Bridge to a cleaner
energy future
2021 Annual Report
Letter to Shareholders
Dear Shareholder,
Last year, global economies and the energy business continued
to be challenged by the COVID-19 pandemic. However, a robust
economic recovery drove energy demand and commodity prices
higher, and underscored the importance of reliable, affordable
energy in our lives.
Our people safely navigated COVID restrictions and supported
each other and our communities. We continued to focus and
deliver on our purpose—to provide the energy that people rely
on every day to fuel their quality of life. We delivered record
safety, operating and financial performance, and executed
on key strategic priorities. At the same time, we took steps to
modernize our systems, diversify our assets, and advance our
net-zero emissions and diversity and inclusion targets.
We’re proud of our people and what we achieved last year—
helping to further cement Enbridge’s position as North
America’s leading energy delivery company.
In 2021, Enbridge set employee and contractor safety
and system reliability records because of our strong
safety culture and investments in system integrity and
preventative maintenance.
Delivering on results and strategic priorities
2021 was a catalyst year for the Company. We built on our
momentum to grow our conventional business, reduce
emissions intensity from our existing assets and expand our
low-carbon investments. We reached the top end of our external
guidance range for distributable cash flow (DCF)1 per share,
increased our dividend for the 26th consecutive year—and
extended that track record with another 3% dividend increase
for 2022.
1 Adjusted EBITDA and DCF per share are non-GAAP measures.
1
In 2021, Enbridge generated strong total shareholder
returns of 30%. Over the last 10 years, we have grown
earnings before interest taxes depreciation and
amortization (adjusted EBITDA1) at an average annual rate
of 14% by executing a $65 billion organic capital program,
delivering on revenue and productivity improvements,
as well as selective acquisitions that have advanced
our strategies and driven further organic growth.
That includes the 2017 acquisition of Spectra, which
transformed the business by adding a leading natural gas
utility and pipeline footprint—complementing Enbridge’s
irreplaceable crude oil assets and growing renewables
business. Last year, Enbridge added North America’s
leading crude oil export platform through the acquisition
of the Ingleside Energy Center, which positions the
Company to play a pivotal role in global energy exports.
Our disciplined investment of capital, while protecting our
sector-leading financial strength, has enabled us to grow
the dividend on average by 13% per year over the last
10 years, supporting robust shareholder returns.
Adjusted EBITDA
($ billions)
Dividend/share ($)
16
14
12
10
8
6
4
2
0
2012
2013 2014 2015 2016 2017 2018 2019 2020 2021
Adjusted EBITDA
Dividend/share
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
2021 Annual ReportEnbridge Inc. In 2021, we placed $10 billion of secured capital into
service—including completion of the state-of-the-art Line 3
Replacement Project, the largest capital project in Enbridge’s
history—and sanctioned $2 billion of new projects. These
investments will contribute to cash flow growth and provide
additional financial capacity in the years to come.
Engagement with Indigenous groups along the Line 3 right-of-
way led to a better route, as well as tailored environmental
measures to protect the land and minimize impacts. This
engagement also resulted in $900 million in Indigenous
business opportunities, including Indigenous workers
comprising 7% of the U.S. Line 3 workforce. This valuable
experience is being shared across our organization to further
strengthen our lifecycle approach to Indigenous and
stakeholder engagement.
Good progress is being made on our $10 billion commercially
secured growth program, including construction of four
offshore wind projects in Europe, connecting new customers
to our natural gas distribution system, and modernizing our
long-haul pipeline systems. We also established industry
partnerships to advance our early-mover position in renewable
natural gas, hydrogen, and carbon capture and storage.
Over the last several years we’ve worked with our customers
to develop a new contract offering for our Canadian Mainline.
Last year, our proposal was declined by the Canada Energy
Regulator (CER), despite having support from more than 75%
of our shippers. We’ll continue to collaborate with our
customers on two alternative options to assure a solid,
long-term commercial arrangement is in place.
> Indigenous-owned MB Customs worked on the Line 3
Replacement Program in Minnesota.
We also advanced our export strategy with the acquisition of
the Ingleside Energy Center, through which we established a
leading light-oil export position and platform for future organic
growth. We aligned that investment with our target to reach
net-zero emissions by 2050 by committing to develop an on-
site solar farm that will drive net-zero Scope 1 and 2 emissions,
while also contributing to Scope 3 reductions. This is a great
example of how Enbridge is differentiating its approach to
energy infrastructure.
> In February 2022, Enbridge and First Nation Capital Investment
Partnership (FNCIP) announced plans to work together to
advance a new carbon transportation and storage solution
west of Edmonton called the Open Access Wabamun Carbon
Hub. The proposed Wabamun Hub will tie into planned carbon
capture projects, with the combined potential to abate nearly
4 million tonnes of CO2 emissions annually.
> The Enbridge team continued to make a positive impact in our
communities—including a US$4 million contribution to the United
Way—and thousands of hours of volunteering with close to
3,000 local community and Indigenous organizations. Our people
stepped up to support recovery efforts following wildfires and
flooding in B.C., and the same care was shown after Hurricane
Ida in Louisiana.
Bridging to a cleaner energy future
Forecasts show that the demand for energy will continue to
increase as populations grow and developing nations raise
their standards of living. Natural gas and oil make up more
than half of that energy demand today and we expect demand
to remain strong for decades to come, even as renewables
grow. This energy is critical for transportation, heating,
cooking, manufacturing, electronics, pharmaceuticals—and
more. North America has an abundant supply of oil and gas
with leading environmental performance—supply that can be
exported to where it’s needed.
It’s clear that society is moving toward a lower-carbon
economy. We believe that we need to transition our energy
systems prudently to ensure adequate supply of conventional
energy while lowering emissions and increasing investment in
low-carbon energies.
We have a solid inventory of both conventional and low-carbon
opportunities, totaling about $6 billion of annual investment.
On the conventional side, we’ll expand and modernize gas
systems, which will displace coal and support renewables
growth. We’ll continue to build out our LNG and export
positions and invest in our gas utility. We’ll also pursue capital-
efficient Liquids Pipelines optimizations.
2
2021 Annual ReportEnbridge Inc. These businesses also come with embedded low-carbon
opportunities. Our existing assets will support the energy
transition by blending and transporting renewable natural gas
and hydrogen, transporting and storing carbon, and moving
more natural gas. Our Renewables business also gives us high
visibility to growth, with 14 projects in construction, including
solar self-power in North America and offshore wind in France.
Getting the pace of the transition right will be critical. We’re
taking a disciplined approach to ensure that new opportunities
provide an attractive return, and we’ll build on proven
technologies and partner with those who can bolster our
capability. This is exactly the model we used for wind and
solar 20 years ago, and today Enbridge has a leading
renewables platform.
Energy is needed in every aspect of daily life, and our
assets provide an essential source of safe, reliable and
affordable energy. Our systems have longevity because
they serve the best markets and can’t be replaced.
We’re modernizing our assets to improve efficiency
and reduce emissions.
Sustaining our growth
In 2022, we’re positioned to grow adjusted EBITDA and
DCF per share by about 8%. We expect to exit 2022 near
the bottom of our 4.5x to 5.0x debt to EBITDA range, driven
by annualized contributions from Line 3 and the Ingleside
terminal. We remain focused on managing costs and
maximizing our financial strength and flexibility.
Our visible cash flow growth outlook and healthy balance
sheet will enable the return of capital as part of our
shareholder value proposition.
Over the next three years, we expect to generate
$5 to $6 billion of annual investment capacity. Of that amount,
$3 to $4 billion will be prioritized to low-capital intensity and
utility-like investments, and the remaining $2 billion will be
deployed to the next best alternatives, such as organic growth,
profitable energy transition investments, share repurchases
or debt reduction. The $1.5 billion share-buyback program we
recently introduced creates an additional avenue to return
value to shareholders.
By executing on our secured capital program, enhancing
returns on our existing businesses, and deploying excess
financial capacity, we estimate 5 – 7% DCF per share
compound annual growth through 2024 versus 2021 results.
Enbridge was an early investor in low-carbon energies and
is well positioned to be a North American leader. In 2021,
we established a dedicated New Energy Technologies
team. Through 2025, we see opportunity to invest a further
$1.5 billion to advance low-carbon opportunities, in addition to
the $2.5 billion in offshore wind projects already in execution.
3
Being a differentiated service provider
Core to our strategy is our industry-leading approach to our
environmental, social and governance (ESG) performance.
Our performance in these areas has and will continue to
differentiate Enbridge—setting us apart as the service provider
of choice for our customers, an employer of choice, a trusted
partner to communities, Indigenous groups and policy makers,
and a best-in-class investment.
In 2020, we introduced ESG goals, including continuing to drive
industry-leading safety performance, reducing emissions to net
zero, and improving diversity and inclusion. We’ve set ambitious
goals for our ESG efforts, made them public and linked
discretionary pay for all employees to progress in these areas.
At our inaugural ESG Forum in September 2021, we shared
detailed plans for how we’re going about achieving these goals
and how we’ve integrated them into each of our businesses.
2021 ESG performance update
Last year, we issued $3 billion in sustainability-linked financings
that are tied to achievement of our ESG goals. We also further
advanced our capital-allocation framework to ensure that all
new investments account for carbon prices and are aligned
with our emissions-reduction goals.
We’re on track to reduce our emissions intensity 35% by 2030
and reach our net-zero emissions target by 2050. Additionally,
we expanded emissions reporting to include new Scope 3
metrics designed to measure the emissions intensity of energy
delivered and the emissions avoided through our more than
two decades of investment in renewables, low-carbon fuels,
and demand-side management programs. Since 2018, we have
reduced our emissions intensity and absolute emissions by
approximately 21% and 14%, respectively.
Through demand-side management in our Gas
Distribution and Storage business unit, we’ve reduced
emissions by nearly 55 million tCO2e since 1995.
GHG emissionsWorkforce diversityBoard diversity2025goal2025goal2025goalIntensity2018baselineDown ~21% from baseline2030goal35%Progress towards net zero2018baseline2050goalNet zeroAbsolute23% representation028%Ethnic and racialminorities2025goalGender031% women40%Gender036% women27% representation040%20%Ethnic and racialminoritiesEnvironmentSocialGovernance2021 Annual ReportEnbridge Inc. In 2021, the Board welcomed three new directors: Mayank
(Mike) Ashar, Gaurdie Banister and Jane Rowe; three highly
qualified individuals who bring significant energy industry
experience and strong skills and business judgment to the
Board. We’re also bringing forward two new Board candidates,
Jason Few and Steven Williams, who will stand for election
at our annual general meeting in May. Information about our
Board directors and new candidates can be found in our
Management Information Circular.
We said goodbye to Gregory Goff, Maureen Kempston-Darkes
and Marcel Coutu as directors. We’d like to thank them for
their valuable contributions to the Company. We’d also like to
acknowledge Herb England who will be retiring at this year’s
meeting. As one of our longest-serving Board members, Herb
has played a significant role in shaping Enbridge’s strategy,
and his leadership and dedication will be missed.
Our thanks
Each year our performance comes down to our people, who
fulfill Enbridge’s purpose while living our values of Safety,
Integrity, Respect and Inclusion. We thank them for their
commitment to our business.
As we look to next year, the strong demand for our systems
and execution on our capital program continue to drive stable
and growing cash flows. We believe that our embedded
conventional and low-carbon organic growth opportunities,
along with our disciplined approach to investment and
increasing dividends, provide a compelling growth outlook and
continued strong value proposition for our shareholders and
our other important stakeholders.
Sincerely,
Greg Ebel and Al Monaco
Gregory L. Ebel
Chair, Board of Directors
Al Monaco
President & Chief
Executive Officer
Calgary, Alberta
March 2, 2022
We’re committed to industry leadership in sustainability
and continuous improvement in this area. That’s why we’ve
implemented additional measures, including working with
our supply chain to lower Scope 3 emissions, developing
partnerships to advance low-carbon innovation within our
businesses, and working proactively with organizations
developing science-based guidelines for emissions targets in
the midstream sector. This year’s annual sustainability report
will include a scenario analysis that considers the resiliency of
our strategy on a net-zero pathway.
We remain steadfast in our belief that an energized work force
is driven by diversity, equity and inclusion. This continues to be
a priority and has been embedded in our hiring decisions and
training, including mandatory training on racial justice,
unconscious bias and Indigenous cultural awareness.
Prior to the pandemic, we enhanced our Workplace Mental
Health initiatives to provide more resources and education
on well-being—programs that proved to be critically
important over the last two years. We’re now advancing
our efforts by raising awareness of the small actions we
can take to reduce stigma, create personal well-being, and
make people feel valued and appreciated.
We’re deliberate about creating the right environment for
our people. We conduct regular surveys and focus groups
to listen to their input and ensure that we continue to evolve
and meet the needs of today. Last year, we expanded
our FlexWork program to give Enbridge employees more
choice to balance accountabilities at work and at home.
Our highly engaged Board reflects a balance of diverse
perspectives, backgrounds and experiences. Our independent
Board Chair and separate Chair and CEO positions represent
corporate governance best practices. Four of our directors
are women, three of whom chair Board committees. Three of
11 directors self-identify as members of an ethnic or visible
minority and, subject to shareholder approval of our 2022
director nominees, we expect to increase our diversity further.
Evolving our leadership and Board
There were several changes to senior leadership last year
as part of development and succession planning, and we’re
fortunate to have strong leaders to step into new roles. This
included the retirement of Bill Yardley, Executive Vice President
and President, Gas Transmission and Midstream, who spent
22 years with Enbridge. Bill leaves a strong legacy and will be
remembered for his passion for the business and his deep
care and respect for the people around him.
4
2021 Annual ReportEnbridge Inc.
Our Board
Gregory L.
Ebel
Mayank (Mike) M.
Ashar
Gaurdie E.
Banister Jr.
Pamela L.
Carter
Susan M.
Cunningham
J. Herb
England
Teresa S.
Madden
Al Monaco
Stephen S.
Poloz
S. Jane Rowe
Dan C.
Tutcher
About us
At Enbridge, our purpose is to fuel quality of life by delivering
energy safely, reliably and sustainably. Whether it’s oil, natural
gas or renewable power, the energy we deliver helps to heat
homes, feed families, fuel vehicles, power industry and benefit
society in thousands of ways. The passion and innovation
of our 11,000-person team has helped Enbridge become
North America’s leading energy delivery company.
Throughout our history, we’ve looked beyond the horizon to
invest in modern infrastructure, resilient communities and
reliable energy. We’re building a bridge to a more sustainable
future by meeting energy needs today and growing our low-
carbon businesses for tomorrow.
While conventional energy will continue to be needed for
decades to come, Enbridge is taking a balanced approach to
the energy transition.
Our networks stretch across North America and we’re
modernizing our systems, expanding our footprint, and working
toward our goal to be net zero by 2050. We’re taking steps
big and small to reduce emissions and accelerate the energy
transition, including pursuing the potential for investment of
$4 billion through 2025 in renewable power and low-carbon
energy solutions such as hydrogen, renewable natural gas
(RNG), and carbon capture and storage (CCS).
As we grow and evolve, we’ll continue to be guided by a strong
set of core values—Safety, Integrity, Respect and Inclusion—
that reflect what is truly important to Enbridge.
Our core businesses
Enbridge plays a significant role in the energy value chain by
connecting people to the energy they need and want.
• Gas Transmission and Midstream (GTM) transports
approximately 20% of the natural gas consumed in the U.S.,
supplying natural gas to approximately 170 million people, as
well as power generation facilities across the continent.
• Gas Distribution and Storage (GDS) has more than
3.9 million metered connections in over 300 municipalities
across Ontario and Quebec and supplies energy to 75% of
Ontario residents.
• Liquids Pipelines (LP) transports approximately 30% of
the crude oil produced in North America to 25 refiners,
connecting producers to the best markets in the
U.S. Midwest, the U.S. Gulf Coast and Eastern Canada.
• Renewable Power Generation has ownership interests in
more than 48 renewable energy facilities (in operation and
under construction) with 2,178 megawatts (MW) of net
generation capacity—enough to meet the electricity needs
of nearly one million homes.
• Enbridge’s recently formed New Energy Technologies team
collaborates with each business unit to advance low-carbon
energy infrastructure opportunities across the Company
and build on Enbridge’s early investments in RNG, hydrogen
and CCS.
5
2021 Annual ReportEnbridge 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, 2021
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)
98-0377957
(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
6.375% Fixed-to-Floating Rate Subordinated
Notes Series 2018-B due 2078
Trading Symbol(s)
ENB
Name of each exchange on which registered
New York Stock Exchange
ENBA
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
_______________________________
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 every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐
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.
Large Accelerated Filer
Non-Accelerated Filer
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 has filed a report on and attestation to its management's assessment of the effectiveness of
its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public
accounting firm that prepared or issued its audit report. Yes ☒ No ☐
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, 2021, was approximately US$77.7 billion.
As at February 4, 2022, the registrant had 2,026,274,277 common shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Not applicable.
EXPLANATORY NOTE
Enbridge Inc., a corporation existing under the Canada Business Corporations Act, qualifies as a foreign
private issuer in the United States of America (US) for purposes of the Securities Exchange Act of 1934,
as amended (the Exchange Act). Although, as a foreign private issuer, Enbridge Inc. is not required to do
so, Enbridge Inc. currently files annual reports on Form 10-K, quarterly reports on Form 10-Q, and current
reports on Form 8-K with the Securities and Exchange Commission (SEC) instead of filing the reporting
forms available to foreign private issuers.
Enbridge Inc. intends to prepare and file a management proxy circular and related material under
Canadian requirements. As Enbridge Inc.’s management proxy circular is not filed pursuant to Regulation
14A, Enbridge Inc. may not incorporate by reference information required by Part III of this Form 10-K
from its management proxy circular. Accordingly, in reliance upon and as permitted by Instruction G(3) to
Form 10-K, Enbridge Inc. will be filing an amendment to this Form 10-K containing the Part III information
no later than 120 days after the end of the fiscal year covered by this Form 10-K.
2
PART I
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Item 4.
Properties
Legal Proceedings
Mine Safety Disclosures
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Item 6.
Item 7.
Purchases of Equity Securities
[Reserved]
Management’s Discussion and Analysis of Financial Condition and Results of
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
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
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 Accounting Fees and Services
PART IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Exhibit Index
Signatures
Page
8
42
54
55
55
55
56
57
58
90
93
179
179
180
180
181
181
181
181
181
182
182
183
189
3
GLOSSARY
AFUDC
AOCI
ARO
ASC
ASU
BC
bcf/d
bpd
CCS
CER
CPP Investments
CTS
DAPL
Dawn
DCP Midstream
EBITDA
EEP
EIEC
EIS
EMF
Enbridge
Enbridge Gas
ESG
FERC
Flanagan South
GHG
H2
IJT
ISO
kbpd
LMCI
LNG
MATL
MD&A
Moda
Allowance for funds used during construction
Accumulated other comprehensive income/(loss)
Asset retirement obligations
Accounting Standards Codification
Accounting Standards Update
British Columbia
Billion cubic feet per day
Barrels per day
Carbon capture and storage
Canada Energy Regulator, created by the Canadian Energy Regulator
Act which also repealed the National Energy Board Act, on August 28,
2019
Canada Pension Plan Investment Board
Competitive Toll Settlement
Dakota Access Pipeline
An extensive network of underground storage pools at the Tecumseh
Gas Storage facility and Dawn Hub
DCP Midstream, LLC
Earnings before interest, income taxes and depreciation and
amortization
Enbridge Energy Partners, L.P.
Enbridge Ingleside Energy Center
Environmental Impact Statement
Éolien Maritime France SAS
Enbridge Inc.
Enbridge Gas Inc.
Environment, Social and Governance
Federal Energy Regulatory Commission
Flanagan South Pipeline
Greenhouse gas
Hydrogen gas
International Joint Tariff
Incentive Stock Options
Thousand barrels per day
Land Matters Consultation Initiative
Liquefied natural gas
Montana-Alberta Tie-Line
Management’s Discussion and Analysis
Moda Midstream Operating, LLC
4
MW
NCIB
NGLs
Noverco
NYSE
OBPS
OCI
OEB
OPEB
PHMSA
PSU
RNG
ROU
RSU
Sabal Trail
Seaway Pipeline
SEP
Spectra Energy
SPOT
Texas Eastern
TSX
US
US GAAP
US L3R Program
VIE
Westcoast
Megawatts
Normal course issuer bid
Natural gas liquids
Noverco Inc.
New York Stock Exchange
Output-based pricing system
Other comprehensive income/(loss)
Ontario Energy Board
Other postretirement benefit obligations
Pipeline and Hazardous Materials Safety Administration
Performance Stock Units
Renewable natural gas
Right-of-use
Restricted Stock Units
Sabal Trail Transmission, LLC
Seaway Crude Pipeline System
Spectra Energy Partners, LP
Spectra Energy Corp
Sea Port Oil Terminal
Texas Eastern Transmission, L.P.
Toronto Stock Exchange
United States of America
Generally accepted accounting principles in the United States of
America
United States portion of the Line 3 Replacement Program
Variable interest entities
Westcoast Energy Inc.
5
CONVENTIONS
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.
Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to
“dollars” or “$” are to Canadian dollars and all references to “US$” are to US 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 our and
our 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”, “believe”, “estimate”, “expect”, “forecast”,
“intend”, “likely”, “plan”, “project”, “target” 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: our corporate vision and strategy, including strategic
priorities and enablers; the COVID-19 pandemic and the duration and impact thereof; energy intensity and emissions
reduction targets and related Environment, Social and Governance (ESG) matters; diversity and inclusion goals;
expected supply of, demand for, and prices of crude oil, natural gas, natural gas liquids (NGLs), liquified natural gas
and renewable energy; energy transition; anticipated utilization of our existing assets; expected earnings before
interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash
flows and distributable cash flow; dividend growth and payout policy; financial strength and flexibility; expectations on
sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids
Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and
Energy Services businesses; expected costs related to announced projects and projects under construction and for
maintenance; expected in-service dates for announced projects and projects under construction and for maintenance;
expected capital expenditures, investment capacity and capital allocation priorities; 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 and the timing thereof; expected benefits of transactions, including the
realization of efficiencies, synergies and cost savings; expected future actions of regulators and courts; toll and rate
cases discussions and filings, including Mainline System contracting; anticipated competition; United States Line 3
Replacement Program (US L3R Program), including anticipated in-service dates and capital costs; and Line 5 dual
pipelines and related litigation and other matters.
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 COVID-19
pandemic and the duration and impact thereof; the expected supply of and demand for crude oil, natural gas, NGL
and renewable energy; prices of crude oil, natural gas, NGLs and renewable energy; anticipated utilization of assets;
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 timing and closing of acquisitions and dispositions; the realization of
anticipated benefits and synergies of transactions; governmental legislation; litigation; estimated future dividends and
impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program;
expected EBITDA; expected earnings/(loss); expected future cash flows; and expected distributable cash flow.
Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGLs 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, interest rates and the
COVID-19 pandemic 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-
6
looking statement cannot be determined with certainty, particularly with respect to expected EBITDA, expected
earnings/(loss), expected future cash flows, expected distributable cash flow or estimated future dividends. The most
relevant assumptions associated with forward-looking statements regarding 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, customer, government,
court and regulatory approvals on construction and in-service schedules and cost recovery regimes; and the
COVID-19 pandemic and the duration and impact thereof.
Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our
strategic priorities, operating performance, legislative and regulatory parameters; litigation, including with respect to
the Dakota Access Pipeline (DAPL) and the Line 5 dual pipelines; acquisitions, dispositions and other transactions
and the realization of anticipated benefits therefrom; our 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;
exchange rates; interest rates; commodity prices; political decisions; the supply of, demand for and prices of
commodities; and the COVID-19 pandemic, 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 US 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 assumes no obligation to publicly update
or revise any forward-looking statement made in this Annual Report on Form 10-K or otherwise, whether as a result
of new information, future events or otherwise. All 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.
NON-GAAP AND OTHER FINANCIAL MEASURES
Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in
this Annual Report on Form 10-K makes reference to non-GAAP and other financial measures, including EBITDA.
EBITDA is defined as earnings before interest, income taxes, depreciation and amortization. Management uses
EBITDA to assess performance of Enbridge and to set targets. Management believes the presentation of EBITDA
gives useful information to investors as it provides increased transparency and insight into the performance of
Enbridge.
The non-GAAP and other financial measures described above are not measures that have a standardized meaning
prescribed by generally accepted accounting principles in the United States of America (US GAAP) and are not US
GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other
issuers. A reconciliation of historical non-GAAP and other financial measures to the most directly comparable GAAP
measures is set out in this MD&A and is available on our website. Additional information on non-GAAP and other
financial measures may be found on our website, www.sedar.com or www.sec.gov.
7
ITEM 1. BUSINESS
PART I
We are a leading North American energy infrastructure company. We safely and reliably deliver the
energy people need and want to fuel quality of life. Our core businesses include Liquids Pipelines, which
transports approximately 30% of the crude oil produced in North America; Gas Transmission and
Midstream, which transports approximately 20% of the natural gas consumed in the US; Gas Distribution
and Storage, which serves approximately 75% of Ontario residents via approximately 3.8 million meter
connections; and Renewable Power Generation, which generates approximately 1,766 megawatts (MW)
of net renewable power in North America and Europe. Our common shares trade on the Toronto Stock
Exchange (TSX) and 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.
A more detailed description of each of our businesses and underlying assets is provided below under
Business Segments.
CORPORATE VISION AND STRATEGY
VISION
Our primary purpose as a company is to fuel quality of life by providing the energy people need and want,
in a safe, clean and socially responsible way. Our vision to be the leading energy infrastructure company
in North America supports this purpose. In pursuing this vision, we play a critical role in enabling the
economic and social well-being of people in the areas we serve who depend on access to affordable and
reliable energy of all types. Our infrastructure franchises transport, distribute, and generate energy
including liquids, natural gas, renewable power, and low-carbon fuels like Renewable Natural Gas (RNG).
We recognize that the energy system is changing, and we aim to bridge to that cleaner energy future by
investing in low-carbon platforms while ensuring the continuity and stability that the world requires through
the transition.
Our investor value proposition is founded on our ability to deliver predictable cash flows and a growing
stream of dividends year-over-year through investment in, and efficient operation of, energy infrastructure
assets that are strategically positioned between key supply basins and strong demand-pull markets. Our
assets are underpinned by long-term contracts, regulated cost-of-service tolling frameworks, power
purchase agreements, and other low-risk commercial arrangements.
We strive to be a leader in ESG; worker and public safety; emissions reduction; stakeholder relations;
customer service; community investment; and employee engagement and satisfaction.
STRATEGY
An in-depth understanding of energy supply and demand fundamentals coupled with disciplined capital
allocation principles has helped us become an industry leader supported by a diverse set of assets across
the energy system. Our assets have reliably generated low-risk, resilient cash flows through many
commodity and economic cycles, including the COVID-19 pandemic and the ensuing volatile economic
recovery.
8
To ensure we continue to be an industry leader and value creator going forward, we maintain a robust
strategic planning approach. We regularly conduct scenario and resiliency analysis on both our assets
and on our business strategy. We test various value enhancement and maximization options, and we
engage regularly with our Board of Directors (Board) to ensure alignment and maintain active oversight.
This Board participation includes updates and discussions throughout the year and a dedicated session to
Strategy Planning annually. This comprehensive approach will continue to guide investment decisions
moving forward.
Predictable growth is a hallmark of our investor value proposition. We see a 5-7% compound annual
growth rate in distributable cash flow per share through 2024, relative to 2021, underpinned by
opportunities to advance returns in our base business and grow organically through disciplined capital
allocation. Our diversified footprint allows for selective investment in both our core businesses and in
emerging low carbon energy platforms such as carbon capture and storage (CCS), hydrogen gas (H2),
and RNG.
In 2021, we progressed several of our strategic priorities. For example:
• Our Liquids Pipelines team delivered record mainline throughput, placed $5.6 billion of capital into
service (Line 3 Replacement, Southern Access), added 90 kbpd of system expansions into
Petroleum Administration for Defense Districts (PADD) III, and acquired the Ingleside Energy
Center in Corpus Christi and related assets which extends our reach into global light-oil export
markets.
• Our Gas Transmission and Midstream business successfully placed $3.1 billion of capital into
service, completed favorable rate settlements, which added $150 million of incremental EBITDA,
and continued to advance more than $2 billion of expansion opportunities.
• Our Gas Distribution and Storage utility provided uninterrupted services during the ongoing
pandemic, added over 40 thousand new customers, completed 190 modernization projects,
placed two RNG projects into service, and completed an H2 blending pilot.
•
In Europe, Renewable Power Generation advanced construction of the 480 MW Saint Nazaire
project, the 500 MW Fécamp project, and the 448 MW Calvados project, and sanctioned the
Provence Grand Large floating offshore wind facility.
• We advanced our self-power strategy and commissioned two projects, Alberta Solar One on our
Liquids Pipeline system and Heidlersberg on our Gas Transmission system. Ten additional self-
power facilities (~100MW) were approved for future development.
• We established our New Energy Technologies team to advance our low-carbon strategy. Through
several strategic partnerships, we are working to develop solutions in RNG, H2 and CCS and to
accelerate global and industry-specific low-carbon objectives.
• We continued to make meaningful progress towards our ESG goals that include a 35% reduction
in greenhouse gas (GHG) emissions intensity from our operations by 2030 (net zero GHG
emissions by 2050) and increased representation of diverse groups within our workforce and the
Board of Directors by 2025.
• We sold $1.2 billion of assets at attractive valuations, further strengthening our financial flexibility.
In addition, we continued to reduce our operating costs ($1.2 billion since 2017), increasing our
profitability and competitiveness.
9
These achievements are discussed in further detail in Part II. Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations.
Looking ahead, our near-term strategic priorities remain similar to years past. As always, proactively
advancing the safety of communities and assets, protecting the environment, and maintaining reliability
will always be our top priorities. We are focused on enhancing the value of our existing assets in Liquids
Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, and Renewable Power
Generation.
We will continue to enhance base business returns, capitalize on our advantaged liquids and natural gas
pipeline infrastructure, emphasizing export-driven opportunities and in-franchise organic growth, and
developing low-carbon opportunities across our business.
Our key strategic priorities are summarized below:
Ensure Safe Reliable Operations
Safety and operational reliability remain the foundation of our strategy. Our 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 while protecting people and the environment.
Enhance Returns from our Base Businesses
A key priority is to drive growth through an ongoing focus on optimization, productivity, and efficiency
across all our businesses. Examples include: the application of drag-reducing agents and pump station
horsepower additions to optimize throughput on our liquids system, the execution of toll settlements and
rate case filings to optimize revenue within our gas transmission franchises, the expansion of low-carbon
gas offerings to modernize and integrate value chains at our gas utility, and more generally, and the
creation of sustainable cost savings across the organization through process improvement and/or system
enhancements.
Execute the Capital Program and Grow Core Business
Successful project execution is integral to our financial performance and to the strategic positioning of our
business over the long term. Our ongoing objective is to deliver our slate of secured projects (currently $9
billion through 2024) at the lowest practical cost while maintaining the highest standards for safety, quality,
customer satisfaction and environmental and regulatory compliance. For a discussion of our current
portfolio of capital projects, refer to Part II. Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Growth Projects - Commercially Secured Projects.
In seeking to extend growth, we expect to have sufficient self-funding capacity of about $5 to $6 billion per
year to invest in new organic growth capital without issuing any additional common equity and maintaining
key credit metrics. We will remain disciplined and deploy capital towards the best uses, prioritizing
balance sheet strength, investment in low capital intensity growth and regulated utility or utility-like
projects. We will carefully assess our remaining investable capacity, deploying capital to the most value-
enhancing opportunities available to us, including further organic growth, asset acquisitions, and share
buybacks, or further deleveraging our balance sheet.
Looking ahead, we see strong utilization of our existing network and opportunities for future growth within
each of our businesses. For example:
• Our liquids pipelines infrastructure will remain a vital connection between key supply basins and
demand-pull markets such as the refinery hubs in the US Midwest, Eastern Canada, and the US
Gulf Coast. The emergence of CCS offers the potential to provide new growth opportunities over
the long term.
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• Our natural gas pipelines business will seek extension and expansion opportunities driven by new
load demand from gas-fired power generation, industrial growth, and coastal liquefied natural gas
(LNG) plants. Looking forward, blending RNG and H2 production projects into our system will
enhance asset longevity and enable us to offer a differentiated low-carbon service to customers.
• Our gas distribution utility will continue to grow through customer additions, productivity
enhancements, modernization investments and facilities that blend H2 and RNG into gas supply,
and expansion of our demand-side management and distributed energy programs.
• Our mature capabilities in the offshore and onshore wind sector position us well to compete for
new projects across the development cycle in Europe and North America, while our multi-year
program to self-power existing pipeline compressor stations represents highly visible and scalable
growth.
Maintain Financial Strength and Flexibility
The maintenance of our financial strength is critical to our strategy. Our financing strategies are designed
to retain strong investment-grade credit ratings to ensure that we have the financial capacity to meet our
capital funding needs and the flexibility to manage capital market disruptions. Our current secured capital
program, which extends to 2024, can be readily financed through internally generated cash flow and
available balance sheet capacity without issuance of additional common equity and we will seek to secure
new growth within our “self-funded” equity model. In addition, we continue to look at opportunities to
monetize non-core assets at attractive valuations. For further discussion on our financing strategies, refer
to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources.
Disciplined Capital Allocation
We assess the latest fundamental trends, monitor the business landscape and proactively conduct
business development activities with the goal of identifying an industry-leading opportunity set for capital
deployment. Opportunities are screened, analyzed and assessed using a disciplined investment
framework with the objective of ensuring effective deployment of capital to achieve attractive risk-adjusted
returns, while maintaining our low-risk “utility-like” business model.
All investment opportunities are evaluated based on their potential to advance our strategy, mitigate risk,
support our ESG goals, and create additional financial flexibility. Our primary emphasis in the near term is
on low capital-intensive opportunities to enhance returns in existing businesses (organic expansions and
optimizations), modernization of our systems and utility rate-based investments. Execution risk remains
high for large scale, long-duration development projects and, therefore, our focus will be on projects
where we can carefully manage at-risk capital during the permitting and construction phases.
In evaluating typical investment opportunities, we also consider other potential capital allocation
alternatives. Other alternatives for capital deployment depend on our current outlook and include further
dividend increases, further debt reduction, and/or share re-purchases.
Adapt to Energy Transition Over Time
As the global population grows and standards of living continue to improve around the world, more energy
will be needed. At the same time, our society increasingly recognizes the impacts of greenhouse gas
emissions on the world’s climate. Accordingly, energy systems are being reshaped as industry
participants, regulators and consumers seek to lower emissions. As a diversified energy infrastructure
company, we are well positioned to play a key role in the transition to a low-emissions economy by
leading the development of the future energy systems and partnering with customers on their low-carbon
strategies, while at the same time working to reduce our own emissions. Furthermore, we have tested our
assets for various energy transition scenarios and concluded that they are highly resilient and can be
relied upon for stable cash flow generation well into the future.
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We believe that diversification and innovation will play a significant role in the transition to a low-carbon
future. To date, we have made large investments in natural gas infrastructure and continue to see
significant opportunity in renewable energy. Our focus areas in renewable energy remain in offshore wind
and utility-scale onshore projects. We are also taking a leadership role in other low-carbon platforms like
CCS, H2 and RNG where we can leverage our infrastructure capability and stakeholder relationships to
accelerate growth and extend the value of our existing assets. Additionally, all new investments that we
make will need to have a clear path to achieve net zero emissions.
We recognize our customer's expectations of a transition to a lower-carbon economy and are working
actively to be a differentiated service provider by leveraging our ESG leadership and world-class
execution capabilities.
STRATEGIC ENABLERS
Our success in executing on our strategic priorities is enabled by our commitment to ESG, the quality and
capabilities of our people, and the extent to which we embrace technology and innovation as a
competitive advantage.
ESG
Sustainability is integral to our ability to safely and reliably deliver the energy people need and want. How
well we perform as a steward of our environment; as a safe operator of essential energy infrastructure; as
a diverse and inclusive employer; and as a responsible corporate citizen is inextricably linked to our ability
to achieve our strategic priorities and create long-term value for all stakeholders.
Our commitment to strong ESG practices and performance has long been core to how we do business
and we are proud to be recognized as a leader amongst our peers. In 2020, we set out ambitious goals1
including:
•
•
•
•
Net zero GHG emissions by 2050 with an interim target to reduce GHG emissions intensity 35%
by 2030 compared to the 2018 baseline.
Increased representation of diverse groups within our workforce by 2025, including representation
goals of 40% women and 28% racial and ethnic groups, along with new initiatives to enhance
supplier diversity.
Strengthening diversity on our Board with representation goals of 40% women and 20% racial
and ethnic groups by 2025.
Annual safety and reliability targets that drive continuous improvement towards our goal of zero
incidents, injuries, and implementation of robust cyber defense programs.
Beginning in 2021, we began linking ESG performance to incentive compensation and are making
meaningful progress toward these targets by executing on specific action plans. In addition, we issued our
first sustainability-linked loan and sustainability-linked bond that ties our financing to our ESG goals.
1 All percentages or specific goals regarding inclusion, diversity, equity and accessibility are aspirational goals which we intend to
achieve in a manner compliant with state, local, provincial and federal law, including, but not limited to, US federal regulations,
Equal Employment Opportunity Commission, Department of Labor and Office of Federal Contract Compliance Programs.
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Enbridge aims to continuously strengthen its approach to emissions reporting and reduction and is
expanding its approach to include the following additional actions:
•
•
Ensure that investment decision making aligns with Enbridge’s interim and long-term emissions
reduction goals.
Continue to proactively work with the organizations developing science-based guidelines for
emissions targets in the midstream sector.
• Work with key suppliers to support the further reduction of Scope 3 emissions.
•
Further develop low carbon energy partnerships to drive innovation across our business, with a
focus on renewable power, renewable natural gas, hydrogen and carbon capture.
Achieving our goals will put us in a better position to successfully transition to a low-carbon, more diverse,
and inclusive future.
People
Our employees are essential to our long-term success and enhancing the capability of our people to
maximize their potential is a key area of focus. We value diversity, and diverse thought, and have
embedded inclusive practices in our programs and approach to people management. Furthermore, we
strive to maintain industry competitive compensation, flexibility, and retention programs that provide both
short-term and long-term performance incentives.
Technology
Given the competitive climate of today’s energy sector, we recognize the vital role technology can play in
helping to achieve our strategic objectives. We’re committed to pursuing innovation and technology
solutions that further improve our safety performance, maximize revenues, improve efficiencies, and
enable transition to new, cleaner energy solutions. Our two Technology and Innovation labs, located in
Calgary and Houston, embody our commitment to technology enabled business solutions. Leveraging the
benefits of technology to contribute to safety, reliability and the profitability of assets has become
entrenched in our everyday operations.
We provide annual progress updates related to the above initiatives, along with our assumptions and
other relevant information, in our annual Sustainability Report which can be found at https://
www.enbridge.com/sustainability-reports. Unless otherwise specifically stated, none of the
information contained on, or connected to, the Enbridge website, including our annual
Sustainability Report, is incorporated by reference in, or otherwise part of, this Annual Report on
Form 10-K.
BUSINESS SEGMENTS
Our activities are carried out through five business segments: Liquids Pipelines; Gas Transmission and
Midstream; Gas Distribution and Storage; Renewable Power Generation; and Energy Services, as
discussed below.
13
LIQUIDS PIPELINES
Liquids Pipelines consists of pipelines and terminals in Canada and the US that transport and export
various grades of crude oil and other liquid hydrocarbons.
14
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 crude oil and other liquid
hydrocarbons within western Canada and from western Canada to the Canada/US border near Gretna,
Manitoba and Neche, North Dakota and from the US/Canada border near Port Huron, Michigan and
Sarnia, Ontario to eastern Canada and the northeastern US. The Canadian Mainline includes six adjacent
pipelines with a combined operating capacity of approximately 3.1 million barrels per day (mmbpd) that
connect with the Lakehead System at the Canada/US border, as well as five pipelines that deliver crude
oil and refined products into eastern Canada and the northeastern US. We have operated, and frequently
expanded, the Canadian Mainline since 1949. The Lakehead System is the portion of the Mainline
System in the US. 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 US.
Tolling Framework
The Competitive Toll Settlement (CTS) which governed tolls paid for products shipped on the Canadian
Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis, expired on June 30,
2021. The CTS was a 10-year negotiated agreement and provided for a Canadian Local Toll (CLT) for
deliveries within western Canada, as well as an International Joint Tariff (IJT) for crude oil shipments
originating in western Canada, on the Canadian Mainline, and delivered into the US, via the Lakehead
System, and into eastern Canada. The IJT tolls were denominated in US dollars.
On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to
implement contracting on our Canadian Mainline System. On November 26, 2021, the CER denied the
application on the basis that, among other things, contracting as proposed would result in a significant
change to access the Canadian Mainline and potentially inequitable outcomes to some shippers and non-
shippers without a compelling justification.
Effective July 1, 2021, the Mainline System is on Interim Tolls which will remain in effect until new tolls are
approved by the CER. In accordance with the terms of the CTS, Interim Tolls are equal to the CTS exit
tolls on June 30, 2021 and are subject to finalization and adjustment applicable to the interim period, if
any. We are currently exploring, with customers and other stakeholders, alternatives that may include: a
modified and extended CTS, a new incentive rate-making agreement, or a cost-of-service rate-making
structure. Any negotiated settlement would require CER approval before implementation. New tolling
framework clarity is expected by 2023.
Shippers continue to nominate volumes on a monthly basis and we continue to allocate capacity to
maximize the efficiency of the Mainline System.
Local tolls for service on the Lakehead System are not affected by Interim Tolls and continue to be
established pursuant to the Lakehead System’s existing toll agreements, as described below. Under
Interim Tolls, the Canadian Mainline’s share of the toll relating to pipeline transportation of a batch from
any western Canada receipt point to the US border is equal to the toll applicable to that batch’s US
delivery point less the Lakehead System’s local toll to that delivery point. While on Interim Tolls, we will
continue to refer to this amount as the Canadian Mainline IJT Residual Benchmark Toll which is
denominated in US dollars.
15
Lakehead System Local Tolls
Transportation rates are governed by the FERC for deliveries from the Canada/US border near Neche,
North Dakota, Clearbrook, Minnesota and other points to principal delivery points on the Lakehead
System. 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 index rates and the
Facilities Surcharge Mechanism. Index rates, the base portion of the transportation rates for the
Lakehead System, are subject to an annual inflationary 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 of each
year. To the extent that the Lakehead System transportation rates materially under-recover the Lakehead
System cost of service, an application can be made with the FERC to seek approval to increase the rates
in order to bring recoveries in-line with costs.
On May 21, 2021, we filed a cost-of-service application to raise our base rates effective July 1, 2021. On
June 30, 2021, the FERC issued an order to accept the rates subject to refund. This matter is currently in
the FERC settlement process.
REGIONAL OIL SANDS SYSTEM
The Regional Oil Sands System includes five intra-Alberta long-haul pipelines; the Athabasca Pipeline,
Waupisoo Pipeline, Woodland Pipeline, Wood Buffalo Extension/Athabasca Twin pipeline system and the
Norlite Pipeline System (Norlite), as well as two large terminals: the Athabasca Terminal located north of
Fort McMurray, Alberta and the Cheecham Terminal, located south of Fort McMurray, Alberta. The
Regional Oil Sands System also includes numerous laterals and related facilities which currently provide
access for oil sands production from twelve producing oil sands projects.
