Tomorrow is on
2022 Annual Report
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, 2022
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
Commission file number 001-15254
_______________________________
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, a
smaller reporting company, or an emerging growth 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 ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐
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, 2022, was approximately US$85.6 billion.
As at February 3, 2023, the registrant had 2,024,907,965 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 (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
Purchases of Equity Securities
Item 6.
Item 7.
[Reserved]
Management’s Discussion and Analysis of Financial Condition and Results of
Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
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
Index of Exhibits
Signatures
PAGE
8
42
56
56
56
57
58
59
60
88
91
175
175
176
176
177
177
177
177
177
178
178
179
186
3
GLOSSARY
AFUDC
Aii
AOCI
ARO
ASC
ASU
Aux Sable
BC
bcf/d
the Board
Cactus II
CER
CTS
DAPL
Dawn
DCP
EBITDA
EEP
EIEC
EIS
Enbridge Gas
EPS
ESG
Exchange Act
FERC
GHG
Gray Oak
H2
IJT
IR
kbpd
L3R
LMCI
LNG
Magic Valley
M&N
Allowance for funds used during construction
Athabasca Indigenous Investments Limited Partnership
Accumulated other comprehensive income/(loss)
Asset retirement obligations
Accounting Standards Codification
Accounting Standards Update
US Midstream ownership interest in Aux Sable Liquid Products LP, Aux
Sable Midstream LLC, Aux Sable Canada LP
British Columbia
Billion cubic feet per day
Board of Directors
Cactus II Pipeline, LLC
Canada Energy Regulator, created by the Canadian Energy Regulator
Act which also repealed the National Energy Board Act, on August 28,
2019
Competitive Toll Settlement
Dakota Access Pipeline
An extensive network of underground storage pools at the Tecumseh
Gas Storage facility and Dawn Hub
DCP Midstream, LP
Earnings before interest, income taxes and depreciation and
amortization
Enbridge Energy Partners, L.P.
Enbridge Ingleside Energy Center
Environmental Impact Statement
Enbridge Gas Inc.
Emission Performance Standards
Environment, Social and Governance
United States Securities Exchange Act of 1934
Federal Energy Regulatory Commission
Greenhouse gas
Gray Oak Pipeline, LLC
Hydrogen gas
International Joint Tariff
Incentive Regulation
Thousand barrels per day
Line 3 Replacement
Land Matters Consultation Initiative
Liquefied natural gas
Magic Valley Wind Farm
Maritimes & Northeast Pipeline
4
M&N Canada
the Court
MD&A
MW
NCIB
NEXUS
NGL
Noverco
NYSE
OBPS
OCI
OEB
OPEB
P66
the Partnerships
PennEast
PHMSA
PPA
PSU
the Reservation
RNG
ROE
ROU
RSU
SEC
SEP
SESH
Spectra Energy
Texas Eastern
TGE
TSX
UK
US
US GAAP
Vector
VIEs
Westcoast
Woodfibre
Canadian portion of our Maritimes & Northeast Pipeline
United States District Court for the Western District of Wisconsin
Management’s Discussion and Analysis
Megawatts
Normal course issuer bid
NEXUS Gas Transmission Pipeline
Natural gas liquids
Noverco Inc.
New York Stock Exchange
Output-based pricing system
Other comprehensive income/(loss)
Ontario Energy Board
Other postretirement benefit obligations
Phillips 66
Spectra Energy Partners, LP and Enbridge Energy Partners, L.P
PennEast Pipeline Company, L.L.C.
Pipeline and Hazardous Materials Safety Administration
Power purchase agreement
Performance Stock Units
Bad River Reservation
Renewable natural gas
Return on equity
Right-of-use
Restricted Stock Units
US Securities and Exchange Commission
Spectra Energy Partners, LP
Southeast Supply Header, L.L.C.
Spectra Energy Corp
Texas Eastern Transmission, L.P.
Tri Global Energy, LLC
Toronto Stock Exchange
The United Kingdom
United States of America
Generally accepted accounting principles in the United States of
America
Vector Pipeline L.P.
Variable interest entities
Westcoast Energy Inc.
Woodfibre LNG Limited Partnership
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; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas
liquids (NGL), liquified natural gas (LNG) and renewable energy; energy transition and lower-carbon energy, and our
approach thereto; environmental, social and governance (ESG) goals, practices and performance; industry and
market conditions; anticipated utilization of our assets; 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, benefits and in-service dates related to
announced projects and projects under construction; expected capital expenditures; investable capacity and capital
allocation priorities; share repurchases under our normal course issuer bid; expected equity funding requirements for
our commercially secured growth program; expected future growth, development and expansion opportunities;
expected optimization and efficiency 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; expected future actions of regulators and courts, and the timing and impact thereof;
toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including Mainline
Contracting and those relating to the Gas Transmission and Midstream and Gas Distribution and Storage businesses;
operational, industry, regulatory, climate change and other risks associated with our businesses; and our assessment
of the potential impact of the various risk factors identified herein.
Although we believe these forward-looking statements are reasonable based on the information available on the date
such statements are made and processes used to prepare the information, such statements are not guarantees of
future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their
nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other
factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed
or implied by such statements. Material assumptions include assumptions about the following: the expected supply of,
demand for, export of and prices of crude oil, natural gas, NGL, LNG and renewable energy; anticipated utilization of
assets; exchange rates; inflation; interest rates; the COVID-19 pandemic and the duration and impact thereof;
availability and price of labor and construction materials; the stability of our supply chain; operational reliability;
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 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 earnings before interest, income taxes, and depreciation
and amortization (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, NGL, LNG and renewable
energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may
impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates 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. The
most relevant assumptions associated with forward-looking statements regarding announced projects and projects
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under construction, including estimated completion dates and expected capital expenditures, include the following:
the availability and price of labor and construction materials; the stability of our supply chain; the effects of inflation
and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of
weather and customer, government, 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; acquisitions, dispositions
and other transactions and the realization of anticipated benefits therefrom; operational dependence on third parties;
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; inflation; interest rates; commodity
prices; access to and cost of capital; political decisions; global geopolitical conditions; the supply of, demand for and
prices of commodities and other alternative energy; 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 assumption, 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 and 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 are not measures that have a standardized meaning prescribed by the
accounting principles generally accepted 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
Enbridge is a leading North American energy infrastructure company. Our core businesses include
Liquids Pipelines, which consists of pipelines and terminals in Canada and the US that transport and
export various grades of crude oil and other liquid hydrocarbons; Gas Transmission and Midstream, which
consists of investments in natural gas pipelines and gathering and processing facilities in Canada and the
US; Gas Distribution and Storage, which consists of natural gas utility operations that serve residential,
commercial and industrial customers in Ontario and Québec; and Renewable Power Generation, which
consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery
and transmission assets, in North America and Europe.
Enbridge is a public company, with common shares that 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 people’s quality of life in a safe, clean, and socially
responsible manner. Our vision to be the leading energy infrastructure company in North America and
beyond supports this purpose. In pursuing this vision, we seek to play a critical role in enabling the
economic and social well-being of people across the world by providing access to affordable, reliable, and
secure energy. Our infrastructure franchises transport, distribute, and generate energy, including liquids,
natural gas, renewable power, and lower-carbon fuels. We recognize that the energy system is changing,
and we aim to bridge to a cleaner energy future by investing in lower-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 (PPAs), and other low-risk commercial arrangements.
In addition, we strive to be a leader in worker and public safety, ESG, stakeholder relations, customer
service, community investment, and employee engagement and satisfaction.
STRATEGY
Our strategy is underpinned by a deep understanding of energy supply and demand fundamentals.
Through disciplined capital allocation that is aligned with our outlook on energy markets, we have become
an industry leader with a diversified portfolio across both conventional and lower-carbon energies. Our
assets have reliably generated low-risk, resilient cash flows through many commodity and economic
cycles.
8
In order to 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 business strategy. We test various value enhancement and maximization options, and we regularly
engage with our Board of Directors (the Board) to ensure alignment and maintain active oversight,
including updates and discussions throughout the year and a dedicated annual Strategic Planning
session. Going forward, we plan to use this comprehensive approach to guide our investment and
portfolio decisions.
Predictable growth is a hallmark of our investor value proposition. Our robust portfolio of project
development opportunities and ongoing efficiency improvements should help drive mid-single digit growth
in our distributable cash flow per share for years to come. We remain confident in our two-pronged growth
strategy and expect to selectively invest in our diversified footprint of both conventional businesses and
complementary lower-carbon platforms, such as renewables, Carbon Capture and Storage (CCS),
Hydrogen (H2), and Renewable Natural Gas (RNG). Additionally, ESG continues to be integral to our
strategy; we are committed to reducing our emissions, building lasting relationships with our stakeholders,
and promoting diversity, equity, and inclusion.
In alignment with our strategy, we progressed several of our priorities in 2022. For example:
• Our Liquids Pipelines business delivered record Mainline volumes, increased ownership in and
operatorship of the Gray Oak pipeline, and permitted a 2 million barrels (mmbl) storage expansion at
Enbridge Ingleside Energy Center (EIEC), further bolstering our presence in the US Gulf Coast and
global export markets.
• Our Gas Transmission and Midstream business successfully expanded our secured capital program
notably with the T-South Expansion Program and T-North Expansion Program and acquired an equity
stake in Woodfibre LNG Limited Partnership to capitalize on increasing global gas demand and
supporting coal-to-gas conversions that are expected to help lower global energy emissions.
• Our Gas Distribution and Storage business added over 45,000 new customers, filed the rate rebasing
application for 2024-2028 which proposes continuation of Incentive Rate-setting mechanisms,
completed the Pathways to Net-Zero Emissions Study for Ontario, and progressed construction of
three RNG projects and development of a green hydrogen blending project at Gazifère Inc.
(Gazifère), a wholly-owned natural gas distribution company in Québec.
• Our Renewable Power Generation business accelerated its growth strategy with the acquisition of the
renewable developer Tri Global Energy, LLC (TGE), securing 3.9 gigawatts (GW) of conditionally sold
renewable generation projects and an additional 3 GW in development projects. In addition, the 480
megawatts (MW) Saint-Nazaire project, France’s first commercial-scale offshore wind in which
Enbridge holds a stake, became fully operational in 2022. We are continuing to advance construction
of three additional offshore wind projects in Europe.
• Our New Energy Technologies team, in collaboration with all of our business units, advanced our
lower-carbon strategy, including building strategic partnerships to progress the Wabamun Carbon Hub
in Alberta and lower-carbon hydrogen and ammonia production and export facilities in the US Gulf
Coast.
• We have made meaningful progress towards our ESG goals, advancing construction of ten solar self-
power projects, signing a landmark sale of a non-operating interest in pipelines in our Regional Oil
Sands System to 23 Indigenous communities, and publishing our Indigenous Reconciliation Action
Plan to further our engagement.
• We continue to recycle capital at attractive valuations, further optimizing and diversifying our portfolio.
In addition, we are focused on improving efficiencies to increase 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 our assets, protecting the environment, and maintaining reliability of our system
remain our top priorities. We are focused on enhancing the value of our existing assets, capitalizing on
our extensive infrastructure, prioritizing in-franchise organic growth and export-driven opportunities, and
developing lower-carbon platforms across all our businesses. We will continue to invest where we can
advance our strategy, build sustainable competitive advantage, and achieve attractive risk-adjusted
returns.
Our key strategic priorities include:
Safety and Operational Reliability
Safety and operational reliability are the foundation of our strategy. We strive to achieve and maintain
industry leadership in all facets of safety - process, public, and personal - and ensure the highest
standards of reliability and integrity across our system to protect our communities and the environment.
Extend Growth
The cornerstone of our growth lies in the successful execution of our slate of secured projects (currently
$18 billion through 2028) on schedule and 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.
Beyond that, we seek to continually identify additional high-quality growth opportunities across all our
platforms. We expect to have sufficient equity self-funding capacity of about $5 to $6 billion per year to
invest in growth without issuing any additional common equity and maintaining key credit metrics. We will
remain disciplined and will strive to 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 what we believe are the most
value-enhancing opportunities available to us, including further organic growth, complementary accretive
"tuck-in" acquisitions that improve our competitive positioning, share repurchases, or further deleveraging
of 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, we expect that:
• 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.
• Our natural gas transmission business will seek extension and expansion opportunities driven by new
load demand from gas-fired power generation, industrial growth, and coastal LNG plants. Looking
forward, blending RNG and H2 production into our system should enhance asset longevity and
enable us to offer a differentiated lower-carbon solution to customers.
• Our gas distribution and storage business will continue to grow through productivity enhancements,
modernization investments, and facilities that blend H2 and RNG into the gas supply. We expect to
continue to add customers over the next regulatory framework period to 2028. Additionally, we expect
to expand our offerings to customers, including additional demand-side management, as well as
resiliency and hybrid heating programs.
10
• Our enhanced renewable power capabilities position us well to capitalize on strong renewables
growth in Europe and North America and execute on our large development program. We also plan to
continue to progress our multi-year self-power program across our liquids and gas systems.
In addition, we aim to drive growth through an ongoing focus on optimization, modernization, productivity,
and efficiency across all our businesses. Examples include: the application of drag-reducing agents and
pump station modifications 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 lower-
carbon offerings to utility customers and investments in lower-carbon supply connections to the gas grid,
and more generally, the creation of sustainable cost savings across the organization through innovation,
process improvement and/or system enhancements.
Maintain a Strong Balance Sheet
The maintenance of our balance sheet strength is critical to our strategy. Our financing strategies are
designed to retain strong, investment-grade credit ratings to ensure we have the financial capacity to
meet our capital funding needs and the flexibility to manage capital market disruptions. Our current
secured capital program can be readily financed through internally generated cash flow and available
balance sheet capacity without issuance of additional common equity. 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 capital deployment
opportunity set. We screen, analyze, and assess opportunities using a disciplined investment framework
with the objective of effectively deploying capital to grow while achieving attractive risk-adjusted returns,
within our low-risk "utility-like" business model.
All investment opportunities are evaluated based on their potential to advance our strategy, mitigate risks,
support our ESG goals, and create additional financial flexibility. Our primary emphasis in the near term is
on low capital intensity opportunities to enhance returns in existing businesses (organic expansions and
optimizations), modernization of our systems, and utility rate-based investments. We also remain focused
on larger projects where commercial constructs fit our investor value proposition and where we can
effectively manage risks during the execution phase. In addition, we continue to assess other value-
enhancing opportunities, such as accretive acquisitions that can complement our portfolio.
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 repurchases.
Lead in Energy Transition Over Time
As the global population grows and standards of living continue to improve around the world, we expect
energy demand to rise. At the same time, we, and our society, increasingly recognize the need for secure
and reliable energy while reducing global greenhouse gas (GHG) emissions. Accordingly, energy systems
around the world are being reshaped as industry participants, regulators, and consumers seek to lower
emissions. As a diversified energy infrastructure company, we believe we are well positioned to play a key
role in the energy transition by leading the development of the future energy systems with regulators and
policy makers and partnering with customers on their lower-carbon strategies, while reducing our own
carbon footprint.
11
We believe that diversification and innovation will play a significant role in the transition to a lower-carbon
future. To date, we have made large investments in natural gas infrastructure and renewable energy
assets, helping to decrease our emissions and further expand our platforms to enable energy transition
across the globe. Our focus areas in renewable energy remain in offshore wind, utility-scale onshore
projects, and integrated clean-energy offerings and solutions for customers. We are also taking a
leadership role in other lower-carbon platforms like CCS, H2 and RNG where we can leverage our
infrastructure, capabilities, and stakeholder relationships to accelerate growth and extend the value of our
existing assets. Additionally, our new investments are expected to have a clear path to achieve net-zero
emissions, in alignment with our ESG goals.
We work closely with our customers to maintain a pulse on the pace of the energy transition and are
actively leveraging our ESG leadership and world-class execution capabilities to advance our positioning
as a differentiated energy provider. We regularly test our assets under various transition scenarios to
assess resiliency of our business.
STRATEGIC ENABLERS
Our commitment and progress on ESG, the capabilities and skills of our people, and how we utilize
technology are core to executing our strategy and maintaining our competitive advantages.
Environmental, Social and Governance
Sustainability is integral to our ability to deliver energy in a safe and reliable manner. 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 our stakeholders.
In 2022, we published our 21st annual Sustainability Report outlining our progress against our ESG
goals1. In particular, we:
• Made meaningful progress towards our interim emissions intensity and net-zero GHG emissions
goals through modernization and innovation of our system, efficiency improvements, and continued
investment in solar self-power;
• Enhanced our efforts to ensure that our workforce and Board better reflect the diversity of our
communities, empowering our workforce through employee resource groups and advancing on our
diversity, equity, and inclusion commitments; and
• Continued to drive improvements towards our goal of zero safety incidents and injuries and
progressed implementation of robust cyber defense programs.
