW New Creek Wind Project (New Creek) for
cash consideration of $48 million (US$36 million), with $35 million (US$26 million) of the purchase price
allocated to Property, plant and equipment and the balance allocated to Intangible assets. New Creek
was placed into service in December 2016 and is a part of our Green Power and Transmission segment.
Midstream Business
On February 27, 2015, Enbridge Energy Partners, L.P. (EEP) acquired, through its partially-owned
subsidiary, Midcoast Energy Partners, L.P. (MEP), the midstream business of New Gulf Resources, LLC
located in Texas for $106 million (US$85 million) in cash and a contingent future payment of up to $21
million (US$17 million). The acquisition consisted of a natural gas gathering system that is in operation
and is a part of our Gas Transmission and Midstream segment. Of the purchase price, we allocated $69
million (US$55 million) to Property, plant and equipment and the balance to Intangible assets. In 2016, we
determined that the likelihood of making any future contingent payments was remote.
ASSETS HELD FOR SALE
US Midstream
In November 2017, we announced that we have identified certain non-core assets that we plan to sell or
monetize in 2018 as they do not meet our long-term strategy. As a result, we are in the process of selling
certain assets within the United States Midstream business of our Gas Transmission and Midstream
segment. As at December 31, 2017, we classified these assets as held for sale and measured them at
the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $4.4 billion ($2.8
billion after-tax) and a related goodwill impairment of $102 million. Fair value less cost to sell was
estimated using the discounted cash flow method, which was negatively impacted by prolonged decline in
commodity prices and deteriorating business performance. This loss has been included within Impairment
of long-lived assets and Impairment of goodwill, respectively, on the Consolidated Statements of Earnings
for the year ended December 31, 2017.
St. Lawrence Gas Company, Inc.
In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence
Gas Company, Inc. (St. Lawrence Gas) for cash proceeds of approximately $88 million (US$70 million).
Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in
underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas
The final purchase price allocation was as follows:
and Westcoast Energy Inc.
During the third quarter of 2017, we finalized our fair value measurement of Sabal Trail, which
resulted in an increase to noncontrolling interests of $85 million as at February 27, 2017.
g) We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the
Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors
that contributed to the goodwill include the opportunity to expand our natural gas pipelines
segment, the potential for cost and supply chain optimization synergies, existing assembled assets
and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and
other intangibles not separately identifiable because they are inextricably linked to the provision of
regulated utility service and the enhanced scale and geographic diversity which provide greater
optionality and platforms for future growth.
During the third quarter of 2017, goodwill increased by $85 million as at February 27, 2017 due to
the finalization of the fair value measurement of Sabal Trail as discussed under (f) above.
During the fourth quarter of 2017, goodwill increased by $1,824 million as at February 27, 2017
due to the finalization of the fair value measurement of BC Pipelines & Field Services as discussed
under (b) above.
Acquisition-related expenses incurred to date were approximately $231 million. Costs incurred for the
years ended December 31, 2017 and 2016 of $180 million and $51 million, respectively, are included in
Operating and administrative expense in the Consolidated Statements of Earnings.
Upon completion of the Merger Transaction, we began consolidating Spectra Energy. Since the closing
date of February 27, 2017 through December 31, 2017, Spectra Energy has generated approximately
$5,740 million in revenues and $2,574 million in earnings.
Our supplemental pro forma consolidated financial information for the years ended December 31, 2017
and 2016, including the results of operations for Spectra Energy as if the Merger Transaction had been
2017
2016
45,669
2,902
40,934
2,820
completed on January 1, 2016 are as follows:
Year ended December 31,
(unaudited; millions of Canadian dollars)
Revenues
Earnings attributable to common shareholders1
2017.
Tupper Main and Tupper West
1 Merger Transaction costs of $180 million (after-tax $131 million) were excluded from earnings for the year ended December 31,
On April 1, 2016, we acquired the Tupper Main and Tupper West gas plants and associated pipelines (the
Tupper Plants) located in northeastern BC for cash consideration of $539 million. The purchase price for
the Tupper Plants was equal to the fair value of identifiable net assets acquired and accordingly, we did
not recognize any goodwill as part of the acquisition. Transaction costs incurred by us totaled
approximately $1 million and are included in Operating and administrative expense in the Consolidated
Statements of Earnings. The Tupper Plants are a part of our Gas Transmission and Midstream segment.
Since the closing date through December 31, 2016, the Tupper Plants generated approximately $33
million in revenues and $22 million in earnings before interest and income taxes. If the acquisition had
closed on January 1, 2016, the Consolidated Statements of Earnings for the year ended December 31,
2016 would have shown revenues of $44 million and earnings before interest and income taxes of $28
million.
April 1,
(millions of Canadian dollars)
Fair value of net assets acquired:
Property, plant and equipment
Intangible assets
Purchase price:
Cash
2016
288
251
539
539
OTHER ACQUISITIONS
Chapman Ranch Wind Project
On September 9, 2016, we acquired a 100% interest in the 249 megawatt (MW) Chapman Ranch Wind
Project (Chapman Ranch) located in Texas for cash consideration of $65 million (US$50 million), of which
$62 million (US$48 million) was allocated to property, plant and equipment and the balance allocated to
Intangible assets. On November 2, 2016, we invested a further $40 million (US$30 million) in Chapman
Ranch, of which $23 million (US$17 million) was related to Property, plant and equipment and the balance
related to Intangible assets. There would have been no effect on our earnings if the transaction had
occurred on January 1, 2016 as the project was under construction and had not generated revenues to
date. Chapman Ranch is a part of our Green Power and Transmission segment.
New Creek Wind Project
In November 2015, we acquired a 100% interest in the 103 MW New Creek Wind Project (New Creek) for
cash consideration of $48 million (US$36 million), with $35 million (US$26 million) of the purchase price
allocated to Property, plant and equipment and the balance allocated to Intangible assets. New Creek
was placed into service in December 2016 and is a part of our Green Power and Transmission segment.
Midstream Business
On February 27, 2015, Enbridge Energy Partners, L.P. (EEP) acquired, through its partially-owned
subsidiary, Midcoast Energy Partners, L.P. (MEP), the midstream business of New Gulf Resources, LLC
located in Texas for $106 million (US$85 million) in cash and a contingent future payment of up to $21
million (US$17 million). The acquisition consisted of a natural gas gathering system that is in operation
and is a part of our Gas Transmission and Midstream segment. Of the purchase price, we allocated $69
million (US$55 million) to Property, plant and equipment and the balance to Intangible assets. In 2016, we
determined that the likelihood of making any future contingent payments was remote.
ASSETS HELD FOR SALE
US Midstream
In November 2017, we announced that we have identified certain non-core assets that we plan to sell or
monetize in 2018 as they do not meet our long-term strategy. As a result, we are in the process of selling
certain assets within the United States Midstream business of our Gas Transmission and Midstream
segment. As at December 31, 2017, we classified these assets as held for sale and measured them at
the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $4.4 billion ($2.8
billion after-tax) and a related goodwill impairment of $102 million. Fair value less cost to sell was
estimated using the discounted cash flow method, which was negatively impacted by prolonged decline in
commodity prices and deteriorating business performance. This loss has been included within Impairment
of long-lived assets and Impairment of goodwill, respectively, on the Consolidated Statements of Earnings
for the year ended December 31, 2017.
St. Lawrence Gas Company, Inc.
In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence
Gas Company, Inc. (St. Lawrence Gas) for cash proceeds of approximately $88 million (US$70 million).
Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in
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137
2018. As at December 31, 2017, St. Lawrence Gas, which is a part of our Gas Distribution segment, was
classified as held for sale in the Consolidated Statements of Financial Position.
8. ACCOUNTS RECEIVABLE AND OTHER
The table below summarizes the presentation of net assets held for sale in our Consolidated Statements
of Financial Position:
December 31,
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)
Deferred amounts and other assets (long-term assets held for sale)
Accounts payable and other (current liabilities held for sale)
Net assets held for sale
2017
424
1,190
(315)
1,299
2016
—
278
—
278
DISPOSITIONS
Olympic Pipeline
On July 31, 2017, we completed the sale of our interest in Olympic Pipeline for cash proceeds of
approximately $203 million (US$160 million). A gain on disposal of $27 million (US$21 million) before tax
was included in Other income/(expense) in the Consolidated Statements of Earnings. This interest was a
part of our Liquids Pipelines segment.
Sandpiper Project
During the year ended December 31, 2017, we sold unused pipe related to the Sandpiper Project
(Sandpiper) for cash proceeds of approximately $148 million (US$111 million). A gain on disposal of $83
million (US$63 million) before tax was included in Operating and administrative expense in the
Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment.
Ozark Pipeline
In 2016, we classified the Ozark Pipeline assets as held for sale. On March 1, 2017, we completed the
sale of the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294
million (US$220 million), including reimbursement of costs. A gain on disposal of $14 million (US$10
million) before tax was included in Operating and administrative expense in the Consolidated Statements
of Earnings. These assets were a part of our Liquids Pipelines segment.
South Prairie Region
On December 1, 2016, we completed the sale of the South Prairie Region assets for cash proceeds of
approximately $1.1 billion. A gain on disposal of $850 million before tax was included in Other income/
(expense) in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines
segment.
OTHER DISPOSITIONS
In December 2016, we sold other miscellaneous non-core assets for cash proceeds of approximately
$286 million.
In August 2015, we sold our 77.8% controlling interest in the Frontier Pipeline Company, which holds
pipeline assets located in the midwest United States, for gross proceeds of approximately $112 million
(US$85 million). A gain on disposal of $70 million (US$53 million) before tax was included in Other
income/(expense) in the Consolidated Statements of Earnings. This interest was a part of our Liquids
Pipelines segment.
In May 2015, the Fund sold certain of its crude oil pipeline system assets for gross proceeds of
approximately $26 million. A gain on disposal of $22 million before tax was included in Other income/
(expense) in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines
segment.
December 31,
(millions of Canadian dollars)
Trade receivables and unbilled revenues1
Other
1 Net of allowance for doubtful accounts of $50 million and $46 million as at December 31, 2017 and 2016, respectively.
During 2017, in conjunction with its restructuring actions (Note 19), EEP terminated a receivable purchase
agreement with a special purpose entity wholly-owned by us.
2017
2016
5,325
1,728
7,053
3,814
1,164
4,978
2017
2016
695
744
89
594
634
5
1,528
1,233
9. INVENTORY
December 31,
(millions of Canadian dollars)
Natural gas
Crude oil
Other commodities
10. PROPERTY, PLANT AND EQUIPMENT
December 31,
(millions of Canadian dollars)
Pipeline
Pumping equipment, buildings, tanks and other
Land and right-of-way1
Gas mains, services and other
Compressors, meters and other operating equipment
Processing and treating plants
Storage
Wind turbines, solar panels and other
Power transmission
improvements
Under construction
Total property, plant and equipment2
Total accumulated depreciation
Property, plant and equipment, net
Vehicles, office furniture, equipment and other buildings and
Weighted Average
Depreciation Rate
2017
2016
2.5%
2.9%
2.1%
2.1%
2.1%
3.1%
2.0%
3.3%
2.2%
6.5%
—
47,720
16,610
2,538
17,026
5,774
1,440
1,545
4,804
365
390
7,601
105,813
(15,102)
90,711
34,474
15,554
2,067
10,022
4,014
846
—
4,259
378
315
6,966
78,895
(14,611)
64,284
1 The measurement of weighted average depreciation rate excludes non-depreciable assets.
2 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7).
Depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $2.9 billion, $2.0
billion and $1.9 billion, respectively.
IMPAIRMENT
Northern Gateway Project
On November 29, 2016, the Canadian Federal Government directed the NEB to dismiss our Northern
Gateway Project application and the Certificates of Public Convenience and Necessity have been
rescinded. In consultation with potential shippers and Aboriginal equity partners, we assessed this
138
139
2018. As at December 31, 2017, St. Lawrence Gas, which is a part of our Gas Distribution segment, was
classified as held for sale in the Consolidated Statements of Financial Position.
8. ACCOUNTS RECEIVABLE AND OTHER
December 31,
(millions of Canadian dollars)
Trade receivables and unbilled revenues1
Other
2017
2016
5,325
1,728
7,053
3,814
1,164
4,978
1 Net of allowance for doubtful accounts of $50 million and $46 million as at December 31, 2017 and 2016, respectively.
During 2017, in conjunction with its restructuring actions (Note 19), EEP terminated a receivable purchase
agreement with a special purpose entity wholly-owned by us.
9. INVENTORY
December 31,
(millions of Canadian dollars)
Natural gas
Crude oil
Other commodities
10. PROPERTY, PLANT AND EQUIPMENT
December 31,
(millions of Canadian dollars)
Pipeline
Pumping equipment, buildings, tanks and other
Land and right-of-way1
Gas mains, services and other
Compressors, meters and other operating equipment
Processing and treating plants
Storage
Wind turbines, solar panels and other
Power transmission
Vehicles, office furniture, equipment and other buildings and
improvements
Under construction
Total property, plant and equipment2
Total accumulated depreciation
Property, plant and equipment, net
1 The measurement of weighted average depreciation rate excludes non-depreciable assets.
2 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7).
2017
2016
695
744
89
1,528
594
634
5
1,233
Weighted Average
Depreciation Rate
2017
2016
2.5%
2.9%
2.1%
2.1%
2.1%
3.1%
2.0%
3.3%
2.2%
6.5%
—
47,720
16,610
2,538
17,026
5,774
1,440
1,545
4,804
365
34,474
15,554
2,067
10,022
4,014
846
—
4,259
378
390
7,601
105,813
(15,102)
90,711
315
6,966
78,895
(14,611)
64,284
138
139
Depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $2.9 billion, $2.0
billion and $1.9 billion, respectively.
IMPAIRMENT
Northern Gateway Project
On November 29, 2016, the Canadian Federal Government directed the NEB to dismiss our Northern
Gateway Project application and the Certificates of Public Convenience and Necessity have been
rescinded. In consultation with potential shippers and Aboriginal equity partners, we assessed this
The table below summarizes the presentation of net assets held for sale in our Consolidated Statements
Accounts receivable and other (current assets held for sale)
Deferred amounts and other assets (long-term assets held for sale)
Accounts payable and other (current liabilities held for sale)
of Financial Position:
December 31,
(millions of Canadian dollars)
Net assets held for sale
DISPOSITIONS
Olympic Pipeline
2017
424
1,190
(315)
1,299
2016
—
278
—
278
On July 31, 2017, we completed the sale of our interest in Olympic Pipeline for cash proceeds of
approximately $203 million (US$160 million). A gain on disposal of $27 million (US$21 million) before tax
was included in Other income/(expense) in the Consolidated Statements of Earnings. This interest was a
part of our Liquids Pipelines segment.
Sandpiper Project
During the year ended December 31, 2017, we sold unused pipe related to the Sandpiper Project
(Sandpiper) for cash proceeds of approximately $148 million (US$111 million). A gain on disposal of $83
million (US$63 million) before tax was included in Operating and administrative expense in the
Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment.
Ozark Pipeline
In 2016, we classified the Ozark Pipeline assets as held for sale. On March 1, 2017, we completed the
sale of the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294
million (US$220 million), including reimbursement of costs. A gain on disposal of $14 million (US$10
million) before tax was included in Operating and administrative expense in the Consolidated Statements
of Earnings. These assets were a part of our Liquids Pipelines segment.
On December 1, 2016, we completed the sale of the South Prairie Region assets for cash proceeds of
approximately $1.1 billion. A gain on disposal of $850 million before tax was included in Other income/
(expense) in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines
South Prairie Region
segment.
OTHER DISPOSITIONS
$286 million.
In December 2016, we sold other miscellaneous non-core assets for cash proceeds of approximately
In August 2015, we sold our 77.8% controlling interest in the Frontier Pipeline Company, which holds
pipeline assets located in the midwest United States, for gross proceeds of approximately $112 million
(US$85 million). A gain on disposal of $70 million (US$53 million) before tax was included in Other
income/(expense) in the Consolidated Statements of Earnings. This interest was a part of our Liquids
Pipelines segment.
In May 2015, the Fund sold certain of its crude oil pipeline system assets for gross proceeds of
approximately $26 million. A gain on disposal of $22 million before tax was included in Other income/
(expense) in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines
segment.
decision and concluded that the project cannot proceed as envisioned. After taking into consideration the
amount recoverable from potential shippers on Northern Gateway Project, we recognized an impairment
of $373 million ($272 million after-tax), which is included in Impairment of property, plant and equipment in
the Consolidated Statements of Earnings. This impairment loss is based on the full carrying value of the
assets, which have an estimated fair value of nil, and are a part of our Liquids Pipelines segment.
Sandpiper Project
On September 1, 2016, we announced that EEP applied for the withdrawal of regulatory applications
pending with the Minnesota Public Utilities Commission for Sandpiper. In connection with this
announcement and other factors, we evaluated Sandpiper for impairment. As a result, we recognized an
impairment loss of $992 million ($81 million after-tax attributable to us) for the year ended December 31,
2016, which is included in Impairment of property, plant and equipment in the Consolidated Statements of
Earnings. Sandpiper is a part of our Liquids Pipelines segment. The estimated remaining fair value of
Sandpiper was based on the estimated price that would be received to sell unused pipe, land and other
related equipment in its current condition, considering the current market conditions for sale of these
assets at the time. The valuation considered a range of potential selling prices from various alternatives
that could be used to dispose of these assets. The estimated fair value, with the exception of $3 million in
land, was reclassified into Deferred amounts and other assets in the Consolidated Statements of
Financial Position as at December 31, 2016. During 2017, we disposed of substantially all of the
remaining Sandpiper assets (Note 7).
Other
For the year ended December 31, 2016, we recorded impairment charges of $11 million related to EEP’s
non-core trucking assets and related facilities, which are a part of our Gas Transmission and Midstream
segment.
For the year ended December 31, 2015, we recorded impairment charges of $96 million, of which $80
million related to EEP’s Berthold rail facility, included within the Liquids Pipelines segment, due to
contracts that were not yet renewed beyond 2016. The remaining $16 million in impairment charges relate
to EEP’s non-core Louisiana propylene pipeline asset, included within the Gas Transmission and
Midstream segment, following finalization of a contract restructuring with a primary customer.
Impairment charges were based on the amount by which the carrying values of the assets exceeded fair
value, determined using expected discounted future cash flows, and such charges are included in
Impairment of property, plant and equipment on the Consolidated Statements of Earnings.
11. VARIABLE INTEREST ENTITIES
CONSOLIDATED VARIABLE INTEREST ENTITIES
Enbridge Energy Partners, L.P.
EEP is a publicly-traded Delaware limited partnership and is considered a VIE as its limited partners do
not have substantive kick-out rights or participating rights. Through our wholly-owned subsidiary, Enbridge
Energy Company, Inc. (EECI), we have the power to direct EEP’s activities and have a significant impact
on EEP’s economic performance. Along with an economic interest held through an indirect common
interest and general partner interest through EECI, and through our 100% ownership of EECI, we are the
primary beneficiary of EEP. As at December 31, 2017 and 2016, our economic interest in EEP was 34.6%
and 35.3% respectively. The public owns the remaining interests in EEP.
Enbridge Income Fund
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. We are the primary
beneficiary of the Fund through our combined 82.5% economic interest held indirectly through a common
investment in ENF, a direct common interest in the Fund, a preferred unit investment in ECT, a direct
common interest in Enbridge Income Partners GP Inc., and a direct common interest in EIPLP. As at
December 31, 2016, our combined economic interest was 86.9%. As at December 31, 2017 and 2016,
our direct common interest in the Fund was 29.4% and 43.2%, respectively. We also serve in the capacity
of Manager of ENF and the Fund Group.
Enbridge Commercial Trust
We have the ability to appoint the majority of the trustees to ECT’s Board of Trustees, resulting in a lack
of decision making ability for the holders of the common trust units of ECT. As a result, ECT is considered
to be a VIE and although we do not have a common equity interest in ECT, we are considered to be the
primary beneficiary of ECT. We also serve in the capacity of Manager of ECT, as part of the Fund Group.
Enbridge Income Partners LP
EIPLP, formed in 2002, is involved in the generation, transportation and storage of energy through
interests in its Liquids Pipelines business, including the Canadian Mainline, the Regional Oil Sands
System, a 50.0% interest in the Alliance Pipeline, which transports natural gas, and its renewable and
alternative power generation facilities. EIPLP is a partnership between an indirect wholly-owned
subsidiary of Enbridge and ECT. EIPLP is considered a VIE as its limited partners lack substantive kick-
out rights and participating rights. Through a majority ownership of EIPLP’s General Partner, 100%
ownership of Enbridge Management Services Inc. (a service provider for EIPLP), and 53.1% of direct
common interest in EIPLP, we have the power to direct the activities that most significantly impact
EIPLP’s economic performance and have the obligation to absorb losses and the right to receive residual
returns that are potentially significant to EIPLP, making us the primary beneficiary of EIPLP. As at
December 31, 2017 and 2016, our economic interest in EIPLP was 73.5% and 79.1%, respectively.
Green Power and Transmission
Through various subsidiaries, we have a majority ownership interest in Magic Valley, Wildcat, Keechi
Wind Project (Keechi), and New Creek wind farms. These wind farms are considered VIEs as they do not
have sufficient equity at risk and are partially financed by tax equity investors. We are the primary
beneficiary of these VIEs by virtue of our voting rights, our power to direct the activities that most
significantly impact the economic performance of the wind farms, and our obligation to absorb losses.
Enbridge Holdings (DakTex) L.L.C.
Enbridge Holdings (DakTex) L.L.C. (DakTex) is owned 75% by a wholly-owned subsidiary of Enbridge
and 25% by EEP, through which we have an effective 27.6% interest in the equity investment, Bakken
Pipeline System (Note 12). EEP is the primary beneficiary because it has the power to direct DakTex’s
activities that most significantly impact its economic performance. We consolidate EEP and by extension
also consolidate DakTex.
Spectra Energy Partners, LP
We acquired a 75% ownership in SEP through the Merger Transaction. SEP is a natural gas and crude oil
infrastructure master limited partnership and is considered a VIE as its limited partners do not have
substantive kick-out rights or participating rights. We are the primary beneficiary of SEP because we have
the power to direct SEP’s activities that most significantly impact its economic performance.
Valley Crossing Pipeline, LLC
Valley Crossing Pipeline, LLC (Valley Crossing), a wholly-owned subsidiary of Enbridge, is constructing a
natural gas pipeline to transport natural gas within Texas. Valley Crossing is considered a VIE due to
insufficient equity at risk to finance its activities. We are the primary beneficiary of Valley Crossing
because we have the power to direct Valley Crossing’s activities that most significantly impact its
economic performance.
140
141
decision and concluded that the project cannot proceed as envisioned. After taking into consideration the
amount recoverable from potential shippers on Northern Gateway Project, we recognized an impairment
of $373 million ($272 million after-tax), which is included in Impairment of property, plant and equipment in
the Consolidated Statements of Earnings. This impairment loss is based on the full carrying value of the
assets, which have an estimated fair value of nil, and are a part of our Liquids Pipelines segment.
Sandpiper Project
On September 1, 2016, we announced that EEP applied for the withdrawal of regulatory applications
pending with the Minnesota Public Utilities Commission for Sandpiper. In connection with this
announcement and other factors, we evaluated Sandpiper for impairment. As a result, we recognized an
impairment loss of $992 million ($81 million after-tax attributable to us) for the year ended December 31,
2016, which is included in Impairment of property, plant and equipment in the Consolidated Statements of
Earnings. Sandpiper is a part of our Liquids Pipelines segment. The estimated remaining fair value of
Sandpiper was based on the estimated price that would be received to sell unused pipe, land and other
related equipment in its current condition, considering the current market conditions for sale of these
assets at the time. The valuation considered a range of potential selling prices from various alternatives
that could be used to dispose of these assets. The estimated fair value, with the exception of $3 million in
land, was reclassified into Deferred amounts and other assets in the Consolidated Statements of
Financial Position as at December 31, 2016. During 2017, we disposed of substantially all of the
remaining Sandpiper assets (Note 7).
For the year ended December 31, 2016, we recorded impairment charges of $11 million related to EEP’s
non-core trucking assets and related facilities, which are a part of our Gas Transmission and Midstream
Other
segment.
For the year ended December 31, 2015, we recorded impairment charges of $96 million, of which $80
million related to EEP’s Berthold rail facility, included within the Liquids Pipelines segment, due to
contracts that were not yet renewed beyond 2016. The remaining $16 million in impairment charges relate
to EEP’s non-core Louisiana propylene pipeline asset, included within the Gas Transmission and
Midstream segment, following finalization of a contract restructuring with a primary customer.
Impairment charges were based on the amount by which the carrying values of the assets exceeded fair
value, determined using expected discounted future cash flows, and such charges are included in
Impairment of property, plant and equipment on the Consolidated Statements of Earnings.
11. VARIABLE INTEREST ENTITIES
CONSOLIDATED VARIABLE INTEREST ENTITIES
Enbridge Energy Partners, L.P.
EEP is a publicly-traded Delaware limited partnership and is considered a VIE as its limited partners do
not have substantive kick-out rights or participating rights. Through our wholly-owned subsidiary, Enbridge
Energy Company, Inc. (EECI), we have the power to direct EEP’s activities and have a significant impact
on EEP’s economic performance. Along with an economic interest held through an indirect common
interest and general partner interest through EECI, and through our 100% ownership of EECI, we are the
primary beneficiary of EEP. As at December 31, 2017 and 2016, our economic interest in EEP was 34.6%
and 35.3% respectively. The public owns the remaining interests in EEP.
Enbridge Income Fund
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. We are the primary
beneficiary of the Fund through our combined 82.5% economic interest held indirectly through a common
investment in ENF, a direct common interest in the Fund, a preferred unit investment in ECT, a direct
common interest in Enbridge Income Partners GP Inc., and a direct common interest in EIPLP. As at
December 31, 2016, our combined economic interest was 86.9%. As at December 31, 2017 and 2016,
our direct common interest in the Fund was 29.4% and 43.2%, respectively. We also serve in the capacity
of Manager of ENF and the Fund Group.
Enbridge Commercial Trust
We have the ability to appoint the majority of the trustees to ECT’s Board of Trustees, resulting in a lack
of decision making ability for the holders of the common trust units of ECT. As a result, ECT is considered
to be a VIE and although we do not have a common equity interest in ECT, we are considered to be the
primary beneficiary of ECT. We also serve in the capacity of Manager of ECT, as part of the Fund Group.
Enbridge Income Partners LP
EIPLP, formed in 2002, is involved in the generation, transportation and storage of energy through
interests in its Liquids Pipelines business, including the Canadian Mainline, the Regional Oil Sands
System, a 50.0% interest in the Alliance Pipeline, which transports natural gas, and its renewable and
alternative power generation facilities. EIPLP is a partnership between an indirect wholly-owned
subsidiary of Enbridge and ECT. EIPLP is considered a VIE as its limited partners lack substantive kick-
out rights and participating rights. Through a majority ownership of EIPLP’s General Partner, 100%
ownership of Enbridge Management Services Inc. (a service provider for EIPLP), and 53.1% of direct
common interest in EIPLP, we have the power to direct the activities that most significantly impact
EIPLP’s economic performance and have the obligation to absorb losses and the right to receive residual
returns that are potentially significant to EIPLP, making us the primary beneficiary of EIPLP. As at
December 31, 2017 and 2016, our economic interest in EIPLP was 73.5% and 79.1%, respectively.
Green Power and Transmission
Through various subsidiaries, we have a majority ownership interest in Magic Valley, Wildcat, Keechi
Wind Project (Keechi), and New Creek wind farms. These wind farms are considered VIEs as they do not
have sufficient equity at risk and are partially financed by tax equity investors. We are the primary
beneficiary of these VIEs by virtue of our voting rights, our power to direct the activities that most
significantly impact the economic performance of the wind farms, and our obligation to absorb losses.
Enbridge Holdings (DakTex) L.L.C.
Enbridge Holdings (DakTex) L.L.C. (DakTex) is owned 75% by a wholly-owned subsidiary of Enbridge
and 25% by EEP, through which we have an effective 27.6% interest in the equity investment, Bakken
Pipeline System (Note 12). EEP is the primary beneficiary because it has the power to direct DakTex’s
activities that most significantly impact its economic performance. We consolidate EEP and by extension
also consolidate DakTex.
Spectra Energy Partners, LP
We acquired a 75% ownership in SEP through the Merger Transaction. SEP is a natural gas and crude oil
infrastructure master limited partnership and is considered a VIE as its limited partners do not have
substantive kick-out rights or participating rights. We are the primary beneficiary of SEP because we have
the power to direct SEP’s activities that most significantly impact its economic performance.
Valley Crossing Pipeline, LLC
Valley Crossing Pipeline, LLC (Valley Crossing), a wholly-owned subsidiary of Enbridge, is constructing a
natural gas pipeline to transport natural gas within Texas. Valley Crossing is considered a VIE due to
insufficient equity at risk to finance its activities. We are the primary beneficiary of Valley Crossing
because we have the power to direct Valley Crossing’s activities that most significantly impact its
economic performance.
140
141
Other Limited Partnerships
By virtue of a lack of substantive kick-out rights and participating rights, substantially all limited
partnerships wholly-owned by us and/or our subsidiaries are considered VIEs. As these entities are 100%
owned and directed by us with no third parties having the ability to direct any of the significant activities,
we are considered the primary beneficiary.
The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of
our consolidated VIEs for which creditors do not have recourse to our general credit as the primary
beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.
December 31,
(millions of Canadian dollars)
Assets
Cash and cash equivalents
Accounts receivable and other
Accounts receivable from affiliates
Inventory
Property, plant and equipment, net
Long-term investments
Restricted long-term investments
Deferred amounts and other assets
Intangible assets, net
Goodwill
Deferred income taxes
Liabilities
Short-term borrowings
Accounts payable and other
Accounts payable to affiliates
Interest payable
Environmental liabilities
Current portion of long-term debt
Long-term debt
Other long-term liabilities
Deferred income taxes
Net assets before noncontrolling interests
2017
2016
368
2,132
3
220
2,723
68,685
6,258
206
2,921
296
29
145
81,263
485
2,859
131
312
35
2,129
5,951
31,469
4,301
3,010
44,731
36,532
314
781
3
53
1,151
45,720
954
83
2,227
488
29
231
50,883
—
1,446
105
204
140
342
2,237
20,176
1,207
1,753
25,373
25,510
We do not have an obligation to provide financial support to any of the consolidated VIEs, with the
exception of EIPLP. We are required, when called on by ENF, to backstop equity funding required by
EIPLP to undertake the growth program embedded in the assets it acquired in the Canadian
Restructuring Plan.
UNCONSOLIDATED VARIABLE INTEREST ENTITIES
Sabal Trail Transmission, LLC
SEP owns a 50% interest in Sabal Trail, a joint venture that operates a pipeline originating in Alabama
that transports natural gas to Florida. On July 3, 2017, we discontinued the consolidation of Sabal Trail
and accounted for our interest under the equity method. Sabal Trail is a VIE due to insufficient equity at
risk to finance its activities. We are not the primary beneficiary because the power to direct Sabal Trail's
activities that most significantly impact its economic performance is shared.
Nexus Gas Transmission, LLC
SEP owns a 50% equity investment in Nexus, a joint venture that is constructing a natural gas pipeline
from Ohio to Michigan and continuing on to Ontario, Canada. Nexus is a VIE due to insufficient equity at
risk to finance its activities. We are not the primary beneficiary because the power to direct Nexus’
activities that most significantly impact its economic performance is shared.
PennEast Pipeline Company, LLC
SEP owned a 10% equity investment in PennEast, which was increased to 20% in June 2017. PennEast
is constructing a natural gas pipeline from northeastern Pennsylvania to New Jersey. PennEast is a VIE
due to insufficient equity at risk to finance its activities. We are not the primary beneficiary since we do not
have the power to direct PennEast’s activities that most significantly impact its economic performance.
We currently hold several equity investments in limited partnerships that are assessed to be VIEs due to
limited partners not having substantive kick-out rights or participating rights. We have determined that we
do not have the power to direct the activities of the VIEs that most significantly impact the VIEs’ economic
performance. Specifically, the power to direct the activities of a majority of these VIEs is shared amongst
the partners. Each partner has representatives that make up an executive committee who makes
significant decisions for the VIE and none of the partners may make major decisions unilaterally.
The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum
exposure to loss as at December 31, 2017 and 2016 is presented below.
Illinois Extension Pipeline Company, L.L.C.4
December 31, 2017
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.1
Eolien Maritime France SAS2
Hohe See Offshore Wind Project3
Nexus Gas Transmission, LLC5
PennEast Pipeline Company, LLC5
Rampion Offshore Wind Limited6
Sabal Trail Transmissions, LLC5
Vector Pipeline L.P.7
Other4
Carrying
Amount of
Investment
Enbridge’s
Maximum
Exposure to
in VIE
Loss
300
69
763
686
834
69
555
169
21
2,355
5,821
361
754
2,484
686
1,678
2,529
345
679
278
21
9,815
142
143
Other Limited Partnerships
By virtue of a lack of substantive kick-out rights and participating rights, substantially all limited
partnerships wholly-owned by us and/or our subsidiaries are considered VIEs. As these entities are 100%
owned and directed by us with no third parties having the ability to direct any of the significant activities,
we are considered the primary beneficiary.
The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of
our consolidated VIEs for which creditors do not have recourse to our general credit as the primary
beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.
December 31,
(millions of Canadian dollars)
Assets
Cash and cash equivalents
Accounts receivable and other
Accounts receivable from affiliates
Inventory
Property, plant and equipment, net
Long-term investments
Restricted long-term investments
Deferred amounts and other assets
Intangible assets, net
Goodwill
Deferred income taxes
Liabilities
Short-term borrowings
Accounts payable and other
Accounts payable to affiliates
Interest payable
Environmental liabilities
Current portion of long-term debt
Long-term debt
Other long-term liabilities
Deferred income taxes
2017
2016
81,263
50,883
368
2,132
3
220
2,723
68,685
6,258
206
2,921
296
29
145
485
2,859
131
312
35
2,129
5,951
31,469
4,301
3,010
44,731
36,532
314
781
3
53
1,151
45,720
2,227
954
83
488
29
231
—
1,446
105
204
140
342
2,237
20,176
1,207
1,753
25,373
25,510
Net assets before noncontrolling interests
We do not have an obligation to provide financial support to any of the consolidated VIEs, with the
exception of EIPLP. We are required, when called on by ENF, to backstop equity funding required by
EIPLP to undertake the growth program embedded in the assets it acquired in the Canadian
Restructuring Plan.