The combined capacity of the intra-Alberta long-haul pipelines is approximately 1,090 kbpd to Edmonton
and 1,370 kbpd into Hardisty, with Norlite providing approximately 218 kbpd of diluent capacity into the
Fort McMurray region. We have a 50% interest in the Woodland Pipeline and a 70% interest in Norlite.
The Regional Oil Sands System is anchored by long-term agreements with multiple oil sands producers
that provide cash flow stability and also include provisions for the recovery of some of the operating costs
of this system.
GULF COAST AND MID-CONTINENT
Gulf Coast includes Seaway Crude Pipeline System (Seaway Pipeline), Flanagan South Pipeline
(Flanagan South), Spearhead Pipeline, Gray Oak Pipeline and the Enbridge Ingleside Energy Center
(EIEC), as well as the Mid-Continent System (Cushing Terminal).
We have a 50% interest in the 1,078-kilometer (670-mile) 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. Total aggregate capacity on the Seaway Pipeline system is approximately 950 kbpd. Seaway
Pipeline also includes 8.8 million barrels of crude oil storage tank capacity on the Texas Gulf Coast.
Flanagan South is a 950-kilometer (590-mile), 36-inch diameter interstate crude oil pipeline that originates
at our terminal at Flanagan, Illinois, a delivery point on the Lakehead System, and terminates in Cushing,
Oklahoma. Flanagan South has a capacity of approximately 600 kbpd.
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 has a capacity of
approximately 193 kbpd.
16
The Gray Oak pipeline is a 1,368-kilometer (850-mile) crude oil system, which runs from the Permian
Basin in West Texas to the US Gulf Coast. The Gray Oak pipeline has an expected average annual
capacity of 900 kbpd and transports light crude oil. We have an effective 22.8% interest in the pipeline.
Initial in-service for the pipeline commenced in November 2019 with full service achieved in the second
quarter of 2020.
The Mid-Continent System is comprised of storage terminals at Cushing, Oklahoma (Cushing Terminal),
consisting of over 80 individual storage tanks ranging in size from 78 to 570 thousand 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 are 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, as well
as blending fees.
In October 2021, we acquired a 100 percent operating interest in the Ingleside Energy Center (renamed
the Enbridge Ingleside Energy Center (EIEC)), located near Corpus Christi, Texas. This terminal is
comprised of 15.6 million barrels of storage and 1.5 million barrels per day of export capacity. We also
acquired a 20% interest in the 670-kbpd Cactus II Pipeline, a 100% interest in the 300-kbpd Viola
pipeline, and a 100% interest in the 350-thousand-barrel Taft Terminal.
OTHER
Other includes Southern Lights Pipeline, Express-Platte System, Bakken System and Feeder Pipelines
and Other.
Southern Lights Pipeline is a single stream 180 kbpd 16/18/20-inch diameter 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. Both the
Canadian portion of Southern Lights Pipeline and the US portion of Southern Lights Pipeline receive tariff
revenues under long-term contracts with committed shippers. Southern Lights Pipeline capacity is 90%
contracted with the remaining 10% of the capacity assigned for shippers to ship uncommitted volumes.
The Express-Platte System consists of 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) long crude oil
transportation system, which begins at Hardisty, Alberta, and terminates at Wood River, Illinois. The 310
kbpd Express pipeline carries crude oil to US refining markets in the Rocky Mountains area, including
Montana, Wyoming, Colorado and Utah. The 145 to 164 kbpd Platte pipeline, which interconnects with
the Express pipeline at 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.
The Bakken System consists of the North Dakota System and the Bakken Pipeline System. The North
Dakota System services the Bakken in North Dakota and is comprised of a crude oil gathering and
interstate pipeline transportation system. The gathering system provides delivery to Clearbrook,
Minnesota for service on the Lakehead system or a variety of interconnecting pipeline and rail export
facilities. The interstate portion of the system has both US and Canadian components that extend from
Berthold, North Dakota into Cromer, Manitoba.
Tariffs on the US portion of the North Dakota System are governed by the FERC. The Canadian portion is
categorized as a Group 2 pipeline, and as such, its tolls are regulated by the CER on a complaint basis.
Tolls on the interstate pipeline system are based on long-term take-or-pay agreements with anchor
shippers.
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We have an effective 27.6% interest in the Bakken Pipeline System, which connects the Bakken
formation in North Dakota to markets in eastern PADD II and the US Gulf Coast. The Bakken Pipeline
System consists of the DAPL from the Bakken area in North Dakota to Patoka, Illinois, and the Energy
Transfer Crude Oil Pipeline from Patoka, Illinois to Nederland, Texas. Current capacity is 750 kbpd of
crude oil with the potential to be expanded through additional pumping horsepower. 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
and the US.
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 the
Southern Access Extension (SAX) pipeline which originates in Flanagan, Illinois and delivers to Patoka,
Illinois. We have an effective 65% interest in the 300 kbpd SAX pipeline of which the majority of its
capacity is 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 Norman
Wells (NW) System. Patoka Storage is comprised of four storage tanks with 480 thousand barrels of shell
capacity located in Patoka, Illinois. The 101 kbpd Toledo pipeline system connects with the Lakehead
System and delivers to Ohio and Michigan. The 45 kbpd NW System transports crude oil from Norman
Wells in the Northwest Territories to Zama, Alberta and has a cost-of-service rate structure based on
established terms with shippers.
COMPETITION
Competition to our liquids pipelines network comes primarily from infrastructure or logistics alternatives
that transport liquid hydrocarbons from production basins in, which we operate, to markets in Canada, the
US and internationally. Competition from existing and proposed pipelines is based primarily on access to
supply, end use markets, the cost of transportation, contract structure and the quality and reliability of
service. Additionally, volatile crude price differentials and insufficient pipeline capacity on either our or
competitors' pipelines can make transportation of crude oil by rail competitive, particularly to markets not
currently served by pipelines.
We believe that our liquids pipelines systems will continue to provide competitive and attractive options to
producers in the Western Canadian Sedimentary Basin (WCSB), North Dakota, and more recently the
Permian Basin, due to our market access, competitive tolls and flexibility through our multiple delivery and
storage points. We also employ long-term agreements with shippers, which mitigates competition risk by
ensuring consistent supply to our liquids pipelines network. Our current complement of growth projects to
expand market access and to enhance capacity on our pipeline system will provide additional competitive
solutions for liquids transportation. We have a proven track record of successfully executing projects to
meet the needs of our customers.
SUPPLY AND DEMAND
We have an established and successful history of being the largest transporter of crude oil to the US, the
world’s largest market for crude oil. While US 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,
both domestic and global.
The COVID-19 pandemic had a significant negative impact on the crude oil market in 2020 with
decreased demand from the economic slowdown and government imposed mobility restrictions. However,
2021 has seen global crude oil demand recover to levels close to pre-pandemic highs. International prices
have strengthened to multi-year highs as global demand has outpaced the return of supply as publicly
traded producers have adopted a more disciplined approach to capital allocation for new drilling.
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Our Mainline System throughput, as measured at the Canada/US border at Gretna, Manitoba ended the
year delivering 3.1 million barrels per day, as the Line 3 Replacement program has come into service.
Refinery demand in the upper Midwest PADD II market has been strong given the economic recovery and
enhanced mobility demand. On the US Gulf Coast, lower supply of heavy crude from Latin America and
the Middle East is driving increased demand for Canadian heavy crude.
Global crude oil demand in most base case forecasts is expected to grow into the next decade, primarily
driven by emerging economies in regions outside the Organization for Economic Cooperation and
Development (OECD), such as India and China. In North America, demand growth for transportation fuels
is expected to moderate over time due to vehicle fuel efficiency improvement and increasing sales of
electric vehicles.
New supply to meet this growing demand will primarily come from Organization of the Petroleum
Exporting Countries (OPEC) countries and North America. Growth in supply from OPEC will be led by
Saudi Arabia and the United Arab Emirates with their significant low cost reserves and could be
supplemented by the return of sanctioned Iranian production. Growth in North America will be driven by
the Permian Basin which is a large and cost competitive light crude oil resource base. In addition, heavy
crude oil growth is expected from the WCSB as additional egress availability will support expansion of
existing projects and some potential new greenfield facilities.
The combination of long term demand growth in non-OECD nations, domestic demand contraction over
time, and continued production growth in the Permian Basin and WCSB highlights the importance of our
strategic asset footprint and reinforces the need for additional export oriented infrastructure. We are well
positioned to meet these evolving supply and demand fundamentals through expansion of system
capacity for incremental access to the US Gulf Coast, and through further development of our new
Enbridge Ingleside Energy Center in Corpus Christi, the largest crude oil export facility in North America.
Opposition to fossil fuel development in conjunction with evolving consumer preferences and new
technology could underpin accelerated energy transition scenarios impacting long term supply and
demand of crude oil. We continue to closely monitor the evolution of all of these factors to be able to pro-
actively adapt our business to help meet our customers’ and society’s energy needs.
Progress on the development and construction of our commercially secured growth projects is discussed
in Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - Growth Projects - Commercially Secured Projects.
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GAS TRANSMISSION AND MIDSTREAM
Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and
processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission,
US Midstream and other assets.
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US GAS TRANSMISSION
US Gas Transmission includes ownership interests in Texas Eastern Transmission, L.P. (Texas Eastern),
Algonquin Gas Transmission, LLC (Algonquin), Maritimes & Northeast (M&N) (US and Canada), East
Tennessee Natural Gas, LLC (East Tennessee), Gulfstream Natural Gas System, L.L.C. (Gulfstream),
Sabal Trail Transmission (Sabal Trail), NEXUS Gas Transmission Pipeline (NEXUS), Valley Crossing
Pipeline, LLC. (Valley Crossing), Southeast Supply Header (SESH), 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 northeastern, southern and midwestern US.
The Texas Eastern natural gas transmission system extends from supply and demand centers in the Gulf
Coast region of Texas and Louisiana to supply and demand centers in Ohio, Pennsylvania, New Jersey
and New York. Texas Eastern's onshore system has a peak day capacity of 13.09 billion cubic feet per
day (bcf/d) of natural gas on approximately 13,807-kilometers (8,579-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 through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it
connects to M&N US. The system has a peak day capacity of 3.09 bcf/d of natural gas on approximately
1,820-kilometers (1,131-miles) of pipeline with associated compressor stations.
M&N US has a peak day capacity of 0.83 bcf/d of natural gas on approximately 552-kilometers (343-
miles) of 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
Canada has a peak day capacity 0.55 bcf/d on approximately 885-kilometers (550-miles) of interprovincial
natural gas transmission mainline system that extends from Goldboro, Nova Scotia to the US border near
Baileyville, Maine. We have a 78% interest in M&N US and M&N Canada.
East Tennessee’s natural gas transmission system has a peak day capacity of 1.86 bcf/d of natural gas,
crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems
totaling approximately 2,456-kilometers (1,526-miles) of pipeline in Tennessee, Georgia, North Carolina
and Virginia, with associated compressor stations. East Tennessee has a 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. Gulfstream has a peak day capacity of 1.31 bcf/d of natural gas from
Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and
southern Florida. We have a 50% interest in Gulfstream.
Sabal Trail is an approximately 832-kilometer (517-mile) pipeline that provides firm natural gas
transportation. Facilities include a pipeline, laterals and various compressor stations. The pipeline
infrastructure is located in Alabama, Georgia and Florida, and adds approximately 1.0 bcf/d of capacity
enabling the access of onshore gas supplies. We have a 50% interest in Sabal Trail.
NEXUS is an approximately 414-kilometer (257-mile) interstate natural gas transmission system with
associated compressor stations. NEXUS transports natural gas from our Texas Eastern system in Ohio to
our Vector interstate pipeline in Michigan, with peak day capacity of 1.4 bcf/d. Through its interconnect
with Vector, NEXUS provides a connection to Dawn Hub, the largest integrated underground storage
facility in Canada and one of the largest in North America, located in southwestern Ontario adjacent to the
Greater Toronto Area. We have a 50% interest in NEXUS.
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Valley Crossing is an approximately 285-kilometer (177-mile) intrastate natural gas transmission system,
with associated compressor stations. The pipeline infrastructure is located in Texas and provides market
access of up to 2.6 bcf/d of design capacity to the Comisión Federal de Electricidad, Mexico’s state-
owned utility.
SESH is an approximately 462-kilometer (287-mile) natural gas transmission system with associated
compressor stations. SESH extends from the Perryville Hub in northeastern Louisiana where the shale
gas production of eastern Texas, northern Louisiana and Arkansas, along with conventional production, is
reached from six major interconnections. SESH extends to Alabama, interconnecting with 14 major north-
south pipelines and three high-deliverability storage facilities and has a peak day capacity of 1.1 bcf/d of
natural gas. We have a 50% interest in SESH.
Vector is an approximately 560-kilometer (348-mile) pipeline travelling between Joliet, Illinois in the
Chicago area and Ontario. Vector can deliver 1.745 bcf/d of natural gas, of which 455 million cubic feet
per day (mmcf/d) is leased to NEXUS. We have a 60% interest in Vector.
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, 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 and are generally at a higher toll than long-term contracted rates.
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
Canadian Gas Transmission is comprised of Westcoast Energy Inc.’s (Westcoast) British Columbia (BC)
Pipeline, Alliance Pipeline and other minor midstream gas gathering pipelines.
BC Pipeline has a peak day capacity of 3.6 bcf/d of natural gas on approximately 2,950-kilometers (1,833-
miles) of transmission pipeline in BC and Alberta that includes associated mainline compressor stations. It
provides cost-of-service based natural gas transmission services.
Alliance Pipeline is an approximately 3,000-kilometer (1,864-mile) integrated, high-pressure natural gas
transmission pipeline with approximately 860-kilometers (534-miles) of lateral pipelines and related
infrastructure. It transports liquids-rich natural gas from northeast BC, 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 system has a peak day capacity of 1.8 bcf/d
of natural gas. We have a 50% interest in Alliance Pipeline.
The majority of transportation services provided by Canadian Gas Transmission 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. Canadian Gas Transmission also provides 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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US MIDSTREAM
US Midstream includes a 42.7% interest in each of Aux Sable Liquid Products LP and Aux Sable
Midstream LLC, and a 50% interest in Aux Sable Canada LP (collectively, 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 connected to Alliance
Pipeline that facilitate delivery of liquids-rich natural gas for 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 BC, comprising the Septimus Pipeline. Aux Sable Canada also owns a facility which
processes refinery/upgrader offgas in Fort Saskatchewan, Alberta.
US Midstream also includes a 50% investment in DCP Midstream, LLC (DCP Midstream), which indirectly
owns approximately 57% of DCP Midstream, LP, including limited partner and general partner interests.
DCP Midstream, LP is a master limited partnership, with a diversified portfolio of assets, engaged in the
business of gathering, compressing, treating, processing, transporting, storing and selling natural gas;
producing, fractionating, transporting, storing and selling NGLs; and recovering and selling condensate.
DCP Midstream, LP owns and operates more than 36 plants and approximately 90,123-kilometers
(56,000-miles) of natural gas and natural gas liquids pipelines, with operations in nine states across major
producing regions.
OTHER
Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 11 natural
gas gathering and FERC regulated transmission pipelines and four oil pipelines. 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 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, nuclear 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 exists in all markets that our businesses serve. Competitors include interstate/interprovincial
and intrastate/intraprovincial 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.
SUPPLY AND DEMAND
Our gas transmission assets make up one of the largest natural gas transportation networks in North
America, driving connectivity between prolific supply basins and major demand centers within the
continent. Our systems have been integral to the transition in supply and demand markets over the last
decade and will continue to play a part as the energy landscape evolves.
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In 2010, natural gas production in each of the Appalachian and Permian basins were less than 5.0 bcf/d
each. Today, these regions produce more than 47.5 bcf/d of natural gas on a combined basis. Improved
technology and increased shale gas drilling have increased the supply of low-cost natural gas. As well,
there has been and continues to be a corresponding increase in demand for our natural gas infrastructure
in North America. Through a series of expansions and reversals on our core systems, combined with the
execution of greenfield projects and strategic acquisitions, we have been able to meet the needs of
producers and consumers alike. Our US Gas Transmission systems were initially designed to transport
natural gas from the Gulf Coast to the supply starved northeast markets. Our asset base now has the
capability to transport diverse bi-directional supply to the northeast, southeast, midwest, Gulf Coast and
LNG markets on a fully subscribed and highly utilized basis.
The northeast market continues its role as a predominantly supply constrained region with steady
demand. The bi-directional capabilities offered by our US Gas Transmission system allows us to deliver in
an efficient manner to our regional customers. The region has seen an increase in natural gas supply due
to the development of the Marcellus and Utica shales in the Appalachia region.
The southeast market is linked to multiple, highly liquid supply pools that include the Marcellus and Utica
shale developments, offering consistent supply and stable pricing to a growing population of end-use
customers across our multiple systems under long term, utility-like arrangements.
With connectivity to Appalachian and western Canadian supply through our systems, the midwest market
has access to two of the lowest cost gas producing regions on the continent. As demand in the region is
expected to continue to grow by approximately 2.0 bcf/d over the next two decades, maintaining this link
will remain important. Flexibility in supply for this market is especially critical to maintaining liquidity and
price stability as natural gas continues to replace coal-fired generation.
Gulf Coast demand growth is being driven by an increase in the volume of LNG exports, an ongoing wave
of gas-intensive petrochemical facilities, along with power generation and additional pipeline exports to
Mexico. Demand to these markets in the region is anticipated to grow by more than 23.0 bcf/d through
2040. The Gulf Coast market has been the beneficiary of low cost capacity on our assets as the
relationship between supply and market centers has shifted. Such cost-effective capacity is difficult to
access or replicate, offering existing shippers and transporters stability of capacity and utilization. Tide-
water market access and proximity to Mexico continue to make this region a platform of global trade as
pipeline and LNG exports continue their growth trajectory. The US exported over 11 bcf/d of natural gas to
LNG markets, primarily from the Gulf Coast region, at the end of 2021.
Western Canada, not unlike other supply hubs, is a source of low-cost supply seeking access to premium
markets in North America and globally. One of the few vital links to demand centers in the pacific
northwest are our own systems in the region, which are highly utilized.
Global energy demand is expected to increase approximately 27% 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 approximately
23% during this period as one of the world’s fastest growing energy sources. North American exports will
play a significant part in meeting global demand, underscoring the ability of our assets to remain highly
utilized by shippers, and highlighting the need for incremental transportation solutions across North
America. In response to these global fundamentals, we believe we are well positioned to provide value-
added solutions to shippers. Opposition to natural gas development, including new pipeline projects, has
been increasing in recent years. This may challenge continued growth of the North American gas market
and the ability to efficiently connect supply and demand. We are responding to the need for regional
infrastructure with additional investments in Canadian and US gas transportation facilities. Progress on
the development and construction of our commercially secured growth projects is discussed in Part II.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth
Projects - Commercially Secured Projects.
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GAS DISTRIBUTION AND STORAGE
Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge
Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers throughout
Ontario. This business segment also includes natural gas distribution activities in Québec and previously
included an investment in Noverco Inc. (Noverco) which was sold on December 30, 2021. Please refer to
Part II. Item 8. Financial Statements and Supplementary data - Note 8 - Acquisitions and Dispositions for
further details.
ENBRIDGE GAS
Enbridge Gas is a rate-regulated natural gas distribution utility with storage and transmission services that
has been in operation for 173 years. Enbridge Gas serves approximately 75% of Ontario residents via
approximately 3.8 million residential, commercial and industrial meter connections.
There are three principal interrelated aspects of the natural gas distribution business in which Enbridge
Gas is directly involved: Distribution, Transportation and Storage.
In 2021, Enbridge Gas implemented a voluntary RNG pilot program, whereby customers can voluntarily
contribute towards the incremental cost of low carbon RNG to displace regular natural gas, and a pilot
project which allows regular natural gas to be blended with H2, in an isolated portion of the existing
distribution system, in an effort to gain insight into the use of H2 as a method for decarbonizing natural
gas for the purpose of reducing GHG emissions.
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Distribution
Enbridge 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 are usually on an annual contract basis under firm or interruptible
service contracts. Under a firm contract, Enbridge Gas is obligated to deliver natural gas to the customer
up to a maximum daily volume. The service provided under an interruptible contract is similar to that of a
firm contract, except that it allows for service interruption at Enbridge Gas’ option primarily to meet
seasonal or peak demands. The Ontario Energy Board (OEB) approves rates for both contract and
general services. The distribution system consists of approximately 147,000-kilometers (91,342-miles) of
pipelines that carry natural gas from the point of local supply to customers.
Customers have a choice with respect to natural gas supply. Customers may purchase and deliver their
own natural gas to points upstream of the distribution system or directly into Enbridge Gas’ distribution
system, or, alternatively, they may choose a system supply option, whereby customers purchase natural
gas from Enbridge Gas’ supply portfolio. To acquire the necessary volume of natural gas to serve its
customers, Enbridge Gas maintains a diversified natural gas supply portfolio, acquiring supplies on a
delivered basis in Ontario, as well as acquiring supply from multiple supply basins across North America.
Transportation
Enbridge Gas contracts for firm transportation service, primarily with TransCanada Pipelines Limited
(TransCanada), Vector and NEXUS, to meet its annual natural gas supply requirements. The
transportation service contracts are not directly linked with any particular source of natural gas supply.
Separating transportation contracts from natural gas supply allows Enbridge Gas flexibility in obtaining its
own natural gas supply and accommodating the requests of its direct purchase customers for assignment
of TransCanada capacity. Enbridge Gas forecasts the natural gas supply needs of its customers,
including the associated transportation and storage requirements.
In addition to contracting for transportation service, Enbridge Gas offers firm and interruptible
transportation services on its own Dawn-Parkway pipeline system. Enbridge Gas’ transmission system
consists of approximately 5,500-kilometers (3,418-miles) of high-pressure pipeline and five mainline
compressor stations and has an effective peak daily demand capacity of 7.6 bcf/d. Enbridge Gas’
transmission system also links an extensive network of underground storage pools at the Tecumseh Gas
Storage facility and Dawn Hub (collectively, Dawn) to major Canadian and US markets, and forms an
important link in moving natural gas from western Canada and US supply basins to central Canadian and
northeastern US markets.
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 US. Enbridge Gas delivered 1,943 bcf of gas
through its distribution and transmission system in 2021. A substantial amount of Enbridge Gas’
transportation revenue is generated by fixed annual demand charges, with the average length of a long-
term contract being approximately 15 years and the longest remaining contract term being 19 years.
Storage
Enbridge Gas’ 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 Enbridge Gas 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 Enbridge Gas 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 Enbridge Gas’ franchise areas.
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Enbridge Gas’ storage facility at Dawn is located in southwestern Ontario, and has a total working
capacity of approximately 281 bcf in 34 underground facilities located in depleted gas fields. Dawn is the
largest integrated underground storage facility in Canada and one of the largest in North America.
Approximately 180 bcf of the total working capacity is available to Enbridge Gas for utility operations.
Enbridge Gas also has storage contracts with third parties for 21 bcf of storage capacity.
Dawn offers customers an important link in the movement of natural gas from western Canadian and US
supply basins to markets in central Canada and the northeast US. 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 2021, Dawn provided services such as storage, balancing,
gas loans, transport, exchange and peaking services to over 200 counterparties.
A substantial amount of Enbridge Gas’ storage revenue is generated by fixed annual demand charges,
with the average length of a long-term contract being approximately four years and the longest remaining
contract term being 15 years.
NOVERCO
Noverco is a holding company that wholly-owns Énergir, LP (Énergir), formerly known as Gaz Metro
Limited Partnership, a natural gas distribution company operating in Québec, with interests in subsidiary
companies operating gas transmission, gas distribution and power distribution businesses in Québec and
Vermont. Énergir serves approximately 525,000 residential and industrial customers and is regulated by
the Québec Régie de l’énergie and the Vermont Public Utility Commission. Noverco also holds an
investment in our common shares. We owned an equity interest in Noverco through ownership of 38.9%
of its common shares and an investment in its preferred shares. On December 30, 2021, we sold our
38.9% non-operating minority ownership interest in Noverco to Trencap L.P. for $1.1 billion in cash.
GAZIFÈRE
We wholly own Gazifère, a natural gas distribution company that serves approximately 44,000 customers
in western Québec, a market not served by Énergir. Gazifère is regulated by the Québec Régie de
l’énergie.
COMPETITION
Enbridge Gas’ distribution system is regulated by the OEB and is subject to regulation in a number of
areas, including rates. Enbridge Gas is not generally subject to third-party distribution competition within
its franchise areas.
Enbridge Gas competes with other forms of energy available to its customers and end-users, including
electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include weather,
price changes, the availability of natural gas and other forms of energy, the level of business activity,
conservation, legislation including the federal carbon pricing law, governmental regulations, the ability to
convert to alternative fuels and other factors.
SUPPLY AND DEMAND
We expect that demand for natural gas in North America will continue to see steady annual growth over
the long term with continued growth in peak day demands, however there are risks to the natural gas
market that may challenge its growth prospects. Evolving customer preferences for lower-carbon fuels
and more efficient technologies, combined with increasing opposition to natural gas development in North
America, may reduce the markets’ ability to efficiently deploy capital to connect supply and demand. We
monitor these factors closely to be able to develop our business strategy to align with shifts in customer
preferences.
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We expect demand for natural gas connections in Ontario to maintain its recent growth profile due to
continued population growth and with competitively priced natural gas expected to continue to provide a
significant price advantage relative to alternate energy options, even with increasing carbon charges.
Specific interest in natural gas connections is expected to come from communities that are not currently
serviced by natural gas in Ontario.
Enbridge Gas continues to focus on promoting conservation and energy efficiency by undertaking
activities focused on reducing natural gas consumption through various demand side management
programs offered across all markets and sourcing supply with a smaller carbon footprint. In addition to our
existing RNG programs, we are also expanding our efforts in other low-carbon supply sourcing such as
Responsibly Sourced Natural Gas, and Hydrogen Gas.
The storage and transportation marketplace continues to respond to changing natural gas supply
dynamics, including a recovering supply environment which was negatively impacted by the global
pandemic.
Over the past decade, growth in the North American gas supply landscape, driven mainly by the
development of unconventional gas resources in the Montney, Permian, Marcellus and Utica supply
basins, has resulted in lower annual commodity prices and narrower seasonal price spreads. Unregulated
storage values are primarily determined by the difference in value between winter and summer natural
gas prices. Storage values have been relatively stable as North American natural gas supply and demand
slowly returned to a more balanced position.
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RENEWABLE POWER GENERATION
Renewable Power Generation consists primarily of investments in wind and solar assets, as well as
geothermal, waste heat recovery, and transmission assets. In North America, assets are primarily located
in the provinces of Alberta, Saskatchewan, Ontario, and Québec and in the states of Colorado, Texas,
Indiana and West Virginia. We are also developing several solar self-power projects along our oil and gas
rights-of-way in North America. In Europe, we hold equity interests in operating offshore wind facilities in
the coastal waters of the United Kingdom and Germany, as well as interests in several offshore wind
projects under construction and active development in France. Further, we are pursuing new European
offshore wind development opportunities through Maple Power Ltd., a joint venture in which we hold a
50% interest.
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Combined Renewable Power Generation investments represent approximately 2,178 MW of net
generation capacity. Of this amount, approximately:
•
•
•
•
•
1,392 MW is generated by North American wind facilities;
255 MW is generated by European offshore wind facilities;
309 MW will be generated by the Saint-Nazaire, Fécamp and Calvados Offshore Wind projects,
all of which are currently under construction;
6 MW will be generated by the Provence Grand Large Floating Offshore Wind project, which
secured funding in 2021 and continues to prepare onshore construction; and
93 MW is generated by North American solar facilities in operation, with an additional 97 MW in
projects in early construction and under-construction.
The vast majority of the power produced from these facilities is sold under long-term Power Purchase
Agreements (PPAs).
Renewable Power Generation also includes our 25% interest in the East-West Tie, a 450-MW
transmission line in northwestern Ontario, which is currently under construction and is expected to reach
commercial operation in the first half of 2022.
JOINT VENTURES / EQUITY INVESTMENTS
The investments in the Canadian wind and solar assets (excluding self-power) and two of the US
renewable assets are held within a joint venture in which we maintain a 51% interest and which we
manage and operate.
•
•
•
•
We also own interests in European offshore wind facilities through the following joint ventures:
a 24.9% interest in Rampion Offshore Wind, located in the United Kingdom;
a 25.4% interest in Hohe See Offshore and its subsequent expansion, located in Germany;
a 25.5% interest in the Saint-Nazaire Offshore Wind project, under construction in France;
a 25% interest in the Provence Grande Large Floating Offshore Wind project, in pre-construction
in France;
a 17.9% interest in the Fécamp Offshore Wind project, under construction in France; and
a 21.7% interest in the Calvados Offshore Wind project, in pre-construction in France.
•
•
The ownership interest percentages in the Saint-Nazaire, Fécamp, and Calvados Offshore Wind projects
reflect the sale of 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to
the Canada Pension Plan Investment Board (CPP Investments) which closed in the first half of 2021.
COMPETITION
Renewable Power Generation operates in the North American and European power markets, which are
subject to competition and supply and demand fundamentals for power in the jurisdictions in which they
operate. The majority of revenue is generated pursuant to long-term PPAs (or has been substantially
hedged). As such, the financial performance is not significantly impacted by fluctuating power prices
arising from supply/demand imbalances or the actions of competing facilities during the term of the
applicable contracts. However, the renewable energy sector includes large utilities, small independent
power producers and private equity investors, which are expected to aggressively compete for new
project development opportunities and for the right to supply customers when contracts expire.
To grow in an environment of heightened competition, we strategically seek opportunities to collaborate
with well-established renewable power developers and financial partners and to target regions with
commercial constructs consistent with our low risk business model. In addition, we bring to bear the
expertise of completing and delivering large scale infrastructure projects.
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SUPPLY AND DEMAND
The renewable power generation network in North America and Europe is expected to grow significantly
over the next 20 years due to the replacement of older fossil fuel-based sources of electricity generation
in support of announced governmental carbon emissions reduction targets. Any additional governmental
actions toward reducing emissions and/or increasing electrification will further accelerate renewable
electricity demand growth and electrification across all sectors.
On the demand side, North American economic growth over the longer term and the continued
electrification and transition to low-carbon strategies within the residential, transportation and industrial
sectors are expected to drive growing electricity demand. Furthermore, voluntary GHG emissions targets
are becoming increasingly expected by stakeholders, which is driving significant demand from corporate
electricity end-users for clean electricity and environmental attributes. However, continued efficiency gains
are expected to make the economy less energy-intensive and temper overall demand growth.
On the supply side in North America, legislation is accelerating the retirement of aging coal-fired
generation, while generation from conventional nuclear power is also forecast to decline. As a result,
North America requires significant new generation capacity from preferred technologies. Gas-fired and
renewable energy facilities, including solar and wind (which make up the bulk of our renewable power
assets), are generally the preferred sources to replace coal-fired generation due to their low carbon
intensities.
The falling capital and operating costs of wind and solar, combined with their improving capacity factors,
are expected to continue the ongoing trend of making renewable energy more competitive and support
investment over the long-term, regardless of available government incentives. Generation from renewable
sources is expected to double over the next two decades in North America. Aside from the construction of
new wind and solar facilities, other growth opportunities include repowering projects to increase output
from, and extending the project-life of, our existing facilities.
In Europe, the renewable energy outlook is robust. Demand for electricity is expected to gradually
increase over the next two decades, driven by electrification of transportation and buildings. Energy
efficiency gains will temper, but not eliminate, demand growth. Renewable power will play a significant
role in the United Kingdom’s ability to meet their aggressive low-carbon and renewable energy targets,
particularly offshore wind.
On the supply side, the International Energy Agency expects coal to fall by more than 90% from 2020
levels, while nuclear falls by one-third, by 2040. Over the same period, it anticipates power generation
from renewable sources will more than double, including installed (onshore and offshore) wind more than
doubling and photovoltaics solar power nearly tripling. We, through our European joint ventures, continue
to invest in offshore wind projects in the United Kingdom, France and Germany, and to explore
opportunities, to meet the growing demand.
ENERGY SERVICES
The Energy Services businesses in Canada and the US provide physical commodity marketing and
logistical services to North American refiners, producers, and other customers.
Energy Services is primarily focused on servicing customers across the value chain and capturing value
from quality, time, and location price differentials when opportunities arise. To execute these strategies,
Energy Services transports and stores on both Enbridge-owned and third party assets using a
combination of contracted long-term and short-term pipeline, storage, railcar, and truck capacity
agreements.
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COMPETITION
Energy Services’ earnings are primarily generated from arbitrage opportunities which, by their nature, can
be replicated by competitors. An increase in market participants entering into similar arbitrage strategies
could have an impact on our earnings. Efforts to mitigate competition risk include diversification of the
marketing business by transacting at the majority of major hubs in North America and establishing long-
term relationships with clients and pipelines.
ELIMINATIONS AND OTHER
Eliminations and Other includes operating and administrative costs that are not allocated to business
segments and the impact of foreign exchange hedge settlements. Eliminations and Other also includes
new business development activities and corporate investments.
REGULATION
GOVERNMENT REGULATION
Pipeline Regulation
Our Liquids Pipelines and Gas Transmission and Midstream assets are subject to numerous 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.
In the US, our interstate pipeline operations are subject to pipeline safety laws and regulations
administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency within
the United States Department of Transportation. 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 and to operate them at permissible pressures.
PHMSA continues to review existing regulations and establish new regulations to support safety
standards that are designed to improve and expand operations integrity management processes. 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 failure 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, capital expenditures, earnings, cash flows, financial condition and competitive
advantage.
Our ability to establish transportation and storage rates on our US interstate natural gas facilities are
subject to regulation by the FERC, whose rulings and policies could have an adverse impact on the ability
of such pipeline and storage assets to recover their respective full cost of operating, including a
reasonable rate of return. Regulatory or administrative actions by FERC such as rate proceedings,
applications to certify construction of new facilities, and depreciation and amortization policies can affect
our business, including decreasing tariff rates and revenues and increasing our costs of doing business.
In Canada, our pipeline operations are subject to pipeline safety regulations administered by the CER or
provincial regulators. Applicable legislation and regulations 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.
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As in the US, several legislative changes addressing pipeline safety in Canada have recently been
enacted. 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 CER 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.
A key component of pipeline safety and reliability is the approach to integrity management that uses
reliability targets and safety case assessments. A long history of extensive inline inspection has provided
detailed knowledge of the assets in our pipeline systems. Our pipelines are assessed and maintained, in
a proactive manner, such that the probability of a release is sufficiently low and that our reliability targets
are met. Furthermore, the integrity management program has an independent step to check the results of
our integrity assessments to validate the effectiveness of the program and to ensure that the operational
risk remains as low as reasonably practicable throughout the integrity inspection and assessment cycle.
As inspection technology, pipeline materials and construction practices improve with time, and new data
on threats and pipeline condition are gathered, our methods of maintaining fitness for service evolves,
with a strong focus on continual improvement in every aspect of integrity management.
Our pipelines also face economic regulation risk. Broadly defined, economic regulation risk is the risk that
governments or regulatory agencies change or reject proposed or existing commercial arrangements or
policies, including permits and regulatory approvals for both new and existing projects or agreements,
upon which future and current operations are dependent. Our Mainline System and other liquids pipelines
and gas transmission facilities are subject to the actions of various regulators, including the CER and the
FERC, with respect to the tariffs and tolls of those pipelines. The changing or rejecting of commercial
arrangements, including decisions by regulators on the applicable permits and tariff structure or changes
in interpretations of existing regulations by courts or regulators, could have an adverse effect on our
revenues and earnings.
Gas Distribution and Storage
Our gas distribution and storage utility operations are regulated by the OEB and the Québec Régie de
l’énergie, among others. 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 amounts that would have been recorded on the Consolidated
Statements of Financial Position in the absence of the effects of regulation, could be different from the
amounts that are eventually recovered or refunded.
Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year incentive regulation (IR)
framework using a price cap mechanism. The price cap mechanism establishes new rates each year
through an annual base rate escalation at inflation less a 0.3% productivity factor, annual updates for
certain costs to be passed through to customers, and where applicable, the recovery of material discrete
incremental capital investments beyond those that can be funded through base rates. The IR framework
includes the continuation and establishment of certain deferral and variance accounts, as well as an
earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in
excess of 150 basis points over the annual OEB approved return on equity (ROE).
We retain dedicated professional staff and maintain strong relationships with customers, intervenors and
regulators. This strong regulatory relationship continued in 2021 following OEB Decisions and Orders
approving Phase 2 of Enbridge Gas’ application for 2021 rates and Phase 1 of Enbridge Gas’ application
for 2022 rates. The Phase 2 Decision and Order approved the funding of $124 million in 2021 discrete
incremental capital investment requested through the incremental capital module, while the Phase 1
Decision and Order approved 2022 base rate escalation under the price cap mechanism.
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Enbridge Gas continues to develop opportunities to support a low-carbon future in Ontario. In 2021, we
received OEB approval of an Integrated Resource Planning (IRP) framework. The framework requires
Enbridge Gas to consider facility and non-pipe demand and/or supply side alternatives (IRP alternatives)
to address systems needs of its regulated operations, where certain parameters have been met. The
framework will also allow Enbridge Gas to pursue an IRP alternative (or combination of IRP and facility
alternative) where it is found to be in the best interest of Enbridge Gas and its customers, taking into
account reliability and safety, cost-effectiveness, public policy, optimized scoping, and risk management.
Renewable Power Generation
Renewable Power Generation is subject to numerous 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.
The North American Reliability Council (NERC) is an international regulatory authority responsible for
establishing and enforcing Reliability Standards to reduce risks to the reliability and security of the grid in
Canada, the United States, and Mexico. It is subject to oversight from the FERC and provincial
governments in Canada. The FERC has authority over many markets in the US and is tasked with
ensuring safe, reliable, and secure interstate transmission of electricity, natural gas, and oil. This includes
establishing reliability standards and determining certain pricing aspects of transmission development and
access, among others. NERC and FERC standards and pricing decisions are also updated from time to
time and could impact our operations, capital expenditures, earnings, and cash flows, though some of
these impacts could be positive for our business.
At the US federal level, our Renewable Power Generation assets are subject to legislation overseen by
the US Fish and Wildlife Service, which is aimed at reducing the impact of development and human
activity on wildlife, along with other federal environmental permitting legislation. These federal
environmental laws are subject to change from time to time which could require Enbridge to obtain new
permits, update practices, or amend operations and operating expenditures.
In Canada, the Federal Government does not generally regulate the electricity sector though it has
imposed a federal carbon price on other sectors via its output-based pricing system (OBPS) and may
seek to impose emissions standards on the electricity sector in the future.
Our Renewable Power Generation assets in France and Germany each have federal policies in place and
are subject to directives and regulations established and enforced by the European Union (EU). These
include the Renewable Energy Directive (RED II most recently passed set targets through 2030), the
European Green Deal, and ongoing work on financing mechanisms and transmission directives and
programs. The EU is also responsible for establishing environmental protection rules and permitting
standards. All of these are subject to change from time to time, which could impact our operations and
related expenditures; however the EU’s general direction is to facilitate increased renewable power
integration to its grid.
The United Kingdom (UK) government is responsible for establishing renewable energy and carbon
pricing policies for the entire UK, as well as long-term electricity sector planning and procurement
mechanisms and structure for auctions that are administered at the national level, e.g., England,
Scotland, within the UK. Each country within the UK is also responsible for establishing its own
environmental and permitting regulations. This process is still ongoing following Brexit and in some cases
continues to result in more volatile merchant power prices; however, expanded interconnectors to Europe
and policies aimed at increasing domestic renewable capacity are in progress.
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Energy Services
Energy Services is regulated by government authorities in the areas of commodity trading, import and
export compliance and the transportation of commodities. Non-compliance with governing rules and
regulations could result in fines, penalties and operating restrictions. These consequences would have an
adverse effect on operations, earnings, cash flows, financial condition and competitive advantage. Energy
Services retains dedicated professional staff and has a robust regulatory compliance program to mitigate
these potential risks associated with the business.
In the US, commodity marketing is regulated by the Commodity Futures Trading Commission, the SEC,
the Federal Trade Commission, the various commodity exchanges, the US Department of Justice and
state regulators. The interstate marketing of electricity and natural gas is also regulated by the FERC. The
provincial and territorial securities regulators similarly regulate commodity marketing within Canada and
are members of the Canadian Securities Administrators. In addition, the Regional Transmission
Organizations and Independent System Operators in both US and Canada regulate commodity
marketing. These various regulators enforce, among other things, the prohibition of market manipulation,
fraud and disruptive trading. To mitigate risks related to commodity trading, Energy Services has
implemented a robust regulatory compliance program that includes targeted training.
The export of natural gas out of Alberta is regulated by the Alberta Energy Regulator. The import and
export of commodities between Canada and the US is subject to regulation by the CER and the US
Department of Energy, as well as customs authorities. In particular, import and export permits are
required, with associated regular reporting requirements. Breaches of such import and export rules could
result in an inability to perform day to day operations, and therein negatively impact the earnings of the
business.
The transportation of crude oil and natural gas liquids by railcar or truck is regulated by the US
Department of Transportation, Transport Canada and provincial regulation. Each jurisdiction requires
compliance with security, safety, emergency management, and environmental laws and regulations
related to ground transportation of commodities. Risks associated with transportation of crude or natural
gas liquids include unplanned releases. In the event of a release, remediation of the affected area would
be required. Energy Services engages third parties, such as the Emergency Response Assistance
Canada, Chemical Transportation Emergency Center and Canadian Transport Emergency Center to
assist in such remediation.
ENVIRONMENTAL REGULATION
Pipeline Regulation
Our Liquids Pipelines and Gas Transmission and Midstream assets are subject to numerous federal, state
and provincial environmental laws and regulations affecting many aspects of our present and future
operations, including air emissions, water quality, water discharge and waste. These laws and regulations
generally require us to obtain and comply with a wide variety of environmental licenses, permits and other
approvals.
In particular, in the US, 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 may significantly increase our operating costs compared to historical
levels.
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In the US, climate change action is evolving at federal, state and regional levels. The Supreme Court
decision in Massachusetts v. Environmental Protection Agency in 2007 established that 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. The new US presidential administration has also
announced that policies designed to combat climate change and reduce GHG emissions will be a key
legislative and regulatory priority, and thus stricter emissions limits and air quality enforcement actions are
likely. In addition, a number of 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 on climate action
with that of the US. In 2019, the Government of Canada implemented a federal system of carbon pricing.
The pricing applies to provinces and territories that do not have a carbon pricing system in place that
meets the federal benchmark. The Canadian Net-Zero Emissions Accountability Act, which received royal
assent in April 2021, requires national targets for the reduction of GHG emissions in Canada be set, with
the objective of attaining net-zero emissions by 2050. As of April 2021, the federal carbon price was
raised to $40 per tonne. This will increase to $65 per tonne in 2023 and rise to $170 per tonne of carbon
dioxide equivalent in 2030.