Since setting our ESG targets in 2020, we have made considerable progress integrating sustainability into
our strategy, governance, operations, and decision-making. We have linked ESG performance to
incentive compensation and are making meaningful progress towards these targets by executing on our
action plans.
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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At Enbridge, we aim to continuously strengthen our ESG approach and are undertaking the following
additional actions:
• Proactively working with organizations advancing science-based guidelines for the midstream sector;
• Collaborating with key suppliers on emissions reduction plans; and
• Further developing lower-carbon energy partnerships to drive innovation across our businesses, with
a focus on renewable power, RNG, H2 and CCS.
People
Our employees are essential to our success and our focus remains on enhancing the capabilities and
skills of our people. We are evolving our people strategy to ensure we attract and retain the talent and
leadership needed for today and tomorrow. This includes growing our focus on learning and development,
and additional focus on overall well-being. We value diversity, and diverse thought, and have embedded
inclusive practices in our programs, processes, and approach to people management. Furthermore, we
strive to maintain industry competitive compensation, flexibility, and retention programs that provide both
short- and long-term performance incentives.
Technology
We recognize the vital role technology plays in helping us achieve our strategic objectives. We are
committed to pursuing innovation and technology solutions that further our safety and reliability, maximize
revenues, improve efficiencies, and enable transition to new, cleaner energy solutions. We continue to
strive to be on the leading edge of cyber security, by enhancing our capabilities and educating our
workforce to protect our critical infrastructure system from increasing threats.
Our two Technology and Innovation labs, located in Calgary and Houston, embody our commitment to
technology enabled business solutions and how we strive to entrench technology in our everyday
operations.
We provide annual progress updates 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.
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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.
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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. Through our predecessors, 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 on 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 in 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. 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,
which is comprised of the IJT Benchmark Toll, the CTS Surcharges and the Line 3 Replacement IJT
Surcharge, 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 Toll which is denominated in US
dollars.
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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 thousand barrels
per day (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.
On October 5, 2022, we completed a transaction with Athabasca Indigenous Investments Limited
Partnership (Aii), a newly created entity representing 23 First Nation and Metis communities, pursuant to
which Aii acquired an 11.6% non-operating interest in seven Regional Oil Sands pipelines in the Regional
Oil Sands System. Pipelines included in the transaction are the Athabasca Pipeline, Wood Buffalo
Extension/Athabasca Twin pipeline system and associated tanks, Norlite, Waupisoo Pipeline, Wood
Buffalo Pipeline, Woodland Pipeline, and Woodland Extension.
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 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.
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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 660 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.
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. As of August 17, 2022, our effective economic interest
in Gray Oak increased to 58.5% from 22.8% as a result of a joint venture merger transaction with Phillips
66 (P66) and we will be assuming operatorship of Gray Oak in the second quarter of 2023.
The Mid-Continent System is comprised of storage terminals at Cushing, Oklahoma (Cushing Terminal),
consisting of over 110 individual storage tanks ranging in size from 78 to 570 thousand barrels. Total
storage shell capacity of Cushing Terminal is approximately 26 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, and
blending fees.
In October 2021, we acquired Moda Midstream Operating, LLC, which included the Ingleside Energy
Center (renamed the Enbridge Ingleside Energy Center or 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. In November 2022, we
acquired an additional 10% ownership interest in Cactus II Pipeline, bringing our total non-operating
ownership to 30%.
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.
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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.
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 Dakota Access Pipeline (DAPL) from the Bakken area in North Dakota to Patoka,
Illinois, and the Energy Transfer Crude Oil Pipeline (ETCO) 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. The majority of the SAX
pipeline's 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 for 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 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. We have a proven track record of successfully
executing projects to meet the needs of our customers.
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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 we expect 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,
since 2021, global crude oil demand has been recovering 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.
Our Mainline System throughput, as measured at the Canada/US border at Gretna, Manitoba ended the
year delivering 3.1 mmbpd. 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 is expected to primarily come from Organization of the
Petroleum Exporting Countries (OPEC) countries and North America. Growth in supply from OPEC is
anticipated to 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 is
expected to 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 anticipated 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 believe that 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 EIEC 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.
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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, LLC (Sabal Trail), NEXUS Gas Transmission Pipeline, LLC (NEXUS), Valley
Crossing Pipeline, LLC. (Valley Crossing), Southeast Supply Header, LLC (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 interstate 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 12.04 billion
cubic feet per day (bcf/d) of natural gas on approximately 13,765 kilometers (8,553 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 interstate 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 of 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 interstate 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 2,449 kilometers (1,522 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 1.39 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) interstate 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) interstate 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 provides natural gas transmission services, transporting processed natural gas from facilities
located primarily in northeastern BC to markets in BC and the US Pacific Northwest. It 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, as well as associated mainline compressor stations. BC Pipeline is regulated
by the CER under cost-of-service regulation.
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 Liquid
Products LP natural gas liquids (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 a 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.
As of August 17, 2022, US Midstream also includes a 13.2% effective economic interest in DCP
Midstream, LP (DCP). Prior to August 17, 2022, we had a 28.3% effective economic interest in DCP. DCP
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 NGL; and recovering and selling condensate. DCP owns and operates
more than 36 plants and approximately 86,905 kilometers (54,000 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 NGL. 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 we expect to continue to play a part as the energy landscape evolves.
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Natural gas production in the Appalachian and Permian basins has grown dramatically in the past
decade. Today, these regions produce more than 47 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 both producers and consumers. Our US Gas Transmission systems were initially designed
to transport natural gas from the Gulf Coast to the supply-constrained 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 allow 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 over 2.0 bcf/d over the next decade, 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 in these markets in the region is anticipated to grow by more than 20.0 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. In 2022, the US exported over 10.6 bcf/d of
natural gas to LNG markets, primarily from the Gulf Coast region.
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. The continental supply profile has
shifted to natural gas shale plays such as the Montney and Duvernay within western Canada. These
supply shifts have shaped our growth strategies and affect the nature of the projects anticipated in the
capital expenditures discussed below in Part II. Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.
Global energy demand is expected to increase approximately 24% by 2050, according to the recently
released International Energy Agency’s Stated Policy Scenario, driven primarily by economic growth in
non-OECD countries. According to the Stated Policy Scenario, natural gas will play an important role in
meeting this energy demand, and gas consumption is anticipated to grow by approximately 13% during
this period as one of the world’s most significant energy sources. North American exports are expected to
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, as well as further build-out of export facilities to meet international demand.
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The long-term impacts of the Ukraine conflict on global gas markets are still unclear. Europe has
experienced a rapid increase in natural gas prices, largely as a result of reduced natural gas supply from
Russia. Global LNG markets have responded, and natural gas storage volumes entering the winter
season in Europe were strong. However, these LNG cargos have largely been diverted from Asian
markets, and over time the LNG market is expected to normalize.
Europe continues to seek lower-carbon gas supplies and has accelerated plans to develop hydrogen as
an alternative to natural gas. The global hydrogen market is still relatively immature, but with incentives
being put in place such as those in the US Inflation Reduction Act, hydrogen production at large scale is
becoming increasingly commercialized, which has led to a growing export market. Given its proximity to
low-cost natural gas supplies and suitable geologic storage for carbon dioxide (CO2), the US Gulf Coast
is well positioned to be a leading export hub to supply blue hydrogen to international markets. Given
these rapidly changing global fundamentals, and coupled with growing appetite for lower-carbon
hydrogen, we believe we are well positioned to provide value-added solutions to shippers and meet both
regional and international demand.
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.
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.
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ENBRIDGE GAS
Enbridge Gas is a rate-regulated natural gas distribution utility with storage and transmission services.
Enbridge Gas' distribution system, supported by storage and compression assets, carries natural gas
from the point of local supply to customers and serves residential, commercial and industrial customers
across Ontario.
There are three principal interrelated aspects of the natural gas distribution business in which Enbridge
Gas is directly involved: Distribution, Transportation and Storage.
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 149,000 kilometers (92,584 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 has continued to grow, there has been 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 2,162
bcf of gas through its distribution and transmission system in 2022. 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 18 years.
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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.
Enbridge Gas’ storage facility at Dawn is located in southwestern Ontario, and has a total working
capacity of approximately 284 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 2022, 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 14 years.
GAZIFÈRE
We wholly own Gazifère, a natural gas distribution company that serves approximately 44,000 customers
in western Québec. 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 anticipate that demand for natural gas in North America will stabilize 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. Net-zero carbon policies, 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 and public policy requirements.
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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
strong 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 and proposed RNG programs, we are also expanding our efforts to source other lower-carbon
supplies, such as responsibly sourced natural gas, and H2.
The storage and transportation marketplace continues to respond to changing natural gas supply
dynamics, including a recovered 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. However,
over the past year, geopolitical unrest has increased and lead to elevated concerns with energy security
in regions such as Europe and Asia. In response, one of the key supply sources supporting global energy
security has been US LNG, which has introduced additional competition for North American supply. These
market dynamics have resulted in higher and more volatile natural gas prices across many US and
Canadian natural gas trading points. Unregulated storage values are primarily determined by the
difference in value between winter and summer natural gas prices. Despite the recent volatility exhibited
in natural gas prices, storage values have been relatively stable.
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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, France, and Germany, as well as interests in several offshore
wind projects under construction and active development in France and the United Kingdom.
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Combined Renewable Power Generation investments represent approximately 2,175 MW of net
generation capacity, which primarily consists of approximately:
• 1,389 MW generated by North American wind facilities;
• 377 MW generated by European offshore wind facilities;
• 187 MW to be generated by the Fécamp and Calvados Offshore Wind projects in France, both of
which are currently under construction;
• 6 MW to be generated by the Provence Grand Large Floating Offshore Wind project in France, which
is under construction; and
• 93 MW generated by North American solar facilities in operation, with an additional 97 MW in projects
in pre-construction and under construction.
The vast majority of the power produced from these facilities is sold under long-term PPAs.
In September 2022, we acquired renewable energy project developer TGE with a development portfolio of
wind, solar, and energy storage projects in Texas, Nebraska, Illinois, Indiana, Virginia, Pennsylvania, and
Wyoming. TGE’s development portfolio includes 3.9 GW of conditionally sold renewable generation
projects and an additional 3 GW of wholly-owned projects in development. Following its acquisition of
TGE, Enbridge became one of the top 15 renewable energy project developers in the US.
Renewable Power Generation also includes our 25% interest in the East-West Tie, a 450-MW
transmission line in northwestern Ontario, which entered operations in March 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 and Albatros Offshore Wind, located in Germany;
• a 25.5% interest in the Saint-Nazaire Offshore Wind project, located in France;
• a 25% interest in the Provence Grande Large Floating Offshore Wind project, under 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, under construction in France.
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 have expertise in
completing and delivering large scale infrastructure projects.
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SUPPLY AND DEMAND
Renewable power generation 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 lower-carbon strategies within the residential, transportation and industrial
sectors are expected to drive growing electricity demand. Furthermore, voluntary GHG emissions
reduction 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 lower-carbon
intensities. Governments are also proposing tax incentives to support low-emission and renewable energy
generation resource development.
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, and the
desire to reduce reliance on gas sourced from Russia. Energy efficiency gains are expected to temper,
but not eliminate, demand growth. Renewable power is expected to play a significant role in Europe’s
ability to meet its aggressive lower-carbon and renewable energy targets.
On the supply side, the International Energy Agency expects coal to fall by more than 90% from 2020
levels, while nuclear is expected to fall 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, the impact of foreign exchange hedge settlements and the activities of our wholly-owned
captive insurance subsidiaries. The principal activity of our captive insurance subsidiaries is providing
insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our
operating subsidiaries and certain equity investments. 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 (DOT). These laws and regulations require us to comply
with a significant set of requirements for the design, construction, maintenance and operation of our
interstate pipelines. These laws and regulations, among other things, include requirements to monitor and
maintain the integrity of our pipelines and to operate them within permissible pressures.
PHMSA continues to review existing regulations and establish new regulations to support safety
standards that are designed to improve operations integrity management processes. There remains
uncertainty as to how these standards will be implemented, but it is expected that the changes will result
in 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 is
subject to regulation by the FERC, whose rulings and policies could have an adverse impact on the ability
to recover the full cost of operating these pipeline and storage assets, 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.
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In Canada, our pipelines are subject to 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.
As in the US, laws and regulations addressing pipeline safety in Canada were enacted over the past few
years. The changes demonstrate an increased focus on the implementation of management systems to
address key areas, such as emergency management, integrity management, safety, security and
environmental protection. The CER also has authority 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 ensuring reliability targets are met. Furthermore, the integrity management program has
an independent step to check the results of 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 regulatory risk. Broadly defined, economic regulatory risk is the risk that
governments or regulatory agencies reject proposed commercial arrangements, applications or policies,
upon which future and current operations are dependent. Our pipelines are subject to the actions of
various regulators, including the CER and the FERC, with respect to the tariffs and tolls. The rejection of
applications for approval of new tariff structures or proposed commercial arrangements and changes in
interpretation 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 in the Consolidated
Statements of Financial Position, or amounts that would have been recorded in 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).
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In October 2022, Enbridge Gas filed its application with the OEB to establish a 2024 through 2028 rate
setting framework. The application and framework seek approval to establish 2024 base rates on a cost-
of-service basis and to establish a price cap IR rate setting mechanism to be used for the remainder of
the term (2025 - 2028). The OEB has determined it will hear the application in two phases, with Phase 1
addressing items that affect rates effective January 1, 2024, and Phase 2 addressing items that will affect
rates subsequent to January 1, 2024. An OEB decision is expected on Phase 1 of the application in the
second half of 2023.
Enbridge Gas continues to develop opportunities to support a lower-carbon future in Ontario. In 2021, we
received OEB approval of an Integrated Resource Planning (IRP) framework and integrated the
framework into our planning practices. The framework requires Enbridge Gas to consider facility and non-
pipe demand and/or supply side alternatives (IRP alternatives) to address the systems needs of its
regulated operations, where certain parameters have been met. The framework also allows Enbridge Gas
to pursue an IRP alternative (or combination of IRP alternatives and facility alternative) where it is found
to be in the best interests of Enbridge Gas and its customers, taking into account reliability and safety,
cost-effectiveness, public policy, optimized scoping, and risk management. Enbridge Gas has reviewed its
system needs as part of its 2023-2032 Asset Management Plan and is now evaluating the technical and
economic feasibility of IRP alternatives for the projects. A summary of the IRP evaluation statuses has
been filed as part of Enbridge Gas’ 2024 Rebasing Application.
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 Electric 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 US, and Mexico. It is subject to oversight from the FERC in the US 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 has
proposed a Clean Electricity Regulation (CE Regulation) that would require Canada’s electricity grid reach
net-zero by 2035. The CE Regulation is expected to come into effect in 2023.
Policy changes may also provide new opportunities for existing assets and new developments. The
United States passed the Inflation Reduction Act in late 2022, which established long-term production and
investment tax credits for renewable power generation, battery storage projects and for related
manufacturing supply chains. Similarly, Canada proposed in its Fall Economic Statement competitive tax
credits for renewable power generation and battery storage projects, which it anticipates passing in 2023.
Changes to these tax programs could impact development plans.
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Renewable Power Generation is also subject to Provincial and State regulations governing the energy
resource mix on the grid, emissions levels of the electricity grid, and market regulations related to
emergency operations, extreme weather preparedness, and market participation, among others. These
regulations may change from time to time, which could impact Enbridge’s operations and increase the
costs of participating in regional electricity markets.
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 (most recently, RED II 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. During 2022, member states of the EU introduced extraordinary and temporary measures to
address high energy prices including caps and demand reduction goals. As the minimum PPA prices in
Germany and France will still be honored, there will not be any negative implications to our PPA prices.
The federal policies and regulations in place 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. Government-imposed
temporary price controls, effective January 1, 2023, were introduced during 2022 to address the
significant increase in energy prices. The impact of merchant exposure on our Renewable Power
Generation asset in the UK is limited by fixed revenue payments backed by the UK government.
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 (including
targeted training) 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 provincial and territorial securities regulators similarly regulate commodity marketing
within Canada and are members of the Canadian Securities Administrators. These various regulators
enforce, among other things, the prohibition of market manipulation, fraud and disruptive trading.
The export of natural gas out of Alberta is regulated by the Alberta Energy Regulator (AER). 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 import and export rules and permits
could result in an inability to perform day to day operations, and therein negatively impact the earnings of
the business.
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The transportation of crude oil and natural gas liquids by railcar or truck is regulated by the US DOT,
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 Emergency Response Assistance Canada, the Chemical Transportation
Emergency Center and the 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 may 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
establishing new state implementation plans which have new emissions limits to comply with ozone
standards regulated under the National Ambient Air Quality Standards. In 2015, the ozone standards were
lowered once again 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.