UNCONSOLIDATED VARIABLE INTEREST ENTITIES
Sabal Trail Transmission, LLC
SEP owns a 50% interest in Sabal Trail, a joint venture that operates a pipeline originating in Alabama
that transports natural gas to Florida. On July 3, 2017, we discontinued the consolidation of Sabal Trail
and accounted for our interest under the equity method. Sabal Trail is a VIE due to insufficient equity at
risk to finance its activities. We are not the primary beneficiary because the power to direct Sabal Trail's
activities that most significantly impact its economic performance is shared.
Nexus Gas Transmission, LLC
SEP owns a 50% equity investment in Nexus, a joint venture that is constructing a natural gas pipeline
from Ohio to Michigan and continuing on to Ontario, Canada. Nexus is a VIE due to insufficient equity at
risk to finance its activities. We are not the primary beneficiary because the power to direct Nexus’
activities that most significantly impact its economic performance is shared.
PennEast Pipeline Company, LLC
SEP owned a 10% equity investment in PennEast, which was increased to 20% in June 2017. PennEast
is constructing a natural gas pipeline from northeastern Pennsylvania to New Jersey. PennEast is a VIE
due to insufficient equity at risk to finance its activities. We are not the primary beneficiary since we do not
have the power to direct PennEast’s activities that most significantly impact its economic performance.
We currently hold several equity investments in limited partnerships that are assessed to be VIEs due to
limited partners not having substantive kick-out rights or participating rights. We have determined that we
do not have the power to direct the activities of the VIEs that most significantly impact the VIEs’ economic
performance. Specifically, the power to direct the activities of a majority of these VIEs is shared amongst
the partners. Each partner has representatives that make up an executive committee who makes
significant decisions for the VIE and none of the partners may make major decisions unilaterally.
The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum
exposure to loss as at December 31, 2017 and 2016 is presented below.
December 31, 2017
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.1
Eolien Maritime France SAS2
Hohe See Offshore Wind Project3
Illinois Extension Pipeline Company, L.L.C.4
Nexus Gas Transmission, LLC5
PennEast Pipeline Company, LLC5
Rampion Offshore Wind Limited6
Sabal Trail Transmissions, LLC5
Vector Pipeline L.P.7
Other4
Carrying
Amount of
Investment
in VIE
Enbridge’s
Maximum
Exposure to
Loss
300
69
763
686
834
69
555
2,355
169
21
5,821
361
754
2,484
686
1,678
345
679
2,529
278
21
9,815
142
143
158
19
58
759
345
159
17
1,515
Carrying
Amount of
Investment
in VIE
Enbridge’s
Maximum
Exposure to
Loss
December 31, 2016
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.
Eddystone Rail Company, LLC8
Eolien Maritime France SAS
Illinois Extension Pipeline Company, L.L.C.
Rampion Offshore Wind Limited
Vector Pipeline L.P.
Other
223
25
686
759
457
289
17
2,456
1 At December 31, 2017, the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing
on a bank credit facility.
2 At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in
project construction contracts in which we would be liable for in the event of default by the VIE and an outstanding affiliate loan
receivable for $163 million held by us.
3 At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in
project construction contracts in which we would be liable for in the event of default by the VIE.
4 At December 31, 2017, the maximum exposure to loss is limited to our equity investment as these companies are in operation
and self-sustaining.
5 At December 31, 2017 the maximum exposure to loss is limited to our equity investment and the remaining expected
contributions for each joint venture.
6 At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in
project construction contracts in which we would be liable for in the event of default by the VIE.
7 At December 31, 2017 the maximum exposure to loss includes the carrying value of an outstanding loan issued by us.
8 As at December 31, 2017, Eddystone Rail Company, LLC is a 100% owned subsidiary and therefore is no longer an
unconsolidated VIE.
We do not have an obligation to and did not provide any additional financial support to the VIEs during the
years ended December 31, 2017 and 2016.
144
145
12. LONG-TERM INVESTMENTS
December 31,
(millions of Canadian dollars)
EQUITY INVESTMENTS
Liquids Pipelines
Bakken Pipeline System1
Eddystone Rail Company, LLC
Seaway Crude Pipeline System
Illinois Extension Pipeline Company, L.L.C.2
Other
Gas Transmission and Midstream
Alliance Pipeline3
Aux Sable
DCP Midstream, LLC4
Gulfstream Natural Gas System, L.L.C.4
Nexus Gas Transmission, LLC4
Offshore - various joint ventures
PennEast Pipeline Company LLC4
Sabal Trail Transmission, LLC5
Southeast Supply Header L.L.C.4
Steckman Ridge LP4
Texas Express Pipeline
Vector Pipeline L.P.
Other4
Gas Distribution
Noverco Common Shares
Other4
Green Power and Transmission
Eolien Maritime France SAS6
Hohe See Offshore Wind Project7
Rampion Offshore Wind Project
Eliminations and Other
Other
Other
OTHER LONG-TERM INVESTMENTS
Gas Distribution
Noverco Preferred Shares
Green Power and Transmission
Emerging Technologies and Other
Eliminations and Other
Other
Ownership
Interest
2017
2016
27.6%
100.0%
50.0%
65.0%
30.0% - 43.8%
42.7% - 50.0%
22.0% - 74.3%
50.0%
50.0%
50.0%
50.0%
20.0%
50.0%
50.0%
49.5%
35.0%
60.0%
38.9%
50.0%
50.0%
50.0%
24.9%
33.3% - 50.0%
19.0% - 50.0%
19.0% - 42.7%
1,938
—
2,882
2,143
1,205
2,355
686
87
375
300
834
389
69
486
221
430
169
34
—
15
69
763
555
95
26
80
67
—
19
3,129
759
70
411
324
435
—
—
—
—
—
—
—
484
159
4
—
—
58
—
345
100
15
90
79
371
355
16,644
6,836
1 On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines
(collectively, the Bakken Pipeline System) for a purchase price of $2 billion (US$1.5 billion). The Bakken Pipeline System was
placed into service on June 1, 2017. For details regarding our funding arrangement, refer to Note 19 - Noncontrolling Interests.
2 Owns the Southern Access Extension Project.
3 Certain assets of the Alliance Pipeline are pledged as collateral to Alliance Pipeline lenders.
4 On February 27, 2017, we acquired Spectra Energy's interests in DCP Midstream, Gulfstream Natural Gas System, L.L.C, Nexus,
PennEast, Southeast Supply Header L.L.C., Steckman Ridge LP and other equity investments as part of the Merger Transaction
(Note 7).
5 On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note
7). On July 3, 2017, Sabal Trail was placed into service and the assets, liabilities, and noncontrolling interests were
deconsolidated as at the in-service date.
6 On May 19, 2016, we acquired a 50% equity interest in Eolien Maritime France SAS.
7 On February 8, 2017, we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG.
Carrying
Amount of
Investment
Enbridge’s
Maximum
Exposure to
in VIE
Loss
158
19
58
759
345
159
17
223
25
686
759
457
289
17
1,515
2,456
December 31, 2016
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.
Eddystone Rail Company, LLC8
Eolien Maritime France SAS
Illinois Extension Pipeline Company, L.L.C.
Rampion Offshore Wind Limited
Vector Pipeline L.P.
Other
on a bank credit facility.
1 At December 31, 2017, the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing
2 At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in
project construction contracts in which we would be liable for in the event of default by the VIE and an outstanding affiliate loan
receivable for $163 million held by us.
3 At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in
project construction contracts in which we would be liable for in the event of default by the VIE.
4 At December 31, 2017, the maximum exposure to loss is limited to our equity investment as these companies are in operation
5 At December 31, 2017 the maximum exposure to loss is limited to our equity investment and the remaining expected
and self-sustaining.
contributions for each joint venture.
6 At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in
project construction contracts in which we would be liable for in the event of default by the VIE.
7 At December 31, 2017 the maximum exposure to loss includes the carrying value of an outstanding loan issued by us.
8 As at December 31, 2017, Eddystone Rail Company, LLC is a 100% owned subsidiary and therefore is no longer an
unconsolidated VIE.
We do not have an obligation to and did not provide any additional financial support to the VIEs during the
years ended December 31, 2017 and 2016.
12. LONG-TERM INVESTMENTS
December 31,
(millions of Canadian dollars)
EQUITY INVESTMENTS
Liquids Pipelines
Bakken Pipeline System1
Eddystone Rail Company, LLC
Seaway Crude Pipeline System
Illinois Extension Pipeline Company, L.L.C.2
Other
Gas Transmission and Midstream
Alliance Pipeline3
Aux Sable
DCP Midstream, LLC4
Gulfstream Natural Gas System, L.L.C.4
Nexus Gas Transmission, LLC4
Offshore - various joint ventures
PennEast Pipeline Company LLC4
Sabal Trail Transmission, LLC5
Southeast Supply Header L.L.C.4
Steckman Ridge LP4
Texas Express Pipeline
Vector Pipeline L.P.
Other4
Gas Distribution
Noverco Common Shares
Other4
Green Power and Transmission
Eolien Maritime France SAS6
Hohe See Offshore Wind Project7
Rampion Offshore Wind Project
Other
Eliminations and Other
Other
OTHER LONG-TERM INVESTMENTS
Gas Distribution
Noverco Preferred Shares
Green Power and Transmission
Emerging Technologies and Other
Eliminations and Other
Ownership
Interest
2017
2016
27.6%
100.0%
50.0%
65.0%
30.0% - 43.8%
50.0%
42.7% - 50.0%
50.0%
50.0%
50.0%
22.0% - 74.3%
20.0%
50.0%
50.0%
49.5%
35.0%
60.0%
33.3% - 50.0%
38.9%
50.0%
50.0%
50.0%
24.9%
19.0% - 50.0%
19.0% - 42.7%
1,938
—
2,882
686
87
375
300
2,143
1,205
834
389
69
2,355
486
221
430
169
34
—
15
69
763
555
95
26
371
80
—
19
3,129
759
70
411
324
—
—
—
435
—
—
—
—
484
159
4
—
—
58
—
345
100
15
355
90
Other
79
6,836
1 On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines
(collectively, the Bakken Pipeline System) for a purchase price of $2 billion (US$1.5 billion). The Bakken Pipeline System was
placed into service on June 1, 2017. For details regarding our funding arrangement, refer to Note 19 - Noncontrolling Interests.
67
16,644
2 Owns the Southern Access Extension Project.
3 Certain assets of the Alliance Pipeline are pledged as collateral to Alliance Pipeline lenders.
4 On February 27, 2017, we acquired Spectra Energy's interests in DCP Midstream, Gulfstream Natural Gas System, L.L.C, Nexus,
PennEast, Southeast Supply Header L.L.C., Steckman Ridge LP and other equity investments as part of the Merger Transaction
(Note 7).
5 On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note
7). On July 3, 2017, Sabal Trail was placed into service and the assets, liabilities, and noncontrolling interests were
deconsolidated as at the in-service date.
6 On May 19, 2016, we acquired a 50% equity interest in Eolien Maritime France SAS.
7 On February 8, 2017, we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG.
144
145
Equity investments include the unamortized excess of the purchase price over the underlying net book
value of the investees’ assets at the purchase date. As at December 31, 2017, this comprised of $2.0
billion in Goodwill and $643 million in amortizable assets. As at December 31, 2016, this comprised of
$859 million in Goodwill and $687 million in amortizable assets.
For the years ended December 31, 2017, 2016 and 2015, dividends received from equity investments
were $1.4 billion, $825 million and $719 million, respectively.
Summarized combined financial information of our interest in unconsolidated equity investments
(presented at 100%) is as follows:
2017
Year Ended December 31,
2016
2015
Seaway
Other
Total Seaway
Other
Total Seaway
Other
Total
959
286
672
336
15,254
12,911
2,056
16,213
13,197
2,728
926
1,262
938
293
643
322
3,164
3,051
(2)
4,102
3,344
641
147
469
833
263
566
283
3,054
2,210
512
3,887
2,473
1,078
207
490
December 31, 2017
December 31, 2016
Seaway
Other
Total Seaway
Other
Total
3,432
106
41,697
3,329
3,311
143
13
13,582
— 3,191
3,538
45,026
3,454
13,595
3,191
86
3,651
172
13
—
842
12,264
831
5,121
—
928
15,915
1,003
5,134
—
(millions of Canadian
dollars)
Operating revenues
Operating expenses
Earnings
Earnings attributable to
controlling interests
(millions of Canadian dollars)
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Noncontrolling interests
Eddystone Rail Company, LLC
On October 19, 2017, we sold all assets related to Eddystone Rail Company, LLC (Eddystone Rail) in
exchange for the remaining 25% interest of the joint venture. As a result, Eddystone Rail is now 100%
owned and carried at nil value.
During the year ended December 31, 2016, we recorded an investment impairment of $184 million
related to our 75% joint venture interest in Eddystone Rail at the time, which is held through Enbridge Rail
(Philadelphia) L.L.C., a wholly-owned subsidiary. Eddystone Rail is a rail-to-barge transloading facility
located in the greater Philadelphia, Pennsylvania area that delivers Bakken and other light sweet crude oil
to Philadelphia area refineries. Due to a significant decrease in price spreads between Bakken crude oil
and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail
services dropped significantly, which led to the completion of an impairment test. The impairment charge
is presented within Income from equity investments on the Consolidated Statements of Earnings. The
investment in Eddystone Rail is a part of our Liquids Pipelines segment.
The impairment charge was based on the amount by which the carrying value of the asset exceeded fair
value, determined using an adjusted net worth approach. Our estimate of fair value required us to use
significant unobservable inputs representative of a Level 3 fair value measurement, including
assumptions related to the future performance of Eddystone Rail.
Aux Sable
During the year ended December 31, 2016, Aux Sable recorded an asset impairment charge of $37
million related to certain underutilized assets at Aux Sable US' NGL extraction and fractionation plant.
Sabal Trail Transmission, LLC
On July 3, 2017, Sabal Trail was placed into service. In accordance with the Sabal Trail LLC Agreement,
upon the in-service date, the power to direct Sabal Trail’s activities become shared with its members. We
are no longer the primary beneficiary and deconsolidated the assets, liabilities and noncontrolling
interests related to Sabal Trail as at the in-service date.
At deconsolidation, our 50% interest in Sabal Trail was recorded at its fair value of $2.3 billion (US$1.9
billion), which approximated its carrying value as a long-term equity investment. As a result, there was no
gain or loss recognized for the year ended December 31, 2017 related to the remeasurement of the
retained equity interest to its fair value. The fair value was determined using the income approach which
is based on the present value of the future cash flows.
Noverco Inc.
As at December 31, 2017 and 2016, we owned an equity interest in Noverco through ownership of 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 margin of 4.38%.
As at December 31, 2017 and 2016, Noverco owned an approximate 1.9% and 3.4% reciprocal
shareholding in our common shares, respectively. Through secondary offerings, Noverco purchased 1.2
million common shares in February 2016. Shares purchased and sold in this transaction were treated as
treasury stock on the Consolidated Statements of Changes in Equity.
As a result of Noverco’s reciprocal shareholding in our common shares, as at December 31, 2017 and
2016, we had an indirect pro-rata interest of 0.7% and 1.3%, respectively, in our own shares. Both the
equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding
of $102 million as at December 31, 2017 and 2016. Noverco records dividends paid from us as dividend
income and we eliminate these dividends from our equity earnings of Noverco. We record our pro-rata
share of dividends paid by us to Noverco as a reduction of dividends paid and an increase in our
investment in Noverco.
13. RESTRICTED LONG-TERM INVESTMENTS
Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline
abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements
under LMCI. The funds collected are held in trusts in accordance with the NEB decision. The funds
collected from shippers are reported within Transportation and other services revenues on the
Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated
Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to
Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term
liabilities on the Consolidated Statements of Financial Position.
We routinely invest excess cash and various restricted balances in securities such as commercial paper,
bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money
market securities in the United States and Canada.
As at December 31, 2017 and 2016, we had restricted long-term investments held in trust and classified
as held for sale and carried at fair value of $267 million and $90 million, respectively. We had estimated
future abandonment costs related to LMCI of $151 million and $97 million as at December 31, 2017 and
2016, respectively.
146
147
Equity investments include the unamortized excess of the purchase price over the underlying net book
value of the investees’ assets at the purchase date. As at December 31, 2017, this comprised of $2.0
billion in Goodwill and $643 million in amortizable assets. As at December 31, 2016, this comprised of
$859 million in Goodwill and $687 million in amortizable assets.
For the years ended December 31, 2017, 2016 and 2015, dividends received from equity investments
were $1.4 billion, $825 million and $719 million, respectively.
Summarized combined financial information of our interest in unconsolidated equity investments
(presented at 100%) is as follows:
2017
2016
2015
Year Ended December 31,
Seaway
Other
Total Seaway
Other
Total Seaway
Other
Total
959
286
672
336
15,254
12,911
2,056
16,213
13,197
2,728
926
1,262
938
293
643
322
3,164
3,051
(2)
4,102
3,344
641
3,054
2,210
512
3,887
2,473
1,078
147
469
207
490
833
263
566
283
December 31, 2017
December 31, 2016
Seaway
Other
Total Seaway
Other
Total
106
3,329
143
13
3,432
41,697
3,311
13,582
— 3,191
3,538
45,026
3,454
13,595
3,191
86
842
928
3,651
12,264
15,915
172
13
—
831
5,121
—
1,003
5,134
—
(millions of Canadian
dollars)
Operating revenues
Operating expenses
Earnings
Earnings attributable to
controlling interests
(millions of Canadian dollars)
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Noncontrolling interests
Eddystone Rail Company, LLC
On October 19, 2017, we sold all assets related to Eddystone Rail Company, LLC (Eddystone Rail) in
exchange for the remaining 25% interest of the joint venture. As a result, Eddystone Rail is now 100%
owned and carried at nil value.
During the year ended December 31, 2016, we recorded an investment impairment of $184 million
related to our 75% joint venture interest in Eddystone Rail at the time, which is held through Enbridge Rail
(Philadelphia) L.L.C., a wholly-owned subsidiary. Eddystone Rail is a rail-to-barge transloading facility
located in the greater Philadelphia, Pennsylvania area that delivers Bakken and other light sweet crude oil
to Philadelphia area refineries. Due to a significant decrease in price spreads between Bakken crude oil
and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail
services dropped significantly, which led to the completion of an impairment test. The impairment charge
is presented within Income from equity investments on the Consolidated Statements of Earnings. The
investment in Eddystone Rail is a part of our Liquids Pipelines segment.
The impairment charge was based on the amount by which the carrying value of the asset exceeded fair
value, determined using an adjusted net worth approach. Our estimate of fair value required us to use
significant unobservable inputs representative of a Level 3 fair value measurement, including
assumptions related to the future performance of Eddystone Rail.
Aux Sable
During the year ended December 31, 2016, Aux Sable recorded an asset impairment charge of $37
million related to certain underutilized assets at Aux Sable US' NGL extraction and fractionation plant.
Sabal Trail Transmission, LLC
On July 3, 2017, Sabal Trail was placed into service. In accordance with the Sabal Trail LLC Agreement,
upon the in-service date, the power to direct Sabal Trail’s activities become shared with its members. We
are no longer the primary beneficiary and deconsolidated the assets, liabilities and noncontrolling
interests related to Sabal Trail as at the in-service date.
At deconsolidation, our 50% interest in Sabal Trail was recorded at its fair value of $2.3 billion (US$1.9
billion), which approximated its carrying value as a long-term equity investment. As a result, there was no
gain or loss recognized for the year ended December 31, 2017 related to the remeasurement of the
retained equity interest to its fair value. The fair value was determined using the income approach which
is based on the present value of the future cash flows.
Noverco Inc.
As at December 31, 2017 and 2016, we owned an equity interest in Noverco through ownership of 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 margin of 4.38%.
As at December 31, 2017 and 2016, Noverco owned an approximate 1.9% and 3.4% reciprocal
shareholding in our common shares, respectively. Through secondary offerings, Noverco purchased 1.2
million common shares in February 2016. Shares purchased and sold in this transaction were treated as
treasury stock on the Consolidated Statements of Changes in Equity.
As a result of Noverco’s reciprocal shareholding in our common shares, as at December 31, 2017 and
2016, we had an indirect pro-rata interest of 0.7% and 1.3%, respectively, in our own shares. Both the
equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding
of $102 million as at December 31, 2017 and 2016. Noverco records dividends paid from us as dividend
income and we eliminate these dividends from our equity earnings of Noverco. We record our pro-rata
share of dividends paid by us to Noverco as a reduction of dividends paid and an increase in our
investment in Noverco.
13. RESTRICTED LONG-TERM INVESTMENTS
Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline
abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements
under LMCI. The funds collected are held in trusts in accordance with the NEB decision. The funds
collected from shippers are reported within Transportation and other services revenues on the
Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated
Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to
Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term
liabilities on the Consolidated Statements of Financial Position.
We routinely invest excess cash and various restricted balances in securities such as commercial paper,
bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money
market securities in the United States and Canada.
As at December 31, 2017 and 2016, we had restricted long-term investments held in trust and classified
as held for sale and carried at fair value of $267 million and $90 million, respectively. We had estimated
future abandonment costs related to LMCI of $151 million and $97 million as at December 31, 2017 and
2016, respectively.
146
147
14. INTANGIBLE ASSETS
15. GOODWILL
The following table provides the weighted average amortization rate, gross carrying value, accumulated
amortization and net carrying value for each of our major classes of intangible assets:
December 31, 20171
(millions of Canadian dollars)
Customer relationships
Power purchase agreements
Project agreement2
Software
Other intangible assets3
Weighted Average
Amortization Rate
Accumulated
Amortization
Cost
3.5%
3.5%
4.0%
11.3%
4.4%
967
99
150
1,760
1,162
4,138
41
17
3
714
96
871
1 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7).
2 Represents a project agreement acquired from the Merger Transaction (Note 7).
3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets.
December 31, 2016
(millions of Canadian dollars)
Customer relationships
Natural gas supply opportunities
Power purchase agreements
Software
Other intangible assets
Weighted Average
Amortization Rate
Accumulated
Amortization
Cost
3.0%
3.2%
3.2%
11.8%
4.8%
251
435
100
1,388
213
2,387
4
127
14
607
62
814
Net
926
82
147
1,046
1,066
3,267
Net
247
308
86
781
151
1,573
For the years ended December 31, 2017, 2016 and 2015, our amortization expense related to intangible
assets totaled $280 million, $177 million and $158 million, respectively. The following table presents our
forecast of amortization expense associated with existing intangible assets for the years indicated as
follows in millions of Canadian dollars:
2018
264
2019
240
2020
217
2021
197
2022
179
Gas
Green Power
Liquids
Transmission
Gas
and
Energy
Eliminations
Pipelines
& Midstream
Distribution
Transmission
Services
and Other Consolidated
(millions of Canadian dollars)
Gross Cost
Balance at January 1, 2016
Foreign exchange and other
Balance at December 31, 2016
Acquired in Merger Transaction
Sabal Trail deconsolidation (Note
(Note 7)
12)
Disposition
Foreign exchange and other
Balance at December 31, 2017
Accumulated Impairment
Balance at January 1, 2016
Impairment
Impairment
Balance at December 31, 2016
Balance at December 31, 2017
Carrying Value
60
(1)
59
—
(29)
(314)
7,786
—
—
—
—
—
8,070
22,914
5,672
458
(1)
457
(966)
—
(866)
(440)
—
(440)
(102)
(542)
7
—
7
—
—
(7)
—
(7)
—
(7)
21,539
5,679
Balance at December 31, 2016
Balance at December 31, 2017
59
7,786
17
20,997
—
5,672
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
—
2
—
—
—
2
—
—
—
—
—
2
2
13
—
13
—
—
—
13
(13)
—
(13)
—
(13)
—
—
540
(2)
538
36,656
(966)
(29)
(1,180)
35,019
(460)
—
(460)
(102)
(562)
78
34,457
ACQUISITION AND DISPOSITION
In 2017, we recognized $36.7 billion of goodwill on the Merger Transaction and derecognized $29 million
of goodwill on the disposition of Olympic Pipeline.
IMPAIRMENT
US Midstream
Gas Transmission and Midstream
During the year ended December 31, 2017, we recorded a goodwill impairment charge of $102 million
related to certain assets in our Gas Transmission and Midstream segment classified as held for sale (Note
7). Goodwill was allocated to certain disposal groups qualifying as a business based on a relative fair
value approach. In connection with the write-down of the carrying values of the assets held for sale to its
fair value less costs to sell, the related goodwill was impaired. The fair value of these assets were
estimated using the discounted cash flow method, which was negatively impacted by prolonged decline in
commodity prices and deteriorating business performance. We also performed goodwill impairment
testing on the associated gas midstream reporting unit resulting in no additional impairment charge.
The estimate of the gas midstream reporting unit’s fair value required the use of significant unobservable
inputs representative of a Level 3 fair value measurement, including assumptions related to the future
performance of the reporting unit.
148
149
14. INTANGIBLE ASSETS
15. GOODWILL
The following table provides the weighted average amortization rate, gross carrying value, accumulated
amortization and net carrying value for each of our major classes of intangible assets:
Weighted Average
Amortization Rate
Accumulated
Cost
Amortization
December 31, 20171
(millions of Canadian dollars)
Customer relationships
Power purchase agreements
Project agreement2
Software
Other intangible assets3
December 31, 2016
(millions of Canadian dollars)
Customer relationships
Natural gas supply opportunities
Power purchase agreements
Software
Other intangible assets
3.5%
3.5%
4.0%
11.3%
4.4%
3.0%
3.2%
3.2%
11.8%
4.8%
967
99
150
1,760
1,162
4,138
251
435
100
1,388
213
2,387
Net
926
82
147
1,046
1,066
3,267
Net
247
308
86
781
151
1,573
41
17
3
714
96
871
4
127
14
607
62
814
1 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7).
2 Represents a project agreement acquired from the Merger Transaction (Note 7).
3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets.
Weighted Average
Amortization Rate
Accumulated
Cost
Amortization
For the years ended December 31, 2017, 2016 and 2015, our amortization expense related to intangible
assets totaled $280 million, $177 million and $158 million, respectively. The following table presents our
forecast of amortization expense associated with existing intangible assets for the years indicated as
follows in millions of Canadian dollars:
2018
264
2019
240
2020
217
2021
197
2022
179
Liquids
Pipelines
Gas
Transmission
& Midstream
Gas
Distribution
Green Power
and
Transmission
Energy
Services
Eliminations
and Other Consolidated
(millions of Canadian dollars)
Gross Cost
Balance at January 1, 2016
Foreign exchange and other
Balance at December 31, 2016
Acquired in Merger Transaction
(Note 7)
Sabal Trail deconsolidation (Note
12)
Disposition
Foreign exchange and other
Balance at December 31, 2017
Accumulated Impairment
Balance at January 1, 2016
Impairment
Balance at December 31, 2016
Impairment
Balance at December 31, 2017
Carrying Value
Balance at December 31, 2016
Balance at December 31, 2017
60
(1)
59
458
(1)
457
7
—
7
8,070
22,914
5,672
—
(29)
(314)
7,786
—
—
—
—
—
(966)
—
(866)
21,539
(440)
—
(440)
(102)
(542)
—
—
5,679
(7)
—
(7)
—
(7)
59
7,786
17
20,997
—
5,672
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
—
2
—
—
—
2
—
—
—
—
—
2
2
13
—
13
—
—
—
13
(13)
—
(13)
—
(13)
—
—
540
(2)
538
36,656
(966)
(29)
(1,180)
35,019
(460)
—
(460)
(102)
(562)
78
34,457
ACQUISITION AND DISPOSITION
In 2017, we recognized $36.7 billion of goodwill on the Merger Transaction and derecognized $29 million
of goodwill on the disposition of Olympic Pipeline.
IMPAIRMENT
Gas Transmission and Midstream
US Midstream
During the year ended December 31, 2017, we recorded a goodwill impairment charge of $102 million
related to certain assets in our Gas Transmission and Midstream segment classified as held for sale (Note
7). Goodwill was allocated to certain disposal groups qualifying as a business based on a relative fair
value approach. In connection with the write-down of the carrying values of the assets held for sale to its
fair value less costs to sell, the related goodwill was impaired. The fair value of these assets were
estimated using the discounted cash flow method, which was negatively impacted by prolonged decline in
commodity prices and deteriorating business performance. We also performed goodwill impairment
testing on the associated gas midstream reporting unit resulting in no additional impairment charge.
The estimate of the gas midstream reporting unit’s fair value required the use of significant unobservable
inputs representative of a Level 3 fair value measurement, including assumptions related to the future
performance of the reporting unit.
148
149
Enbridge Energy Partners, L.P.
During the year ended December 31, 2015, we recorded a goodwill impairment loss of $440 million ($167
million after-tax attributable to us) related to EEP’s natural gas and NGL businesses, which EEP held
directly and indirectly through its partially-owned subsidiary, MEP. Due to a prolonged decline in
commodity prices, reduction in producers’ expected drilling programs negatively impacted forecasted
cash flows from EEP’s natural gas and NGL systems. This change in circumstance led to the completion
of an impairment test, resulting in a full impairment of goodwill on EEP’s natural gas and NGL businesses.
In performing the impairment assessment, EEP measured the fair value of its reporting units primarily by
using a discounted cash flow analysis and it also considered overall market capitalization of its business,
cash flow measurement data and other factors. EEP’s estimate of fair value required it to use significant
unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to
the future performance of its reporting units.
16. ACCOUNTS PAYABLE AND OTHER
December 31,
(millions of Canadian dollars)
Trade payables and operating accrued liabilities
Construction payables and contractor holdbacks
Current derivative liabilities
Dividends payable
Other
2017
2016
5,135
706
1,130
1,169
1,338
9,478
3,718
712
1,941
29
895
7,295
17. DEBT
December 31,
Enbridge Inc.
(millions of Canadian dollars)
United States dollar term notes1
Medium-term notes
Fixed-to-floating subordinated term notes2,3
Floating rate notes4
Commercial paper and credit facility draws5
Other6
Enbridge (U.S.) Inc.
Medium-term notes7
Commercial paper and credit facility draws8
Enbridge Energy Partners, L.P.
Senior notes9
Junior subordinated notes10
Commercial paper and credit facility draws11
Enbridge Gas Distribution Inc.
Commercial paper and credit facility draws
Commercial paper and credit facility draws
Enbridge Pipelines (Southern Lights) L.L.C.
Medium-term notes
Debentures
Enbridge Income Fund
Medium-term notes
Senior notes12
Enbridge Pipelines Inc.
Medium-term notes13
Debentures
Commercial paper and credit facility draws14
Commercial paper and credit facility draws16
Other6
Enbridge Southern Lights LP
Midcoast Energy Partners, L.P.
Senior notes
Senior notes15
Spectra Energy Capital17
Senior notes18
Spectra Energy Partners, LP17
Senior secured notes19
Senior notes20
Floating rate notes21
Union Gas Limited17
Medium-term notes
Senior debentures
Debentures
Westcoast Energy Inc.17
Senior secured notes
Medium-term notes
Debentures
Other23
Total debt
Current maturities
Short-term borrowings24
Long-term debt
Commercial paper and credit facility draws22
Commercial paper and credit facility draws
Fair value adjustment - Spectra Energy acquisition
Weighted Average
Interest Rate
Maturity
2017
2016
4.1%
4.4%
5.6%
2.3%
2022-2046
2019-2064
2077
2019-2020
2019-2022
2.1%
2019
6.2%
2018-2045
2.3%
2019-2022
2020-2050
2018-2044
2067
2024
2019
2020
2040
2024
2019
2018-2046
2018-2045
2020
2020
2022
2018
2021
2019
2018-2047
2018-2025
2019-2041
2018-2026
4.5%
9.9%
1.4%
4.3%
2.9%
4.0%
4.5%
8.2%
1.5%
6.1%
2.7%
2.0%
4.2%
8.7%
8.7%
1.3%
6.4%
4.7%
8.6%
4.0%
2040
4.1%
2019-2024
5.3%
2018-2038
5,889
5,698
3,843
2,254
2,729
3
—
490
6,328
501
1,820
3,695
85
960
1,750
755
1,207
4,525
200
1,438
4
315
501
—
1,665
138
7,192
501
2,824
3,490
75
250
485
66
2,177
525
1,114
4,968
4,498
1,007
1,171
4,672
4
14
126
6,781
537
2,226
3,904
85
351
2,075
225
1,342
4,525
200
1,032
4
323
537
564
—
—
—
—
—
—
—
—
—
—
—
—
—
(312)
65,180
(2,871)
(1,444)
60,865
(226)
40,945
(4,100)
(351)
36,494
150
151
1 2017 - US$4,700 million; 2016 - US$3,700 million.
2 2017 - $1,650 million and US$1,750 million; 2016 - US$750 million. For the initial 10 years, the notes carry a fixed interest rate.
Subsequently, the interest rate will be floating and set to equal the three-month Bankers' Acceptance Rate or London Interbank
Offered Rate (LIBOR) plus a margin.
Enbridge Energy Partners, L.P.
During the year ended December 31, 2015, we recorded a goodwill impairment loss of $440 million ($167
million after-tax attributable to us) related to EEP’s natural gas and NGL businesses, which EEP held
directly and indirectly through its partially-owned subsidiary, MEP. Due to a prolonged decline in
commodity prices, reduction in producers’ expected drilling programs negatively impacted forecasted
cash flows from EEP’s natural gas and NGL systems. This change in circumstance led to the completion
of an impairment test, resulting in a full impairment of goodwill on EEP’s natural gas and NGL businesses.
In performing the impairment assessment, EEP measured the fair value of its reporting units primarily by
using a discounted cash flow analysis and it also considered overall market capitalization of its business,
cash flow measurement data and other factors. EEP’s estimate of fair value required it to use significant
unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to
the future performance of its reporting units.
16. ACCOUNTS PAYABLE AND OTHER
December 31,
(millions of Canadian dollars)
Trade payables and operating accrued liabilities
Construction payables and contractor holdbacks
Current derivative liabilities
Dividends payable
Other
2017
2016
5,135
706
1,130
1,169
1,338
9,478
3,718
712
1,941
29
895
7,295
17. DEBT
December 31,
(millions of Canadian dollars)
Enbridge Inc.
United States dollar term notes1
Medium-term notes
Fixed-to-floating subordinated term notes2,3
Floating rate notes4
Commercial paper and credit facility draws5
Other6
Enbridge (U.S.) Inc.
Medium-term notes7
Commercial paper and credit facility draws8
Enbridge Energy Partners, L.P.
Senior notes9
Junior subordinated notes10
Commercial paper and credit facility draws11
Enbridge Gas Distribution Inc.
Medium-term notes
Debentures
Commercial paper and credit facility draws
Enbridge Income Fund
Medium-term notes
Commercial paper and credit facility draws
Enbridge Pipelines (Southern Lights) L.L.C.
Senior notes12
Enbridge Pipelines Inc.
Medium-term notes13
Debentures
Commercial paper and credit facility draws14
Other6
Enbridge Southern Lights LP
Senior notes
Midcoast Energy Partners, L.P.