Due to the speculative outlook regarding any US 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.
Gas Distribution and Storage
Our Gas Distribution and Storage operations, facilities and workers are subject to municipal, provincial
and federal legislation which regulate the protection of the environment and the health and safety of
workers. Environmental legislation primarily includes regulation of spills and emissions to air, land and
water; hazardous waste management; the assessment and management of contaminated sites;
protection of environmentally sensitive areas, and species at risk and their habitat; and the reporting and
reduction of GHG emissions.
Gas distribution system operation, as with any industrial operation, has the potential risk of abnormal or
emergency conditions, or other unplanned events that could result in releases or emissions exceeding
permitted levels. These events could result in injuries to workers or the public, adverse impacts to the
environment, property damage and/or regulatory infractions including orders and fines. We could also
incur future liability for soil and groundwater contamination associated with past and present site
activities.
In addition to gas distribution, we also operate storage facilities and a small volume of oil and brine
production in southwestern Ontario. Environmental risk associated with these facilities has the potential
for unplanned releases. In the event of a release, remediation of the affected area would be required.
There would also be potential for fines, orders or charges under environmental legislation, and potential
third-party liability claims by any affected landowners.
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The gas distribution system and our other operations must maintain environmental approvals and permits
from regulators to operate. As a result, these assets and facilities are subject to periodic inspections and/
or audits. Annual reports, such as Annual Written Summary Reports for Environmental Compliance
Approvals (ECAs) are submitted to the Ontario Ministry of the Environment, Conservation and Parks
(MECP) and other regulators to demonstrate we are in good standing with our environmental
requirements. Failure to maintain regulatory compliance could result in operational interruptions, fines,
and/or orders for additional pollution control technology or environmental mitigation. As environmental
requirements and regulations become more stringent, the cost to maintain compliance and the time
required to obtain approvals is expected to increase.
As in previous years, in 2021, we reported operational GHG emissions, including emissions from
stationary combustion, flaring, venting and fugitive sources to Environment and Climate Change Canada
(ECCC), the Ontario MECP, and a number of voluntary reporting programs. In accordance with the
provincial GHG regulations, stationary combustion and flaring emissions related to storage and
transmission operations were verified in detail by a third-party accredited verifier with no material
discrepancies found.
Enbridge Gas utilizes 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 our systems as required. Enbridge Gas continues to work with industry
associations to refine quantification methodologies and emissions factors, as well as best management
practices to minimize emissions.
In October 2018, the federal government confirmed that Ontario is subject to the federal government’s
carbon pricing program, otherwise known as the Federal Carbon Pricing Backstop Program. This program
consists of two components: a carbon charge levied on fossil fuels, including natural gas, and an OBPS.
The federal carbon charge took effect on April 1, 2019 at a rate of 3.91 cents/cubic meter (m3) of natural
gas and is applicable to the majority of customers. Enbridge Gas is registered as a natural gas distributor
with the Canada Revenue Agency and remits the federal carbon charge on a monthly basis. The charge
increases annually on April 1 of each year by 1.96 cents/m3, rising up to 9.79 cents/m3 in 2022. In
December 2020, the federal government announced plans to increase the federal carbon price by $15 per
tonne each year in 2023, rising to $170 per tonne of carbon dioxide equivalent in 2030. Enbridge Gas
estimates that this will equate to a federal carbon charge on natural gas of approximately 33.31 cents/m3
in 2030. Enbridge Gas applies for approval from the OEB on an annual basis to pass through federal
carbon charges.
The OBPS component came into effect on January 1, 2019. Under OBPS, a registered facility has a
compliance obligation for the portion of their emissions that exceeds their annual facility emissions limit,
which is calculated based on the sector specific output-based standard and annual production. Enbridge
Gas is registered with ECCC as an emitter in the OBPS program and has an annual compliance
obligation associated with the combustion and flaring emissions associated with its natural gas pipeline
transmission system. As a registered facility under OBPS, Enbridge Gas submitted an annual report
along with the required verification report from an accredited third-party verifier who found no material
misstatements. Enbridge Gas is required to remit payment for facility emissions that exceed its annual
facility emissions limit. Due to COVID-19, ECCC delayed the payment deadline for the 2019 compliance
obligation from December 15, 2020 to April 15, 2021. Enbridge Gas made payment for the 2019
compliance obligation in March 2021 and for the 2020 compliance obligation in November 2021.
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In September 2020, Ontario and the federal government announced that the federal government has
accepted that Ontario’s Emission Performance Standards (EPS) will replace the federal OBPS for
industrial facilities. In March 2021, the federal government announced that the federal OBPS will stand
down in Ontario at the end of 2021 and Ontario will transition to the EPS effective January 1, 2022. In
September 2021, the Greenhouse Gas Pollution Pricing Act was amended to remove Ontario as a
covered province effective January 1, 2022. Beginning January 1, 2022, Enbridge Gas will have a
compliance obligation under the EPS program for its facility-related emissions, as well as the federal
carbon charge for its customer-related emissions.
HUMAN CAPITAL RESOURCES
WORKFORCE SIZE AND COMPOSITION
As at December 31, 2021, we had approximately 10,900 regular employees, including approximately
1,500 unionized employees across our North American operations. This total rises to nearly 13,000 if
temporary employees and contractors are included. We have a strong preference for direct employment
relationships but where we have collectively bargained-for employees, 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.
SAFETY
We believe all injuries, incidents and occupational illnesses are preventable. Our overall focus on
employee and contractor safety, including through the COVID-19 pandemic, continues to result in strong
performance compared against industry benchmarks and we are actively engaged in continuous
improvement exercises as we pursue our goal of zero incidents.
DIVERSITY AND INCLUSION
To ensure our workforce is reflective of the communities where we operate, we have pursued efforts to
increase the representation of women, underrepresented ethnic and racial groups, people with disabilities
and veterans. In 2021 we set diversity representation goals and shared these goals with employees and
external stakeholders. Consistent with our culture, we remain committed to open, two-way dialogue
related to our goals, enhancing transparency and accountability for all stakeholders.
In 2021, we added Inclusion to our core values of Safety, Integrity and Respect to demonstrate this
commitment. We are building an organization where people feel safe and welcome and have the
opportunity to thrive and grow based on merit. As part of our evolving ESG strategy, we created a tighter
link between our success and the workforce related ESG measures – including safety, emissions
reduction efforts and diversity & inclusion – that enable it. As a result, beginning in 2021, key metrics in
these areas are embedded in our scorecards and directly impact compensation.
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PRODUCTIVITY AND DEVELOPMENT
We continually invest in our people’s personal and professional development because we recognize their
success is our success. Every year, employees are provided access to a range of development and re-
skilling opportunities through a variety of channels, including: extensive catalog of self-directed learning
(10,000+ external courses plus proprietary Enbridge University courses); on-the-job learning opportunities
and rotational assignments; curated leadership development programs; educational reimbursement; and
developmental relationships with mentors through our formal mentor-protégé matching program.
EXECUTIVE OFFICERS
The following table sets forth information regarding our executive officers as at February 11, 2022:
Name
Al Monaco
Vern D. Yu
Colin K. Gruending
Cynthia L. Hansen
Byron C. Neiles
Robert R. Rooney
William T. Yardley
Matthew Akman
Allen C. Capps
Age
Position
62
55
52
57
56
65
57
54
51
President & Chief Executive Officer
Executive Vice President & Chief Financial Officer
Executive Vice President & President, Liquids Pipelines
Executive Vice President & President, Gas Distribution and Storage
Executive Vice President, Corporate Services
Executive Vice President & Chief Legal Officer
Executive Vice President & President, Gas Transmission and Midstream
Senior Vice President, Strategy, Power & New Energy Technologies
Senior Vice President, Corporate Development & Energy Services
Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. Mr. Monaco is also
a member of the Enbridge Board of Directors.
Vern D. Yu was appointed Executive Vice President and Chief Financial Officer on October 1, 2021, with
oversight for all of Enbridge’s financial affairs including investor relations, financial reporting, financial
planning, treasury, tax, insurance, risk and audit management functions as well as implementation of our
ERP transformation system. Previously, Mr. Yu served as Executive Vice President and President, Liquids
Pipelines and prior to that served as President and Chief Operating Officer for Liquids Pipelines and as
Executive Vice President and Chief Development Officer. Effective March 1, 2022, Mr. Yu will be
appointed as Executive Vice President, Corporate Development and Chief Financial Officer.
Colin K. Gruending was appointed Executive Vice President and President, Liquids Pipelines on October
1, 2021. Mr. Gruending is responsible for the overall leadership and operations of Enbridge’s Liquids
Pipelines business. Previously, he served as our Executive Vice President and Chief Financial Officer and
as Senior Vice President, Corporate Development and Investment Review.
Cynthia L. Hansen was appointed Executive Vice President and President, Gas Distribution and Storage,
on June 1, 2019. Ms. Hansen is responsible for the overall leadership and operations of Enbridge Gas,
following the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas),
as well as Gazifère. Previously, our Executive Vice President, Utilities and Power Operations, Ms. Hansen
is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working
with other business unit leaders. Effective March 1, 2022, Ms. Hansen will be appointed as the Executive
Vice President and President of Gas Transmission and Midstream and Michele E. Harradence will be
appointed as Senior Vice President and President, Gas Distribution and Storage. Ms. Harradence most
recently held the role of Senior Vice President and Chief Operations Officer, Gas Transmission and
Midstream.
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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, supply chain management,
safety, environment, land & right-of-way, and public affairs, communications and sustainability functions.
Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017.
Mr. Rooney leads our legal, ethics and compliance, security and aviation teams across the organization.
William T. Yardley was named Executive Vice President and President, Gas Transmission and Midstream
on February 27, 2017. Mr. Yardley was previously President of Spectra Energy Corp's (Spectra Energy)
US Transmission and Storage business, leading the business development, project execution, operations
and environment, health and safety efforts associated with Spectra Energy’s US portfolio of assets. Mr.
Yardley will retire on May 31, 2022.
Matthew Akman was appointed Senior Vice President, Strategy & Power on June 1, 2019 and he is
currently Senior Vice President, Strategy, Power & New Energy Technologies. He is responsible for the
corporate strategic planning process and all renewable power operations and development globally, as
well as for our New Energy Technologies team formed in 2021. Mr. Akman joined Enbridge in early 2016
as our head of Corporate Strategy and also previously held responsibilities for Corporate Development
and Investor Relations.
Allen C. Capps was appointed Senior Vice President, Corporate Development and Energy Services in
September 2020. He is responsible for capital allocation, investment review, corporate business
development including Mergers & Acquisitions and Energy Services. Prior to assuming his current role,
Mr. Capps served as Senior Vice President, Corporate Development and Investment Review. Mr. Capps
has also served as Senior Vice President and Chief Accounting Officer and before that Vice President and
Controller of Spectra Energy. Effective March 1, 2022, Mr. Capps will be appointed as the Senior Vice
President and Chief Commercial Officer of Gas Transmission & Midstream.
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 Exchange Act, 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).
ENBRIDGE GAS INC.
Additional information about Enbridge Gas can be found in its annual information form, financial
statements and management's discussion and analysis (MD&A) for the year ended December 31, 2021,
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 Enbridge 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.
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ENBRIDGE PIPELINES INC.
Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form,
financial statements and MD&A for the year ended December 31, 2021, 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.
WESTCOAST ENERGY INC.
Additional information about Westcoast can be found in its annual information form, financial statements
and MD&A for the year ended December 31, 2021, 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 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.
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ITEM 1A. RISK FACTORS
The following risk factors could materially and adversely affect our business, operations, financial results,
market price or value of our securities. This list is not exhaustive, and we place no priority or likelihood
based on order of presentation or grouping under sub-captions.
RISKS RELATED TO CLIMATE CHANGE
Climate change risks could adversely affect our business, operations and financial results, and
these effects could be material.
Climate change presents both physical and transition risks to our organization. A summary of these risks
is discussed below. Given the interconnected nature of climate impacts, however, we also discuss these
risks within the context of other risks impacting Enbridge throughout Item 1A - Risk Factors. Climate
change and its associated impacts may increase our exposure to, and magnitude of, the other risks
identified in Item 1A - Risk Factors. Our business, financial condition, results of operations, cash flows,
reputation, access to and cost of capital or insurance, business plans or strategy may all be adversely
impacted as a result of climate change and its associated impacts.
PHYSICAL RISKS
Physical risks relate to the physical impacts of climate change. These risks could damage our assets or
affect the safety and reliability of our operations.
Climate change could result in extreme variability in weather patterns, such as increased frequency and
severity of extreme weather events, heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes,
tropical storms, ice storms, rising mean temperature and sea levels, and long-term changes in
precipitation patterns. Our assets and operations are exposed to potential interruption or damage from
these kinds of events, and we may also experience reduced access to our assets or increased risk of loss
of life or injury or damage to property and the environment. We have experienced operational
interruptions and damage to our assets from such weather events in the past, and we expect to
experience climate related physical risks in the future, potentially with increasing frequency or severity.
Operational risk is intensified by changing climate and more extreme weather events. Any of these
physical risks could result in substantial losses for which our insurance may not be sufficient or available
and for which we may bear a part or all of the cost.
TRANSITION RISKS
Transition risks relate to the transition to a lower-emission economy, which may increase our cost of
operations, impact our business plans, and influence stakeholder decisions about our company, each of
which could adversely impact our strategic plan, business, operations or financial results. These transition
risks include:
Policy and legal risks
Foreign and domestic governments continue to evaluate and implement policy, legislation, and
regulations focused on reducing GHG emissions, promoting adaptation to climate change, transitioning to
a low-carbon economy, and disclosure of climate-related matters. Such policies, laws and regulations
vary at the federal, state, provincial and municipal levels in which Enbridge operates and can be highly
variable and subject to change. It is expected that further investments will be required to meet new
regulatory requirements. In addition, in recent years there has been an increase in climate and disclosure-
related litigation against governments as well as companies involved in the energy industry. There is no
assurance that our company will not be impacted by such litigation.
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Technology risks
Our success in executing our strategic plan, including our role in the transition to a lower-carbon
economy, and attaining our GHG emissions reduction goals and targets, depends, in part, on technology
(including technology still under development), innovation and continued diversification with renewable
power and other low carbon energy infrastructure as well as modernization of our infrastructure to reduce
GHG emissions. Achieving our GHG emissions reductions goals and targets could require significant
capital expenditures and resources, with the potential that the costs required to achieve our goals and
targets materially differ from our original estimates and expectations. Similarly, there is a risk that
emissions reduction technology – like battery storage, CCS or direct air capture – do not materialize as
expected, making it more difficult to reduce emissions.
Market risks
Climate change concerns, increase in demand for low-carbon and zero-emissions energy, alternative and
new energy sources and technologies, changing customer behavior and reduced energy consumption
could impact the demand for our services or securities. The pace and scale of the transition to a lower
carbon economy may pose a climate-related transition risk if Enbridge diversifies either too quickly or too
slowly. Similarly, uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and
demands, including due to climate change concerns, can impact revenue through reduced throughput
volumes on our pipeline transportation systems.
Reputational risks
We have long been committed to strong ESG practices and performance, and in November 2020, we
introduced a set of ESG goals to strengthen transparency and accountability. We have set GHG
emissions reduction goals and a strategic priority to adapt to the energy transition over time. If we are not
able to achieve our GHG emissions reduction goals, we are not able to meet future climate, emissions or
other reporting requirements of regulators, or we are not able to meet or manage current and future
expectations and issues important to investors or other stakeholders, including those related to climate
change, it could negatively impact our reputation and our business, operations or financial results.
RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS
Pipeline operations involve numerous risks that may adversely affect our business, financial
results and the environment.
Operation of complex pipeline systems, gathering, treating, storing and processing operations involves
many risks, hazards and uncertainties.
These operational risks include adverse weather conditions, natural disasters, accidents, the breakdown
or failure of equipment or processes, and the performance of the facilities below expected levels of
capacity and efficiency and catastrophic events. Climate change presents physical risks relating to the
physical impacts of climate change, which can affect the safety and reliability of our operations. Climate
change could result in extreme variability in weather patterns, such as increased frequency and severity
of extreme weather events, extreme hot and cold weather, heavy snowfall, heavy rainfall, floods,
landslides, fires, hurricanes, tropical storms, ice storms, rising mean temperature and sea levels, and
long-term changes in precipitation patterns.
Our assets and operations are exposed to potential interruption or damage from these kinds of events,
and we may also experience reduced access to our assets, increased risk of loss of life or injury, damage
to our property and our assets, environmental pollution or impairment of our operations. These kinds of
events could also result in rupture or release of product from our pipeline systems and facilities. Such
events could 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. Operational risk is also intensified by changing climate and
more extreme weather events.
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An environmental incident is an event that may cause environmental harm and could lead to an increased
cost of operating and insuring our assets, thereby negatively impacting earnings. An environmental
incident could have lasting reputational impacts 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 events could be greater.
We have experienced such events in the past, including in 2010 on Lines 6A and 6B of the Lakehead
System; in October 2018 at the BC Pipeline T-South system; in January 2019, August 2019 and May
2020 at the Texas Eastern Pipeline; impacts from the winter storm in February 2021 in Texas and from
wildfires in July 2021 and flooding in November 2021 in BC. We have incurred and expect to continue to
incur significant costs in preparing for or responding to operational risks and events. We expect to
continue to experience climate related physical risks, potentially with increasing frequency and severity,
and we cannot guarantee that we will not experience catastrophic or other events in the future. In
addition, we could be subject to litigation and significant fines and penalties from regulators in connection
with any such events.
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, curtailment of commodity supply, operational
incident, availability of gas supply or distribution or other reasons could have a significant impact on our
operations and negatively impact financial results, relationships with stakeholders, our reputation or the
safety of our end customers. Service interruptions that impact our crude oil and natural gas 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. We have experienced, and
may again experience, service interruptions including in connection with the kinds of operational incidents
referred to in the previous risk factor.
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 or loss of life 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 or loss of life to our workers or contractors,
which we have experienced in the past and, despite the precautions we take, may experience in the
future, could result in reputational damage to us, material repair costs or increased costs of operating and
insuring our assets.
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, pipelines and other assets, 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, or the network or systems of our third-party
vendors, 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
and distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we
and some of our vendors collect and store sensitive data in the ordinary course of our business, including
personal information of our employees and residential gas distribution customers as well as our
proprietary business information and that of our customers, suppliers, investors and other stakeholders.
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Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and
the increased sophistication, magnitude and frequency of cyber-attacks and data security breaches, as
well as due to international and national political factors. Because of the critical nature of our
infrastructure and our use of information systems and other digital technologies to control our assets, we
face a heightened risk of cyber-attacks. New cybersecurity regulations have been recently implemented
resulting in additional regulatory oversight and compliance requirements.
During the normal course of business, we have experienced and expect to continue to experience
attempts to gain unauthorized access, compromise our information systems or to disrupt our operations
through cyber-attacks or security breaches, although none to our knowledge have had a material adverse
effect on our business, operations or financial results. Despite our security measures, our information
systems or those of our vendors are expected to become the target of further cyber-attacks or security
breaches which could compromise our systems, affect our ability to correctly record, process and report
transactions, result in the loss of information, or cause operational disruption. 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, incur additional costs for remediation, litigation or other costs, all of which
could materially adversely affect our reputation, business, operations or financial results.
Pandemics, epidemics or disease outbreaks, such as the COVID-19 pandemic, may adversely
affect local and global economies and our business, operations or financial results.
Disruptions caused by pandemics, epidemics or disease outbreaks, in locations in which we operate or
globally, could materially adversely affect our business, operations, financial results and forward-looking
expectations.
In response to the rapid global spread of COVID-19, governments continue to enact emergency
measures to combat the spread of the virus. These measures include restrictions on business activity and
travel, as well as requirements to isolate or quarantine. Certain of our operations and projects have been
deemed essential services in critical infrastructure sectors and are currently exempt from certain business
activity restrictions. COVID-19 and government responses have interrupted business activities and supply
chains, disrupted travel, and contributed to significant volatility in the financial and commodity markets.
Given the ongoing and dynamic nature of the COVID-19 pandemic, further impacts will depend on future
developments and factors outside of our control, which are uncertain, evolving and cannot be predicted,
including new information which may emerge concerning the severity or duration of this pandemic
(including new COVID-19 strains and the efficacy of vaccines) and actions taken by governments and
others to contain or end the COVID-19 pandemic or its impact. Such developments include disruptions,
which have had or may have an adverse effect on our customers, suppliers, regulators, business,
operations and financial results.
There can be no assurance that our strategies to address potential disruptions will mitigate these risks or
the adverse impacts to our business, operations and financial results. In addition, disruptions related to
the COVID-19 pandemic have had, or could continue to have, the effect of heightening many of the other
risks described in this Item 1A. Risk Factors.
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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 (which may take the form of cyber-attacks), escalation of military activity or
acts of war, or other civil unrest or activism may have significant effects on general economic conditions
and may cause 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 US, 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 US 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.
RISKS RELATED TO OUR BUSINESS AND INDUSTRY
There are utilization risks with respect to our assets.
With respect to our Liquids Pipelines assets, we may be exposed to throughput risk on the Canadian
Mainline depending upon the tolling framework we adopt for that system, and we are exposed to
throughput risk 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, regulatory restrictions,
maintenance and operational incidents on our system and upstream or downstream facilities 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 and new
energy sources and technologies, 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.
With respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue
to change due to shifts in regional production and consumption. These shifts can lead to fluctuations in
commodity prices and price differentials, resulting in oversupply of pipeline takeaway capacity in some
areas and an adverse effect to the utilization of our systems. Other factors affecting system utilization
include operational incidents, regulatory restrictions, system maintenance, and increased competition.
With respect to our Gas Distribution and Storage assets, customers are billed on both a fixed charge and
volumetric basis and our ability to collect the 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 our Gas Distribution 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.
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 we attain our respective total forecast distribution volume, our Gas
Distribution business may not earn its expected ROE due to other forecast variables, such as the mix
between the higher margin residential and commercial sectors and the lower margin industrial sector. Our
Gas Distribution business remains at risk for the actual versus forecast large volume contract commercial
and industrial volumes.
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With respect to our Renewable Power Generation 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 Renewable Power Generation 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
Renewable Power Generation facilities could lead to decreased earnings and cash flows for us.
Additionally, inefficiencies or interruptions of Renewable Power Generation facilities due to operational
disturbances or outages resulting from weather conditions or other factors, could also impact earnings.
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.
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.
We face competition from competing carriers available to ship western Canadian liquid hydrocarbons to
markets in Canada, the US and internationally and from proposed pipelines that seek to access markets
currently served by our liquids pipelines. 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. We also face competition from alternative storage facilities. 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 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. Renewable Power Generation business faces competition in
the procurement of long-term power purchase agreements and from other fuel sources in the markets in
which we operate. Competition in all of our businesses, including competition for new project
development opportunities, could have a negative impact on our business, financial condition or results of
operations.
Execution of our projects subjects us to various regulatory, operational and market risks that may
affect our financial results.
Our ability to successfully bring our secured capital growth program into service is exposed to risks
including:
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the ability to obtain or amend necessary approvals and permits from governments and regulatory
agencies on a timely basis and with acceptable terms and conditions and to maintain those
issued approvals and permits and satisfy the terms and conditions imposed therein;
opposition by third parties, physical protests, interference with or damage to our property or
infrastructure, litigation or increased execution and stakeholder engagement complexity;
new or incremental changes in federal, state, provincial and local laws and regulations after
projects are sanctioned;
inflationary pressures on labor, materials and equipment, which have decreased price
predictability;
bottlenecked global supply chains and logistics, which have increased delivery times of materials
and equipment;
timely acquisition or renewal of rights-of-way or land rights with acceptable terms and conditions;
extreme weather events (e.g. hurricanes, forest fires, floods); or
contractor or supplier non-performance, weather, geological or other factors beyond our control.
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Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated
cost.
New projects may not achieve their expected investment return, which could affect our financial results,
reputation and hinder our ability to secure future projects. Recent projects that have experienced various
degrees of impacts include the US L3R Program that was placed into service in the third quarter of 2021,
Line 5 projects (tunnel and reroute), Texas Eastern Modernization, East-West Tie and Offshore Wind. For
additional discussion of specific proceedings that could affect our operations and financial results, refer to
Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -
Legal and Other Updates.
Changing expectations from stakeholders regarding ESG practices and climate change or erosion
of stakeholder trust or confidence could damage our reputation and influence actions or
decisions about our company and industry and have negative impacts on our business,
operations or financial results.
Companies across all sectors and industries are facing changing expectations or increasing scrutiny from
stakeholders related to their approach to ESG matters of greatest relevance to their business and to their
stakeholders. For energy companies, climate change, safety, stakeholder and Indigenous relations
remain primary focus areas, while other environmental elements such as biodiversity are ascendant;
changing expectations of our practices and performance across these and other ESG areas may impose
additional costs or create exposure to new or additional risks.
Our operations, projects and growth opportunities require us to have strong relationships with key
stakeholders, including local communities, Indigenous groups and communities and other groups directly
impacted by our activities, as well as governments and government agencies, investor advocacy groups,
institutional investors, investment funds, financial institutions, insurers and others, which are increasingly
focused on ESG practices.
Enhanced public awareness of climate change has driven an increase in demand for low-carbon and
zero-emissions energy. Enbridge has a long history of diversifying its portfolio of businesses to align with
the mix of energy that people need and want. However, the pace and scale of the transition to a lower
emissions economy may pose a climate-related transition risk if Enbridge diversifies either too quickly or
too slowly. Similarly, unexpected shifts in energy demands, including due to climate changes concerns,
can impact revenue through reduced throughput volumes on our pipeline transportation system.
We have long been committed to strong ESG practices, performance and reporting, and in late 2020
introduced a set of ESG goals to strengthen transparency and accountability. The goals include
increasing diversity and inclusion within our organization and reducing emissions from our operations to
net zero by 2050, with corporate and business unit action plans aligned to our strategic priority to adapt to
the energy transition over time. Given elevated long-term risks associated with climate change, there
have also been efforts in recent years by the investment community, including increased engagement with
companies on climate change and decreasing the carbon intensity of their portfolios. If we are not able to
achieve our GHG emissions reduction goals, are not able to meet future climate, emissions or other
reporting requirements of regulators, or are not able to meet or manage current and future expectations or
issues important to investors or other stakeholders including those related to climate change, it could
negatively impact stakeholder trust and confidence, our reputation, and our business, operations or
financial results, including:
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loss of business;
loss of ability to secure growth opportunities;
delays in project execution;
legal action, such as the legal challenges to the operation of Line 5 in Michigan and Wisconsin;
increased regulatory oversight;
loss of ability to obtain and maintain necessary approvals and permits from governments and
regulatory agencies on a timely basis and on acceptable terms;
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impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and
on acceptable terms;
changing investor sentiment regarding investment in the oil and gas industry or our company;
restricted access to and cost of capital and insurance; and
loss of ability to hire and retain top talent.
We are also exposed to the risk of higher costs, delays, project cancellations, new restrictions or the
cessation of operations of existing pipelines due to increasing pressure on governments and regulators.
Recent judicial decisions have increased the ability of 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 organized opposition to oil and gas
extraction and shipment of oil and gas products.
Our forecasted assumptions may not materialize as expected, including 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, and changes in cost estimates,
project scoping and risk assessment could result in a loss of our profits. Similarly, uncertainty in market
signals, such as abrupt and unexpected shifts in energy costs and demands, as we saw in 2020 resulting
from the COVID-19 pandemic, have impacted, and may in the future impact, revenue through reduced
throughput volumes on our pipeline transportation system.
Our insurance coverage may not be sufficient to cover our losses in the event of an accident,
natural disaster or other hazardous event.
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, and in some cases
have caused, 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 certain of our affiliates to mitigate the
financial impacts arising from these hazards. This program includes insurance coverage in types and
amounts and with terms and conditions that are generally consistent with coverage customary for our
industry; however, insurance does not cover all events in all circumstances.
In the unlikely event that multiple insurable incidents that in the 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. Additionally,
even with insurance, if any natural disaster or other hazardous event leads to a catastrophic interruption
in operations, we may not be able to restore operations without significant interruption.
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. 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. It
is possible that customer payment defaults, if significant, could adversely affect our earnings and cash
flows.
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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 financial derivatives to manage risks associated with changes in foreign exchange rates, interest
rates, commodity prices and our share price to reduce volatility of our cash flows. Based on our risk
management policies, all of our financial derivatives are associated with an underlying asset, liability and/
or forecasted transaction and not intended for speculative purposes.
These policies cannot, however, eliminate all risk including unauthorized trading. Although this activity is
monitored independently by our risk management function, we can provide no assurance that we will
detect and prevent all unauthorized trading and other violations, particularly if deception, collusion or
other intentional misconduct is involved, and any such violations could adversely affect our business,
operations or financial results.
Our business requires the retention and recruitment of a skilled and diverse workforce, and
difficulties in 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 and diverse workforce,
including engineers, technical personnel and other professionals. We and our affiliates compete with other
companies in the energy industry, and for some jobs the broader labor market, 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 costs
to retain and recruit these professionals.
Our transformation projects may fail to fully deliver anticipated results.
We launched projects starting in 2016 to transform various processes, capabilities and reporting systems
infrastructure to continuously improve effectiveness and efficiency across the organization and are subject
to transformation project risk with respect to these projects. Such projects, some of which will continue
beyond 2022, are subject to transformation project risk. 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.
Our business is undergoing significant changes driven by technological advancements and the
energy transition, which could impact our strategic plan, business, operations or financial results.
Our success in executing our strategic plan, including our role in the transition to a low-carbon economy,
and attaining our GHG emissions reduction goals and targets depends, in part, on technology (including
technology still under development), innovation and continued diversification with renewable power and
other low carbon energy infrastructure as well as modernization of our infrastructure to reduce GHG
emissions, all of which could require significant capital expenditures and resources. Public policy relating
to climate change can drive investment in lower-emissions technologies which could impact both the
supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.
Our Liquids Pipelines growth rate and results may be directly and indirectly affected by
commodity prices and government policy.
This intervention had a negligible impact on the Mainline System throughput, as enough inventory existed
to meet refinery customer needs and service our favorable markets. Wide commodity price basis between
Western Canada and global tidewater markets have 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 which are operating at capacity. A protracted long-term
outlook for low crude oil prices could result in delay or cancellation of future projects. Effective December
31, 2021, the Government of Alberta lifted the oil production curtailment that was imposed in December
2018.
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The tight conventional oil plays of Western Canada, the Permian basin, 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 to 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.
Our Energy Services and Gas Transmission and Midstream results may be adversely affected by
commodity price volatility.
Within our US Midstream assets, through our investments in DCP Midstream and Aux Sable, we are
engaged in the businesses of gathering, treating and processing natural gas and natural gas liquids. The
financial results of these businesses are directly impacted by changes in commodity prices.
Energy Services generates margin by capitalizing on quality, time and location differentials when
opportunities arise. Lower commodity prices due to changing market conditions could limit margin
opportunities and impede Energy Services' ability to cover capacity commitments.
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
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. An inability to access capital may limit our ability to pursue enhancements
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.
RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS
Many of our operations are regulated and failure to secure timely regulatory approval for our
proposed projects, or loss of required approvals for our existing operations, could have a
negative impact on our business, operations or financial results.
The nature and degree of regulation and legislation affecting energy companies in Canada and the US
have changed significantly in recent years.
51
In Canada, the passing of the Canadian Energy Regulator Act and the Impact Assessment Act under Bill
C-69, which came into force on August 28, 2019, adds steps in the regulatory process and extends
overall timelines associated with regulatory approvals for new projects which trigger a federal impact
assessment. Changes to the BC regulatory framework have also been made, including a new
Environmental Assessment Act, which came into force in December 2019, affecting provincially-regulated
projects in a similar manner as those that are federally-regulated. Within the US and in Canada, pipelines
companies continue to face opposition from anti-pipeline activists, Indigenous and tribal groups and
communities, citizens, environmental groups and politicians concerned with either the safety of pipelines
or environmental effects. In the US, several federal agencies made changes to regulations that were
designed to streamline permitting, including changes that the Environmental Protection Agency made in
June 2020 to regulations implementing Section 401 of the Clean Water Act and the July 2020 Council on
Environmental Quality revisions to regulations implementing the National Environmental Policy Act. These
and many other regulations adopted during the previous US presidential administration are not only being
challenged in multiple courts, but have now been expressly targeted for rollback by the new US
administration, which is expected to modify or reverse the regulations.
These actions could adversely impact permitting of a wide range of energy projects. We may not be able
to obtain or maintain all required regulatory approvals for our operating assets or development projects. If
there is a delay in obtaining any required regulatory approvals, if we fail to obtain or comply with them, or
if 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.
Our operations are subject to numerous environmental laws and regulations, including those
relating to climate change and GHG emissions and climate-related disclosure, as well as internal
initiatives to reduce GHG emissions, 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.
Foreign and domestic governments continue to evaluate and implement policy, legislation, and
regulations focused on restricting GHG emissions, promoting adaptation to climate change and the
transition to a low-carbon economy, and disclosure of climate-related matters. Such policies, laws and
regulations vary at the federal, state, and provincial levels in which Enbridge operates and can be highly
variable and subject to change. International multilateral agreements, the obligations adopted thereunder,
increasing physical impacts of climate change, changing political and public opinion and legal challenges
concerning the adequacy of climate-related policy brought against governments and corporations, among
other factors, are expected to accelerate the implementation of these measures.
Enbridge is required to adhere to a number of implicit and explicit carbon-pricing mechanisms. These
mechanisms may present climate-related transition risk to our business strategy, impacting both
commodity demand and the overall energy mix we deliver.
Failure to comply with environmental laws and regulations and failure to secure permits necessary for our
operations 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, including those related to climate change and GHG emissions, could
result in a material increase in our cost of compliance with such laws and regulations, such as costs to
monitor and report our emissions and install new emission controls to reduce emissions. We may not be
able to include some or all of such increased costs in the rates charged by our pipelines or other facilities.
Efforts to regulate or restrict GHG emissions could also drive down demand for the products we transport.
52
We may not be able to obtain or maintain all required environmental regulatory approvals and permits for
our operating assets or development projects. If there is a delay in obtaining any required environmental
regulatory approvals or permits, 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 may have a significant
effect on our earnings and cash flows.
In November 2020, we set new ESG goals for the future related to GHG emissions reduction. Our ability
to achieve these goals depends on many factors, including our ability to reduce emissions from our
operations through modernization and innovation, reduce the emissions intensity of the electricity we buy,
invest in renewables and low carbon energy and balance residual emissions through carbon offset
credits. The cost associated with our GHG emissions reduction goals could be significant. There is also a
risk that some or all of the expected benefits and opportunities of achieving the various GHG emissions
reduction and energy transition goals may fail to materialize, may cost more to achieve or may not occur
within the anticipated time periods. Similarly, there is a risk that emissions reduction technology – like
battery storage or direct air capture – do not materialize as expected making it more difficult to reduce
emissions. Failure to achieve our emissions targets could result in reputational harm, changing investor
sentiment regarding investment in Enbridge or a negative impact on access to and cost of capital,
including penalties associated with our sustainability-linked bond offerings.
Our operations are subject to operational regulation and other requirements, including
compliance with easements and other land tenure documents, and failure to comply with
applicable regulations and other requirements could have a negative impact on our reputation,
business, operations or financial results.
Operational risks relate to compliance with applicable operational rules and regulations mandated by
governments, applicable regulatory authorities, or other requirements that may be found in easements or
other agreements that provide a legal basis for our operations, breaches of which could result in fines,
penalties, awards of damages, operating restrictions (including shutdown of lines) and an overall increase
in operating and compliance costs. We do not own all of the land on which our pipelines, facilities and
other assets are located and we obtain the rights to construct and operate our pipelines and other assets
from third parties or government entities. In addition, some of our pipelines, facilities and other assets
cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights
could have an adverse effect on our reputation, operations and financial results. Regulator scrutiny over
our assets and operations has the potential to increase operating costs or limit future projects. Regulatory
enforcement actions issued by regulators for non-compliant findings can increase operating costs and
negatively impact reputation. Potential regulatory changes and legal challenges could have an impact on
our future earnings from existing operations and the cost related to the construction of new projects.
Regulators' future actions may differ from current expectations, or future legislative changes may impact
the regulatory environments in which we operate. While we seek to mitigate operational regulation risk by
actively monitoring and consulting on potential regulatory requirement changes with the respective
regulators directly, or through industry associations, and by developing response plans to regulatory
changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. 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 or other
government officials to make unilateral decisions that could disrupt our operations or have an adverse
financial impact on us.
53
Our operations are subject to economic regulation and failure to secure regulatory approval for
our proposed or existing commercial arrangements could have a negative impact on our
business, operations or financial results.
Our liquids pipelines, gas transmission and gas distribution assets face economic regulation risk. Broadly
defined, economic regulation risk is the risk that governments or regulatory agencies change or reject
proposed or existing commercial arrangements or policies, including permits and regulatory approvals for
both new and existing projects or agreements, upon which future and current operations are dependent.
Our Mainline System, other liquids pipelines and gas transmission assets are subject to the actions of
various regulators, including the CER and the FERC, with respect to the tariffs and tolls of those
pipelines. The changing or rejecting of commercial arrangements, including decisions by regulators on the
applicable permits and tariff structure or changes in interpretations of existing regulations by courts or
regulators such as with respect to Mainline Contracting, could have an adverse effect on our revenues
and earnings.
We could be subject to changes in our tax rates, the adoption of new US, Canadian or
international tax legislation or exposure to additional tax liabilities.
We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and
political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax
rates could be affected by changes in the mix of earnings in countries with differing statutory tax rates,
changes in the valuation of deferred tax assets and liabilities, or changes in tax laws or their
interpretation. In particular, we are anticipating interest deductibility rules to be tabled in Canada, possible
new tax legislation to be passed in the US and a minimum tax rate to be introduced on a global basis for
OECD countries. All of these measures could cause our effective tax rate to increase.
We are also subject to the examination of our tax returns and other tax matters by the US Internal
Revenue Service, the Canada Revenue Agency and other tax authorities and governmental bodies. We
regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the
adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations.
If our effective tax rates were to increase, particularly in the US or Canada, or if the ultimate determination
of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition and
operating results could be materially adversely affected.
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. In recent years there has been an increase in climate and
disclosure-related litigation against governments as well as companies involved in the energy industry.
There is no assurance that we will not be impacted by such litigation. 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 or affect our reputation. Refer to Part II. Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and
Other Updates for a discussion of certain legal proceedings with recent developments.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
54
ITEM 2. PROPERTIES
Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are
included in Part 1. 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 pipeline 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 pipeline
systems have natural gas compressor stations, of which the vast majority are located on land that is
owned by us, with the remainder used by us under easements, leases or permits.
Titles to Enbridge owned properties or affiliate entities may be 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 certain legal proceedings with recent developments.
SEC regulations require the disclosure of any proceeding under environmental laws to which a
governmental authority is a party unless the registrant reasonably believes it will not result in monetary
sanctions over a certain threshold. Given the size of our operations, we have elected to use a threshold of
US$1 million for the purposes of determining proceedings requiring disclosure.
The Minnesota Department of Natural Resources (DNR) issued an Administrative Penalty Order on
September 16, 2021 due to an uncontrolled groundwater flow at Clearbrook. The groundwater flow was
stopped in January 2022 after diligently implementing the steps required under the remedial action plan.
We have also provided all required information to date. A contested case was not sought in this matter;
instead, the penalty and mitigation amounts will be paid as directed for the Clearbrook site. A separate
US$2.75 million escrow account is being established for any potential future monitoring and mitigation. In
total, Enbridge will direct US$3.3 million to address this matter. With work complete at Clearbrook and a
second site, Enbridge continues to work with the DNR towards a corrective action plan for the final
location, including ongoing restoration, monitoring, and mitigation for all three sites.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
55
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Common Stock
Enbridge common stock is traded on the TSX and NYSE under the symbol “ENB.” As at February 4,
2022, there were 80,754 registered shareholders of record of Enbridge common stock. A substantially
greater number of holders of Enbridge common stock are "street name" or beneficial holders, whose
shares are held by banks, brokers and other financial institutions.
Securities Authorized for Issuance Under Equity Compensation Plans
The information required by this Item will be contained in our Form 10-K/A, which will be filed no later than
120 days after December 31, 2021.
Recent Sales of Unregistered Equity Securities
None.
Issuer Purchases of Equity Securities
None.
Total Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 2017 through
December 31, 2021 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the
S&P/TSX Composite index, (3) the S&P 500 index, (4) our US peer group (comprising CNP, D, DTE,
DUK, EPD, ET, KMI, MMP, NEE, NI, OKE, PAA, PCG, SO, SRE and WMB) and (5) our Canadian peer
group (comprising CU, FTS, PPL and TRP). The amounts included in the table were calculated assuming
the reinvestment of dividends at the time dividends were paid.
56
Enbridge Inc.
S&P/TSX Composite
S&P 500 Index
US Peers1
Canadian Peers
January 1,
2017
100.00
100.00
100.00
100.00
100.00
December 31,
2017
91.20
109.10
121.83
103.37
110.39
2018
83.64
99.40
116.49
99.41
101.93
2019
108.32
122.14
153.17
121.77
133.27
2020
91.84
128.98
181.35
107.12
110.56
2021
119.50
161.34
233.41
131.86
138.14
1 For the purpose of the graph, it was assumed that CAD:US dollar conversion ratio remained at 1:1 for the years presented.
ITEM 6. [Reserved]
57
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION 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" and "Non-GAAP and Other Financial
Measures", 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.
This section of our Annual Report on Form 10-K discusses 2021 and 2020 items and year-over-year
comparisons between 2021 and 2020. For discussion of 2019 items and year-over-year comparisons
between 2020 and 2019, refer to Part II. Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December
31, 2020.
RECENT DEVELOPMENTS
ACQUISITION OF MODA MIDSTREAM OPERATING, LLC
On October 12, 2021, we acquired Moda Midstream Operating, LLC (Moda) for $3.7 billion (US$3.0
billion) of cash plus potential contingent payments dependent on performance of the assets (the
Acquisition). Moda owns and operates a vertically-integrated crude export system of pipeline and storage
assets on the US Gulf Coast, including the EIEC located near Corpus Christi, Texas. EIEC, North
America's largest crude export terminal, controls 15.6 million barrels of storage and 1.6 million barrels per
day (mmbpd) of export capacity and volumes are underpinned by 925- thousand barrels per day (kbpd) of
long-term take-or-pay vessel loading contracts and 15.3 million barrels of long-term storage contracts.
The Acquisition aligns with and advances our US Gulf Coast export strategy and connectivity to low-cost
and long-lived reserves in the Permian and Eagle Ford basins.
NORMAL COURSE ISSUER BID
On December 31, 2021, we announced that the Toronto Stock Exchange (TSX) had approved our normal
course issuer bid (NCIB) to purchase, for cancellation, up to 31,062,331 of the outstanding common
shares of Enbridge to an aggregate amount of up to $1.5 billion, subject to certain restrictions on the
number of common shares that may be purchased on a single day.