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 current 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
uncertain.
Canada has adopted a pan-Canadian approach to pricing carbon emissions to incent GHG emission
reductions across all sectors of the economy. This approach was adopted in 2016 and entails both a
consumer price on carbon, and an intensity-based system for industry which addresses competitiveness
and carbon leakage. Provinces and territories may implement their own system of carbon pricing provided
it meets the federal benchmark (and if they fail to do so the federal system will be imposed on them). In
March 2022, Canada published its 2030 Emissions Reduction Plan (ERP) which builds on the Pan-
Canadian Framework, and Net-Zero Emissions Accountability Act, and details the roadmap for Canada to
meet its domestic climate target of a 40-45% reduction in GHG emissions by 2030 and attaining net-zero
emissions by 2050. The ERP details the complementary policies and programs that Canada will enact to
enable it to meet its domestic climate goal. Effective January 1, 2023, the federal carbon price was
increased from $50 to $65 per tonne of carbon dioxide equivalent (tCO2e). This will increase by $15 per
tonne and rise to $170 per tCO2e in 2030.
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Gas Distribution and Storage
Our Gas Distribution and Storage operations, facilities and workers are subject to municipal, provincial
and federal legislation which regulates 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 excess soil and contaminated
sites; protection of environmentally sensitive areas, and species at risk and their habitats; 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 gas 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 and orders under environmental legislation, and potential third-
party liability claims by any affected landowners.
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. Reports are submitted to our regulators as required 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 regulations continue to evolve and become more stringent, the cost to maintain
compliance and the time required to obtain approvals continues to increase. A recent example includes
the implementation of the new excess soil management requirements (Ontario Regulation 406/19) which
has resulted in an increase in soil management costs and effort.
As in previous years, in 2022, we reported operational GHG emissions, including emissions from
stationary combustion, flaring, venting and fugitive sources to Environment and Climate Change Canada
(ECCC), the Ontario Ministry of Environment, Conservation and Parks, 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 are
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.
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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 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 beginning in 2023, rising to $170 per tCO2e 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.
The OBPS component came into effect in Ontario on January 1, 2019 and ended on December 31, 2021.
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. From 2019 to 2021, Enbridge Gas was registered with ECCC as an
emitter in the OBPS program and has an annual compliance obligation associated with the combustion
and flaring emissions from 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 was required to remit
payment for facility emissions that exceed its annual facility emissions limit by December of the year
following a compliance period. In accordance with the regulations, Enbridge Gas made payment for the
2021 compliance obligation in December 2022.
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 would stand
down in Ontario at the end of 2021 and Ontario would 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, enabling the EPS to take effect on January 1, 2022. Effective January 1, 2022,
Enbridge Gas transitioned out of the federal OBPS to the provincial EPS. Enbridge Gas is registered with
the Ministry of the Environment, Conservation and Parks as a covered facility under the EPS and has an
annual compliance obligation for its facility-related stationary combustion and flaring emissions associated
with its transmission and storage operations. Enbridge Gas must remit payment annually on the portion of
emissions that exceed its total annual emissions limit. Payment is due the year following a compliance
period and as such, Enbridge Gas will remit payment for its 2022 EPS compliance obligation in 2023.
Enbridge Gas applies to the OEB annually through a Federal Carbon Pricing Program application for
approval of just and reasonable rates effective April 1 each year for the Enbridge Gas Distribution Inc. and
Union rate zones, to recover the costs associated with the Federal Carbon Charge and EPS Regulation
as a pass-through to customers.
Renewable Power Generation
In March 2022, the Federal Government of Canada released a white paper setting out its plans for caps
on emissions on Canada’s electricity grid with the intention of reaching a net-zero grid by 2035. The
government subsequently proposed a CE Regulation framework and provided technical details for the
program, which would cap emissions from electricity generation sources at, or near zero tCO2e per
megawatt hour. Details of related compliance payments and potential credit generation opportunities are
under review and the CE Regulation is expected to come into effect in 2023. Enbridge’s Renewable
Power Generation resources are substantially non-emitting.
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HUMAN CAPITAL RESOURCES
WORKFORCE SIZE AND COMPOSITION
As at December 31, 2022, we had approximately 11,100 regular employees, including approximately
1,600 unionized employees across our North American operations. This total rises to just over 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, EQUITY AND INCLUSION
In 2020, we announced Enbridge’s ESG goals – including goals to increase representation of women,
underrepresented ethnic and racial groups (including Indigenous peoples), people with disabilities and
veterans – to ensure our workforce is reflective of the communities where we operate. In executing on our
ESG strategy, we continue to track progress towards these representation goals in 2022. Consistent with
our culture, we remain committed to open, two-way dialogue related to our goals, enhancing transparency
and accountability for all stakeholders.
Diversity Representation Goals
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.
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EXECUTIVE OFFICERS
The following table sets forth information regarding our executive officers as at February 10, 2023:
Name
Gregory L. Ebel
Vern D. Yu
Colin K. Gruending
Cynthia L. Hansen
Byron C. Neiles
Robert R. Rooney
Matthew A. Akman
Age Position
58
56
53
58
57
66
55
President & Chief Executive Officer
Executive Vice President, Corporate Development, Chief Financial Officer
& President, New Energy Technologies
Executive Vice President & President, Liquids Pipelines
Executive Vice President & President, Gas Transmission and Midstream
Executive Vice President & Chief Administrative Officer
Executive Vice President & Chief Legal Officer
Senior Vice President, Corporate Strategy & President, Power
Michele E. Harradence 54
Senior Vice President & President, Gas Distribution
Laura J. Sayavedra
55
Senior Vice President, Safety & Reliability, Projects and Unify
Gregory L. Ebel was appointed President and Chief Executive Officer on January 1, 2023. Mr. Ebel is also
a member of the Enbridge Board of Directors. Mr. Ebel served as Chair of the Enbridge Board of Directors
following the merger of Enbridge and Spectra Energy Corp (Spectra Energy) in 2017 until January 1,
2023. Prior to that time, he served as Chairman, President and CEO of Spectra Energy from 2009 until
February 27, 2017. Previously, Mr. Ebel also served as Spectra Energy’s Group Executive and Chief
Financial Officer beginning in 2007, President of Union Gas Limited from 2005 until 2007, and Vice
President, Investor & Shareholder Relations of Duke Energy Corporation from 2002 until 2005.
Vern D. Yu was appointed Executive Vice President, Corporate Development, Chief Financial Officer &
President, New Energy Technologies on January 1, 2023. Prior thereto, he served as Executive Vice
President, Corporate Development and Chief Financial Officer from March 2022 to December 2022, and
Executive Vice President and Chief Financial Officer from October 2021 to March 2022. Mr. Yu has
oversight for all of Enbridge’s financial affairs including investor relations, financial reporting, financial
planning, treasury, tax, insurance, risk and audit management functions. He is also responsible for
overseeing Enbridge’s new energy technology ventures. Previously, Mr. Yu served as Executive Vice
President and President, Liquids Pipelines from January 2020 to October 2021; President and Chief
Operating Officer for Liquids Pipelines from June 2019 to December 2019; and Executive Vice President
and Chief Development Officer from May 2016 to June 2019.
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
from June 2019 to October 2021; Senior Vice President, Corporate Development and Investment Review
from May 2018 to June 2019; and Vice President, Corporate Development and Investment Review from
February 2017 to May 2018.
Cynthia L. Hansen was appointed Executive Vice President and President, Gas Transmission and
Midstream on March 1, 2022. Ms. Hansen is responsible for the overall leadership and operations of
Enbridge’s natural gas pipeline and midstream business across North America. Previously, she served as
our Executive Vice President, Gas Distribution and Storage from June 2019 to March 2022 and as
Executive Vice President, Utilities and Power Operations from February 2017 to June 2019. Ms. Hansen
is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working
with other business unit leaders.
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Byron C. Neiles was appointed Executive Vice President & Chief Administrative Officer on January 1,
2023. Prior thereto, he served as Executive Vice President, Corporate Services from May 2016 to
December 2022. Mr. Neiles has oversight of our information technology, human resources, real estate,
supply chain management, 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.
Matthew A. Akman was appointed Senior Vice President, Corporate Strategy & President, Power on
January 1, 2023. Prior thereto, he was Senior Vice President, Strategy, Power & New Energy
Technologies from October 2021 to December 2022, and Senior Vice President, Strategy & Power from
June 2019 to October 2021. Mr. Akman is responsible for the overall leadership and operations of
Enbridge’s power business and also leads our corporate strategy efforts. Mr. Akman joined Enbridge in
early 2016 as our head of Corporate Strategy and also previously held responsibilities for Corporate
Development and Investor Relations.
Michele E. Harradence was appointed Senior Vice President & President, Gas Distribution and Storage
on March 1, 2022. She is responsible for the overall leadership and operations of Ontario-based Enbridge
Gas Inc., as well as Gazifère, which serves the Gatineau region of Québec. Prior to assuming her current
role, Ms. Harradence was Senior Vice President and Chief Operations Officer of Enbridge’s Gas
Transmission and Midstream business unit from June 2019 to March 2022. Prior thereto, she was Senior
Vice President Operations, Gas Transmission and Midstream from February 2017 to June 2019.
Laura J. Sayavedra was appointed Senior Vice President, Safety & Reliability, Projects and Unify on
March 1, 2022. This includes oversight of our safety, capital project execution, environment, land, and
right of way functions, and business leadership of our multi-year Unify transformation project. Prior to that,
she led Finance Transformation at Enbridge, and was also Vice President & Treasurer for Spectra Energy,
and CFO of Spectra Energy Partners. She has held various finance, strategy, and business development
executive leadership roles.
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 MD&A for the year ended December 31, 2022, 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, 2022, 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 financial statements and MD&A for the year
ended December 31, 2022, 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.
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 is a systemic risk that presents both physical and transition risks to our organization. A
summary of these risks is discussed below. Given the interconnected nature of climate impacts, 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, 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 materially
adversely impacted as a result of climate change and its associated impacts.
PHYSICAL RISKS
Climate-related physical risks as a result of changing and more extreme weather, can damage our assets
and affect the safety and reliability of our operations and has had such impacts in the past. Climate-
related physical risks may be acute or chronic. Acute physical risks are those that are event-driven,
including increased frequency and severity of extreme weather events, such as heavy snowfall, heavy
rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice storms, and extreme
temperatures. Chronic physical risks are longer-term shifts in climate patterns, such as long-term changes
in precipitation patterns, or sustained higher temperatures, which may cause sea level rises or chronic
heat waves.
Our assets are exposed to potential damage or other negative impacts from these kinds of events, which
could result in reduced revenue from business disruption or reduced capacity and may also lead to
increased costs due to repairs and required adaptation measures. Such events may also result in 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.
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TRANSITION RISKS
Transition risks relate to the transition to a lower-emissions 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 reputation, 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 regarding reduction of GHG emissions, adaptation to climate change, transition to a
lower-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 are
continually evolving. 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.
Efforts to regulate or restrict GHG emissions could negatively impact demand for the products we
transport. Significant expenditures and resources could be required in order to meet new regulatory
requirements. In addition, there has been an increase in climate and disclosure-related litigation
against governments as well as energy companies. There is no assurance that our company will not
be impacted by such litigation.
In addition, Enbridge is required to adhere to a number of implicit and explicit carbon-pricing
mechanisms. Many jurisdictions in which we operate are either increasing the stringency of existing,
or introducing new, legislation or public policy to address climate change and reduce GHG emissions.
These mechanisms may present climate-related transition risk to our business strategy, impacting
both commodity demand and the overall energy mix we deliver. Carbon pricing mechanisms may
expose us to increased costs as well as increasing energy costs to our customers. Our operations are
subject to both explicit carbon prices (i.e., in BC) and implicit carbon prices (i.e., Canadian federal
OBPS). These requirements are evolving; in Canada, the federal government is considering options
to cap and cut oil and gas sector GHG emissions, which may impact our business, including a new
cap-and-trade system under the Canadian Environmental Protection Act, 1999 or modification of the
current carbon pricing approach under the Greenhouse Gas Pollution Pricing Act.
• Technology risks
Our success in executing our strategic plan, including adapting to the energy transition over time 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 lower-carbon energy infrastructure as well as modernization of our infrastructure to reduce
GHG emissions. Achieving our GHG emissions reduction 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 does not materialize as expected, making it more difficult to reduce
emissions.
• Market risks
Climate change concerns, increase in demand for lower-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 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.
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• 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 one of our strategic priorities is to adapt to the energy transition over
time. 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 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.
• Disclosure risks
Finally, we currently provide certain climate-related disclosures, and from time to time, we establish
and publicly announce goals and commitments to reduce our GHG emissions. These disclosures and
goals, and our progress towards these commitments, may be based on standards for measuring
progress that are still developing, internal controls and processes that continue to evolve, and
assumptions that are subject to change in the future. There can be no assurance that our current or
future disclosures and goals, the pathways by which we plan to reach our goals, or the methodologies
that we currently use to support our disclosures and progress towards our goals, will satisfy any new
and evolving regulations and legal requirements or expectations of our stakeholders, and the costs of
aligning our current disclosures and goals to any new legal requirements may be significant.
Additionally, if we fail to achieve or improperly report on our progress toward achieving our emissions
reduction goals and commitments, we may be subject to reputational harm, regulatory action, or other
legal action.
Companies across all sectors and industries are facing changing expectations or increasing scrutiny from
stakeholders related to their approach to ESG matters, including climate change and GHG emissions.
Companies in the energy industry are experiencing stakeholder opposition to new infrastructure, as well
as organized opposition to oil and natural gas extraction and shipment of oil and natural gas products.
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 adapting to the energy transition over time 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 lower-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.
RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS
Operation of complex energy infrastructure involves many hazards and risks that may adversely
affect our business, financial results and the environment.
These operational risks include adverse weather conditions, natural disasters, accidents, the breakdown
or failure of equipment or processes, and lower than expected levels of operating capacity and efficiency.
These operational risks could be catastrophic in nature.
Operational risk is also intensified by climate change. Climate change presents physical risks that may
affect the safety and reliability of our operations. These include acute physical risks, such as heavy
snowfall, heavy rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice
storms, and extreme temperatures, and chronic physical risks, such as long-term changes in precipitation
patterns, or sustained higher temperatures.
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Our assets and operations are exposed to potential damage or other negative impacts from these
operational risks, which could result in reduced revenue from business disruption or reduced capacity and
may also lead to increased costs due to repairs and required adaptation measures. Such events have led
to, could in the future lead to, rupture or release of product from our pipeline systems and facilities, or loss
of life or injury to people, which could result in substantial losses for which insurance may not be sufficient
or available and for which we may bear part or all of the cost.
An environmental incident is an event that may cause environmental harm and could lead to increased
operating and insurance costs, 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, security incident (cyber or physical), 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, and this has in the past and may again lead to claims against us. We have experienced,
and may again experience, service interruptions, restrictions or other operational constraints, 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 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 operating and insurance costs.
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Cyber attacks pose threats to our technology systems and could materially adversely affect our
business, operations, reputation 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, damage to our facilities or those of our customers, or releases of hydrocarbon products for
which we could be held liable, all of which could materially adversely affect our reputation, business,
operations or financial results. 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.
Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and
the increased sophistication of cyber attacks and data security breaches, as well as due to international
and domestic political factors including geopolitical tensions, armed hostilities, war, civil unrest, sabotage
and terrorism. Human error can also contribute to a cyber incident, and cyber attacks can be internal as
well as external and occur at any point in our supply chain. 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. Cyber threat actors have attacked and threatened to attack
energy infrastructure, and various government agencies have increasingly stressed that these attacks are
targeting critical infrastructure, and are increasing in sophistication, magnitude, and frequency. New
cybersecurity legislation, regulations and orders have been recently implemented or proposed resulting in
additional actual and anticipated regulatory oversight and compliance requirements, which will require
significant internal and external resources. We cannot predict the potential impact to our business of
potential future legislation, regulations or orders relating to cybersecurity.
We have been, and expect to continue to be, the target of cyber-attacks against which we have deployed,
and continue to deploy, security measures. Our information systems or those of our vendors or other
service providers are expected to become the target of further cyber attacks or security breaches which
could compromise our data and systems, affect our ability to correctly record, process and report
transactions, result in the loss of information, or cause operational disruption or incidents. As a result of a
cyber attack or security breach, we could also be liable under laws that protect the privacy of personal
information, be subject to regulatory action, fines or penalties, incur additional costs for remediation,
litigation, breach of contract or indemnity claims, or other costs, all of which could materially adversely
affect our reputation, business, operations or financial results.