Senior notes15
Commercial paper and credit facility draws16
Spectra Energy Capital17
Senior notes18
Spectra Energy Partners, LP17
Senior secured notes19
Senior notes20
Floating rate notes21
Commercial paper and credit facility draws22
Union Gas Limited17
Medium-term notes
Senior debentures
Debentures
Commercial paper and credit facility draws
Westcoast Energy Inc.17
Senior secured notes
Medium-term notes
Debentures
Weighted Average
Interest Rate
Maturity
2017
2016
4.1%
4.4%
5.6%
2.3%
2.1%
6.2%
2.3%
4.5%
9.9%
1.4%
4.3%
2.9%
4.0%
4.5%
8.2%
1.5%
2022-2046
2019-2064
2077
2019-2020
2019-2022
2019
2018-2045
2067
2019-2022
2020-2050
2024
2019
2018-2044
2020
2040
2018-2046
2024
2019
4.0%
2040
4.1%
2019-2024
5.3%
2018-2038
6.1%
2.7%
2.0%
4.2%
8.7%
8.7%
1.3%
6.4%
4.7%
8.6%
2020
2018-2045
2020
2022
2018-2047
2018
2018-2025
2021
2019
2019-2041
2018-2026
5,889
5,698
3,843
2,254
2,729
3
—
490
6,328
501
1,820
3,695
85
960
1,750
755
1,207
4,525
200
1,438
4
315
501
—
1,665
138
7,192
501
2,824
3,490
75
250
485
4,968
4,498
1,007
1,171
4,672
4
14
126
6,781
537
2,226
3,904
85
351
2,075
225
1,342
4,525
200
1,032
4
323
537
564
—
—
—
—
—
—
—
—
—
66
2,177
525
1,114
(312)
65,180
(2,871)
(1,444)
60,865
—
—
—
—
(226)
40,945
(4,100)
(351)
36,494
Fair value adjustment - Spectra Energy acquisition
Other23
Total debt
Current maturities
Short-term borrowings24
Long-term debt
1 2017 - US$4,700 million; 2016 - US$3,700 million.
2 2017 - $1,650 million and US$1,750 million; 2016 - US$750 million. For the initial 10 years, the notes carry a fixed interest rate.
Subsequently, the interest rate will be floating and set to equal the three-month Bankers' Acceptance Rate or London Interbank
Offered Rate (LIBOR) plus a margin.
150
151
3 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.
4 2017 - $750 million and US$1,200 million; 2016 - $500 million and US$500 million. Carries an interest rate equal to the three-
month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points.
5 2017 - $1,593 million and US$907 million; 2016 - $3,600 million and US$799 million.
6 Primarily capital lease obligations.
7 2016 - US$10 million.
8 2017 - US$391 million; 2016 - US$94 million.
9 2017 - US$5,050 million; 2016 - US$5,050 million.
10 2017 - US$400 million; 2016 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75
basis points.
11 2017 - US$1,453 million; 2016 - US$1,658 million.
12 2017 - US$963 million; 2016 - US$1,000 million.
13 Included in medium-term notes is $100 million with a maturity date of 2112.
14 2017 - $1,080 million and US$286 million; 2016 - $750 million and US$210 million.
15 2017 - US$400 million; 2016 - US$400 million.
16 2016 - US$420 million.
17 Debt acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7).
18 2017 - US$1,329 million.
19 2017 - US$110 million.
20 2017 - US$5,740 million.
21 2017 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points.
22 2017 - US$2,254 million.
23 Primarily debt discount and debt issue costs.
24 Weighted average interest rate - 1.4%; 2016 - 0.8%.
SECURED DEBT
Senior secured notes, totaling $206 million as at December 31, 2017, includes project financings for M&N
Canada and Express-Platte System. Ownership interests in M&N Canada and certain of its accounts,
revenues, business contracts and other assets are pledged as collateral. Express-Platte System notes
payable are secured by the assignment of the Express-Platte System transportation receivables and by
the Canadian portion of the Express-Platte pipeline system assets.
CREDIT FACILITIES
The following table provides details of our committed credit facilities at December 31, 2017:
2017
Total
Facilities
Draws1
Available
Maturity
December 31,
(millions of Canadian dollars)
Enbridge Inc.2
2,737
Enbridge (U.S.) Inc.
490
Enbridge Energy Partners, L.P.3
1,820
Enbridge Gas Distribution Inc.
972
Enbridge Income Fund
766
Enbridge Pipelines (Southern Lights) L.L.C.
—
Enbridge Pipelines Inc.
1,438
Enbridge Southern Lights LP
—
Spectra Energy Partners, LP4,5
2,824
Union Gas Limited5
485
Westcoast Energy Inc.5
—
Total committed credit facilities
11,532
1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
2 Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020,
2019-2022
2019
2019-2022
2019
2020
2019
2019
2019
2022
2021
2021
7,353
3,590
3,289
1,016
1,500
25
3,000
5
3,133
700
400
24,011
4,616
3,100
1,469
44
734
25
1,562
5
309
215
400
12,479
respectively.
3 Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020,
respectively.
4 Includes $421 million (US$336 million) of commitments that expire in 2021.
5 Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7).
During the first quarter of 2017, Enbridge established a five-year, term credit facility for $239 million
(¥20,000 million) with a syndicate of Japanese banks.
152
153
In addition to the committed credit facilities noted above, we have $792 million of uncommitted demand
credit facilities, of which $518 million were unutilized as at December 31, 2017. As at December 31, 2016,
we had $335 million of uncommitted credit facilities, of which $177 million were unutilized.
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 we have the option to extend such facilities, which are currently set to mature from 2019 to
2022.
As at December 31, 2017 and 2016, commercial paper and credit facility draws, net of short-term
borrowings and non-revolving credit facilities that mature within one year of $10,055 million and $7,344
million, respectively, are supported by the availability of long-term committed credit facilities and therefore
have been classified as long-term debt.
LONG-TERM DEBT ISSUANCES
The following are long-term debt issuances made during 2017 and 2016:
Company Issue Date
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
Floating rate notes due May 20191
3.19% medium-term notes due December 2022
3.20% medium-term notes due June 2027
4.57% medium-term notes due March 2044
Floating rate notes due June 20202
2.90% senior notes due July 2022
3.70% senior notes due July 2027
Fixed-to-floating rate subordinated notes due July 20773
September 2017
Fixed-to-floating rate subordinated notes due September 20774
Fixed-to-floating rate subordinated notes due September 20774
Floating rate notes due January 20205
4.25% medium-term notes due December 2026
5.50% medium-term notes due December 2046
Fixed-to-floating rate subordinated notes due January 20776
May 2017
June 2017
June 2017
June 2017
June 2017
July 2017
July 2017
July 2017
October 2017
October 2017
November 2016
November 2016
December 2016
November 2017
3.51% medium-term notes due November 2047
August 2016
2.50% medium-term notes due August 2026
August 2016
August 2016
3.00% medium-term notes due August 2026
4.13% medium-term notes due August 2046
Enbridge Gas Distribution Inc.
Enbridge Pipelines Inc.
Spectra Energy Partners, LP
Union Gas Limited
November 2017
November 2017
2.88% medium-term notes due November 2027
3.59% medium-term notes due November 2047
June 2017
Floating rate notes due June 20207
US$400
1 Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points.
2 Carries an interest rate equal to the three-month LIBOR plus 70 basis points.
3 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.5%.
Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 342 basis points from year 10 to 30,
and a margin of 417 basis points from year 30 to 60.
4 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%.
Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points
from year 10 to 30, and a margin of 400 basis points from year 30 to 60.
5 Carries an interest rate equal to the three-month LIBOR plus 40 basis points.
6 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.0%.
Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 389 basis points from year 10 to 30,
and a margin of 464 basis points from year 30 to 60.
7 Carries an interest rate equal to the three-month LIBOR plus 70 basis points.
Principal
Amount
750
450
450
300
US$500
US$700
US$700
US$1,000
1,000
650
US$700
US$750
US$750
US$750
300
300
400
400
250
250
3 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.
4 2017 - $750 million and US$1,200 million; 2016 - $500 million and US$500 million. Carries an interest rate equal to the three-
month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points.
5 2017 - $1,593 million and US$907 million; 2016 - $3,600 million and US$799 million.
In addition to the committed credit facilities noted above, we have $792 million of uncommitted demand
credit facilities, of which $518 million were unutilized as at December 31, 2017. As at December 31, 2016,
we had $335 million of uncommitted credit facilities, of which $177 million were unutilized.
10 2017 - US$400 million; 2016 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75
13 Included in medium-term notes is $100 million with a maturity date of 2112.
14 2017 - $1,080 million and US$286 million; 2016 - $750 million and US$210 million.
15 2017 - US$400 million; 2016 - US$400 million.
16 2016 - US$420 million.
17 Debt acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7).
6 Primarily capital lease obligations.
7 2016 - US$10 million.
8 2017 - US$391 million; 2016 - US$94 million.
9 2017 - US$5,050 million; 2016 - US$5,050 million.
basis points.
11 2017 - US$1,453 million; 2016 - US$1,658 million.
12 2017 - US$963 million; 2016 - US$1,000 million.
18 2017 - US$1,329 million.
19 2017 - US$110 million.
20 2017 - US$5,740 million.
22 2017 - US$2,254 million.
23 Primarily debt discount and debt issue costs.
24 Weighted average interest rate - 1.4%; 2016 - 0.8%.
SECURED DEBT
21 2017 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points.
Senior secured notes, totaling $206 million as at December 31, 2017, includes project financings for M&N
Canada and Express-Platte System. Ownership interests in M&N Canada and certain of its accounts,
revenues, business contracts and other assets are pledged as collateral. Express-Platte System notes
payable are secured by the assignment of the Express-Platte System transportation receivables and by
the Canadian portion of the Express-Platte pipeline system assets.
CREDIT FACILITIES
The following table provides details of our committed credit facilities at December 31, 2017:
Maturity
Facilities
Draws1
Available
Total
7,353
3,590
3,289
1,016
1,500
25
3,000
5
3,133
700
400
2017
2,737
490
1,820
972
766
—
1,438
—
2,824
485
—
4,616
3,100
1,469
1,562
44
734
25
5
309
215
400
2019-2022
2019-2022
2019
2019
2020
2019
2019
2019
2022
2021
2021
Enbridge Pipelines (Southern Lights) L.L.C.
December 31,
(millions of Canadian dollars)
Enbridge Inc.2
Enbridge (U.S.) Inc.
Enbridge Energy Partners, L.P.3
Enbridge Gas Distribution Inc.
Enbridge Income Fund
Enbridge Pipelines Inc.
Enbridge Southern Lights LP
Spectra Energy Partners, LP4,5
Union Gas Limited5
Westcoast Energy Inc.5
Total committed credit facilities
respectively.
respectively.
1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
2 Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020,
24,011
11,532
12,479
3 Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020,
4 Includes $421 million (US$336 million) of commitments that expire in 2021.
5 Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7).
During the first quarter of 2017, Enbridge established a five-year, term credit facility for $239 million
(¥20,000 million) with a syndicate of Japanese banks.
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 we have the option to extend such facilities, which are currently set to mature from 2019 to
2022.
As at December 31, 2017 and 2016, commercial paper and credit facility draws, net of short-term
borrowings and non-revolving credit facilities that mature within one year of $10,055 million and $7,344
million, respectively, are supported by the availability of long-term committed credit facilities and therefore
have been classified as long-term debt.
LONG-TERM DEBT ISSUANCES
The following are long-term debt issuances made during 2017 and 2016:
Company Issue Date
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
May 2017
June 2017
June 2017
June 2017
June 2017
July 2017
July 2017
July 2017
September 2017
October 2017
October 2017
November 2016
November 2016
December 2016
Floating rate notes due May 20191
3.19% medium-term notes due December 2022
3.20% medium-term notes due June 2027
4.57% medium-term notes due March 2044
Floating rate notes due June 20202
2.90% senior notes due July 2022
3.70% senior notes due July 2027
Fixed-to-floating rate subordinated notes due July 20773
Fixed-to-floating rate subordinated notes due September 20774
Fixed-to-floating rate subordinated notes due September 20774
Floating rate notes due January 20205
4.25% medium-term notes due December 2026
5.50% medium-term notes due December 2046
Fixed-to-floating rate subordinated notes due January 20776
Enbridge Gas Distribution Inc.
November 2017
August 2016
Enbridge Pipelines Inc.
August 2016
August 2016
Spectra Energy Partners, LP
3.51% medium-term notes due November 2047
2.50% medium-term notes due August 2026
3.00% medium-term notes due August 2026
4.13% medium-term notes due August 2046
June 2017
Floating rate notes due June 20207
Union Gas Limited
November 2017
November 2017
2.88% medium-term notes due November 2027
3.59% medium-term notes due November 2047
Principal
Amount
750
450
450
300
US$500
US$700
US$700
US$1,000
1,000
650
US$700
US$750
US$750
US$750
300
300
400
400
US$400
250
250
1 Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points.
2 Carries an interest rate equal to the three-month LIBOR plus 70 basis points.
3 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.5%.
Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 342 basis points from year 10 to 30,
and a margin of 417 basis points from year 30 to 60.
4 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%.
Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points
from year 10 to 30, and a margin of 400 basis points from year 30 to 60.
5 Carries an interest rate equal to the three-month LIBOR plus 40 basis points.
6 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.0%.
Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 389 basis points from year 10 to 30,
and a margin of 464 basis points from year 30 to 60.
7 Carries an interest rate equal to the three-month LIBOR plus 70 basis points.
152
153
LONG-TERM DEBT REPAYMENTS
The following are long-term debt repayments during 2017 and 2016:
Company
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
Retirement/Repayment Date
March 2017
April 2017
June 2017
May 2016
August 2016
October 2016
Floating rate note
5.60% medium-term notes
Floating rate note
5.17% medium-term notes
5.00% medium-term notes
Floating rate note
Enbridge Energy Partners, L.P.
December 2016
5.88% senior notes
Enbridge Gas Distribution Inc.
April 2017
December 2017
Enbridge Income Fund
June 2017
December 2017
November 2016
Enbridge Pipelines (Southern Lights) L.L.C.
1.85% medium-term notes
5.16% medium-term
5.00% medium-term
2.92% medium-term
Floating rate note
June and December 2017
June and December 2016
3.98% medium-term note due June 2040
3.98% medium-term note due June 2040
Enbridge Southern Lights LP
June 2017
June and December 2016
4.01% medium-term note due June 2040
4.01% medium-term note due June 2040
Spectra Energy Capitals, LLC
July and September 20171,3
July 20172,3
8.00% senior notes due 2019
Senior notes carrying interest ranging from 3.3%
to 7.5% due 2018 to 2038
Spectra Energy Partners, LP
September 2017
June and December 2017
6.00% senior notes
7.39% subordinated secured notes
Union Gas Limited
Westcoast Energy Inc.
November 2017
9.70% debentures
May and November 2017
May and November 2017
6.90% senior secured
4.34% senior secured
Principal
Amount
500
US$400
US$500
400
300
US$350
US$300
300
200
100
225
330
US$37
US$30
7
14
US$500
US$761
US$400
US$12
125
26
24
1 On July 7, 2017 and September 8, 2017, Enbridge and Spectra Energy Capital, LLC (Spectra Capital) completed a cash tender
offer for and follow-up redemption of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019. The aggregate
principal amount tendered and redeemed was US$500 million. Spectra Capital paid the consenting note holders an aggregate
cash consideration of US$581 million.
2 On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased a portion of the principal amount of its outstanding
senior unsecured notes carrying interest rates ranging from 3.3% to 7.5%, with maturities ranging from one to 21 years. The
principal amount tendered and accepted was US$761 million. Spectra Capital paid the consenting note holders an aggregate
cash consideration of US$857 million.
3 The loss on debt extinguishment of $50 million (US$38 million), net of the fair value adjustment recorded upon completion of the
Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.
DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant
provisions whereby accelerated repayment and/or termination of the agreements may result if we were to
default on payment or violate certain covenants. As at December 31, 2017, we were in compliance with
all debt covenants.
INTEREST EXPENSE
Year ended December 31,
(millions of Canadian dollars)
Debentures and term notes
Commercial paper and credit facility draws
Amortization of fair value adjustment - Spectra Energy acquisition
Capitalized
2017
2016
2015
3,011
206
(270)
(391)
2,556
1,714
197
—
(321)
1,590
1,805
172
—
(353)
1,624
18. ASSET RETIREMENT OBLIGATIONS
Our AROs relate mostly to the retirement of pipelines, renewable power generation assets, obligations
related to right-of way agreements and contractual leases for land use.
A reconciliation of movements in our ARO liabilities is as follows:
December 31,
(millions of Canadian dollars)
Obligations at beginning of year
Liabilities acquired
Liabilities incurred
Liabilities settled
Change in estimate
Accretion expense
Obligations at end of year
Presented as follows:
Accounts payable and other
Other long-term liabilities
Foreign currency translation adjustment
2017
2016
232
546
—
(22)
18
(12)
31
793
2
791
793
198
—
2
(33)
63
(5)
7
232
2
230
232
154
155
LONG-TERM DEBT REPAYMENTS
The following are long-term debt repayments during 2017 and 2016:
Company
Retirement/Repayment Date
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
March 2017
April 2017
June 2017
May 2016
August 2016
October 2016
April 2017
December 2017
June 2017
December 2017
November 2016
Enbridge Energy Partners, L.P.
Enbridge Gas Distribution Inc.
Enbridge Income Fund
Enbridge Pipelines (Southern Lights) L.L.C.
Floating rate note
5.60% medium-term notes
Floating rate note
5.17% medium-term notes
5.00% medium-term notes
Floating rate note
1.85% medium-term notes
5.16% medium-term
5.00% medium-term
2.92% medium-term
Floating rate note
December 2016
5.88% senior notes
Enbridge Southern Lights LP
Spectra Energy Capitals, LLC
July 20172,3
Spectra Energy Partners, LP
June and December 2017
June and December 2016
3.98% medium-term note due June 2040
3.98% medium-term note due June 2040
June 2017
4.01% medium-term note due June 2040
June and December 2016
4.01% medium-term note due June 2040
July and September 20171,3
8.00% senior notes due 2019
Senior notes carrying interest ranging from 3.3%
to 7.5% due 2018 to 2038
September 2017
6.00% senior notes
June and December 2017
7.39% subordinated secured notes
Union Gas Limited
Westcoast Energy Inc.
November 2017
9.70% debentures
May and November 2017
May and November 2017
6.90% senior secured
4.34% senior secured
1 On July 7, 2017 and September 8, 2017, Enbridge and Spectra Energy Capital, LLC (Spectra Capital) completed a cash tender
offer for and follow-up redemption of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019. The aggregate
principal amount tendered and redeemed was US$500 million. Spectra Capital paid the consenting note holders an aggregate
cash consideration of US$581 million.
2 On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased a portion of the principal amount of its outstanding
senior unsecured notes carrying interest rates ranging from 3.3% to 7.5%, with maturities ranging from one to 21 years. The
principal amount tendered and accepted was US$761 million. Spectra Capital paid the consenting note holders an aggregate
cash consideration of US$857 million.
3 The loss on debt extinguishment of $50 million (US$38 million), net of the fair value adjustment recorded upon completion of the
Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.
Principal
Amount
500
US$400
US$500
400
300
US$350
US$300
300
200
100
225
330
US$37
US$30
7
14
US$500
US$761
US$400
US$12
125
26
24
DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant
provisions whereby accelerated repayment and/or termination of the agreements may result if we were to
default on payment or violate certain covenants. As at December 31, 2017, we were in compliance with
all debt covenants.
INTEREST EXPENSE
Year ended December 31,
(millions of Canadian dollars)
Debentures and term notes
Commercial paper and credit facility draws
Amortization of fair value adjustment - Spectra Energy acquisition
Capitalized
2017
2016
2015
3,011
206
(270)
(391)
2,556
1,714
197
—
(321)
1,590
1,805
172
—
(353)
1,624
18. ASSET RETIREMENT OBLIGATIONS
Our AROs relate mostly to the retirement of pipelines, renewable power generation assets, obligations
related to right-of way agreements and contractual leases for land use.
A reconciliation of movements in our ARO liabilities is as follows:
December 31,
(millions of Canadian dollars)
Obligations at beginning of year
Liabilities acquired
Liabilities incurred
Liabilities settled
Change in estimate
Foreign currency translation adjustment
Accretion expense
Obligations at end of year
Presented as follows:
Accounts payable and other
Other long-term liabilities
2017
2016
232
546
—
(22)
18
(12)
31
793
2
791
793
198
—
2
(33)
63
(5)
7
232
2
230
232
154
155
19. NONCONTROLLING INTERESTS
NONCONTROLLING INTERESTS
The following table provides additional information regarding Noncontrolling interests as presented in our
Consolidated Statements of Financial Position:
December 31,
(millions of Canadian dollars)
Enbridge Energy Management, L.L.C.1
Enbridge Energy Partners, L.P.2
Enbridge Gas Distribution Inc.3
Renewable energy assets4
Spectra Energy Partners, LP5,8
Union Gas Limited6,8
Westcoast Energy Inc.7,8
Other
2017
2016
34
157
100
806
5,385
110
1,005
—
7,597
36
(99)
100
516
—
—
—
24
577
1 Represents the 88.3% of the listed shares of Enbridge Energy Management, L.L.C. (EEM) not held by us as at December 31,
2017 and 2016.
2 Represents the 68.2% and 80.2% interest in EEP held by public unitholders as well as interests of third parties in subsidiaries of
EEP as at December 31, 2017 and 2016, respectively.
3 Represents the four million cumulative redeemable preferred shares held by third parties in EGD as at December 31, 2017 and
2016.
4 Represents the tax equity investors' interests in our Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind farms,
which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and
Wildcat wind farms held by third parties as at December 31, 2017 and 2016.
5 Represents the 25.7% interest in SEP held by public unitholders as at December 31, 2017.
6 Represents the four million cumulative redeemable preferred shares held by third parties in Union Gas as at December 31, 2017.
7 Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at
December 31, 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline
Limited Partnership held by third parties.
8 Represents noncontrolling interests resulting from the Merger Transaction (Note 7).
Enbridge Energy Partners, L.P.
United States Sponsored Vehicle Strategy
On April 28, 2017, we completed a strategic review of EEP and took the actions described below. As a
result of these actions, we recorded an increase in Noncontrolling interests of $458 million, inclusive of
foreign currency translation adjustments, and a decrease in Additional paid-in capital of $421 million, net
of deferred income taxes of $253 million.
Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.
On April 27, 2017, we completed our previously-announced merger through a wholly-owned subsidiary,
through which we privatized MEP by acquiring all of the outstanding publicly-held common units of MEP
for total consideration of approximately US$170 million.
On June 28, 2017, we acquired, through a wholly-owned subsidiary, all of EEP’s interest in the Midcoast
gas gathering and processing business for cash consideration of US$1.3 billion plus existing
indebtedness of MEP of US$953 million.
As a result of the above transactions, 100% of the Midcoast gas gathering and processing business is
now owned by us.
EEP Strategic Restructuring Actions
On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by us at face value
of US$1.2 billion through the issuance of 64.3 million Class A common units to us. We also irrevocably
waived all of our rights associated with our ownership of 66.1 million Class D units and 1,000 Incentive
Distribution Units of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units are
entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US
$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable
waiver was effective with respect to distributions declared with a record date after April 27, 2017. In
connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US
$0.583 per unit to US$0.35 per unit. Further, in conjunction with the restructuring actions, EEP terminated
a receivable purchase agreement with a special purpose entity wholly-owned by us.
Finalization of Bakken Pipeline System Joint Funding Agreement
On April 27, 2017, we entered into a joint funding arrangement with EEP. Pursuant to this joint funding
arrangement, we own 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken
Pipeline System. Under this arrangement, EEP retains a five-year option to acquire an additional 20%
interest in the Bakken Pipeline System. Upon the execution of the joint funding arrangement, EEP repaid
the outstanding balance on its US$1.5 billion credit agreement with us, which it had drawn upon to fund
the initial purchase.
Drop Down of Interest to Enbridge Energy Partners, L.P.
On January 2, 2015, we transferred our 66.7% interest in the United States segment of the Alberta
Clipper pipeline, held through a wholly-owned subsidiary, to EEP for aggregate consideration of $1.1
billion (US$1 billion), consisting of approximately $814 million (US$694 million) of Class E equity units
issued to us by EEP and the repayment of approximately $359 million (US$306 million) of indebtedness
owed to us. Prior to the transfer, EEP owned the remaining 33.3% interest in the United States segment
of the Alberta Clipper pipeline. As a result of this transfer, we recorded a decrease in Noncontrolling
interests of $304 million and increases in Additional paid-in capital and Deferred income tax liabilities of
$218 million and $86 million, respectively.
Other
The EEP partnership agreement does not permit capital deficits to accumulate in the capital accounts of
any limited partner and thus requires that such capital account deficits be "cured" by additional allocations
from the positive capital accounts of the other limited partners and the General Partner, generally on a
pro-rata basis. Further, as outlined in the EEP partnership agreement, when a limited partner's capital
accounts have positive capital balances, such limited partner must allocate its earnings to the General
Partner of EEP to reimburse them for previous curing allocations. As a result, earnings attributable to
noncontrolling interests in the Consolidated Statements of Earnings for the years ended December 31,
2017 and 2016 were lower by $73 million and higher by $816 million, respectively, due to these
reallocations.
On March 13, 2015, EEP completed a public common unit issuance. We participated only to the extent to
maintain our 2% general partner interest. The common unit issuance resulted in contributions of $366
million (US$289 million) from noncontrolling interest holders.
156
157
19. NONCONTROLLING INTERESTS
NONCONTROLLING INTERESTS
Consolidated Statements of Financial Position:
The following table provides additional information regarding Noncontrolling interests as presented in our
December 31,
(millions of Canadian dollars)
Enbridge Energy Management, L.L.C.1
Enbridge Energy Partners, L.P.2
Enbridge Gas Distribution Inc.3
Renewable energy assets4
Spectra Energy Partners, LP5,8
Union Gas Limited6,8
Westcoast Energy Inc.7,8
Other
2017
2016
34
157
100
806
5,385
110
1,005
—
7,597
36
(99)
100
516
—
—
—
24
577
1 Represents the 88.3% of the listed shares of Enbridge Energy Management, L.L.C. (EEM) not held by us as at December 31,
2 Represents the 68.2% and 80.2% interest in EEP held by public unitholders as well as interests of third parties in subsidiaries of
EEP as at December 31, 2017 and 2016, respectively.
3 Represents the four million cumulative redeemable preferred shares held by third parties in EGD as at December 31, 2017 and
2017 and 2016.
2016.
4 Represents the tax equity investors' interests in our Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind farms,
which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and
Wildcat wind farms held by third parties as at December 31, 2017 and 2016.
5 Represents the 25.7% interest in SEP held by public unitholders as at December 31, 2017.
6 Represents the four million cumulative redeemable preferred shares held by third parties in Union Gas as at December 31, 2017.
7 Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at
December 31, 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline
Limited Partnership held by third parties.
8 Represents noncontrolling interests resulting from the Merger Transaction (Note 7).
Enbridge Energy Partners, L.P.
United States Sponsored Vehicle Strategy
On April 28, 2017, we completed a strategic review of EEP and took the actions described below. As a
result of these actions, we recorded an increase in Noncontrolling interests of $458 million, inclusive of
foreign currency translation adjustments, and a decrease in Additional paid-in capital of $421 million, net
of deferred income taxes of $253 million.
Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.
On April 27, 2017, we completed our previously-announced merger through a wholly-owned subsidiary,
through which we privatized MEP by acquiring all of the outstanding publicly-held common units of MEP
for total consideration of approximately US$170 million.
On June 28, 2017, we acquired, through a wholly-owned subsidiary, all of EEP’s interest in the Midcoast
gas gathering and processing business for cash consideration of US$1.3 billion plus existing
indebtedness of MEP of US$953 million.
As a result of the above transactions, 100% of the Midcoast gas gathering and processing business is
now owned by us.
EEP Strategic Restructuring Actions
On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by us at face value
of US$1.2 billion through the issuance of 64.3 million Class A common units to us. We also irrevocably
waived all of our rights associated with our ownership of 66.1 million Class D units and 1,000 Incentive
Distribution Units of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units are
entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US
$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable
waiver was effective with respect to distributions declared with a record date after April 27, 2017. In
connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US
$0.583 per unit to US$0.35 per unit. Further, in conjunction with the restructuring actions, EEP terminated
a receivable purchase agreement with a special purpose entity wholly-owned by us.
Finalization of Bakken Pipeline System Joint Funding Agreement
On April 27, 2017, we entered into a joint funding arrangement with EEP. Pursuant to this joint funding
arrangement, we own 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken
Pipeline System. Under this arrangement, EEP retains a five-year option to acquire an additional 20%
interest in the Bakken Pipeline System. Upon the execution of the joint funding arrangement, EEP repaid
the outstanding balance on its US$1.5 billion credit agreement with us, which it had drawn upon to fund
the initial purchase.
Drop Down of Interest to Enbridge Energy Partners, L.P.
On January 2, 2015, we transferred our 66.7% interest in the United States segment of the Alberta
Clipper pipeline, held through a wholly-owned subsidiary, to EEP for aggregate consideration of $1.1
billion (US$1 billion), consisting of approximately $814 million (US$694 million) of Class E equity units
issued to us by EEP and the repayment of approximately $359 million (US$306 million) of indebtedness
owed to us. Prior to the transfer, EEP owned the remaining 33.3% interest in the United States segment
of the Alberta Clipper pipeline. As a result of this transfer, we recorded a decrease in Noncontrolling
interests of $304 million and increases in Additional paid-in capital and Deferred income tax liabilities of
$218 million and $86 million, respectively.
Other
The EEP partnership agreement does not permit capital deficits to accumulate in the capital accounts of
any limited partner and thus requires that such capital account deficits be "cured" by additional allocations
from the positive capital accounts of the other limited partners and the General Partner, generally on a
pro-rata basis. Further, as outlined in the EEP partnership agreement, when a limited partner's capital
accounts have positive capital balances, such limited partner must allocate its earnings to the General
Partner of EEP to reimburse them for previous curing allocations. As a result, earnings attributable to
noncontrolling interests in the Consolidated Statements of Earnings for the years ended December 31,
2017 and 2016 were lower by $73 million and higher by $816 million, respectively, due to these
reallocations.
On March 13, 2015, EEP completed a public common unit issuance. We participated only to the extent to
maintain our 2% general partner interest. The common unit issuance resulted in contributions of $366
million (US$289 million) from noncontrolling interest holders.
156
157
REDEEMABLE NONCONTROLLING INTERESTS
The following table presents additional information regarding Redeemable noncontrolling interests as
presented in our Consolidated Statements of Financial Position:
Year ended December 31,
(millions of Canadian dollars)
Balance at beginning of year
Earnings/(loss) attributable to redeemable noncontrolling interests
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges
Other comprehensive loss from equity investees
Reclassification to earnings of loss on cash flow hedges
Foreign currency translation adjustments
Other comprehensive income/(loss), net of tax
Distributions to unitholders
Contributions from unitholders
Reversal of cumulative redemption value adjustment attributable to
ECT preferred units
Net dilution loss
Redemption value adjustment
Balance at end of year
2017
3,392
175
(21)
—
57
(6)
30
(247)
1,178
—
(169)
(292)
4,067
2016
2015
2,141
268
2,249
(3)
(17)
—
9
(3)
(11)
(202)
591
—
(81)
686
3,392
(7)
(12)
4
18
3
(114)
670
(541)
(482)
359
2,141
Redeemable noncontrolling interests in the Fund as at December 31, 2017, 2016 and 2015 represented
56.5%, 45.6% and 40.7%, respectively, of interests in the Fund’s trust units that are held by third parties.
Common Share Issuances
During the years ended December 31, 2017, 2016 and 2015, the following occurred:
Year ended December 31,
(millions of Canadian dollars)
ENF issuance of common shares1:
Gross proceeds from the public
Gross proceeds from us2
ENF purchase of Fund trust units1,3:
Contributions from redeemable noncontrolling interest holders, net
of share issue costs
Dilution gain/(loss) for redeemable noncontrolling interests
Dilution gain/(loss) in Additional paid-in capital
ECT purchase of EIPLP Class A units1,4:
Proceeds used by ECT to purchase EIPLP Class A units
Dilution loss for redeemable noncontrolling interests
Dilution gain in Additional paid-in capital
ENF purchase of Fund trust units5:
Contributions from redeemable noncontrolling interest holders
Dilution gain/(loss) for redeemable noncontrolling interests
Dilution gain/(loss) in Additional paid-in capital
2017
2016
2015
575
143
552
5
(5)
718
(123)
123
51
(5)
5
575
143
551
(4)
4
718
(103)
103
40
(4)
4
700
174
670
(355)
355
874
(132)
132
—
—
—
1 These transactions occurred in December 2017, April 2016 and November 2015.
2 Concurrent with the public offerings, we subscribed for ENF common shares on a private placement basis to maintain our 19.9%
ownership interest in ENF.
3 ENF used the proceeds from the common share issuances to purchase additional trust units of the Fund. We did not participate in
these offerings, resulting in increases in redeemable noncontrolling interests (2017 - 53.6% to 56.5%; 2016 - 40.7% to 45.6%;
2015 - 34.3% to 40.7%).
4 The Fund used a portion of the proceeds from the trust unit issuances to purchase additional common units of ECT, and ECT
used the proceeds to purchase additional Class A units of EIPLP, resulting in dilution losses for ECT. These dilution losses
resulted in dilution losses for the Fund’s equity investment in ECT and the above-noted dilution gains/(losses) for redeemable
noncontrolling interests and Additional paid-in capital.
5 For the years ended December 31, 2017, 2016 and 2015, ENF used cash in respect of reinvested dividends and option cash
payments from its Dividend Reinvestment Plan (DRIP) to purchase 1.6 million, 1.3 million and nil Fund trust units, respectively, on
behalf of the public.
Further to the above, in April 2017, Enbridge and ENF completed the secondary public offering of ENF
common shares for gross proceeds of $575 million (the Secondary Offering). To effect the Secondary
Offering, we exchanged 21,657,617 Fund units we owned for an equivalent amount of ENF common
shares. In order to maintain our 19.9% interest in ENF, we retained 4,309,867 of the common shares we
received in the exchange, and sold the balance through the Secondary Offering. Upon closing of the
Secondary Offering, our total economic interest in ENF decreased from 86.9% to 84.6% and redeemable
noncontrolling interests increased from 45.6% to 53.7%. As a result of the Secondary Offering, we
recorded a dilution loss for redeemable noncontrolling interests of $87 million and a dilution gain in
Additional paid-in capital of $87 million.
Canadian Restructuring Plan
In September 2015, our unitholdings in the Fund increased upon closing of the Canadian Restructuring
Plan (Note 1), resulting in a decrease in redeemable noncontrolling interests.