Purchases under the NCIB may be made through the facilities of the TSX, the New York Stock Exchange
(NYSE) and other designated exchanges and alternative trading systems, commencing on January 5,
2022 and continuing until January 4, 2023, when the bid expires, or such earlier date on which Enbridge
has either acquired the maximum number of common shares allowable under the NCIB or otherwise
decide not to make any further repurchases under the NCIB. The maximum number of common shares
that Enbridge may repurchase for cancellation represents approximately 1.53% of the 2,026,085,179
common shares issued and outstanding as at December 22, 2021.
58
MAINLINE SYSTEM CONTRACTING
On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to
implement contracting on our Canadian Mainline System. On November 26, 2021, the CER denied the
application on the basis that, among other things, contracting as proposed would result in a significant
change to access the Canadian Mainline and potentially inequitable outcomes to some shippers and non-
shippers without a compelling justification.
We are currently exploring with customers and other stakeholders alternatives that may include: a
modified and extended Competitive toll Settlement (CTS), a new incentive rate-making agreement or a
cost-of-service rate-making structure. Any negotiated settlement would require CER approval before
implementation.
In accordance with the terms of the CTS, which expired on June 30, 2021, the tolls in place on June 30,
2021 will continue on an interim basis, subject to finalization and adjustment applicable to the interim
period, if any.
GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS
Texas Eastern Transmission
Texas Eastern Transmission, LP (Texas Eastern) filed a rate case on July 30, 2021. On August 31, 2021
the Federal Energy Regulatory Commission (FERC) issued an order rejecting the July 30, 2021 filing in
its entirety noting the proposed US federal income tax rate in the filing was not known and measurable
(“August 2021 Order”). Additionally, the August 31, 2021 order directed Texas Eastern to show cause that
its reservation charge crediting process is in accordance with FERC policy.
In response to the August 2021 Order, on September 30, 2021 Texas Eastern responded to the show
cause directive and filed a new rate case using the current US federal income tax rate. On October 29,
2021, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions,
and establishing hearing procedures for the new rate case filed on September 30, 2021.
Texas Eastern also filed for rehearing of the August 2021 Order. On January 20, 2022 the FERC issued
an “Order Addressing Arguments Raised On Rehearing And Setting Aside Prior Order, In Part” (“January
2022 Order”). The January 2022 Order set aside the August 2021 Order, and accepted and suspended
Texas Eastern’s proposed rates from its initial rate case filing to be effective upon motion on February 1,
2022, subject to refund, conditions, and the outcome of hearing proceedings. In addition, the January
2022 Order directed Texas Eastern to remove its proposed income tax adjustment and include the actual
tax rate in the computation of its rates when it files to motion the suspended rates into effect.
Finally, the FERC left to the discretion of the Chief Administrative Law Judge whether to consolidate the
two rate case proceedings.
East Tennessee
East Tennessee Natural Gas, LLC (ETNG) filed a rate case in the second quarter of 2020 and an
agreement in principle was reached with shippers in April 2021. A Stipulation and Agreement was filed on
May 21, 2021, approved by the FERC on September 10, 2021 and was effective on November 1, 2021.
Maritimes & Northeast Pipeline
The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an
agreement in principle was reached with shippers in December 2020. A Stipulation and Agreement was
filed on February 17, 2021, approved by the FERC on April 30, 2021 and was effective on June 1, 2021.
In December 2021, the CER approved interim rates for the Canadian portion of Maritimes & Northeast
Pipeline effective January 1, 2022, which were based on the negotiated 2022 rates in the 2022-2023
settlement agreement and unanimously supported by shippers. A decision from the CER on the
2022-2023 settlement agreement is expected in the first quarter of 2022.
59
Alliance Pipeline
The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement in
principle was reached with shippers in January 2021. A Stipulation and Agreement was filed on March 31,
2021, approved by the FERC on July 15, 2021 and was effective on September 1, 2021.
British Columbia (BC) Pipeline
The settlement agreement for our BC Pipeline system expired in December 2021. The CER has approved
2022 interim tolls for BC Pipeline and settlement agreement negotiations are ongoing, with an expected
agreement to be reached in the first half of 2022.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
2021 Rate Application
Enbridge Gas Inc.'s (Enbridge Gas) rate applications are filed in two phases. As part of an Ontario Energy
Board (OEB) Decision and Order issued in November 2020, Phase 1 of the application for 2021 rates (the
2021 Application), exclusive of 2021 capital investment funding requested through the incremental capital
module (ICM) mechanism, was approved on an interim basis effective January 1, 2021. Through a
subsequent OEB Rate Order issued in June 2021, Phase 2 of the 2021 Application, inclusive of funding
for $124 million of requested 2021 ICM amounts, was approved effective July 1, 2021, and interim rates
in effect for 2021 were made final. The 2021 Application, which represented the third year of a five-year
term, was filed in accordance with the parameters of the Enbridge Gas OEB approved Price Cap
Incentive Regulation (IR) rate setting mechanism.
2022 Rate Application
In June 2021, Enbridge Gas filed Phase 1 of the application with the OEB for the setting of rates for 2022
(the 2022 Application). The 2022 Application was filed in accordance with the parameters of the Enbridge
Gas OEB approved Price Cap IR rate setting mechanism which represents the fourth year of a five-year
term. In October 2021, the OEB approved a Phase 1 Settlement Proposal and Interim Rate Order
effective January 1, 2022. Phase 2 of the 2022 Application addressing ICM funding requirements was
filed in October 2021, with a decision from the OEB expected in the second quarter of 2022.
FINANCING UPDATE
We completed long-term debt issuances totaling US$3.9 billion and $3.2 billion during the year ended
December 31, 2021, including an inaugural US$1.0 billion 12-year sustainability-linked senior notes
issuance in June 2021 and an inaugural $1.1 billion Canadian 12-year sustainability-linked medium-term
notes issuance in September 2021. We renewed approximately $8.0 billion of our five-year credit
facilities, extending the maturity date out to July 2026. We also extended approximately $10.0 billion of
our 364-day extendible credit facilities to July 2022, which includes a one-year term out provision to July
2023.
Our 2021 financing activities, in combination with the asset monetization activities noted below, provide
significant liquidity that we expect will enable us to fund our current portfolio of capital projects without
requiring access to the capital markets for the next 12 months should market access be restricted or
pricing is unattractive. Refer to Liquidity and Capital Resources.
On January 19, 2022, we closed a $750 million private placement offering of non-call 10-year fixed-to-
fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering will be
used to redeem the Preference Shares, Series 17 at par on March 1, 2022.
On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending
the maturity date out to July 2025.
60
Credit Rating Action
On June 1, 2021, Moody's Investors Service (Moody's) upgraded the credit ratings of Enbridge Inc.,
including our senior unsecured and issuer ratings, to Baa1 from Baa2. Moody's also upgraded the credit
ratings of our subsidiaries: Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Limited Partnership
(EELP), Spectra Energy Partners, LP (SEP) and Texas Eastern. The outlooks of all five entities are
stable.
ENERGY TRANSITION
Given the priority we are placing on low carbon investments and energy transition, we have established a
dedicated New Energy Technologies team. This team will extend the capabilities we have built over the
last 20 years of renewable investments and will establish priorities and co-ordinate strategy across our
business units. The team will also develop new partnerships to enable access to new technology,
complementary assets and skills.
During 2021, the Alberta Solar One and Heidlersburg solar self-power projects were placed into service.
We also started the construction process on 10 additional solar self-power projects in Wisconsin, Illinois,
Pennsylvania, Kentucky, Ohio and Minnesota, together capable of generating more than 97 megawatts
(MW) MW of emissions-free electricity. These projects will provide clean power to our liquids and natural
gas pipeline right-of-way and support scope 1 and 2 emission targets.
ASSET MONETIZATION
Éolien Maritime France SAS
On March 18, 2021, we sold 49% of an entity that holds our 50% interest in Éolien Maritime France SAS
(EMF) to the Canada Pension Plan Investment Board (CPP Investments). CPP Investments will fund their
49% share of all ongoing future development capital. Through our investment in EMF, we own equity
interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and
Calvados (21.7%). The Calvados Offshore Wind Project reached a positive final investment decision in
February 2021 and all three projects are now considered commercially secured and are under
construction.
Noverco Inc.
On December 30, 2021, we sold our 38.9% non-operating minority ownership interest in Noverco Inc.
(Noverco) to Trencap L.P. for $1.1 billion in cash.
61
RESULTS OF OPERATIONS
(millions of Canadian dollars, except per share amounts)
Segment earnings before interest, income taxes and
depreciation and amortization1
Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution and Storage
Renewable Power Generation
Energy Services
Eliminations and Other
Earnings before interest, income taxes and depreciation and
amortization1
Depreciation and amortization
Interest expense
Income tax expense
Earnings attributable to noncontrolling interests and redeemable
noncontrolling interests
Preference share dividends
Earnings attributable to common shareholders
Earnings per common share
Diluted earnings per common share
1 Non-GAAP financial measures.
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Year ended December 31,
2021
2020
2019
7,897
3,671
2,117
508
(313)
356
7,683
1,087
1,748
523
(236)
(113)
7,681
3,371
1,747
111
250
429
14,236
10,692
13,589
(3,852)
(2,655)
(1,415)
(3,712)
(2,790)
(774)
(3,391)
(2,663)
(1,708)
(125)
(373)
5,816
2.87
2.87
(53)
(380)
2,983
1.48
1.48
(122)
(383)
5,322
2.64
2.63
Year ended December 31, 2021 compared with year ended December 31, 2020
Earnings Attributable to Common Shareholders increased by $2.2 billion due to certain unusual,
infrequent or other non-operating factors, primarily explained by the following:
•
•
•
•
•
a non-cash, unrealized net gain of $53 million ($40 million after-tax) in 2021, compared with an
unrealized net loss of $122 million ($92 million after-tax) in 2020 reflecting the revaluation of
derivatives used to manage the profitability of transportation and storage transactions, as well as
manage the exposure to movements in commodity prices;
an impairment loss of $111 million ($83 million after-tax) in 2021 to our investment in the
PennEast pipeline project after a decision by project partners to cease development, compared to
a combined impairment loss of $615 million ($452 million after-tax) in 2020 to our investments in
Southeast Supply Header (SESH) and Steckman Ridge, LP (Steckman);
a gain of $303 million ($298 million after-tax) resulting from the sale of our investment in Noverco;
employee severance, transition and transformation costs of $147 million ($112 million after-tax) in
2021, compared to $339 million ($256 million after-tax) in 2020 primarily related to our voluntary
workforce reduction program offered in the second quarter of 2020;
the absence in 2021 of a non-cash impairment to the carrying value of our investment in DCP
Midstream, LLC (DCP Midstream) of $1.7 billion ($1.3 billion after-tax) and a $324 million loss
($244 million after-tax) resulting from our share of asset and goodwill impairments recognized by
DCP Midstream, both recognized in 2020; and
62
•
•
the absence in 2021 of a $159 million loss ($119 million after-tax) recorded in 2020 to reflect the
Texas Eastern rate case settlement that re-established the Excess Accumulated Deferred Income
Tax (EDIT) regulated liability that was previously eliminated in December 2018; partially offset by
a non-cash, unrealized derivative fair value net gain of $197 million ($150 million after-tax) in
2021, compared with a net gain of $856 million ($646 million after-tax) in 2020, 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 risks.
The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a
result of a comprehensive long-term economic hedging program to mitigate interest rate, foreign
exchange and commodity price risks. This program creates volatility in reported 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 investor value proposition is based.
After taking into consideration the factors above, the remaining $657 million increase in earnings
attributable to common shareholders is primarily explained by the following significant business factors:
•
•
•
•
stronger contributions from our Liquids Pipelines segment due to increased volumes enabled by
incremental Line 3 capacity placed into service in the fourth quarter of 2021 and a higher Mainline
International Joint Tariff (IJT) Benchmark Toll, partially offset by the recognition of a provision
against the interim Mainline IJT for barrels shipped between July 1, 2021 and December 31,
2021;
increased earnings from our Gas Distribution and Storage segment due to increased rates and
customer base;
higher equity earnings from our Aux Sable and DCP Midstream joint ventures in our Gas
Transmission and Midstream; and
lower interest expense for the first nine months of 2021 due to favourable interest rates on short-
term borrowings, and the impact of a weaker US dollar currency that positively impacted the
translation of interest payments on US dollar denominated debt.
The business factors above were partially offset by the following:
•
•
•
•
decreased earnings from our Energy Services segment due to the significant compression of
location and quality differentials in certain markets, fewer storage opportunities due to market
backwardation, adverse impacts from the major winter storm experienced across the US Midwest
during February 2021 and fewer opportunities to achieve profitable transportation margins on
facilities in which Energy Services holds capacity obligations;
the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average
exchange rate in 2021 compared to the same period in 2020;
the absence in 2021 of the recognition of revenue in 2020 from a rate settlement on Texas
Eastern, partially offset by increased revenue due to the absence of pressure restrictions that
existed on the Texas Eastern system in 2020; and
higher depreciation expense on new assets placed into service throughout 2021, including the US
L3R Program, placed into service early in the fourth quarter and the EIEC, acquired in mid-
October.
REVENUES
We generate revenues from three primary sources: transportation and other services, gas distribution
sales and commodity sales.
63
Transportation and other services revenues of $16.2 billion, $16.2 billion and $16.6 billion for the years
ended December 31, 2021, 2020 and 2019, respectively, were earned from our crude oil and natural gas
pipeline transportation businesses and also include power generation 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.
Gas distribution sales revenues of $4.0 billion, $3.7 billion and $4.2 billion for the years ended
December 31, 2021, 2020 and 2019, respectively, were 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 revenues of $26.9 billion, $19.3 billion and $29.3 billion for the years ended
December 31, 2021, 2020 and 2019, respectively, were generated primarily through our Energy Services
operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas,
power and Natural Gas Liquids (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 depend on activity levels, which vary from year-to-year depending on market conditions
and commodity prices.
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.
BUSINESS SEGMENTS
LIQUIDS PIPELINES
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2021
2020
2019
7,897
7,683
7,681
Year ended December 31, 2021 compared with year ended December 31, 2020
EBITDA was negatively impacted by $335 million due to certain unusual, infrequent or other non-
operating factors, primarily explained by a non-cash, unrealized gain of $120 million in 2021 compared
with an unrealized gain of $545 million in 2020 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
risks.
64
The factor above was partially offset by the following:
•
•
a property tax settlement receipt of $57 million in 2021 related to the resolution of Minnesota
property tax appeals for the tax years 2012 through 2018; and
the absence in 2021 of $30 million of asset impairment losses recognized in 2020.
After taking into consideration the factors above, the remaining $549 million increase is primarily
explained by the following factors:
•
•
•
•
•
higher Mainline system ex-Gretna average throughput of 2.8 million barrels per day (mmbpd) in
2021 as compared to 2.6 mmbpd in 2020 driven by the rebounding demand for crude oil and
related products as economies continue to recover from the impacts of the COVID-19 pandemic;
incremental L3R capacity that came into service October 2021 further supporting demand growth
and the implementation of full L3R surcharge of US$0.93 per barrel beginning October 2021
compared to the Canadian L3R program US$0.20 per barrel;
a higher average IJT Benchmark Toll on our Mainline System of US$4.27 in 2021, compared with
US$4.24 in 2020;
a higher foreign exchange hedge rate used to lock-in US dollar denominated Canadian Mainline
revenue; and
higher equity income from our investment in the Seaway Crude Pipeline System driven by
increased volumes.
The positive business factors above were partially offset by the following:
•
•
the recognition of a provision in the fourth quarter against the interim Mainline IJT for barrels
shipped between July 1, 2021 and December 31, 2021; and
the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average
exchange rate in 2021 versus 2020.
GAS TRANSMISSION AND MIDSTREAM
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2021
2020
2019
3,671
1,087
3,371
Year ended December 31, 2021 compared with year ended December 31, 2020
EBITDA was positively impacted by $2.6 billion due to certain unusual, infrequent or other non-operating
factors primarily explained by the following:
•
•
•
•
an impairment loss of $111 million in 2021 to our investment in the PennEast pipeline project after
a decision by project partners to cease development, compared to a combined impairment loss of
$615 million in 2020 to our investments in SESH and Steckman;
the absence in 2021 of a $1.7 billion non-cash impairment to the carrying value of our investment
in DCP Midstream and a $324 million loss resulting from our share of asset and goodwill
impairments recognized by DCP Midstream, both recognized in 2020;
the absence in 2021 of a $159 million loss recorded in 2020 to reflect the Texas Eastern rate case
settlement that re-established the EDIT regulated liability that was previously eliminated in
December 2018; partially offset by
a negative impact in equity earnings of $44 million in 2021, compared with a positive impact of
$22 million in 2020 relating to changes in the mark-to-market value of derivative financial
instruments within our equity method investee, DCP Midstream.
65
After taking into consideration the factors above, we saw a $45 million decrease to EBITDA that is
primarily explained by the following business factors:
•
•
the net unfavorable effect of translating US dollar EBITDA at a lower Canadian to US dollar
average exchange rate in 2021, compared to the same period in 2020; and
the absence in 2021 of the recognition of revenue in 2020 that related to the settlement of interim
rates collected from shippers on Texas Eastern, retroactive to June 1, 2019.
The factors above were partially offset by the following positive factors:
•
•
•
higher commodity prices benefiting equity earnings from our Aux Sable and DCP Midstream joint
ventures;
increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern
system in 2020; and
a full year of contributions from the Atlantic Bridge Phase III project after it commenced service in
January of 2021.
GAS DISTRIBUTION AND STORAGE
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2021
2020
2019
2,117
1,748
1,747
Year ended December 31, 2021 compared with year ended December 31, 2020
EBITDA was positively impacted by $338 million due to certain unusual, infrequent or other non-operating
factors primarily explained by the following:
•
•
a gain of $303 million resulting from the sale of our investment in Noverco; and
a non-cash, unrealized gain of $14 million in 2021, compared with a loss of $10 million in 2020,
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 risks.
After taking into consideration the positive factors above, the remaining $31 million increase is primarily
explained by the following significant business factors:
•
•
higher distribution charges resulting from increases in rates and customer base; and
higher storage revenue, mainly relating to storage optimization activities.
The positive business factors above were partially offset by the following factors:
•
•
higher operating and administrative costs largely related to operational, pipeline integrity and
safety costs; and
when compared with the normal weather forecast embedded in rates, weather was warmer in
both 2021 and 2020, negatively impacting EBITDA in both years. Warmer than normal weather in
2021 negatively impacted 2021 EBITDA by approximately $55 million, while the warmer than
normal weather in 2020 negatively impacted 2020 EBITDA by approximately $33 million.
66
RENEWABLE POWER GENERATION
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2021
2020
2019
508
523
111
Year ended December 31, 2021 compared with year ended December 31, 2020
EBITDA was negatively impacted by $15 million primarily explained by the following significant business
factors:
•
weaker wind resources at Canadian and United States wind facilities and the effects from the
Texas winter storm in February 2021; and
the absence in 2021 of reimbursements received in 2020 at certain Canadian wind facilities
resulting from a change in operator; partially offset by
the sale of a 49% interest of an entity that holds our 50% interest in EMF.
•
•
ENERGY SERVICES
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2021
2020
2019
(313)
(236)
250
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, 2021 compared with year ended December 31, 2020
EBITDA was positively impacted by $164 million due to certain unusual, infrequent or other non-operating
factors, primarily explained by a non-cash, unrealized net gain of $53 million in 2021, compared with a
loss of $122 million in 2020, reflecting the revaluation of derivatives used to manage the profitability of
transportation and storage transactions, as well as manage the exposure to movements in commodity
prices.
After taking into consideration the positive factors above, the remaining $241 million decrease is primarily
explained by the following significant business factors:
•
•
•
•
significant compression of location and quality differentials in certain markets;
limited storage opportunities in 2021 due to market backwardation compared to favorable storage
opportunities in 2020;
fewer opportunities to achieve profitable transportation margins on facilities in which Energy
Services holds capacity obligations; and
adverse impacts from the major winter storm experienced across the US Midwest during
February 2021.
67
ELIMINATIONS AND OTHER
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2021
2020
2019
356
(113)
429
Eliminations and Other includes operating and administrative costs which are not allocated to business
segments and the impact of foreign exchange hedge settlements. Eliminations and Other also includes
the impact of new business development activities and corporate investments.
Year ended December 31, 2021 compared with year ended December 31, 2020
EBITDA was positively impacted by $24 million due to certain unusual, infrequent or other non-operating
factors, primarily explained by the following:
•
•
•
•
employee severance, transition and transformation costs of $87 million in 2021 compared with
$279 million in 2020 primarily related to our voluntary workforce reduction program offered in the
second quarter of 2020;
the absence in 2021 of a non-cash loss of $74 million in 2020 relating to the recognition of a
corporate guarantee obligation; and
the absence in 2021 of a loss of $43 million in 2020 relating to the write-down of certain
investments in emerging energy and other technologies; partially offset by
a non-cash, unrealized gain of $55 million in 2021 compared with a gain of $318 million in 2020
reflecting net fair value gains and losses arising from the change in the mark-to-market value of
derivative financial instruments used to manage foreign exchange risk.
After taking into consideration the factors above, the remaining $445 million increase is primarily
explained by realized gains related to settlements under our enterprise-wide foreign exchange risk
management program which substantially offset the foreign currency exposures realized within our
business segments’ results.
68
GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our commercially secured projects, organized by business
segment:
Enbridge's
Ownership
Interest
Estimated
Capital
Cost1
Expenditures
to Date2
Status2
Expected
In-Service
Date
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1. US Line 3 Replacement
Program
2. Southern Access
Expansion
100 % US$4.0 billion
US$4.1 billion
Complete In-service
100 % US$0.5 billion
US$0.5 billion
Complete In-service
100 % US$0.1 billion
US$0.1 billion
Complete In-service
$1.0 billion
$0.9 billion
Complete In-service
3. Other - US
GAS TRANSMISSION AND MIDSTREAM
100 %
4. T-South Reliability &
Expansion Program
5. Spruce Ridge Project
6. Texas Eastern
100 %
$0.4 billion
100 % US$0.4 billion
Modernization
7. Appalachia to Market II
100 % US$0.1 billion
8. Other - US3
Various US$0.6 billion
$0.4 billion
No significant
expenditures to date
No significant
expenditures to date
US$0.4 billion
Complete In-service
2024 -
2026
2025
Pre-
construction
Pre-
construction
Various
stages
GAS DISTRIBUTION AND STORAGE
9. System Enhancement
100 %
Projects4
$0.4 billion
$0.1 billion
10. Storage Enhancements
100 %
$0.1 billion
11. Natural Gas Expansion
100 %
$0.1 billion
Program5
No significant
expenditures to date
No significant
expenditures to date
RENEWABLE POWER GENERATION
12. East-West Tie Line
25.0 %
$0.2 billion
$0.2 billion
13. Solar Self-Power
Projects6
14. Saint-Nazaire France
Offshore Wind
Project7
15. Provence Grand Large
Floating Offshore
Wind Project8
16. Fécamp Offshore Wind
Project9
100 % US$0.2 billion
25.5 %
$0.9 billion
(€0.6 billion)
No significant
expenditures to date
$0.5 billion
(€0.3 billion)
25.0 %
$0.1 billion
(€0.1 billion)
No significant
expenditures to date
Pre-
construction
17. Calvados Offshore
21.7 %
Wind Project9
17.9 %
$0.7 billion
(€0.5 billion)
$0.9 billion
(€0.6 billion)
$0.3 billion
(€0.2 billion)
$0.1 billion
(€0.1 billion)
Under
construction
Pre-
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, 2021.
3
Includes the US$0.1 billion Texas Eastern Middlesex Extension placed into service in September of 2021 and the US$0.1 billion
Cameron Extension Project placed into service in November of 2021.
69
Various
stages
Under
construction
Pre-
construction
Under
construction
Pre-
construction
Under
construction
2021 -
2023
2021 -
2023
2H - 2022
2022 -
2027
1H - 2022
2022 -
2023
2H - 2022
2023
2023
2024
4
Includes the $0.1 billion London Line Replacement Project placed into service in December of 2021. Total estimated capital cost
consists of site restoration work expected to be completed in 2022.
5 Represents Phase 2 of the Natural Gas Expansion Program (the Program) and the estimated capital cost is presented net of the
maximum funding assistance we expect to receive from the Government of Ontario. The expected in-service dates represent the
expected completion dates of the leave to construct requirements.
6 Self-Power Projects consists of solar self-power projects along our liquids and gas transmission systems. All 10 projects will be
located at existing pump and/or compressor stations.
7 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of
2021. Our equity contribution is $0.15 billion, with the remainder of the project financed through non-recourse project level debt.
8 Reflects the sale of 50% of an entity that holds our 50% interest in Provence Grand Large to CPP Investments. Our equity
contribution is $0.05 billion, with the remainder of the project financed through non-recourse project level debt for each project.
9 Each project reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first
quarter of 2021. Our equity contribution is $0.1 billion, with the remainder of the project financed through non-recourse project
level debt.
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 2021:
•
•
United States Line 3 Replacement Program – replacement of the existing Line 3 crude oil pipeline
between Neche, North Dakota and Superior, Wisconsin is now complete and in-service. The US L3R
Program supports the safety and operational reliability of the Mainline System, enhances system
flexibility and allows us to optimize throughput on the mainline. The US L3R Program restored the
original capacity of 760 kbpd and brought the total Mainline System operating capacity to
approximately 3.1 mmbpd.
Southern Access Expansion – expansion of our existing Southern Access crude oil pipeline from
996 kbpd to approximately 1,200 kbpd.
GAS TRANSMISSION AND MIDSTREAM
The following commercially secured growth projects were placed into service in 2021:
•
•
•
Atlantic Bridge Phase III – an expansion of the Algonquin natural gas transmission systems which
transports 133 million cubic feet per day (mmcf/d) of natural gas to the New England region. The third
and final phase of Atlantic Bridge fully commenced service in January 2021 with the Weymouth
compressor station being brought online.
T-South Reliability & Expansion Program – a natural gas pipeline expansion of Westcoast's BC
Pipeline in southern BC that provides improved compressor reliability and additional capacity of
approximately 190 mmcf/d into the Huntington/Sumas market at the US/Canada border.
Spruce Ridge Project – a natural gas pipeline expansion of Westcoast's BC Pipeline in northern BC.
The project provides additional capacity of up to 402 mmcf/d.
The following commercially secured growth projects are currently in pre-construction stages:
•
Texas Eastern Modernization Phase II – this program is the modernization of compression facilities
in Pennsylvania and New Jersey to increase safety and reliability and reduce associated greenhouse
gas emissions at multiple sites on our Texas Eastern system. The program will be completed in
stages over a period of years beginning in 2024.
70
•
Appalachia to Market II - the expansion is designed to deliver 55 MDth per day on the Texas
Eastern pipeline from the Appalachia supply basin in Southwest Pennsylvania to existing local
distribution company customers in New Jersey beginning in late 2025. The project is a brown-field
expansion and upgrade of existing Texas Eastern facilities in Pennsylvania.
GAS DISTRIBUTION AND STORAGE
The following commercially secured growth project was placed into service in 2021:
•
System Enhancement Projects – The London Line Replacement Project replaced two existing
pipelines known collectively as the London Line and included the construction of approximately 90.5-
kilometers of natural gas pipeline and ancillary facilities in southern Ontario.
The following commercially secured growth projects are currently in various stages of construction:
•
•
•
System Enhancement Project – The Lake Shore Kipling Oshawa Loop (KOL) Replacement Project
is a replacement of approximately 4.5-kilometers of natural gas pipeline and ancillary facilities of the
Cherry to Bathurst segment of the KOL along Lake Shore Boulevard in the City of Toronto. The St.
Laurent Ottawa North Replacement Project is a replacement of approximately 16-kilometers of
natural gas pipeline in the City of Ottawa. The first two phases of this project have already been
completed. Phases 3 and 4 represent approximately 11.4-kilometers of pipeline.
Storage Enhancements – Storage Enhancements are part of a larger delta pressuring project to
increase deliverability and storage capacity at Enbridge Gas' storage facilities. The additional
deliverability and storage capacity will be sold as part of Enbridge Gas' unregulated storage portfolio.
Natural Gas Expansion Program – The Program was created under the Access to Natural Gas Act,
2018 to help expand access to natural gas to areas of Ontario that currently do not have access to
the natural gas distribution system. Under Phase 2 of the Program, we will be provided up to $214
million in funding assistance to deliver 25 community expansion and two economic development
projects throughout Ontario.
RENEWABLE POWER GENERATION
The following commercially secured growth projects are currently in various stages of construction:
•
•
•
•
East-West Tie Line – a transmission project that will parallel an existing double-circuit, 230 kilovolt
transmission line that connects the Wawa Transformer Station to the Lakehead Transformer Station
near Thunder Bay, Ontario, including a connection midway in Marathon, Ontario.
Solar Self-Power Projects – 10 solar self-power projects under development in Wisconsin, Illinois,
Pennsylvania, Kentucky, Ohio and Minnesota, with a combined estimate of 97 MW of emissions-free
generating capacity. These projects will provide clean power directly to our liquids and natural gas
pipeline rights-of-way.
Saint-Nazaire France Offshore Wind Project – a wind project located off the west coast of France
that is expected to generate approximately 480-MW. Project revenues are backed by a 20-year fixed
price power purchase agreement (PPA) with added power production protection.
Provence Grand Large Floating Offshore Wind Project – a floating offshore wind facility off the
southern coast of France that secured funding in 2021 and continues to prepare onshore construction
and is expected to generate approximately 24-MW. Project revenues are underpinned by a 20-year
fixed price PPA.
71
•
•
Fécamp Offshore Wind Project – an offshore wind project located off the northwest coast of France
and is expected to generate approximately 500-MW. Project revenues are underpinned by a 20-year
fixed price PPA.
Calvados Offshore Wind Project – an offshore wind project located off the northwest coast of
France that is expected to generate approximately 448-MW. Project revenues are underpinned by a
20-year fixed price power purchase agreement.
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
•
•
Sea Port Oil Terminal Project – the Sea Port Oil Terminal (SPOT) project consists of onshore and
offshore facilities, including a fixed platform located approximately 30 miles off the coast of Brazoria
County, Texas. SPOT is designed to load very large crude carriers at rates of approximately 85,000
barrels per hour, or up to approximately 2 million bpd. Along with Enterprise Products Partners, L.P.,
we announced our intent to jointly develop and market SPOT, and we will work to finalize an equity
participation agreement. The agreement will allow us to purchase an ownership interest in SPOT,
subject to SPOT receiving a deep-water port license.
Enbridge Houston Oil Terminal – the terminal is expected to have an ultimate capability of up to 15
million barrels of storage, access to crude oil from all major North American production basins and will
be fully integrated with the Seaway Crude Pipeline System to allow for access to Houston-area
refineries, existing export facilities, the SPOT project and other facilities in the future.
GAS TRANSMISSION AND MIDSTREAM
•
Rio Bravo Pipeline – the Rio Bravo Pipeline is designed to transport up to 4.5 billion cubic feet per
day (bcf/d) of natural gas from the Agua Dulce supply area to NextDecade Corporation's
(NextDecade) Rio Grande liquefied natural gas (LNG) export facility in the Port of Brownsville, Texas.
We have executed a precedent agreement with NextDecade under which we will provide firm
transportation capacity on the Rio Bravo Pipeline to NextDecade's Rio Grande LNG export facility for
a term of at least 20 years. Construction of the pipeline will be subject to the Rio Grande LNG export
facility reaching a final investment decision.
72
•
•
•
Ridgeline Expansion Project Opportunity – We are working on a potential expansion of the ETNG
system which would provide additional natural gas for the Tennessee Valley Authority (TVA) to
support the replacement of an existing coal-fired power plant as it continues to transition its
generation mix towards lower-carbon fuels. The TVA environmental review scoping process has
begun for this proposed plant; TVA published a Notice of Intent on the Federal Register on June 15,
2021 to initiate their review process. Several options to replace the retiring coal-fired generation
would be assessed in TVA’s Environmental Impact Statement (EIS). Should the onsite natural gas
option of building a combined cycle plant be selected through TVA’s review, we would deliver on the
required expansion of the East Tennessee system. ETNG’s proposed project would consist of the
installation of additional pipeline primarily along the ETNG system, the installation of one electric-
powered compressor station and solar facilities behind the meter, as well as other design features all
contributing to minimizing greenhouse gas emissions. Should TVA’s environmental assessment
determine that the natural gas solution of building an onsite combined cycle plant is the optimal
supply source, and pending the approval and receipt of all necessary permits, construction of the
pipeline would begin in 2025 with a target in-service date of fall 2026.
Valley Crossing Expansion Project – On January 10, 2022, we executed a precedent agreement
with Texas LNG Brownsville LLC (Texas LNG) under which, via an expansion of our Valley Crossing
Pipeline, we will provide 0.72 bcf/d firm transportation capacity to Texas LNG’s proposed LNG
liquefaction and export facility in the Port of Brownsville, Texas for a term of at least 20 years.
Expansion of the pipeline will be subject to Texas LNG’s export facility reaching a final investment
decision.
Texas Eastern Venice Extension Project - a reversal and expansion of Texas Eastern’s Line 40
from its existing New Roads compressor station to a new delivery point with the proposed Gator
Express pipeline just south of Texas Eastern’s Larose compressor station. The project is expected to
deliver 1.26 bcf/d of feed gas to Venture Global’s proposed Plaquemines LNG export facility located
in Plaquemine Parish, Louisiana. The expansion will be subject to the Plaquemines LNG export
facility reaching a final investment decision.
We also have a portfolio of additional projects under development that have not yet progressed to the
point of securement.
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.
Material contractual obligations arising in the normal course of business primarily consist of long-term
contracts, annual debt maturities and related interest obligations, rights-of-way and leases. See Part II.
Item 8. Financial Statements and Supplementary data - Note 18 - Debt and Note 27 - Leases for amounts
outstanding at December 31, 2021, related to debt and leases.
73
Long-term contracts are contracts that we have signed for the purchase of services, pipe and other
materials totaling $5.9 billion which are expected to be paid over the next five years. Long-term contracts
also consists of the following purchase obligations: gas transportation and storage contracts, firm capacity
payments and gas purchase commitments, transportation, service and product purchase obligations, and
power commitments.
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. Our current
financing plan does not include any issuances of additional common equity. On January 19, 2022, we
closed a $750 million private placement offering of non-call 10-year fixed-to-fixed subordinated notes
which mature on January 19, 2082. The net proceeds from the offering will be used to redeem the
Preference Shares, Series 17 at par on March 1, 2022.
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 long-
term debt issuances totaling US$3.9 billion and $3.2 billion in 2021:
Type of Issuance
Issuance Date
Entity
(in millions of Canadian dollars, unless stated otherwise)
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Gas Inc.
Enbridge Pipelines Inc.
Spectra Energy Partners, LP1
1 Issued through Texas Eastern, a wholly-owned operating subsidiary of SEP.
February 2021
June 2021
June, October 2021
September 2021
September 2021
September 2021
May 2021
September 2021
Floating rate senior-notes
Sustainability-linked senior notes
Senior notes
Medium-term notes
Sustainability-linked medium-term
notes
Medium-term notes
Medium-term notes
Senior notes
Amount
US$500
US$1,000
US$2,000
$1,100
$400
$900
$800
US$400
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, 2021:
(millions of Canadian dollars)
Enbridge Inc.
Enbridge (U.S.) Inc.
Enbridge Pipelines Inc.
Enbridge Gas Inc.
Total committed credit facilities
Maturity1
Total
Facilities
Draws2
Available
2022-2026
2023-2026
2023
2023
9,137
6,948
3,000
2,000
21,085
7,837
4,845
667
1,515
14,864
1,300
2,103
2,333
485
6,221
1 Maturity date is inclusive of the one-year term out option for certain credit facilities.
2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability-linked
credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year,
revolving, syndicated credit facility for $3.0 billion.
74
On July 22 and 23, 2021, we renewed approximately $8.0 billion of our five-year credit facilities, extending
the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day
extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023.
On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending
the maturity date out to July 2025.
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand
letter of credit facilities, of which $854 million was unutilized as at December 31, 2021. As at December
31, 2020, we had $849 million of uncommitted demand letter of credit facilities, of which $533 million was
unutilized.
As at December 31, 2021, our net available liquidity totaled $6.5 billion (2020 - $12.7 billion), consisting of
available credit facilities of $6.2 billion (2020 - $12.3 billion) and unrestricted Cash and cash equivalents
of $286 million (2020 - $452 million) as reported in 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, 2021, we were in compliance with all
debt covenants and expect to continue to comply with such covenants.
Cash flow growth, proceeds from non-core asset dispositions, 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 EBITDA.
On June 1, 2021, Moody's upgraded the credit ratings of Enbridge Inc., including our senior unsecured
and issuer ratings, to Baa1 from Baa2. Moody's also upgraded the credit ratings of our subsidiaries: EEP,
EELP, SEP and Texas Eastern. The outlooks of all five entities are stable.
There are no material restrictions on our cash. Total Restricted cash of $34 million, as reported on the
Consolidated Statements of Financial Position, primarily includes cash collateral and future pipeline
abandonment costs collected and held in trust. Cash and cash equivalents held by certain subsidiaries
may not be readily accessible for alternative use by us.
Excluding current maturities of long-term debt, as at December 31, 2021 and 2020, we had a negative
working capital position of $3.1 billion and $3.7 billion, respectively. In both periods, the major contributing
factor to the negative working capital position was the current liabilities associated with 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.
75
SOURCES AND USES OF CASH
Year ended December 31,
(millions of Canadian dollars)
Operating activities
Investing activities
Financing activities
Effect of translation of foreign denominated cash and cash
equivalents and restricted cash
Net increase/(decrease) in cash and cash equivalents and restricted
cash
2021
2020
2019
9,256
(10,657)
1,236
9,781
(5,177)
(4,770)
9,398
(4,658)
(4,745)
(5)
(20)
(170)
(186)
44
39
Significant sources and uses of cash for the years ended December 31, 2021 and 2020 are summarized
below:
Operating Activities
Typically, the primary factors impacting cash flow from operating activities year-over-year include changes
in our operating assets and liabilities in the normal course due to various factors, including the impact of
fluctuations in commodity prices and activity levels on working capital within our business segments, the
timing of tax payments, as well as timing of cash receipts and payments generally. Refer to Part II. Item 8.
Financial Statements and Supplementary Data - Note 28. Changes in Operating Assets and Liabilities.
Cash provided by operating activities is also impacted by changes in earnings and certain unusual,
infrequent and other non-operating factors, as discussed under Results of Operations.
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, 2021, 2020
and 2019 is set out below:
Year ended December 31,
(millions of Canadian dollars)
Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution and Storage
Renewable Power Generation
Energy Services
Eliminations and Other
Total capital expenditures
2021
2020
2019
4,051
2,353
1,343
16
1
54
7,818
2,032
2,066
1,134
81
2
90
5,405
2,548
1,695
1,100
23
2
124
5,492
2021
The increase in cash used in investing activities primarily resulted from the following factors:
• Our acquisition of Moda on October 12, 2021 and higher capital expenditures related to the
completion of the US L3R Program, partially offset by higher proceeds received from dispositions
in 2021 compared with 2020 due to the sale of our interest in Noverco on December 30, 2021.
2020
The increase in cash used in investing activities primarily resulted from the following factors:
•
Lower proceeds from asset dispositions in 2020 compared with 2019, primarily due to the sale of
the federally regulated portion of our Canadian natural gas gathering and processing businesses
assets on December 31, 2019.
76
•
The factor above was partially offset by lower contributions to the Gray Oak Holdings LLC equity
investment in 2020, higher return of capital primarily from equity investments in Seaway Crude
Holdings LLC, MarEn Bakken Company LLC, Gray Oak Holdings LLC and Enbridge Renewable
Infrastructure Investments S.a.r.l., and lower net cash invested in affiliate loans in 2020 compared
with 2019.
Financing Activities
Cash provided by and used in financing activities primarily relates to issuances and repayments of
external debt, as well as transactions with our common and preference shareholders relating to dividends,
share issuances and share redemptions. Cash from financing activities is also impacted by changes in
distributions to, and contributions from, noncontrolling interests.
2021
The increase in cash provided by financing activities primarily resulted from the following factors:
•
•
Increased issuances of long-term debt, commercial paper and credit facility draws and short-term
borrowings, along with lower repayments of long-term debt in 2021 compared to 2020.
The factors above were partially offset by the redemption of Westcoast Energy Inc.'s (Westcoast)
preferred shares in 2021 and increased common share dividend payments primarily due to the
increase in our common share dividend rate.
2020
Cash used in financing activities in 2020 was consistent with 2019 due to the following factors:
•
Increased commercial paper and credit facility draws, increased short-term borrowings and lower
repayments of long-term debt in 2020 compared with 2019, partially offset by lower issuances of
long-term debt.
• The absence in 2020 of the redemption of Westcoast's preferred shares in 2019.
• The above factors were partially offset by increased common share dividend payments primarily
due to the increase in our common share dividend rate.
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 Part II. Item 8. Financial Statements and
Supplementary Data - Note 31 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 guarantee
arrangements and financings entered into by our equity investments. For additional information on these
commitments, see Part II. Item 8. Financial Statements and Supplementary Data - Note 30 Commitments
and Contingencies and Note 31 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.
77
Preference Share Issuances
Since July 2011, we have issued 315 million preference shares for gross proceeds of approximately $7.9
billion with the following characteristics:
Gross Proceeds
Dividend Rate
(Canadian dollars, unless otherwise stated)
Series A
Series B
$125 million
$457 million
5.50 %
3.42 %
3-month treasury bill
plus 2.40%
Series C5
Series D
Series F
Series H
Series J
Series L
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 19
$43 million
$450 million
$500 million
$350 million
US$200 million
US$400 million
$450 million
$400 million
$400 million
US$400 million
$600 million
US$200 million
$250 million
$275 million
$500 million
$350 million
$275 million
$750 million
$500 million
Per Share
Base
Redemption
Value2
Redemption
and Conversion
Option Date2,3
Right to
Convert
Into3,4
$25
$25
—
June 1, 2022
—
Series C
Dividend1
$1.37500
$0.85360
—
$1.11500
4.46 %
$1.17224
4.69 %
4.38 %
$1.09400
4.89 % US$1.22160
4.96 % US$1.23972
$1.27152
5.09 %
$1.09476
4.38 %
4.07 %
$1.01825
5.95 % US$1.48728
$0.93425
3.74 %
5.38 % US$1.34383
$1.11224
4.45 %
$1.02424
4.10 %
$0.98452
3.94 %
$0.76076
3.04 %
$0.74576
2.98 %
$1.28750
5.15 %
$1.22500
4.90 %
$25
$25
$25
$25
US$25
US$25
$25
$25
$25
US$25
$25
US$25
$25
$25
$25
$25
$25
$25
$25
June 1, 2022
March 1, 2023
June 1, 2023
September 1, 2023
June 1, 2022
September 1, 2022
December 1, 2023
March 1, 2024
June 1, 2024
June 1, 2023
September 1, 2024
March 1, 2024
March 1, 2024
December 1, 2024
March 1, 2025
June 1, 2025
September 1, 2025
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
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/number of days in a
year) x three-month 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/
number of days in a year) x three-month US Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or
2.8% (Series 6).
5 The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.15501 from $0.15349 on March 1,
2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1,
2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the
issuance thereof.