In addition, a cyber attack could occur and persist for an extended period without detection. Any
investigation of a cyber attack or other security incident may be inherently unpredictable, and it would
take time before the completion of any investigation and availability of full and reliable information. During
such time, we may not know the extent of the harm or how best to remediate it, and certain errors or
actions could be repeated or compounded before they are discovered and remediated, all or any of which
could further increase the costs and consequences of a cyber attack or other security incident, and our
remediation efforts may not be successful. The inability to implement, maintain and upgrade adequate
safeguards could materially and adversely affect our results of operations, cash flows, and financial
condition. As cyber attacks continue to evolve, we may be required to expend significant additional
resources to continue to modify or enhance our protective measures or to investigate and remediate any
information security vulnerabilities.
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Furthermore, media reports about a cyber attack or other significant security incident affecting the
Company, whether accurate or not, or, under certain circumstances, our failure to make adequate or
timely disclosures to the public, law enforcement, other regulatory agencies or affected individuals
following any such event, whether due to delayed discovery or otherwise, could negatively impact our
operating results and result in other negative consequences, including damage to our reputation or
competitiveness, harm to our relationships with customers, partners, suppliers and other third parties,
interruption to our management, remediation or increased protection costs, significant litigation or
regulatory action, fines or penalties, all of which could materially adversely affect our business,
operations, reputation or financial results.
Pandemics, epidemics or infectious 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 infectious disease outbreaks could materially adversely
affect our business, operations, financial results and forward-looking expectations. Governments'
emergency measures to combat the spread could include restrictions on business activity and travel, as
well as requirements to isolate or quarantine. The duration and magnitude of such impacts will depend on
many factors that we may not be able to accurately predict. COVID-19 and government responses
interrupted business activities and supply chains, disrupted travel, and contributed to significant volatility
in the financial and commodity markets.
Disruptions related to pandemics, epidemics or infectious disease outbreaks could have the effect of
heightening many of the other risks described in this Item 1A. Risk Factors.
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,
armed hostilities, war, sabotage, or 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 critical infrastructure targets, such as energy-related
assets, are at greater risk of cyber attack and may be at greater risk of other future attacks than other
targets in the US and Canada. The Company’s infrastructure and projects under construction could be
direct targets or indirect casualties of a cyber or physical attack. In addition, increased environmental
activism against pipeline construction and operation could potentially result in work delays, reduced
demand for our products and services, new legislation or public policy or increased stringency thereof, or
denial or delay of permits and rights-of-way.
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.
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With respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue
to change due to shifts in regional and global 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.
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. 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 causes our inspection,
maintenance or repair costs to increase.
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 and construction techniques, some assets require more frequent inspections, which has
resulted in and is expected to continue to 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.
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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.
Our Liquids Pipelines business faces competition from competing carriers available to ship liquid
hydrocarbons to markets in Canada, the US and internationally and from proposed pipelines that seek to
access basins and 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. The liquids transported in our pipelines
currently, or are expected to increasingly, compete with other emerging alternatives for end-users,
including, but not limited to, electric batteries, biofuels, and hydrogen. Additionally, we 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 also competes with other forms of energy available to our
customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Our
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.
Completion of our secured projects and maintenance programs are subject to various regulatory,
operational and market risks, which may affect our ability to drive long-term growth.
Our project execution continues to face challenges with intense scrutiny on regulatory and environmental
permit applications, politicized permitting, public opposition including protests, action to repeal permits,
and resistance to land access.
Continued challenges with global supply chains have created unpredictability in materials cost and
availability. Labor shortages and union strikes have increased costs of engineering and construction
services.
Other events that can and have delayed project completion and increased anticipated costs include
contractor or supplier non-performance, extreme weather events or geological factors beyond our control.
Changing expectations of stakeholders regarding ESG practices and climate change could erode
stakeholder trust and confidence, 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, GHG emissions, safety and stakeholder and
Indigenous relations remain primary focus areas, while other environmental elements such as biodiversity
and supply chain are ascendant. Companies in the energy industry are experiencing stakeholder
opposition to new and existing infrastructure, as well as organized opposition to oil and natural gas
extraction and shipment of oil and natural gas products. Changing expectations of our practices and
performance across these ESG areas may impose additional costs or create exposure to new or
additional risks. We are also exposed to the risk of higher costs, delays, project cancellations, loss of
ability to secure new growth opportunities, new restrictions or the cessation of operations of existing
pipelines due to increasing pressure on governments and regulators, and legal action, such as the legal
challenges to the operation of Line 5 in Michigan and Wisconsin.
Our operations, projects and growth opportunities require us to have strong relationships with key
stakeholders, including local communities, Indigenous groups and others directly impacted by our
activities, as well as governments, regulatory agencies, investors and investor advocacy groups,
investment funds, financial institutions, insurers and others, which are increasingly focused on ESG
practices and performance.
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Enhanced public awareness of climate change has driven an increase in demand for lower-carbon and
zero-emissions energy. Over the past year, the invasion of Ukraine and inflationary pressure following the
COVID-19 pandemic have underscored the critical need for access to secure affordable energy. Enbridge
has a long history of diversifying its portfolio of businesses to align with the mix of energy that people
need and want. The pace and scale of the transition to a lower-emission economy may pose a risk if
Enbridge diversifies either too quickly or too slowly. Similarly, unexpected shifts in energy demands,
including due to climate change concerns, can impact revenue through reduced throughput volumes on
our pipeline transportation systems.
We have long been committed to strong ESG practices, performance and reporting, and in 2020
introduced a set of ESG goals to strengthen transparency and accountability. The goals include
increasing diversity and inclusion within our organization and reducing GHG 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. The costs associated with meeting our ESG goals,
including 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 our ESG goals may fail to materialize, may cost
more than anticipated to achieve, may not occur within the anticipated time periods or may no longer
meet changing stakeholder expectations. Similarly, there is a risk that emissions reduction technologies
do not materialize as expected making it more difficult to reduce emissions. If we are not able to achieve
our ESG goals, are not able to meet current and future climate, emissions or related reporting
requirements of regulators, or are unable to meet or manage current and future expectations regarding
issues important to investors or other stakeholders (including those related to climate change), it could
erode stakeholder trust and confidence, which could negatively impact our reputation, business,
operations or financial results. Potential impacts could also include changing investor sentiment regarding
investment in Enbridge or impair our access to and increase our cost of capital, including penalties
associated with our sustainability-linked financing.
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 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 systems.
Our insurance coverage may not fully cover our losses in the event of an accident, natural
disaster or other hazardous event, and we may encounter increased cost arising from the
maintenance of, or lack of availability of, insurance.
Our operations are subject to many hazards inherent in our industry. Our assets may experience physical
damage as a result of an accident or natural disaster. These hazards can also cause, 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 an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a
certain portion of our risks. However, not all potential risks arising from our operations are insurable, or
are insured by us as a result of availability, high premiums and for various other reasons. The Company
self-insures a significant portion of certain risks through our wholly-owned captive insurance subsidiaries,
and the Company’s insurance coverage is subject to terms and conditions, exclusions and large
deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances.
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The Company’s insurance policies are generally renewed on an annual basis and, depending on factors
such as market conditions, the premiums, terms, policy limits and/or deductibles can vary substantially.
We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on
other terms we consider commercially reasonable. In such case, we may decide to self-insure additional
risks.
A significant self-insured loss, uninsured loss, a loss significantly exceeding the limits of our insurance
policies, a significant delay in the payment of a major insurance claim, or the failure to renew insurance
policies on similar or favorable terms could materially and adversely affect our business, financial
condition and results of operations.
We are exposed to the credit risk of our customers, counterparties, and vendors.
We are exposed to the credit risk of multiple parties 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 the creditworthiness of our
customers, vendors, or counterparties. It is possible that payment or performance defaults from these
entities, if significant, could adversely affect our earnings and cash flows.
Our business is exposed to changes in market prices including interest rates and foreign
exchange rates. Our risk management policies cannot eliminate all risks and may result in
material financial losses. In addition, any non-compliance with our risk management policies
could adversely affect our business, operations or financial results.
Our use of debt financing exposes us to changes in interest rates on both future fixed rate debt issuances
and floating rate debt. While our financial results are denominated in Canadian dollars, many of our
businesses have foreign currency revenues or expenses, particularly the US dollar. Changes in interest
rates and foreign exchange rates could materially impact our financial results.
We use financial derivatives to manage risks associated with changes in foreign exchange rates, interest
rates, commodity prices, power prices and our share price to reduce volatility of our cash flows. Based on
our risk management policies, substantially 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.
In addition, to the extent that we hedge our foreign exchange rates, interest rates or commodity prices, we
will forego the benefits we would otherwise experience if these were to change in our favor. In addition,
hedging activities can result in losses that might be material to our financial condition, results of
operations and cash flows. Such losses have occurred in the past and could occur in the future. See Part
II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Financial Statements
and Supplementary Data for a discussion of our derivative instruments and related hedging activities.
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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, other professionals and executive officers and senior
management. 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 Liquids Pipelines growth rate and results may be directly and indirectly affected by
commodity prices and government policy.
Effective December 31, 2021, the Government of Alberta lifted the oil production curtailment that was
imposed in December 2018. 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.
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 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. To a lesser degree, the
financial results of our US Transmission business are subject to fluctuation in power prices which impact
electric power costs associated with operating compressor stations.
Energy Services generates margin by capitalizing on quality, time and location differentials when
opportunities arise. Changing market conditions that impact the prices at which we buy and sell
commodities have in the past limited margin opportunities and impeded Energy Services' ability to cover
capacity commitments and could do so again in the future. Other market conditions, such as
backwardation, have likewise limited margin opportunities.
We rely on access to short-term and long-term capital markets to finance capital requirements and
support liquidity needs. 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 refinance investments
originally financed with 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.
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We maintain revolving credit facilities at various entities to backstop commercial paper programs, for
borrowings and for providing letters of credit. These facilities typically include financial covenants and
failure to maintain these covenants at a particular entity could preclude that entity from accessing the
credit facility, which could impact liquidity. 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.
Recently, interest rates have increased significantly. If we are not able to access capital at competitive
rates or at all, our ability to finance operations and implement our strategy may be affected. An inability to
access capital on favorable terms or at all may limit our ability to pursue enhancements or acquisitions
that we may otherwise rely on for future growth or to refinance our existing indebtedness. 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 permitting and environmental review for
energy infrastructure companies in Canada and the US continues to evolve.
Within the US and in Canada, pipeline companies continue to face opposition from anti-energy/anti-
pipeline activists, Indigenous and tribal groups and communities, citizens, environmental groups, and
politicians concerned with either the safety of pipelines or their potential environmental effects. In the US,
the Environmental Protection Agency redefined the Waters of the United States under Section 401 of the
Clean Water Act, and the FERC released draft policy statements on the Certification of New Interstate
Natural Gas Facilities and the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure
Project Review that could introduce changes to the regulatory approval process for natural gas
infrastructure. The Council for Environmental Quality published immediately applicable guidance for
conducting analyses under the National Environmental Policy Act that may significantly change
environmental scope and cost assessments. Many other regulations adopted during the previous US
presidential administration are being challenged in multiple courts and some have been overturned by
reviewing courts. The current US administration may take further action to modify or reverse regulations
that were promulgated by the previous US administration.
In March of 2023, the Supreme Court of Canada will hear the Attorney General of Canada’s appeal of the
Alberta Court of Appeal’s non-binding decision that the federal Impact Assessment Act (“IAA”) is
unconstitutional. The IAA includes impact assessment requirements that could apply to either federally or
provincially regulated pipeline projects that fall within prescribed criteria or that the federal Minister of
Environment otherwise designates for review. The potential for any pipeline project to be subject to IAA
requirements adds significant uncertainty as to regulatory timelines and outcomes. The Alberta Court of
Appeal found that the IAA is an impermissible federal overreach into provincial jurisdiction that would
amount to a de facto expropriation of provincial natural resources and proprietary interests by the federal
government. The Supreme Court of Canada will determine whether the IAA and the related Physical
Activities Regulations are within the constitutional legislative authority of the Parliament of Canada, the
outcome of which could impact the applicability of the legislation to provincially regulated pipeline
projects.
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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 significant 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 and climate laws and regulations,
including those relating to climate change and GHG emissions and climate-related disclosure,
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 past,
current, and future operations, including air emissions, water quality, wastewater discharges, solid waste
and hazardous waste.
If we are unable to obtain or maintain all required environmental regulatory approvals and permits for our
operating assets and projects or if there is a delay in obtaining any required environmental regulatory
approvals or permits, the operation of existing facilities or the development of new facilities could be
prevented, delayed, or become subject to additional costs. Failure to comply with environmental laws and
regulations may result in the imposition of civil or criminal fines, penalties and injunctive measures
affecting our operating assets. We expect that changes in environmental laws and 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 for utilization of our pipelines or other facilities.
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,
permits, 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. We have experienced litigation in relation to certain Line 5
easements; refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Legal and Other Updates.
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Regulatory 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.
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, gas transmission and distribution assets are
subject to the actions of various regulators, including the CER, the FERC, and the OEB with respect to
the rates, tariffs, and tolls for these assets. 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 the Mainline
Commercial Framework, could have an adverse effect on our revenues and earnings.
Our Renewable Power Generation assets in Europe (France, Germany and the UK) are also subject to
the directives, regulations and policies established and enforced by the EU and the UK government.
These measures are variable and can include price controls, caps and demand reduction goals, all of
which can have a negative impact on our revenues and earnings.
We are 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, Canada has introduced interest deductibility rules, the US enacted the
Inflation Reduction Act and we are anticipating 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.
55
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, or by other legal
proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual
matters with assurance. It is reasonably possible that the final resolution of some of the matters in which
we are involved or new matters 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.
ITEM 2. PROPERTIES
Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are
included in Part I. 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 regulatory actions and proceedings which arise in the ordinary
course of business. While the final outcome of such actions and proceedings cannot be predicted with
certainty, management believes that the resolution of such actions and proceedings will not have a
material impact on our consolidated financial position or results of operations. 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.
56
On October 17, 2022, four separate comprehensive enforcement resolutions were announced with the
Minnesota Pollution Control Agency, Minnesota Department of Natural Resources (DNR), Fond du Lac
Band of Lake Superior Chippewa, and Minnesota Attorney General’s Office related to alleged violations
that occurred during construction of Line 3 Replacement. As part of these agreements, together with the
DNR’s previous Administrative Penalty Order, Enbridge will provide the various entities a total of
approximately US$11 million, approximately US$7.5 million of which is to provide financial assurances
and fund multiple environmental and resource enhancement projects. The Minnesota Attorney General
has filed a misdemeanor criminal charge for the taking of water without a permit at the Clearbrook aquifer,
with this charge against us to be dismissed following one year of compliance with the state water
appropriation rules.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
57
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 3, 2023,
there were 76,001 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, 2022.
Recent Sales of Unregistered Equity Securities
None.
Issuer Purchases of Equity Securities
Period
October 2022
(October 1 - October 31)
November 2022
(November 1 - November 30)
December 2022
(December 1 - December 31)
Total number of
shares
purchased
Average price
paid per share
Total number of
shares purchased
as part of publicly
announced plans or
programs
Maximum number
of shares that may
yet be purchased
under the plans or
programs1
—
—
—
N/A
N/A
N/A
—
—
—
28,324,366
28,324,366
28,324,366
1 On December 31, 2021, we announced that the TSX approved our prior 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. Our
prior NCIB commenced on January 5, 2022 and expired on January 4, 2023. On January 4, 2023, we announced that the TSX
had approved our new NCIB, which commenced on January 6, 2023 and continues until January 5, 2024. Under the new NCIB,
Enbridge may purchase, for cancellation, up to 27,938,163 of its outstanding common shares to an aggregate amount of up to
$1.5 billion. Purchases may be made through the facilities of the TSX, the NYSE and other designated exchanges and alternative
trading systems.
58
Total Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 2018 through
December 31, 2022 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, by stock symbols,
CNP, D, DTE, DUK, EPD, ET, KMI, MMP, NEE, NI, OKE, PAA, PCG, SO, SRE and WMB) and (5) our
Canadian peer group (comprising, by stock symbols, CU, FTS, PPL and TRP). The amounts included in
the table were calculated assuming the reinvestment of dividends.
Enbridge Inc.
S&P/TSX Composite
S&P 500 Index
US Peers1
Canadian Peers
January 1,
2018
100.00
100.00
100.00
100.00
100.00
December 31,
2018
91.90
91.11
95.62
94.80
92.00
2019
118.86
111.96
125.72
114.97
120.56
2020
100.80
118.23
148.85
98.40
99.72
2021
131.30
147.89
191.58
121.17
124.49
2022
149.54
139.25
156.88
134.17
129.22
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]
59
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 2022 and 2021 items and year-over-year
comparisons between 2022 and 2021. For discussion of 2020 items and year-over-year comparisons
between 2021 and 2020, 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, 2021.
RECENT DEVELOPMENTS
Chair of the Board and CEO Appointments
Pamela L. Carter was appointed Chair of the Board of Directors (the Board) effective January 1, 2023.