Upon closing of the Canadian Restructuring Plan, ECT, an equity investment of the Fund, reclassified its
Preferred Units from mezzanine equity to liabilities. Accordingly, ECT reduced the recorded redemption
value of its Preferred Units to their aggregate par value, resulting in an increase to the Fund’s equity
investment in ECT. This resulted in an adjustment to redeemable noncontrolling interests of approximately
$541 million.
Upon closing of the Canadian Restructuring Plan, EIPLP, an indirect equity investment of the Fund,
issued Special Interest Rights to us which are entitled to Temporary Performance Distribution Rights
(TPDR) distributions. TPDR distributions occur when the Fund distribution rate exceeds a payout target
and are paid in the form of Class D units. The Class D unitholders receive a distribution each month equal
to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units.
The issuances of TPDR and additional Class D units resulted in a dilution gain for the Fund’s indirect
equity investment in EIPLP, a dilution gain for redeemable noncontrolling interests of $41 million, $30
million and $5 million for the years ended December 31, 2017, 2016 and 2015, respectively, with
offsetting dilution losses in Additional paid-in capital.
Our authorized share capital consists of an unlimited number of common shares with no par value and an
20. SHARE CAPITAL
unlimited number of preference shares.
COMMON SHARES
December 31,
(millions of Canadian dollars; number of
shares in millions)
Balance at beginning of year
Common shares issued1
Common shares issued in
Merger Transaction (Note 7)
Dividend Reinvestment and
Share Purchase Plan
Shares issued on exercise of
stock options
Balance at end of year
2017
Number
of Shares
2016
Number
2015
Number
Amount of Shares
Amount of Shares
Amount
943
33
691
25
3
10,492
1,500
37,429
1,226
90
1,695
50,737
868
56
—
16
3
943
7,391
2,241
—
795
65
10,492
852
—
—
12
4
868
6,669
—
—
646
76
7,391
1 Gross proceeds of $1.5 billion, $2.3 billion and nil for the years ended December 31, 2017, 2016 and 2015, respectively; net
issuance costs of nil, $59 million and nil for the years ended December 31, 2017, 2016 and 2015, respectively.
158
159
REDEEMABLE NONCONTROLLING INTERESTS
The following table presents additional information regarding Redeemable noncontrolling interests as
presented in our Consolidated Statements of Financial Position:
Year ended December 31,
(millions of Canadian dollars)
Balance at beginning of year
Earnings/(loss) attributable to redeemable noncontrolling interests
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges
Other comprehensive loss from equity investees
Reclassification to earnings of loss on cash flow hedges
Foreign currency translation adjustments
Other comprehensive income/(loss), net of tax
Reversal of cumulative redemption value adjustment attributable to
Distributions to unitholders
Contributions from unitholders
ECT preferred units
Net dilution loss
Redemption value adjustment
Balance at end of year
Year ended December 31,
(millions of Canadian dollars)
ENF issuance of common shares1:
Gross proceeds from the public
Gross proceeds from us2
ENF purchase of Fund trust units1,3:
Contributions from redeemable noncontrolling interest holders, net
of share issue costs
Dilution gain/(loss) for redeemable noncontrolling interests
Dilution gain/(loss) in Additional paid-in capital
ECT purchase of EIPLP Class A units1,4:
Proceeds used by ECT to purchase EIPLP Class A units
Dilution loss for redeemable noncontrolling interests
Dilution gain in Additional paid-in capital
ENF purchase of Fund trust units5:
Contributions from redeemable noncontrolling interest holders
Dilution gain/(loss) for redeemable noncontrolling interests
Dilution gain/(loss) in Additional paid-in capital
1 These transactions occurred in December 2017, April 2016 and November 2015.
2017
3,392
175
(21)
—
57
(6)
30
(247)
1,178
—
(169)
(292)
4,067
575
143
552
5
(5)
718
(123)
123
51
(5)
5
2016
2015
2,141
268
2,249
(3)
(17)
—
9
(3)
(11)
(202)
591
—
(81)
686
(7)
(12)
4
18
3
(114)
670
(541)
(482)
359
3,392
2,141
575
143
551
(4)
4
718
(103)
103
40
(4)
4
700
174
670
(355)
355
874
(132)
132
—
—
—
Redeemable noncontrolling interests in the Fund as at December 31, 2017, 2016 and 2015 represented
56.5%, 45.6% and 40.7%, respectively, of interests in the Fund’s trust units that are held by third parties.
Common Share Issuances
During the years ended December 31, 2017, 2016 and 2015, the following occurred:
2017
2016
2015
2 Concurrent with the public offerings, we subscribed for ENF common shares on a private placement basis to maintain our 19.9%
3 ENF used the proceeds from the common share issuances to purchase additional trust units of the Fund. We did not participate in
these offerings, resulting in increases in redeemable noncontrolling interests (2017 - 53.6% to 56.5%; 2016 - 40.7% to 45.6%;
ownership interest in ENF.
2015 - 34.3% to 40.7%).
4 The Fund used a portion of the proceeds from the trust unit issuances to purchase additional common units of ECT, and ECT
used the proceeds to purchase additional Class A units of EIPLP, resulting in dilution losses for ECT. These dilution losses
resulted in dilution losses for the Fund’s equity investment in ECT and the above-noted dilution gains/(losses) for redeemable
noncontrolling interests and Additional paid-in capital.
5 For the years ended December 31, 2017, 2016 and 2015, ENF used cash in respect of reinvested dividends and option cash
payments from its Dividend Reinvestment Plan (DRIP) to purchase 1.6 million, 1.3 million and nil Fund trust units, respectively, on
behalf of the public.
Further to the above, in April 2017, Enbridge and ENF completed the secondary public offering of ENF
common shares for gross proceeds of $575 million (the Secondary Offering). To effect the Secondary
Offering, we exchanged 21,657,617 Fund units we owned for an equivalent amount of ENF common
shares. In order to maintain our 19.9% interest in ENF, we retained 4,309,867 of the common shares we
received in the exchange, and sold the balance through the Secondary Offering. Upon closing of the
Secondary Offering, our total economic interest in ENF decreased from 86.9% to 84.6% and redeemable
noncontrolling interests increased from 45.6% to 53.7%. As a result of the Secondary Offering, we
recorded a dilution loss for redeemable noncontrolling interests of $87 million and a dilution gain in
Additional paid-in capital of $87 million.
Canadian Restructuring Plan
In September 2015, our unitholdings in the Fund increased upon closing of the Canadian Restructuring
Plan (Note 1), resulting in a decrease in redeemable noncontrolling interests.
Upon closing of the Canadian Restructuring Plan, ECT, an equity investment of the Fund, reclassified its
Preferred Units from mezzanine equity to liabilities. Accordingly, ECT reduced the recorded redemption
value of its Preferred Units to their aggregate par value, resulting in an increase to the Fund’s equity
investment in ECT. This resulted in an adjustment to redeemable noncontrolling interests of approximately
$541 million.
Upon closing of the Canadian Restructuring Plan, EIPLP, an indirect equity investment of the Fund,
issued Special Interest Rights to us which are entitled to Temporary Performance Distribution Rights
(TPDR) distributions. TPDR distributions occur when the Fund distribution rate exceeds a payout target
and are paid in the form of Class D units. The Class D unitholders receive a distribution each month equal
to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units.
The issuances of TPDR and additional Class D units resulted in a dilution gain for the Fund’s indirect
equity investment in EIPLP, a dilution gain for redeemable noncontrolling interests of $41 million, $30
million and $5 million for the years ended December 31, 2017, 2016 and 2015, respectively, with
offsetting dilution losses in Additional paid-in capital.
20. SHARE CAPITAL
Our authorized share capital consists of an unlimited number of common shares with no par value and an
unlimited number of preference shares.
COMMON SHARES
December 31,
(millions of Canadian dollars; number of
shares in millions)
Balance at beginning of year
Common shares issued1
Common shares issued in
Merger Transaction (Note 7)
Dividend Reinvestment and
Share Purchase Plan
Shares issued on exercise of
stock options
2017
2016
2015
Number
of Shares
Number
Amount of Shares
Number
Amount of Shares
Amount
943
33
691
10,492
1,500
37,429
25
1,226
868
56
—
16
7,391
2,241
—
795
852
—
—
12
6,669
—
—
646
Balance at end of year
1 Gross proceeds of $1.5 billion, $2.3 billion and nil for the years ended December 31, 2017, 2016 and 2015, respectively; net
3
1,695
90
50,737
3
943
65
10,492
4
868
76
7,391
158
159
issuance costs of nil, $59 million and nil for the years ended December 31, 2017, 2016 and 2015, respectively.
PREFERENCE SHARES
Characteristics of the preference shares are as follows:
December 31,
(millions of Canadian dollars; number of
shares in millions)
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series C
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
Preference Shares, Series 9
Preference Shares, Series 11
Preference Shares, Series 13
Preference Shares, Series 15
Preference Shares, Series 17
Preference Shares, Series 19
Issuance costs
Balance at end of year
2017
2016
2015
Number
of Shares
Number
Amount of Shares
Number
Amount of Shares
Amount
5
18
2
18
20
14
8
16
18
16
16
16
24
8
10
11
20
14
11
30
20
125
457
43
450
500
350
199
411
450
400
400
411
600
206
250
275
500
350
275
750
500
(155)
7,747
5
20
—
18
20
14
8
16
18
16
16
16
24
8
10
11
20
14
11
30
—
125
500
—
450
500
350
199
411
450
400
400
411
600
206
250
275
500
350
275
750
—
(147)
7,255
5
20
—
18
20
14
8
16
18
16
16
16
24
8
10
11
20
14
11
—
—
125
500
—
450
500
350
199
411
450
400
400
411
600
206
250
275
500
350
275
—
—
(137)
6,515
(Canadian dollars unless otherwise stated)
Preference Shares, Series A
Preference Shares, Series B5
3-month treasury bill
plus 2.400%
Preference Shares, Series C5
Preference Shares, Series D6
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J7
Preference Shares, Series L7
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
Preference Shares, Series 9
Preference Shares, Series 11
Preference Shares, Series 13
Preference Shares, Series 15
Preference Shares, Series 17
Preference Shares, Series 19
Dividend Rate
Dividend1
Per Share Base
Redemption
Value2
Redemption and
Conversion
Option Date2,3
Right to
Convert
Into3,4
5.50%
3.42%
$1.37500
$0.85360
—
$1.00000
$1.00000
$1.00000
4.00%
4.00%
4.00%
4.89% US$1.22160
4.96% US$1.23972
4.00%
4.00%
4.00%
$1.00000
$1.00000
$1.00000
4.00% US$1.00000
4.00%
$1.00000
4.40% US$1.10000
4.40%
4.40%
4.40%
4.40%
4.40%
5.15%
4.90%
$1.10000
$1.10000
$1.10000
$1.10000
$1.10000
$1.28750
$1.22500
$25
$25
$25
$25
$25
—
—
June 1, 2022
Series C
June 1, 2022
Series B
March 1, 2018
Series E
June 1, 2018
Series G
$25 September 1, 2018
Series I
US$25
June 1, 2022
Series K
US$25 September 1, 2022
Series M
$25
$25
$25
US$25
US$25
$25
$25
$25
$25
$25
$25
December 1, 2018
March 1, 2019
June 1, 2019
June 1, 2018
$25 September 1, 2019
March 1, 2019
March 1, 2019
Series O
Series Q
Series S
Series 2
Series 4
Series 6
Series 8
December 1, 2019 Series 10
March 1, 2020 Series 12
June 1, 2020 Series 14
$25 September 1, 2020 Series 16
March 1, 2022 Series 18
March 1, 2023 Series 20
1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With
the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial
redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed
dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference
Shares has this feature.
2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our
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 a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an
ascribed issue price equal to the Base Redemption Value.
4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect 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), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7%
(Series 16), 4.1% (Series 18) or 3.2% (Series 20); 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 On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares
based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount
for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual
dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount
for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on
December 1, 2017, due to reset on a quarterly basis following the issuance thereof.
6 On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on
March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D
fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less
than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were
tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E
Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference
Shares will be increased to $0.27875 from $0.25000, due to the reset of the annual dividend rate on every fifth anniversary of the
date of issuance of the Series D Preference Shares.
7 No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates,
respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US
$0.30540 from US$0.25000 on June 1, 2017, and to US$0.30993 from US$0.25000 on September 1, 2017, respectively, due to
the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference
Shares.
160
161
(millions of Canadian dollars; number of
shares in millions)
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series C
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
Preference Shares, Series 9
Preference Shares, Series 11
Preference Shares, Series 13
Preference Shares, Series 15
Preference Shares, Series 17
Preference Shares, Series 19
Issuance costs
Balance at end of year
5
18
2
18
20
14
8
16
18
16
16
16
24
8
10
11
20
14
11
30
20
125
457
43
450
500
350
199
411
450
400
400
411
600
206
250
275
500
350
275
750
500
5
20
—
18
20
14
8
16
18
16
16
16
24
8
10
11
20
14
11
30
—
125
500
—
450
500
350
199
411
450
400
400
411
600
206
250
275
500
350
275
750
—
5
20
—
18
20
14
8
16
18
16
16
16
24
8
10
11
20
14
11
—
—
125
500
—
450
500
350
199
411
450
400
400
411
600
206
250
275
500
350
275
—
—
(155)
7,747
(147)
7,255
(137)
6,515
PREFERENCE SHARES
Characteristics of the preference shares are as follows:
December 31,
of Shares
Amount of Shares
Amount of Shares
Amount
2017
Number
2016
Number
2015
Number
(Canadian dollars unless otherwise stated)
Preference Shares, Series A
Preference Shares, Series B5
Dividend Rate
Dividend1
Per Share Base
Redemption
Value2
Redemption and
Conversion
Option Date2,3
Right to
Convert
Into3,4
—
$25
Series B
June 1, 2022
$1.37500
$0.85360
$25
$25
—
June 1, 2022
—
Series C
Preference Shares, Series C5
Preference Shares, Series D6
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J7
Preference Shares, Series L7
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
Preference Shares, Series 9
Preference Shares, Series 11
Preference Shares, Series 13
Preference Shares, Series 15
Preference Shares, Series 17
Preference Shares, Series 19
1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With
Series E
Series G
Series I
Series K
Series M
Series O
Series Q
Series S
Series 2
Series 4
Series 6
US$25
Series 8
$25
December 1, 2019 Series 10
$25
March 1, 2020 Series 12
$25
June 1, 2020 Series 14
$25
$25 September 1, 2020 Series 16
March 1, 2022 Series 18
$25
March 1, 2023 Series 20
$25
5.50%
3.42%
3-month treasury bill
plus 2.400%
4.00%
$1.00000
4.00%
$1.00000
4.00%
$1.00000
4.89% US$1.22160
4.96% US$1.23972
4.00%
$1.00000
4.00%
$1.00000
4.00%
$1.00000
4.00% US$1.00000
4.00%
$1.00000
4.40% US$1.10000
4.40%
$1.10000
4.40%
$1.10000
4.40%
$1.10000
4.40%
$1.10000
4.40%
$1.10000
5.15%
$1.28750
4.90%
$1.22500
March 1, 2018
$25
$25
June 1, 2018
$25 September 1, 2018
US$25
June 1, 2022
US$25 September 1, 2022
December 1, 2018
March 1, 2019
June 1, 2019
June 1, 2018
$25 September 1, 2019
March 1, 2019
March 1, 2019
$25
$25
$25
US$25
the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial
redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed
dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference
Shares has this feature.
2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our
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 a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an
ascribed issue price equal to the Base Redemption Value.
4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect 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), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7%
(Series 16), 4.1% (Series 18) or 3.2% (Series 20); 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 On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares
based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount
for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual
dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount
for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on
December 1, 2017, due to reset on a quarterly basis following the issuance thereof.
6 On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on
March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D
fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less
than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were
tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E
Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference
Shares will be increased to $0.27875 from $0.25000, due to the reset of the annual dividend rate on every fifth anniversary of the
date of issuance of the Series D Preference Shares.
7 No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates,
respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US
$0.30540 from US$0.25000 on June 1, 2017, and to US$0.30993 from US$0.25000 on September 1, 2017, respectively, due to
the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference
Shares.
160
161
DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN
Under the DRIP, registered shareholders may reinvest dividends in our common shares and make
additional optional cash payments to purchase common shares, free of brokerage or other charges.
Participants in our DRIP receive a 2% discount on the purchase of common shares with reinvested
dividends. For the years ended December 31, 2017 and 2016, total dividends paid were $3.5 billion and
$1.9 billion, respectively, of which $2.3 billion and $1.2 billion, respectively, were paid in cash and
reflected in financing activities. The remaining $1.2 billion and $795 million, respectively, of dividends paid
were reinvested pursuant to the DRIP and resulted in the issuance of common shares rather than a cash
payment. In addition to amounts paid in cash and reflected in financing activities for the year ended
December 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders prior to the
Merger Transaction that were paid after the Merger Transaction.
SHAREHOLDER RIGHTS PLAN
The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection
with any takeover offer for us. 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 our outstanding common
shares without complying with certain provisions set out in the plan or without approval of our 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 our common shares at a 50% discount to the market price
at that time.
21. STOCK OPTION AND STOCK UNIT PLANS
We maintain four long-term incentive compensation plans: the ISO Plan, the Performance Stock Options
(PSO) Plan, the Performance Stock Units (PSU) Plan and the RSU Plan. A maximum of 60 million
common shares were reserved for issuance under the 2002 ISO Plan, of which 50 million have been
issued to date. A further 71 million common shares have been reserved for issuance under the 2007 ISO
and PSO Plans, of which 16 million have been issued to date. The PSU and RSU Plans grant notional
units as if a unit was one Enbridge common share and are payable in cash.
Prior to the Merger Transaction, Spectra Energy had a long-term incentive plan providing for the granting
of stock options, restricted and unrestricted stock awards and units, and other equity-based awards. Upon
closing of the Merger Transaction, Enbridge replaced existing Spectra Energy share-based payment
awards with awards that will be settled in shares of Enbridge, with Spectra Energy's cash-settled phantom
awards included in the fair value of the net assets acquired (Note 7).
Total stock-based compensation expense recorded for the years ended December 31, 2017, 2016 and
2015 was $165 million, $130 million and $97 million, respectively. Disclosure of activity and assumptions
for material stock-based compensation plans are included below.
INCENTIVE STOCK OPTIONS
Key employees are granted ISOs to purchase common shares at the market price on the grant date.
ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date.
Weighted
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
December 31, 2017
(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
32,909
5,995
(3,350)
(1,188)
34,366
20,403
42.51
55.72
32.65
53.23
45.41
40.89
1 The total intrinsic value of ISOs exercised during the years ended December 31, 2017, 2016 and 2015 was $62 million, $123
million and $126 million, respectively, and cash received on exercise was $17 million, $37 million and $43 million, respectively.
2 The total fair value of ISOs vested during the years ended December 31, 2017, 2016 and 2015 was $44 million, $36 million and
$34 million, respectively.
Weighted average assumptions used to determine the fair value of ISOs granted using the Black-
Scholes-Merton option pricing model are as follows:
6.1
4.7
271
228
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
2017
6.00
5
20.4%
4.2%
1.2%
2016
7.37
5
25.1%
4.4%
0.8%
2015
6.48
5
19.9%
3.2%
0.9%
1 Options granted to United States employees are based on NYSE 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 for the years ended December 31,
2017, 2016 and 2015 were $5.66, $7.01 and $6.22, respectively, for Canadian employees and US$5.72, US$6.60 and US$6.16,
respectively, for United States employees.
2 The expected option term is six years based on historical exercise practice and three years for retirement eligible employees.
3 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.
4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond
Yields.
Compensation expense recorded for the years ended December 31, 2017, 2016 and 2015 for ISOs was
$40 million, $43 million and $35 million, respectively. As at December 31, 2017, unrecognized
compensation expense related to non-vested stock-based compensation arrangements granted under the
ISO Plan was $47 million. The expense is expected to be fully recognized over a weighted average period
of approximately two years.
162
163
DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN
Under the DRIP, registered shareholders may reinvest dividends in our common shares and make
additional optional cash payments to purchase common shares, free of brokerage or other charges.
Participants in our DRIP receive a 2% discount on the purchase of common shares with reinvested
dividends. For the years ended December 31, 2017 and 2016, total dividends paid were $3.5 billion and
$1.9 billion, respectively, of which $2.3 billion and $1.2 billion, respectively, were paid in cash and
reflected in financing activities. The remaining $1.2 billion and $795 million, respectively, of dividends paid
were reinvested pursuant to the DRIP and resulted in the issuance of common shares rather than a cash
payment. In addition to amounts paid in cash and reflected in financing activities for the year ended
December 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders prior to the
Merger Transaction that were paid after the Merger Transaction.
SHAREHOLDER RIGHTS PLAN
The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection
with any takeover offer for us. 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 our outstanding common
shares without complying with certain provisions set out in the plan or without approval of our 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 our common shares at a 50% discount to the market price
at that time.
21. STOCK OPTION AND STOCK UNIT PLANS
We maintain four long-term incentive compensation plans: the ISO Plan, the Performance Stock Options
(PSO) Plan, the Performance Stock Units (PSU) Plan and the RSU Plan. A maximum of 60 million
common shares were reserved for issuance under the 2002 ISO Plan, of which 50 million have been
issued to date. A further 71 million common shares have been reserved for issuance under the 2007 ISO
and PSO Plans, of which 16 million have been issued to date. The PSU and RSU Plans grant notional
units as if a unit was one Enbridge common share and are payable in cash.
Prior to the Merger Transaction, Spectra Energy had a long-term incentive plan providing for the granting
of stock options, restricted and unrestricted stock awards and units, and other equity-based awards. Upon
closing of the Merger Transaction, Enbridge replaced existing Spectra Energy share-based payment
awards with awards that will be settled in shares of Enbridge, with Spectra Energy's cash-settled phantom
awards included in the fair value of the net assets acquired (Note 7).
Total stock-based compensation expense recorded for the years ended December 31, 2017, 2016 and
2015 was $165 million, $130 million and $97 million, respectively. Disclosure of activity and assumptions
for material stock-based compensation plans are included below.
INCENTIVE STOCK OPTIONS
Key employees are granted ISOs to purchase common shares at the market price on the grant date.
ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date.
Weighted
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
Number
December 31, 2017
(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
1 The total intrinsic value of ISOs exercised during the years ended December 31, 2017, 2016 and 2015 was $62 million, $123
million and $126 million, respectively, and cash received on exercise was $17 million, $37 million and $43 million, respectively.
2 The total fair value of ISOs vested during the years ended December 31, 2017, 2016 and 2015 was $44 million, $36 million and
32,909
5,995
(3,350)
(1,188)
34,366
20,403
42.51
55.72
32.65
53.23
45.41
40.89
6.1
4.7
271
228
$34 million, respectively.
Weighted average assumptions used to determine the fair value of ISOs 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
2017
6.00
2016
7.37
2015
6.48
Expected option term (years)2
Expected volatility3
Expected dividend yield4
Risk-free interest rate5
5
19.9%
3.2%
0.9%
1 Options granted to United States employees are based on NYSE 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 for the years ended December 31,
2017, 2016 and 2015 were $5.66, $7.01 and $6.22, respectively, for Canadian employees and US$5.72, US$6.60 and US$6.16,
respectively, for United States employees.
5
20.4%
4.2%
1.2%
5
25.1%
4.4%
0.8%
2 The expected option term is six years based on historical exercise practice and three years for retirement eligible employees.
3 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.
4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond
Yields.
Compensation expense recorded for the years ended December 31, 2017, 2016 and 2015 for ISOs was
$40 million, $43 million and $35 million, respectively. As at December 31, 2017, unrecognized
compensation expense related to non-vested stock-based compensation arrangements granted under the
ISO Plan was $47 million. The expense is expected to be fully recognized over a weighted average period
of approximately two years.
162
163
Aggregate
Intrinsic
Value
Weighted
Average
Remaining
Contractual
Life (years)
RESTRICTED STOCK UNITS
We have a RSU Plan where cash awards are paid to certain of our non-executive employees following a
35-month maturity period. RSU holders receive cash equal to our weighted average share price for 20
days prior to the maturity of the grant multiplied by the units outstanding on the maturity date.
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
December 31, 2017
(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
83
1 The total amount paid during the years ended December 31, 2017, 2016 and 2015 for RSUs was $39 million, $56 million and $45
1,854
741
(186)
(839)
123
1,693
1.4
Number
(millions of Canadian dollars)
Balance at January 1, 2016
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
(millions of Canadian dollars)
Balance at January 1, 2015
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
Other comprehensive income reclassified to
earnings of derecognized cash flow
hedges
Tax impact
Income tax on amounts retained in AOCI
Income tax on amounts reclassified to
Income tax on amounts reclassified to
earnings of derecognized cash flow
earnings
hedges
(688)
(216)
147
(11)
1
(18)
—
(97)
91
(52)
39
(746)
(488)
73
(34)
(11)
7
26
—
(338)
(277)
(29)
15
91
77
(688)
(795)
171
3,365
(665)
171
(665)
—
—
—
—
—
(5)
—
(5)
—
—
—
—
—
—
49
—
—
49
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(952)
3,056
Total
1,632
(760)
147
(11)
1
(18)
21
(620)
102
(56)
46
Total
(435)
2,289
(34)
(11)
7
26
32
(338)
1,971
1
4
91
96
1,632
(287)
(45)
—
—
—
—
21
(24)
11
(4)
7
(359)
65
—
—
—
—
32
—
97
(14)
(11)
—
(25)
(287)
37
(5)
—
—
—
—
—
(5)
5
—
5
37
(5)
47
—
—
—
—
—
—
47
(5)
—
—
(5)
37
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
108
(952)
309
3,056
Balance at December 31, 2015
(795)
3,365
1 Reported within Interest expense in the Consolidated Statements of Earnings.
2 Reported within Commodity costs in the Consolidated Statements of Earnings.
3 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5 These components are included in the computation of net benefit costs and are reported within Operating and administrative
expense in the Consolidated Statements of Earnings.
million, respectively.
Balance at December 31, 2016
(629)
2,700
(304)
1,058
Compensation expense recorded for the years ended December 31, 2017, 2016 and 2015 for RSUs was
$46 million, $51 million and $47 million, respectively. As at December 31, 2017, unrecognized
compensation expense related to non-vested units granted under the RSU Plan was $48 million. The
expense is expected to be fully recognized over a weighted average period of approximately one year.
22. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE
INCOME/(LOSS)
Changes in AOCI attributable to our common shareholders for the years ended December 31, 2017, 2016
and 2015 are as follows:
(millions of Canadian dollars)
Balance at January 1, 2017
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, 2017
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(746)
1
207
(7)
(6)
(6)
—
189
(16)
(71)
(87)
(644)
(629)
478
2,700
(2,623)
—
—
—
—
—
—
—
—
—
—
478
(2,623)
12
—
12
(139)
—
—
—
77
37
(11)
—
—
—
—
—
(11)
(16)
—
(16)
10
(304)
1,058
18
(2,137)
—
—
—
—
41
59
(10)
(22)
(32)
(277)
207
(7)
(6)
(6)
41
(1,908)
(30)
(93)
(123)
(973)
164
165
RESTRICTED STOCK UNITS
We have a RSU Plan where cash awards are paid to certain of our non-executive employees following a
35-month maturity period. RSU holders receive cash equal to our weighted average share price for 20
days prior to the maturity of the grant multiplied by the units outstanding on the maturity date.
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
December 31, 2017
(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
million, respectively.
Number
1,854
741
(186)
(839)
123
1,693
1 The total amount paid during the years ended December 31, 2017, 2016 and 2015 for RSUs was $39 million, $56 million and $45
1.4
83
Compensation expense recorded for the years ended December 31, 2017, 2016 and 2015 for RSUs was
$46 million, $51 million and $47 million, respectively. As at December 31, 2017, unrecognized
compensation expense related to non-vested units granted under the RSU Plan was $48 million. The
expense is expected to be fully recognized over a weighted average period of approximately one year.
22. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE
Changes in AOCI attributable to our common shareholders for the years ended December 31, 2017, 2016
INCOME/(LOSS)
and 2015 are as follows:
(millions of Canadian dollars)
Balance at January 1, 2017
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
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(629)
478
2,700
(2,623)
(304)
1,058
18
(2,137)
(746)
1
207
(7)
(6)
(6)
—
189
(16)
(71)
(87)
(644)
478
(2,623)
—
—
—
—
—
12
—
12
—
—
—
—
—
—
—
—
77
37
(11)
—
—
—
—
—
(11)
(16)
—
(16)
10
—
—
—
—
41
59
(10)
(22)
(32)
(277)
(1,908)
207
(7)
(6)
(6)
41
(30)
(93)
(123)
(973)
(millions of Canadian dollars)
Balance at January 1, 2016
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, 2016
(millions of Canadian dollars)
Balance at January 1, 2015
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
Other comprehensive income reclassified to
earnings of derecognized cash flow
hedges
Tax impact
Income tax on amounts retained in AOCI
Income tax on amounts reclassified to
earnings
Income tax on amounts reclassified to
earnings of derecognized cash flow
hedges
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
(688)
(216)
147
(11)
1
(18)
—
(97)
91
(52)
39
(746)
(795)
171
—
—
—
—
—
171
(5)
—
(5)
(629)
3,365
(665)
—
—
—
—
—
(665)
—
—
—
2,700
37
(5)
—
—
—
—
—
(5)
5
—
5
37
(287)
(45)
—
—
—
—
21
(24)
11
(4)
7
(304)
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
(488)
73
(34)
(11)
7
26
—
(338)
(277)
(29)
15
91
108
(952)
309
3,056
—
—
—
—
—
—
—
—
—
—
—
—
(952)
3,056
49
—
—
—
—
—
(5)
47
—
—
—
—
—
—
47
(5)
—
—
(359)
65
—
—
—
—
32
—
97
(14)
(11)
—
Total
1,632
(760)
147
(11)
1
(18)
21
(620)
102
(56)
46
1,058
Total
(435)
2,289
(34)
(11)
7
26
32
(338)
1,971
1
4
91
Balance at December 31, 2015
1 Reported within Interest expense in the Consolidated Statements of Earnings.
2 Reported within Commodity costs in the Consolidated Statements of Earnings.
3 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5 These components are included in the computation of net benefit costs and are reported within Operating and administrative
77
(688)
49
(795)
—
3,365
(5)
37
(25)
(287)
96
1,632
Balance at December 31, 2017
(139)
expense in the Consolidated Statements of Earnings.
164
165
23. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Commodity Price Risk
MARKET RISK
Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates,
commodity prices and our share price (collectively, market risk). Formal risk management policies,
processes and systems have been designed to mitigate these risks.
The following summarizes the types of market risks to which we are exposed and the risk management
instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative
instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that
are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI
are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A
combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign
currency denominated revenues and expenses, and to manage variability in cash flows. We hedge
certain net investments in United States dollar denominated investments and subsidiaries using foreign
currency derivatives and United States dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing
of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are
used to hedge against the effect of future interest rate movements. We have implemented a program to
significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of
floating to fixed interest rate swaps with an average swap rate of 2.6%.
As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that
arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are
used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program
within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via
execution of fixed to floating interest rate swaps with an average swap rate of 2.2%.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of
anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against
the effect of future interest rate movements. We have assumed a program within some of our subsidiaries
to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via
execution of floating to fixed interest rate swaps with an average swap rate of 3.1%.
We also monitor our debt portfolio mix of fixed and variable rate debt instruments to maintain a
consolidated portfolio of debt within the Board of Directors approved policy limit of a maximum of 25%
floating rate debt as a percentage of total debt outstanding. Effective January 1, 2018, the Board of
Directors approved a policy limit increase of a maximum of 30% floating rate debt as a percentage of total
debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership
interests in certain assets and investments, as well as through the activities of our energy services
subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and
physical derivative instruments to fix a portion of the variable price exposures that arise from physical
transactions involving these commodities. We use primarily non-qualifying derivative instruments to
manage commodity price risk.
Emission Allowance Price Risk
Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission
allowances that our gas distribution business is required to purchase for itself and most of its customers
to meet GHG compliance obligations under the Ontario Cap and Trade framework. Similar to the gas
supply procurement framework, the OEB's framework for emission allowance procurement allows
recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure
to our 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. We use equity derivatives
to manage the earnings volatility derived from one form of stock-based compensation, restricted share
units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity
price risk.
TOTAL DERIVATIVE INSTRUMENTS
value of our derivative instruments.
The following table summarizes the Consolidated Statements of Financial Position location and carrying
We generally have a policy of entering into individual International Swaps and Derivatives
Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial
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 events, and
reduces our credit risk exposure on financial derivative asset positions outstanding with the
counterparties in those circumstances. The following table summarizes the maximum potential settlement
in the event of these specific circumstances. All amounts are presented gross in the Consolidated
Statements of Financial Position.
166
167
23. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET RISK
Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates,
commodity prices and our share price (collectively, market risk). Formal risk management policies,
processes and systems have been designed to mitigate these risks.
The following summarizes the types of market risks to which we are exposed and the risk management
instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative
instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that
are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI
are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A
combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign
currency denominated revenues and expenses, and to manage variability in cash flows. We hedge
certain net investments in United States dollar denominated investments and subsidiaries using foreign
currency derivatives and United States dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing
of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are
used to hedge against the effect of future interest rate movements. We have implemented a program to
significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of
floating to fixed interest rate swaps with an average swap rate of 2.6%.
As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that
arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are
used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program
within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via
execution of fixed to floating interest rate swaps with an average swap rate of 2.2%.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of
anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against
the effect of future interest rate movements. We have assumed a program within some of our subsidiaries
to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via
execution of floating to fixed interest rate swaps with an average swap rate of 3.1%.
We also monitor our debt portfolio mix of fixed and variable rate debt instruments to maintain a
consolidated portfolio of debt within the Board of Directors approved policy limit of a maximum of 25%
floating rate debt as a percentage of total debt outstanding. Effective January 1, 2018, the Board of
Directors approved a policy limit increase of a maximum of 30% floating rate debt as a percentage of total
debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.
Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership
interests in certain assets and investments, as well as through the activities of our energy services
subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and
physical derivative instruments to fix a portion of the variable price exposures that arise from physical
transactions involving these commodities. We use primarily non-qualifying derivative instruments to
manage commodity price risk.
Emission Allowance Price Risk
Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission
allowances that our gas distribution business is required to purchase for itself and most of its customers
to meet GHG compliance obligations under the Ontario Cap and Trade framework. Similar to the gas
supply procurement framework, the OEB's framework for emission allowance procurement allows
recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure
to our 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. We use equity derivatives
to manage the earnings volatility derived from one form of stock-based compensation, restricted share
units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity
price risk.
TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying
value of our derivative instruments.