PREFERENCE SHARE REDEMPTION
We intend to exercise our right to redeem all of our outstanding cumulative redeemable minimum rate
reset preference shares, Series 17, on March 1, 2022 at a price of $25 per Series 17 share, together with
all accrued and unpaid dividends, if any.
78
Dividends
We have paid common share dividends in every year since we became a publicly traded company in
1953. In December 2021, we announced a 3% increase in our quarterly dividend to $0.86 per common
share, or $3.44 annualized, effective with the dividend payable on March 1, 2022, thereby making a
dividend increase for 27 straight years.
For the years ended December 31, 2021 and 2020, total dividends paid were $6.8 billion and $6.6 billion,
respectively, all of which were paid in cash and reflected in financing activities.
On December 6, 2021, our Board of Directors declared the following quarterly dividends. All dividends are
payable on March 1, 2022 to shareholders of record on February 15, 2022.
Common Shares1
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series C2
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
Dividend per share
$0.86000
$0.34375
$0.21340
$0.15719
$0.27875
$0.29306
$0.27350
US$0.30540
US$0.30993
$0.31788
$0.27369
$0.25456
US$0.37182
$0.23356
US$0.33596
$0.27806
$0.25606
$0.24613
$0.19019
$0.18644
$0.32188
$0.30625
1 The quarterly dividend per common share was increased 3% to $0.86 from $0.835, effective March 1, 2022.
2 The quarterly dividend per share paid on Series C was increased to $0.15501 from $0.15349 on March 1, 2021, was increased to
$0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1, 2021 and was decreased
to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the date of issuance of the Series C
Preference Shares.
79
SUMMARIZED FINANCIAL INFORMATION
On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries,
SEP and EEP (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a
senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding
series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships
entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally
guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The
Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the
Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes
issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the
outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same
position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's
outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the
Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the
Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not
otherwise guaranteed any of Enbridge's outstanding series of senior notes.
Consenting SEP notes and EEP notes under Guarantee
SEP Notes1
4.750% Senior Notes due 2024
3.500% Senior Notes due 2025
3.375% Senior Notes due 2026
5.950% Senior Notes due 2043
4.500% Senior Notes due 2045
EEP Notes2
5.875% Notes due 2025
5.950% Notes due 2033
6.300% Notes due 2034
7.500% Notes due 2038
5.500% Notes due 2040
7.375% Notes due 2045
1 As at December 31, 2021, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2 As at December 31, 2021, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.
80
Enbridge Notes under Guarantees
US Dollar Denominated1
Floating Rate Senior Notes due 2022
Floating Rate Senior Notes due 2023
2.900% Senior Notes due 2022
4.000% Senior Notes due 2023
0.550% Senior Notes due 2023
3.500% Senior Notes due 2024
2.500% Senior Notes due 2025
4.250% Senior Notes due 2026
1.600% Senior Notes due 2026
3.700% Senior Notes due 2027
3.125% Senior Notes due 2029
2.500% Sustainability-linked Senior Notes due
2033
4.500% Senior Notes due 2044
5.500% Senior Notes due 2046
4.000% Senior Notes due 2049
3.400% Senior Notes due 2051
Canadian Dollar Denominated2
4.850% Senior Notes due 2022
3.190% Senior Notes due 2022
3.940% Senior Notes due 2023
3.940% Senior Notes due 2023
3.950% Senior Notes due 2024
2.440% Senior Notes due 2025
3.200% Senior Notes due 2027
6.100% Senior Notes due 2028
2.990% Senior Notes due 2029
7.220% Senior Notes due 2030
7.200% Senior Notes due 2032
3.100% Sustainability-linked Senior Notes due
2033
5.570% Senior Notes due 2035
5.750% Senior Notes due 2039
5.120% Senior Notes due 2040
4.240% Senior Notes due 2042
4.570% Senior Notes due 2044
4.870% Senior Notes due 2044
4.100% Senior Notes due 2051
4.560% Senior Notes due 2064
1 As at December 31, 2021, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was
approximately US$11 billion.
2 As at December 31, 2021, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was
approximately $9.2 billion.
Rule 3-10 of the US Securities and Exchange Commission's (SEC) Regulation S-X provides an
exemption from the reporting requirements of the Securities Exchange Act of 1934, as amended
(Exchange Act) for fully consolidated subsidiary issuers of guaranteed securities and subsidiary
guarantors and allows for summarized financial information in lieu of filing separate financial statements
for each of the Partnerships.
The following Summarized Combined Statement of Earnings and the Summarized Combined Statements
of Financial Position combines the balances of EEP, SEP and Enbridge.
Summarized Combined Statement of Earnings
(millions of Canadian dollars)
Operating loss
Earnings
Earnings attributable to common shareholders
Year ended
December 31, 2021
(64)
4,970
4,604
81
Summarized Combined Statements of Financial Position
(millions of Canadian dollars)
Accounts receivable from affiliates
Short-term loans receivable from affiliates
Other current assets
Long-term loans receivable from affiliates
Other long-term assets
Accounts payable to affiliates
Short-term loans payable to affiliates
Other current liabilities
Long-term loans payable to affiliates
Other long-term liabilities
December 31,
2021
December 31,
2020
3,442
4,947
605
51,983
3,732
1,982
2,891
8,110
41,370
41,353
2,108
4,926
375
43,217
4,237
1,267
4,117
5,628
32,035
41,353
The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to
the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-
Guarantors.
Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can
be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the
guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments
become due under the guarantee:
•
•
•
received less than reasonably equivalent value or fair consideration for the incurrence of the
guarantee and was insolvent or rendered insolvent by reason of such incurrence;
was engaged in a business or transaction for which the guarantor’s remaining assets constituted
unreasonably small capital; or
intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as
they mature.
The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of
liability that the Partnerships could incur without causing the incurrence of obligations under the
guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law.
Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all
payments, damages and expenses incurred by that Partnership in discharging its obligations under the
guarantees for the Guaranteed Enbridge Notes.
Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of
either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and
discharged automatically upon the occurrence of any of the following events:
•
•
•
any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of
equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of
Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a
result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
the merger of that Partnership into Enbridge or the other Partnership or the liquidation and
dissolution of that Partnership;
the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as
contemplated by the applicable indenture or guarantee agreement;
82
•
•
•
with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting
EEP notes listed above;
with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting
SEP notes listed above; or
with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a
majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.
The guarantee obligations of Enbridge of the Guaranteed Partnership Notes will terminate with respect to
any series of Guaranteed Partnership Notes if that series is discharged or defeased.
The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.
LEGAL AND OTHER UPDATES
LIQUIDS PIPELINES
Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement
In 2019, the Michigan Attorney General filed a complaint in the Michigan Ingham County Circuit Court (the
Court) that requests the Court to declare the easement granted in 1953 that we have for the operation of
Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in
the Straits “as soon as possible after a reasonable notice period to allow orderly adjustments by affected
parties”. On December 15, 2021, we removed the case to the US District Court in the Western District of
Michigan (US District Court), where it was assigned to Judge Janet T. Neff. The removal of the Attorney
General’s case to federal court follows a November 16, 2021 ruling (further described below) which held
that the similar (and now dismissed) 2020 lawsuit brought by the Governor to force Line 5’s shutdown
raised important federal issues that should be heard in federal court. On December 21, 2021, the Attorney
General made a request to file a remand motion and on December 28, 2021, we responded to her
request to file that motion. On January 5, 2022, the court issued an Order allowing the Attorney General
to file a motion to remand the 2019 case. The Attorney General’s motion and brief was filed on January
14, 2022, and our response is due on February 11, 2022. The motion is expected to be fully briefed by
March 2022.
On November 13, 2020, the Governor of Michigan and the Director of the Michigan Department of Natural
Resources notified us that the State of Michigan (the State) was revoking and terminating the easement
granted in 1953 that allows Line 5 to operate across the Straits. The notice demanded that the portion of
Line 5 that crosses the Straits must be shut down by May 2021. On November 24, 2020, we filed in the
US District Court for the Western District of Michigan a Notice of Removal, which removed the State’s
November Complaint to federal court, and a Complaint for Declaratory and Injunctive Relief that requests
the US District Court to enjoin the Governor from taking any action to prevent or impede the operation of
Line 5. US District Court Judge Neff was assigned to the cases and on November 16, 2021, Judge Neff
issued an order denying the State’s motion to remand its 2020 case back to Ingham County Circuit
Court ,finding that the case should remain in federal court. Judge Neff also ruled in our favor on our
motion for additional briefing and granted the Government of Canada’s motion to file a supplemental brief,
which reiterated that the 1977 Transit Pipelines Treaty between the US and Canada had been invoked in
October and that the matter is of great importance to Canada. Subsequently, the Governor voluntarily
dismissed the State’s lawsuit on November 30, 2021.
Our lawsuit to prohibit the Governor of Michigan and Director of the Michigan Department of Natural
Resources from interfering with the operation of Line 5, remains in federal court. On November 30, 2021
the State made a request to Judge Neff to file a motion to dismiss the complaint. On the same date, we
made a request to file a motion for summary judgment. Briefing on these motions began on January 18,
2022 and is scheduled to be complete by April 2022.
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In 2021, we completed the engineering and design phase of the Great Lakes Tunnel Project and we have
begun the process of hiring a contractor to construct the tunnel. We continue to actively pursue state and
federal regulatory permits from the US Army Corps of Engineers (Army Corps), the Michigan Department
of Environment, Great Lakes & Energy (EGLE) and the Michigan Public Service Commission (MPSC).
The EGLE permits were granted in the first quarter of 2021; one of the EGLE permits was challenged by
the Bay Mills Indian Community. Dispositive motions are fully briefed and with the Administrative Law
Judge for decision.
On June 23, 2021, the Army Corps announced they would proceed with an EIS for the Great Lakes
Tunnel Project to replace Line 5 at the Straits. On June 23, 2021, we issued a statement stating that
construction on this project would be delayed due to the EIS.
In the MPSC contested case proceeding, testimony has been filed, and the hearing took place during
January 2022, with briefing scheduled to be complete by March 2022.
Dakota Access Pipeline
We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of DAPL. The
Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court
for the District of Columbia (the District Court) contesting the lawfulness of the Army Corps easement for
DAPL, including the adequacy of the Army Corps’ environmental review and tribal consultation process.
The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018.
On June 14, 2017, the District Court found the Army Corps’ environmental review to be deficient and
ordered the Army Corps to conduct further study concerning spill risks from DAPL. In August 2018, the
Army Corps completed on remand the further environmental review ordered by the District Court and
reaffirmed the issuance of the easement for DAPL. All four plaintiff Tribes subsequently amended their
complaints to include claims challenging the adequacy of the Army Corps’ August 2018 remand decision.
On March 25, 2020, in response to amended complaints from the Tribes, the District Court found the
Army Corps’ environmental review on remand was deficient and ordered the Army Corps to prepare an
EIS to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July
6, 2020, the District Court issued an order vacating the Army Corps’ easement for DAPL and ordering that
the pipeline be shut down by August 5, 2020. Dakota Access, LLC and the Army Corps appealed the
decision and filed a motion for a stay pending appeal with the US Court of Appeals for the District of
Columbia Circuit. On August 5, 2020, the US Court of Appeals stayed the District Court’s July 6 order to
shut down and empty the pipeline, but did not stay the District Court’s March 25 order requiring the Army
Corps to prepare an EIS or the District Court’s July 6 order vacating the DAPL easement.
On January 26, 2021, the US Court of Appeals affirmed the District Court’s decision, holding that the Army
Corps is required to prepare an EIS and that the Army Corps’ easement for DAPL is vacated. Dakota
Access, LLC has since filed a petition asking the US Supreme Court to review the decision that an EIS is
required. The US Court of Appeals also determined that, absent considering the closure of DAPL in the
context of an injunction proceeding, the District Court could not order DAPL’s operations to cease. While
not an issue before the US Court of Appeals, the US Court of Appeals also recognized that the Army
Corps could consider whether to allow DAPL to continue to operate in the absence of an easement. On
September 20, 2021, DAPL requested that the US Supreme Court review the US Court of Appeals
decision. That request, opposed by the US Government and the Tribes, remands pending.
On May 21, 2021, the District Court dismissed the plaintiff Tribes’ request for an injunction enjoining DAPL
from operating until the Army Corps has completed its EIS. The right of the plaintiff Tribes to appeal the
denial of the injunction request expired on July 20, 2021. The Army Corps earlier indicated that it did not
intend, at that time, to exercise its authority to bar DAPL’s continued operation, notwithstanding the
absence of an easement and that it anticipates completing its EIS by March 2022.
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On July 22, 2021, the Army Corps filed a notice with the District Court advising that the Pipeline and
Hazardous Materials Safety Administration (PHMSA) issued a notice asserting violations of federal safety
regulations resulting from the operation of DAPL. The Army Corps stated that it would consider PHMSA’s
notice as part of its ongoing consideration of whether and how the Army Corps will enforce its rights on
property crossed by the pipeline and in the context of the ongoing EIS. The Army Corps also granted the
request from the Tribes to extend the EIS completion date to September 2022.
OTHER LITIGATION
We and our subsidiaries are involved in 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. 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.
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.
CRITICAL ACCOUNTING ESTIMATES
Our consolidated financial statements are prepared in accordance with generally accepted accounting
principles in the United States of America (US GAAP), 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 (ASC) 805 Business Combinations in
accounting for our acquisitions. The acquired long-lived assets, 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.
Goodwill Impairment
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.
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We perform our impairment assessment annually on April 1 at the reporting unit level. Reporting units are
determined 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 have the option to first assess qualitative factors to determine whether it is necessary to perform the
quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine
the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or
negatively affected by relevant events and circumstances since the last fair value assessment. Our
evaluation includes, but is not limited to, assessment of macroeconomic trends, regulatory environments,
capital accessibility, operating income trends, and industry conditions. Based on our assessment of the
qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less
than it’s carrying amount, a quantitative goodwill impairment assessment is performed.
The quantitative goodwill impairment assessment involves determining the fair value of our reporting units
and comparing those values to the carrying value of each corresponding 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. Fair value of our reporting units is estimated using a
combination of discounted cash flow models and earnings multiples techniques. The determination of fair
value using the discounted cash flow model technique requires the use of estimates and assumptions
related to discount rates, projected operating income, terminal value growth rates, capital expenditures
and working capital levels. The cash flow projections include significant judgments and assumptions
relating to discount rates and expected future capital expenditures. The determination of fair value using
the earnings multiples technique requires assumptions to be made in relation to maintainable earnings
and earnings multipliers for reporting units.
Our most recent annual assessment of the goodwill balance was performed on April 1, 2021. As at April 1,
2021, our reporting units were equivalent to our reportable segments. We performed a quantitative
goodwill impairment assessment for the Gas Transmission and Midstream reporting unit and qualitative
assessments for the Liquids Pipelines and Gas Distribution and Storage reporting units. Our goodwill
impairment assessments did not result in an impairment charge. Also, we did not identify any indicators of
goodwill impairment during the remainder of 2021.
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.
With respect to equity method investments, we assess at each balance sheet date whether there is
objective evidence that the investment is impaired by completing a quantitative or qualitative analysis of
factors impacting the investment. If there is objective evidence of impairment, we 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 investment.
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Asset fair value is 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 asset
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.
Regulatory Accounting
Certain of our businesses are subject to regulation by various authorities, including but not limited to, the
CER, the FERC, the Alberta Energy Regulator, La Régie de l’energie du Québec and the OEB.
Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking
and agreements with customers. To recognize the economic effects of the actions of the regulator, the
timing of recognition of certain revenues and expenses in these operations may differ from that otherwise
expected under US GAAP for non-rate-regulated entities. Key determinants in the ratemaking process
are:
•
•
•
•
Costs of providing service, including operating costs, capital invested, depreciation expense and
taxes;
Allowed rate of return, including the equity component of the capital structure and related income
taxes;
Interest costs on the debt component of the capital structure; 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 CER’s Land Matters Consultation Initiative
(LMCI) and for future removal and site restoration costs as approved by the OEB.
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, 2021 and 2020, our regulatory assets totaled $5.9 billion and $5.6 billion,
respectively, and regulatory liabilities totaled $3.4 billion and $3.4 billion, respectively.
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Depreciation
Depreciation of property, plant and equipment, our largest asset with a net book value at December 31,
2021 and 2020, of $100.1 billion and $94.6 billion, 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
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.
Pension and Other Postretirement Benefits
We use certain assumptions relating to the calculation of defined benefit pension and other postretirement
liabilities and net periodic benefit costs. These assumptions comprise management’s best estimates of
expected return on plan assets, future salary levels, 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 anticipated to be made under each of the respective plans. The expected return on plan
assets is determined using market-related values and assumptions on the asset mix consistent with the
investment policy relating to the assets and their projected returns. The assumptions are reviewed
annually by our independent actuaries. Actual results that differ from results based on assumptions are
amortized over future periods and, therefore, could materially affect the expense recognized and the
recorded obligation in future periods.
The following sensitivity analysis identifies the impact on the December 31, 2021 Consolidated Financial
Statements of a 0.5% change in key pension and other postretirement benefit obligations (OPEB)
assumptions:
Canada
United States
Obligation
Expense
Obligation
Expense
(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
378
—
(71)
21
N/A
31
21
(15)
1
N/A
70
—
(6)
8
—
5
5
(2)
—
1
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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 30. 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. The discount rates used to estimate the present value of the expected future
cash flows for the year ended December 31, 2021 ranged from 0.9% to 9.0% (2020 - 1.8% to 9.0%). 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 CER issued a decision related to the LMCI, which required holders of an authorization to
operate a pipeline under the CER 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
CER'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 CER. Following the CER'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 CER 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.
The Minnesota Public Utilities Commission (MPUC), in its June 28, 2018 decision granting the Line 3
Replacement Project’s Certificate of Need, required Enbridge to establish and fund a decommissioning
trust (Decommissioning Trust Fund) for the purpose of funding the cost of retiring Line 3 Replacement
Project assets at the end of their useful lives. Further to the Certificate of Need decision, in late 2021 the
MPUC established a process for the purpose of determining the terms and conditions of the
Decommissioning Trust Fund. Enbridge anticipates this MPUC process to be completed in 2022, with a
decision from the MPUC in the second half of 2022. Enbridge expects to recover contributions necessary
to fund the Decommissioning Trust Fund from its shippers through rates.
CHANGES IN ACCOUNTING POLICIES
Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 3. Changes in Accounting
Policies.
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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 is used to hedge anticipated foreign
currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain
net investments in US dollar denominated investments and subsidiaries using foreign currency derivatives
and US 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. We monitor our debt portfolio mix of fixed and
variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of
Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt
outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-
receive floating interest rate swaps may be used to hedge against the effect of future interest rate
movements. We have implemented a program to 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
3.9%.
We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market
interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against
future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value
via execution of fixed to floating interest rate swaps. As at December 31, 2021, we do not have any pay
floating-receive fixed interest rate swaps outstanding.
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 established a program including 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 2.0%.
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.
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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.
Market Risk Management
We have a Risk Policy to minimize the likelihood that adverse cash flow 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 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 cash flow volatility arising from
market related risks to an acceptable approved risk tolerance threshold. Our market risk metric is Cash
Flow at Risk (CFaR).
CFaR is a statistically derived measurement used to measure the maximum cash flow loss 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
Consolidated Statements of Financial Position as at December 31, 2021. CFaR assumes that no further
mitigating actions are taken to hedge or otherwise minimize exposures and the selection of a one month
holding period reflects the mix of price risk sensitive assets at Enbridge. 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.
The consolidated CFaR policy limit for Enbridge is 3.5% of its forward 12 month normalized cash flow. At
December 31, 2021 and 2020 CFaR was $103 million and $128 million or 0.9% and 1.2%, respectively, of
estimated 12 month forward normalized cash flow.
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 ready access to either the Canadian or US public capital markets, subject to
market conditions. 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, 2021. 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 strong investment grade credit ratings.
Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit
exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of
counterparty credit exposure using external credit rating services and other analytical tools.
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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
reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties
in those circumstances.
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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
93
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Enbridge Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated statements of financial position of Enbridge Inc. and its
subsidiaries (together, the Company) as of December 31, 2021 and 2020, 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, 2021, 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, 2021, 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 financial position of the Company as of December 31, 2021 and 2020, and the results of its
operations and its cash flows for each of the three years in the period ended December 31, 2021 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, 2021, 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 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.
PricewaterhouseCoopers LLP
111-5th Avenue SW, Suite 3100, Calgary, Alberta, Canada T2P 5L3
T: +1 403 509 7500, F: +1 403 781 1825
“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.
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.
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 financial statements for
external purposes in accordance with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the
consolidated financial statements that was communicated or required to be communicated to the audit
committee and that (i) relates to accounts or disclosures that are material to the consolidated financial
statements and (ii) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the consolidated financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing
a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Goodwill impairment assessment
As described in Notes 2 and 16 to the consolidated financial statements, the Company’s goodwill balance
was $32,775 million at December 31, 2021. As disclosed by management, an annual goodwill impairment
assessment is performed at the reporting unit level as of April 1 of each year, or more frequently if events
or circumstances indicate that the carrying value of goodwill may be impaired. Management has the
option to first assess qualitative factors to determine whether it is necessary to perform the quantitative
goodwill impairment assessment. In making the qualitative assessment, management considers
macroeconomic trends, changes to regulatory environments, capital accessibility, operating income
trends, and changes to industry conditions. The quantitative goodwill impairment assessment involves
determining the fair value of the Company’s reporting units and comparing those values to the carrying
value of each reporting unit, including goodwill. Fair value is estimated using a combination of discounted
cash flow and earnings multiples techniques. The determination of fair value using the discounted cash
flow technique requires the use of estimates and assumptions related to discount rates, projected
operating income, terminal value growth rates, expected future capital expenditures and working capital
levels. The determination of fair value using the earnings multiples technique requires assumptions to be
made in relation to maintainable earnings and earnings multipliers for reporting units. In the current year,
the quantitative goodwill impairment assessment was performed for the Gas Transmission and Midstream
(Gas Transmission) reporting unit, while the qualitative goodwill impairment assessments were performed
for the Liquids Pipelines and Gas Distribution and Storage reporting units.
The principal considerations for our determination that performing procedures relating to the goodwill
impairment assessment is a critical audit matter are the significant judgment required by management
when (i) developing the significant assumptions related to operating income trends used in the qualitative
assessment for all reporting units outside of the Gas Transmission reporting unit, and (ii) developing such
significant assumptions as discount rates, projected operating income, expected future capital
expenditures and earnings multipliers used to estimate the fair value of the Gas Transmission reporting
unit. This led to a high degree of auditor judgment, effort and subjectivity in performing procedures to
evaluate the reasonableness of management’s significant assumptions used in the qualitative assessment
and the quantitative assessment of the Gas Transmission reporting unit. In addition, the audit effort
involved the use of professionals with specialized skill and knowledge to assist in performing the
procedures and evaluating the audit evidence obtained over the quantitative assessment.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with
forming our overall opinion on the consolidated financial statements. These procedures included testing
the effectiveness of controls relating to management’s goodwill impairment assessment, including controls
over (i) the development of significant assumptions related to operating income trends used in the
qualitative assessment and (ii) the determination of the fair value estimate of the Gas Transmission
reporting unit. These procedures also included, among others (i) evaluating the reasonableness of
significant assumptions used by management in the qualitative assessment of the Company’s reporting
units, specifically those related to operating income trends and (ii) testing management’s process for
developing the fair value estimate of the Gas Transmission reporting unit. Testing management’s process
for developing the fair value estimate of the Gas Transmission reporting unit included evaluating the
appropriateness of the discounted cash flow and the earnings multiples models; testing the completeness,
accuracy, and relevance of underlying data used in the models; and evaluating the reasonableness of
significant assumptions used by management in determining the fair value estimate including discount
rates, projected operating income, expected future capital expenditures and earnings multipliers.
Assessing the reasonableness of projected operating income and its trends, and expected future capital
expenditures, involved evaluating whether these significant assumptions were reasonable considering the
current and past performance of the Company’s reporting units, external industry data, and evidence
obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to
assist in evaluating the appropriateness of management’s discounted cash flow and earnings multiples
models and evaluating the reasonableness of assumptions used in the models, specifically discount rates
and earnings multipliers.
/s/PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Canada
February 11, 2022
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 (Note 4)
Operating expenses
Commodity costs
Gas distribution costs
Operating and administrative
Depreciation and amortization
Impairment of long-lived assets
Total operating expenses
Operating income
Income from equity investments (Note 13)
Impairment of equity investments (Note 13)
Other income/(expense)
Net foreign currency gain
Gain/(loss) on dispositions
Other
Interest expense (Note 18)
Earnings before income taxes
Income tax expense (Note 25)
Earnings
Earnings attributable to noncontrolling interests
Earnings attributable to controlling interests
Preference share dividends
Earnings attributable to common shareholders
Earnings per common share attributable to common shareholders
(Note 6)
Diluted earnings per common share attributable to common
shareholders (Note 6)
The accompanying notes are an integral part of these consolidated financial statements.
2021
2020
2019
26,873
4,026
16,172
47,071
19,259
3,663
16,165
39,087
26,608
2,094
6,712
3,852
—
39,266
7,805
1,711
(111)
286
319
374
(2,655)
7,729
(1,415)
6,314
(125)
6,189
(373)
5,816
18,890
1,779
6,749
3,712
—
31,130
7,957
1,136
(2,351)
181
(17)
74
(2,790)
4,190
(774)
3,416
(53)
3,363
(380)
2,983
29,309
4,205
16,555
50,069
28,802
2,202
6,991
3,391
423
41,809
8,260
1,503
—
477
(300)
258
(2,663)
7,535
(1,708)
5,827
(122)
5,705
(383)
5,322
2.87
1.48
2.64
2.87
1.48
2.63
98
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31,
(millions of Canadian dollars)
Earnings
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges
Change in unrealized gain on net investment hedges
Other comprehensive income/(loss) from equity investees
Excluded components of fair value hedges
Reclassification to earnings of loss on cash flow hedges
Reclassification to earnings of pension and other postretirement
benefits (OPEB) amounts
Reclassification to earnings of gain on equity investees
Actuarial gain/(loss) on pension and OPEB
Foreign currency translation adjustments
Other comprehensive income/(loss), net of tax
Comprehensive income
Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to controlling interests
Preference share dividends
Comprehensive income attributable to common shareholders
2021
2020
2019
6,314
3,416
5,827
162
49
(12)
(5)
235
21
(62)
394
(507)
275
6,589
(95)
6,494
(373)
6,121
(457)
102
(1)
5
198
13
—
(167)
(853)
(1,160)
2,256
(22)
2,234
(380)
1,854
(437)
281
40
—
127
13
—
(96)
(3,035)
(3,107)
2,720
(7)
2,713
(383)
2,330
The accompanying notes are an integral part of these consolidated financial statements.
99
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Year ended December 31,
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 21)
Balance at beginning and end of year
Common shares (Note 21)
Balance at beginning of year
Shares issued on exercise of stock options
Balance at end of year
Additional paid-in capital
Balance at beginning of year
Stock-based compensation
Repurchase of noncontrolling interest
Options exercised
Change in reciprocal interest
Other
Balance at end of year
Deficit
Balance at beginning of year
Earnings attributable to controlling interests
Preference share dividends
Common share dividends declared
Dividends paid to reciprocal shareholder
Modified retrospective adoption of ASU 2016-13 Financial Instruments - Credit Losses
Other
Balance at end of year
Accumulated other comprehensive income/(loss) (Note 23)
Balance at beginning of year
Other comprehensive income/(loss) attributable to common shareholders, net of tax
Other
Balance at end of year
Reciprocal shareholding
Balance at beginning of year
Change in reciprocal interest
Balance at end of year
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 20)
Balance at beginning of year
Earnings attributable to noncontrolling interests
Other comprehensive loss attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges
Foreign currency translation adjustments
Comprehensive income attributable to noncontrolling interests
Distributions
Contributions
Redemption of noncontrolling interests
Repurchase of noncontrolling interest
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.
100
2021
2020
2019
7,747
7,747
7,747
64,768
31
64,799
64,746
22
64,768
64,677
69
64,746
277
28
—
(23)
98
(15)
365
(9,995)
6,189
(373)
(6,818)
8
—
—
(10,989)
(1,401)
305
—
(1,096)
(29)
29
—
60,826
187
30
—
(21)
76
5
277
(6,314)
3,363
(380)
(6,612)
17
(66)
(3)
(9,995)
(272)
(1,129)
—
(1,401)
—
34
65
(61)
117
32
187
(5,538)
5,705
(383)
(6,125)
18
—
9
(6,314)
2,672
(2,992)
48
(272)
(51)
22
(29)
61,367
(88)
37
(51)
66,043
2,996
125
3,364
53
3,965
122
(15)
(15)
(30)
95
(271)
15
(293)
—
—
2,542
63,368
3.34
(6)
(25)
(31)
22
(300)
23
(112)
—
(1)
2,996
64,363
3.24
(7)
(108)
(115)
7
(254)
12
(300)
(65)
(1)
3,364
69,407
2.95
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,
(millions of Canadian dollars)
Operating activities
2021
2020
2019
Earnings
Adjustments to reconcile earnings to net cash provided by operating activities:
6,314
3,416
5,827
Depreciation and amortization
Deferred income tax expense (Note 25)
Unrealized derivative fair value gain, net (Note 24)
Income from equity investments
Distributions from equity investments
Impairment of long-lived assets
Impairment of equity investments
(Gain)/loss on dispositions
Other
Changes in operating assets and liabilities (Note 28)
Net cash provided by operating activities
Investing activities
Capital expenditures
Long-term investments and restricted long-term investments
Distributions from equity investments in excess of cumulative earnings
Additions to intangible assets
Acquisitions
Proceeds from dispositions
Affiliate loans, net
Other
Net cash used in investing activities
Financing activities
Net change in short-term borrowings
Net change in commercial paper and credit facility draws
Debenture and term note issues, net of issue costs
Debenture and term note repayments
Contributions from noncontrolling interests
Distributions to noncontrolling interests
Common shares issued
Preference share dividends
Common share dividends
Redemption of preferred shares held by subsidiary (Note 20)
Other
Net cash provided by/(used in) financing activities
Effect of translation of foreign denominated cash and cash equivalents and
restricted cash
Net increase/(decrease) in cash and cash equivalents and restricted cash
Cash and cash equivalents and restricted cash at beginning of year
Cash and cash equivalents and restricted cash 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.
101
3,852
1,091
(173)
(1,711)
1,630
—
111
(319)
77
(1,616)
9,256
(7,818)
(640)
533
(275)
(3,785)
1,263
65
—
(10,657)
394
2,960
8,032
(2,264)
15
(271)
5
(367)
(6,766)
(415)
(87)
1,236
(5)
(170)
490
320
3,712
447
(756)
(1,136)
1,392
—
2,351
(6)
268
93
9,781
(5,405)
(487)
705
(215)
(24)
265
(16)
—
(5,177)
223
1,542
5,230
(4,463)
23
(300)
5
(380)
(6,560)
—
(90)
(4,770)
(20)
(186)
676
490
3,391
1,156
(1,751)
(1,503)
1,804
423
—
254
56
(259)
9,398
(5,492)
(1,159)
417
(200)
—
2,110
(314)
(20)
(4,658)
(127)
825
6,176
(4,668)
12
(254)
18
(383)
(5,973)
(300)
(71)
(4,745)
44
39
637
676
489
2,427
831
524
2,538
801
571
2,738
730
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
Restricted cash
Accounts receivable and other (Note 9)
Accounts receivable from affiliates
Inventory (Note 10)
Property, plant and equipment, net (Note 11)
Long-term investments (Note 13)
Restricted long-term investments (Note 14)
Deferred amounts and other assets
Intangible assets, net (Note 15)
Goodwill (Note 16)
Deferred income taxes (Note 25)
Total assets
Liabilities and equity
Current liabilities
Short-term borrowings (Note 18)
Accounts payable and other (Note 17)
Accounts payable to affiliates
Interest payable
Current portion of long-term debt (Note 18)
Long-term debt (Note 18)
Other long-term liabilities
Deferred income taxes (Note 25)
Commitments and contingencies (Note 30)
Equity
Share capital (Note 21)
Preference shares
Common shares (2,026 outstanding at December 31, 2021 and 2020)
Additional paid-in capital
Deficit
Accumulated other comprehensive loss (Note 23)
Reciprocal shareholding
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 20)
Total liabilities and equity
Variable Interest Entities (VIE) (Note 12)
The accompanying notes are an integral part of these consolidated financial statements.
102
2021
2020
286
34
6,862
107
1,670
8,959
100,067
13,324
630
8,613
4,008
32,775
488
168,864
1,515
9,767
90
693
6,164
18,229
67,961
7,617
11,689
105,496
7,747
64,799
365
(10,989)
(1,096)
—
60,826
2,542
63,368
168,864
452
38
5,258
66
1,536
7,350
94,571
13,818
553
8,446
2,080
32,688
770
160,276
1,121
9,228
22
651
2,957
13,979
62,819
8,783
10,332
95,913
7,747
64,768
277
(9,995)
(1,401)
(29)
61,367
2,996
64,363
160,276
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
INDEX
Page
104
105
116
117
122
124
124
127
130
130
130
131
134
136
137
138
138
139
142
143
143
146
149
150
162
165
174
176
176
177
178
179
1. Business Overview
2. Significant Accounting Policies
3. Changes in Accounting Policies
4. Revenue
5. Segmented Information
6. Earnings per Common Share
7. Regulatory Matters
8. Acquisitions and Dispositions
9. Accounts Receivable and Other
10. Inventory
11. Property, Plant and Equipment
12. Variable Interest Entities
13. Long-Term Investments
14. Restricted Long-Term Investments
15. Intangible Assets
16. Goodwill
17. Accounts Payable and Other
18. Debt
19. Asset Retirement Obligations
20. Noncontrolling Interests
21. Share Capital
22. Stock Option and Stock Unit Plans
23. Components of Accumulated Other Comprehensive Income/(Loss)
24. Risk Management and Financial Instruments
25. Income Taxes
26. Pension and Other Postretirement Benefits
27. Leases
28. Changes in Operating Assets and Liabilities
29. Related Party Transactions
30. Commitments and Contingencies
31. Guarantees
32. Quarterly Financial Data (Unaudited)
103
1. BUSINESS OVERVIEW
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.
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
and Storage, Renewable Power Generation, 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 pipelines and terminals in Canada and the United States (US) that transport
various grades of crude oil and other liquid hydrocarbons, including the Mainline System, Regional Oil
Sands System, Gulf Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken
System, and Feeder Pipelines and Other. This segment also includes Moda Midstream Operating, LLC
(Moda) which was acquired on October 12, 2021 (Note 8) and is a component of Gulf Coast and Mid-
Continent.
GAS TRANSMISSION AND MIDSTREAM
Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and
processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission,
US Midstream and Other.
GAS DISTRIBUTION AND STORAGE
Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge
Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers located
throughout Ontario. This business segment also includes natural gas distribution activities in Québec and
an investment in Noverco Inc. (Noverco). We sold our investment in Noverco to Trencap L.P. on
December 30, 2021 (Note 13).
RENEWABLE POWER GENERATION
Renewable Power Generation consists primarily of investments in wind and solar assets, as well as
geothermal, waste heat recovery and transmission assets. In North America, assets are primarily located
in the provinces of Alberta, Saskatchewan, Ontario and Québec, and in the states of Colorado, Texas,
Indiana and West Virginia. We also have offshore wind assets in operation and under development in the
United Kingdom, Germany and France.
ENERGY SERVICES
Our Energy Services businesses in Canada and the US undertake physical commodity marketing activity
and logistical services to manage our volume commitments on various pipeline systems. Energy Services
also provides energy marketing services to North American refiners, producers and other customers.
ELIMINATIONS AND OTHER
In addition to the business segments noted above, Eliminations and Other includes operating and
administrative costs that are not allocated to business segments as well as a foreign exchange hedging
program. Eliminations and Other also includes new business development activities and corporate
investments.
104
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements are prepared in accordance with accounting principles generally
accepted in the United States of America (US GAAP). Amounts are stated in Canadian dollars unless
otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use US
GAAP for the purposes of meeting both our Canadian and US continuous disclosure requirements.
BASIS OF PRESENTATION AND USE OF ESTIMATES
The preparation of financial statements in conformity with US 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: variable consideration included in revenue (Note 4); carrying values of
regulatory assets and liabilities (Note 7); purchase price allocations (Note 8); unbilled revenues; expected
credit losses; depreciation rates and carrying value of property, plant and equipment (Note 11); amortization
rates and carrying value of intangible assets (Note 15); measurement of goodwill (Note 16); fair value of asset
retirement obligations (ARO) (Note 19); valuation of stock-based compensation (Note 22); fair value of
financial instruments (Note 24); provisions for income taxes (Note 25); assumptions used to measure
retirement benefits and OPEB (Note 26); commitments and contingencies (Note 30); and estimates of losses
related to environmental remediation obligations (Note 30). Actual results could differ from these estimates.
Certain comparative figures in our consolidated financial statements have been reclassified to conform to
the current year's presentation.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include our accounts and accounts of our subsidiaries and 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 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 if there are changes in the facts and
circumstances related to a VIE. If an entity is determined to not be a VIE, the voting interest entity model
is applied, where an investor holding the majority voting rights consolidates the entity. 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.
105
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.
Investments and entities over which we exercise significant influence are accounted for using the equity
method.
REGULATION
Certain parts of our businesses are subject to regulation by various authorities including, but not limited
to, the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the Alberta
Energy Regulator, 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 US 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
CER’s Land Matters Consultation Initiative (LMCI). 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. We believe that the recovery of our regulatory assets as at December 31, 2021
is probable over the periods described in Note 7 - Regulatory Matters.
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. The corresponding impact on
earnings is included in Interest expense for the interest component and Other income/(expense) for the
equity component. In the absence of rate regulation, we would capitalize interest using a capitalization
rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding
earnings during the construction phase and the subsequent depreciation relating to the equity component
would not be recognized.
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.
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.
For certain regulated operations to which US 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 US 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 US GAAP
and no regulatory asset is recorded.
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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 creditworthiness 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 ratably over
the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are
earned by shippers when minimum volume commitments are not utilized during the period but under
certain circumstances can be used to offset overages in future periods, subject to expiry. 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 us to provide transportation services for the life
of the underlying producing fields. Under these arrangements, shippers pay us 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, 2021, 2020 and 2019, cash received net of revenue recognized for
contracts under make-up rights and similar deferred revenue arrangements was $127 million, $292 million
and $169 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 utility revenues are recorded based on 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 areas.
Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded
on a gross basis as the related contracts are not held for trading purposes and we are acting as the
principal in the transactions.
Our largest non-affiliated customer accounted for approximately 13.5% of our third-party revenues for the
year ended December 31, 2021 and 13.6% for the year ended December 31, 2020. No non-affiliated
customer exceeded 10% of our third-party revenues for the year ended December 31, 2019.
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 Commodity sales, Transportation and other services
revenue, Commodity costs, Operating and administrative expense, Net foreign currency gain/(loss) and
Interest expense.
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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 us 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 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.
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 in earnings
concurrently with the related transaction. If an anticipated hedged 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 may 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 risk of the
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 risk of the asset or liability ceases to be remeasured at fair value
and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in
earnings over the remaining life of the hedged item.
Net Investment Hedges
Gains and losses arising from the translation of our net investment in foreign operations from their
functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative
translation adjustments (CTA), a component of OCI. We currently have designated a portion of our US
dollar denominated debt, as well as a portfolio of foreign exchange forward contracts in prior periods, as a
hedge of our net investment in US dollar denominated investments and subsidiaries. As a result, the
change in fair value of the foreign currency derivatives as well as the translation of US dollar denominated
debt are reflected in OCI. 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 the disposal of a foreign operation.
Classification of Derivatives
We recognize the fair value of derivative instruments in the Consolidated Statements of Financial Position
as current and non-current assets or liabilities depending on the timing of 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 in 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.
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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 reduction to Long-term debt in the Consolidated 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 investee. To
the extent an equity investee undertakes activities necessary to commence its planned principal
operations, we capitalize interest costs associated with the investment during such period.
RESTRICTED LONG-TERM INVESTMENTS
Long-term investments that are restricted as to withdrawal or usage, for the purposes of the CER’s LMCI,
are presented as Restricted long-term investments in 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 have readily determinable fair values as other investments measured using the fair value
measurement alternative (FVMA). These investments are recorded at cost minus impairment, if any, plus
or minus the impact of observable price changes occurring in orderly transactions for an identical or
similar investment of the same issuer. Investments in equity securities measured using the FVMA are
reviewed for impairment each reporting period and written down to their fair value if objective evidence of
impairment is identified. Equity investments with readily determinable fair values are measured at fair
value through earnings. Dividends received from investments in equity securities are recognized in
earnings when the right to receive payment is established.
Investments in debt securities are classified as available-for-sale and measured at fair value through OCI.
NONCONTROLLING INTERESTS
Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated
subsidiaries. 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.
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 that taxes can be recovered through rates. Any interest and/or penalty
incurred related to tax is reflected in Income tax expense.
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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 to the functional currency using the exchange rate prevailing at the date of the transaction.
Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency
using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from
the 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 the 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 as at 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 in 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.
Interest income is recognized in earnings as it is earned with the passage of time.
CURRENT EXPECTED CREDIT LOSSES
For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses.
The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking
information and management expectations. Other loan receivables and applicable off-balance sheet
commitments utilize a discounted cash flow methodology which calculates the current expected credit
losses based on historical default probability rates associated with the credit rating of the counterparty
and the related term of the loan or commitment, adjusted for forward-looking information and
management expectations.
NATURAL GAS IMBALANCES
The Consolidated Statements of Financial Position include balances as a result of differences in gas
volumes received from, and delivered for, customers. As 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.
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INVENTORY
Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held
primarily by businesses in the Energy Services segment and materials and supplies. Natural gas held in
storage by Enbridge 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 gas purchased is deferred as a liability for
future refund, or as an asset for collection as approved by the OEB. Other inventory is recorded at the
lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other
commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the
weighted average cost of inventory, including any adjustments recorded to reduce inventory to market
value. Materials and supplies inventory is recorded at the lower of average cost or net realizable 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.
LEASES
We recognize an arrangement 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
recognize right-of-use (ROU) assets and the related lease liabilities in the Consolidated Statements of
Financial Position for operating lease arrangements with a term of 12 months or longer. We do not
separate non-lease components from the associated lease components of our lessee contracts and
account for both components as a single lease component. We combine lease and non-lease
components within a contract for operating lessor leases when certain conditions are met. ROU assets
are assessed for impairment using the same approach applied for other long-lived assets.
Lease liabilities and ROU assets require the use of judgment and estimates which are applied in
determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease,
whether there are any indicators of impairment for ROU assets and whether any ROU assets should be
grouped with other long-lived assets for impairment testing.
DEFERRED AMOUNTS AND OTHER ASSETS
Deferred amounts and other assets primarily consists of costs that regulatory authorities have permitted,
or are expected to permit, to be recovered through future rates, including: deferred income taxes; the fair
value adjustment to long-term debt; actual cost of removal of previously retired or decommissioned plant
assets; and actuarial gains and losses arising from defined benefit pension plans.
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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. 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 upon
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 of the goodwill balance on
April 1.