Gregory L. Ebel was appointed as President and Chief Executive Officer (CEO) effective the same date.
Mr. Ebel succeeds retiring President and CEO, Al Monaco. To support Mr. Ebel through the transition, Mr.
Monaco will serve as an advisor until June 30, 2023. Mr. Ebel will continue as a member of the Board.
Ms. Carter has served as a director of the Board since 2017 and with Spectra Energy Corp since 2007.
Most recently she has served as Chair of the Human Resources & Compensation Committee of the
Board, as a member of the Sustainability and Safety & Reliability Committees and as a former Chair of
the Governance Committee.
ASSET TRANSACTIONS
Joint Venture Merger Transaction to Advance US Gulf Coast Oil Strategy
On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 (P66) resulting in a
single joint venture, DCP Midstream LLC, holding both Enbridge Inc.'s (Enbridge) and P66's indirect
ownership interests in Gray Oak Pipeline, LLC (Gray Oak) and DCP Midstream, LP (DCP), as well as an
agreement to realign our respective economic and governance interests in the underlying business
operations. Our effective economic interest in Gray Oak has increased to 58.5% from 22.8%, and we will
assume operatorship of Gray Oak in the second quarter of 2023. Simultaneously, our effective economic
interest in DCP has been reduced to 13.2% from 28.3%. We received approximately $522 million
(US$404 million) in cash proceeds and recorded an accounting gain of approximately $1.1 billion
(US$832 million) in the Consolidated Statements of Earnings as a result of the transaction.
Acquisition of Tri Global Energy, LLC
On September 27, 2022, we acquired Tri Global Energy, LLC (TGE), a leading United States (US)
renewable power project developer, for approximately US$270 million in cash and assumed debt. The
acquisition of TGE enhances our renewable power platform and further builds on our inventory of North
American growth opportunities for wind and solar projects.
Athabasca Indigenous Investments Partnership
On October 5, 2022, we completed a transaction with Athabasca Indigenous Investments Limited
Partnership (Aii), a newly created entity representing 23 First Nation and Métis communities, in which Aii
acquired an 11.6% non-operating interest in seven Regional Oil Sands pipelines in northern Alberta for
$1.1 billion.
60
Increased Ownership in Cactus II Pipeline
On November 2, 2022, we acquired an additional 10.0% ownership in Cactus II Pipeline from Western
Midstream Partners, L.P., for cash payment of $241 million (US$177 million), bringing our total non-
operating ownership to 30.0%. Plains All-American Pipeline, L.P. remains the operator with a 70%
ownership stake.
Woodfibre LNG Limited Partnership Agreement
On November 29, 2022, we finalized our partnership agreement with Pacific Energy Corporation Limited.
We acquired, for cash payment of $533 million (US$392 million), an effective 30.0% interest in Woodfibre
LNG Limited Partnership (Woodfibre), which will operate the 2.1 million tonnes per annum Woodfibre LNG
facility located in Squamish, British Columbia (BC). The facility, via an interconnect with FortisBC Energy
Inc., is an extension of the BC Pipeline System, which will supply gas to the facility under a 40-year
transportation agreement.
GAS TRANSMISSION AND MIDSTREAM PROCEEDINGS
Texas Eastern Transmission
Texas Eastern Transmission, LP (Texas Eastern) filed two rate cases in the third quarter of 2021. These
two rate proceedings have since been consolidated and settlement negotiations began during the first
quarter of 2022. An uncontested settlement in principle was reached on July 7, 2022. Texas Eastern filed
an uncontested Stipulation and Agreement on September 8, 2022 to resolve all issues from the rate
proceedings. The Federal Energy Regulatory Commission (FERC) approved the Stipulation and
Agreement on November 30, 2022, and the Stipulation and Agreement became effective on January 1,
2023.
Maritimes & Northeast Pipeline
The toll settlement agreement for the Canadian portion of our Maritimes & Northeast (M&N Canada)
Pipeline system expired in December 2021. In December 2021, the Canada Energy Regulator (CER)
approved interim tolls for M&N Canada effective January 1, 2022, which were based on the negotiated
2022 tolls in the 2022-2023 settlement agreement and unanimously supported by shippers. The
2022-2023 M&N Canada settlement agreement was approved by the CER in February 2022.
British Columbia Pipeline
The toll settlement agreement for our BC Pipeline system expired in December 2021. In December 2021,
the CER approved interim tolls for BC Pipeline effective January 1, 2022. In the fourth quarter of 2022, a
five-year 2022-2026 BC Pipeline settlement agreement was approved by shippers and subsequently
approved as filed by the CER.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
2022 Rate Application
Enbridge Gas Inc.'s (Enbridge Gas) rate applications are filed in two phases. In June 2021, Enbridge Gas
filed Phase 1 of the application with the Ontario Energy Board (OEB) for the setting of rates for 2022 (the
2022 Application). The 2022 Application was filed in accordance with the parameters of Enbridge Gas'
OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism and 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. In April 2022, the OEB issued its decision on Phase 2 of the 2022
Application filed in October 2021, addressing incremental capital module (ICM) funding requirements,
under which $127 million of the requested capital funding was approved and incorporated into final rates,
effective July 1, 2022.
61
2023 Rate Application
In June 2022, Enbridge Gas filed Phase 1 of the application with the OEB for the setting of rates for 2023
(the 2023 Application). The 2023 Application was filed in accordance with the parameters of Enbridge
Gas' OEB approved Price Cap IR rate setting mechanism and represents the final year of a five-year
term. In November 2022, the OEB approved the Phase 1 Settlement Proposal and Final Rate Order
effective January 1, 2023. In addition, Enbridge Gas did not anticipate 2023 capital investments to require
incremental funding during the final year of its current Price Cap IR term, and, as such, Enbridge Gas did
not make a Phase 2 ICM request as part of the 2023 Application.
2024 Rebasing and Incentive Rate-Setting Mechanism Application
In October 2022, Enbridge Gas filed its application with the OEB to establish a 2024 through 2028 rate
setting framework. The application and framework seek approval to establish 2024 base rates on a cost-
of-service basis and to establish a price cap IR rate setting mechanism to be used for the remainder of
the IR term (2025-2028). The OEB has determined it will hear the application in two phases, with Phase 1
addressing items that affect rates effective January 1, 2024, and Phase 2 addressing items that will affect
rates subsequent to January 1, 2024. An OEB decision is expected on Phase 1 of the application in the
second half of 2023.
Purchase Gas Variance
The Purchase Gas Variance Account (PGVA) captures the difference between actual and forecasted
natural gas prices reflected in rates. Account balances are typically recovered or refunded over a
prospective 12-month period through Quarterly Rate Adjustment Mechanism (QRAM) applications.
In March and June 2022, the OEB approved Enbridge Gas' April 1, 2022 and July 1, 2022 QRAM
applications, respectively. Due to the significant increase in natural gas prices, the approvals have also
included rate mitigation plans intended to ease bill impacts to ratepayers. Specifically, the approved rate
mitigation plans extended the PGVA recovery period from 12 months to 24 months in both applications.
As an additional mitigation measure, as part of the April 1, 2022 QRAM, a portion of the PGVA balance
was deferred for recovery, which was subsequently approved for recovery as part of the July 1, 2022
QRAM. In September and December 2022, the October 1, 2022 and January 1, 2023 QRAM applications
were filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and did
not include any additional rate mitigation measures.
As at December 31, 2022, Enbridge Gas' PGVA receivable balance was $434 million.
FINANCING UPDATE
We completed long-term debt issuances totaling US$3.2 billion and $3.4 billion during the year ended
December 31, 2022, including $900 million of 10-year sustainability-linked medium-term notes in
November 2022. We increased our credit facilities during our annual renewal process by approximately
$640 million and also entered into new term loans with maturities ranging from 2023 to 2027 totaling
approximately $3.2 billion.
Our 2022 financing activities have provided 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 be unattractive. Refer to Liquidity and Capital Resources.
As at December 31, 2022, after adjusting for the impact of floating-to-fixed interest rate swap hedges,
approximately 6% of our total debt is exposed to floating rates. Refer to Part II. Item 8. Financial
Statements and Supplementary Data - Note 24. Risk Management and Financial Instruments for more
information on our interest rate hedging program.
62
NORMAL COURSE ISSUER BID
On January 4, 2023, we announced that the Toronto Stock Exchange (TSX) had approved our new
normal course issuer bid (NCIB) to purchase for cancellation up to 27,938,163 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. The NCIB follows on the
termination of our prior NCIB, which expired on January 4, 2023.
Purchases under the NCIB may be made through the facilities of the TSX, the New York Stock Exchange
and other designated exchanges and alternative trading systems commencing on January 6, 2023 and
continuing until January 5, 2024, when the NCIB expires, or such earlier date on which Enbridge has
either acquired the maximum number of common shares allowable under the NCIB or otherwise decided
not to make any further repurchases under the NCIB. The maximum number of common shares that
Enbridge may purchase for cancellation under the NCIB represents approximately 1.38% of the
2,024,890,423 common shares issued and outstanding as at December 23, 2022.
RESULTS OF OPERATIONS
Year ended December 31,
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) 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)/loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Preference share dividends
Earnings attributable to common shareholders
Earnings per common share attributable to common shareholders
Diluted earnings per common share attributable to common
shareholders
1 Non-GAAP financial measures.
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
2022
2021
2020
8,364
3,126
1,827
262
(417)
(1,124)
7,897
3,671
2,117
508
(313)
356
7,683
1,087
1,748
523
(236)
(113)
12,038
(4,317)
(3,179)
(1,604)
14,236
(3,852)
(2,655)
(1,415)
10,692
(3,712)
(2,790)
(774)
65
(414)
2,589
1.28
(125)
(373)
5,816
2.87
(53)
(380)
2,983
1.48
1.28
2.87
1.48
Year ended December 31, 2022 compared with year ended December 31, 2021
Earnings attributable to common shareholders decreased by $3,368 million due to certain infrequent or
other non-operating factors, primarily explained by the following:
• a goodwill impairment of $2.5 billion relating to our Gas Transmission reporting unit;
• non-cash, net unrealized derivative fair value losses of $1,265 million ($964 million after-tax) in 2022,
compared with unrealized gains of $197 million ($150 million after-tax) in 2021, reflecting changes in
the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;
• an asset impairment loss of $227 million ($173 million after-tax) to our Magic Valley Wind Farm
(Magic Valley);
63
• an asset impairment loss of $183 million ($137 million after-tax) on the US and Canadian components
of the interstate pipeline transportation system within the North Dakota System of our Bakken
System;
• a transaction cost of $114 million in relation to our investment purchase in the Woodfibre LNG project;
• an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans;
• an asset impairment loss of $40 million ($30 million after-tax) relating to MacKay River line within our
Alberta Regional Oil Sands System;
• the absence in 2022 of a gain of $303 million ($298 million after-tax) from the sale of our investment
in Noverco Inc. (Noverco); and
• the absence in 2022 of a $57 million ($43 million after-tax) property tax settlement received in 2021
related to the resolution of Minnesota property tax appeals for 2012-2018.
The factors above were partially offset by:
• a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction
with P66 realigning our effective economic interests in Gray Oak and DCP;
• a gain of $118 million ($89 million after-tax) on Texas Eastern recorded to reflect a settlement with a
transportation customer undergoing bankruptcy;
• a deferred tax benefit of $95 million recognized as a result of the reduced Pennsylvania state
corporate income tax;
• a non-cash, net negative equity earnings adjustment of $10 million ($7 million after-tax) in 2022,
compared to a net negative adjustment of $44 million ($33 million after-tax) in 2021 relating to our
share of changes in the mark-to-market value of derivative financial instruments of our equity method
investee, DCP;
• transition and transformation costs of $66 million ($50 million after-tax) in 2022, compared to $147
million ($112 million after-tax) in 2021; and
• the absence in 2022 of an impairment loss of $111 million ($83 million after-tax) to our investment in
the PennEast Pipeline Company, LLC (PennEast) pipeline project.
The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a
result of our comprehensive economic hedging program to mitigate 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 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 $141 million increase in earnings
attributable to common shareholders is primarily explained by the following significant business factors:
• higher throughput within our Liquids Pipelines segment driven by higher demand and incremental
Line 3 Replacement (L3R) capacity that came into service October 2021;
• increased earnings within our Liquids Pipelines segment from the implementation of the full L3R
surcharge when compared to the lower surcharge on the Canadian portion of the project in effect
prior to October 2021, as well as from new US export assets acquired in October 2021;
• increased earnings from our Gas Transmission and Midstream segment primarily as a result of higher
commodity prices benefiting our investments in DCP and Aux Sable, as well as higher contributions
from projects placed into service in November 2021; and
• recognition of revenues attributable to the Texas Eastern rate case resulting from a FERC-approved
Stipulation and Agreement; partially offset by
• the recognition of a provision against the interim Mainline International Joint Tariff (IJT) for barrels
shipped for the full year in 2022, as compared to the barrels shipped in the second half of 2021
following the expiry of the Competitive Toll Settlement (CTS);
64
• higher interest expense primarily due to higher interest rates and higher average principal, as well as
reduced capitalized interest associated with the US portion of the L3R Project placed into service in
the fourth quarter of 2021;
• higher depreciation and amortization expense as a result of several projects placed into service in the
fourth quarter of 2021, as well as for new US export assets acquired in October 2021; and
• higher income tax expense due to higher earnings, higher US minimum taxes, and the effect of rate-
regulated accounting for income taxes.
REVENUES
We generate revenues from three primary sources: transportation and other services, gas distribution
sales and commodity sales.
Transportation and other services revenues of $18.5 billion, $16.2 billion and $16.2 billion for the years
ended December 31, 2022, 2021 and 2020, 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 $5.7 billion, $4.0 billion and $3.7 billion for the years ended
December 31, 2022, 2021 and 2020, 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 $29.2 billion, $26.9 billion and $19.3 billion for the years ended
December 31, 2022, 2021 and 2020, 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 (NGL) 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.
65
BUSINESS SEGMENTS
LIQUIDS PIPELINES
Year ended December 31,
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2022
2021
2020
8,364
7,897
7,683
Year ended December 31, 2022 compared with year ended December 31, 2021
EBITDA was negatively impacted by $710 million due to certain infrequent or other non-operating factors,
primarily explained by the following:
• non-cash, net unrealized losses of $183 million in 2022, compared with unrealized gains of $120
million in 2021, 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;
• total asset impairment loss of $183 million on the US and Canadian components of the interstate
pipeline transportation system within the North Dakota System of our Bakken System;
• an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil
Sands System; and
• the absence in 2022 of a $57 million property tax settlement received in 2021 related to the resolution
of Minnesota property tax appeals for 2012-2018.
After taking into consideration the factors above, the remaining $1.2 billion increase is primarily explained
by the following significant business factors:
• higher Mainline System ex-Gretna average throughput of 3.0 million barrels per day (mmbpd) in 2022
as compared to 2.8 mmbpd in 2021 driven by higher demand and incremental L3R capacity that
came into service October 2021;
• implementation of the full L3R surcharge when compared to the lower surcharge on the Canadian
portion of the project in effect prior to October 2021;
• higher contributions from the Gulf Coast and Mid-Continent System due primarily to the acquisition of
the Enbridge Ingleside Energy Center and related assets in the fourth quarter of 2021 in addition to
the increased effective economic interest in the Gray Oak pipeline during the third quarter of 2022
and higher volumes from Flanagan South Pipeline;
• higher contributions from the Bakken System due to higher volumes; and
• the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2022
compared to the same period in 2021; partially offset by
• the recognition of a provision against the interim Mainline IJT for barrels shipped for the full year in
2022, as compared to the barrels shipped in the second half of 2021 following the expiry of the CTS;
• lower contributions from the Seaway Crude Pipeline System, as well as from the Cushing and
Hardisty storage assets as a result of lower demand; and
• higher power costs as a result of increased volumes and power prices.
66
GAS TRANSMISSION AND MIDSTREAM
Year ended December 31,
2022
2021
2020
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
3,126
3,671
1,087
Year ended December 31, 2022 compared with year ended December 31, 2021
EBITDA was negatively impacted by $1.1 billion due to certain infrequent or other non-operating factors
primarily explained by the following:
• a goodwill impairment of $2.5 billion; partially offset by
• a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our
effective economic interests in Gray Oak and DCP;
• the absence of the $111 million impairment loss in 2021 to our investment in the PennEast pipeline
project after a decision by project partners to cease development;
• a gain of $118 million on Texas Eastern recorded for a customer bankruptcy settlement; and
• a non-cash, net negative equity earnings adjustment of $10 million in 2022, compared to a net
negative adjustment of $44 million in 2021 relating to our share of changes in the mark-to-market
value of derivative financial instruments of our equity method investees, DCP and Aux Sable.