We generally have a policy of entering into individual International Swaps and Derivatives
Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial
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 events, and
reduces our credit risk exposure on financial derivative asset positions outstanding with the
counterparties in those circumstances. The following table summarizes the maximum potential settlement
in the event of these specific circumstances. All amounts are presented gross in the Consolidated
Statements of Financial Position.
166
167
December 31, 2017
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Deferred amounts and other
assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Accounts payable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Other long-term liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other 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
Derivative
Instruments
Used as
Fair Value
Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as
Presented
Amounts
Available
for Offset
Total Net
Derivative
Instruments
Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as Net
Investment
Hedges
Non-
Qualifying
Derivative
Total Gross
Derivative
Instruments
Available for
Amounts
Total Net
Derivative
Instruments
as Presented
Offset
Instruments
1
6
2
9
1
7
17
25
(5)
(140)
—
(1)
(146)
(4)
(38)
—
(1)
(43)
(7)
(165)
19
(2)
(155)
4
—
—
4
1
—
—
1
(42)
—
—
—
(42)
(9)
—
—
—
(9)
(46)
—
—
—
(46)
—
2
—
2
—
6
—
6
—
(6)
—
—
(6)
—
(2)
—
—
(2)
—
—
—
—
—
138
—
143
281
143
—
6
149
(312)
(183)
(439)
(2)
(936)
(1,299)
—
(186)
—
(1,485)
(1,330)
(183)
(476)
(2)
(1,991)
143
8
145
296
145
13
23
181
(359)
(329)
(439)
(3)
(1,130)
(1,312)
(40)
(186)
(1)
(1,539)
(1,383)
(348)
(457)
(4)
(2,192)
(83)
(3)
(64)
(150)
(125)
(2)
(19)
(146)
83
3
64
—
150
125
2
19
—
146
—
—
—
—
—
60
5
81
146
20
11
4
35
(276)
(326)
(375)
(3)
(980)
(1,187)
(38)
(167)
(1)
(1,393)
(1,383)
(348)
(457)
(4)
(2,192)
December 31, 2016
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Deferred amounts and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Accounts payable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Other long-term liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net derivative asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
101
113
3
9
1
8
7
1
17
—
(452)
—
(1)
(453)
(268)
—
—
(268)
102
(709)
16
—
(591)
3
—
—
3
3
—
—
—
3
—
—
—
(268)
(68)
—
—
(68)
(330)
—
—
—
(330)
5
—
232
237
69
—
61
1
131
(727)
(131)
(359)
(3)
(1,961)
(205)
(211)
(2,377)
(2,614)
(336)
(277)
(2)
(3,229)
109
3
241
353
73
8
68
2
151
(995)
(583)
(359)
(4)
(2,029)
(473)
(211)
(2,713)
(2,842)
(1,045)
(261)
(2)
(4,150)
(268)
(1,220)
(1,941)
(103)
(3)
(125)
(231)
(72)
(6)
(22)
—
(100)
103
3
125
—
231
72
6
22
100
—
—
—
—
—
6
—
116
122
1
2
46
2
51
(892)
(580)
(234)
(4)
(1,710)
(1,957)
(467)
(189)
(2,613)
(2,842)
(1,045)
(261)
(2)
(4,150)
168
169
Derivative
Derivative
Derivative
Instruments
Instruments
Instruments
Used as
Used as Net
Used as
Cash Flow
Investment
Fair Value
Non-
Qualifying
Derivative
Total Gross
Derivative
Instruments
Amounts
Available
Total Net
Derivative
as
December 31, 2017
Hedges
Hedges
Hedges
Instruments
Presented
for Offset
Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Deferred amounts and other
assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Accounts payable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Other long-term liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Total net derivative asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
1
6
2
9
1
7
17
25
(5)
(140)
—
(1)
(146)
(4)
(38)
—
(1)
(43)
(7)
(165)
19
(2)
(155)
4
—
—
4
1
—
—
1
—
—
—
(42)
(42)
(9)
—
—
—
(9)
(46)
—
—
—
(46)
—
2
—
2
—
6
—
6
—
(6)
—
—
(6)
—
(2)
—
—
(2)
—
—
—
—
—
138
—
143
281
143
—
6
149
(312)
(183)
(439)
(2)
(936)
(186)
—
—
(183)
(476)
(2)
143
8
145
296
145
13
23
181
(359)
(329)
(439)
(3)
(1,130)
(40)
(186)
(1)
(348)
(457)
(4)
(1,299)
(1,312)
(1,485)
(1,539)
(1,330)
(1,383)
(1,991)
(2,192)
(83)
(3)
(64)
(150)
(125)
(2)
(19)
(146)
83
3
64
—
150
125
2
19
—
146
—
—
—
—
—
60
5
81
146
20
11
4
35
(276)
(326)
(375)
(3)
(980)
(1,187)
(38)
(167)
(1)
(1,393)
(1,383)
(348)
(457)
(4)
(2,192)
December 31, 2016
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Deferred amounts and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Accounts payable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Other long-term liabilities
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
101
3
9
113
1
8
7
1
17
—
(452)
—
(1)
(453)
—
(268)
—
(268)
102
(709)
16
—
(591)
3
—
—
3
3
—
—
—
3
(268)
—
—
—
(268)
(68)
—
—
(68)
(330)
—
—
—
(330)
5
—
232
237
69
—
61
1
131
(727)
(131)
(359)
(3)
(1,220)
(1,961)
(205)
(211)
(2,377)
(2,614)
(336)
(277)
(2)
(3,229)
109
3
241
353
73
8
68
2
151
(995)
(583)
(359)
(4)
(1,941)
(2,029)
(473)
(211)
(2,713)
(2,842)
(1,045)
(261)
(2)
(4,150)
(103)
(3)
(125)
(231)
(72)
(6)
(22)
—
(100)
103
3
125
—
231
72
6
22
100
—
—
—
—
—
6
—
116
122
1
2
46
2
51
(892)
(580)
(234)
(4)
(1,710)
(1,957)
(467)
(189)
(2,613)
(2,842)
(1,045)
(261)
(2)
(4,150)
168
169
The following table summarizes the maturity and notional principal or quantity outstanding related to our
derivative instruments.
As at December 31,
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 - British pound
(GBP) forwards - purchase (millions of GBP)
Foreign exchange contracts - GBP forwards -
sell (millions of GBP)
Foreign exchange contracts - Euro forwards -
purchase (millions of Euro)
Foreign exchange contracts - Euro forwards -
sell (millions of Euro)
Foreign exchange contracts - Japanese yen
forwards - purchase (millions of yen)
Interest rate contracts - short-term pay fixed
rate (millions of Canadian dollars)
Interest rate contracts - long-term receive fixed
rate (millions of Canadian dollars)
Interest rate contracts - long-term pay fixed rate
(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 per hour
(MW/H))
2018
2019
2020
2021
2022 Thereafter
2017
2016
Total
755
2
2
—
—
—
997
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
4,478
3,246
3,258
1,689
1,676
1,820
13,591
18
—
—
89
280
375
—
—
— 32,662
4,950
1,585
1,522
1,018
4,007
45
957
37
—
25
—
35
—
215
822
438
8
—
27
—
—
28
—
169
169
—
149
—
889
97
285
—
—
— 20,000
—
32,662
202
14,008
95
433
—
—
91
349
—
—
(1)
—
—
52
—
—
—
—
—
—
7,509
88
(161)
(20)
(14)
(4)2
(59)
(3)
(12)
42
(69)
(20)
(10)
—
—
51
—
—
55
—
—
(3)
(43)
1
(43)
1 As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025.
2 As at December 31, 2016, the average net purchase/(sell) of power was (4) MW/H for 2017 through 2025 with a high of 40 MW/H
and a low of (43) MW/H.
170
171
The Effect of Derivative Instruments on the Consolidated Statements of Earnings and
Comprehensive Income
The following table presents the effect of cash flow hedges and net investment hedges on our
consolidated earnings and consolidated comprehensive income, before the effect of income taxes:
Cash flow hedges
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Net investment hedges
Foreign exchange contracts
portion)
Foreign exchange contracts1
Interest rate contracts2,3
Commodity contracts4
Other contracts5
Restructuring Plan
Interest rate contracts2
Interest rate contracts2, 3
Commodity contracts4
Earnings.
Amount of (gain)/loss reclassified from AOCI to earnings (effective
De-designation of qualifying hedges in connection with the Canadian
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective
portion and amount excluded from effectiveness testing)
2017
2016
2015
(5)
6
11
1
284
297
(104)
388
(9)
8
283
—
—
(4)
—
(4)
(19)
(90)
14
39
22
(34)
2
145
(12)
(29)
106
—
—
61
—
61
77
(275)
9
(47)
(248)
(484)
9
128
(46)
28
119
338
338
21
5
26
1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of
2 Reported within Interest expense in the Consolidated Statements of Earnings.
3 For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest
rate swaps as not highly probable to issue long-term debt.
4 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and
administrative expense in the Consolidated Statements of Earnings.
5 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
We estimate that a loss of $38 million from 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 we are hedging
exposures to the variability of cash flows is 36 months as at December 31, 2017.
Fair Value Derivatives
For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or
loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged
risk is included in Interest expense in the Consolidated Statements of Earnings. During the years ended
December 31, 2017 and 2016, we recognized an unrealized loss of $10 million and nil, respectively, on
the derivative and an unrealized gain of $11 million and nil, respectively, on the hedged item in earnings.
During the years ended December 31, 2017 and 2016, we recognized a realized gain of $2 million and
nil, respectively, on the derivative and a realized loss of $2 million and nil, respectively, on the hedged
item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness.
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 - British pound
(GBP) forwards - purchase (millions of GBP)
Foreign exchange contracts - GBP forwards -
sell (millions of GBP)
Foreign exchange contracts - Euro forwards -
purchase (millions of Euro)
Foreign exchange contracts - Euro forwards -
sell (millions of Euro)
Foreign exchange contracts - Japanese yen
forwards - purchase (millions of yen)
Interest rate contracts - short-term pay fixed
rate (millions of Canadian dollars)
Interest rate contracts - long-term receive fixed
rate (millions of Canadian dollars)
Interest rate contracts - long-term pay fixed rate
(millions of Canadian dollars)
Equity contracts (millions of Canadian dollars)
Commodity contracts - natural gas (billions of
cubic feet)
barrels)
(MW/H))
Commodity contracts - crude oil (millions of
Commodity contracts - NGL (millions of barrels)
Commodity contracts - power (megawatt per hour
755
2
2
—
—
—
997
4,478
3,246
3,258
1,689
1,676
1,820
13,591
—
—
169
169
— 32,662
— 20,000
—
32,662
202
14,008
18
—
—
89
280
375
4,950
1,585
1,522
1,018
4,007
45
957
37
(59)
(3)
(12)
42
—
—
51
—
25
—
35
—
215
822
438
8
—
—
55
—
28
—
91
349
—
—
(1)
—
—
—
27
—
95
433
—
—
—
—
(3)
(69)
(20)
(10)
—
149
—
889
52
—
—
—
—
—
2016
Total
97
285
—
—
—
7,509
88
(161)
(20)
(14)
(4)2
1 As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025.
2 As at December 31, 2016, the average net purchase/(sell) of power was (4) MW/H for 2017 through 2025 with a high of 40 MW/H
and a low of (43) MW/H.
(43)
1
(43)
The following table summarizes the maturity and notional principal or quantity outstanding related to our
derivative instruments.
As at December 31,
2018
2019
2020
2021
2022 Thereafter
2017
The Effect of Derivative Instruments on the Consolidated Statements of Earnings and
Comprehensive Income
The following table presents the effect of cash flow hedges and net investment hedges on our
consolidated earnings and consolidated comprehensive income, before the effect of income taxes:
(millions of Canadian dollars)
Amount of unrealized gain/(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 (gain)/loss reclassified from AOCI to earnings (effective
portion)
Foreign exchange contracts1
Interest rate contracts2,3
Commodity contracts4
Other contracts5
De-designation of qualifying hedges in connection with the Canadian
Restructuring Plan
Interest rate contracts2
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective
portion and amount excluded from effectiveness testing)
Interest rate contracts2, 3
Commodity contracts4
2017
2016
2015
(5)
6
11
1
284
297
(104)
388
(9)
8
283
—
—
(4)
—
(4)
(19)
(90)
14
39
22
(34)
2
145
(12)
(29)
106
—
—
61
—
61
77
(275)
9
(47)
(248)
(484)
9
128
(46)
28
119
338
338
21
5
26
1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of
Earnings.
2 Reported within Interest expense in the Consolidated Statements of Earnings.
3 For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest
rate swaps as not highly probable to issue long-term debt.
4 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and
administrative expense in the Consolidated Statements of Earnings.
5 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
We estimate that a loss of $38 million from 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 we are hedging
exposures to the variability of cash flows is 36 months as at December 31, 2017.
Fair Value Derivatives
For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or
loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged
risk is included in Interest expense in the Consolidated Statements of Earnings. During the years ended
December 31, 2017 and 2016, we recognized an unrealized loss of $10 million and nil, respectively, on
the derivative and an unrealized gain of $11 million and nil, respectively, on the hedged item in earnings.
During the years ended December 31, 2017 and 2016, we recognized a realized gain of $2 million and
nil, respectively, on the derivative and a realized loss of $2 million and nil, respectively, on the hedged
item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness.
170
171
Non-Qualifying Derivatives
The following table presents the unrealized gains and losses associated with changes in the fair value of
Non-Qualifying Derivatives
our non-qualifying derivatives:
The following table presents the unrealized gains and losses associated with changes in the fair value of
our non-qualifying derivatives:
Year ended December 31,
(millions of Canadian dollars)
Year ended December 31,
Foreign exchange contracts1
(millions of Canadian dollars)
Interest rate contracts2
Foreign exchange contracts1
Interest rate contracts2
Commodity contracts3
Other contracts4
Commodity contracts3
Other contracts4
Total unrealized derivative fair value gain/(loss), net
Total unrealized derivative fair value gain/(loss), net
1 For the respective annual periods, reported within Transportation and other services revenues (2017 - $800 million gain; 2016 -
$497 million gain; 2015 - $1,383 million loss) and Other income/(expense) (2017 - $484 million gain; 2016 - $438 million gain;
1 For the respective annual periods, reported within Transportation and other services revenues (2017 - $800 million gain; 2016 -
2015 - $804 million loss) in the Consolidated Statements of Earnings.
$497 million gain; 2015 - $1,383 million loss) and Other income/(expense) (2017 - $484 million gain; 2016 - $438 million gain;
2015 - $804 million loss) in the Consolidated Statements of Earnings.
2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
3 For the respective annual periods, reported within Transportation and other services revenues (2017 - $104 million loss; 2016 -
2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
3 For the respective annual periods, reported within Transportation and other services revenues (2017 - $104 million loss; 2016 -
$52 million loss; 2015 - $328 million gain), Commodity sales (2017 - $90 million gain 2016 - $474 million loss; 2015 - $226 million
loss), Commodity costs (2017 - $223 million loss; 2016 - $38 million gain; 2015 - $99 million gain) and Operating and
$52 million loss; 2015 - $328 million gain), Commodity sales (2017 - $90 million gain 2016 - $474 million loss; 2015 - $226 million
administrative expense (2017 - $38 million gain; 2016 - $20 million loss; 2015 - $2 million loss) in the Consolidated Statements of
loss), Commodity costs (2017 - $223 million loss; 2016 - $38 million gain; 2015 - $99 million gain) and Operating and
Earnings.
administrative expense (2017 - $38 million gain; 2016 - $20 million loss; 2015 - $2 million loss) in the Consolidated Statements of
Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
2015
2015
(2,187)
(363)
(2,187)
(363)
199
(22)
199
(2,373)
(22)
(2,373)
2017
2017
1,284
157
1,284
157
(199)
—
(199)
1,242
—
1,242
2016
2016
935
73
935
73
(508)
9
(508)
509
9
509
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments
LIQUIDITY RISK
and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments
12 month rolling time period to determine whether sufficient funds will be available and maintain
and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a
12 month rolling time period to determine whether sufficient funds will be available and maintain
substantial capacity under our committed bank lines of credit to address any contingencies. Our primary
substantial capacity under our committed bank lines of credit to address any contingencies. Our 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
sources of liquidity and capital resources are funds generated from operations, the issuance of
debentures and medium-term notes. We also maintain current shelf prospectuses with securities
commercial paper and draws under committed credit facilities and long-term debt, which includes
regulators which enables, subject to market conditions, ready access to either the Canadian or United
debentures and medium-term notes. We also maintain 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, we maintain sufficient liquidity through committed credit facilities
with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated
States public capital markets. In addition, we maintain sufficient liquidity through committed credit facilities
requirements for approximately one year without accessing the capital markets. We are in compliance
with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated
with all the terms and conditions of our committed credit facility agreements and term debt indentures as
requirements for approximately one year without accessing the capital markets. We are in compliance
with all the terms and conditions of our committed credit facility agreements and term debt indentures as
at December 31, 2017. As a result, all credit facilities are available to us and the banks are obligated to
fund and have been funding us under the terms of the facilities.
at December 31, 2017. As a result, all credit facilities are available to us and the banks are obligated to
fund and have been funding us under the terms of the facilities.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a
CREDIT RISK
counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk
Entering into derivative instruments may result in exposure to credit risk from the possibility that a
management transactions primarily with institutions that possess investment grade credit ratings. Credit
counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk
risk relating to derivative counterparties is mitigated by credit exposure limits and contractual
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, netting arrangements, and ongoing monitoring of counterparty credit exposure using
requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using
external credit rating services and other analytical tools.
external credit rating services and other analytical tools.
172
172
We have 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
Asian financial institutions
Other1
2017
2016
82
19
145
2
137
385
39
179
106
1
162
487
1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at December 31, 2017, we provided letters of credit totaling nil in lieu of providing cash collateral to our
counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on
derivative asset exposures as at December 31, 2017 and December 31, 2016.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets
are adjusted for non-performance risk of our counterparties using their credit default swap spread rates,
and are reflected at fair value. For derivative liabilities, our 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 EGD and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base
and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively
monitor the financial strength of large industrial customers and, in select cases, have obtained additional
security to minimize the risk of default on receivables. Generally, we classify and provide for receivables
older than 20 days as past due. The maximum exposure to credit risk related to non-derivative financial
assets is their carrying value.
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivative
instruments. We also disclose the fair value of other financial instruments not measured at fair value. The
fair value of financial instruments reflects our best estimates of market value based on generally accepted
valuation techniques or models and is supported by observable market prices and rates. When such
values are not available, we use discounted cash flow analysis from applicable yield curves based on
observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our 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 2
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. Our Level 1 instruments consist primarily of exchange-
traded derivatives used to mitigate the risk of crude oil price fluctuations.
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
173
The following table presents the unrealized gains and losses associated with changes in the fair value of
Non-Qualifying Derivatives
our non-qualifying derivatives:
The following table presents the unrealized gains and losses associated with changes in the fair value of
Non-Qualifying Derivatives
our non-qualifying derivatives:
Year ended December 31,
(millions of Canadian dollars)
Year ended December 31,
Foreign exchange contracts1
(millions of Canadian dollars)
Interest rate contracts2
Foreign exchange contracts1
Commodity contracts3
Interest rate contracts2
Other contracts4
Commodity contracts3
We have group credit concentrations and maximum credit exposure, with respect to derivative
instruments, in the following counterparty segments:
2017
2017
1,284
1,284
157
(199)
157
(199)
—
1,242
—
2016
2016
935
935
73
(508)
73
(508)
9
509
9
2015
2015
(2,187)
(2,187)
(363)
(363)
199
199
(22)
(2,373)
(22)
December 31,
(millions of Canadian dollars)
Canadian financial institutions
United States financial institutions
European financial institutions
Asian financial institutions
Other1
2017
2016
82
19
145
2
137
385
39
179
106
1
162
487
1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at December 31, 2017, we provided letters of credit totaling nil in lieu of providing cash collateral to our
counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on
derivative asset exposures as at December 31, 2017 and December 31, 2016.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets
are adjusted for non-performance risk of our counterparties using their credit default swap spread rates,
and are reflected at fair value. For derivative liabilities, our 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 EGD and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base
and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively
monitor the financial strength of large industrial customers and, in select cases, have obtained additional
security to minimize the risk of default on receivables. Generally, we classify and provide for receivables
older than 20 days as past due. The maximum exposure to credit risk related to non-derivative financial
assets is their carrying value.
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivative
instruments. We also disclose the fair value of other financial instruments not measured at fair value. The
fair value of financial instruments reflects our best estimates of market value based on generally accepted
valuation techniques or models and is supported by observable market prices and rates. When such
values are not available, we use discounted cash flow analysis from applicable yield curves based on
observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our 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. Our 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
173
Other contracts4
Total unrealized derivative fair value gain/(loss), net
1 For the respective annual periods, reported within Transportation and other services revenues (2017 - $800 million gain; 2016 -
Total unrealized derivative fair value gain/(loss), net
(2,373)
509
1,242
$497 million gain; 2015 - $1,383 million loss) and Other income/(expense) (2017 - $484 million gain; 2016 - $438 million gain;
1 For the respective annual periods, reported within Transportation and other services revenues (2017 - $800 million gain; 2016 -
2015 - $804 million loss) in the Consolidated Statements of Earnings.
$497 million gain; 2015 - $1,383 million loss) and Other income/(expense) (2017 - $484 million gain; 2016 - $438 million gain;
2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
2015 - $804 million loss) in the Consolidated Statements of Earnings.
3 For the respective annual periods, reported within Transportation and other services revenues (2017 - $104 million loss; 2016 -
2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
$52 million loss; 2015 - $328 million gain), Commodity sales (2017 - $90 million gain 2016 - $474 million loss; 2015 - $226 million
3 For the respective annual periods, reported within Transportation and other services revenues (2017 - $104 million loss; 2016 -
loss), Commodity costs (2017 - $223 million loss; 2016 - $38 million gain; 2015 - $99 million gain) and Operating and
$52 million loss; 2015 - $328 million gain), Commodity sales (2017 - $90 million gain 2016 - $474 million loss; 2015 - $226 million
administrative expense (2017 - $38 million gain; 2016 - $20 million loss; 2015 - $2 million loss) in the Consolidated Statements of
loss), Commodity costs (2017 - $223 million loss; 2016 - $38 million gain; 2015 - $99 million gain) and Operating and
administrative expense (2017 - $38 million gain; 2016 - $20 million loss; 2015 - $2 million loss) in the Consolidated Statements of
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
Earnings.
Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments
LIQUIDITY RISK
and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments
12 month rolling time period to determine whether sufficient funds will be available and maintain
and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a
substantial capacity under our committed bank lines of credit to address any contingencies. Our primary
12 month rolling time period to determine whether sufficient funds will be available and maintain
sources of liquidity and capital resources are funds generated from operations, the issuance of
substantial capacity under our committed bank lines of credit to address any contingencies. Our primary
commercial paper and draws under committed credit facilities and long-term debt, which includes
sources of liquidity and capital resources are funds generated from operations, the issuance of
debentures and medium-term notes. We also maintain current shelf prospectuses with securities
commercial paper and draws under committed credit facilities and long-term debt, which includes
regulators which enables, subject to market conditions, ready access to either the Canadian or United
debentures and medium-term notes. We also maintain current shelf prospectuses with securities
States public capital markets. In addition, we maintain sufficient liquidity through committed credit facilities
regulators which enables, subject to market conditions, ready access to either the Canadian or United
with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated
States public capital markets. In addition, we maintain sufficient liquidity through committed credit facilities
requirements for approximately one year without accessing the capital markets. We are in compliance
with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated
with all the terms and conditions of our committed credit facility agreements and term debt indentures as
requirements for approximately one year without accessing the capital markets. We are in compliance
at December 31, 2017. As a result, all credit facilities are available to us and the banks are obligated to
with all the terms and conditions of our committed credit facility agreements and term debt indentures as
fund and have been funding us under the terms of the facilities.
at December 31, 2017. As a result, all credit facilities are available to us and the banks are obligated to
fund and have been funding us under the terms of the facilities.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a
CREDIT RISK
counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk
Entering into derivative instruments may result in exposure to credit risk from the possibility that a
management transactions primarily with institutions that possess investment grade credit ratings. Credit
counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk
risk relating to derivative counterparties is mitigated by credit exposure limits and contractual
management transactions primarily with institutions that possess investment grade credit ratings. Credit
requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using
risk relating to derivative counterparties is mitigated by credit exposure limits and contractual
external credit rating services and other analytical tools.
requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using
external credit rating services and other analytical tools.
172
172
We have categorized our derivative assets and liabilities measured at fair value as follows:
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.
We have also categorized the fair value of our held to maturity preferred share investment and long-term
debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the
yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted
market prices for instruments of similar yield, credit risk and tenor.
Level 3
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. We have
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. We do not have any other
financial instruments categorized in Level 3.
We use the most observable inputs available to estimate the fair value of our derivatives. When possible,
we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are
not available, we use estimates from third party brokers. For non-exchange traded derivatives classified
in Levels 2 and 3, we use 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, we use observable
market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to
these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit
default swap spreads associated with our counterparties in our estimation of fair value.
December 31, 2017
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Long-term derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Long-term derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other 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
—
—
1
1
—
—
—
—
—
—
(13)
—
(13)
—
—
—
—
—
—
—
(12)
—
(12)
143
8
30
181
145
13
2
160
(359)
(329)
(87)
(3)
(778)
(1,312)
(40)
(3)
(1)
(1,356)
(1,383)
(348)
(58)
(4)
(1,793)
—
—
114
114
—
—
21
21
(339)
(339)
(183)
(183)
—
—
—
—
—
—
—
—
—
(387)
(387)
143
8
145
296
145
13
23
181
(359)
(329)
(439)
(3)
(1,130)
(1,312)
(40)
(186)
(1)
(1,539)
(1,383)
(348)
(457)
(4)
(2,192)
174
175
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.
We have also categorized the fair value of our held to maturity preferred share investment and long-term
debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the
yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted
market prices for instruments of similar yield, credit risk and tenor.
Level 3
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. We have
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. We do not have any other
financial instruments categorized in Level 3.
We use the most observable inputs available to estimate the fair value of our derivatives. When possible,
we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are
not available, we use estimates from third party brokers. For non-exchange traded derivatives classified
in Levels 2 and 3, we use 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, we use observable
market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to
these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit
default swap spreads associated with our counterparties in our estimation of fair value.
We have categorized our derivative assets and liabilities measured at fair value as follows:
December 31, 2017
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Long-term derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Long-term derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other 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
—
—
1
1
—
—
—
—
—
—
(13)
—
(13)
—
—
—
—
—
—
—
(12)
—
(12)
143
8
30
181
145
13
2
160
(359)
(329)
(87)
(3)
(778)
(1,312)
(40)
(3)
(1)
(1,356)
(1,383)
(348)
(58)
(4)
(1,793)
—
—
114
114
—
—
21
21
—
—
(339)
—
(339)
—
—
(183)
—
(183)
—
—
(387)
—
(387)
143
8
145
296
145
13
23
181
(359)
(329)
(439)
(3)
(1,130)
(1,312)
(40)
(186)
(1)
(1,539)
(1,383)
(348)
(457)
(4)
(2,192)
174
175
December 31, 2016
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity 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
Other 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
—
—
2
2
—
—
—
—
—
—
—
(12)
—
(12)
—
—
—
—
—
—
(10)
—
(10)
109
3
86
198
73
8
43
2
126
(995)
(583)
(75)
(4)
(1,657)
(2,029)
(473)
(10)
(2,512)
(2,842)
(1,045)
44
(2)
(3,845)
—
—
153
153
—
—
25
—
25
—
—
(272)
—
(272)
—
—
(201)
(201)
—
—
(295)
—
(295)
109
3
241
353
73
8
68
2
151
(995)
(583)
(359)
(4)
(1,941)
(2,029)
(473)
(211)
(2,713)
(2,842)
(1,045)
(261)
(2)
(4,150)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
were as follows:
December 31, 2017
Fair Value
Unobservable Input
Minimum
Price/Volatility
Maximum
Price/Volatility
Weighted
Average
Price/Volatility
Unit of
Measurement
(fair value in millions of
Canadian dollars)
Commodity contracts -
financial1
Natural gas
Crude
NGL
Power
Commodity contracts -
physical1
Natural gas
Crude
NGL
Commodity options2
Crude
Power
Forward gas price
Forward crude price
Forward NGL price
Forward power price
Forward gas price
Forward crude price
Forward NGL price
2.67
43.76
0.30
15.39
2.51
34.38
0.28
5.52
65.60
1.83
71.41
7.57
80.56
1.94
3.38
51.03
1.32
50.72
2.93
69.01
0.93
$/mmbtu3
$/barrel
$/gallon
$/MW/H
$/mmbtu3
$/barrel
$/gallon
Option volatility
Option volatility
15%
29%
24%
55%
22%
35%
(1)
(4)
(12)
(110)
(114)
(148)
3
(1)
—
(387)
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).
If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on
the fair value of our 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 our Level 3 derivatives. Changes in price volatility would change the value of the option
contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the
Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy
estimate of price volatility.
were as follows:
Year ended December 31,
(millions of Canadian dollars)
Total gain/(loss)
Included in earnings1
Included in OCI
Settlements
Level 3 net derivative asset/(liability) at beginning of period
2017
2016
(295)
(184)
4
88
(387)
54
(113)
3
(239)
(295)
Level 3 net derivative liability at end of period
Consolidated Statements of Earnings.
1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the
Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers
between levels as at December 31, 2017 or 2016.
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Our other long-term investments in other entities with no actively quoted prices are recorded at cost. The
carrying value of other long-term investments recognized at cost totaled $99 million and $110 million as at
December 31, 2017 and 2016, respectively.
We have Restricted long-term investments held in trust totaling $267 million and $90 million as at
December 31, 2017 and 2016, respectively, which are recognized at fair value.
We have a held to maturity preferred share investment carried at its amortized cost of $371 million and
$355 million as at December 31, 2017 and 2016, respectively. These preferred shares are entitled to a
cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin
of 4.38%. The fair value of this preferred share investment approximates its face value of $580 million as
at December 31, 2017 and 2016.
As at December 31, 2017 and 2016, our long-term debt had a carrying value of $64.0 billion and $40.8
billion, respectively, before debt issuance costs and a fair value of $67.4 billion and $43.9 billion,
respectively. We also have noncurrent notes receivable carried at book value recorded in Deferred
amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2017
and 2016, the noncurrent notes receivable had a carrying value of $89 million and nil, and a fair value of
$89 million and nil, respectively.
NET INVESTMENT HEDGES
We have designated a portion of our United States dollar denominated debt, as well as a portfolio of
foreign exchange forward contracts, as a hedge of our net investment in United States dollar
denominated investments and subsidiaries.
During the years ended December 31, 2017 and 2016, we recognized an unrealized foreign exchange
gain on the translation of United States dollar denominated debt of $367 million and $121 million,
respectively, and an unrealized gain on the change in fair value of our outstanding foreign exchange
176
177
Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments
—
—
2
2
—
—
—
—
—
—
—
(12)
—
(12)
—
—
—
—
—
—
(10)
—
(10)
109
3
86
198
73
8
43
2
126
(995)
(583)
(75)
(4)
(2,029)
(473)
(10)
(2,512)
(2,842)
(1,045)
44
(2)
(3,845)
—
—
153
153
—
—
25
—
25
—
—
—
—
—
(272)
(201)
(201)
—
—
—
(295)
(295)
109
3
241
353
73
8
68
2
151
(995)
(583)
(359)
(4)
(2,029)
(473)
(211)
(2,713)
(2,842)
(1,045)
(261)
(2)
(4,150)
(1,657)
(272)
(1,941)
December 31, 2016
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity 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
Other 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
were as follows:
December 31, 2017
(fair value in millions of
Canadian dollars)
Commodity contracts -
Commodity contracts -
financial1
Natural gas
Crude
NGL
Power
physical1
Natural gas
Crude
NGL
Crude
Power
Commodity options2
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value
Unobservable Input
Price/Volatility
Price/Volatility
Price/Volatility
Measurement
Minimum
Maximum
Weighted
Average
Unit of
Forward gas price
Forward crude price
Forward NGL price
Forward power price
Forward gas price
Forward crude price
Forward NGL price
2.67
43.76
0.30
15.39
2.51
34.38
0.28
5.52
65.60
1.83
71.41
7.57
80.56
1.94
3.38
51.03
1.32
50.72
2.93
69.01
0.93
$/mmbtu3
$/barrel
$/gallon
$/MW/H
$/mmbtu3
$/barrel
$/gallon
Option volatility
Option volatility
15%
29%
24%
55%
22%
35%
(1)
(4)
(12)
(110)
(114)
(148)
3
(1)
—
(387)
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).
If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on
the fair value of our 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 our Level 3 derivatives. Changes in price volatility would change the value of the option
contracts. Generally, 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 gain/(loss)
Included in earnings1
Included in OCI
Settlements
2017
2016
(295)
54
(184)
4
88
(387)
(113)
3
(239)
(295)
Level 3 net derivative liability at end of period
1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the
Consolidated Statements of Earnings.
Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers
between levels as at December 31, 2017 or 2016.
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Our other long-term investments in other entities with no actively quoted prices are recorded at cost. The
carrying value of other long-term investments recognized at cost totaled $99 million and $110 million as at
December 31, 2017 and 2016, respectively.
We have Restricted long-term investments held in trust totaling $267 million and $90 million as at
December 31, 2017 and 2016, respectively, which are recognized at fair value.
We have a held to maturity preferred share investment carried at its amortized cost of $371 million and
$355 million as at December 31, 2017 and 2016, respectively. These preferred shares are entitled to a
cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin
of 4.38%. The fair value of this preferred share investment approximates its face value of $580 million as
at December 31, 2017 and 2016.
As at December 31, 2017 and 2016, our long-term debt had a carrying value of $64.0 billion and $40.8
billion, respectively, before debt issuance costs and a fair value of $67.4 billion and $43.9 billion,
respectively. We also have noncurrent notes receivable carried at book value recorded in Deferred
amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2017
and 2016, the noncurrent notes receivable had a carrying value of $89 million and nil, and a fair value of
$89 million and nil, respectively.
NET INVESTMENT HEDGES
We have designated a portion of our United States dollar denominated debt, as well as a portfolio of
foreign exchange forward contracts, as a hedge of our net investment in United States dollar
denominated investments and subsidiaries.
During the years ended December 31, 2017 and 2016, we recognized an unrealized foreign exchange
gain on the translation of United States dollar denominated debt of $367 million and $121 million,
respectively, and an unrealized gain on the change in fair value of our outstanding foreign exchange
176
177
forward contracts of $286 million and $21 million, respectively, in OCI. During the years ended
December 31, 2017 and 2016, we recognized a realized loss of $198 million and a realized gain of $3
million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and also
recognized a realized gain of $23 million and $26 million, respectively, in OCI associated with the
settlement of United States dollar denominated debt that had matured during the period. There was no
ineffectiveness during the years ended December 31, 2017 and 2016.
COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
Year ended December 31,
(millions of Canadian dollars)
Earnings/(loss) before income taxes
2017
2016
2015
24. INCOME TAXES
INCOME TAX RATE RECONCILIATION
Year ended December 31,
(millions of Canadian dollars)
Earnings before income taxes
Canadian federal statutory income tax rate
Expected federal taxes at statutory rate
Increase/(decrease) resulting from:
Provincial and state income taxes1
Foreign and other statutory rate differentials
Impact of United States tax reform2
Effects of rate-regulated accounting
Foreign allowable interest deductions
Part VI.1 tax, net of federal Part I deduction
Goodwill write-down3
Intercompany sale of investment4
Non-taxable portion of gain on sale of investment to unrelated
party5
Valuation allowance6
Intercorporate investment in EIPLP7
Noncontrolling interests
Other8
2017
569
15%
85
2016
2015
2,451
15%
368
11
15%
2
133
(601)
(2,045)
(189)
(124)
68
15
—
34
(56)
—
(116)
(107)
56
—
6
(204)
310
—
(52)
(84)
55
—
23
—
(17)
77
(80)
(19)
(2,697)
(474.0)%
(61)
22
—
(15)
11
142
5.8% 1,545.5%
—
154
—
(28)
(6)
170
Income tax (recovery)/expense
Effective income tax rate
1 The change in provincial and state income taxes from 2016 to 2017 reflects the increase in earnings from the Canadian
operations and the impact of the United States tax reform on state income tax expense.
2 The amount was due to the enactment of the “Tax Cuts and Jobs Act” by the United States on December 22, 2017, which
included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after
December 31, 2017.
3 The amount relates to the federal component of the tax effect a goodwill write-down pursuant to ASU 2017-04.
4 In November 2016 and September 2015, certain assets were sold to entities under common control. The intercompany gains
realized on these transfers were eliminated. However, because these transactions involved the sale of partnership units, tax
consequences have been recognized in earnings.
5 The amount in 2016 represents the federal component of the non-taxable portion of the gain on the sale of the South Prairie
Region assets to unrelated party.
6 The decrease from 2015 to 2016 is due to the federal component of the tax effect of a valuation allowance on the deferred tax
assets related to an outside basis temporary difference that, in 2015, was no longer more likely than not to be realized.
7 There was a change in assertion regarding the manner of recovery of the intercorporate investment in EIPLP such that deferred
tax related to outside basis temporary differences was required to be recorded.
8 2015 included $17 million recovery related to the federal component of the tax effect of adjustments related to prior periods.
178
179
A valuation allowance has been established for certain loss and credit carryforwards, and outside basis
temporary differences on investments that reduce deferred income tax assets to an amount that will more
likely than not be realized.
As at December 31, 2017 and 2016, we recognized the benefit of unused tax loss carryforwards of $3.8
billion and $2.5 billion, respectively, in Canada which expire in 2025 and beyond.
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 as follows:
2017
2016
Canada
United States
Other
Current income taxes
Canada
United States
Other
Deferred income taxes
Canada
United States
Other
Income tax (recovery)/expense
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:
Total deferred income tax assets
Total deferred income tax liabilities
Net deferred income tax liabilities
2,200
(2,431)
800
569
129
46
5
180
299
(3,160)
(16)
(2,877)
(2,697)
2,034
(333)
750
2,451
74
21
4
99
188
(151)
6
43
142
(4,089)
(6,596)
(977)
(50)
(11,712)
697
258
1,781
1,057
3,793
(286)
3,507
(8,205)
1,090
(9,295)
(8,205)
(1,365)
808
568
11
157
3
3
163
(558)
565
—
7
170
(3,867)
(2,938)
(439)
(47)
(7,291)
1,215
219
1,189
374
2,997
(572)
2,425
(4,866)
1,170
(6,036)
(4,866)
forward contracts of $286 million and $21 million, respectively, in OCI. During the years ended
December 31, 2017 and 2016, we recognized a realized loss of $198 million and a realized gain of $3
million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and also
recognized a realized gain of $23 million and $26 million, respectively, in OCI associated with the
settlement of United States dollar denominated debt that had matured during the period. There was no
ineffectiveness during the years ended December 31, 2017 and 2016.
24. INCOME TAXES
INCOME TAX RATE RECONCILIATION
Year ended December 31,
(millions of Canadian dollars)
Earnings before income taxes
Canadian federal statutory income tax rate
Expected federal taxes at statutory rate
Increase/(decrease) resulting from:
Provincial and state income taxes1
Foreign and other statutory rate differentials
Impact of United States tax reform2
Effects of rate-regulated accounting
Foreign allowable interest deductions
Part VI.1 tax, net of federal Part I deduction
Goodwill write-down3
Intercompany sale of investment4
party5
Valuation allowance6
Intercorporate investment in EIPLP7
Noncontrolling interests
Other8
Income tax (recovery)/expense
Effective income tax rate
Non-taxable portion of gain on sale of investment to unrelated
2017
569
15%
85
2016
2015
2,451
15%
368
11
15%
2
133
(601)
(2,045)
(189)
(124)
68
15
—
—
(17)
77
(80)
(19)
(2,697)
(474.0)%
34
(56)
—
(116)
(107)
56
—
6
(61)
22
—
(15)
11
142
(204)
310
—
(52)
(84)
55
—
23
—
154
—
(28)
(6)
170
5.8% 1,545.5%
1 The change in provincial and state income taxes from 2016 to 2017 reflects the increase in earnings from the Canadian
operations and the impact of the United States tax reform on state income tax expense.
2 The amount was due to the enactment of the “Tax Cuts and Jobs Act” by the United States on December 22, 2017, which
included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after
December 31, 2017.
3 The amount relates to the federal component of the tax effect a goodwill write-down pursuant to ASU 2017-04.
4 In November 2016 and September 2015, certain assets were sold to entities under common control. The intercompany gains
realized on these transfers were eliminated. However, because these transactions involved the sale of partnership units, tax
5 The amount in 2016 represents the federal component of the non-taxable portion of the gain on the sale of the South Prairie
consequences have been recognized in earnings.
Region assets to unrelated party.
6 The decrease from 2015 to 2016 is due to the federal component of the tax effect of a valuation allowance on the deferred tax
assets related to an outside basis temporary difference that, in 2015, was no longer more likely than not to be realized.
7 There was a change in assertion regarding the manner of recovery of the intercorporate investment in EIPLP such that deferred
tax related to outside basis temporary differences was required to be recorded.
8 2015 included $17 million recovery related to the federal component of the tax effect of adjustments related to prior periods.
COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
Year ended December 31,
(millions of Canadian dollars)
Earnings/(loss) before income taxes
Canada
United States
Other
Current income taxes
Canada
United States
Other
Deferred income taxes
Canada
United States
Other
Income tax (recovery)/expense
2017
2016
2015
2,200
(2,431)
800
569
129
46
5
180
299
(3,160)
(16)
(2,877)
(2,697)
2,034
(333)
750
2,451
(1,365)
808
568
11
74
21
4
99
188
(151)
6
43
142
157
3
3
163
(558)
565
—
7
170
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 as follows:
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:
Total deferred income tax assets
Total deferred income tax liabilities
Net deferred income tax liabilities
2017
2016
(4,089)
(6,596)
(977)
(50)
(11,712)
697
258
1,781
1,057
3,793
(286)
3,507
(8,205)
1,090
(9,295)
(8,205)
(3,867)
(2,938)
(439)
(47)
(7,291)
1,215
219
1,189
374
2,997
(572)
2,425
(4,866)
1,170
(6,036)
(4,866)
178
179
A valuation allowance has been established for certain loss and credit carryforwards, and outside basis
temporary differences on investments that reduce deferred income tax assets to an amount that will more
likely than not be realized.
As at December 31, 2017 and 2016, we recognized the benefit of unused tax loss carryforwards of $3.8
billion and $2.5 billion, respectively, in Canada which expire in 2025 and beyond.
As at December 31, 2017 and 2016, we recognized the benefit of unused tax loss carryforwards of $2.1
billion and $1.3 billion, respectively, in the United States which expire in 2021 and beyond.
As at December 31, 2017 and 2016, we recognized the benefit of unused capital loss carryforwards of
$143 million and nil, respectively, in Canada which can be carried forward indefinitely.
As at December 31, 2017 and 2016, we recognized the benefit of unused capital loss carryforwards of
$20 million and nil, respectively, in the United States which will expire in 2021.
We have not provided for deferred income taxes on the difference between the carrying value of
substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those
subsidiaries are intended to be permanently reinvested in their operations. As such these investments are
not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying
values of the investments and their tax bases is largely a result of unremitted earnings and currency
translation adjustments. The unremitted earnings and currency translation adjustment for which no
deferred taxes have been recognized in respect of foreign subsidiaries were $2.1 billion and $4.1 billion
for the period December 31, 2017 and 2016, respectively. If such earnings are remitted, in the form of
dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The
determination of the amount of unrecognized deferred income tax liabilities on such amounts is not
practicable.
Enbridge and one or more of our subsidiaries are subject to taxation in Canada, the United States and
other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations
include the United States (Federal) and Canada (Federal, Alberta and Ontario). We are open to
examination by Canadian tax authorities for the 2009 to 2017 tax years and by United States tax
authorities for the 2014 to 2017 tax years. We are currently under examination for income tax matters in
Canada for the 2013 to 2016 tax years. We are not currently under examination for income tax matters in
any other material jurisdiction where we are subject to income tax.
United States Tax Reform
On December 22, 2017, the United States enacted the TCJA. The changes in the TCJA are effective for
taxation years beginning after December 31, 2017. While the changes are broad and complex, the most
significant change is the reduction in the corporate federal income tax rate from 35% to 21%. We are also
impacted by a one-time deemed repatriation or “toll” tax on undistributed earnings and profits of United
States controlled foreign affiliates, including Canadian subsidiaries.
We have made reasonable estimates for the measurement and accounting of certain effects of the TCJA
in accordance with SEC Staff Accounting Bulletin No.118 (SAB 118). We recorded a provisional $34
million increase to our 2017 current income tax provision related to the toll tax, payable over eight years.
We recorded a provisional $2.0 billion decrease to our 2017 deferred income tax provision related to the
reduction in the corporate federal income tax rate. The accounting for these provisional items decreased
our accumulated deferred income tax liability by $3.1 billion and increased our regulatory liability by $1.1
billion. We have also adjusted our valuation allowance for certain deferred tax assets existing at
December 31, 2016 for the reduction in the corporate federal income tax rate by $0.2 billion. We have
recognized these provisional tax impacts and included these amounts in our consolidated financial
statements for the year ended December 31, 2017. The ultimate impact may differ from these provisional
amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations
and assumptions we have made, additional regulatory guidance that may be issued, and actions we may
take as a result of the TCJA. The accounting is expected to be complete when the 2017 US corporate
income tax return is filed in 2018.
As provided for under SAB 118, we have not recorded the impact for certain items under the TCJA for
which we have not yet been able to gather, prepare and analyze the necessary information in reasonable
detail to complete the ASC 740 accounting. For these items, the current and deferred taxes were
recognized and measured based on the provisions of the tax laws that were in effect immediately prior to
the TCJA being enacted. These certain items include but are not limited to the computation of state
income taxes as there is uncertainty on conformity to the federal tax system following the TCJA, global
intangible low taxed income, and base erosion and anti-abuse tax. The determination of the impact of the
income tax effects of these items will require additional analysis of historical records and further
interpretation of the TCJA from yet to be issued United States Treasury regulations which will require
more time, information and resources than currently available to us.
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 for tax positions of prior year
Change in translation of foreign currency
Lapses of statute of limitations
Settlements
Unrecognized tax benefits at end of year
2017
2016
84
15
65
(2)
(8)
(4)
150
65
27
—
(2)
(6)
—
84
The unrecognized tax benefits as at December 31, 2017, if recognized, would impact our effective income
tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12
months that would have a material impact on our consolidated financial statements.
We recognize accrued interest and penalties related to unrecognized tax benefits as a component of
income taxes. Income taxes for the years ended December 31, 2017 and 2016 included $3 million and $1
million recoveries, respectively, of interest and penalties. As at December 31, 2017 and 2016, interest and
penalties of $8 million and $6 million, respectively, have been accrued.
25. PENSION AND OTHER POSTRETIREMENT BENEFITS
PENSION PLANS
We maintain registered and non-registered, contributory and non-contributory pension plans which
provide defined benefit and/or defined contribution pension benefits covering substantially all employees.
The Canadian Plans provide Company funded defined benefit and/or defined contribution pension
benefits to our Canadian employees. The United States Plans provide Company funded defined benefit
pension benefits to our United States employees. We also maintain supplemental pension plans that
provide pension benefits in excess of the basic plans for certain employees.
Defined Benefit Plans
Benefits payable from the defined benefit plans are based on each plan participant’s years of service and
final average remuneration. These benefits are partially inflation-indexed after a plan participant’s
retirement. Our contributions are made in accordance with independent actuarial valuations and are
invested primarily in publicly-traded equity and fixed income securities.
Defined Contribution Plans
Contributions are generally based on each plan participant’s age, years of service and current eligible
remuneration. For defined contribution plans, benefit costs equal amounts required to be contributed by
us.
180
181
As at December 31, 2017 and 2016, we recognized the benefit of unused tax loss carryforwards of $2.1
billion and $1.3 billion, respectively, in the United States which expire in 2021 and beyond.
As at December 31, 2017 and 2016, we recognized the benefit of unused capital loss carryforwards of
$143 million and nil, respectively, in Canada which can be carried forward indefinitely.
As at December 31, 2017 and 2016, we recognized the benefit of unused capital loss carryforwards of
$20 million and nil, respectively, in the United States which will expire in 2021.
We have not provided for deferred income taxes on the difference between the carrying value of
substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those
subsidiaries are intended to be permanently reinvested in their operations. As such these investments are
not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying
values of the investments and their tax bases is largely a result of unremitted earnings and currency
translation adjustments. The unremitted earnings and currency translation adjustment for which no
deferred taxes have been recognized in respect of foreign subsidiaries were $2.1 billion and $4.1 billion
for the period December 31, 2017 and 2016, respectively. If such earnings are remitted, in the form of
dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The
determination of the amount of unrecognized deferred income tax liabilities on such amounts is not
practicable.
Enbridge and one or more of our subsidiaries are subject to taxation in Canada, the United States and
other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations
include the United States (Federal) and Canada (Federal, Alberta and Ontario). We are open to
examination by Canadian tax authorities for the 2009 to 2017 tax years and by United States tax
authorities for the 2014 to 2017 tax years. We are currently under examination for income tax matters in
Canada for the 2013 to 2016 tax years. We are not currently under examination for income tax matters in
any other material jurisdiction where we are subject to income tax.
United States Tax Reform
On December 22, 2017, the United States enacted the TCJA. The changes in the TCJA are effective for
taxation years beginning after December 31, 2017. While the changes are broad and complex, the most
significant change is the reduction in the corporate federal income tax rate from 35% to 21%. We are also
impacted by a one-time deemed repatriation or “toll” tax on undistributed earnings and profits of United
States controlled foreign affiliates, including Canadian subsidiaries.
We have made reasonable estimates for the measurement and accounting of certain effects of the TCJA
in accordance with SEC Staff Accounting Bulletin No.118 (SAB 118). We recorded a provisional $34
million increase to our 2017 current income tax provision related to the toll tax, payable over eight years.
We recorded a provisional $2.0 billion decrease to our 2017 deferred income tax provision related to the
reduction in the corporate federal income tax rate. The accounting for these provisional items decreased
our accumulated deferred income tax liability by $3.1 billion and increased our regulatory liability by $1.1
billion. We have also adjusted our valuation allowance for certain deferred tax assets existing at
December 31, 2016 for the reduction in the corporate federal income tax rate by $0.2 billion. We have
recognized these provisional tax impacts and included these amounts in our consolidated financial
statements for the year ended December 31, 2017. The ultimate impact may differ from these provisional
amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations
and assumptions we have made, additional regulatory guidance that may be issued, and actions we may
take as a result of the TCJA. The accounting is expected to be complete when the 2017 US corporate
income tax return is filed in 2018.
As provided for under SAB 118, we have not recorded the impact for certain items under the TCJA for
which we have not yet been able to gather, prepare and analyze the necessary information in reasonable
detail to complete the ASC 740 accounting. For these items, the current and deferred taxes were
recognized and measured based on the provisions of the tax laws that were in effect immediately prior to
the TCJA being enacted. These certain items include but are not limited to the computation of state
income taxes as there is uncertainty on conformity to the federal tax system following the TCJA, global
intangible low taxed income, and base erosion and anti-abuse tax. The determination of the impact of the
income tax effects of these items will require additional analysis of historical records and further
interpretation of the TCJA from yet to be issued United States Treasury regulations which will require
more time, information and resources than currently available to us.
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 for tax positions of prior year
Change in translation of foreign currency
Lapses of statute of limitations
Settlements
Unrecognized tax benefits at end of year
2017
2016
84
15
65
(2)
(8)
(4)
150
65
27
—
(2)
(6)
—
84
The unrecognized tax benefits as at December 31, 2017, if recognized, would impact our effective income
tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12
months that would have a material impact on our consolidated financial statements.
We recognize accrued interest and penalties related to unrecognized tax benefits as a component of
income taxes. Income taxes for the years ended December 31, 2017 and 2016 included $3 million and $1
million recoveries, respectively, of interest and penalties. As at December 31, 2017 and 2016, interest and
penalties of $8 million and $6 million, respectively, have been accrued.
25. PENSION AND OTHER POSTRETIREMENT BENEFITS
PENSION PLANS
We maintain registered and non-registered, contributory and non-contributory pension plans which
provide defined benefit and/or defined contribution pension benefits covering substantially all employees.
The Canadian Plans provide Company funded defined benefit and/or defined contribution pension
benefits to our Canadian employees. The United States Plans provide Company funded defined benefit
pension benefits to our United States employees. We also maintain supplemental pension plans that
provide pension benefits in excess of the basic plans for certain employees.
Defined Benefit Plans
Benefits payable from the defined benefit plans are based on each plan participant’s years of service and
final average remuneration. These benefits are partially inflation-indexed after a plan participant’s
retirement. Our contributions are made in accordance with independent actuarial valuations and are
invested primarily in publicly-traded equity and fixed income securities.
Defined Contribution Plans
Contributions are generally based on each plan participant’s age, years of service and current eligible
remuneration. For defined contribution plans, benefit costs equal amounts required to be contributed by
us.
180
181
Benefit Obligation, Plan Assets and Funded Status
The following table details the changes in the projected benefit obligation, the fair value of plan assets
and the recorded asset or liability for our defined benefit pension plans:
Amount Recognized in Accumulated Other Comprehensive Income
The amounts of pre-tax AOCI relating to our pension plans are as follows:
December 31,
(millions of Canadian dollars)
Change in projected benefit obligation
Projected benefit obligation at beginning of year
Service cost
Interest cost
Actuarial loss
Benefits paid
Foreign currency exchange rate changes
Acquired in Merger Transaction
Plan settlements
Other
Projected benefit obligation at end of year1
Change in plan assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Benefits paid
Foreign currency exchange rate changes
Acquired in Merger Transaction
Plan settlements
Other
Fair value of plan assets at end of year2
Underfunded status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities
Canada
2017
2016
United States
2017
2016
2,270
156
116
145
(165)
—
1,505
—
6
4,033
2,019
308
161
(165)
—
1,290
—
6
3,619
(414)
38
(60)
(392)
(414)
2,064
129
73
97
(87)
—
—
—
(6)
2,270
1,886
146
74
(87)
—
—
—
—
2,019
(251)
5
—
(256)
(251)
508
48
35
57
(42)
(63)
811
(59)
(16)
1,279
361
113
57
(42)
(51)
731
(59)
(13)
1,097
(182)
—
(3)
(179)
(182)
487
26
16
15
(21)
(14)
—
—
(1)
508
343
22
28
(21)
(10)
—
—
(1)
361
(147)
—
—
(147)
(147)
1 The accumulated benefit obligation for our Canadian pension plans was $3.7 billion and $978 million as at December 31, 2017
and 2016, respectively. The accumulated benefit obligation for our United States pension plans was $$1.2 billion and $462 million
as at December 31, 2017 and 2016, respectively.
2 Assets in the amount of $9 million (2016 - $8 million) and $40 million (2016 - $44 million), related to our Canadian and United
States non-registered supplemental pension plan obligations, are held in grantor trusts that, in accordance with federal tax
regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included
in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.
Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan
assets. For these plans, the projected benefit obligations, accumulated benefit obligations and the fair
value of plan assets were as follows:
December 31,
(millions of Canadian dollars)
Projected benefit obligations
Accumulated benefit obligations
Fair value of plan assets
Canada
2017
2016
United States
2017
2016
1,444
1,306
1,131
2,188
978
1,927
1,280
1,217
1,098
508
462
361
182
183
The components of net benefit cost and other amounts recognized in pre-tax OCI related to our pension
December 31,
(millions of Canadian dollars)
Net actuarial gain
Total amount recognized in AOCI
Net Benefit Costs Recognized
plans are as follows:
Year ended December 31,
(millions of Canadian dollars)
Service cost
Interest cost
Expected return on plan assets
Amortization of actuarial loss
Net defined benefit costs
Defined contribution benefit costs
Net benefit cost recognized in Earnings
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year
Amortization of net actuarial gain
Total amount recognized in OCI
Total amount recognized in Comprehensive income
Canada
United States
2017
2016
2017
2016
334
334
310
310
112
112
121
121
Canada
United States
2017
2016
2015
2017
2016
2015
156
116
(201)
29
100
11
111
38
(14)
24
135
129
73
(127)
32
107
3
110
28
(14)
14
124
137
81
(120)
39
137
3
140
(58)
(20)
(78)
62
(57)
(21)
(22)
48
35
10
36
15
51
—
(9)
(9)
42
26
16
3
24
—
24
16
(6)
10
34
30
17
10
35
—
35
(19)
(10)
(29)
6
We estimate that approximately $25 million related to the Canadian pension plans and $4 million related
to the United States pension plans as at December 31, 2017 will be reclassified from AOCI into earnings
The weighted average assumptions made in the measurement of the projected benefit obligations and
net benefit cost of our pension plans are as follows:
Canada
United States
2017
2016
2015
2017
2016
2015
3.6%
3.2%
4.0%
6.5%
3.7%
4.0%
3.7%
4.2%
6.5%
3.6%
4.2%
3.6%
4.0%
4.4%
2.5%
3.5%
3.1%
4.0%
7.2%
3.3%
4.0%
3.3%
4.1%
7.2%
3.2%
4.1%
3.3%
3.7%
7.1%
4.0%
in the next 12 months.
Actuarial Assumptions
Projected benefit obligations
Discount rate
Rate of salary increase
Net benefit cost
Discount rate
Rate of return on plan assets
Rate of salary increase
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.
Benefit Obligation, Plan Assets and Funded Status
The following table details the changes in the projected benefit obligation, the fair value of plan assets
and the recorded asset or liability for our defined benefit pension plans:
Projected benefit obligation at end of year1
4,033
2,270
1,279
December 31,
(millions of Canadian dollars)
Change in projected benefit obligation
Projected benefit obligation at beginning of year
Service cost
Interest cost
Actuarial loss
Benefits paid
Plan settlements
Other
Foreign currency exchange rate changes
Acquired in Merger Transaction
Change in plan assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Benefits paid
Foreign currency exchange rate changes
Acquired in Merger Transaction
Plan settlements
Other
Fair value of plan assets at end of year2
Underfunded status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities
Canada
United States
2017
2016
2017
2016
2,270
156
116
145
(165)
1,505
—
—
6
2,019
308
161
(165)
1,290
—
—
6
3,619
(414)
38
(60)
(392)
(414)
2,064
129
73
97
(87)
—
—
—
(6)
1,886
146
74
(87)
—
—
—
—
2,019
(251)
5
—
(256)
(251)
508
48
35
57
(42)
(63)
811
(59)
(16)
361
113
57
(42)
(51)
731
(59)
(13)
1,097
(182)
—
(3)
(179)
(182)
487
26
16
15
(21)
(14)
—
—
(1)
508
343
22
28
(21)
(10)
—
—
(1)
361
(147)
—
—
(147)
(147)
1 The accumulated benefit obligation for our Canadian pension plans was $3.7 billion and $978 million as at December 31, 2017
and 2016, respectively. The accumulated benefit obligation for our United States pension plans was $$1.2 billion and $462 million
as at December 31, 2017 and 2016, respectively.
2 Assets in the amount of $9 million (2016 - $8 million) and $40 million (2016 - $44 million), related to our Canadian and United
States non-registered supplemental pension plan obligations, are held in grantor trusts that, in accordance with federal tax
regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included
in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.
Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan
assets. For these plans, the projected benefit obligations, accumulated benefit obligations and the fair
value of plan assets were as follows:
December 31,
(millions of Canadian dollars)
Projected benefit obligations
Accumulated benefit obligations
Fair value of plan assets
Canada
United States
2017
2016
2017
2016
1,444
1,306
1,131
2,188
978
1,927
1,280
1,217
1,098
508
462
361
Amount Recognized in Accumulated Other Comprehensive Income
The amounts of pre-tax AOCI relating to our pension plans are as follows:
December 31,
(millions of Canadian dollars)
Net actuarial gain
Total amount recognized in AOCI
Canada
2017
2016
United States
2017
2016
334
334
310
310
112
112
121
121
Net Benefit Costs Recognized
The components of net benefit cost and other amounts recognized in pre-tax OCI related to our pension
plans are as follows:
Year ended December 31,
(millions of Canadian dollars)
Service cost
Interest cost
Expected return on plan assets
Amortization of actuarial loss
Net defined benefit costs
Defined contribution benefit costs
Net benefit cost recognized in Earnings
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year
Amortization of net actuarial gain
Total amount recognized in OCI
Total amount recognized in Comprehensive income
Canada
2016
2017
United States
2015
2017
2016
2015
156
116
(201)
29
100
11
111
38
(14)
24
135
129
73
(127)
32
107
3
110
28
(14)
14
124
137
81
(120)
39
137
3
140
(58)
(20)
(78)
62
48
35
(57)
10
36
15
51
—
(9)
(9)
42
26
16
(21)
3
24
—
24
16
(6)
10
34
30
17
(22)
10
35
—
35
(19)
(10)
(29)
6
We estimate that approximately $25 million related to the Canadian pension plans and $4 million related
to the United States pension plans as at December 31, 2017 will be reclassified from AOCI into earnings
in the next 12 months.
Actuarial Assumptions
The weighted average assumptions made in the measurement of the projected benefit obligations and
net benefit cost of our pension plans are as follows:
Projected benefit obligations
Discount rate
Rate of salary increase
Net benefit cost
Discount rate
Rate of return on plan assets
Rate of salary increase
Canada
2016
2017
United States
2015
2017
2016
2015
3.6%
3.2%
4.0%
6.5%
3.7%
4.0%
3.7%
4.2%
6.5%
3.6%
4.2%
3.6%
4.0%
4.4%
2.5%
3.5%
3.1%
4.0%
7.2%
3.3%
4.0%
3.3%
4.1%
7.2%
3.2%
4.1%
3.3%
3.7%
7.1%
4.0%
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.
182
183
OTHER POSTRETIREMENT BENEFITS
OPEB primarily includes supplemental health and dental, health spending accounts and life insurance
coverage for qualifying retired employees on a non-contributory basis.
The following table details the changes in the accumulated postretirement benefit obligation, the fair value
of plan assets and the recorded asset or liability for our OPEB plans:
December 31,
(millions of Canadian dollars)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation at beginning of year
Service cost
Interest cost
Participant contributions
Actuarial (gain)/loss
Benefits paid
Foreign currency exchange rate changes
Acquired in Merger Transaction
Other
Accumulated postretirement 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 contributions
Participant contributions
Benefits paid
Foreign currency exchange rate changes
Acquired in Merger Transaction
Fair value of plan assets at end of year
Underfunded status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities
Canada
2017
2016
United States
2017
2016
179
7
10
—
(8)
(10)
—
146
(3)
321
—
—
10
—
(10)
—
—
—
(321)
—
(12)
(309)
(321)
173
4
6
—
2
(6)
—
—
—
179
—
—
6
—
(6)
—
—
—
(179)
—
(7)
(172)
(179)
133
5
10
4
(34)
(19)
(17)
254
1
337
115
21
1
4
(19)
(11)
102
213
(124)
7
(7)
(124)
(124)
135
4
5
1
10
(6)
(4)
—
(12)
133
115
5
3
1
(6)
(3)
—
115
(18)
4
—
(22)
(18)
Amount Recognized in Accumulated Other Comprehensive Income
The amounts of pre-tax AOCI relating to our OPEB plans are as follows:
December 31,
(millions of Canadian dollars)
Net actuarial gain/(loss)
Prior service cost
Total amount recognized in AOCI
Canada
2017
2016
United States
2017
2016
17
(2)
15
25
2
27
(15)
(11)
(26)
29
(15)
14
Net Benefit Costs Recognized
The components of net benefit cost and other amounts recognized in pre-tax OCI related to our OPEB
plans are as follows:
Year ended December 31,
(millions of Canadian dollars)
Service cost
Interest cost
Expected return on plan assets
Amortization of actuarial loss and prior service cost
Net OPEB cost recognized in Earnings
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year
Amortization of net actuarial (gain)/loss
Prior service cost
Total amount recognized in OCI
Total amount recognized in Comprehensive income
next 12 months.
Actuarial Assumptions
Canada
United States
2017
2016
2015
2017
2016
2015
7
10
—
1
18
(8)
(1)
(3)
(12)
6
4
6
—
—
10
2
(1)
—
1
11
3
7
—
1
11
2
(1)
—
1
12
(10)
5
10
—
5
(42)
1
1
(40)
(35)
4
5
(6)
—
3
12
(1)
(12)
(1)
2
5
4
(6)
—
3
16
—
(7)
9
12
We estimate that approximately nil related to the Canadian OPEB plans and $2 million related to the
United States OPEB plans as at December 31, 2017 will be reclassified from AOCI into earnings in the
The weighted average assumptions made in the measurement of the accumulated postretirement benefit
obligations and net benefit cost of our OPEB plans are as follows:
Accumulated postretirement benefit
obligations
Discount rate
Net OPEB cost
Discount rate
Rate of return on plan assets
Canada
United States
2017
2016
2015
2017
2016
2015
3.6%
4.0%
4.2%
3.5%
3.6%
4.2%
4.0%
4.2%
4.0%
4.0%
6.0%
3.8%
6.0%
3.9%
6.0%
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.
Assumed Health Care Cost Trend Rates
The assumed rates for the next year used to measure the expected cost of benefits are as follows:
Health care cost trend rate assumed for next year
Rate to which the cost trend is assumed to decline (the
ultimate trend rate)
Year that the rate reaches the ultimate trend rate
Canada
United States
2017
5.5%
4.4%
2034
2016
5.4%
4.5%
2034
2017
7.4%
4.5%
2037
2016
6.9%
4.5%
2037
184
185
OTHER POSTRETIREMENT BENEFITS
OPEB primarily includes supplemental health and dental, health spending accounts and life insurance
coverage for qualifying retired employees on a non-contributory basis.
Net Benefit Costs Recognized
The components of net benefit cost and other amounts recognized in pre-tax OCI related to our OPEB
plans are as follows:
The following table details the changes in the accumulated postretirement benefit obligation, the fair value
of plan assets and the recorded asset or liability for our OPEB plans:
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation at beginning of year
173
December 31,
(millions of Canadian dollars)
Service cost
Interest cost
Participant contributions
Actuarial (gain)/loss
Benefits paid
Foreign currency exchange rate changes
Acquired in Merger Transaction
Other
Change in plan assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Participant contributions
Benefits paid
Foreign currency exchange rate changes
Acquired in Merger Transaction
Fair value of plan assets at end of year
Underfunded status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities
Canada
United States
2017
2016
2017
2016
179
7
10
—
(8)
(10)
—
146
(3)
321
—
—
10
—
—
—
—
(10)
4
6
—
2
(6)
—
—
—
—
—
6
—
—
—
—
(6)
(321)
(179)
—
(12)
(309)
(321)
—
(7)
(172)
(179)
133
5
10
4
(34)
(19)
(17)
254
1
337
115
21
1
4
(19)
(11)
102
213
(124)
7
(7)
(124)
(124)
135
4
5
1
10
(6)
(4)
—
(12)
133
115
5
3
1
(6)
(3)
—
115
(18)
4
—
(22)
(18)
Accumulated postretirement benefit obligation at end of year
179
Amount Recognized in Accumulated Other Comprehensive Income
The amounts of pre-tax AOCI relating to our OPEB plans are as follows:
December 31,
(millions of Canadian dollars)
Net actuarial gain/(loss)
Prior service cost
Total amount recognized in AOCI
Canada
United States
2017
2016
2017
2016
17
(2)
15
25
2
27
(15)
(11)
(26)
29
(15)
14
Year ended December 31,
(millions of Canadian dollars)
Service cost
Interest cost
Expected return on plan assets
Amortization of actuarial loss and prior service cost
Net OPEB cost recognized in Earnings
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year
Amortization of net actuarial (gain)/loss
Prior service cost
Total amount recognized in OCI
Total amount recognized in Comprehensive income
Canada
2017
2016
2015
United States
2016
2017
2015
7
10
—
1
18
(8)
(1)
(3)
(12)
6
4
6
—
—
10
2
(1)
—
1
11
3
7
—
1
11
2
(1)
—
1
12
5
10
(10)
—
5
(42)
1
1
(40)
(35)
4
5
(6)
—
3
12
(1)
(12)
(1)
2
5
4
(6)
—
3
16
—
(7)
9
12
We estimate that approximately nil related to the Canadian OPEB plans and $2 million related to the
United States OPEB plans as at December 31, 2017 will be reclassified from AOCI into earnings in the
next 12 months.
Actuarial Assumptions
The weighted average assumptions made in the measurement of the accumulated postretirement benefit
obligations and net benefit cost of our OPEB plans are as follows:
Accumulated postretirement benefit
obligations
Discount rate
Net OPEB cost
Discount rate
Rate of return on plan assets
Canada
2016
2017
United States
2015
2017
2016
2015
3.6%
4.0%
4.2%
3.5%
3.6%
4.2%
4.0%
4.2%
4.0%
4.0%
6.0%
3.8%
6.0%
3.9%
6.0%
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.