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 have the option to first assess qualitative factors to determine whether it is necessary to perform the
quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine
the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or
negatively affected by relevant events and circumstances since the last fair value assessment. Our
evaluation includes, but is not limited to, the assessment of macroeconomic trends, regulatory
environments, capital accessibility, operating income trends and industry conditions. Based on our
assessment of qualitative factors, if we determine it is more likely than not that the fair value of the
reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is
performed.
The quantitative goodwill impairment assessment 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. The fair value of our reporting units is estimated using a combination of
discounted cash flow and earnings multiples techniques. The determination of fair value using the
discounted cash flow technique requires the use of estimates and assumptions related to discount rates,
projected operating income, terminal value growth rates, capital expenditures and working capital levels.
Cash flow projections include significant judgments and assumptions relating to discount rates and
expected future capital expenditures. The determination of fair value using the earnings multiples
technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers
for reporting units.
The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of
businesses included in the relevant reporting unit.
On April 1, 2021, we performed a quantitative goodwill impairment assessment for the Gas Transmission
and Midstream reporting unit and qualitative assessments for the Liquids Pipelines and Gas Distribution
and Storage reporting units. Our goodwill impairment assessments did not result in an impairment charge.
Also, we did not identify any indicators of goodwill impairment during the remainder of 2021.
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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 its expected undiscounted cash flows, we will
calculate fair value based on the discounted cash flows and write the asset down to the extent that the
carrying value exceeds the fair value.
With respect to investments in debt securities and equity investments, 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. We determine whether the
decline below carrying value is other-than-temporary for equity method investments or is due to a credit
loss for investments in debt securities. If the decline is determined to be other-than-temporary for equity
method investments or is due to a credit loss for investments in debt securities, an impairment charge is
recorded in earnings with an offsetting reduction to the carrying value of the asset.
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. Fair value approximates the cost a third party would charge to perform the tasks necessary
to retire such assets and is recognized at the present value of expected future cash flows. ARO are added
to the carrying value of the associated asset and depreciated over the asset’s useful life. The
corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of
decommissioning and reclamation. 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, it is not possible to
make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements.
PENSION AND OTHER POSTRETIREMENT BENEFITS
We sponsor defined benefit and defined contribution pension plans, and defined benefit OPEB plans,
which provide group health care, life insurance benefits and other postretirement benefits.
Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unit
credit 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. The OPEB benefit obligation and net periodic benefit cost are estimated using the projected unit
credit method, where benefits are attributed to years of service, taking into consideration projection of
benefit costs.
We use mortality tables issued by the Society of Actuaries in the US (revised in 2021) and the Canadian
Institute of Actuaries (revised in 2014) to measure the benefit obligations of our US pension plans (the US
Plans) 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.
Funded pension and OPEB plan assets are measured at fair value. The expected return on funded
pension and OPEB plan assets is determined using market-related values and assumptions on the
invested asset mix consistent with the investment policies relating to the plan assets. The market-related
values reflect estimated return on investments consistent with long-term historical averages for similar
assets.
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Actuarial gains and losses arise from the difference between the actual and expected rate of return on
plan assets for that period (for funded pension and OPEB plans) or from changes in actuarial
assumptions used to determine the accrued benefit obligation, including discount rate, changes in
headcount and salary inflation experience.
The excess of the fair value of a plan’s assets over the fair value of a plan’s benefit obligation is
recognized as Deferred amounts and other assets in the Consolidated Statements of Financial Position.
The excess of the fair value of a plan’s benefit obligation over the fair value of a plan’s assets is
recognized as Accounts payable and other and Other long-term liabilities in the Consolidated Statements
of Financial Position.
Net periodic benefit cost is charged to earnings and includes:
•
cost of benefits provided in exchange for employee services rendered during the year (current
service cost);
interest cost of plan obligations;
•
• expected return on plan assets (for funded pension and OPEB plans);
• amortization of prior service costs 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.
Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined
benefit pension plans for our non-utility operations and from defined benefit OPEB plans are presented as
a component of AOCI in the Consolidated Statements of Changes in Equity. Any unrecognized actuarial
gains and losses and prior service costs and credits related to those plans that arise during the period are
recognized as a component of OCI, net of tax. Cumulative unrecognized net actuarial gains and losses
and prior service costs arising from defined benefit pension plans for our utility operations, which have
been permitted or are expected to be permitted by the regulators, to be recovered through future rates,
are presented as a component of Deferred amounts and other assets in the Consolidated Statements of
Financial Position.
Our utility operations also record regulatory adjustments to reflect the difference between certain net
periodic benefit costs for accounting purposes and net periodic benefit costs for ratemaking purposes.
Offsetting regulatory assets or liabilities are recorded to the extent net periodic benefit costs are expected
to be collected from or refunded to customers, respectively, in future rates. In the absence of rate
regulation, regulatory assets or liabilities would not be recorded and net periodic benefit costs would be
charged to earnings and OCI on an accrual basis.
For defined contribution plans, contributions made by us are expensed in the period in which the
contribution occurs.
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.
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Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the
related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and
RSUs vest one-third annually from the grant date. 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. The value of the PSUs is
also dependent on our performance relative to performance targets set out under the plan.
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 Accounts payable and other
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.
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3. CHANGES IN ACCOUNTING POLICIES
CHANGES IN ACCOUNTING POLICIES
There were no changes in accounting policies during the year ended December 31, 2021.
ADOPTION OF NEW ACCOUNTING STANDARDS
Accounting for Contract Assets and Liabilities from Contracts with Customers in a Business
Combination
Effective November 1, 2021, we adopted Accounting Standards Update (ASU) 2021-08 on a retrospective
basis beginning January 1, 2021. The new standard was issued in October 2021 to amend business
combination accounting specific to contract assets and contract liabilities resulting from contracts with
customers, requiring measurement in accordance with Accounting Standards Codification (ASC) 606. The
ASU is also applicable to contract assets and contract liabilities from other contracts to which ASC 606
applies, such as contract liabilities from the sale of nonfinancial assets within the scope of ASC 610-20.
The adoption of this ASU did not have a material impact on our consolidated financial statements.
Reference Rate Reform
For eligible hedging relationships existing as at January 1, 2021 and prospectively, we have applied the
optional expedient in ASU 2020-04 whereby the modification of the hedging instrument does not result in
an automatic hedging relationship de-designation. The adoption of this ASU did not have a material
impact on our consolidated financial statements.
Clarifying Interaction Between Equity Securities, Equity Method Investments and Derivatives
Effective January 1, 2021, we adopted ASU 2020-01 on a prospective basis. The new standard was
issued in January 2020 and clarifies that observable transactions should be considered for the purpose of
applying the measurement alternative in accordance with ASC 321 Investments - Equity Securities
immediately before the application or upon discontinuance of the equity method of accounting.
Furthermore, the ASU clarifies that forward contracts or purchased options on equity securities are not out
of scope of ASC 815 Derivatives and Hedging guidance only because, upon the contracts' exercise, the
equity securities could be accounted for under the equity method of accounting or fair value option. The
adoption of this ASU did not have a material impact on our consolidated financial statements.
Accounting for Income Taxes
Effective January 1, 2021, we adopted ASU 2019-12 on a prospective basis. The new standard was
issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting
update removes certain exceptions to the general principles in ASC 740 Income Taxes as well as
provides simplification by clarifying and amending existing guidance. The adoption of this ASU did not
have a material impact on our consolidated financial statements.
FUTURE ACCOUNTING POLICY CHANGES
Disclosures About Government Assistance
ASU 2021-10 was issued in November 2021 to increase the transparency of government assistance to
business entities. The ASU adds new disclosure requirements for transactions with government that are
accounted for using a grant or contribution accounting model by analogy. The required disclosures include
information about the nature of transactions, accounting policy applied, impacted financial statement line
items and significant terms and conditions. ASU 2021-10 is effective January 1, 2022 and can be applied
either prospectively or retrospectively with early adoption permitted. The adoption of ASU 2021-10 is not
expected to have a material impact on our consolidated financial statements.
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Accounting for Certain Lessor Leases with Variable Lease Payments
ASU 2021-05 was issued in July 2021 to amend lessor accounting for certain leases with variable lease
payments that do not depend on a reference index or a rate and would have resulted in the recognition of
a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends
the classification requirements of such leases for lessors to result in an operating lease classification.
ASU 2021-05 is effective January 1, 2022 and can be applied either retrospectively or prospectively with
early adoption permitted. The adoption of ASU 2021-05 is not expected to have a material impact on our
consolidated financial statements.
Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts
ASU 2021-04 was issued in May 2021 to clarify issuer accounting for modifications or exchanges of
freestanding equity-classified written call options that remain equity classified after modification or
exchange. The ASU requires an issuer to determine the accounting for the modification or exchange
based on the economic substance of the modification or exchange. ASU 2021-04 is effective January 1,
2022 and should be applied prospectively. The adoption of ASU 2021-04 is not expected to have a
material impact on our consolidated financial statements.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
ASU 2020-06 was issued in August 2020 to simplify accounting for certain financial instruments. The ASU
eliminates the current models that require separation of beneficial conversion and cash conversion
features from convertible instruments and simplifies the derivative scope exception guidance pertaining to
equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures
for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity.
The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted
method for all convertible instruments and an update for instruments that can be settled in either cash or
shares. ASU 2020-06 is effective January 1, 2022 and should be applied on a full or modified
retrospective basis. The adoption of ASU 2020-06 is not expected to have a material impact on our
consolidated financial statements.
4. REVENUE
REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
Year ended December 31, 2021
(millions of Canadian dollars)
Transportation revenue
Storage and other revenue
Gas gathering and processing
revenue
Gas distribution revenue
Electricity and transmission
revenue
Total revenue from contracts with
customers
Commodity sales
Other revenue1,2
Intersegment revenue
Total revenue
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation
Energy
Services
Eliminations
and Other Consolidated
9,492
147
4,364
255
—
—
—
49
—
—
676
246
—
4,026
—
9,639
4,668
4,948
—
—
—
—
177
177
—
—
—
—
—
—
—
375
567
—
42
1
—
13
19
— 26,873
336
(1)
—
44
10,581
4,711
4,980
512 26,917
—
—
—
—
—
—
—
—
(630)
(630)
14,532
648
49
4,026
177
19,432
26,873
766
—
47,071
117
Year ended December 31, 2020
(millions of Canadian dollars)
Transportation revenue
Storage and other revenue
Gas gathering and processing
revenue
Gas distribution revenue
Electricity and transmission
revenue
Total revenue from contracts with
customers
Commodity sales
Other revenue1,2
Intersegment revenue
Total revenue
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation
Energy
Services
Eliminations
and Other Consolidated
9,161
94
4,523
274
—
—
—
27
—
—
674
203
—
3,663
—
9,255
4,824
4,540
—
—
—
—
198
198
—
—
—
—
—
—
—
584
584
—
44
2
—
17
12
— 19,259
389
—
—
24
10,423
4,870
4,569
587 19,283
—
—
—
—
—
—
—
(23)
(622)
(645)
14,358
571
27
3,663
198
18,817
19,259
1,011
—
39,087
Year ended December 31, 2019
(millions of Canadian dollars)
Transportation revenue
Storage and other revenue
Gas gathering and processing
revenue
Gas distribution revenue
Electricity and transmission
revenue
Commodity sales
Total revenue from contracts with
customers
Commodity sales
Other revenue1,2
Intersegment revenue
Total revenue
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation
Energy
Services
Eliminations
and Other Consolidated
9,082
109
4,477
268
—
—
—
—
423
—
—
4
743
201
—
4,210
—
—
9,191
5,172
5,154
—
—
—
—
180
—
180
—
—
—
—
—
—
—
—
659
369
—
30
5
—
9
16
— 29,305
387
—
(2)
71
10,219
5,207
5,179
567 29,374
—
—
—
—
—
—
—
—
(16)
(461)
(477)
14,302
578
423
4,210
180
4
19,697
29,305
1,067
—
50,069
1 Includes mark-to-market gains from our hedging program for the year ended December 31, 2021 of $59 million, (2020 -
$265 million, 2019 - $346 million).
2 Includes revenues from lease contracts. Refer to Note 27 - Leases.
We disaggregate revenue into categories which represent our principal performance obligations within
each business segment. These revenue categories represent the most significant revenue streams in
each segment and consequently are considered to be the most relevant revenue information for
management to consider in evaluating performance.
Contract Balances
(millions of Canadian dollars)
Balance as at December 31, 2021
Balance as at December 31, 2020
2,369
2,042
213
226
1,898
1,815
Contract Receivables
Contract Assets
Contract Liabilities
Contract receivables represent the amount of receivables derived from contracts with customers.
118
Contract assets represent the amount of revenue which has been recognized in advance of payments
received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at
which our right to the payment is unconditional. Amounts included in contract assets are transferred to
accounts receivable when our right to the consideration becomes unconditional.
Contract liabilities represent payments received for performance obligations which have not been fulfilled.
Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during
the year ended December 31, 2021 included in contract liabilities at the beginning of the period is $305
million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during
the year ended December 31, 2021 were $397 million.
Performance Obligations
Segment
Liquids Pipelines
Gas Transmission and Midstream •
Gas Distribution and Storage
Renewable Power Generation
Nature of Performance Obligation
•
Transportation and storage of crude oil and natural gas liquids
(NGLs)
Transportation, storage, gathering, compression and treating of
natural gas
Transportation of NGLs
Sale of crude oil, natural gas and NGLs
Supply and delivery of natural gas
Transportation of natural gas
Storage of natural gas
•
•
•
•
•
• Generation and transmission of electricity
•
Delivery of electricity from renewable energy generation facilities
There was no material revenue recognized in the year ended December 31, 2021 from performance
obligations satisfied in previous periods.
Payment Terms
Payments are received monthly from customers under long-term transportation, commodity sales, and
gas gathering and processing contracts. Payments from Gas Distribution and Storage customers are
received on a continuous basis based on established billing cycles.
Certain contracts in the US offshore business provide for us to receive a series of fixed monthly payments
(FMPs) for a specified period which is less than the period during which the performance obligations are
satisfied. As a result, a portion of the FMPs are recorded as contract liabilities. The FMPs are not
considered to be a financing arrangement because the payments are scheduled to match the production
profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their
productive lives.
Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $59.8 billion, of
which $7.4 billion is expected to be recognized during the year ended December 31, 2022.
119
The revenues excluded from the amounts above based on optional exemptions available under ASC 606,
as explained below, represent a significant portion of our overall revenues and revenues from contracts
with customers. Certain revenues such as flow-through operating costs charged to shippers are
recognized at the amount for which we have the right to invoice our customers and are excluded from the
amounts of revenue to be recognized in the future from unfulfilled performance obligations above.
Variable consideration is excluded from the amounts above due to the uncertainty of the associated
consideration, which is generally resolved when actual volumes and prices are determined. For example,
we consider interruptible transportation service revenues to be variable revenues since volumes cannot
be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for
inflation has not been reflected in the amounts above as it is not possible to reliably estimate future
inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated
contracts where the tolls are periodically reset by the regulator are excluded from the amounts above
since future tolls remain unknown. Finally, revenues from contracts with customers which have an original
expected duration of one year or less are excluded from the amounts above.
SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE
Long-Term Transportation Agreements
For long-term transportation agreements, significant judgments pertain to the period over which revenue
is recognized and whether the agreement provides for make-up rights for the shippers. Transportation
revenue earned from firm contracted capacity arrangements is recognized ratably over the contract
period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when
services are performed.
Variable Consideration
Revenue from arrangements subject to variable consideration is recognized only to the extent that it is
probable that a significant reversal in the amount of cumulative revenue recognized will not occur when
the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties
associated with variable consideration relate principally to differences between estimated and actual
volumes and prices. These uncertainties are resolved each month when actual volumes are sold or
transported and actual tolls and prices are determined.
During the year ended December 31, 2021, revenue for the Canadian Mainline has been recognized in
accordance with the terms of the Competitive Tolling Settlement (CTS), which expired on June 30, 2021.
The tolls in place on June 30, 2021 continue on an interim basis until a new commercial arrangement is
implemented and are subject to finalization and adjustment applicable to the interim period, if any. Due to
the uncertainty of adjustment to tolling pursuant to a CER decision and potential customer negotiations,
interim toll revenue recognized during the year ended December 31, 2021 is considered variable
consideration.
Recognition and Measurement of Revenue
Year ended December 31, 2021
(millions of Canadian dollars)
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation Consolidated
Revenue from products transferred at a point in time
Revenue from products and services transferred over
time1
Total revenue from contracts with customers
—
—
70
9,639
9,639
4,668
4,668
4,878
4,948
—
177
177
70
19,362
19,432
120
Year ended December 31, 2020
(millions of Canadian dollars)
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation Consolidated
Revenue from products transferred at a point in time
Revenue from products and services transferred over
time1
Total revenue from contracts with customers
—
—
60
9,255
9,255
4,824
4,824
4,480
4,540
—
198
198
60
18,757
18,817
Year ended December 31, 2019
(millions of Canadian dollars)
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation Consolidated
Revenue from products transferred at a point in time
Revenue from products and services transferred over
time1
Total revenue from contracts with customers
—
4
65
9,191
9,191
5,168
5,172
5,089
5,154
—
180
180
69
19,628
19,697
1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural
gas distribution, natural gas storage services and electricity sales.
Performance Obligations Satisfied Over Time
For arrangements involving the transportation and sale of petroleum products and natural gas where the
transportation services or commodities are simultaneously received and consumed by the shipper or
customer, we recognize revenue over time using an output method based on volumes of commodities
delivered or transported. The measurement of the volumes transported or delivered corresponds directly
to the benefits received by the shippers or customers during that period.
Determination of Transaction Prices
Prices for transportation and gas processing services are determined based on the capital cost of the
facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on
capital invested that is determined either through negotiations with customers or through regulatory
processes for those operations that are subject to rate regulation.
Prices for commodities sold are determined by reference to market price indices plus or minus a
negotiated differential and in certain cases a marketing fee.
Prices for natural gas sold and distribution services provided by regulated natural gas distribution
operations are prescribed by regulation.
121
5. SEGMENTED INFORMATION
Segmented information for the years ended December 31, 2021, 2020 and 2019 is as follows:
Year ended December 31, 2021
(millions of Canadian dollars)
Revenues
Commodity and gas distribution
costs
Operating and administrative
Income/(loss) from equity
investments
Impairment of 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 property, plant and
equipment, net
Year ended December 31, 2020
(millions of Canadian dollars)
Revenues
Commodity and gas distribution
costs
Operating and administrative
Income/(loss) from equity
investments
Impairment of 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 property, plant and
equipment, net
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation
Energy
Services
Eliminations
and Other Consolidated
10,581
4,711
4,980
512 26,917
(630)
47,071
(25)
(3,431)
—
(1,877)
(2,147)
(1,143)
— (27,174)
(48)
(180)
759
—
13
813
(111)
135
42
—
385
101
—
75
—
—
(8)
644
(33)
(4)
—
379
7,897
3,671
2,117
508
(313)
356
4,051
2,420
1,343
16
1
54
(28,702)
(6,712)
1,711
(111)
979
14,236
(3,852)
(2,655)
(1,415)
6,314
7,885
52,530
27,028
16,904
3,315
23
267
100,067
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation
Energy
Services
Eliminations
and Other Consolidated
10,423
4,870
4,569
587 19,283
(645)
39,087
(20)
(3,331)
—
(1,859)
(1,810)
(1,091)
(2) (19,450)
(67)
(191)
613
(210)
(20,669)
(6,749)
558
—
53
479
(2,351)
(52)
9
—
71
94
—
35
(3)
—
1
(1)
—
130
1,136
(2,351)
238
7,683
1,087
1,748
523
(236)
(113)
2,033
2,130
1,134
81
2
90
10,692
(3,712)
(2,790)
(774)
3,416
5,470
48,799
25,745
16,079
3,495
24
429
94,571
122
Year ended December 31, 2019
(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 before interest, income
tax expense and depreciation
and amortization
Depreciation and amortization
Interest expense
Income tax expense
Earnings
Capital expenditures1
Total property, plant and
equipment, net
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation
Energy
Services
Eliminations
and Other Consolidated
10,219
5,207
5,179
567 29,374
(477)
50,069
(29)
(3,298)
(21)
780
30
—
(2,232)
(105)
(2,354)
(1,149)
—
(2) (29,091)
(44)
—
(189)
(297)
682
(181)
4
67
31
1
8
3
472
(79)
—
(2)
515
7,681
3,371
1,747
111
250
429
2,548
1,753
1,100
23
2
124
(31,004)
(6,991)
(423)
1,503
435
13,589
(3,391)
(2,663)
(1,708)
5,827
5,550
48,783
25,268
15,622
3,658
24
368
93,723
1 Includes allowance for equity funds used during construction.
The measurement basis for preparation of segmented information is consistent with the significant
accounting policies (Note 2).
GEOGRAPHIC INFORMATION
Revenues1
Year ended December 31,
(millions of Canadian dollars)
Canada
US
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
US
1 Amounts are based on the location where the assets are held.
2021
2020
2019
20,474
26,597
47,071
16,453
22,634
39,087
19,954
30,115
50,069
2021
2020
47,102
52,965
100,067
46,499
48,072
94,571
123
6. 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 approximately 2 million as at December 31, 2021, 5 million as at December 31, 2020, and 6
million as at December 31, 2019, resulting from our reciprocal investment in Noverco. On December 30,
2021, we closed the sale of our non-operating minority ownership of Noverco. Refer to Note 13 - Long-
term Investments for more information.
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
2021
2020
2019
2,023 2,020 2,017
3
2,025 2,021 2,020
2
1
For the years ended December 31, 2021, 2020 and 2019, 18.6 million, 29.8 million and 17.8 million,
respectively, of anti-dilutive stock options with a weighted average exercise price of $52.89, $51.42 and
$53.56, respectively, were excluded from the diluted earnings per common share calculation.
7. REGULATORY MATTERS
We record assets and liabilities that result from regulated ratemaking processes that would not be
recorded under US GAAP for non-regulated entities. See Note 2 - Significant Accounting Policies for
further discussion. Our significant regulated businesses and the related accounting impacts are described
below.
Under the current authorized rate structure for certain operations, income tax costs are recovered in rates
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 temporary differences that created the
deferred income taxes, it is expected that rates will be adjusted to recover these taxes. Since most of
these temporary differences are related to property, plant and equipment costs, this recovery is expected
to occur over the life of the related assets.
124
LIQUIDS PIPELINES
Canadian Mainline
Canadian Mainline includes the Canadian portion of our mainline system and is subject to regulation by
the CER. Tolls, excluding Lines 8 and 9, are governed by the 10-year CTS which expired on June 30,
2021 (Note 4). The CTS established 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 our Lakehead System. Under the CTS, we have recognized a regulatory asset of
$2.1 billion as at December 31, 2021 (2020 - $1.9 billion) to offset deferred income taxes, as a CER 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 US and Canadian portions of the Southern Lights Pipeline are regulated by the FERC and CER,
respectively. 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 and
provide for the recovery of allowable operating and debt financing costs, plus a pre-determined after-tax
return on equity (ROE) of 10%.
GAS TRANSMISSION AND MIDSTREAM
British Columbia Pipeline and Maritimes & Northeast Canada
British Columbia (BC) Pipeline and Maritimes & Northeast (M&N) Canada are regulated by the CER.
Rates are approved by the CER through negotiated toll settlement agreements based on cost-of-service.
Both our BC Pipeline and M&N Canada systems operate under the terms of their respective negotiated
toll settlements, which stipulate an allowable ROE and the continuation and establishment of certain
deferral and variance accounts. As both settlement agreements expired in December 2021, we are
currently operating under CER-approved interim tolls and negotiating the terms of new toll settlements for
periods beginning in 2022.
US Gas Transmission
Most of our US gas transmission and storage services are regulated by the FERC and may also be
subject to the jurisdiction of various other federal, state and local agencies. The FERC regulates natural
gas transmission in US interstate commerce including the establishment of rates for services, while rates
for intrastate commerce and/or gathering services are regulated by the state gas commissions. Cost-of-
service is the basis for the calculation of regulated tariff rates, although the FERC also allows the use of
negotiated and discounted rates within contracts with shippers that may result in a rate that is above or
below the FERC-regulated recourse rate for that service.
GAS DISTRIBUTION AND STORAGE
Enbridge Gas
Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year Incentive Regulation (IR)
framework using a price cap mechanism. The price cap mechanism establishes new rates each year
through an annual base rate escalation at inflation less a 0.3% stretch factor, annual updates for certain
costs to be passed through to customers, and where applicable, the recovery of material discrete
incremental capital investments beyond those that can be funded through base rates. The IR framework
includes the continuation and establishment of certain deferral and variance accounts, as well as an
earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in
excess of 150 basis points over the annual OEB approved ROE.
125
FINANCIAL STATEMENT EFFECTS
Accounting for rate-regulated activities has resulted in the recognition of the following regulatory assets
and liabilities in the Consolidated Statements of Financial Position:
2021
2020
Recovery/Refund
Period Ends
114
145
259
86
146
232
2022
2022
December 31,
(millions of Canadian dollars)
Current regulatory assets
Under-recovery of fuel costs
Other current regulatory assets
Total current regulatory assets1 (Note 9)
Long-term regulatory assets
Deferred income taxes2
Long-term debt3
Negative salvage4
4,176
398
243
215
157
78
339
5,606
5,865
3,890
429
246
—
169
402
261
5,397
5,629
Various
2023-2046
Various
2023
Various
Various
Various
Purchase gas variance
Accounting policy changes5
Pension plan receivable6
Other long-term regulatory assets
Total long-term regulatory assets1
Total regulatory assets
Current regulatory liabilities
Purchase gas variance
Other current regulatory liabilities
Total current regulatory liabilities7
Long-term regulatory liabilities
Future removal and site restoration reserves8
Regulatory liability related to US income taxes9
Pipeline future abandonment costs (Note 14)
Other long-term regulatory liabilities
Total long-term regulatory liabilities7
Total regulatory liabilities
1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in
1,543
895
649
234
3,321
3,427
1,455
941
578
150
3,124
3,394
—
106
106
153
117
270
2021
2022
Various
2050-2072
Various
Various
Deferred amounts and other assets.
2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-
approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary
differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be
recorded.
3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra
Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished
at an amount higher than the carrying value.
4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or
decommissioned plant assets, as approved by the FERC.
5 This deferral reflects unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited,
relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this
balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and
recovered in rates, as previously approved by the OEB.
6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future
rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated
accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI.
7 Current regulatory liabilities are included in Accounts payable and other, while long-term regulatory liabilities are included in Other
long-term liabilities.
8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund
future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the
depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur
over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a
charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for
amounts previously collected.
126
9 The regulatory liability related to US income taxes resulted from the US tax reform legislation dated December 22, 2017. These
balances will be refunded to customers in accordance with the respective rate settlements approved by the FERC.
8. ACQUISITIONS AND DISPOSITIONS
ACQUISITION
Moda Midstream Operating, LLC
On October 12, 2021, through a wholly-owned US subsidiary, we acquired all of the outstanding
membership interests in Moda for $3.7 billion (US$3.0 billion) of cash plus potential contingent payments
of up to US$150 million dependent on performance of the assets (the Acquisition). The Acquisition is also
subject to customary closing and working capital adjustments. Moda owns and operates a light crude
export platform with very large crude carrier capability. The Acquisition aligns with and advances our US
Gulf Coast export strategy and enables connectivity to low-cost and long-lived reserves in the Permian
and Eagle Ford basins.
We accounted for the Acquisition using the acquisition method as prescribed by ASC 805 Business
Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value
Measurements, the acquired assets and assumed liabilities were recorded at their estimated fair values
as at the date of acquisition.
The following table summarizes the estimated preliminary fair values that were assigned to the net assets
of Moda:
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets
Property, plant and equipment (a)
Long-term investments (b)
Intangible assets (c)
Current liabilities
Long-term liabilities
Goodwill (d)
Purchase price:
Cash
Contingent consideration (e)
October 12,
2021
62
1,480
427
1,781
59
17
268
3,755
187
3,942
a) Due to the specialized nature of Moda's property, plant and equipment, which includes groups of
assets configured for use as storage facilities, pipelines and export terminals, the depreciated
replacement cost approach was adopted as the primary valuation methodology. In determining
replacement cost, both indirect costing using relevant inflation indices and direct costing using relevant
market quotes were utilized. Adjustments were then applied for physical deterioration as well as
functional and economic obsolescence. The fair value of land was determined using a market
approach, which is based on rents and offerings for comparable properties.
b) Long-term investments represent Moda's 20% equity interest in Cactus II Pipeline, LLC (Cactus II).
The fair value of Cactus II was determined using the discounted cash flow method. The discounted
cash flow method is an income-based approach to valuation which estimates the present value of
future projected benefits from the investment.
127
c) Intangible assets consist primarily of customer relationships associated with long-term take-or-pay
contracts. Fair value was determined using an income-based approach by estimating the present
value of the after-tax earnings attributable to the contracts, including earnings associated with
expected renewal terms, and will be amortized on a straight-line basis over an expected useful life of
10 years.
d) Goodwill is primarily attributable to uncontracted future revenues, existing assembled assets that
cannot be duplicated at the same cost by a new entrant, and enhanced scale and geographic diversity
which provide greater optionality and platforms for future growth. The goodwill balance recognized has
been assigned to our Liquids Pipelines segment and is tax deductible over 15 years.
e) We agreed to pay additional contingent consideration of up to US$150 million to Moda's former
membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or
exceed specified throughput levels. These performance requirements terminate the earlier of
December 31, 2023 or the date the final contingent payment is made. The US$150 million of
contingent consideration recognized in the purchase price represents the fair value of contingent
consideration at the date of acquisition. As at December 31, 2021, there were no changes to the
amount of contingent consideration recognized.
Acquisition-related expenses incurred were approximately $21 million for the year ended December 31,
2021 and are included in Operating and administrative expense in the Consolidated Statements of
Earnings.
Upon completion of the Acquisition, we began consolidating Moda. For the period beginning October 12,
2021 through to December 31, 2021, Moda generated approximately $80 million in operating revenues
and $9 million in earnings attributable to common shareholders.
Our supplemental pro forma consolidated financial information for the years ended December 31, 2021
and 2020, including the results of operations for Moda as if the Acquisition had been completed on
January 1, 2020, are as follows:
Year ended December 31,
(unaudited; millions of Canadian dollars)
Operating revenues
Earnings attributable to common shareholders1,2
2021
2020
47,339
5,771
39,435
2,938
1 Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common
shareholders for the year ended December 31 2021 and deducted for the year ended December 31, 2020.
2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments
and intangible assets of $193 million and $207 million (after-tax of $145 million and $155 million) for the years ended December
31, 2021 and 2020, respectively.
DISPOSITIONS
Line 10 Crude Oil Pipeline
In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line
10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca,
New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), owned
the Canadian and US portions of Line 10, respectively, and the related assets were included in our
Liquids Pipelines segment. The transaction closed on June 1, 2020. No gain or loss on disposition was
recorded.
128
Montana-Alberta Tie Line
In the fourth quarter of 2019, we committed to a plan to sell the Montana-Alberta Tie Line (MATL)
transmission asset, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta.
MATL was included in our Renewable Power Generation segment. The purchase and sale agreement
was signed in January 2020.
Upon the reclassification and subsequent remeasurement of MATL assets as held for sale, a loss of $297
million was included within Impairment of long-lived assets in the Consolidated Statements of Earnings for
the year ended December 31, 2019.
On May 1, 2020, we closed the sale of MATL for cash proceeds of approximately $189 million. After
closing adjustments, a gain on disposal of $4 million was included in Other income/(expense) in the
Consolidated Statements of Earnings.
Ozark Gas Transmission
In the first quarter of 2020, we agreed to sell our Ozark Gas Transmission and Ozark Gas Gathering
assets (Ozark assets). The Ozark assets are composed of a transmission system that extends from
southeastern Oklahoma through Arkansas to southeastern Missouri, and a fee-based gathering system
that accesses Fayetteville Shale and Arkoma production. These assets were included in our Gas
Transmission and Midstream segment.
On April 1, 2020, we closed the sale of the Ozark assets for cash proceeds of approximately $63 million.
After closing adjustments, a gain on disposal of $1 million was included in Other income/(expense) in the
Consolidated Statements of Earnings.
Canadian Natural Gas Gathering and Processing Businesses
On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing
businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase
price of approximately $4.3 billion, subject to customary closing adjustments. Separate agreements were
entered into for those facilities currently governed by provincial regulations and those governed by federal
regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets); these
assets were part of our Gas Transmission and Midstream segment.
On October 1, 2018, we closed the sale of the provincially regulated facilities. On December 31, 2019, we
closed the sale of the federally regulated facilities for proceeds of approximately $1.7 billion. After closing
adjustments, a loss on disposal of $268 million before tax was included in Other income/(expense) in the
Consolidated Statements of Earnings for the year ended December 31, 2019. As these assets
represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to
these assets using a relative fair value approach.
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). St. Lawrence Gas assets were included in the Gas Distribution
and Storage segment. On November 1, 2019, we closed the sale of St. Lawrence Gas for cash proceeds
of approximately $72 million. After closing adjustments, a loss on disposal of $10 million was included in
Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31,
2019.
129
Enbridge Gas New Brunswick
In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited
Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB). EGNB assets were a part of our
Gas Distribution and Storage segment. On October 1, 2019, we closed the sale of EGNB to Liberty
Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for cash
proceeds of approximately $331 million. After closing adjustments, a loss on disposal of $3 million was
included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended
December 31, 2019.
As EGNB assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the
reporting unit to these assets using a relative fair value approach. As such, allocated goodwill of $133
million was included in assets subsequently disposed.
9. ACCOUNTS RECEIVABLE AND OTHER
December 31,
(millions of Canadian dollars)
Trade receivables and unbilled revenues1
Short-term portion of derivative assets (Note 24)
Regulatory assets (Note 7)
Taxes receivable
Other
2021
2020
4,957
529
259
407
710
6,862
3,923
323
232
374
406
5,258
1 Net of allowance for expected credit losses of $87 million as at December 31, 2021 and $70 million as at December 31, 2020.
10. INVENTORY
December 31,
(millions of Canadian dollars)
Natural gas
Crude oil
Other
11. PROPERTY, PLANT AND EQUIPMENT
December 31,
(millions of Canadian dollars)
Pipelines
Facilities and equipment
Land and right-of-way1
Gas mains, services and other
Storage
Wind turbines, solar panels and other
Other
Under construction
Total property, plant and equipment
Total accumulated depreciation
Property, plant and equipment, net
2021
2020
953
624
93
1,670
710
744
82
1,536
Weighted Average
Depreciation Rate
2021
2020
2.8 %
3.1 %
2.3 %
2.7 %
2.4 %
4.0 %
8.2 %
— %
62,997
34,331
3,320
13,606
3,099
4,912
1,507
2,268
57,459
30,149
2,896
12,813
2,936
4,877
1,558
5,762
126,040 118,450
(23,879)
94,571
(25,973)
100,067
1 The measurement of weighted average depreciation rate excludes non-depreciable assets.
130
Depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $3.5 billion, $3.4
billion and $3.0 billion, respectively.
IMPAIRMENT
Access Northeast Project
In 2019, we announced that we terminated the agreements with Eversource Energy and National Grid
USA Service Company, Inc. related to the Access Northeast project. As a result, we recognized an
impairment loss of $105 million for the year ended December 31, 2019, which is included in Impairment of
long-lived assets in the Consolidated Statements of Earnings. Access Northeast is part of our Gas
Transmission and Midstream segment.
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.
12. VARIABLE INTEREST ENTITIES
CONSOLIDATED VARIABLE INTEREST ENTITIES
Our consolidated VIEs consist of legal entities where we are the primary beneficiary. We are the primary
beneficiary when our variable interest(s) provide us with (i) the power to direct the activities of the VIE that
most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the
VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. We
determine whether we are the primary beneficiary of a VIE by considering qualitative and quantitative
factors, including, but not limited to: 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.
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
Restricted cash
Accounts receivable and other
Inventory
Property, plant and equipment, net
Long-term investments
Restricted long-term investments
Deferred amounts and other assets
Intangible assets, net
Liabilities
Accounts payable and other
Other long-term liabilities
Deferred income taxes
20211
20201
247
4
99
9
359
3,052
16
101
2
108
3,638
84
182
5
271
3,367
215
1
65
7
288
3,201
14
84
3
115
3,705
52
175
5
232
3,473
1 Excludes assets and liabilities of EEP and Spectra Energy Partners, L.P. (SEP) following the subsidiary guarantees agreement
entered on January 22, 2019. See Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - Summarized Financial Information.
131
We do not have obligations to provide additional financial support to any of our consolidated VIEs.
UNCONSOLIDATED VARIABLE INTEREST ENTITIES
We currently hold interests in several non-consolidated VIEs where we are not the primary beneficiary as
we do not have the power to direct the activities of the VIEs that most significantly impact the VIEs'
economic performance. These interests include investments in limited partnerships that are assessed to
be VIEs due to the limited partners not having substantive kick-out rights or participating rights. The
power to direct the activities of a majority of these non-consolidated limited partnership VIEs is shared
amongst the partners. Each partner has representatives that make up an executive committee that makes
significant decisions for the VIE and none of the partners may make significant decisions unilaterally.
The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31,
2021 and 2020 are presented below:
December 31, 2021
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.1
EIH S.á r.l.2, 8
Enbridge Renewable Infrastructure Investments S.á r.l.3
Rampion Offshore Wind Limited5
Vector Pipeline L.P.6
Other4,7
Carrying
Amount of
the VIE
Maximum
Exposure to
Loss
113
38
54
450
189
210
1,054
195
664
2,121
508
374
426
4,288
132
December 31, 2020
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.1
Éolien Maritime France SAS2, 8
Enbridge Renewable Infrastructure Investments S.á r.l.3
PennEast Pipeline Company, LLC4
Rampion Offshore Wind Limited5
Vector Pipeline L.P.6
Other7
Carrying
Amount of
the VIE
Maximum
Exposure to
Loss
106
96
100
116
599
201
133
1,351
187
949
2,516
371
650
390
361
5,424
1 At December 31, 2021 and 2020, the maximum exposure to loss includes guarantees by us for our respective share of the VIE’s
borrowing on a bank credit facility.
2 At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection
with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding
affiliate loan receivable for $73 million held by us as at December 31, 2021. On March 18, 2021, Enbridge Renewable
Infrastructure Holdings S.á r.l. (ERIH) closed the sale of 49% of its interest in EIH S.á r.l. to the Canada Pension Plan Investment
Board (CPP Investments).
3 At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in
connection with the project for which we would be liable in the event of default by the VIE and an outstanding affiliate loan
receivable for $807 million and $904 million held by us as at December 31, 2021 and 2020, respectively.
4 At December 31, 2021, the maximum exposure to loss is limited to our equity investment and at December 31, 2020, the
maximum exposure to loss includes the remaining expected contributions to the joint venture.
5 At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in
project contracts in which we would be liable for in the event of default by the VIE.
6 At December 31, 2021 and 2020, the maximum exposure to loss includes the carrying value of outstanding affiliate loans
receivable for $80 million and $84 million held by us as at December 31, 2021 and 2020, respectively, and an outstanding credit
facility for $105 million as at December 31, 2021 and 2020.
7 At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection
with the project for which we would be liable in the event of default by the VIE.
8 At December 31, 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection
with the project for which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for
$132 million held by us as at December 31, 2020. In relation to the sale of 49% of EIH S.á r.l.'s interest to CPP Investments,
Eolien Maritime France SAS is now reported under EIH S.á r.l. in 2021.
We do not have an obligation to and did not provide any additional financial support to the VIEs during the
years ended December 31, 2021 and 2020.
133
13. LONG-TERM INVESTMENTS
December 31,
(millions of Canadian dollars)
EQUITY INVESTMENTS
Liquids Pipelines
MarEn Bakken Company LLC1
Gray Oak Holdings LLC2
Seaway Crude Holdings LLC
Illinois Extension Pipeline Company, L.L.C.3
Cactus II Pipeline, LLC4
Other
Gas Transmission and Midstream
Alliance Pipeline5
Aux Sable6
DCP Midstream, LLC7
Gulfstream Natural Gas System, L.L.C.
Nexus Gas Transmission, LLC
PennEast Pipeline Company, LLC
Sabal Trail Transmission, LLC
Southeast Supply Header, LLC
Steckman Ridge, LP
Vector Pipeline8
Offshore - various joint ventures
Other
Gas Distribution and Storage
Noverco Common Shares9
Other
Renewable Power Generation
EIH S.a.r.l.10
Enbridge Renewable Infrastructure Investments S.a.r.l.
Rampion Offshore Wind Limited
NextBridge Infrastructure LP
Other
Eliminations and Other
Other
OTHER LONG-TERM INVESTMENTS
Gas Distribution and Storage
Noverco Preferred Shares9
Renewable Power Generation
Emerging Technologies and Other
Eliminations and Other
Other11
Ownership
Interest
2021
2020
75.0%
35.0%
50.0%
65.0%
20.0%
30.0% - 43.8%
50.0%
42.7% - 50.0%
50.0%
50.0%
50.0%
20.0%
50.0%
50.0%
50.0%
60.0%
22.0% - 74.3%
33.3%
38.9%
47.6% - 50%
51.0%
51.0%
24.9%
25.0%
12.0% - 50.0%
1,728
469
2,634
593
434
71
504
238
397
1,180
1,724
12
1,464
82
88
189
309
2
—
20
38
54
450
186
93
1,795
502
2,668
623
—
73
269
251
331
1,175
1,745
116
1,510
84
90
201
338
4
156
13
96
100
599
122
74
42.7% - 50.0%
23
32
—
567
32
32
310
252
13,324 13,818
1 Owns 49% interest in Bakken Pipeline Investments L.L.C., which owns 75% of the Bakken Pipeline System resulting in a 27.6%
effective interest in the Bakken Pipeline System.
2 Owns 65% interest in Gray Oak Pipeline, LLC resulting in a 22.8% effective interest in Gray Oak Pipeline, LLC.
3 Owns the Southern Access Extension Project.
4 In October 2021 we acquired an effective 20.0% interest in Cactus II Pipeline, LLC through the acquisition of Moda Midstream
Operating, LLC. See Note 8 - Acquisitions and Dispositions for further discussion.
5 Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US.
6 Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products LP and Aux Sable Midstream LLC in the US.
134
7 Our ownership in DCP Midstream, LLC (DCP Midstream) holds an interest of 56.5% in DCP Midstream, LP.
8 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US.
9 On December 30, 2021, we sold our 38.9% common share and preferred share interest of Noverco Inc.
10 On March 18, 2021, we sold 49% of EIH S.a.r.l., an entity that holds our 50% interest in Éolien Maritime France SAS (EMF), to
the CPP Investments. This resulted in a 25.5% effective interest in EMF. Through our investment in EMF, we own equity interests
in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%).
11 Includes investments held and valued at fair value through net income.
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, 2021, this basis difference was
$2.5 billion (2020 - $2.4 billion), of which $730 million (2020 - $657 million) was amortizable.
For the years ended December 31, 2021, 2020 and 2019, distributions received from equity investments
were $2.2 billion, $2.1 billion and $2.2 billion, respectively.