After taking into consideration the factors above, we saw a $567 million increase, primarily explained by
the following significant business factors:
• higher commodity prices benefiting our DCP and Aux Sable joint ventures;
• the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2022
compared to the same period in 2021;
• recognition of revenues attributable to the Texas Eastern rate case resulting from a FERC-approved
Stipulation and Agreement;
• contributions from the T-South and Spruce Ridge expansion projects, the Cameron and Middlesex
Extension projects, and the Appalachia to Market project after service commenced in the fourth
quarter of 2021;
• higher AECO-Chicago basis differential and lower costs benefiting earnings from our investment in
Alliance; and
• recognition of revenues attributable to the BC Pipeline rate settlement; partially offset by
• higher operating costs; and
• a reduction in earnings from our investment in DCP as a result of our decreased effective economic
interest due to the joint venture merger transaction with P66 that closed during the third quarter of
2022.
GAS DISTRIBUTION AND STORAGE
Year ended December 31,
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2022
2021
2020
1,827
2,117
1,748
Year ended December 31, 2022 compared with year ended December 31, 2021
EBITDA was negatively impacted by $293 million due to certain infrequent or other non-operating factors
primarily explained by the absence of a gain of $303 million resulting from the sale of our investment in
Noverco in 2021.
67
After taking into consideration the factors above, the remaining $3 million increase is primarily explained
by the following significant business factors:
• higher distribution charges at Enbridge Gas resulting from increases in rates and customer base, as
well as higher demand in the contract market;
• when compared with the normal weather forecast embedded in rates, colder than normal weather in
2022 positively impacted Enbridge Gas 2022 EBITDA by approximately $17 million while warmer than
normal weather in 2021 negatively impacted 2021 EBITDA by approximately $55 million; and
• lower pension related costs; partially offset by
• the absence of earnings from Noverco due to the sale of our minority investment in December 2021;
and
• higher operating costs at Enbridge Gas largely driven by higher employee costs and higher
maintenance and integrity spend.
RENEWABLE POWER GENERATION
Year ended December 31,
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2022
2021
2020
262
508
523
Year ended December 31, 2022 compared with year ended December 31, 2021
EBITDA was negatively impacted by $272 million due to certain infrequent or non-operating factors,
primarily explained by an impairment loss of $227 million to Magic Valley.
After taking into consideration the negative factor above, the remaining $26 million increase is primarily
explained by the following significant business factors:
• higher energy pricing at European offshore wind facilities;
• stronger wind resources at Canadian and US onshore wind facilities; and
• the absence in 2022 of the adverse effects from the major winter storm in Texas during February
2021; partially offset by
• the absence in 2022 of a promote fee received in the first quarter of 2021 associated with the closing
of the sale of 49% of our interest in three European offshore wind projects to Canada Pension Plan
Investment Board.
ENERGY SERVICES
Year ended December 31,
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2022
2021
2020
(417)
(313)
(236)
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, 2022 compared with year ended December 31, 2021
EBITDA was negatively impacted by $100 million due to certain non-operating factors, primarily explained
by non-cash, unrealized losses of $27 million in 2022, compared with unrealized gains of $53 million in
2021, reflecting the revaluation of derivatives used to manage the profitability of transportation and
storage transactions, as well as to manage the exposure to movements in commodity prices.
68
After taking into consideration the factor above, the remaining $4 million decrease is primarily explained
by the following significant business factors:
• more pronounced market structure backwardation than in 2021 and significant compression of
location differentials in certain markets; partially offset by
• the absence of adverse impacts from the major winter storm experienced across the US Midwest
during February 2021.
ELIMINATIONS AND OTHER
Year ended December 31,
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and
amortization1
1 Non-GAAP financial measure.
2022
2021
2020
(1,124)
356
(113)
Eliminations and Other includes operating and administrative costs that are not allocated to business
segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned
captive insurance subsidiaries. Eliminations and Other also includes the impact of new business
development activities and corporate investments.
Year ended December 31, 2022 compared with year ended December 31, 2021
EBITDA was negatively impacted by $1.2 billion due to certain infrequent or non-operating factors,
primarily explained by:
• non-cash, net unrealized losses of $1,090 million in 2022, compared with unrealized gains of $55
million in 2021, reflecting the change in the mark-to-market value of derivative financial instruments
used to manage foreign exchange risk;
• a transaction cost of $114 million in relation to our investment purchase in the Woodfibre LNG project;
and
• an impairment of $44 million for lease assets due to office relocation plans in Houston.
After taking into consideration the non-operating factors above, we saw a $239 million decrease in
EBITDA that is primarily explained by:
• the lower realized foreign exchange gains on hedge settlements in 2022; and
• higher Operating and administrative expense largely driven by an increase in employee costs.
69
GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our significant 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)
GAS TRANSMISSION AND MIDSTREAM
100 %
US$0.3 billion
US$0.2 billion
100 %
US$0.4 billion
100 %
US$0.4 billion
US$0.1 billion
No significant
expenditures to date
No significant
expenditures to date
No significant
expenditures to date
No significant
expenditures to date
Complete
Pre-
construction
Pre-
construction
Pre-
construction
Pre-
construction
Pre-
construction
In-service
2023 - 2024
2024 - 2025
2026
2027
2028
Vito Gas & Oil
Texas Eastern Venice
Extension Project
Texas Eastern
Modernization
1.
2.
3.
4.
T-North Expansion
100 %
$1.2 billion
5. Woodfibre LNG Project3
30 %
US$1.5 billion
T-South Expansion
6.
RENEWABLE POWER GENERATION
100 %
Saint-Nazaire France
Offshore Wind
Project4
Fécamp Offshore Wind
Project5
Calvados Offshore Wind
Project4
7.
8.
9.
25.5 %
17.9 %
21.7 %
$3.6 billion
$0.9 billion
(€0.6 billion)
$0.7 billion
(€0.5 billion)
$0.9 billion
(€0.6 billion)
$0.9 billion
(€0.6 billion)
$0.4 billion
(€0.3 billion)
$0.3 billion
(€0.2 billion)
Complete
Under
construction
Under
construction
In-service
2023
2025
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 and status of the project are determined as at December 31, 2022.
3 Our equity contribution is US$0.9 billion, with the remainder financed through non-recourse project level debt.
4 Our equity contribution is $0.2 billion for each project, with the remainder of each project financed through non-recourse project
level debt.
5 Our equity contribution is $0.1 billion, with the remainder 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.
GAS TRANSMISSION AND MIDSTREAM
The following commercially secured growth project was placed into service in 2022:
• Vito Gas & Oil – Two pipelines connecting Vito Floating Production System from Mississippi Canyon
to the Shell Mars System platform in West Delta 143 and Olympic Gas. Enbridge designed,
fabricated, installed, and now operates, the Vito Gas & Oil export pipeline system consisting of
pipeline and steel catenary riser.
70
The following commercially secured growth projects are currently in various stages of construction:
• 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 1.5 billion cubic feet per day (bcf/d) of natural gas to Venture Global Plaquemines LNG, LLC’s
LNG export facility located in Plaquemines Parish, Louisiana and is underpinned by long-term take or
pay contracts.
• Texas Eastern Modernization – 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.
• T-North Expansion – An expansion of Westcoast Energy Inc.'s (Westcoast) BC Pipeline in northern
BC that includes pipeline looping, additional compressor units and other ancillary station modifications
to support 535 million cubic feet per day (MMcf/d) of additional capacity. The project will be
underpinned by a cost-of-service commercial model with a target in-service date of 2026.
• Woodfibre LNG Project – Construction of liquefaction and floating storage facilities in Squamish,
BC, as well as an expansion of the BC Pipeline System. The project is expected to be placed into
service in 2027.
• T-South Expansion – An expansion of Westcoast's BC Pipeline's T-South section that includes
pipeline looping, additional compressor units and other ancillary station modifications to support 300
MMcf/d of additional capacity. The project is expected to be placed in service in 2028 and will be
underpinned by a cost-of-service commercial model.
RENEWABLE POWER GENERATION
The following commercially secured growth projects were placed into service in 2022:
• Saint-Nazaire Offshore Wind Project – A wind project located off the west coast of France that is
expected to generate approximately 480 megawatts (MW). Project revenues are backed by a 20-year
fixed price power purchase agreement (PPA) with added power production protection.
The following commercially secured growth projects are expected to be placed into service from 2023 to
2025:
• Fécamp Offshore Wind Project – An offshore wind project that will be comprised of 71 wind turbines
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 PPA.
71
OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
The following project has been announced by us, but has not yet met our criteria to be classified as
commercially secured:
GAS TRANSMISSION AND MIDSTREAM
• 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.
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, 2022, related to debt and leases.
Long-term contracts are contracts that we have signed for the purchase of services, pipe and other
materials totaling $7.9 billion which are expected to be paid over the next five years. Long-term contracts
primarily consists of the following purchase obligations: firm capacity payments for natural gas and crude
oil transportation and storage contracts, natural gas purchase commitments, 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 common equity.
72
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$3.2 billion and $3.4 billion in 2022:
Issuance date
Type of issuance
Entity
(in millions of Canadian dollars, unless stated otherwise)
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Inc.
Enbridge Gas Inc.
Texas Eastern Transmission LP December 2022 Senior notes
Fixed-to-fixed subordinated notes
January 2022
Floating rate senior notes
February 2022
February 2022
Senior notes
September 2022 Fixed-to-fixed subordinated notes
November 2022 Medium-term notes
November 2022 Sustainability-linked medium-term notes
Medium-term notes
August 2022
Amount
$750
US$600
US$900
US$1,100
$1,100
$900
$650
US$600
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,
inclusive of term loans, at December 31, 2022:
(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
2023-2027
2024-2027
2024
2024
10,987
8,604
2,000
2,000
23,591
7,984
4,199
312
2,000
14,495
3,003
4,405
1,688
—
9,096
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, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility,
extending the maturity date out to July 2025.
On May 17, 2022, we entered into a three year term loan with a syndicate of Japanese banks for
approximately $806 million (¥84.8 billion), which will mature in May 2025 and replaces the approximately
$499 million (¥52.5 billion) term loan that matured in May 2022. Additionally, on May 24, 2022, we entered
into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023.
On June 23, 2022, we renewed approximately $5.5 billion of our 364-day extendible credit facilities to
July 2024, which includes a one-year term out provision from July 2023.
In July and August 2022, we renewed $12.7 billion of our credit facilities, extending the maturity dates of
our 364-day credit facilities to July 2024, inclusive of a one year term out provision from July 2023, and
our five year facilities out to July 2027. As a part of the renewals, we increased our credit facilities by
approximately $640 million.
On December 16, 2022, Enbridge (U.S.) Inc. entered into a five year delay draw term loan in support of
solar self-power projects for approximately $479 million, which will mature in December 2027.
73
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand
letter of credit facilities, of which $689 million was unutilized as at December 31, 2022. As at December
31, 2021, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $854 million was
unutilized.
As at December 31, 2022, our net available liquidity totaled $10.0 billion (2021 - $6.5 billion), consisting of
available credit facilities of $9.1 billion (2021 - $6.2 billion) and unrestricted Cash and cash equivalents of
$861 million (2021 - $286 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, 2022, we were in compliance with all
debt covenants and expect to continue to comply with such covenants.
Cash flow growth, 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. In 2022, our credit ratings with DBRS
Morningstar, Fitch Ratings, Moody's Investor Services, Inc. and Standard & Poor's were all affirmed. 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.
There are no material restrictions on our cash. Total Restricted cash of $46 million, as reported in 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, 2022 and 2021, we had a negative
working capital position of $2.1 billion and $3.1 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.
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 change in cash and cash equivalents and restricted cash
2022
2021
2020
11,230
(5,270)
(5,428)
9,256
(10,657)
1,236
9,781
(5,177)
(4,770)
55
587
(5)
(170)
(20)
(186)
74
Significant sources and uses of cash for the years ended December 31, 2022 and 2021 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 29. Changes in Operating Assets and Liabilities.
Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or
other non-operating factors, as discussed under Results of Operations.
Investing Activities
Cash used in investing activities primarily relates to capital expenditures to execute our 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, 2022, 2021
and 2020 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
2022
2021
2020
1,418
1,647
1,499
50
—
33
4,647
4,051
2,353
1,343
16
1
54
7,818
2,032
2,066
1,134
81
2
90
5,405
2022
The decrease in cash used in investing activities primarily resulted from the following factors:
• lower capital expenditures due to the US L3R Program that was placed into service in the fourth
quarter of 2021;
• lower cash outflows related to acquisitions in 2022 when compared to 2021; and
• proceeds received from the completion of a joint venture merger transaction for DCP Midstream LLC
in August 2022.
The factors above were partially offset by:
• the absence in 2022 of proceeds received from dispositions in 2021 related to sale of our interest in
Noverco in December 2021; and
• increased investments held by our wholly-owned captive insurance subsidiaries.
2021
The increase in cash used in investing activities primarily resulted from our acquisition of Moda Midstream
Operating, LLC and higher capital expenditures related to the completion of the US L3R Program in 2021,
partially offset by higher proceeds received from dispositions in 2021 compared to 2020 due to the sale of
our interest in Noverco.
75
Financing Activities
Cash 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,
share redemptions and common share repurchases under our NCIB. Cash flow from financing activities is
also impacted by changes in distributions to, and contributions from, noncontrolling interests.
2022
The increase in cash used in financing activities primarily resulted from the following factors:
• net commercial paper and credit facility repayments in 2022 when compared to draws in 2021;
• higher long-term debt repayments along with lower long-term debt issuances in 2022 when compared
to 2021;
• the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022,
respectively;
• the repurchase and cancellation of 2,737,965 common shares under our NCIB for approximately
$151 million in 2022; and
• increased common share dividend payments primarily due to the increase in our common share
dividend rate.
The factors above were partially offset by:
• proceeds received from the sale of a non-operating interest in seven pipelines from our Regional Oil
Sands System in October 2022;
• the absence in 2022 of the redemption of Westcoast's preferred shares in the first quarter of 2021;
and
• higher short-term borrowings in 2022 when compared to 2021.
2021
The increase in cash provided by financing activities primarily resulted from 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 when compared to 2020.
The factors above were partially offset by the redemption of Westcoast's preferred shares in 2021 and
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 and can include financial guarantees, stand-by letters of credit, debt
guarantees, surety bonds and indemnifications. Please see Part II. Item 8. Financial Statements and
Supplementary Data - Note 32. Guarantees for further discussion of guarantee arrangements.
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, please refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 31.
Commitments and Contingencies and Note 12. Variable Interest Entities.
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, revenues or expenses, results of operations, liquidity,
capital expenditures or capital resources.
76
PREFERENCE SHARE ISSUANCES
Characteristics of our outstanding 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 B5
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series L6
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 19
$1.37500
5.50%
$1.30052
5.20%
$1.11500
4.46%
$1.17224
4.69%
$1.09400
4.38%
5.86% US$1.46448
$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%
$1.22500
4.90%
—
$25
$25
$25
US$25
$25
June 1, 2027
$25
March 1, 2023
$25
$25
June 1, 2023
$25 September 1, 2023
US$25 September 1, 2027
December 1, 2023
March 1, 2024
June 1, 2024
June 1, 2023
$25 September 1, 2024
US$25
March 1, 2024
$25
March 1, 2024
$25
December 1, 2024
$25
March 1, 2025
June 1, 2025
$25
$25 September 1, 2025
March 1, 2023
$25
—
Series C
Series E
Series G
Series I
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 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 Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial redemption
and conversion option date. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every
five years, will not be less than 4.90%. No other series of Preference Shares has this feature.
2 Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our
option, redeem all or a portion of the outstanding preference shares for the Base Redemption Value per share plus all accrued
and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.
3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference
Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an
ascribed issue price equal to the Base Redemption Value.
4 With the exception of Preference Shares, Series A, 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 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), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in
year) x Three-Month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6).
5 The quarterly dividend per share paid on Preference Shares, Series B was increased to $0.32513 from $0.21340 on June 1, 2022
due to reset of the annual dividend on June 1, 2022. On June 1, 2022, all outstanding Preference Shares, Series C were
converted to Preference Shares, Series B.
6 The quarterly dividend per share paid on Preference Shares, Series L was increased to US$0.36612 from US$0.30993 on
September 1, 2022, due to reset of the annual dividend on September 1, 2022.
PREFERENCE SHARE REDEMPTIONS
On March 1, 2022, we redeemed our $750 million outstanding Cumulative Redeemable Minimum Rate
Reset Preference Shares, Series 17. On June 1, 2022, we also redeemed our US$200 million
outstanding Cumulative Redeemable Preference Shares, Series J. Dividends are cumulative, payable
quarterly and are included in Preference share dividends in the Consolidated Statements of Earnings.