Assumed Health Care Cost Trend Rates
The assumed rates for the next year used to measure the expected cost of benefits are as follows:
Health care cost trend rate assumed for next year
Rate to which the cost trend is assumed to decline (the
ultimate trend rate)
Year that the rate reaches the ultimate trend rate
Canada
2017
5.5%
4.4%
2034
2016
5.4%
4.5%
2034
United States
2017
7.4%
2016
6.9%
4.5%
2037
4.5%
2037
184
185
A 1% change in the assumed health care cost trend rate would have the following effects for the year
ended and as at December 31, 2017:
The following tables summarize the fair value of plan assets for our pension and OPEB plans recorded at
(millions of Canadian dollars)
Effect on total service and interest costs
Effect on accumulated postretirement benefit obligation
Canada
1%
Increase
1%
Decrease
United States
1%
Increase
1%
Decrease
2
28
(1)
(23)
1
20
(1)
(17)
PLAN ASSETS
We manage the investment risk of our 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) our
operating environment and financial situation and our 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 asset allocation targets and major categories of plan assets are as follows:
Asset Category
Equity securities
Fixed income securities
Other
Target
Allocation
40.0 - 70.0%
27.5 - 60.0%
0.0 - 20.0%
2017
52.0%
34.2%
13.8%
Target
Allocation
2016
47.0% 52.5 - 70.0%
39.0% 27.5 - 30.0%
14.0% 0.0 - 20.0%
December 31,
2017
47.1%
47.7%
5.2%
2016
55.4%
33.0%
11.6%
Canada
December 31,
United States
each fair value hierarchy level.
Pension
(millions of Canadian dollars)
December 31, 2017
Cash and cash equivalents
Equity securities
Canada
United States
Global
Fixed income securities
Government
Corporate
Infrastructure and real estate4
Forward currency contracts
Total pension plan assets at fair
value
December 31, 2016
Cash and cash equivalents
Equity securities
United States
Canada
Global
Fixed income securities
Government
Corporate
Infrastructure and real estate4
Forward currency contracts
Total pension plan assets at fair
value
OPEB
(millions of Canadian dollars)
December 31, 2017
Cash and cash equivalents
Equity securities
United States
Global
Fixed income securities
Government
Total OPEB plan assets at fair
value
December 31, 2016
Cash and cash equivalents
Equity securities
United States
Global
Fixed income securities
Government
Total OPEB plan assets at fair
value
2,861
169
842
427
189
933
301
—
—
156
219
425
165
351
277
—
—
—
—
—
—
—
—
—
—
—
—
Level 11
Level 22
Level 33
Total
Level 11
Level 22
Level 33
Total
Canada
United States
425
(10)
418
140
—
—
—
—
3
—
—
—
—
—
3
—
2
—
—
—
—
—
—
—
—
—
—
340
—
340
—
—
—
—
—
—
—
—
—
—
—
—
281
—
281
—
—
—
—
—
—
—
—
—
—
169
1,267
427
189
933
304
340
(10)
3,619
156
219
425
305
351
280
281
2
—
—
—
—
—
—
—
—
—
—
2
—
343
122
—
522
—
—
989
3
54
—
116
—
116
—
—
289
213
1
80
36
96
1
35
34
45
115
—
—
—
52
—
1
—
(1)
52
—
—
—
30
—
—
—
2
32
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
56
—
56
—
—
—
—
—
—
40
—
40
—
—
—
—
—
—
—
—
—
—
1,097
2
—
343
174
—
523
56
(1)
3
54
—
146
—
116
40
2
361
213
1
80
36
96
1
35
34
45
115
1,593
145
2,019
Level 11
Level 22
Level 33
Total
Level 11
Level 22
Level 33
Total
Canada
United States
1 Level 1 assets include assets with quoted prices in active markets for identical assets.
2 Level 2 assets include assets with significant observable inputs.
3 Level 3 assets include assets with significant unobservable inputs.
4 The fair values of the infrastructure and real estate investments are established through the use of valuation models.
186
187
A 1% change in the assumed health care cost trend rate would have the following effects for the year
ended and as at December 31, 2017:
The following tables summarize the fair value of plan assets for our pension and OPEB plans recorded at
each fair value hierarchy level.
(millions of Canadian dollars)
Effect on total service and interest costs
Effect on accumulated postretirement benefit obligation
Canada
1%
1%
United States
1%
1%
Increase
Decrease
Increase
Decrease
2
28
(1)
(23)
1
20
(1)
(17)
PLAN ASSETS
We manage the investment risk of our 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) our
operating environment and financial situation and our 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 asset allocation targets and major categories of plan assets are as follows:
Asset Category
Equity securities
Fixed income securities
Other
Canada
United States
Target
Allocation
40.0 - 70.0%
27.5 - 60.0%
0.0 - 20.0%
December 31,
Target
December 31,
2017
52.0%
34.2%
13.8%
2016
Allocation
47.0% 52.5 - 70.0%
39.0% 27.5 - 30.0%
14.0% 0.0 - 20.0%
2017
47.1%
47.7%
5.2%
2016
55.4%
33.0%
11.6%
Pension
(millions of Canadian dollars)
December 31, 2017
Cash and cash equivalents
Equity securities
Canada
United States
Global
Fixed income securities
Government
Corporate
Infrastructure and real estate4
Forward currency contracts
Total pension plan assets at fair
value
December 31, 2016
Cash and cash equivalents
Equity securities
United States
Canada
Global
Fixed income securities
Government
Corporate
Infrastructure and real estate4
Forward currency contracts
Total pension plan assets at fair
value
OPEB
(millions of Canadian dollars)
December 31, 2017
Cash and cash equivalents
Equity securities
United States
Global
Fixed income securities
Government
Total OPEB plan assets at fair
value
December 31, 2016
Cash and cash equivalents
Equity securities
United States
Global
Fixed income securities
Government
Total OPEB plan assets at fair
value
Level 11
Level 22
Level 33
Total
Level 11
Level 22
Level 33
Total
Canada
United States
169
842
427
189
933
301
—
—
2,861
156
219
425
165
351
277
—
—
—
425
—
—
—
3
—
(10)
418
—
—
—
140
—
3
—
2
1,593
145
—
—
—
—
—
—
340
—
340
—
—
—
—
—
—
281
—
281
169
1,267
427
189
933
304
340
(10)
3,619
156
219
425
305
351
280
281
2
2,019
2
—
343
122
—
522
—
—
989
3
54
—
116
—
116
—
—
289
—
—
—
52
—
1
—
(1)
52
—
—
—
30
—
—
—
2
32
—
—
—
—
—
—
56
—
56
—
—
—
—
—
—
40
—
40
2
—
343
174
—
523
56
(1)
1,097
3
54
—
146
—
116
40
2
361
Level 11
Level 22
Level 33
Total
Level 11
Level 22
Level 33
Total
Canada
United States
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
80
36
96
213
1
35
34
45
115
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
80
36
96
213
1
35
34
45
115
1 Level 1 assets include assets with quoted prices in active markets for identical assets.
2 Level 2 assets include assets with significant observable inputs.
3 Level 3 assets include assets with significant unobservable inputs.
4 The fair values of the infrastructure and real estate investments are established through the use of valuation models.
186
187
Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were as
follows:
27. RELATED PARTY TRANSACTIONS
December 31,
(millions of Canadian dollars)
Balance at beginning of year
Unrealized and realized gains
Purchases and settlements, net
Balance at end of year
Canada
2017
2016
United States
2017
2016
281
26
33
340
248
20
13
281
40
5
11
56
49
2
(11)
40
EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS
Year ended December 31,
(millions of Canadian dollars)
Pension
Canada
United States
OPEB
Canada
United States
2018
2019
2020
2021
2022
2023-2027
TRANSPORTATION AGREEMENTS
158
82
12
25
165
81
12
25
172
85
13
25
180
83
13
25
187
92
14
24
1,036
453
43
110
In 2018, we expect to contribute approximately $126 million and $36 million to the Canadian and United
States pension plans, respectively, and $12 million and $7 million to the Canadian and United States
OPEB plans, respectively.
RETIREMENT SAVINGS PLANS
In addition to the retirement plans discussed above, we also have defined contribution employee savings
plans available to both Canadian and United States employees. Employees may participate in a matching
contribution where we match a certain percentage of before-tax employee contributions of up to 5.0% of
eligible pay per pay period for Canadian employees and up to 6.0% of eligible pay per pay period for
United States employees. For the years ended December 31, 2017, 2016 and 2015, we expensed pre-tax
employer matching contributions of $14 million, nil and nil for Canadian employees and $31 million, $13
million and $15 million for United States employees, respectively.
26. CHANGES IN OPERATING ASSETS AND LIABILITIES
Year ended December 31,
(millions of Canadian dollars)
Restricted Cash
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
2017
2016
2015
15
(783)
24
(289)
(138)
286
(62)
124
509
(314)
—
(437)
(7)
(371)
(183)
396
71
20
153
(358)
—
698
82
(315)
364
(1,472)
(26)
31
(7)
(645)
Related party transactions are conducted 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.
SERVICE AGREEMENTS
Vector Pipeline L.P. (Vector), a joint venture, contracts our services to operate the pipeline. Amounts for
these services, which are charged at cost in accordance with service agreements, were $14 million for
the year ended December 31, 2017 and $7 million for each of the years ended December 31, 2016 and
2015.
Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Transmission and Midstream, Gas
Distribution and Energy Services segments have committed and uncommitted transportation
arrangements with several joint venture affiliates that are accounted for using the equity method. Total
amounts charged to us for transportation services for the years ended December 31, 2017, 2016 and
2015 were $417 million, $357 million and $332 million, respectively.
LEASE AGREEMENTS
A wholly-owned subsidiary within the Liquids Pipelines segment has a lease arrangement with a joint
venture affiliate. During the years ended December 31, 2017, 2016 and 2015, expenses related to the
lease arrangement totaled $304 million, $287 million and $151 million, respectively, and were recorded to
Operating and administrative expense in the Consolidated Statements of Earnings.
AFFILIATE REVENUES AND PURCHASES
Certain wholly-owned subsidiaries within the Gas Distribution and Energy Services segments made
natural gas and NGL purchases of $142 million, $98 million and $228 million from several joint venture
affiliates during the years ended December 31, 2017, 2016 and 2015, respectively.
Natural gas sales of $60 million, $49 million and $5 million were made by certain wholly-owned
subsidiaries within the Energy Services segment to several joint venture affiliates during the years ended
December 31, 2017, 2016 and 2015, respectively.
DCP Midstream processes certain of our pipeline customers' gas to meet gas quality specifications in
order to be transported on our system. DCP Midstream processes the gas and sells the NGLs that are
extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and
the balance is remitted to us. We received proceeds of $47 million (US$36 million) during the year ended
December 31, 2017 from DCP Midstream related to those sales.
In addition to the above, we recorded other revenues from DCP Midstream and its affiliates related to the
transportation and storage of natural gas of $4 million (US$3 million) during the year ended December 31,
2017.
In the ordinary course of business, we are reimbursed by joint venture partners for operating and
maintenance expenses for certain projects. We received reimbursements from Spectra Energy joint
ventures of $10 million (US$8 million) during the year ended December 31, 2017.
RECOVERIES OF COSTS
We provide certain administrative and other services to certain operating entities acquired through the
Merger Transaction, and recorded recoveries of costs from these affiliates of $88 million (US$68 million)
for the year ended December 31, 2017. Cost recoveries are recorded as a reduction to Operating and
administrative expense in the Consolidated Statements of Earnings.
188
189
EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS
2018
2019
2020
2021
2022
2023-2027
Canada
United States
2017
2016
2017
2016
281
26
33
340
172
85
13
25
248
20
13
281
180
83
13
25
40
5
11
56
49
2
(11)
40
187
92
14
24
1,036
453
43
110
158
82
12
25
165
81
12
25
In 2018, we expect to contribute approximately $126 million and $36 million to the Canadian and United
States pension plans, respectively, and $12 million and $7 million to the Canadian and United States
In addition to the retirement plans discussed above, we also have defined contribution employee savings
plans available to both Canadian and United States employees. Employees may participate in a matching
contribution where we match a certain percentage of before-tax employee contributions of up to 5.0% of
eligible pay per pay period for Canadian employees and up to 6.0% of eligible pay per pay period for
United States employees. For the years ended December 31, 2017, 2016 and 2015, we expensed pre-tax
employer matching contributions of $14 million, nil and nil for Canadian employees and $31 million, $13
million and $15 million for United States employees, respectively.
26. CHANGES IN OPERATING ASSETS AND LIABILITIES
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
Year ended December 31,
(millions of Canadian dollars)
Pension
Canada
OPEB
Canada
United States
United States
OPEB plans, respectively.
RETIREMENT SAVINGS PLANS
Year ended December 31,
(millions of Canadian dollars)
Restricted Cash
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
2017
2016
2015
(783)
15
24
(289)
(138)
286
(62)
124
509
(314)
—
(437)
(7)
(371)
(183)
396
71
20
153
(358)
—
698
82
(315)
364
(1,472)
(26)
31
(7)
(645)
Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were as
27. RELATED PARTY TRANSACTIONS
Related party transactions are conducted 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.
SERVICE AGREEMENTS
Vector Pipeline L.P. (Vector), a joint venture, contracts our services to operate the pipeline. Amounts for
these services, which are charged at cost in accordance with service agreements, were $14 million for
the year ended December 31, 2017 and $7 million for each of the years ended December 31, 2016 and
2015.
TRANSPORTATION AGREEMENTS
Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Transmission and Midstream, Gas
Distribution and Energy Services segments have committed and uncommitted transportation
arrangements with several joint venture affiliates that are accounted for using the equity method. Total
amounts charged to us for transportation services for the years ended December 31, 2017, 2016 and
2015 were $417 million, $357 million and $332 million, respectively.
LEASE AGREEMENTS
A wholly-owned subsidiary within the Liquids Pipelines segment has a lease arrangement with a joint
venture affiliate. During the years ended December 31, 2017, 2016 and 2015, expenses related to the
lease arrangement totaled $304 million, $287 million and $151 million, respectively, and were recorded to
Operating and administrative expense in the Consolidated Statements of Earnings.
AFFILIATE REVENUES AND PURCHASES
Certain wholly-owned subsidiaries within the Gas Distribution and Energy Services segments made
natural gas and NGL purchases of $142 million, $98 million and $228 million from several joint venture
affiliates during the years ended December 31, 2017, 2016 and 2015, respectively.
Natural gas sales of $60 million, $49 million and $5 million were made by certain wholly-owned
subsidiaries within the Energy Services segment to several joint venture affiliates during the years ended
December 31, 2017, 2016 and 2015, respectively.
DCP Midstream processes certain of our pipeline customers' gas to meet gas quality specifications in
order to be transported on our system. DCP Midstream processes the gas and sells the NGLs that are
extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and
the balance is remitted to us. We received proceeds of $47 million (US$36 million) during the year ended
December 31, 2017 from DCP Midstream related to those sales.
In addition to the above, we recorded other revenues from DCP Midstream and its affiliates related to the
transportation and storage of natural gas of $4 million (US$3 million) during the year ended December 31,
2017.
In the ordinary course of business, we are reimbursed by joint venture partners for operating and
maintenance expenses for certain projects. We received reimbursements from Spectra Energy joint
ventures of $10 million (US$8 million) during the year ended December 31, 2017.
RECOVERIES OF COSTS
We provide certain administrative and other services to certain operating entities acquired through the
Merger Transaction, and recorded recoveries of costs from these affiliates of $88 million (US$68 million)
for the year ended December 31, 2017. Cost recoveries are recorded as a reduction to Operating and
administrative expense in the Consolidated Statements of Earnings.
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189
LONG-TERM NOTES RECEIVABLE FROM AFFILIATES
As at December 31, 2017, amounts receivable from affiliates include a series of loans to Vector and other
affiliates totaling $109 million and $167 million, respectively ($130 million and $140 million, respectively
as at December 31, 2016), which require quarterly interest payments at annual interest rates ranging from
4% to 12%. These amounts are included in Deferred amounts and other assets in the Consolidated
Statements of Financial position.
28. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
At December 31, 2017, we have commitments as detailed below.
Less
than
1 year
Total
2 years
3 years
4 years
5 years Thereafter
62,927
42,083
2,831
2,485
6,273
2,298
6,722
2,117
2,505
1,941
8,839
1,853
35,757
31,389
(millions of Canadian dollars)
Annual debt maturities1,2
Interest obligations2,3
Purchase of services, pipe
and other materials,
including transportation4,5
Operating leases
Capital leases
Maintenance agreements
Land lease commitments
Total
1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes
short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt
facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments
could be materially different than presented above.
4,144
91
9
38
15
9,613
2,455
86
8
32
16
11,168
14,396
746
35
322
405
120,914
1,163
78
2
15
16
11,966
1,496
80
2
17
16
10,450
1,255
74
2
15
16
5,808
3,883
337
12
205
326
71,909
2 Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017 (Note 30).
3 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.
4 Includes capital and operating commitments.
5 Consists primarily of gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments
(Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP).
Total rental expense for operating leases included in Operating and administrative expense were $118 million,
$85 million and $72 million for the years ended December 31, 2017, 2016 and 2015, respectively.
ENVIRONMENTAL
We are subject to various federal, state and local laws relating to the protection of the environment. These
laws and regulations can change from time to time, imposing new obligations on us.
Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge
and our affiliates are, at times, subject to environmental remediation at various contaminated sites. We
manage this environmental risk through appropriate environmental policies and practices to minimize any
impact our operations may have on the environment. To the extent that we are unable to recover payment
for environmental liabilities from insurance or other potentially responsible parties, we will be responsible
for payment of liabilities arising from environmental incidents associated with the operating activities of
our liquids and natural gas businesses.
190
191
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. Further, on September 9, 2010, a release of crude oil from Line 6A of EEP’s
Lakehead System was reported in an industrial area of Romeoville, Illinois.
As at December 31, 2017, EEP’s total cost estimate for the Line 6B crude oil release remains at US$1.2
billion ($195 million after-tax attributable to us) including those costs that were considered probable and
that could be reasonably estimated as at December 31, 2017. As at December 31, 2017, EEP's
remaining estimated liability is approximately US$62 million.
Insurance
EEP is included in the comprehensive insurance program that is maintained by Enbridge for its
subsidiaries and affiliates. As at December 31, 2017, EEP has recorded total insurance recoveries of
US$547 million ($80 million after-tax attributable to us) for the Line 6B crude oil release out of the US
$650 million applicable limit. Of the remaining US$103 million coverage limit, US$85 million was the
subject matter of a lawsuit against one particular insurer. In March 2015, we reached an agreement with
that insurer to submit the US$85 million claim to binding arbitration. On May 2, 2017, the arbitration panel
issued a decision that was not favorable to us. As a result, EEP will not receive any additional insurance
recoveries in connection with the Line 6B crude oil release.
Legal and Regulatory Proceedings
A number of United States governmental agencies and regulators initiated investigations into the Line 6B
crude oil release. As at December 31, 2017, there are no claims pending against Enbridge, EEP or their
affiliates in United States state courts in connection with the Line 6B crude oil release.
We have accrued a provision for future legal costs and probable losses associated with the Line 6B crude
oil release as described above in this note.
Line 6B Fines and Penalties
As at December 31, 2017, EEP’s total estimated costs related to the Line 6B crude oil release include US
$69 million in paid fines and penalties, which includes fines and penalties paid to the United States
Department of Justice (DOJ) as discussed below.
Consent Decree
On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division,
approved the Consent Decree. The Consent Decree is EEP’s signed settlement agreement with the
United States Environmental Protection Agency (EPA) and the DOJ regarding the Lines 6A and 6B crude
oil releases. On June 15, 2017, we made a total payment of US$68 million as required by the Consent
Decree, which reflects US$61 million for the civil penalty for the Line 6B release, US$1 million for the Line
6A release, and US$6 million for past removal costs and interest.
AUX SABLE
Notice of Violation
In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United
States EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program,
and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the
ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believed to
be an exceedance of currently permitted limits for Volatile Organic Material. In April 2015, a second NFOV
from the EPA was received in connection with this potential exceedance. Aux Sable engaged in
discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with
respect to a draft Consent Decree, and those discussions are continuing. The Consent Decree, when
finalized, is not expected to have a material impact.
LONG-TERM NOTES RECEIVABLE FROM AFFILIATES
As at December 31, 2017, amounts receivable from affiliates include a series of loans to Vector and other
affiliates totaling $109 million and $167 million, respectively ($130 million and $140 million, respectively
as at December 31, 2016), which require quarterly interest payments at annual interest rates ranging from
4% to 12%. These amounts are included in Deferred amounts and other assets in the Consolidated
Statements of Financial position.
28. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
At December 31, 2017, we have commitments as detailed below.
(millions of Canadian dollars)
Annual debt maturities1,2
Interest obligations2,3
Purchase of services, pipe
and other materials,
including transportation4,5
Operating leases
Capital leases
Maintenance agreements
Land lease commitments
Less
than
1 year
Total
2 years
3 years
4 years
5 years Thereafter
62,927
42,083
2,831
2,485
6,273
2,298
6,722
2,117
2,505
1,941
8,839
1,853
35,757
31,389
14,396
4,144
2,455
1,496
1,255
1,163
3,883
746
35
322
405
91
9
38
15
86
8
32
16
80
2
17
16
74
2
15
16
78
2
15
16
337
12
205
326
Total
120,914
9,613
11,168
10,450
5,808
11,966
71,909
1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes
short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt
facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments
could be materially different than presented above.
2 Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017 (Note 30).
3 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.
4 Includes capital and operating commitments.
5 Consists primarily of gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments
(Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP).
Total rental expense for operating leases included in Operating and administrative expense were $118 million,
$85 million and $72 million for the years ended December 31, 2017, 2016 and 2015, respectively.
ENVIRONMENTAL
We are subject to various federal, state and local laws relating to the protection of the environment. These
laws and regulations can change from time to time, imposing new obligations on us.
Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge
and our affiliates are, at times, subject to environmental remediation at various contaminated sites. We
manage this environmental risk through appropriate environmental policies and practices to minimize any
impact our operations may have on the environment. To the extent that we are unable to recover payment
for environmental liabilities from insurance or other potentially responsible parties, we will be responsible
for payment of liabilities arising from environmental incidents associated with the operating activities of
our liquids and natural gas businesses.
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. Further, on September 9, 2010, a release of crude oil from Line 6A of EEP’s
Lakehead System was reported in an industrial area of Romeoville, Illinois.
As at December 31, 2017, EEP’s total cost estimate for the Line 6B crude oil release remains at US$1.2
billion ($195 million after-tax attributable to us) including those costs that were considered probable and
that could be reasonably estimated as at December 31, 2017. As at December 31, 2017, EEP's
remaining estimated liability is approximately US$62 million.
Insurance
EEP is included in the comprehensive insurance program that is maintained by Enbridge for its
subsidiaries and affiliates. As at December 31, 2017, EEP has recorded total insurance recoveries of
US$547 million ($80 million after-tax attributable to us) for the Line 6B crude oil release out of the US
$650 million applicable limit. Of the remaining US$103 million coverage limit, US$85 million was the
subject matter of a lawsuit against one particular insurer. In March 2015, we reached an agreement with
that insurer to submit the US$85 million claim to binding arbitration. On May 2, 2017, the arbitration panel
issued a decision that was not favorable to us. As a result, EEP will not receive any additional insurance
recoveries in connection with the Line 6B crude oil release.
Legal and Regulatory Proceedings
A number of United States governmental agencies and regulators initiated investigations into the Line 6B
crude oil release. As at December 31, 2017, there are no claims pending against Enbridge, EEP or their
affiliates in United States state courts in connection with the Line 6B crude oil release.
We have accrued a provision for future legal costs and probable losses associated with the Line 6B crude
oil release as described above in this note.
Line 6B Fines and Penalties
As at December 31, 2017, EEP’s total estimated costs related to the Line 6B crude oil release include US
$69 million in paid fines and penalties, which includes fines and penalties paid to the United States
Department of Justice (DOJ) as discussed below.
Consent Decree
On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division,
approved the Consent Decree. The Consent Decree is EEP’s signed settlement agreement with the
United States Environmental Protection Agency (EPA) and the DOJ regarding the Lines 6A and 6B crude
oil releases. On June 15, 2017, we made a total payment of US$68 million as required by the Consent
Decree, which reflects US$61 million for the civil penalty for the Line 6B release, US$1 million for the Line
6A release, and US$6 million for past removal costs and interest.
AUX SABLE
Notice of Violation
In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United
States EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program,
and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the
ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believed to
be an exceedance of currently permitted limits for Volatile Organic Material. In April 2015, a second NFOV
from the EPA was received in connection with this potential exceedance. Aux Sable engaged in
discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with
respect to a draft Consent Decree, and those discussions are continuing. The Consent Decree, when
finalized, is not expected to have a material impact.
190
191
On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply
agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While
the final outcome of this action cannot be predicted with certainty, at this time management believes that
the ultimate resolution of this action will not have a material impact on the our consolidated financial
position or results of operations.
TAX MATTERS
We maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax
positions, if challenged by tax authorities, may not be fully sustained on review.
OTHER LITIGATION
We 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 our consolidated financial position or results of
operations.
29. GUARANTEES
In the normal course of conducting business, we enter into agreements which indemnify third parties and
affiliates. 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, and litigation and contingent
liabilities. We may indemnify the purchaser for certain tax liabilities incurred while we owned the assets or
for a misrepresentation related to taxes that result in a loss to the purchaser. Similarly, we may indemnify
the purchaser of assets for certain tax liabilities related to those assets.
As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt
guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate commercial
transactions with third parties by enhancing the value of the transactions to the third parties. To varying
degrees, these guarantees involve elements of performance and credit risk, which are not included on our
Consolidated Statements of Financial Position. The possibility of having to perform under these
guarantees and indemnifications is largely dependent upon future operations of various subsidiaries,
investees and other third parties, or the occurrence of certain future events.
We cannot reasonably estimate the maximum potential amounts that could become payable to third
parties and affiliates under these agreements; however, historically, we have 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 our financial condition, changes in financial condition,
earnings, liquidity, capital expenditures or capital resources.
We have agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating
to environmental matters, arising from operations prior to the transfer of our 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.
We have also agreed to indemnify EEM for any tax liability related to EEM’s formation, management of
EEP and ownership of i-units of EEP. We have not made any significant payment under these tax
indemnifications. We do not believe there is a material exposure at this time.
We have agreed to indemnify the Fund Group for certain liabilities relating to environmental matters
arising from operations prior to the transfer of certain assets and interests to the Fund Group in 2012 and
prior to the transfer of certain assets and interests to the Fund Group as part of the Canadian
Restructuring Plan. We have also agreed to pay defined payments to the Fund Group on their investment
in Southern Lights Pipeline in the event shippers do not elect to extend their current contracts post
June 2025.
In connection with Spectra Energy's spin-off from Duke Energy in 2007, certain guarantees that were
previously issued by Spectra Energy were assigned to, or replaced by, Duke Energy as guarantor in
2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified
Spectra Energy against any losses incurred under these guarantee arrangements. The maximum
potential amount of future payments we could have been required to make under these performance
guarantees as at December 31, 2017 was approximately US$406 million, which has been indemnified by
Duke Energy as discussed above. One of these outstanding performance guarantees, which has a
maximum potential future payment of US$201 million, expires in 2028. The remaining guarantees have
no contractual expirations.
Spectra Energy has also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD)
project owners, guaranteeing the performance of D/FD under its engineering, procurement and
construction contracts and other contractual commitments in place at the time of Spectra Energy's spin-
off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with Spectra
Energy's spin-off. Substantially all of these guarantees have no contractual expiration and no stated
maximum amount of future payments that we could be required to make. Fluor Enterprises Inc.,
as 50% owner in D/FD, issued similar joint and several guarantees to the same D/FD project owners.
In connection with Spectra Energy's 50% ownership in DCP Midstream, Spectra Energy has agreed to
guarantee their portion of the obligations of the joint venture under a US$424 million term loan agreement
of which US$350 million is outstanding as at December 31, 2017. If DCP Midstream fails to meet its
obligations under the credit agreement, Spectra Energy's maximum potential total future payments to
lenders under the guarantee based on the amounts outstanding as at December 31, 2017 would be US
$175 million. The guarantee will terminate upon the payment of all obligations under the credit agreement,
which expires in December 2019.
SEP has issued performance guarantees to a third party and an affiliate on behalf of an equity method
investee. These guarantees were issued to enable the equity method investee to enter into long-term
transportation contracts with the third party. While the likelihood is remote, the maximum potential amount
of future payments that could be required to be made as at December 31, 2017 is US$90 million. These
performance guarantees expire in 2032.
Westcoast Energy Inc., a 100%-owned subsidiary, has issued performance guarantees to third parties
guaranteeing the performance of unconsolidated entities, such as equity method investees, and of
entities previously sold by Westcoast Energy Inc. to third parties. Those guarantees require Westcoast
Energy Inc. to make payment to the guaranteed third party upon the failure of such unconsolidated or
sold entity to make payment under some of its contractual obligations, such as debt agreements,
purchase contracts and leases.
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193
On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply
agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While
the final outcome of this action cannot be predicted with certainty, at this time management believes that
the ultimate resolution of this action will not have a material impact on the our consolidated financial
position or results of operations.
TAX MATTERS
We maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax
positions, if challenged by tax authorities, may not be fully sustained on review.
OTHER LITIGATION
We 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 our consolidated financial position or results of
operations.
29. GUARANTEES
In the normal course of conducting business, we enter into agreements which indemnify third parties and
affiliates. 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, and litigation and contingent
liabilities. We may indemnify the purchaser for certain tax liabilities incurred while we owned the assets or
for a misrepresentation related to taxes that result in a loss to the purchaser. Similarly, we may indemnify
the purchaser of assets for certain tax liabilities related to those assets.
As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt
guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate commercial
transactions with third parties by enhancing the value of the transactions to the third parties. To varying
degrees, these guarantees involve elements of performance and credit risk, which are not included on our
Consolidated Statements of Financial Position. The possibility of having to perform under these
guarantees and indemnifications is largely dependent upon future operations of various subsidiaries,
investees and other third parties, or the occurrence of certain future events.
We cannot reasonably estimate the maximum potential amounts that could become payable to third
parties and affiliates under these agreements; however, historically, we have 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 our financial condition, changes in financial condition,
earnings, liquidity, capital expenditures or capital resources.
We have agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating
to environmental matters, arising from operations prior to the transfer of our 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.
We have also agreed to indemnify EEM for any tax liability related to EEM’s formation, management of
EEP and ownership of i-units of EEP. We have not made any significant payment under these tax
indemnifications. We do not believe there is a material exposure at this time.
We have agreed to indemnify the Fund Group for certain liabilities relating to environmental matters
arising from operations prior to the transfer of certain assets and interests to the Fund Group in 2012 and
prior to the transfer of certain assets and interests to the Fund Group as part of the Canadian
Restructuring Plan. We have also agreed to pay defined payments to the Fund Group on their investment
in Southern Lights Pipeline in the event shippers do not elect to extend their current contracts post
June 2025.
In connection with Spectra Energy's spin-off from Duke Energy in 2007, certain guarantees that were
previously issued by Spectra Energy were assigned to, or replaced by, Duke Energy as guarantor in
2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified
Spectra Energy against any losses incurred under these guarantee arrangements. The maximum
potential amount of future payments we could have been required to make under these performance
guarantees as at December 31, 2017 was approximately US$406 million, which has been indemnified by
Duke Energy as discussed above. One of these outstanding performance guarantees, which has a
maximum potential future payment of US$201 million, expires in 2028. The remaining guarantees have
no contractual expirations.
Spectra Energy has also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD)
project owners, guaranteeing the performance of D/FD under its engineering, procurement and
construction contracts and other contractual commitments in place at the time of Spectra Energy's spin-
off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with Spectra
Energy's spin-off. Substantially all of these guarantees have no contractual expiration and no stated
maximum amount of future payments that we could be required to make. Fluor Enterprises Inc.,
as 50% owner in D/FD, issued similar joint and several guarantees to the same D/FD project owners.
In connection with Spectra Energy's 50% ownership in DCP Midstream, Spectra Energy has agreed to
guarantee their portion of the obligations of the joint venture under a US$424 million term loan agreement
of which US$350 million is outstanding as at December 31, 2017. If DCP Midstream fails to meet its
obligations under the credit agreement, Spectra Energy's maximum potential total future payments to
lenders under the guarantee based on the amounts outstanding as at December 31, 2017 would be US
$175 million. The guarantee will terminate upon the payment of all obligations under the credit agreement,
which expires in December 2019.
SEP has issued performance guarantees to a third party and an affiliate on behalf of an equity method
investee. These guarantees were issued to enable the equity method investee to enter into long-term
transportation contracts with the third party. While the likelihood is remote, the maximum potential amount
of future payments that could be required to be made as at December 31, 2017 is US$90 million. These
performance guarantees expire in 2032.
Westcoast Energy Inc., a 100%-owned subsidiary, has issued performance guarantees to third parties
guaranteeing the performance of unconsolidated entities, such as equity method investees, and of
entities previously sold by Westcoast Energy Inc. to third parties. Those guarantees require Westcoast
Energy Inc. to make payment to the guaranteed third party upon the failure of such unconsolidated or
sold entity to make payment under some of its contractual obligations, such as debt agreements,
purchase contracts and leases.
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30. SUBSEQUENT EVENTS
On January 9, 2018, Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP,
completed an offering of US$800 million of senior notes, which consisted of two US$400 million tranches
with fixed interest rates of 3.50% and 4.15% which mature in 2028 and 2048, respectively.
None.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in
us converting all of our incentive distribution rights (IDRs) and general partner economic interests in SEP
into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs have been
eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403
million of SEP common units, representing approximately 83% of SEP's outstanding common units.
31. QUARTERLY FINANCIAL DATA
(unaudited; millions of Canadian dollars, except per
share amounts)
20171
Operating revenues
Operating income/(loss)
Earnings
Earnings attributable to controlling interests
Earnings attributable to common
shareholders
Earnings per common share
Basic
Diluted
2016
Operating revenues
Operating income/(loss)
Earnings/(loss)
Earnings/(loss) attributable to controlling
interests
Earnings/(loss) attributable to common
shareholders
Earnings/(loss) per common share
Basic
Diluted
Q1
Q2
Q3
Q4
Total
11,146
1,358
945
721
11,116
1,684
1,241
1,000
638
0.54
0.54
8,795
1,674
1,347
1,286
1,213
1.38
1.38
919
0.56
0.56
7,939
794
352
372
301
0.33
0.33
9,227
1,490
1,015
847
765
0.47
0.47
8,488
(216)
(237)
(30)
(103)
(0.11)
(0.11)
12,889
(2,961)
65
291
44,378
1,571
3,266
2,859
207
2,529
0.13
0.12
9,338
329
847
441
365
0.39
0.39
1.66
1.65
34,560
2,581
2,309
2,069
1,776
1.95
1.93
1 The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 7).
ITEM 9A. 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, 2017, an evaluation was carried out under the supervision of and with
the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of
the effectiveness of the design and operations of our disclosure controls and procedures (as defined in
Rule 13a-15(e) and 15d-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
us in reports that we file with or submits to the Securities and Exchange Commission (SEC) and the
Canadian Securities Administrators is recorded, processed, summarized and reported within the time
periods required.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management’s Annual Report on Internal Control over Financial Reporting
Our management 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. Our
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 our financial statements for external reporting purposes in
accordance with U.S. GAAP.