Summarized combined financial information of our interest in unconsolidated equity investments
(presented at 100%) is as follows:
Year ended December 31,
(millions of Canadian dollars)
Operating revenues
Operating expenses
Earnings
Earnings attributable to Enbridge
December 31,
(millions of Canadian dollars)
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Noncontrolling interests
2021
2020
19,891
16,514
2,952
1,711
13,987
12,223
2,306
1,136
2021
3,581
44,497
3,678
16,950
3,786
2019
15,687
13,153
3,016
1,503
2020
3,136
45,955
3,539
19,639
3,810
Noverco Inc.
On June 7, 2021, IPL System Inc., a wholly owned subsidiary of Enbridge, entered into a purchase and
sale agreement to sell its 38.9% common share and preferred share interest in Noverco to Trencap L.P.
for $1.1 billion in cash.
On December 30, 2021, we closed the sale of Noverco for cash proceeds of $1.1 billion. After closing
adjustments, a gain on disposal of $303 million before tax was included in Other income/(expense) in the
Consolidated Statements of Earnings for the year ended December 31, 2021. Noverco was previously
included in our Gas Distribution and Storage segment.
IMPAIRMENT OF EQUITY INVESTMENTS
PennEast Pipeline Company, LLC
PennEast Pipeline Company, LLC (PennEast) is a joint venture formed to develop a natural gas
transmission pipeline to serve local distribution companies and power generators in Southeastern
Pennsylvania and New Jersey, is owned 20% by Enbridge, and is recorded as an equity method
investment. In the third quarter of 2021, PennEast determined further development of the project was no
longer viable and development of the project was ceased. As a result, we recorded an other-than-
temporary impairment loss of $111 million on our investment for the year ended December 31, 2021
based on the estimated fair value of our share of the net assets. The carrying value of this investment as
at December 31, 2021 and 2020 was $12 million and $116 million, respectively.
135
Steckman Ridge, LP
Steckman Ridge, LP (Steckman Ridge) is engaged in the storage of natural gas, is owned 50% by
Enbridge and is recorded as an equity method investment. During the year ended December 31, 2020,
Steckman Ridge’s forecasted performance was adjusted for the expectation that future available capacity
will be re-contracted at lower than expected rates and an other than temporary impairment loss on our
investment of $221 million for the year ended December 31, 2020 was recorded based on a discounted
cash flow analysis. The carrying value of this investment as at December 31, 2021 and 2020 was
$88 million and $90 million, respectively.
Southeast Supply Header, L.L.C.
Southeast Supply Header, L.L.C. (SESH) provides natural gas transmission services from east Texas and
northern Louisiana to the southeast markets of the Gulf Coast. SESH is owned 50% by Enbridge and is
recorded as an equity method investment. The forecasted performance of SESH was revised during the
year ended December 31, 2020 to reflect downward revisions to future negotiated rates as well as higher
than expected available capacity levels, caused primarily by a significant contract expiry. An other than
temporary impairment loss on our investment of $394 million for the year ended December 31, 2020 was
recorded based on a discounted cash flow analysis. The carrying value of this investment as at
December 31, 2021 and 2020 was $82 million and $84 million, respectively.
DCP Midstream, LLC
DCP Midstream, a 50% owned equity method investment of Enbridge, holds an equity interest in DCP
Midstream, LP. A decline in the market price of DCP Midstream, LP’s publicly traded units during the first
quarter of 2020 resulted in an other than temporary impairment loss on our investment in DCP Midstream
of $1.7 billion for the year ended December 31, 2020. In addition, we incurred losses of $324 million
through our equity earnings pick up in relation to asset and goodwill impairment losses recorded by DCP
Midstream, LP. The carrying value of our investment in DCP Midstream as at December 31, 2021 and
2020 was $397 million and $331 million, respectively.
Our investments in PennEast, Steckman, SESH and DCP Midstream form part of our Gas Transmission
and Midstream segment. The impairment losses were recorded within Impairment of Equity Investments
in the Consolidated Statements of Earnings.
14. RESTRICTED LONG-TERM INVESTMENTS
Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline
abandonment costs for all CER regulated pipelines as a result of the CER’s regulatory requirements
under LMCI. The funds collected are held in trusts in accordance with the CER 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.
136
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 US and Canada.
As at December 31, 2021 and 2020, we had restricted long-term investments held in trust and classified
as available-for-sale of $630 million and $553 million, respectively. The cost basis of our debt securities
classified as available-for-sale and recorded as part of our restricted long-term investment balance was
$383 million and $322 million as at December 31, 2021 and 2020, respectively. Within Other long-term
liabilities we had estimated future abandonment costs related to LMCI of $649 million and $578 million as
at December 31, 2021 and 2020, respectively (Note 7).
15. INTANGIBLE ASSETS
December 31, 2021
(millions of Canadian dollars)
Software
Power purchase agreements
Project agreement1
Customer relationships
Other intangible assets
Under development
December 31, 2020
(millions of Canadian dollars)
Software
Power purchase agreements
Project agreement1
Customer relationships
Other intangible assets
Under development
Weighted Average
Amortization Rate
Accumulated
Cost Amortization
12.0 %
4.5 %
4.0 %
8.5 %
3.9 %
— %
2,067
63
152
2,532
475
246
5,535
(1,148)
(21)
(27)
(215)
(116)
—
(1,527)
Weighted Average
Amortization Rate
Accumulated
Cost Amortization
10.5 %
4.5 %
4.0 %
5.0 %
2.7 %
— %
2,043
63
153
724
456
214
3,653
(1,299)
(18)
(21)
(139)
(96)
—
(1,573)
Net
919
42
125
2,317
359
246
4,008
Net
744
45
132
585
360
214
2,080
1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.
For the years ended December 31, 2021, 2020 and 2019, our amortization expense related to intangible
assets totaled $348 million, $294 million and $296 million, respectively. Our expected amortization
expense associated with existing intangible assets for each of the years 2022 to 2026 is $492 million.
137
16. GOODWILL
(millions of Canadian dollars)
Balance at January 1, 2020
Foreign exchange and other
Acquisition
Balance at December 31, 20201,2
Foreign exchange and other
Acquisition3
Balance at December 31, 20211,2
Gas
Transmission
and
Midstream
Gas
Distribution
and Storage
Liquids
Pipelines
Energy
Services Consolidated
7,951
(123)
—
7,828
(55)
268
8,041
19,844
(364)
—
19,480
(145)
—
19,335
5,356
—
22
5,378
—
19
5,397
2
—
—
2
—
—
2
33,153
(487)
22
32,688
(200)
287
32,775
1 Gross cost of goodwill as at December 31, 2021 and 2020 was $34.4 billion and $34.3 billion, respectively.
2 Accumulated impairment as at December 31, 2021 and 2020 was $1.6 billion.
3 In 2021, we recorded $268 million of goodwill related to the acquisition of Moda. See Note 8 - Acquisitions and Dispositions for
further discussion.
17. ACCOUNTS PAYABLE AND OTHER
December 31,
(millions of Canadian dollars)
Trade payables and operating accrued liabilities
Dividends payable
Current deferred credits
Construction payables and contractor holdbacks
Current derivative liabilities (Note 24)
Taxes payable
Other
2021
2020
4,470
1,773
853
844
717
478
632
9,767
3,497
1,728
978
855
896
622
652
9,228
138
18. DEBT
December 31,
(millions of Canadian dollars)
Enbridge Inc.
US dollar senior notes
Medium-term notes
Sustainability-linked bonds
Fixed-to-fixed subordinated term notes1
Fixed-to-floating rate subordinated term notes2
Floating rate notes3
Commercial paper and credit facility draws
Other4
Enbridge (U.S.) Inc.
Commercial paper and credit facility draws
Other4
Enbridge Energy Partners, L.P.
Senior notes
Enbridge Gas Inc.
Medium-term notes
Debentures
Commercial paper and credit facility draws
Enbridge Pipelines (Southern Lights) L.L.C.
Senior notes
Enbridge Pipelines Inc.
Medium-term notes5
Debentures
Commercial paper and credit facility draws
Enbridge Southern Lights LP
Senior notes
Spectra Energy Capital, LLC
Senior notes
Spectra Energy Partners, LP
Senior notes
Westcoast Energy Inc.
Medium-term notes
Debentures
Fair value adjustment
Other6
Total debt7
Current maturities
Short-term borrowings8
Long-term debt
Weighted Average
Interest Rate9
Maturity
2021
2020
3.2 %
3.9 %
1.1 %
5.8 %
5.8 %
1.0 %
2022 - 2051
2022 - 2064
2033
2080
2023 - 2028
2022 - 2023
2022 - 2026
0.4 %
2023 - 2026
10,992
8,123
2,363
1,263
6,442
1,579
7,837
5
4,845
7
8,536
8,323
—
1,274
6,477
956
8,719
5
492
7
6.5 %
2025 - 2045
3,095
3,886
3.8 %
9.1 %
0.5 %
4.0 %
4.0 %
8.2 %
0.7 %
4.0 %
2022 - 2051
2024 - 2025
2023
9,010
210
1,515
8,485
210
1,121
2040
949
1,038
2022 - 2051
2024
2023
2040
5,575
200
667
240
218
4,775
200
1,278
257
220
7.0 %
2032 - 2038
3.9 %
2022 - 2048
8,451
8,332
4.5 %
8.1 %
2022 - 2041
2025 - 2026
1,475
275
667
(363)
1,625
275
750
(344)
75,640
(6,164)
(1,515)
67,961
66,897
(2,957)
(1,121)
62,819
1 For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be set to equal to the Five-Year
US Treasury Rate plus a margin of 5.31% from years 10 to 30 and a margin of 6.06% from years 30 to 60.
2 For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the
Canadian Dollar Offered Rate (CDOR) or the London Interbank Offered Rate (LIBOR) plus a margin. The notes would be
converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.
3 The notes carry an interest rate equal to the three-month LIBOR plus a margin of 50 basis points and Secured Overnight
Financing Rate (SOFR) plus a margin of 40 basis points.
Included in medium-term notes is $100 million with a maturity date of 2112.
4 Primarily finance lease obligations.
5
6 Primarily unamortized discounts, premiums and debt issuance costs.
7
2021 - $36 billion and US$31 billion; 2020 - $35 billion and US$24 billion. Totals exclude capital lease obligations, unamortized
discounts, premiums and debt issuance costs and fair value adjustment.
8 Weighted average interest rates on outstanding commercial paper were 0.5% as at December 31, 2021 (2020 - 0.3%).
9 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2021.
As at December 31, 2021, all outstanding debt was unsecured.
139
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at December 31, 2021:
(millions of Canadian dollars)
Enbridge Inc.
Enbridge (U.S.) Inc.
Enbridge Pipelines Inc.
Enbridge Gas Inc.
Total committed credit facilities
Maturity1
Total
Facilities
Draws2
Available
2022-2026
2023-2026
2023
2023
9,137
6,948
3,000
2,000
21,085
7,837
4,845
667
1,515
14,864
1,300
2,103
2,333
485
6,221
1 Maturity date is inclusive of the one-year term out option for certain credit facilities.
2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability-linked
credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year,
revolving, syndicated credit facility for $3.0 billion.
On February 25, 2021, two term loans with an aggregate total of US$500 million were repaid with
proceeds from a floating rate notes issuance.
On July 22 and 23, 2021, we renewed approximately $8.0 billion of our five-year credit facilities, extending
the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day
extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023.
On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending
the maturity date out to July 2025.
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand
letter of credit facilities, of which $854 million was unutilized as at December 31, 2021. As at December
31, 2020, we had $849 million of uncommitted demand letter of credit facilities, of which $533 million was
unutilized.
Our credit facilities carry a weighted average standby fee of 0.1% 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 scheduled to mature from
2022 to 2026.
As at December 31, 2021 and 2020, commercial paper and credit facility draws, net of short-term
borrowings and non-revolving credit facilities that mature within one year, of $11.3 billion and $9.9 billion,
respectively, were supported by the availability of long-term committed credit facilities and, therefore,
have been classified as long-term debt.
140
LONG-TERM DEBT ISSUANCES
During the year ended December 31, 2021, we completed the following long-term debt issuances totaling
US$3.9 billion and $3.2 billion:
Company Issue Date
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
February 2021
June 2021
June 2021
September 2021
September 2021
October 2021
October 2021
October 2021
Floating rate senior-notes due February 20231
2.50% Sustainability-linked senior notes due August 2033
3.40% senior notes due August 2051
3.10% Sustainability-linked medium-term notes due
September 2033
4.10% medium-term notes due September 2051
0.55% senior notes due October 2023
1.60% senior notes due October 2026
3.40% senior notes due August 2051
Enbridge Gas Inc.
September 2021
September 2021
2.35% medium-term notes due September 2031
3.20% medium-term notes due September 2051
Enbridge Pipelines Inc.
May 2021
May 2021
2.82% medium-term notes due May 2031
4.20% medium-term notes due May 2051
Principal
Amount
US$500
US$1,000
US$500
$1,100
$400
US$500
US$500
US$500
$475
$425
$400
$400
Spectra Energy Partners, LP
September 2021
2.50% senior notes due September 20312
US$400
1 Notes carry an interest rate equal to the SOFR plus a margin of 40 basis points.
2 Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.
On January 19, 2022, we closed a $750 million private placement offering of non-call 10-year fixed-to-
fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering will be
used to redeem the Preference Shares, Series 17 at par on March 1, 2022.
LONG-TERM DEBT REPAYMENTS
During the year ended December 31, 2021, we completed the following long-term debt repayments
totaling $1.1 billion and US$914 million, respectively:
Company
Repayment Date
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
February 2021
March 2021
4.26% medium-term notes
3.16% medium-term notes
Enbridge Energy Partners, L.P.
June 2021
4.20% senior notes
Enbridge Gas Inc.
May 2021
December 2021
Enbridge Pipelines (Southern Lights) L.L.C.
2.76% medium-term notes
4.77% medium-term notes
June and December 2021
3.98% senior notes
Enbridge Southern Lights LP
June and December 2021
4.01% senior notes
Spectra Energy Partners, LP
March 2021
Westcoast Energy Inc.
4.60% senior notes
October 2021
3.88% medium-term notes
141
Principal
Amount
$200
$400
US$600
$200
$175
US$64
$16
US$250
$150
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, 2021, 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
Capitalized interest
2021
2020
2019
2,850
70
(50)
(215)
2,655
2,913
123
(54)
(192)
2,790
2,783
273
(67)
(326)
2,663
19. ASSET RETIREMENT OBLIGATIONS
Our ARO relate mostly to the retirement of pipelines, renewable power generation assets and obligations
related to right-of way agreements and contractual leases for land use.
The discount rates used to estimate the present value of the expected future cash flows for the year
ended December 31, 2021 ranged from 0.9% to 9.0% (2020 - 1.8% to 9.0%).
A reconciliation of movements in our ARO liabilities is as follows:
December 31,
(millions of Canadian dollars)
Obligations at beginning of year
Liabilities disposed
Liabilities incurred
Liabilities settled
Change in estimate and other
Foreign currency translation adjustment
Accretion expense
Obligations at end of year
Presented as follows:
Accounts payable and other
Other long-term liabilities
2021
2020
496
—
—
(67)
70
(3)
6
502
160
342
502
520
—
—
(30)
—
(6)
12
496
56
440
496
142
20. 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)
Algonquin Gas Transmission, L.L.C
Maritimes & Northeast Pipeline, L.L.C
Renewable energy assets
Westcoast Energy Inc.1
2021
2020
377
546
384
558
1,503 1,646
408
2,542 2,996
116
1 Includes nil and 12 million cumulative redeemable preferred shares as at December 31, 2021 and 2020, respectively.
Westcoast Energy Inc. Preferred Shares Redemption
On March 20, 2019, Westcoast Energy Inc. (Westcoast) exercised its right to redeem all of its outstanding
5.5% Cumulative Redeemable First Preferred Shares, Series 7 (Series 7 Shares) and all of its
outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 (Series 8 Shares) at a price
of $25 per Series 7 Share and $25 per Series 8 Share, respectively, for a total payment of $300 million. In
addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a
$300 million decrease in Noncontrolling interests for the year ended December 31, 2019.
On January 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable
First Preferred Shares, Series 10 with a par value of $115 million. The par value of $115 million was
included in Accounts payable and other in the Consolidated Statements of Financial Position as at
December 31, 2020.
On October 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable
First Preferred Shares, Series 12 with a par value of $300 million. As a result, we recorded a decrease of
$293 million, which represents the par value less related issuance costs, in Noncontrolling interests for
the year ended December 31, 2021.
21. 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
Shares issued on exercise of stock
options
Balance at end of year
2021
Number
of
Shares Amount
2020
Number
of
Shares Amount of Shares Amount
Number
2019
2,026 64,768 2,025 64,746
2,022 64,677
—
22
2,026 64,799 2,026 64,768
31
1
3
69
2,025 64,746
143
PREFERENCE SHARES
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
2021
2020
2019
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
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
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
144
Characteristics of the preference shares are as follows:
Dividend Rate
Dividend1
Per Share Base
Redemption
Value2
Redemption and
Conversion
Option Date2,3
Right to
Convert
Into3,4
(Canadian dollars unless otherwise stated)
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series C5
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
5.50 %
3.42 %
3-month treasury bill
plus 2.40%
$1.37500
$0.85360
$25
$25
—
June 1, 2022
—
Series C
—
$1.11500
4.46 %
$1.17224
4.69 %
4.38 %
$1.09400
4.89 % US$1.22160
4.96 % US$1.23972
$1.27152
5.09 %
$1.09476
4.38 %
4.07 %
$1.01825
5.95 % US$1.48728
3.74 %
$0.93425
5.38 % US$1.34383
$1.11224
4.45 %
$1.02424
4.10 %
$0.98452
3.94 %
$0.76076
3.04 %
$0.74576
2.98 %
$1.28750
5.15 %
$25
$25
$25
US$25
June 1, 2022
$25
March 1, 2023
$25
June 1, 2023
$25
$25 September 1, 2023
US$25
June 1, 2022
US$25 September 1, 2022
December 1, 2023
March 1, 2024
June 1, 2024
June 1, 2023
$25 September 1, 2024
March 1, 2024
March 1, 2024
Series B
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, 2024 Series 10
$25
March 1, 2025 Series 12
$25
June 1, 2025 Series 14
$25
$25 September 1, 2025 Series 16
March 1, 2022 Series 18
$25
4.90 %
$1.22500
$25
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/number of days in a
year) x three-month 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/
number of days in a year) x three-month US Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or
2.8% (Series 6).
5 The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.15501 from $0.15349 on March 1,
2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1,
2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the
issuance thereof.
PREFERENCE SHARE REDEMPTION
We intend to exercise our right to redeem all of our outstanding cumulative redeemable minimum rate
reset preference shares, Series 17, on March 1, 2022 at a price of $25 per Series 17 share, together with
all accrued and unpaid dividends, if any.
145
SHAREHOLDER RIGHTS PLAN
The Shareholder Rights Plan is designed to encourage the fair treatment of our shareholders in
connection with any takeover offer. 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.
22. STOCK OPTION AND STOCK UNIT PLANS
We maintain three long-term incentive compensation plans: the ISO Plan, the PSU Plan and the RSU
Plan. Total stock-based compensation expense recorded for the years ended December 31, 2021, 2020
and 2019 was $157 million, $145 million and $117 million, respectively. Disclosure of activity and
assumptions for material stock-based compensation plans are included below.
INCENTIVE STOCK OPTIONS
Certain key employees are granted ISOs to purchase common shares at the grant date market price.
ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date.
December 31, 2021
(options in thousands; intrinsic value in millions of Canadian
dollars; weighted average exercise price in 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
35,494
4,072
(4,142)
(1,407)
34,017
22,029
Weighted
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
48.65
43.86
41.85
50.74
49.28
49.84
5.7
4.5
128
64
1 The total intrinsic value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $24 million, $13
million and $58 million, respectively, and cash received on exercise was $2 million, $4 million and $1 million, respectively.
2 The total fair value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $25 million, $30 million
and $32 million, respectively.
146
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
Expected option term (years)2
Expected volatility3
Expected dividend yield4
Risk-free interest rate5
2021
2020
2019
4.10
4.01
4.37
5
6
6
25.5 % 18.3 % 19.9 %
6.1 %
5.9 %
2.0 %
1.3 %
7.6 %
0.7 %
1 Options granted to US employees are based on NYSE prices. The option value and assumptions shown are based on a weighted
average of the US and the Canadian options. The fair values per option for the years ended December 31, 2021, 2020 and 2019
were $3.91, $3.75 and $4.04, respectively, for Canadian employees and US$3.65, US$3.62 and US$4.09, respectively, for US
employees.
2 The expected option term is six years based on historical exercise practice and five 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 US Treasury Bond Yields.
Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for ISOs was
$16 million, $24 million and $32 million, respectively. As at December 31, 2021, unrecognized
compensation expense related to non-vested stock-based compensation arrangements granted under the
ISO Plan was $11 million. The expense is expected to be fully recognized over a weighted average period
of approximately two years.
PERFORMANCE STOCK UNITS
Under PSU awards for certain key employees, cash awards are paid following a three-year performance
cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance
period by Enbridge's weighted average share price for 20 days prior to the maturity of the grant and by a
performance multiplier. The performance multiplier ranges from zero, if our performance fails to meet
threshold performance levels, to a maximum of two if we perform within the highest range of the
performance targets. The performance multiplier is derived through a calculation of our Total Shareholder
Return percentile rank, in each case relative to a specified peer group of companies and our distributable
cash flow per share, adjusted for unusual, non-operating or non-recurring items, relative to targets
established at the time of grant. To calculate the 2021 expense, a multiplier of 0.5 was used for 2021 PSU
grants, 0.5 for 2020 PSU grants and 1.3 for the 2019 PSU grants.
December 31, 2021
(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
Number
3,056
1,895
(76)
(1,664)
218
3,429
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
1.1
181
1 The total amount paid during the years ended December 31, 2021, 2020 and 2019 for PSUs was $70 million, $14 million and $19
million, respectively.
147
Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for PSUs was
$56 million, $76 million and $40 million, respectively. As at December 31, 2021, unrecognized
compensation expense related to non-vested PSUs was $31 million. The expense is expected to be fully
recognized over a weighted average period of approximately two years.
RESTRICTED STOCK UNITS
Under RSU awards, cash awards are paid to certain of our employees vesting in equal installments on
each of the first, second and third anniversaries of the grant date. Share settled awards are given to
certain senior management employees following a three year maturity period. RSU holders receive cash
or shares 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.
December 31, 2021
(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
Number
2,453
1,514
(75)
(1,433)
246
2,705
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
1.1
129
1 The total amount paid during the years ended December 31, 2021, 2020 and 2019 for RSUs was $72 million, $27 million and $34
million, respectively.
Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for RSUs was
$85 million, $44 million and $41 million, respectively. As at December 31, 2021, unrecognized
compensation expense related to non-vested RSUs was $62 million. The expense is expected to be fully
recognized over a weighted average period of approximately two years.
148
23. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE
INCOME/(LOSS)
Changes in AOCI attributable to our common shareholders for the years ended December 31, 2021, 2020
and 2019 are as follows:
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance at January 1, 2021
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive (income)/loss
reclassified to earnings
Interest rate contracts1
Commodity contracts2
Foreign exchange contracts3
Other contracts4
Equity investment disposal
Amortization of pension and OPEB
actuarial loss and prior service costs5
Other
Tax impact
Income tax on amounts retained in
AOCI
Income tax on amounts reclassified to
earnings
Balance at December 31, 2021
(1,326)
238
296
1
5
2
—
—
17
559
(61)
(69)
(130)
(897)
5
(5)
—
—
—
—
—
—
—
(5)
—
—
—
—
(215)
568
66
(499)
(1,401)
49
(492)
(12)
520
298
—
—
—
—
—
—
—
49
—
—
—
(166)
—
—
—
—
—
—
(20)
(512)
—
—
—
56
—
—
—
—
(66)
—
3
(75)
—
—
—
—
—
28
—
548
296
1
5
2
(66)
28
—
564
—
(126)
(187)
4
4
(5)
(7)
(133)
(84)
(72)
(259)
(1,096)
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance at January 1, 2020
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive (income)/loss
reclassified to earnings
Interest rate contracts1
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, 2020
(1,073)
—
(317)
1,396
(591)
5
115
(828)
253
5
(2)
—
(335)
140
(58)
82
(1,326)
—
—
—
—
5
—
—
—
5
—
—
—
—
115
—
—
—
—
(828)
(13)
—
—
(13)
(215)
—
—
568
67
(2)
—
—
—
—
(2)
1
—
1
66
(345)
(272)
(221)
(1,522)
—
—
—
253
5
(2)
17
(204)
17
(1,249)
54
182
(4)
50
(499)
(62)
120
(1,401)
149
(millions of Canadian dollars)
Balance at January 1, 2019
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
Other
Balance at December 31, 2019
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(770)
(598)
4,323
(599)
320
(2,927)
157
(1)
5
(3)
—
(441)
—
—
—
—
—
320
—
—
—
—
—
(2,927)
169
(39)
—
(31)
138
—
(1,073)
—
(39)
—
(317)
—
—
—
1,396
34
34
—
—
—
—
—
34
6
—
6
(7)
67
(317)
2,672
(124)
(3,296)
—
—
—
—
157
(1)
5
(3)
17
(107)
17
(3,121)
28
164
(4)
24
55
(345)
(35)
129
48
(272)
1 Reported within Interest expense in the Consolidated Statements of Earnings.
2 Reported within Transportation and other services revenue, Commodity sales revenue, Commodity costs and Operating and
administrative expense in the Consolidated Statements of Earnings.
3 Reported within Transportation and other services revenue and Net foreign currency gain 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 Other income/(expense) in the
Consolidated Statements of Earnings.
24. 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 risks). 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 is used to hedge anticipated foreign
currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain
net investments in US dollar denominated investments and subsidiaries using foreign currency derivatives
and US dollar denominated debt.
150
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. We monitor our debt portfolio mix of fixed and
variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of
Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt
outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-
receive floating interest rate swaps may be used to hedge against the effect of future interest rate
movements. We have implemented a program to 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
3.9%.
We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market
interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against
future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value
via execution of fixed to floating interest rate swaps. As at December 31, 2021, we do not have any pay
floating-receive fixed interest rate swaps outstanding.
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 established a program including 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 2.0%.
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.
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
reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties
in those circumstances.
151
The following table summarizes the maximum potential settlement amounts in the event of these specific
circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.
December 31, 2021
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Deferred amounts and other assets
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
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
—
—
—
—
—
—
—
—
—
—
(112)
—
—
—
(112)
—
—
—
—
—
259
—
204
2
465
240
—
29
3
272
(176)
—
(250)
—
(426)
259
64
204
2
529
240
88
29
3
360
(303)
(150)
(264)
—
(717)
(423)
(423)
(23)
(67)
—
(24)
(84)
—
(513)
(531)
(112)
(100)
—
—
—
(23)
(84)
5
(112)
(202)
(227)
(22)
(115)
5
(359)
(41)
—
(129)
—
(170)
(61)
(1)
(13)
—
(75)
41
—
129
—
170
61
1
13
—
75
—
—
—
—
—
218
64
75
2
359
179
87
16
3
285
(262)
(150)
(135)
—
(547)
(362)
(23)
(71)
—
(456)
(227)
(22)
(115)
5
(359)
—
64
—
—
64
—
88
—
—
88
(15)
(150)
(14)
—
(179)
—
(1)
(17)
—
(18)
(15)
1
(31)
—
(45)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
152
December 31, 2020
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Deferred amounts and other assets
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
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
—
—
—
—
—
14
56
—
—
70
(5)
(423)
(2)
(1)
(431)
—
(218)
(1)
—
(219)
9
(585)
(3)
(1)
(580)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(29)
—
—
—
(29)
(87)
—
—
—
(87)
(116)
—
—
—
(116)
180
—
143
—
323
452
—
39
—
491
(151)
(2)
(278)
(3)
(434)
(673)
(23)
(57)
—
(753)
(192)
(25)
(153)
(3)
(373)
180
—
143
—
323
466
56
39
—
561
(185)
(425)
(280)
(4)
(894)
(760)
(241)
(58)
—
(1,059)
(299)
(610)
(156)
(4)
(1,069)
(28)
—
(81)
—
(109)
(218)
(25)
(9)
—
(252)
28
—
81
—
109
218
25
9
—
252
—
—
—
—
—
152
—
62
—
214
248
31
30
—
309
(157)
(425)
(199)
(4)
(785)
(542)
(216)
(49)
—
(807)
(299)
(610)
(156)
(4)
(1,069)
153
The following table summarizes the maturity and notional principal or quantity outstanding related to our
derivative instruments.
As at December 31,
Foreign exchange contracts - US
dollar forwards - purchase
(millions of US dollars)
Foreign exchange contracts - US
dollar forwards - sell (millions of
US dollars)
Foreign exchange contracts -
British pound (GBP) forwards -
sell (millions of GBP)
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
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 - power
(megawatt per hour (MW/H)
2022
2023
2024
2025
2026 Thereafter
Total
2021
2020
Total
2,508
—
—
—
—
—
2,508
3,522
9,245
5,596
4,346
3,174
2,574
492
25,427
17,859
28
29
30
30
28
32
104
92
91
86
85
343
177
801
265
885
72,500
—
—
—
—
—
72,500
72,500
395
47
35
30
26
64
597
4,635
2,363
1,784
1,132
—
—
—
5,279
5,396
20
26
21
—
—
165
18
5
11
—
12
—
—
—
—
(43)
(43)
(43)
(43)
—
—
—
—
—
67
62
199
173
12
15
1
(43)
1
(35)
1 Total is an average net purchase/(sell) of power.
154
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of cash flow hedges and net investment hedges on 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
Fair value hedges
Foreign exchange contracts
Net investment hedges
Foreign exchange contracts
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1
Interest rate contracts2
Commodity contracts3
Other contracts4
2021
2020
2019
(29)
252
(28)
1
(1)
(595)
2
(3)
(19)
(559)
(25)
10
(5)
5
—
—
191
13
(579)
2
(591)
5
296
1
2
304
5
253
—
(2)
256
5
157
(1)
(3)
158
1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements
of Earnings.
2 Reported within Interest expense in the Consolidated Statements of Earnings.
3 Reported within Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and
administrative expense in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expenses in the Consolidated Statements of Earnings.
We estimate that a loss of $47 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, 2021.
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.
Year ended December 31,
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative
Unrealized gain/(loss) on hedged item
Realized loss on derivative
Realized gain on hedged item
2021
2020
8
(15)
(41)
45
(116)
133
(12)
—
155
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)
Foreign exchange contracts1
Interest rate contracts2
Commodity contracts3
Other contracts4
Total unrealized derivative fair value gain/(loss), net
2021
2020
2019
92
2
71
8
173
902
(25)
(114)
(7)
756
1,626
178
(62)
9
1,751
1 For the respective annual periods, reported within Transportation and other services revenue (2021 - $98 million gain; 2020 -
$533 million gain; 2019 - $930 million gain) and Net foreign currency gain/(loss) (2021 - $6 million loss; 2020 - $369 million gain;
2019 - $696 million gain) in the Consolidated Statements of Earnings.
2 Reported as an increase within Interest expense in the Consolidated Statements of Earnings.
3 For the respective annual periods, reported within Transportation and other services revenue (2021 - $9 million gain; 2020 - $2
million loss; 2019 - $26 million loss), Commodity sales (2021 - $160 million gain; 2020 - $321 million loss; 2019 - $544 million
loss), Commodity costs (2021 - $105 million loss; 2020 - $207 million gain; 2019 - $459 million gain) and Operating and
administrative expense (2021 - $7 million gain; 2020 - $2 million gain; 2019 - $49 million gain) in the Consolidated Statements of
Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk 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 ready access to either the Canadian or US public capital markets, subject to
market conditions. 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, 2021. 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 strong investment grade credit ratings.
Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit
exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of
counterparty credit exposure using external credit rating services and other analytical tools.
156
We have credit concentrations and credit exposure, with respect to derivative instruments, in the following
counterparty segments:
December 31,
(millions of Canadian dollars)
Canadian financial institutions
US financial institutions
European financial institutions
Asian financial institutions
Other1
2021
2020
424
130
181
30
122
887
481
99
28
167
97
872
1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at December 31, 2021, we provided letters of credit totaling nil in lieu of providing cash collateral to our
counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association
agreements. We held no cash collateral on derivative asset exposures as at December 31, 2021 and
December 31, 2020.
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 Enbridge 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 30 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.
157
Level 2
Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than
quoted prices included within Level 1. Derivatives in this category are valued using models or other
industry standard valuation techniques derived from observable market data. Such valuation techniques
include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be
observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using
Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange
forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as
well as commodity swaps 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 physical forward commodity contracts.
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.
158
We have categorized our derivative assets and liabilities measured at fair value as follows:
December 31, 2021
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Long-term derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
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
—
—
38
—
38
—
—
—
—
—
—
—
(52)
—
(52)
—
—
—
—
—
—
—
(14)
—
(14)
259
64
71
2
396
240
88
21
3
352
(303)
(150)
(66)
—
(519)
(423)
(24)
(19)
—
(466)
(227)
(22)
7
5
(237)
—
—
95
—
95
—
—
8
—
8
—
—
(146)
—
(146)
—
—
(65)
—
(65)
—
—
(108)
—
(108)
259
64
204
2
529
240
88
29
3
360
(303)
(150)
(264)
—
(717)
(423)
(24)
(84)
—
(531)
(227)
(22)
(115)
5
(359)
159
December 31, 2020
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Long-term derivative assets
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
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
—
—
43
—
43
—
—
1
—
1
—
—
(39)
—
(39)
—
—
(1)
—
(1)
—
—
4
—
4
180
—
33
—
213
466
56
24
—
546
(185)
(425)
(18)
(4)
(632)
(760)
(241)
(8)
—
(1,009)
(299)
(610)
31
(4)
(882)
—
—
67
—
67
—
—
14
—
14
—
—
(223)
—
(223)
—
—
(49)
—
(49)
—
—
(191)
—
(191)
180
—
143
—
323
466
56
39
—
561
(185)
(425)
(280)
(4)
(894)
(760)
(241)
(58)
—
(1,059)
(299)
(610)
(156)
(4)
(1,069)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
were as follows:
December 31, 2021
(fair value in millions of
Canadian dollars)
Commodity contracts -
financial1
Natural gas
Crude
Power
Commodity contracts -
physical1
Natural gas
Crude
Fair Value
Unobservable Input
Minimum
Price
Maximum
Price
Weighted
Average Price
Unit of
Measurement
(19)
3
(60)
Forward gas price
Forward crude price
Forward power price
(56)
24
(108)
Forward gas price
Forward crude price
3.12
76.02
31.00
2.65
68.66
9.05
98.99
125.13
9.25
97.00
4.49
91.73
76.23
$/mmbtu2
$/barrel
$/MW/H
4.63
87.97
$/mmbtu2
$/barrel
1 Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2 One million British thermal units (mmbtu).
160
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 liability at beginning of period
Total gain/(loss)
Included in earnings1
Included in OCI
Settlements
Level 3 net derivative liability at end of period
2021
2020
(191)
(69)
(39)
(29)
151
(108)
(123)
2
(1)
(191)
1 Reported within Transportation and other services revenue, Commodity costs and Operating and administrative expenses in the
Consolidated Statements of Earnings.
There were no transfers into or out of Level 3 as at December 31, 2021 or 2020.
NET INVESTMENT HEDGES
We have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign
exchange forward contracts, as a hedge of our net investment in US dollar denominated investments and
subsidiaries.
During the years ended December 31, 2021 and 2020, we recognized unrealized foreign exchange gains
of $49 million and $117 million, respectively, on the translation of US dollar denominated debt and an
unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of nil
and $13 million, respectively, in OCI. During the years ended December 31, 2021 and 2020, we
recognized a realized loss of nil and $15 million, respectively, in OCI associated with the settlement of
foreign exchange forward contracts. No realized gains or losses associated with the settlement of US
dollar denominated debt that had matured during the period were recognized in OCI during the years
ended December 31, 2021 and 2020.
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Certain long-term investments in other entities with no actively quoted prices are classified as FVMA
investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled
$52 million as at December 31, 2021 and 2020.
We have Restricted long-term investments held in trust totaling $630 million and $553 million as at
December 31, 2021 and 2020, respectively, which are recognized at fair value.
As at December 31, 2021 and 2020, our long-term debt had a carrying value of $74.4 billion and $66.1
billion, respectively, before debt issuance costs and a fair value of $82.0 billion and $75.1 billion,
respectively. We also have non-current notes receivable carried at book value and recorded in Deferred
amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2021
and 2020, the non-current notes receivable had a carrying value of $1.0 billion and $1.1 billion,
respectively, which also approximates their fair value.
161
The fair value of other financial assets and liabilities other than derivative instruments, other long-term
investments, restricted long-term investments and long-term debt approximate their cost due to the short
period to maturity.
25. 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 differentials2
Effects of rate-regulated accounting3
Foreign allowable interest deductions4
Part VI.1 tax, net of federal Part I deduction5
US Minimum Tax6
Non-taxable portion of gain on sale of investment7
Valuation allowance8
Intercorporate investments9
Noncontrolling interests
Other
2021
2020
2019
7,729 4,190
15%
1,159
629
15%
7,535
15%
1,130
228
134
(139)
—
73
—
(23)
5
—
(17)
(5)
1,415
18.3%
288
(53)
(145)
(4)
76
44
—
(6)
—
(8)
(47)
774
18.5%
415
129
(63)
(29)
78
67
—
26
(14)
(13)
(18)
1,708
Income tax expense
Effective income tax rate
22.7%
1 The change in provincial and state income taxes from 2020 to 2021 reflects the 2020 impact of state tax apportionment and rate
changes in both the US and Canada offset by the increase in earnings from US and Canadian operations in 2021.
2 The change in foreign and other statutory rate differentials from 2020 to 2021 reflects the increase in earnings from US operations
partially offset by higher rate benefits from foreign operations.
3 The amount in 2019 included the federal component of the tax benefit of the write-off of regulatory assets.
4 The decrease in foreign allowable interest deductions from 2019 to 2021 was due to changes in the related loan portfolio.
5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada.
6 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation.
7 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco.
8 The increase in 2021 is due to the federal component of the tax effect of a valuation allowance on additional deferred tax assets
that are not more likely than not to be realized.
9 The amount in 2019 relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate
investments such that deferred tax related to outside basis temporary differences was required to be recorded for MATL.
162
COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
Year ended December 31,
(millions of Canadian dollars)
Earnings before income taxes
Canada
US
Other
Current income taxes
Canada
US
Other
Deferred income taxes
Canada
US
Other
Income tax expense
2021
2020
2019
3,399
3,336
994
7,729
2,789
407
994
4,190
162
80
82
324
344
741
6
1,091
1,415
165
64
98
327
378
66
3
447
774
3,560
3,115
860
7,535
347
107
98
552
490
672
(6)
1,156
1,708
COMPONENTS OF DEFERRED INCOME TAXES
Deferred income 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
2021
2020
(8,721)
(6,097)
(1,245)
(208)
(16,271)
315
110
3,081
1,648
5,154
(84)
5,070
(11,201)
488
(11,689)
(11,201)
(7,786)
(4,649)
(1,156)
(127)
(13,718)
518
251
2,005
1,461
4,235
(79)
4,156
(9,562)
770
(10,332)
(9,562)
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.
163
As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $1.9 billion
(2020 - $2.6 billion) in Canada which expire in 2026 and beyond.
As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $11.0 billion
(2020 - $5.8 billion) in the US. Unused tax loss carryforwards of $3.5 billion (2020 - $2.4 billion) begin to
expire in 2023, and unused tax loss carryforwards of $7.5 billion (2020 - $3.4 billion) have no expiration.
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 $4.3 billion and $5.5
billion for the periods December 31, 2021 and 2020, 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 certain of our subsidiaries are subject to taxation in Canada, the US and other foreign
jurisdictions. The material jurisdictions in which we are subject to potential examinations include the US
(Federal) and Canada (Federal, Alberta and Ontario). We are open to examination by Canadian tax
authorities for the 2012 to 2021 tax years and by US tax authorities for the 2018 to 2021 tax years. We
are currently under examination for income tax matters in Canada for the 2014 to 2018 tax years. We are
not currently under examination for income tax matters in any other material jurisdiction where we are
subject to income tax.
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 decreases for tax positions of prior year
Change in translation of foreign currency
Lapses of statute of limitations
Unrecognized tax benefits at end of year
2021
2020
121
1
(26)
(1)
(19)
76
129
1
(1)
(3)
(5)
121
The unrecognized tax benefits as at December 31, 2021, 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. Interest and penalties included in income taxes for the years ended December 31, 2021
and 2020 were a $5 million recovery and $3 million expense, respectively. As at December 31, 2021 and
2020, interest and penalties of $12 million and $17 million, respectively, have been accrued.
164
26. PENSION AND OTHER POSTRETIREMENT BENEFITS
PENSION PLANS
We sponsor Canadian and US contributory and non-contributory registered defined benefit and defined
contribution pension plans, which provide benefits covering substantially all employees. The Canadian
Plans provide defined benefit and defined contribution pension benefits to our Canadian employees. The
US Plans provide defined benefit pension benefits to our US employees. We also sponsor supplemental
non-contributory defined benefit pension plans, which provide non-registered benefits for certain
employees in Canada and the US.
Defined Benefit Pension Plan Benefits
Benefits payable from the defined benefit pension plans are based on each plan participant’s years of
service and final average remuneration. Some benefits are partially inflation-indexed after a plan
participant’s retirement. Our contributions are made in accordance with independent actuarial valuations.
Participant contributions to contributory defined benefit pension plans are based upon each plan
participant’s current eligible remuneration.
Defined Contribution Pension Plan Benefits
Our contributions are based on each plan participant’s current eligible remuneration. Our contributions for
some defined contribution pension plans are also based on age and years of service. Our defined
contribution pension benefit costs are equal to the amount of contributions required to be made by us.
165
Benefit Obligations, 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 assets or liabilities for our defined benefit pension plans:
December 31,
(millions of Canadian dollars)
Change in projected benefit obligation
Projected benefit obligation at beginning of year
Service cost
Interest cost
Participant contributions
Actuarial (gain)/loss1
Benefits paid
Foreign currency exchange rate changes
Other
Projected benefit obligation at end of year2
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
Other
Fair value of plan assets at end of year3
Underfunded status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities
Canada
US
2021
2020
2021
2020
4,855
139
101
28
(329)
(194)
—
—
4,600
4,077
505
120
28
(194)
—
—
4,536
(64)
250
(9)
(305)
(64)
4,446
148
128
31
292
(190)
—
—
4,855
3,827
288
121
31
(190)
—
—
4,077
(778)
35
(9)
(804)
(778)
1,243
44
17
—
(21)
(84)
(11)
(4)
1,184
1,062
151
43
—
(84)
(8)
(4)
1,160
(24)
98
(4)
(118)
(24)
1,230
44
31
—
95
(128)
(23)
(6)
1,243
1,104
83
27
—
(128)
(18)
(6)
1,062
(181)
—
(3)
(178)
(181)
1 Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the
discount rate used to measure the benefit obligations).