DIVIDENDS
We have paid common share dividends in every year since we became a publicly traded company in
1953. In November 2022, we announced a 3.2% increase in our quarterly dividend to $0.88750 per
common share, or $3.55 annualized, effective with the dividend payable on March 1, 2023, thereby
declaring a dividend increase for 28 straight years.
For the years ended December 31, 2022 and 2021, total dividends paid were $7.0 billion and $6.8 billion,
respectively, all of which were paid in cash and reflected in financing activities.
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On November 29, 2022, our Board of Directors declared the following quarterly dividends. All dividends
are payable on March 1, 2023 to shareholders of record on February 15, 2023.
Common Shares1
Preference Shares, Series A
Preference Shares, Series B2
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series L3
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 19
Dividend per share
$0.88750
$0.34375
$0.32513
$0.27875
$0.29306
$0.27350
US$0.36612
$0.31788
$0.27369
$0.25456
US$0.37182
$0.23356
US$0.33596
$0.27806
$0.25606
$0.24613
$0.19019
$0.18644
$0.30625
1 The quarterly dividend per common share was increased 3.2% to $0.8875 from $0.860, effective March 1, 2023.
2 The quarterly dividend per share paid on Preference Shares Series B was increased to $0.32513 from $0.21340 on June 1, 2022,
due to reset of the annual dividend on June 1, 2022 and every five years thereafter. Following the date of conversion of
Preference Shares Series C, on June 1, 2022 all outstanding Preference Shares Series C were converted to Preference Shares
Series B.
3 The quarterly dividend per share paid on Series L was increased to US$0.36612 from US$0.30993 on September 1, 2022, due to
reset of the annual dividend on September 1, 2022, and every five years thereafter.
SUMMARIZED FINANCIAL INFORMATION
On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries,
Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (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.
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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, 2022, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2 As at December 31, 2022, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.
Enbridge Notes under Guarantees
USD Denominated1
Floating Rate Senior Notes due 2023
Floating Rate Senior Notes due 2024
4.000% Senior Notes due 2023
0.550% Senior Notes due 2023
3.500% Senior Notes due 2024
2.150% Senior Notes due 2024
2.500% Senior Notes due 2025
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
CAD Denominated2
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
5.700% 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
6.100% Sustainability-Linked 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
6.510% Senior Notes due 2052
4.560% Senior Notes due 2064
1 As at December 31, 2022, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was
approximately US$11.0 billion.
2 As at December 31, 2022, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was
approximately $10.2 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 (the
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.
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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
Year ended December 31,
(millions of Canadian dollars)
Operating loss
Earnings
Earnings attributable to common shareholders
Summarized Combined Statements of Financial Position
December 31,
(millions of Canadian dollars)
Cash and cash equivalents
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
2022
(179)
1,921
1,507
2021
12
3,442
4,947
593
51,983
3,732
1,982
2,891
8,110
41,370
41,353
2022
425
2,486
5,232
969
43,873
4,111
1,375
1,745
8,752
37,626
47,447
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.
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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;
• 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 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
Line 5 Easement (Bad River Band)
On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a
complaint in the United States District Court for the Western District of Wisconsin (the Court) over our
Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion
of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our
continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public
nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which
the Band possesses ownership interests. The complaint seeks an Order prohibiting us from using Line 5
to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from
the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based
damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and
amended complaints with an answer, defenses and counterclaims.
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On August 29, 2022, the Government of Canada released a statement formally invoking the dispute
settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation; reiterating its
concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022,
the Court issued a decision on cross-motions for summary judgment. The Court determined that the
Band’s nuisance claim raised factual issues that could not be resolved on summary judgment. The Court
further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is
entitled to some measure of profits-based damages and to an injunction, with the level of damages and
scope of the injunction to be determined at trial, which occurred between October 24 and November 1,
2022. While the Court reserved judgment at the conclusion of the trial, the summary judgment decision
and subsequent pre-trial decisions provide that the Court will assess trespass damages calculated using
a pro-rata share of Enbridge’s profits from the operation of the pipeline attributable to the 12 disputed
parcels compared to the pipeline as a whole rather than the profits associated with the entire length of the
pipeline, as the Band sought. The Court has also stated that any injunction will not result in the immediate
closure of the pipeline but also will not allow the pipeline to operate indefinitely. On November 28, 2022,
the Court issued an interim Order ruling that: (a) the parties are to meet and confer by December 16 on
installation of EFRDs (Emergency Flow Restriction Devices) on the Reservation, an appropriate shutdown
and purge protocol should conditions worsen at the meander, and any other reasonable remediation
projects that could inhibit further erosion at the meander; (b) the parties are to submit a Joint Proposal by
December 23 on appropriate shutoff and purge plan for the meander, or if they cannot agree, each party
must submit their own best offer on a shutdown and purge protocol; and (c) denied Enbridge’s request for
declaratory and injunctive relief on its counterclaims asking for Court-Ordered relief relating to access and
erosion mitigation at the meander. The parties met and conferred by December 16 and a Joint Status
Report, along with individual best offers on shutdown and purge protocol, were filed on December 23. We
continue to wait on the Court’s rulings on the issues of financial compensation and Line 5’s operations.
Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement
In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit
Court (the Circuit Court) that requests the Circuit 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. 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 AG’s case to federal court follows a November 16, 2021 ruling which held that
the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5’s
shutdown raised important federal issues that should be heard in federal court. On December 21, 2021,
the AG 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 AG to file a motion to
remand the 2019 case. The AG’s motion and brief were filed on January 14, 2022, and our response was
filed on February 11, 2022. The motion was fully briefed in March 2022. On August 18, 2022, Judge Neff
denied the AG’s motion to remand which now remains in the US District Court. On August 30, 2022, the
AG filed a motion to certify the US District Court’s August 18 Order to pursue an appeal on the
jurisdictional issue, which Enbridge opposed. We anticipate a decision on the jurisdictional issue in 2023.
Dakota Access Pipeline
We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the Dakota
Access Pipeline (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.
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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
Environmental Impact Statement (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. On
February 22, 2022, the US Supreme Court denied the request of Dakota Access, LLC 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 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 completion of the EIS process.
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 draft EIS completion date to September 2022. The Army Corps now
expects to complete the draft EIS in the spring of 2023.
OTHER LITIGATION
We and our subsidiaries are subject to various other legal and regulatory actions and proceedings which
arise in the normal course of business, including interventions in regulatory proceedings and challenges
to regulatory approvals and permits. 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.
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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 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. Our reporting units are Liquids
Pipelines, Gas Transmission, Gas Distribution and Storage and Renewable Power Generation. The
Renewable Power Generation reporting unit had goodwill starting in the third quarter of 2022.
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, changes to regulatory
environments, capital accessibility, operating income trends and changes to 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.
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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, expected future capital expenditures and working capital levels, as well as
terminal value growth rates for the Liquids Pipelines, Gas Transmission and Renewable Power
Generation reporting units, and projected regulatory rate base and rate base multiplier for the Gas
Distribution and Storage reporting unit. The determination of fair value using the earnings multiples
technique requires assumptions to be made in relation to maintainable earnings and earnings multiples
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, 2022, we performed our annual goodwill impairment assessment which consisted of a
qualitative assessment for the Liquids Pipelines, Gas Transmission and Gas Distribution and Storage
reporting units and did not identify impairment indicators. Due to changes in the macroeconomic
environment that has led to a rise in interest rates, we performed a quantitative assessment for the
Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation
reporting units as at December 1, 2022, which resulted in the recognition of an impairment loss in Gas
Transmission. Goodwill impairments were not identified in relation to the Liquids Pipelines, Gas
Distribution, or Renewable Power Generation reporting units.
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 regularly 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.
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.
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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, 2022 and 2021, our regulatory assets totaled $6.5 billion and $5.9 billion,
respectively, and regulatory liabilities totaled $3.8 billion and $3.4 billion, respectively.
DEPRECIATION
Depreciation of property, plant and equipment, our largest asset with a net book value at December 31,
2022 and 2021, of $104.5 billion and $100.1 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.
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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, 2022 Consolidated Financial
Statements of a 0.5% change in key pension and other postretirement benefit (OPEB) obligation
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
243
—
(47)
13
N/A
27
23
(11)
1
N/A
49
—
(5)
5
—
3
6
(1)
—
1
CONTINGENT LIABILITIES
Provisions for claims filed against us are determined on a case-by-case basis. Case estimates are
reviewed on a regular basis and are updated as new information is received. The process of evaluating
claims involves the use of estimates and a high degree of management judgment. Claims outstanding,
the final determination of which could have a material impact on our financial results and certain
subsidiaries and investments are detailed in Part II. Item 8. Financial Statements and Supplementary
Data - Note 31. 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.
87
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, 2022 ranged from 1.5% to 9.0% (2021 - 0.9% 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.
CHANGES IN ACCOUNTING POLICIES
Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 3. Changes in Accounting
Policies.
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.
88
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A
combination of qualifying cash flow, fair value 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 hedging program to partially mitigate the impact of short-term
interest rate volatility on interest expense via execution of floating to fixed interest rate swaps. These
hedges have an average fixed rate of 4.0%.
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, 2022, 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 partially mitigate our exposure to long-term interest rate variability on forecasted term debt
issuances via execution of floating to fixed interest rate swaps with an average swap rate of 2.2%.
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.
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).
89
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 in the
Consolidated Statements of Financial Position as at December 31, 2022. 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, 2022 and 2021 CFaR was $144 million and $103 million or 1.3% and 0.9%, 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. Our shelf prospectuses with securities regulators enable 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, 2022. As a result, all
credit facilities are available to us and the banks are obligated to fund 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.
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.
90
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
91
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, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and the results of its
operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, 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.
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
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.
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 $32,440 million at December 31, 2022. 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, expected future capital expenditures and working capital levels, as well as terminal
value growth rates for the Liquids Pipelines, Gas Transmission and Midstream (Gas Transmission) and
Renewable Power Generation reporting units and projected regulatory rate base and rate base multiple
for the Gas Distribution and Storage (Gas Distribution) reporting unit. The determination of fair value using
the earnings multiples technique requires assumptions to be made in relation to maintainable earnings
and earnings multiples. Management elected to perform a qualitative goodwill impairment assessment as
of April 1, 2022 for the following reporting units: Liquids Pipelines, Gas Transmission and Gas Distribution
and did not identify impairment indicators. Due to changes in the macroeconomic environment that led to
a rise in interest rates, management performed a quantitative assessment as of December 1, 2022 for the
following reporting units: Liquids Pipelines, Gas Transmission, Gas Distribution and Renewable Power
Generation. A goodwill impairment of $2,465 million was recorded in relation to the Gas Transmission
reporting unit. Goodwill impairments were not identified in relation to the Liquids Pipelines, Gas
Distribution or Renewable Power Generation 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 judgments required by management
when developing such significant assumptions as discount rates, projected operating income, expected
future capital expenditures, terminal value growth rates, projected regulatory rate base, rate base multiple
and earnings multiples used to estimate the fair value of the reporting units, as applicable, as of
December 1, 2022. 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
quantitative assessment. In addition, the audit effort involved the use of professionals with specialized skill
and knowledge.
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 quantitative goodwill impairment assessment,
including controls over the determination of the fair value estimates of the Company’s reporting units.
These procedures also included, among others, testing management’s process for developing the fair
value estimates of the Company’s reporting units. Testing management’s process for developing the fair
value estimates included evaluating the appropriateness of the discounted cash flow and the earnings
multiples models; testing the completeness and accuracy of underlying data used in the models; and
evaluating the reasonableness of significant assumptions used by management in determining the fair
value estimates including discount rates, projected operating income, expected future capital
expenditures, projected regulatory rate base and rate base multiple, terminal value growth rates and
earnings multiples. Assessing the reasonableness of projected operating income, expected future capital
expenditures and the projected regulatory rate base 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, as applicable.
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 significant assumptions used in the models, specifically discount rates, terminal value growth rates, rate
base multiple and earnings multiples.
/s/PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Canada
February 10, 2023
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
Impairment of goodwill (Note 16)
Total operating expenses
Operating income
Income from equity investments (Note 13)
Impairment of equity investments (Note 13)
Gain on joint venture merger transaction (Note 13)
Other income/(expense) (Note 28)
Interest expense (Note 18)
Earnings before income taxes
Income tax expense (Note 25)
Earnings
(Earnings)/loss 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.
2022
2021
2020
29,150
5,653
18,506
53,309
26,873
4,026
16,172
47,071
19,259
3,663
16,165
39,087
28,942
3,647
8,219
4,317
541
2,465
48,131
5,178
2,056
—
1,076
(589)
(3,179)
4,542
(1,604)
2,938
65
3,003
(414)
2,589
26,608
2,094
6,712
3,852
—
—
39,266
7,805
1,711
(111)
—
979
(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)
—
238
(2,790)
4,190
(774)
3,416
(53)
3,363
(380)
2,983
1.28
2.87
1.48
1.28
2.87
1.48
96
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/(loss) on net investment hedges
Other comprehensive 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)/loss 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
The accompanying notes are an integral part of these consolidated financial statements.
2022
2021
2020
2,938
6,314
3,416
847
(971)
(6)
(35)
143
(10)
16
312
4,406
4,702
7,640
(21)
7,619
(414)
7,205
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
97
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 of year
Redemption of preference shares
Balance at end of year
Common shares (Note 21)
Balance at beginning of year
Shares issued on exercise of stock options
Share purchases at stated value
Other
Balance at end of year
Additional paid-in capital
Balance at beginning of year
Stock-based compensation
Purchase 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
Share purchases in excess of stated value
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
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/(loss) attributable to noncontrolling interests
Other comprehensive income/(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
Purchase 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.
98
2022
2021
2020
7,747
(929)
6,818
64,799
53
(88)
(4)
64,760
365
36
(43)
(50)
—
(33)
275
(10,989)
3,003
(414)
(7,023)
—
—
(63)
—
(15,486)
(1,096)
4,616
3,520
—
—
—
59,887
7,747
—
7,747
64,768
31
—
—
64,799
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
7,747
—
7,747
64,746
22
—
—
64,768
187
30
—
(21)
76
5
277
(6,314)
3,363
(380)
(6,612)
17
(66)
—
(3)
(9,995)
(272)
(1,129)
(1,401)
(51)
22
(29)
61,367
2,542
(65)
2,996
125
3,364
53
(28)
114
86
21
(259)
1,105
—
55
47
3,511
63,398
(15)
(15)
(30)
95
(271)
15
(293)
—
—
2,542
63,368
(6)
(25)
(31)
22
(300)
23
(112)
—
(1)
2,996
64,363
3.44
3.34
3.24
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,
(millions of Canadian dollars)
Operating activities
2022
2021
2020
Earnings
Adjustments to reconcile earnings to net cash provided by operating activities:
2,938
6,314
3,416
Depreciation and amortization
Deferred income tax expense (Note 25)
Unrealized derivative fair value (gain)/loss, net (Note 24)
Income from equity investments (Note 13)
Distributions from equity investments
Impairment of long-lived assets
Impairment of equity investments (Note 13)
Impairment of goodwill (Note 16)
Gain on joint venture merger transaction (Note 13)
(Gain)/loss on dispositions
Other
Changes in operating assets and liabilities (Note 29)
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 joint venture merger transaction (Note 13)
Proceeds from dispositions
Affiliate loans, net
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
Sale of noncontrolling interest in subsidiary (Note 8)
Contributions from noncontrolling interests
Distributions to noncontrolling interests
Common shares issued
Common shares repurchased
Preference share dividends
Common share dividends
Redemption of preference shares
Redemption of preferred shares held by subsidiary
Other
Net cash provided by/(used in) financing activities
Effect of translation of foreign denominated cash and cash equivalents and restricted
cash
Net change 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 and intangible assets non-cash accruals
The accompanying notes are an integral part of these consolidated financial statements.
4,317
957
1,280
(2,056)
1,827
541
—
2,465
(1,076)
12
37
(12)
11,230
(4,647)
(1,041)
763
(174)
(828)
522
—
135
(5,270)
481
(1,333)
7,547
(4,198)
1,092
13
(259)
3
(151)
(338)
(6,968)
(1,003)
—
(314)
(5,428)
55
587
320
907
495
2,920
937
3,852
1,091
(173)
(1,711)
1,630
—
111
—
—
(319)
(73)
(1,466)
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
489
2,427
831
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
524
2,538
801
99
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 31)
Equity
Share capital (Note 21)
Preference shares
Common shares (2,025 and 2,026 outstanding at December 31, 2022 and
2021, respectively)
Additional paid-in capital
Deficit
Accumulated other comprehensive income/(loss) (Note 23)
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 20)
Total liabilities and equity
Variable Interest Entities (VIEs) (Note 12)
The accompanying notes are an integral part of these consolidated financial statements.