Our 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 our assets;
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 our assets that could have a material effect on the financial
•
•
•
statements.
Our 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 our policies and procedures.
Our management assessed the effectiveness of our internal control over financial reporting as at
December 31, 2017, based on the framework established in Internal Control – Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
this assessment, our management concluded that we maintained effective internal control over financial
reporting as at December 31, 2017.
The effectiveness of our internal control over financial reporting as at December 31, 2017 has been
audited by PricewaterhouseCoopers LLP, independent auditors appointed by our shareholders. As stated
in their attestation report which appears in Item 8. Financial Statements and Supplementary Data, they
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195
30. SUBSEQUENT EVENTS
On January 9, 2018, Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP,
completed an offering of US$800 million of senior notes, which consisted of two US$400 million tranches
with fixed interest rates of 3.50% and 4.15% which mature in 2028 and 2048, respectively.
On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in
us converting all of our incentive distribution rights (IDRs) and general partner economic interests in SEP
into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs have been
eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403
million of SEP common units, representing approximately 83% of SEP's outstanding common units.
31. QUARTERLY FINANCIAL DATA
(unaudited; millions of Canadian dollars, except per
share amounts)
20171
Operating revenues
Operating income/(loss)
Earnings
Earnings attributable to controlling interests
Earnings attributable to common
shareholders
Earnings per common share
Basic
Diluted
2016
Operating revenues
Operating income/(loss)
Earnings/(loss)
Earnings/(loss) attributable to controlling
Earnings/(loss) attributable to common
Earnings/(loss) per common share
interests
shareholders
Basic
Diluted
Q1
Q2
Q3
Q4
Total
11,146
1,358
945
721
638
0.54
0.54
8,795
1,674
1,347
1,286
1,213
1.38
1.38
11,116
1,684
1,241
1,000
7,939
919
0.56
0.56
794
352
372
301
0.33
0.33
9,227
1,490
1,015
847
765
0.47
0.47
8,488
(216)
(237)
(30)
(103)
(0.11)
(0.11)
12,889
(2,961)
9,338
65
291
207
0.13
0.12
329
847
441
365
0.39
0.39
44,378
1,571
3,266
2,859
2,529
1.66
1.65
34,560
2,581
2,309
2,069
1,776
1.95
1.93
1 The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 7).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. 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, 2017, an evaluation was carried out under the supervision of and with
the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of
the effectiveness of the design and operations of our disclosure controls and procedures (as defined in
Rule 13a-15(e) and 15d-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
us in reports that we file with or submits to the Securities and Exchange Commission (SEC) and the
Canadian Securities Administrators is recorded, processed, summarized and reported within the time
periods required.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management’s Annual Report on Internal Control over Financial Reporting
Our management 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. Our
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 our financial statements for external reporting purposes in
accordance with U.S. GAAP.
Our 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 our assets;
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 our assets that could have a material effect on the financial
statements.
Our 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 our policies and procedures.
Our management assessed the effectiveness of our internal control over financial reporting as at
December 31, 2017, based on the framework established in Internal Control – Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
this assessment, our management concluded that we maintained effective internal control over financial
reporting as at December 31, 2017.
The effectiveness of our internal control over financial reporting as at December 31, 2017 has been
audited by PricewaterhouseCoopers LLP, independent auditors appointed by our shareholders. As stated
in their attestation report which appears in Item 8. Financial Statements and Supplementary Data, they
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195
expressed an unqualified opinion on the effectiveness of our internal control over financial reporting as of
December 31, 2017.
Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2017, there has been no material change in our internal
control over financial reporting.
ITEM 9B. OTHER INFORMATION
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules
included in Part II of this annual report are as follows:
Item 5.02. Departure of Directors or Certain Officers; Election of Directors; Appointment of
Certain Officers; Compensatory Arrangements of Certain Officers
Enbridge Inc.:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Earnings
Consolidated Statements of Comprehensive Income
Consolidated Statements of Changes in Equity
Consolidated Statements of Cash Flows
Consolidated Statements of Financial Position
Notes to the Consolidated Financial Statements
All schedules are omitted because they are not required or because the required information is included
in the Consolidated Financial Statements or Notes.
(b) Exhibits:
incorporated into this Item.
Reference is made to the “Index of Exhibits” following Item 16. Form 10-K Summary, which is hereby
On February 13, 2018, Rebecca B. Roberts notified us that she would not stand for re-election as a
director of Enbridge at our 2018 Annual Meeting of Shareholders to be held on May 9, 2018. Ms. Roberts
has served on our Board since March 2015, prior to which she was a director of Enbridge Energy
Company, Inc. and Enbridge Energy Management, L.L.C. Ms. Roberts will continue to serve on our Board
through to the end of her term on May 9, 2018 and her decision not to stand for re-election was based on
the demands on her time from other professional commitments, and not the result of any disagreement
relating to our operations, policies or practices.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Reference to "Executive Officers" is included in Part I. Item 1. Business of this report. Other information in
response to this item, including information on our directors, is incorporated by reference from our Proxy
Statement to be filed with the SEC relating to our 2018 annual meeting of shareholders.
ITEM 11. EXECUTIVE COMPENSATION
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
196
197
expressed an unqualified opinion on the effectiveness of our internal control over financial reporting as of
December 31, 2017.
Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2017, there has been no material change in our internal
control over financial reporting.
ITEM 9B. OTHER INFORMATION
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules
included in Part II of this annual report are as follows:
Item 5.02. Departure of Directors or Certain Officers; Election of Directors; Appointment of
Certain Officers; Compensatory Arrangements of Certain Officers
Enbridge Inc.:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Earnings
Consolidated Statements of Comprehensive Income
Consolidated Statements of Changes in Equity
Consolidated Statements of Cash Flows
Consolidated Statements of Financial Position
Notes to the Consolidated Financial Statements
All schedules are omitted because they are not required or because the required information is included
in the Consolidated Financial Statements or Notes.
(b) Exhibits:
Reference is made to the “Index of Exhibits” following Item 16. Form 10-K Summary, which is hereby
incorporated into this Item.
On February 13, 2018, Rebecca B. Roberts notified us that she would not stand for re-election as a
director of Enbridge at our 2018 Annual Meeting of Shareholders to be held on May 9, 2018. Ms. Roberts
has served on our Board since March 2015, prior to which she was a director of Enbridge Energy
Company, Inc. and Enbridge Energy Management, L.L.C. Ms. Roberts will continue to serve on our Board
through to the end of her term on May 9, 2018 and her decision not to stand for re-election was based on
the demands on her time from other professional commitments, and not the result of any disagreement
relating to our operations, policies or practices.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Reference to "Executive Officers" is included in Part I. Item 1. Business of this report. Other information in
response to this item, including information on our directors, is incorporated by reference from our Proxy
Statement to be filed with the SEC relating to our 2018 annual meeting of shareholders.
ITEM 11. EXECUTIVE COMPENSATION
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with
the SEC relating to our 2018 annual meeting of shareholders.
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197
ITEM 16. FORM 10-K SUMMARY
None.
INDEX OF EXHIBITS
Each exhibit identified below is included as a part of this annual report. Exhibits included in this filing are
designated by an asterisk (“*”); all exhibits not so designated are incorporated by reference to a prior filing
as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan
arrangement.
Exhibit No. Name of Exhibit
2.1 Agreement and Plan of Merger, dated as of September 5, 2016, by and among
Spectra Energy Corp, Enbridge Inc. and Sand Merger Sub, Inc. (incorporated by
reference to Exhibit 2.1 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
2.2 Contribution Agreement dated as of June 18, 2015 among Enbridge Inc., IPL
System Inc., Enbridge Income Fund Holdings Inc., Enbridge Income Fund,
Enbridge Commercial Trust and Enbridge Income Partners LP (incorporated by
reference to Exhibit 2.1 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.1 Articles of Continuance of the Corporation, dated December 15, 1987
(incorporated by reference to Exhibit 2.1(a) to Enbridge’s Registration Statement
on Form S-8 filed May 7, 2001)
3.2 Certificate of Amendment, dated August 2, 1989, to the Articles of the
Corporation (incorporated by reference to Exhibit 2.1(b) to Enbridge’s
Registration Statement on Form S-8 filed May 7, 2001)
3.3 Articles of Amendment of the Corporation, dated April 30, 1992 (incorporated by
reference to Exhibit 2.1(c) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.4 Articles of Amendment of the Corporation, dated July 2, 1992 (incorporated by
reference to Exhibit 2.1(d) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.5 Articles of Amendment of the Corporation, dated August 6, 1992 (incorporated
by reference to Exhibit 2.1(e) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.6 Articles of Arrangement of the Corporation dated December 18, 1992, attaching
the Arrangement Agreement, dated December 15, 1992 (incorporated by
reference to Exhibit 2.1(f) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.7 Certificate of Amendment of the Corporation (notarial certified copy), dated
December 18, 1992 (incorporated by reference to Exhibit 2.1(g) to Enbridge’s
Registration Statement on Form S-8 filed May 7, 2001)
3.8 Articles of Amendment of the Corporation, dated May 5, 1994 (incorporated by
reference to Exhibit 2.1(h) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.9 Certificate of Amendment, dated October 7, 1998 (incorporated by reference to
Exhibit 2.1(i) to Enbridge’s Registration Statement on Form S-8 filed May 7,
2001)
2001)
2001)
2005)
3.10 Certificate of Amendment, dated November 24, 1998 (incorporated by reference
to Exhibit 2.1(j) to Enbridge’s Registration Statement on Form S-8 filed May 7,
3.11 Certificate of Amendment, dated April 29, 1999 (incorporated by reference to
Exhibit 2.1(k) to Enbridge’s Registration Statement on Form S-8 filed May 7,
3.12 Certificate of Amendment, dated May 5, 2005 (incorporated by reference to
Exhibit 2.1(l) to Enbridge’s Registration Statement on Form S-8 filed August 5,
3.13 Certificate of Amendment, dated May 11, 2011 (incorporated by reference to
Exhibit 3.13 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.14 Certificate of Amendment, dated September 28, 2011 (incorporated by reference
to Exhibit 3.14 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.15 Certificate of Amendment, dated November 21, 2011 (incorporated by reference
to Exhibit 3.15 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.16 Certificate of Amendment, dated January 16, 2012 (incorporated by reference to
Exhibit 3.16 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
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199
ITEM 16. FORM 10-K SUMMARY
INDEX OF EXHIBITS
None.
arrangement.
Exhibit No. Name of Exhibit
2.1 Agreement and Plan of Merger, dated as of September 5, 2016, by and among
Spectra Energy Corp, Enbridge Inc. and Sand Merger Sub, Inc. (incorporated by
reference to Exhibit 2.1 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
2.2 Contribution Agreement dated as of June 18, 2015 among Enbridge Inc., IPL
System Inc., Enbridge Income Fund Holdings Inc., Enbridge Income Fund,
Enbridge Commercial Trust and Enbridge Income Partners LP (incorporated by
reference to Exhibit 2.1 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.1 Articles of Continuance of the Corporation, dated December 15, 1987
(incorporated by reference to Exhibit 2.1(a) to Enbridge’s Registration Statement
on Form S-8 filed May 7, 2001)
3.2 Certificate of Amendment, dated August 2, 1989, to the Articles of the
Corporation (incorporated by reference to Exhibit 2.1(b) to Enbridge’s
Registration Statement on Form S-8 filed May 7, 2001)
3.3 Articles of Amendment of the Corporation, dated April 30, 1992 (incorporated by
reference to Exhibit 2.1(c) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.4 Articles of Amendment of the Corporation, dated July 2, 1992 (incorporated by
reference to Exhibit 2.1(d) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.5 Articles of Amendment of the Corporation, dated August 6, 1992 (incorporated
by reference to Exhibit 2.1(e) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
Each exhibit identified below is included as a part of this annual report. Exhibits included in this filing are
designated by an asterisk (“*”); all exhibits not so designated are incorporated by reference to a prior filing
as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan
3.7 Certificate of Amendment of the Corporation (notarial certified copy), dated
December 18, 1992 (incorporated by reference to Exhibit 2.1(g) to Enbridge’s
Registration Statement on Form S-8 filed May 7, 2001)
3.6 Articles of Arrangement of the Corporation dated December 18, 1992, attaching
the Arrangement Agreement, dated December 15, 1992 (incorporated by
reference to Exhibit 2.1(f) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.8 Articles of Amendment of the Corporation, dated May 5, 1994 (incorporated by
reference to Exhibit 2.1(h) to Enbridge’s Registration Statement on Form S-8
filed May 7, 2001)
3.9 Certificate of Amendment, dated October 7, 1998 (incorporated by reference to
Exhibit 2.1(i) to Enbridge’s Registration Statement on Form S-8 filed May 7,
2001)
3.10 Certificate of Amendment, dated November 24, 1998 (incorporated by reference
to Exhibit 2.1(j) to Enbridge’s Registration Statement on Form S-8 filed May 7,
2001)
3.11 Certificate of Amendment, dated April 29, 1999 (incorporated by reference to
Exhibit 2.1(k) to Enbridge’s Registration Statement on Form S-8 filed May 7,
2001)
3.12 Certificate of Amendment, dated May 5, 2005 (incorporated by reference to
Exhibit 2.1(l) to Enbridge’s Registration Statement on Form S-8 filed August 5,
2005)
3.13 Certificate of Amendment, dated May 11, 2011 (incorporated by reference to
Exhibit 3.13 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.14 Certificate of Amendment, dated September 28, 2011 (incorporated by reference
to Exhibit 3.14 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.15 Certificate of Amendment, dated November 21, 2011 (incorporated by reference
to Exhibit 3.15 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.16 Certificate of Amendment, dated January 16, 2012 (incorporated by reference to
Exhibit 3.16 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
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199
3.17 Certificate of Amendment, dated March 27, 2012 (incorporated by reference to
Exhibit 3.17 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.18 Certificate of Amendment, dated April 16, 2012 (incorporated by reference to
Exhibit 3.18 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.19 Certificate of Amendment, dated May 17, 2012 (incorporated by reference to
Exhibit 3.19 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.20 Certificate of Amendment, dated July 12, 2012 (incorporated by reference to
Exhibit 3.20 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.21 Certificate of Amendment, dated September 11, 2012 (incorporated by reference
to Exhibit 3.21 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.22 Certificate of Amendment, dated December 3, 2012 (incorporated by reference
to Exhibit 3.22 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.23 Certificate of Amendment, dated March 25, 2013 (incorporated by reference to
Exhibit 3.23 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.24 Certificate of Amendment, dated June 4, 2013 (incorporated by reference to
Exhibit 3.24 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.25 Certificate of Amendment, dated September 25, 2013 (incorporated by reference
to Exhibit 3.25 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.26 Certificate of Amendment, dated December 10, 2013 (incorporated by reference
to Exhibit 3.26 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.27 Certificate of Amendment, dated March 10, 2014 (incorporated by reference to
Exhibit 3.27 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.28 Certificate of Amendment, dated May 20, 2014 (incorporated by reference to
Exhibit 3.28 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.29 Certificate of Amendment, dated July 15, 2014 (incorporated by reference to
Exhibit 3.29 to Enbridge’s Registration Statement on Form F-4 filed September
23, 2017)
3.30 Certificate of Amendment, dated September 19, 2014 (incorporated by reference
to Exhibit 3.30 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.31 Certificate of Amendment, dated November 22, 2016 (incorporated by reference
to Enbridge’s Report of Foreign Issuer on Form 6-K filed December 1, 2016)
3.32 Certificate of Amendment, dated December 15, 2016 (incorporated by reference
to Enbridge’s Report of Foreign Issuer on Form 6-K filed December 16, 2016)
3.33 Certificate of Amendment, dated July 13, 2017 (incorporated by reference to
Enbridge’s Report of Foreign Issuer on Form 6-K filed July 13, 2017)
3.34 Certificate of Amendment, dated September 25, 2017
3.35 Certificate of Amendment, dated December 7, 2017
3.36 Amended and Restated General By-Law No. 1 of Enbridge Inc. (incorporated by
reference to Enbridge’s Report of Foreign Issuer on Form 6-K filed February 27,
2017)
3.37 By-Law No. 2 of Enbridge Inc. (incorporated by reference to Enbridge’s Current
Report on Form 6-K filed December 5, 2014)
4.1 Form of Indenture between Enbridge Inc. and Deutsche Bank Trust Company
Americas to be dated February 25, 2005 (incorporated by reference to Exhibit
7.3 to Enbridge’s Registration Statement on Form F-10 filed February 4, 2005)
4.2 First Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust
Company Americas, dated March 1, 2012 (incorporated by reference to Exhibit
7.3 to Enbridge’s Registration Statement on Form F-10 filed May 11, 2012)
4.3 Second Supplemental Indenture between Enbridge Inc. and Deutsche Bank
Trust Company Americas, dated December 19, 2016 (incorporated by reference
to Enbridge’s Report of Foreign Issuer on Form 6-K filed December 20, 2016)
4.4 Third Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust
Company Americas, dated July 14, 2017 (incorporated by reference to
Enbridge’s Report of Foreign Issuer on Form 6-K filed July 14, 2017)
4.5 Shareholder Rights Plan Agreement dated as of November 9, 1995 and
amended and restated as of May 1, 1996, February 24, 1999, May 3, 2002,
May 5, 2005, May 7, 2008, May 11, 2011, May 7, 2014 and May 11, 2017
between Enbridge Inc. and CST Trust Company (incorporated by reference to
Enbridge’s Report of Foreign Issuer on Form 6-K filed May 12, 2017)
Certain instruments defining the rights of holders of long-term debt securities of
the Registrant and its subsidiaries are omitted pursuant to Item 601(b)(4)(iii) of
Regulation S-K. The Registrant hereby undertakes to furnish to the SEC, upon
request, copies of any such instruments.
10.1 Enbridge Pipelines Inc. Competitive Toll Settlement Dated July 1, 2011
10.2 Form of Executive Employment Agreement (pre-2014)
10.3 Form of Executive Employment Agreement (2014-2016)
10.4 Form of Executive Employment Agreement (2017)
10.5 Enbridge Inc. Performance Stock Option Plan (2007) (Canadian)
10.6 Enbridge Inc. Performance Stock Option Plan (2007), as amended and restated
(2011)
*
*
*
*+
*+
*+
*+
*+
200
201
23, 2017)
23, 2017)
23, 2017)
23, 2017)
23, 2017)
23, 2017)
23, 2017)
23, 2017)
23, 2017)
3.18 Certificate of Amendment, dated April 16, 2012 (incorporated by reference to
Exhibit 3.18 to Enbridge’s Registration Statement on Form F-4 filed September
3.19 Certificate of Amendment, dated May 17, 2012 (incorporated by reference to
Exhibit 3.19 to Enbridge’s Registration Statement on Form F-4 filed September
3.20 Certificate of Amendment, dated July 12, 2012 (incorporated by reference to
Exhibit 3.20 to Enbridge’s Registration Statement on Form F-4 filed September
3.21 Certificate of Amendment, dated September 11, 2012 (incorporated by reference
to Exhibit 3.21 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.22 Certificate of Amendment, dated December 3, 2012 (incorporated by reference
to Exhibit 3.22 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.23 Certificate of Amendment, dated March 25, 2013 (incorporated by reference to
Exhibit 3.23 to Enbridge’s Registration Statement on Form F-4 filed September
3.24 Certificate of Amendment, dated June 4, 2013 (incorporated by reference to
Exhibit 3.24 to Enbridge’s Registration Statement on Form F-4 filed September
3.25 Certificate of Amendment, dated September 25, 2013 (incorporated by reference
to Exhibit 3.25 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.26 Certificate of Amendment, dated December 10, 2013 (incorporated by reference
to Exhibit 3.26 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.27 Certificate of Amendment, dated March 10, 2014 (incorporated by reference to
Exhibit 3.27 to Enbridge’s Registration Statement on Form F-4 filed September
3.28 Certificate of Amendment, dated May 20, 2014 (incorporated by reference to
Exhibit 3.28 to Enbridge’s Registration Statement on Form F-4 filed September
3.29 Certificate of Amendment, dated July 15, 2014 (incorporated by reference to
Exhibit 3.29 to Enbridge’s Registration Statement on Form F-4 filed September
3.30 Certificate of Amendment, dated September 19, 2014 (incorporated by reference
to Exhibit 3.30 to Enbridge’s Registration Statement on Form F-4 filed
September 23, 2017)
3.17 Certificate of Amendment, dated March 27, 2012 (incorporated by reference to
Exhibit 3.17 to Enbridge’s Registration Statement on Form F-4 filed September
3.31 Certificate of Amendment, dated November 22, 2016 (incorporated by reference
to Enbridge’s Report of Foreign Issuer on Form 6-K filed December 1, 2016)
3.32 Certificate of Amendment, dated December 15, 2016 (incorporated by reference
to Enbridge’s Report of Foreign Issuer on Form 6-K filed December 16, 2016)
3.33 Certificate of Amendment, dated July 13, 2017 (incorporated by reference to
Enbridge’s Report of Foreign Issuer on Form 6-K filed July 13, 2017)
3.34 Certificate of Amendment, dated September 25, 2017
3.35 Certificate of Amendment, dated December 7, 2017
3.36 Amended and Restated General By-Law No. 1 of Enbridge Inc. (incorporated by
reference to Enbridge’s Report of Foreign Issuer on Form 6-K filed February 27,
2017)
3.37 By-Law No. 2 of Enbridge Inc. (incorporated by reference to Enbridge’s Current
Report on Form 6-K filed December 5, 2014)
4.1 Form of Indenture between Enbridge Inc. and Deutsche Bank Trust Company
Americas to be dated February 25, 2005 (incorporated by reference to Exhibit
7.3 to Enbridge’s Registration Statement on Form F-10 filed February 4, 2005)
4.2 First Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust
Company Americas, dated March 1, 2012 (incorporated by reference to Exhibit
7.3 to Enbridge’s Registration Statement on Form F-10 filed May 11, 2012)
4.3 Second Supplemental Indenture between Enbridge Inc. and Deutsche Bank
Trust Company Americas, dated December 19, 2016 (incorporated by reference
to Enbridge’s Report of Foreign Issuer on Form 6-K filed December 20, 2016)
4.4 Third Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust
Company Americas, dated July 14, 2017 (incorporated by reference to
Enbridge’s Report of Foreign Issuer on Form 6-K filed July 14, 2017)
4.5 Shareholder Rights Plan Agreement dated as of November 9, 1995 and
amended and restated as of May 1, 1996, February 24, 1999, May 3, 2002,
May 5, 2005, May 7, 2008, May 11, 2011, May 7, 2014 and May 11, 2017
between Enbridge Inc. and CST Trust Company (incorporated by reference to
Enbridge’s Report of Foreign Issuer on Form 6-K filed May 12, 2017)
Certain instruments defining the rights of holders of long-term debt securities of
the Registrant and its subsidiaries are omitted pursuant to Item 601(b)(4)(iii) of
Regulation S-K. The Registrant hereby undertakes to furnish to the SEC, upon
request, copies of any such instruments.
10.1 Enbridge Pipelines Inc. Competitive Toll Settlement Dated July 1, 2011
10.2 Form of Executive Employment Agreement (pre-2014)
10.3 Form of Executive Employment Agreement (2014-2016)
10.4 Form of Executive Employment Agreement (2017)
10.5 Enbridge Inc. Performance Stock Option Plan (2007) (Canadian)
10.6 Enbridge Inc. Performance Stock Option Plan (2007), as amended and restated
(2011)
*
*
*
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200
201
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10.7 Enbridge Inc. Performance Stock Option Plan (2007), as amended and restated
(2011) and as further amended (2012)
10.8 Enbridge Inc. Performance Stock Option Plan (2007), as amended and restated
(2011) and as further amended (2012 and 2014)
10.9 Enbridge Inc. Performance Stock Unit Plan (2007, revised effective November
2014)
10.10 Enbridge Inc. Performance Stock Unit Plan (2007), as revised
10.11 Enbridge Inc. Restricted Stock Unit Plan (2006), as revised
10.12 Enbridge Inc. Incentive Stock Option Plan (2007)
10.13 Enbridge Inc. Incentive Stock Option Plan (2007), as amended and restated
(2011)
10.14 Enbridge Inc. Incentive Stock Option Plan (2007), as amended and restated
(2011 and 2014)
10.15 Enbridge Inc. Incentive Stock Option Plan (2017), as revised
10.16 Enbridge Inc. Directors’ Compensation Plan, November 3, 2015, effective
January 1, 2016
10.17 Enbridge Inc. Short Term Incentive Plan (2007), as revised
10.18 The Enbridge Supplemental Pension Plan, As Amended and Restated Effective
January 1, 2005
10.19 Amendment No. 1 and Amendment No. 2 to The Enbridge Supplemental
Pension Plan, As Amended and Restated Effective January 1, 2005
10.20 Enbridge Supplemental Pension Plan for United States Employees (As
Amended and Restated Effective January 1, 2005)
10.21 Amendment 1 and Amendment 2 to the Enbridge Supplemental Pension Plan for
United States Employees (As Amended and Restated Effective January 1, 2005)
10.22 Spectra Energy Corp Directors’ Savings Plan, as amended and restated
10.23 Spectra Energy Corp Executive Savings Plan, as amended and restated
10.24 Spectra Energy Executive Cash Balance Plan, as amended and restated
10.25 Omnibus Amendment, dated June 20, 2014, to Spectra Energy Corp Executive
Savings Plan, Spectra Energy Corp Executive Cash Balance Plan and Spectra
Energy Corp 2007 Long-Term Incentive Plan
10.26 Form of Spectra Energy Corp Change in Control Agreement (As Amended and
Restated)
10.27 Form of Spectra Energy Corp Phantom Stock Award Agreement (2015) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan
10.28 Form of Spectra Energy Corp Stock Option Agreement (Nonqualified Stock
Options) (2016) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive
Plan
10.29 Form of Spectra Energy Corp Performance Share Award Agreement (2016)
pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan
10.30 Form of Spectra Energy Corp Phantom Stock Award Agreement (2016) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Cash-settled)
10.31 Form of Spectra Energy Corp Phantom Stock Award Agreement (2016) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Stock-settled)
10.32 Spectra Energy Corp 2007 Long-Term Incentive Plan (as amended and
restated)
10.33 Spectra Energy Corp Executive Short-Term Incentive Plan (as amended and
restated)
*+
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*
*
*
*
*
*
*
*
*
*
*
10.34 Form of Spectra Energy Corp Phantom Stock Award Agreement (2017) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Cash-settled)
10.35 Form of Spectra Energy Corp Phantom Stock Award Agreement (2017) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Stock-settled)
10.36 Second Amendment to the Spectra Energy Corp Executive Savings Plan (As
Amended and Restated Effective May 1, 2012)
10.37 Second Amendment to the Spectra Energy Corp Executive Cash Balance Plan
(As Amended and Restated Effective May 1, 2012)
12.1 Computation of Ratio Earnings to Fixed Charges
21.1 Subsidiaries of the Registrant
23.1 Consent of PricewaterhouseCoopers LLP
24.1 Powers of Attorney (included on the signature page of the Annual Report)
31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS XBRL Instance Document.
101.SCH XBRL Taxonomy Extension Schema.
101.CAL XBRL Taxonomy Extension Calculation Linkbase.
101.DEF XBRL Taxonomy Extension Definition Linkbase.
101.LAB XBRL Taxonomy Extension Label Linkbase.
101.PRE XBRL Taxonomy Extension Presentation Linkbase.
SIGNATURES
POWER OF ATTORNEY
Each person whose signature appears below appoints Robert R. Rooney, John K. Whelen and Tyler W.
Robinson, and each of them, any of whom may act without the joinder of the other, as their true and
lawful attorneys-in-fact and agents, with full power of substitution, for him or her and in his or her name,
place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of the
Company on Form 10-K, and to file the same, with all exhibits thereto, and all other documents in
connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact
and agents, and each of them, full power and authority to do and perform each and every act and thing
requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in
person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or
his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
202
203
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(2011)
(2011 and 2014)
January 1, 2016
January 1, 2005
10.7 Enbridge Inc. Performance Stock Option Plan (2007), as amended and restated
(2011) and as further amended (2012)
10.8 Enbridge Inc. Performance Stock Option Plan (2007), as amended and restated
(2011) and as further amended (2012 and 2014)
10.9 Enbridge Inc. Performance Stock Unit Plan (2007, revised effective November
2014)
10.10 Enbridge Inc. Performance Stock Unit Plan (2007), as revised
10.11 Enbridge Inc. Restricted Stock Unit Plan (2006), as revised
10.12 Enbridge Inc. Incentive Stock Option Plan (2007)
10.13 Enbridge Inc. Incentive Stock Option Plan (2007), as amended and restated
10.14 Enbridge Inc. Incentive Stock Option Plan (2007), as amended and restated
10.15 Enbridge Inc. Incentive Stock Option Plan (2017), as revised
10.16 Enbridge Inc. Directors’ Compensation Plan, November 3, 2015, effective
10.17 Enbridge Inc. Short Term Incentive Plan (2007), as revised
10.18 The Enbridge Supplemental Pension Plan, As Amended and Restated Effective
10.19 Amendment No. 1 and Amendment No. 2 to The Enbridge Supplemental
Pension Plan, As Amended and Restated Effective January 1, 2005
10.20 Enbridge Supplemental Pension Plan for United States Employees (As
Amended and Restated Effective January 1, 2005)
10.21 Amendment 1 and Amendment 2 to the Enbridge Supplemental Pension Plan for
United States Employees (As Amended and Restated Effective January 1, 2005)
10.22 Spectra Energy Corp Directors’ Savings Plan, as amended and restated
10.23 Spectra Energy Corp Executive Savings Plan, as amended and restated
10.24 Spectra Energy Executive Cash Balance Plan, as amended and restated
10.25 Omnibus Amendment, dated June 20, 2014, to Spectra Energy Corp Executive
Savings Plan, Spectra Energy Corp Executive Cash Balance Plan and Spectra
Energy Corp 2007 Long-Term Incentive Plan
10.26 Form of Spectra Energy Corp Change in Control Agreement (As Amended and
10.27 Form of Spectra Energy Corp Phantom Stock Award Agreement (2015) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan
10.28 Form of Spectra Energy Corp Stock Option Agreement (Nonqualified Stock
Options) (2016) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive
10.29 Form of Spectra Energy Corp Performance Share Award Agreement (2016)
pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan
10.30 Form of Spectra Energy Corp Phantom Stock Award Agreement (2016) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Cash-settled)
10.31 Form of Spectra Energy Corp Phantom Stock Award Agreement (2016) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Stock-settled)
10.32 Spectra Energy Corp 2007 Long-Term Incentive Plan (as amended and
10.33 Spectra Energy Corp Executive Short-Term Incentive Plan (as amended and
Restated)
Plan
restated)
restated)
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10.34 Form of Spectra Energy Corp Phantom Stock Award Agreement (2017) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Cash-settled)
10.35 Form of Spectra Energy Corp Phantom Stock Award Agreement (2017) pursuant
to the Spectra Energy Corp 2007 Long-Term Incentive Plan (Stock-settled)
10.36 Second Amendment to the Spectra Energy Corp Executive Savings Plan (As
Amended and Restated Effective May 1, 2012)
10.37 Second Amendment to the Spectra Energy Corp Executive Cash Balance Plan
(As Amended and Restated Effective May 1, 2012)
12.1 Computation of Ratio Earnings to Fixed Charges
21.1 Subsidiaries of the Registrant
23.1 Consent of PricewaterhouseCoopers LLP
24.1 Powers of Attorney (included on the signature page of the Annual Report)
31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS XBRL Instance Document.
101.SCH XBRL Taxonomy Extension Schema.
101.CAL XBRL Taxonomy Extension Calculation Linkbase.
101.DEF XBRL Taxonomy Extension Definition Linkbase.
101.LAB XBRL Taxonomy Extension Label Linkbase.
101.PRE XBRL Taxonomy Extension Presentation Linkbase.
SIGNATURES
POWER OF ATTORNEY
Each person whose signature appears below appoints Robert R. Rooney, John K. Whelen and Tyler W.
Robinson, and each of them, any of whom may act without the joinder of the other, as their true and
lawful attorneys-in-fact and agents, with full power of substitution, for him or her and in his or her name,
place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of the
Company on Form 10-K, and to file the same, with all exhibits thereto, and all other documents in
connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact
and agents, and each of them, full power and authority to do and perform each and every act and thing
requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in
person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or
his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
202
203
ENBRIDGE INC.
(Registrant)
Date:
February 16, 2018
By:
/s/ Al Monaco
Al Monaco
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below
on February 16, 2018 by the following persons on behalf of the registrant and in the capacities indicated.
/s/ Al Monaco
/s/ John K. Whelen
Al Monaco
President, Chief Executive Officer and Director
(Principal Executive Officer)
John K. Whelen
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ Allen C. Capps
Allen C. Capps
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
/s/ Pamela L. Carter
Pamela L. Carter
Director
/s/ Marcel R. Coutu
Marcel R. Coutu
Director
/s/ Charles W. Fischer
Charles W. Fischer
Director
/s/ Michael McShane
Michael McShane
Director
/s/ Rebecca B. Roberts
Rebecca B. Roberts
Director
/s/ Cathy L. Williams
Cathy L. Williams
Director
/s/ Gregory L. Ebel
Gregory L. Ebel
Chairman of the Board of Directors
/s/ Clarence P. Cazalot, Jr.
Clarence P. Cazalot, Jr.
Director
/s/ J. Herb England
J. Herb England
Director
/s/ V. Maureen Kempston Darkes
V. Maureen Kempston Darkes
Director
/s/ Michael E.J. Phelps
Michael E.J. Phelps
Director
/s/ Dan C. Tutcher
Dan C. Tutcher
Director
204
The Global 100 Most Sustainable Corporations in
the World highlights global corporations that have been
most proactive in managing environmental, social and
governance issues. In January 2018, Enbridge was named
to the Global 100 for the ninth straight year, and 12th time
overall. Enbridge is ranked No. 12 worldwide, up from
our No. 39 overall ranking in 2017—top among the other
four Canadian corporations listed and the only Canadian
energy-sector company to make the grade.
Safety Report to the Community
Our annual Safety Report to the Community, which outlines
our progress as we strive for 100 percent safety and
zero incidents, is available at enbridge.com/safetyreport
Sustainability Report
Enbridge publishes an annual Sustainability Report.
Our first report for our combined company will be published
in June 2018 and will be available at enbridge.com/sustainability
Online Annual Report
You can read our 2017 Annual Report online
at enbridge.com/ar2017
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 post-consumer waste fiber.
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200, 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