2 The accumulated benefit obligation for our Canadian pension plans was $4.3 billion and $4.5 billion as at December 31, 2021 and
2020, respectively. The accumulated benefit obligation for our US pension plans was $1.1 billion and $1.2 billion as at
December 31, 2021 and 2020, respectively.
3 Assets in the amount of $13 million (2020 - $11 million) and $84 million (2020 - $59 million), related to our Canadian and United
States non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi 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.
166
Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan
assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows:
December 31,
(millions of Canadian dollars)
Accumulated benefit obligation
Fair value of plan assets
Canada
US
2021
2020
2021
2020
440
247
4,094
3,621
115
—
1,207
1,062
Certain of our pension plans have projected benefit obligations in excess of the fair value of plan assets.
For these plans, the projected benefit obligation and fair value of plan assets were as follows:
December 31,
(millions of Canadian dollars)
Projected benefit obligation
Fair value of plan assets
Canada
US
2021
2020
2021
2020
1,272
1,020
4,434
3,621
121
—
1,243
1,062
Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our pension plans are as follows:
December 31,
(millions of Canadian dollars)
Net actuarial loss
Prior service credit
Total amount recognized in AOCI1
1 Excludes amounts related to cumulative translation adjustment.
Canada
US
2021
2020
2021
2020
226
—
226
542
—
542
92
(1)
91
233
(1)
232
Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income
The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive
income related to our pension plans are as follows:
Year ended December 31,
(millions of Canadian dollars)
Service cost
Interest cost1
Expected return on plan assets1
Amortization/settlement of net actuarial loss1
Amortization/curtailment of prior service credit1
Net periodic benefit (credit)/cost
Defined contribution benefit cost
Net pension (credit)/cost recognized in Earnings
Amount recognized in OCI:
Effect of plan combination
Amortization/settlement of net actuarial loss
Amortization/curtailment of prior service credit
Net actuarial (gain)/loss arising during the year
Total amount recognized in OCI
Total amount recognized in Comprehensive income
Canada
2020
2021
2019
2021
US
2020
2019
139
101
(252)
54
—
42
7
49
—
(25)
—
(291)
(316)
(267)
148
128
(260)
42
—
58
6
64
—
(21)
—
118
97
161
149
139
(245)
41
—
84
8
92
—
(26)
—
115
89
181
44
17
(73)
11
—
(1)
—
(1)
—
(11)
—
(99)
(110)
(111)
44
31
(88)
1
(1)
(13)
—
(13)
—
(1)
1
100
100
87
45
41
(78)
2
(1)
9
—
9
(6)
(2)
1
8
1
10
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
167
Actuarial Assumptions
The weighted average assumptions made in the measurement of the projected benefit obligation and net
periodic benefit cost of our pension plans are as follows:
Projected benefit obligation
Discount rate
Rate of salary increase
Cash balance interest credit rate
Net periodic benefit cost
Discount rate
Rate of return on plan assets
Rate of salary increase
Cash balance interest credit rate
Canada
US
2021
2020
2019
2021
2020
2019
3.2 %
2.9 %
N/A
2.6 %
6.2 %
2.3 %
N/A
2.6 %
2.3 %
N/A
3.0 %
6.8 %
3.2 %
N/A
3.0 %
3.2 %
N/A
3.8 %
7.0 %
3.2 %
N/A
2.6 %
2.8 %
4.3 %
2.2 %
7.3 %
2.7 %
4.3 %
2.2 %
2.7 %
4.3 %
3.0 %
7.9 %
2.9 %
4.5 %
3.0 %
2.9 %
4.5 %
3.9 %
8.0 %
2.9 %
4.5 %
OTHER POSTRETIREMENT BENEFIT PLANS
We sponsor funded and unfunded defined benefit OPEB Plans, which provide non-contributory
supplemental health, dental, life and health spending account benefit coverage for certain qualifying
retired employees.
168
Benefit Obligations, Plan Assets and Funded Status
The following table details the changes in the accumulated postretirement benefit obligation, the fair value
of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans:
December 31,
(millions of Canadian dollars)
Change in accumulated postretirement benefit
obligation
Canada
US
2021
2020
2021
2020
Accumulated postretirement benefit obligation at beginning
321
293
254
288
of year
Service cost
Interest cost
Participant contributions
Actuarial (gain)/loss1
Benefits paid
Plan amendments
Foreign currency exchange rate changes
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
Other
Fair value of plan assets at end of year
Overfunded/(underfunded) status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities
6
7
—
(51)
(9)
—
—
—
274
—
—
9
—
(9)
—
—
—
(274)
—
(12)
(262)
(274)
5
8
—
21
(6)
—
—
—
321
—
—
6
—
(6)
—
—
—
(321)
—
(13)
(308)
(321)
1
3
8
(69)
(22)
—
(3)
1
173
188
22
6
8
(22)
(3)
2
201
28
71
—
(43)
28
2
7
4
17
(28)
(33)
(4)
1
254
188
14
12
4
(28)
(3)
1
188
(66)
19
(6)
(79)
(66)
1 Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the
discount rate used to measure the benefit obligations).
169
Certain of our OPEB plans have accumulated benefit obligations in excess of the fair value of plan assets.
For these plans, the accumulated benefit obligation and fair value of plan assets were as follows:
December 31,
(millions of Canadian dollars)
Accumulated benefit obligation
Fair value of plan assets
Canada
US
2021
2020
2021
2020
274
—
321
—
94
51
191
106
Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our OPEB plans are as follows:
December 31,
(millions of Canadian dollars)
Net actuarial (gain)/loss
Prior service credit
Total amount recognized in AOCI1
1 Excludes amounts related to cumulative translation adjustment.
Canada
US
2021
2020
2021
2020
(35)
(1)
(36)
15
(1)
14
(104)
(37)
(141)
(7)
(44)
(51)
Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income
The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive
income related to our OPEB plans are as follows:
Year ended December 31,
(millions of Canadian dollars)
Service cost
Interest cost1
Expected return on plan assets1
Amortization/settlement of net actuarial gain1
Amortization/curtailment of prior service credit1
Net periodic benefit (credit)/cost recognized in
Earnings
Amount recognized in OCI:
Amortization/settlement of net actuarial gain
Amortization/curtailment of prior service credit
Net actuarial (gain)/loss arising during the year
Prior service credit
Total amount recognized in OCI
Total amount recognized in Comprehensive income
Canada
2020
2021
2019
2021
US
2020
6
7
—
—
—
5
8
—
(1)
—
5
10
—
(7)
(1)
1
3
(10)
(1)
(7)
2
7
(12)
(1)
(2)
2019
2
10
(12)
—
(2)
13
12
—
—
(50)
—
(50)
(37)
1
—
21
—
22
34
7
7
1
15
—
23
30
(14)
(6)
(2)
1
7
(80)
—
(72)
(86)
1
2
15
(33)
(15)
(21)
—
2
(8)
—
(6)
(8)
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
170
Actuarial Assumptions
The weighted average assumptions made in the measurement of the accumulated postretirement benefit
obligation and net periodic benefit cost of our OPEB plans are as follows:
Accumulated postretirement
benefit obligation
Discount rate
Net periodic benefit cost
Discount rate
Rate of return on plan assets
Canada
US
2021
2020
2019
2021
2020
2019
3.2 %
2.6 %
3.1 %
2.4 %
2.0 %
2.8 %
2.6 %
N/A
3.1 %
N/A
3.8 %
N/A
2.0 %
6.0 %
2.8 %
6.7 %
4.0 %
6.7 %
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
(ultimate trend rate)
Year that the rate reaches the ultimate trend rate
Canada
2021
4.0 %
4.0 %
N/A
2020
4.0 %
4.0 %
N/A
US
2021
7.0 %
4.5 %
2037
2020
6.8 %
4.5 %
2037
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 overall expected rate of return on plan assets is based on the asset allocation targets with estimates
for returns based on long-term expectations.
The asset allocation targets and major categories of plan assets are as follows:
Asset Category
Equity securities
Fixed income securities
Alternatives1
Canada
Target
Allocation
43.8 %
28.9 %
27.3 %
December 31,
Target
2021
46.7 %
29.8 %
23.5 %
2020 Allocation
45.0 %
20.1 %
34.9 %
47.2 %
29.6 %
23.2 %
US
December 31,
2021
52.5 %
18.4 %
29.1 %
2020
55.6 %
17.2 %
27.2 %
1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the
net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have
been estimated using the capital accounts representing the plan's ownership interest in the funds.
171
Pension Plans
The following table summarizes the fair value of plan assets for our pension plans recorded at each fair
value hierarchy level:
Canada
US
Level 11
Level 22
Level 33
Total
Level 11
Level 22
Level 33
Total
(millions of Canadian dollars)
December 31, 2021
Cash and cash equivalents
Equity securities
Canada
US
Global
Fixed income securities
Government
Corporate
Alternatives4
Forward currency contracts
Total pension plan assets at fair value
December 31, 2020
Cash and cash equivalents
Equity securities
Canada
US
Global
Fixed income securities
Government
Corporate
Alternatives4
Forward currency contracts
Total pension plan assets at fair value
180
—
—
180
10
—
—
10
198
1
—
258
—
—
—
637
228
—
1,693
459
453
—
2
2,835
—
—
—
—
—
1,064
—
1,064
426
1
1,693
717
453
1,064
2
4,536
—
—
—
—
—
—
—
10
—
—
609
86
118
—
—
813
213
—
—
213
5
—
178
2
—
207
—
—
—
600
188
—
1,556
378
410
—
33
2,565
—
—
—
—
—
912
—
912
366
2
1,556
585
410
912
33
4,077
—
—
—
—
—
—
—
5
—
—
590
75
103
—
—
768
—
—
—
—
—
337
—
337
—
—
—
—
—
—
289
—
289
—
—
609
86
118
337
—
1,160
5
—
—
590
75
103
289
—
1,062
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 Alternatives include investments in private debt, private equity, infrastructure and real estate funds.
Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were
as follows:
December 31,
(millions of Canadian dollars)
Balance at beginning of year
Unrealized and realized gains/(losses)
Purchases and settlements, net
Balance at end of year
Canada
US
2021
2020
2021
2020
912
77
75
1,064
852
(27)
87
912
289
38
10
337
276
7
6
289
172
OPEB Plans
The following table summarizes the fair value of plan assets for our US funded OPEB plans recorded at
each fair value hierarchy level:
Level 11
Level 22
Level 33
Total
(millions of Canadian dollars)
December 31, 2021
Cash and cash equivalents
Equity securities
US
Global
Fixed income securities
Government
Corporate
Alternatives4
Total OPEB plan assets at fair value
December 31, 2020
Equity securities
US
Global
Fixed income securities
Government
Corporate
Alternatives4
Total OPEB plan assets at fair value
4
—
—
47
—
—
51
—
—
38
—
—
38
—
39
75
6
8
—
128
35
79
6
8
—
128
—
—
—
—
—
22
22
—
—
—
—
22
22
4
39
75
53
8
22
201
35
79
44
8
22
188
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 Alternatives includes investments in private debt, private equity, infrastructure and real estate.
Changes in the net fair value of US funded OPEB plan assets classified as Level 3 in the fair value
hierarchy were as follows:
December 31,
(millions of Canadian dollars)
Balance at beginning of year
Unrealized and realized gains
Purchases and settlements, net
Balance at end of year
EXPECTED BENEFIT PAYMENTS
Year ending December 31,
(millions of Canadian dollars)
Pension
Canada
US
OPEB
Canada
US
2021
2020
22
2
(2)
22
18
1
3
22
2022
2023
2024
2025
2026
2027-2031
197
80
12
17
203
78
12
15
208
78
12
14
212
76
13
13
217
77
13
12
1,163
374
67
51
173
EXPECTED EMPLOYER CONTRIBUTIONS
In 2022, we expect to contribute approximately $110 million and $4 million to the Canadian and US
pension plans, respectively, and $12 million and $6 million to the Canadian and US OPEB plans,
respectively.
RETIREMENT SAVINGS PLANS
In addition to the pension and OPEB plans discussed above, we also have defined contribution employee
savings plans available to US employees. Employees may participate in a matching contribution where
we match a certain percentage of before-tax employee contributions of up to 6.0% of eligible pay per pay
period. For the years ended December 31, 2021, 2020 and 2019, pre-tax employer matching contribution
costs were $27 million each year, respectively.
27. LEASES
LESSEE
We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our
operating leases have remaining lease terms of 5 months to 25 years as at December 31, 2021.
For the years ended December 31, 2021 and 2020, we incurred operating lease expenses of $95 million
and $107 million, respectively. Operating lease expenses are reported under Operating and
administrative expense in the Consolidated Statements of Earnings.
For the years ended December 31, 2021 and 2020, operating lease payments to settle lease liabilities
were $118 million and $133 million, respectively. Operating lease payments are reported under Operating
activities in the Consolidated Statements of Cash Flows.
174
Supplemental Statements of Financial Position Information
(millions of Canadian dollars, except lease term and discount rate)
Operating leases1
Operating lease right-of-use assets, net2
Operating lease liabilities - current3
Operating lease liabilities - long-term3
Total operating lease liabilities
Finance leases
Finance lease right-of-use assets, net4
Finance lease liabilities - current5
Finance lease liabilities - long-term3
Total finance lease liabilities
Weighted average remaining lease term
Operating leases
Finance leases
December 31,
2021
December 31,
2020
645
92
612
704
49
13
33
46
708
80
681
761
57
11
42
53
12 years
7 years
13 years
7 years
Weighted average discount rate
Operating leases
Finance leases
1 Affiliate right-of-use assets, current lease liabilities and long-term lease liabilities as at December 31, 2021 were $51 million
4.1 %
3.8 %
4.1 %
3.8 %
(December 31, 2020 - $65 million), $5 million (December 31, 2020 - $5 million) and $47 million (December 31, 2020 - $52 million),
respectively.
2 Operating lease right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of
Financial Position.
3 Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and
other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position.
4 Finance lease right-of-use assets are reported under Property, plant and equipment, net in the Consolidated Statements of
Financial Position.
5 Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial
Position.
As at December 31, 2021, our operating and finance lease liabilities are expected to mature as follows:
Operating leases
Finance leases
(millions of Canadian dollars)
2022
2023
2024
2025
2026
Thereafter
Total undiscounted lease payments
Less imputed interest
Total
117
98
91
84
72
455
917
(213)
704
15
13
9
2
1
11
51
(5)
46
175
LESSOR
We receive revenues from operating leases primarily related to natural gas and crude oil storage and
processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining
lease terms of 1 month to 30 years as at December 31, 2021.
Year ended December 31,
(millions of Canadian dollars)
263
Operating lease income
333
Variable lease income
596
Total lease income1
1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.
2021
2020
265
361
626
As at December 31, 2021, the following table sets out future lease payments to be received under
operating lease contracts where we are the lessor:
(millions of Canadian dollars)
2022
2023
2024
2025
2026
Thereafter
Future lease payments
Operating leases
235
215
205
196
191
1,938
2,980
28. CHANGES IN OPERATING ASSETS AND LIABILITIES
Year ended December 31,
(millions of Canadian dollars)
Accounts receivable and other
Accounts receivable from affiliates
Inventory
Deferred amounts and other assets
Accounts payable and other
Accounts payable to affiliates
Interest payable
Other long-term liabilities
2021
2020
2019
(1,228)
(38)
(118)
(195)
(63)
52
43
(69)
(1,616)
1,546
8
(254)
(586)
(770)
1
31
117
93
(547)
6
(24)
133
63
(24)
(41)
175
(259)
29. 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.
We provide transportation services to several significantly influenced investees which we record as
transportation and other services revenue. We also purchase and sell natural gas and crude oil with
several of our significantly influenced investees. These revenues and costs are recorded as commodity
sales and commodity costs. We contract for firm transportation services to meet our annual natural gas
supply requirements which we record as gas distribution costs.
176
Our transactions with significantly influenced investees are as follows:
Year ended December 31,
(millions of Canadian dollars)
Transportation and other services
Commodity sales
Operating and administrative1
Commodity costs2
Gas distribution costs
2021
2020
2019
149
20
292
790
131
133
21
252
518
135
140
107
241
773
133
1 During the years December 31, 2021, 2020 and 2019, we had Operating and administrative costs from the Seaway Crude
Pipeline System of $389 million, $342 million and $327 million, respectively. These costs are a result of an operational contract
where we utilize capacity on Seaway Crude Pipeline System assets for use in our Liquids Pipelines business. The costs are
offset by recoveries recorded on expenses incurred by us on behalf of our significantly influenced investees of $104 million,
$94 million and $86 million for the years ended December 31, 2021, 2020 and 2019.
2 During the years December 31, 2021, 2020 and 2019, we had Commodity costs from the Aux Sable Canada LP. of $447 million,
$91 million and $272 million, respectively.
LONG-TERM NOTES RECEIVABLE FROM AFFILIATES
As at December 31, 2021, amounts receivable from affiliates include a series of loans totaling
$954 million ($1,108 million as at December 31, 2020), which require quarterly or semi-annual interest
payments at annual interest rates ranging from 3% to 8%. Interest income recognized from these notes
totaled $39 million, $44 million and $40 million for the years ended December 31, 2021, 2020 and 2019,
respectively. The amounts receivable from affiliates are included in Deferred amounts and other assets in
the Consolidated Statements of Financial position.
30. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As at December 31, 2021, we have commitments as detailed below:
(millions of Canadian dollars)
Annual debt maturities1
Interest obligations2
Purchase of services, pipe and other
materials, including transportation3
Maintenance agreements
Right-of-ways commitments
Total
Less
than
Total
1 year 2 years 3 years 4 years 5 years Thereafter
73,809 6,164 7,910 4,559 4,357 11,007
36,044 2,531 2,389 2,229 2,073 1,925
39,812
24,897
7,876 2,945 1,010
20
35
607
21
346
37
1,249
119,324 11,716 11,364 7,579 7,048 13,597
736
20
35
561
21
36
41
35
2,017
223
1,071
68,020
1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes
short-term borrowings, debt discounts, debt issuance costs, finance lease obligations and fair value adjustment. 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 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.
3 Includes capital and operating commitments. Consists primarily of gas transportation and storage contracts, firm capacity
payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.
177
ENVIRONMENTAL
We are subject to various Canadian and US 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 its affiliates are, at times, subject to environmental remediation at various sites where we operate. We
manage this environmental risk through appropriate environmental policies, programs 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 our
operating activities.
AUX SABLE
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.
On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of
its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid
Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux
Sable filed an amended Statement of Defence responding to the amended amended claim on January
31, 2020.
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.
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 involved in 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. 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.
31. GUARANTEES
In the normal course of conducting business, we may enter into agreements which indemnify third parties
and affiliates. We may also be a party to agreements with subsidiaries, jointly owned entities,
unconsolidated entities such as equity method investees, or entities with other ownership arrangements
that require us to provide financial and performance guarantees. Financial guarantees include stand-by
letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these
guarantees involve elements of performance and credit risk, which are not included on our Consolidated
Statements of Financial Position. Performance guarantees require us to make payments to a third party if
the guaranteed entity does not perform on its contractual obligations, such as debt agreements, purchase
or sale agreements, and construction contracts and leases.
178
We typically enter into these arrangements to facilitate commercial transactions with third parties.
Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in
matters such as breaches of representations, warranties or covenants, loss or damages to property,
environmental liabilities, and litigation and contingent liabilities. We may indemnify third parties for certain
liabilities relating to environmental matters arising from operations prior to the purchase or transfer of
certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities
incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the
purchaser or other certain tax liabilities related to those assets.
The likelihood 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 total maximum potential amounts that could
become payable to third parties and affiliates under such agreements described above; however,
historically, we have not made any significant payments under guarantee or indemnification provisions.
While these agreements may specify a maximum potential exposure, or a specified duration to the
guarantee or indemnification obligation, there are circumstances where the amount and duration are
unlimited. As at December 31, 2021 guarantees and indemnifications 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.
32. QUARTERLY FINANCIAL DATA (UNAUDITED)
(unaudited; millions of Canadian dollars, except per
share amounts)
2021
Operating revenues
Operating income
Earnings
Earnings attributable to controlling interests
Earnings attributable to common
shareholders
Earnings per common share
Basic
Diluted
2020
Operating revenues
Operating income
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
12,187
2,548
2,014
1,992
10,948
1,816
1,521
1,484
11,466
1,388
814
780
12,470
2,053
1,965
1,933
47,071
7,805
6,314
6,189
1,900
1,394
682
1,840
5,816
0.94
0.94
0.69
0.69
0.34
0.34
0.91
0.91
2.87
2.87
12,013
1,513
(1,364)
7,956
2,098
1,777
9,110
2,095
1,104
10,008
2,251
1,899
39,087
7,957
3,416
(1,333)
1,741
1,084
1,871
3,363
(1,429)
1,647
990
1,775
2,983
(0.71)
(0.71)
0.82
0.82
0.49
0.49
0.88
0.88
1.48
1.48
179
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 US securities
law. As at December 31, 2021, 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 Exchange Act). 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 submit to the 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 US 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 US 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, 2021, 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, 2021.
180
The effectiveness of our internal control over financial reporting as at December 31, 2021 has been
audited by PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm appointed by
our shareholders. As stated in their Report of Independent Registered Public Accounting Firm which
appears in Item 8. Financial Statements and Supplementary Data, they expressed an unqualified opinion
on the effectiveness of our internal control over financial reporting as at December 31, 2021.
Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2021, there has been no material change in our internal
control over financial reporting.
ITEM 9B. OTHER INFORMATION
NORMAL COURSE ISSUER BID
On December 31, 2021, we announced that the TSX had approved our NCIB to purchase, for
cancellation, up to 31,062,331 of the outstanding common shares of Enbridge to an aggregate amount of
up to $1.5 billion, subject to certain restrictions on the number of common shares that may be purchased
on a single day.
Purchases under the NCIB may be made through the facilities of the TSX, the NYSE and other
designated exchanges and alternative trading systems, commencing on January 5, 2022 and continuing
until January 4, 2023, when the bid expires, or such earlier date on which Enbridge has either acquired
the maximum number of common shares allowable under the NCIB or otherwise decide not to make any
further repurchases under the NCIB. The maximum number of common shares that Enbridge may
repurchase for cancellation represents approximately 1.53% of the 2,026,085,179 common shares issued
and outstanding as at December 22, 2021.
A copy of our notice of intention to make a normal course issuer bid may be obtained, free of charge, by
contacting Investor Relations by email, phone or mail at:
Email: investor.relations@enbridge.com
Phone Within North America: 1-800-481-2804
Phone Outside North America: 1-403-231-3960
Mail: Enbridge Inc. Investor Relations, 200, 425 – 1st Street S.W., Calgary, Alberta, Canada T2P 3L8
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT
PREVENT INSPECTIONS
Not applicable.
181
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Directors of Registrant
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than
120 days after December 31, 2021. This information will also be disclosed in the management proxy
information that we prepare in accordance with Canadian corporate and securities law requirements.
Executive Officers of Registrant
The information regarding executive officers is included in Part I. Item 1. Business - Executive Officers.
Code of Ethics for Chief Executive Officer and Senior Financial Officers
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than
120 days after December 31, 2021. This information will also be disclosed in the management proxy
information that we prepare in accordance with Canadian corporate and securities law requirements.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than
120 days after December 31, 2021. This information will also be disclosed in the management proxy
information that we prepare in accordance with Canadian corporate and securities law requirements.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than
120 days after December 31, 2021. This information will also be disclosed in the management proxy
information that we prepare in accordance with Canadian corporate and securities law requirements.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than
120 days after December 31, 2021. This information will also be disclosed in the management proxy
information that we prepare in accordance with Canadian corporate and securities law requirements.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than
120 days after December 31, 2021. This information will also be disclosed in the management proxy
information that we prepare in accordance with Canadian corporate and securities law requirements.
182
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:
Enbridge Inc.:
Report of Independent Registered Public Accounting Firm (PCAOB ID 271)
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.
ITEM 16. FORM 10-K SUMMARY
Not applicable.
183
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
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
3.15
3.16
3.17
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
184
3.18
3.19
3.20
3.21
3.22
3.23
3.24
3.25
3.26
3.27
3.28
3.29
3.30
3.31
3.32
3.33
3.34
3.35
3.36
3.37
3.38
3.39
3.40
3.41
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
Certificate of Amendment, dated September 25, 2017 (incorporated by reference to
Exhibit 3.34 to Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
Certificate of Amendment, dated December 7, 2017 (incorporated by reference to
Exhibit 3.35 to Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
Certificate of Amendment, dated February 27, 2018 (incorporated by reference to
Exhibit 3.1 to Enbridge’s Current Report on Form 8-K filed March 1, 2018)
Certificate of Amendment, dated April 9, 2018 (incorporated by reference to Exhibit 3.1
to Enbridge’s Current Report on Form 8-K filed April 12, 2018)
Certificate of Amendment, dated April 10, 2018 (incorporated by reference to Exhibit
3.1 to Enbridge’s Current Report on Form 8-K filed April 12, 2018)
Certificate and Articles of Amendment, dated July 6, 2020 (incorporated by reference
to Exhibit 3.1 to Enbridge’s Current Report on Form 8-K filed July 8, 2020)
* General By-Law No. 1 of Enbridge Inc.
By-Law No. 2 of Enbridge Inc. (incorporated by reference to Enbridge’s Current Report
on Form 6-K filed December 5, 2014)
185
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
10.1
10.2
10.3
10.4
Form of Indenture between Enbridge Inc. and Deutsche Bank Trust Company
Americas to be dated February 25, 2005 (incorporated by reference to Exhibit 7.1 to
Enbridge’s Registration Statement on Form F-10 filed February 4, 2005)
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)
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)
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)
Fourth Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust
Company Americas, dated March 1, 2018 (incorporated by reference to Enbridge’s
Current Report on Form 8-K filed March 1, 2018)
Fifth Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust
Company Americas, dated April 12, 2018 (incorporated by reference to Enbridge’s
Current Report on Form 8-K filed April 12, 2018)
Sixth Supplemental Indenture between Enbridge Inc., Spectra Energy Partners, LP (as
guarantor), Enbridge Energy Partners, L.P. (as guarantor) and Deutsche Bank Trust
Company Americas, dated May 13, 2019 (incorporated by reference to Enbridge’s
Registration Statement on Form S-3 filed May 17, 2019)
Seventh Supplemental Indenture to the Indenture between Enbridge Inc. and
Deutsche Bank Trust Company Americas, dated July 8, 2020 (incorporated by
reference to Exhibit 4.1 to Enbridge’s Current Report on Form 8-K filed July 8, 2020)
Eighth Supplemental Indenture to the Indenture between Enbridge Inc. and Deutsche
Bank Trust Company Americas, dated June 28, 2021 (incorporated by reference to
Exhibit 4.4 to Enbridge’s Current Report on Form 8-K filed June 28, 2021)
Shareholder Rights Plan Agreement between Enbridge Inc. and Computershare Trust
Company of Canada dated as of November 9, 1995 and Amended and Restated as of
May 5, 2020 (incorporated by reference to Exhibit 4.1 to Enbridge’s Current Report on
Form 8-K filed May 6, 2020).
Description of Securities Registered Under Section 12 of the Securities Exchange Act,
as amended (incorporated by reference to Exhibit 4.9 to Enbridge’s Form 10-K filed
February 14, 2020)
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.
Enbridge Pipelines Inc. Competitive Toll Settlement dated July 1, 2011 (incorporated
by reference to Exhibit 10.1 to Enbridge’s Annual Report on Form 10-K filed February
16, 2018)
Sixteenth Supplemental Indenture dated as of January 22, 2019 between Enbridge
Energy Partners, L.P. and US Bank National Association, as trustee (incorporated by
reference as Exhibit 4.1 to Enbridge’s Current Report on Form 8-K filed January 24,
2019)
Seventeenth Supplemental Indenture dated as of January 22, 2019 between Enbridge
Energy Partners, L.P., Enbridge Inc. and US Bank National Association, as trustee
(incorporated by reference as Exhibit 4.2 to Enbridge’s Current Report on Form 8-K
filed January 24, 2019)
Seventh Supplemental Indenture dated as of January 22, 2019 between Spectra
Energy Partners, LP, Enbridge Inc. and Wells Fargo Bank, National Association, as
trustee (incorporated by reference as Exhibit 4.3 to Enbridge’s Current Report on Form
8-K filed January 24, 2019)
186
10.5
10.6
10.7
10.8
10.9
10.10
Eighth Supplemental Indenture dated as of January 22, 2019 between Spectra
Energy Partners, LP, Enbridge Inc. and Wells Fargo Bank, National Association, as
trustee (incorporated by reference as Exhibit 4.4 to Enbridge’s Current Report on
Form 8-K filed January 24, 2019)
Subsidiary Guarantee Agreement dated as of January 22, 2019 between Spectra
Energy Partners, LP and Enbridge Energy Partners, L.P. (incorporated by reference
as Exhibit 4.5 to Enbridge’s Current Report on Form 8-K filed January 24, 2019)
+ Form of Executive Employment Agreement (pre-2014) (incorporated by reference
to Exhibit 10.2 to Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
+ Form of Executive Employment Agreement (2014-2016) (incorporated by reference
to Exhibit 10.3 to Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
+ Form of Executive Employment Agreement (2017) (incorporated by reference to
Exhibit 10.4 to Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
+ Executive Employment Agreement between Enbridge Employee Services, Inc. and
William T. Yardley, dated July 25, 2018 (incorporated by reference to Exhibit 10.1
to Enbridge’s Form 8-K filed July 27, 2018)
10.11
+ Form of Director Indemnity Agreement (2015) (incorporated by reference to
Exhibit 10.11 to Enbridge’s Annual Report on Form 10-K filed February 15, 2019)
10.12
10.13
10.14
10.15
10.16
10.17
10.18
+ Enbridge Inc. 2019 Long Term Incentive Plan (incorporated by reference to Appendix
A to Enbridge’s Proxy Statement on Schedule 14A for Enbridge’s Annual Meeting of
Shareholders (File No. 001-15254) filed March 27, 2019)
Form of Enbridge Inc. 2019 Long Term Incentive Plan Stock Option Grant Notice
and Stock Option Award Agreement (2021) (incorporated by reference to Exhibit
10.1 to Enbridge’s Form 10-Q filed May 7, 2021)
Form of Enbridge Inc. 2019 Long Term Incentive Plan Performance Stock Unit
Grant Notice and Performance Stock Unit Award Agreement (2021) (incorporated by
reference to Exhibit 10.2 to Enbridge’s Form 10-Q filed May 7, 2021)
Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant
Notice and Restricted Stock Unit Award Agreement (2021 Share-settled) (incorporated
by reference to Exhibit 10.3 to Enbridge’s Form 10-Q filed May 7, 2021)
Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant
Notice and Restricted Stock Unit Award Agreement (2021 Cash-settled)
(incorporated by reference to Exhibit 10.4 to Enbridge’s Form 10-Q filed May 7, 2021)
Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit - Energy
Marketers Grant Notice and Restricted Stock Unit Award Agreement (2021)
(incorporated by reference to Exhibit 10.5 to Enbridge’s Form 10-Q filed May 7, 2021)
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Stock Option Grant Notice
and Stock Option Award Agreement (2020) (incorporated by reference to Exhibit
10.1 to Enbridge’s Form 10-Q filed May 7, 2020)
10.19
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Performance Stock Unit
Grant Notice and Performance Stock Unit Award Agreement (2020) (incorporated by
reference to Exhibit 10.2 to Enbridge’s Form 10-Q filed May 7, 2020)
10.20
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant
Notice and Restricted Stock Unit Award Agreement (2020 Share-settled)
(incorporated by reference to Exhibit 10.3 to Enbridge’s Form 10-Q filed May 7, 2020)
10.21
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant
Notice and Restricted Stock Unit Award Agreement (2020 Cash-settled)
(incorporated by reference to Exhibit 10.4 to Enbridge’s Form 10-Q filed May 7, 2020)
10.22
10.23
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Stock Option Grant Notice
and Stock Option Award Agreement (incorporated by reference to Exhibit 10.4 to
Enbridge’s Form 10-Q filed May 10, 2019)
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Performance Stock Unit
Grant Notice and Performance Stock Unit Award Agreement (incorporated by
reference to Exhibit 10.5 to Enbridge’s Form 10-Q filed May 10, 2019)
187
10.24
10.25
10.26
10.27
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit
Grant Notice and Restricted Stock Unit Award Agreement (incorporated by
reference to Exhibit 10.6 to Enbridge’s Form 10-Q filed May 10, 2019)
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit - Energy
Marketers Grant Notice and Restricted Stock Unit Award Agreement (incorporated
by reference to Exhibit 10.7 to Enbridge’s Form 10-Q filed May 10, 2019)
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant
Notice and Restricted Stock Unit Award Agreement - Retention Award Version
(incorporated by reference to Exhibit 10.8 to Enbridge’s Form 10-Q filed August
2, 2019)
+ Enbridge Inc. Incentive Stock Option Plan (2007), as amended and restated (2011)
(incorporated by reference to Exhibit 10.13 to Enbridge’s Annual Report on Form 10-
K filed February 16, 2018)
10.28
+ Enbridge Inc. Incentive Stock Option Plan (2007), as amended and restated (2011
and 2014) (incorporated by reference to Exhibit 10.14 to Enbridge’s Annual Report on
Form 10-K filed February 16, 2018)
10.29
10.30
+ Enbridge Inc. Incentive Stock Option Plan (2007), as revised (incorporated by
reference to Exhibit 10.15 to Enbridge’s Annual Report on Form 10-K filed
February 16, 2018)
Enbridge Inc. Directors’ Compensation Plan dated February 9, 2021, effective April
1, 2021 (incorporated by reference to Exhibit 10.6 to Enbridge’s Form 10-Q filed May
7, 2021)
10.31
+ Enbridge Inc. Directors’ Compensation Plan dated February 11, 2020, effective
January 1, 2020 (incorporated by reference to Exhibit 10.1 to Enbridge’s Form 10-
Q filed July 29, 2020),
10.32
+ Enbridge Inc. Directors’ Compensation Plan dated February 14, 2018 Amended
Effective February 12, 2019 (incorporated by reference to Exhibit 10.2 to
Enbridge’s Form 10-Q filed May 10, 2019)
10.33
+ Enbridge Inc. Directors’ Compensation Plan dated February 14, 2018, effective
January 1, 2018 (incorporated by reference as Exhibit 10.3 to Enbridge’s Form 10-
Q filed May 10, 2018)
10.34
10.35
Enbridge Inc. Directors’ Compensation Plan, November 3, 2015, effective January
1, 2016 (incorporated by reference as Exhibit 10.16 to Enbridge’s Form 10-K filed
February 16, 2018)
+ Enbridge Inc. Short Term Incentive Plan (As Amended and Restated Effective
January 1, 2019) (incorporated by reference to Exhibit 10.1 to Enbridge’s Form 10-Q
filed May 10, 2019)
10.36
+ The Enbridge Supplemental Pension Plan, As Amended and Restated Effective
January 1, 2018 (incorporated by reference as Exhibit 10.1 to Enbridge’s
Quarterly Report on Form 10-Q filed May 10, 2018)
10.37
+ Enbridge Supplemental Pension Plan for United States Employees (As Amended
and Restated Effective January 1, 2005) (incorporated by reference to Exhibit 10.20
to Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
10.38
+ Amendment 1 and Amendment 2 to the Enbridge Supplemental Pension Plan for
United States Employees (As Amended and Restated Effective January 1, 2005)
(incorporated by reference to Exhibit 10.21 to Enbridge’s Annual Report on Form 10-
K filed February 16, 2018)
10.39
+ Third Amendment to The Enbridge Supplemental Pension Plan for United States
Employees (As Amended and Restated Effective January 1, 2005) (incorporated by
reference as Exhibit 10.2 to Enbridge’s Quarterly Report on Form 10-Q filed May
10, 2018)
10.40
+ Spectra Energy Corp Directors’ Savings Plan, as amended and restated (incorporated
by reference to Exhibit 10.22 to Enbridge’s Annual Report on Form 10-K filed
February 16, 2018)
188
10.41
10.42
+ Spectra Energy Corp Executive Savings Plan, as amended and restated (incorporated
by reference to Exhibit 10.23 to Enbridge’s Annual Report on Form 10-K filed February
16, 2018)
+ Spectra Energy Executive Cash Balance Plan, as amended and restated (incorporated
by reference to Exhibit 10.24 to Enbridge’s Annual Report on Form 10-K filed February
16, 2018)
10.43
+ 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 (incorporated by reference to Exhibit 10.25 to
Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
10.44
+ Form of Spectra Energy Corp Stock Option Agreement (Nonqualified Stock Options)
(2016) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.28 to Enbridge’s Annual Report on Form 10-K
filed February 16, 2018)
10.45
+ Spectra Energy Corp 2007 Long-Term Incentive Plan (as amended and restated)
(incorporated by reference to Exhibit 10.32 to Enbridge’s Annual Report on Form 10-K
filed February 16, 2018)
10.46
10.47
21.1
22.1
23.1
24.1
31.1
31.2
32.1
+ Second Amendment to the Spectra Energy Corp Executive Savings Plan (As Amended
and Restated Effective May 1, 2012) (incorporated by reference to Exhibit 10.36 to
Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
+ Second Amendment to the Spectra Energy Corp Executive Cash Balance Plan (As
Amended and Restated Effective May 1, 2012) (incorporated by reference to Exhibit
10.37 to Enbridge’s Annual Report on Form 10-K filed February 16, 2018)
* Subsidiaries of the Registrant
* Subsidiary Guarantors
* Consent of PricewaterhouseCoopers LLP
Powers of Attorney (included on the signature page of the Annual Report)
* Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
* Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
* 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
* Inline XBRL Document Set for the consolidated financial statements and
accompanying notes in Part II. Item 8 “Financial Statements and Supplementary Data”
of this Annual Report on Form 10-K
104
* Cover Page Interactive Date File – the cover page XBRL tags are embedded within
the Inline XBRL document (included in Exhibit 101).
189
SIGNATURES
POWER OF ATTORNEY
Each person whose signature appears below appoints Robert R. Rooney, Vern D. Yu and Karen K. L.
Uehara, 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 Enbridge 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.
ENBRIDGE INC.
(Registrant)
Date:
February 11, 2022
By:
/s/ Al Monaco
Al Monaco
President and Chief Executive Officer
190
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below
on February 11, 2022 by the following persons on behalf of the registrant and in the capacities indicated.
/s/ Al Monaco
Al Monaco
President, Chief Executive Officer and Director
(Principal Executive Officer)
/s/ Patrick R. Murray
Patrick R. Murray
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
/s/ Mayank (Mike) M. Ashar
Mayank (Mike) M. Ashar
Director
/s/ Pamela L. Carter
Pamela L. Carter
Director
/s/ J. Herb England
J. Herb England
Director
/s/ Stephen S. Poloz
Stephen S. Poloz
Director
/s/ Dan C. Tutcher
Dan C. Tutcher
Director
/s/ Vern D. Yu
Vern D. Yu
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ Gregory L. Ebel
Gregory L. Ebel
Chairman of the Board of Directors
/s/ Gaurdie E. Banister
Gaurdie E. Banister
Director
/s/ Susan M. Cunningham
Susan M. Cunningham
Director
/s/ Teresa S. Madden
Teresa S. Madden
Director
/s/ S. Jane Rowe
S. Jane Rowe
Director
191
Investor information
Investor inquiries
2022 Enbridge Inc. Common Share Dividends
If you have inquiries regarding the following:
• The latest news releases or
investor presentations
• Any investment-related inquiries
Please contact Enbridge Investor Relations
Toll-free: 1-800-481-2804
investor.relations@enbridge.com
Enbridge Inc.
200, 425 – 1 Street S.W.
Calgary, Alberta, Canada T2P 3L8
Annual Meeting
The Annual Meeting of Shareholders will be
held on May 4, 2022 at 1:30 p.m. MDT. Due to
the COVID-19 pandemic, the Meeting will be
held virtually via live audio webcast. A replay
will be available on enbridge.com. Webcast
details will be available on the Company’s
website closer to the Meeting date.
Registrar and Transfer Agent
For information relating to shareholdings,
dividends, direct dividend deposit and lost
certificates, please contact:
Computershare Trust Company of Canada
100 University Avenue, 8th Floor
Toronto, Ontario M5J 2Y1
Toll-free North America: 1-866-276-9479
Outside North America: 1-514-982-8696
computershare.com/enbridge
Auditors
PricewaterhouseCoopers LLP
Dividend
Payment date
Record date1
Q1
$0.86
Q2
$ – 2
Q3
$ – 2
Mar 01
Jun 01
Sep 01
Feb 15
May 13
Aug 15
Q4
$ – 2
Dec 01
Nov 15
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 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 19 – ENB.PF.K
Forward-looking information
This Annual Report includes references to forward-looking information, including with regards to the supply of
and demand for energy, energy transition and low-carbon energy, ESG goals, growth opportunities and outlook,
financial guidance and investment capacity. 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 Factors sections of our Form 10-K and Management’s Discussion
and Analysis, included in this Annual Report and available on both sedar.com and sec.gov.
Non-GAAP measures
This Annual Report makes reference to non-GAAP financial measures and non-GAAP ratios, including EBITDA,
adjusted EBITDA and distributable cash flow (DCF) per share. Management believes the presentation of these
metrics gives useful information to investors and shareholders as they provide increased transparency and
insight into the performance of Enbridge. EBITDA represents earnings before interest, tax, depreciation and
amortization. Adjusted EBITDA represents EBITDA adjusted for unusual, infrequent or other non-operating
factors. Management uses EBITDA and adjusted EBITDA to set targets and to assess the performance of the
Company and its business units. DCF is defined as cash flow provided by operating activities before the impact
of changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to
non-controlling interests, preference share dividends and maintenance capital expenditures, and further
adjusted for unusual, infrequent or other non-operating factors. Management uses DCF to assess the
performance of the Company and to set its dividend payout target. Debt to EBITDA is a non-GAAP ratio used
as a liquidity measure to indicate the amount of adjusted earnings available to pay debt (as calculated on a
GAAP basis) before covering interest, tax, depreciation and amortization. Adjusted earnings is a non-GAAP
financial measure that represents earnings attributable to common shareholders adjusted for unusual,
infrequent or other non-operating factors included in adjusted EBITDA, as well as adjustments for unusual,
infrequent or other non-operating factors in respect of depreciation and amortization expense, interest
expense, income taxes and noncontrolling interests on a consolidated basis.
Our non-GAAP metrics described above are not measures that have standardized meaning prescribed by
generally accepted accounting principles (GAAP) in the United States of America and are not U.S. GAAP
measures. Therefore, these metrics may not be comparable with similar measures presented by other issuers.
A reconciliation of historical non-GAAP financial measures to the most directly comparable GAAP measures is
available on the Company’s website. Additional information on non-GAAP financial measures and non-GAAP
ratios may be found in the Company’s earnings news releases or in additional information on the Company’s
website, sedar.com and sec.gov. Reconciliations of forward-looking non-GAAP financial measures to
comparable GAAP measures are not available due to the challenges and impracticability with estimating some
items, particularly certain contingent liabilities and non-cash unrealized derivative fair value losses and gains
which are subject to market variability. Because of these challenges, reconciliations of forward-looking
non-GAAP financial measures are not available without unreasonable effort.
Front cover
Images from across Enbridge’s business.
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.