100
2022
2021
861
46
8,871
114
2,255
12,147
104,460
15,936
593
9,542
4,018
32,440
472
179,608
1,996
11,392
105
763
6,045
20,301
72,939
9,189
13,781
116,210
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
6,818
7,747
64,760
275
(15,486)
3,520
59,887
3,511
63,398
179,608
64,799
365
(10,989)
(1,096)
60,826
2,542
63,368
168,864
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
INDEX
PAGE
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103
113
115
119
121
121
124
127
128
128
129
131
134
134
135
135
136
139
140
140
143
145
146
157
160
168
170
170
171
172
173
174
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. Other Income/(Expense)
29. Changes in Operating Assets and Liabilities
30. Related Party Transactions
31. Commitments and Contingencies
32. Guarantees
33. Quarterly Financial Data (Unaudited)
101
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
and export various grades of crude oil and other liquid hydrocarbons, including the Mainline System,
Regional Oil Sands System, Gulf Coast and Mid-Continent, 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 throughout
Ontario. This business segment also includes natural gas distribution activities in Québec. We sold our
investment in Noverco Inc. (Noverco), previously reported in the Gas Distribution and Storage segment,
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. This segment also includes Tri Global Energy, LLC (TGE) which
was acquired on September 27, 2022 (Note 8).
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 segments described above, Eliminations and Other includes operating and
administrative costs that are not allocated to business segments, the impact of foreign exchange hedge
settlements and the activities of our wholly-owned captive insurance subsidiaries. The principal activity of
our captive insurance subsidiaries is providing insurance and reinsurance coverage for certain insurable
property and casualty risk exposures of our operating subsidiaries and certain equity investments.
Eliminations and Other also includes new business development activities and corporate investments.
102
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 31); and estimates of losses
related to environmental remediation obligations (Note 31). 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 the 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 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.
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.
103
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 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, 2022 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. The equity component of AFUDC is included as a non-cash reconciling item to
earnings within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows.
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.
104
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 our liquids and natural 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. We also have long-term contracts where the revenue profile does not align with the cash
receipt schedule, resulting in the recognition of deferred revenue.
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, 2022, 2021 and 2020, cash received net of revenue recognized for
contracts under make-up rights and similar deferred revenue arrangements was $238 million, $127 million
and $292 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.
No non-affiliated customer exceeded 10.0% of our third-party revenues for the year ended December 31,
2022. Our largest non-affiliated customer accounted for approximately 13.5% and 13.6% of our third-party
revenues for the years ended December 31, 2021 and 2020, respectively.
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, Other income/(expense) and Interest
expense.
105
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 Cash Flows from 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.
106
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. These investments are initially measured at cost
and are adjusted for our proportionate share of undistributed equity earnings or loss. Our 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 less impairment, if any, and
adjusted for 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.
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 earnings in the period in which they arise.
107
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 for the purposes of the CER’s
LMCI or in accordance with specific commercial arrangements are presented as Restricted cash in the
Consolidated Statements of Financial Position.
LOANS AND RECEIVABLES
Long-term notes receivable from affiliates 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.
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.
108
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.
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; the difference between the actual cost and approved cost of natural gas reflected in rates; and
actuarial gains and losses arising from defined benefit pension plans.
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.
109
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. Our reporting units are Liquids
Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. The
Renewable Power Generation reporting unit had goodwill beginning in the third quarter of 2022.
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, changes to regulatory
environments, capital accessibility, operating income trends and changes to 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, expected future capital expenditures and working capital levels, as well as
terminal value growth rates for the Liquids Pipelines, Gas Transmission and Renewable Power
Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas
Distribution and Storage reporting unit. The determination of fair value using the earnings multiples
technique requires assumptions to be made in relation to maintainable earnings and earnings multiples
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, 2022, we performed our annual goodwill impairment assessment which consisted of a
qualitative assessment for the Liquids Pipelines, Gas Transmission and Gas Distribution and Storage
reporting units and did not identify impairment indicators. Due to changes in the macroeconomic
environment that have led to a rise in interest rates, we performed a quantitative assessment for the
Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation
reporting units as at December 1, 2022, which resulted in the recognition of an impairment loss for Gas
Transmission (Note 16). Goodwill impairments were not identified in relation to the Liquids Pipelines, Gas
Distribution and Storage or Renewable Power Generation reporting units. Also, we did not identify any
indicators of goodwill impairment during the remainder of 2022.
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.
110
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, as well as defined benefit OPEB
plans.
Obligations and net periodic benefit costs for defined benefit pension and OPEB plans are estimated
using the projected unit credit method, which is based on years of service, as well as our best estimates
of actuarial assumptions such as discount rates, future salary levels, other cost escalations, employees'
retirement ages, and mortality.
We determine discount rates using market yields of high-quality corporate bonds with maturities that
approximate the estimated timing of future benefit payments.
Plan assets are measured at fair value. The expected return on plan assets is determined using the long-
term target asset mixes in our investment policies and long-term market expectations.
Actuarial gains and losses arise from the difference between the actual and expected return on plan
assets, and changes in actuarial assumptions such as discount rates. Periodic net actuarial gains and
losses and prior service costs are accumulated and presented as follows in the Consolidated Statements
of Financial Position:
• as a component of AOCI, for our non-utilities' defined benefit pension plans and all defined benefit
OPEB plans; and
• as a component of Deferred amounts and other assets and/or Other long-term liabilities, for our
utilities' defined benefit pension plans, to the extent that the net actuarial gains and losses and prior
service costs have been permitted or are expected to be permitted by the regulators, to be recovered
through future rates.
111
Net periodic benefit cost is recognized in earnings and includes:
• current service cost;
• interest cost;
• expected return on plan assets;
• amortization of prior service costs over the expected average remaining service life of the plans'
active employee group; and
• amortization of net actuarial gains and losses in excess of 10% of the greater of the benefit obligation
or the fair value of plan assets, over the expected average remaining service life of the plans' active
employee group.
Our utility operations also record regulatory adjustments for the difference between net periodic benefit
costs for accounting versus ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to
the extent net periodic benefit costs are expected to be recovered 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, our contributions are expensed when 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.
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 common
shares with an offset to Accounts payable and other or Other long-term liabilities. The value of the PSUs
is also dependent on our performance relative to performance targets set out under the plan. We also
award share settled RSUs which vest at the completion of a three-year term. During the vesting term,
compensation expense is recorded based on the number of units granted and the market price of
Enbridge's common shares on the day immediately preceding the grant date, with an offset to Additional
paid-in capital.
112
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.
3. CHANGES IN ACCOUNTING POLICIES
CHANGES IN ACCOUNTING POLICIES
There were no changes in accounting policies during the year ended December 31, 2022.
ADOPTION OF NEW ACCOUNTING STANDARDS
Disclosures About Government Assistance
Effective January 1, 2022, we adopted Accounting Standards Update (ASU) 2021-10 on a prospective
basis. The new standard was issued in November 2021 to increase the transparency of government
assistance to business entities. The ASU adds new disclosure requirements for transactions with
governments 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. The adoption of this ASU did
not have a material impact on our consolidated financial statements.
Accounting for Certain Lessor Leases with Variable Lease Payments
Effective January 1, 2022, we adopted ASU 2021-05 on a prospective basis. The new standard 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. The
adoption of this ASU did not have a material impact on our consolidated financial statements.
113
Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts
Effective January 1, 2022, we adopted ASU 2021-04 on a prospective basis. The new standard 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. The adoption of this ASU did not have a material impact on
our consolidated financial statements.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
Effective January 1, 2022, we adopted ASU 2020-06 on a modified retrospective basis. The new standard
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. The adoption of this ASU did not have a material impact on our consolidated financial statements.
114
4. REVENUE
REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
Year ended December 31, 2022
(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
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
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
11,283
235
5,012
350
—
—
—
11,518
—
(81)
615
12,052
22
—
—
5,384
—
39
3
5,426
782
308
—
5,643
—
—
—
—
—
281
—
—
—
—
—
6,733
—
(20)
16
6,729
281
—
— 29,150
—
25
582 29,175
305
(4)
—
—
—
—
—
—
—
—
(655)
(655)
17,077
893
22
5,643
281
23,916
29,150
243
—
53,309
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
—
—
—
9,639
—
375
567
10,581
49
—
—
4,668
—
42
1
4,711
676
246
—
4,026
—
—
—
—
—
177
—
—
—
—
—
4,948
—
13
19
4,980
177
—
— 26,873
—
44
512 26,917
336
(1)
—
—
—
—
—
—
—
—
(630)
(630)
14,532
648
49
4,026
177
19,432
26,873
766
—
47,071
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
—
—
—
9,255
—
584
584
10,423
27
—
—
4,824
—
44
2
4,870
674
203
—
3,663
—
—
—
—
—
198
—
—
—
—
—
4,540
—
17
12
4,569
198
—
— 19,259
—
24
389
—
587 19,283
—
—
—
—
—
—
—
(23)
(622)
(645)
14,358
571
27
3,663
198
18,817
19,259
1,011
—
39,087
1 Includes mark-to-market losses from our hedging program for the year ended December 31, 2022 of $431 million (2021 -
$59 million gain; 2020 - $265 million gain).
2 Includes revenues from lease contracts. Refer to Note 27 - Leases.
115
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, 2022
Balance as at December 31, 2021
Contract
Receivables
Contract
Assets
Contract
Liabilities
3,183
2,369
230
213
2,241
1,898
Contract receivables represent the amount of receivables derived from contracts with customers.
Contract assets represent the amount of revenue which has been recognized in advance of payments
received for performance obligations we have fulfilled (or have 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, 2022 included in contract liabilities at the beginning of the year is $166
million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during
the year ended December 31, 2022, were $453 million.
Performance Obligations
Segment
Liquids Pipelines
Nature of Performance Obligation
• Transportation and storage of crude oil and natural gas liquids
(NGL)
Gas Transmission and Midstream
• Transportation, storage, gathering, compression and treating of
Gas Distribution and Storage
Renewable Power Generation
natural gas
• Transportation of NGL
• Sale of crude oil, natural gas and NGL
• 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 during the year ended December 31, 2022 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 our US offshore business provide for us to receive a series of fixed monthly payments
(FMPs) for a specified period that 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 as 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.
116
Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $58.6 billion, of
which $7.6 billion is expected to be recognized during the year ending December 31, 2023.
The revenues excluded from the amounts above based on optional exemptions available under
Accounting Standards Codification (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, 2022, revenue for the Canadian Mainline has been recognized in
accordance with the terms of the Competitive Toll 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, 2022 is considered variable
consideration.
117
Recognition and Measurement of Revenue
Year ended December 31, 2022
(millions of Canadian dollars)
Revenue from products transferred at a point in time
Revenue from products and services transferred over
time1
Total revenue from contracts with customers
Year ended December 31, 2021
(millions of Canadian dollars)
Revenue from products transferred at a point in time
Revenue from products and services transferred over
time1
Total revenue from contracts with customers
Year ended December 31, 2020
(millions of Canadian dollars)
Revenue from products transferred at a point in time
Revenue from products and services transferred over
time1
Total revenue from contracts with customers
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation Consolidated
—
—
127
11,518
11,518
5,384
5,384
6,606
6,733
—
281
281
127
23,789
23,916
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation Consolidated
—
—
70
9,639
9,639
4,668
4,668
4,878
4,948
—
177
177
70
19,362
19,432
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation Consolidated
—
—
60
9,255
9,255
4,824
4,824
4,480
4,540
—
198
198
60
18,757
18,817
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.
118
5. SEGMENTED INFORMATION
Segmented information for the years ended December 31, 2022, 2021 and 2020 is as follows:
Year ended December 31, 2022
(millions of Canadian dollars)
Revenues (Note 4)
Commodity and gas distribution
costs
Operating and administrative
Impairment of long-lived assets
Impairment of goodwill (Note 16)
Income/(loss) from equity
investments (Note 13)
Gain on joint venture merger
transaction (Note 13)
Other income/(expense) (Note 28)
Earnings/(loss) before interest,
income taxes and depreciation
and amortization
Depreciation and amortization
Interest expense (Note 18)
Income tax expense (Note 25)
Earnings
Capital expenditures1
Total property, plant and
Gas
Transmission
and
Midstream
Gas
Distribution
and
Storage
Liquids
Pipelines
Renewable
Power
Generation
Energy
Services
Eliminations
and Other Consolidated
12,052
5,426
6,729
582 29,175
(655)
53,309
—
(4,287)
(245)
—
—
(2,254)
—
(2,465)
(3,693)
(1,289)
—
—
785
1,133
—
59
1,076
210
1
—
79
(16) (29,525)
(49)
(13)
—
(255)
(235)
—
141
—
45
—
—
(5)
645
(85)
(48)
—
(32,589)
(8,219)
(541)
(2,465)
(4)
2,056
—
(977)
1,076
(589)
8,364
3,126
1,827
262
(417)
(1,124)
1,418
1,690
1,499
50
—
33
12,038
(4,317)
(3,179)
(1,604)
2,938
4,690
equipment, net (Note 11)
53,567
29,666
17,857
3,082
6
282
104,460
Year ended December 31, 2021
(millions of Canadian dollars)
Revenues (Note 4)
Commodity and gas distribution
costs
Operating and administrative
Income/(loss) from equity
investments (Note 13)
Impairment of equity investments
(Note 13)
Other income/(expense) (Note 28)
Earnings/(loss) before interest,
income taxes and depreciation
and amortization
Depreciation and amortization
Interest expense (Note 18)
Income tax expense (Note 25)
Earnings
Capital expenditures1
Total property, plant and
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)
644
(33)
(28,702)
(6,712)
759
813
42
101
—
13
(111)
135
—
385
—
75
—
—
(8)
(4)
1,711
—
379
(111)
979
7,897
3,671
2,117
508
(313)
356
4,051
2,420
1,343
16
1
54
14,236
(3,852)
(2,655)
(1,415)
6,314
7,885
equipment, net (Note 11)
52,530
27,028
16,904
3,315
23
267
100,067
119
Year ended December 31, 2020
(millions of Canadian dollars)
Revenues (Note 4)
Commodity and gas distribution
costs
Operating and administrative
Income/(loss) from equity
investments (Note 13)
Impairment of equity investments
(Note 13)
Other income/(expense) (Note 28)
Earnings/(loss) before interest,
income taxes and depreciation
and amortization
Depreciation and amortization
Interest expense (Note 18)
Income tax expense (Note 25)
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
10,423
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
479
—
53
(2,351)
(52)
9
—
71
94
—
35
(3)
—
1
(1)
1,136
—
130
(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
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.
2022
2021
2020
27,498
25,811
53,309
20,474
26,597
47,071
16,453
22,634
39,087
2022
2021
47,602
56,858
104,460
47,102
52,965
100,067
120
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. On December 30, 2021, we closed the
sale of our minority ownership in Noverco. The weighted average number of common shares outstanding
was reduced by our pro-rata weighted average interest in our own common shares of approximately 2
million and 5 million as at December 31, 2021 and 2020, respectively, resulting from our reciprocal
investment in Noverco.
DILUTED
The treasury stock method is used to determine the dilutive impact of stock options and RSUs. This
method assumes any proceeds from the exercise of stock options and vesting of RSUs 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 and RSUs
Diluted weighted average shares outstanding
2022
2021
2020
2,025
4
2,029
2,023
2
2,025
2,020
1
2,021
For the years ended December 31, 2022, 2021 and 2020, 10.4 million, 18.6 million and 29.8 million,
respectively, of anti-dilutive stock options with a weighted average exercise price of $56.49, $52.89 and
$51.42, 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. In the absence of rate-regulated accounting, this regulatory
Deferred income taxes balance and the related earnings impact would not be recorded.
121
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. The tolls in place on June 30, 2021 continue on an interim basis until new tolls are finalized and
approved by the CER (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, 2022 (2021 - $2.1 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 currently operate under the terms of their respective
2022-2026 and 2022-2023 settlement agreements, which stipulate an allowable ROE and the
continuation and establishment of certain deferral and variance accounts.
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 agencies. 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.
122
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.
December 31,
(millions of Canadian dollars)
Current regulatory assets
Purchase gas variance
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
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
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)
Pension plan payable6
Other long-term regulatory liabilities
Total long-term regulatory liabilities7
Total regulatory liabilities
2022
190
109
305
604
4,473
378
265
244
219
40
244
5,863
6,467
167
167
1,615
918
610
231
250
3,624
3,791
2021
Recovery/Refund
Period Ends
2023
2023
2023
Various
2032-2046
Various
2024
Various
Various
Various
2023
Various
2050-2072
Various
Various
Various
15
114
130
259
4,176
398
243
215
157
78
339
5,606
5,865
106
106
1,543
895
649
—
234
3,321
3,427
1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in
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 primarily consists of 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.
123
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.
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
ACQUISITIONS
Tri Global Energy, LLC
On September 27, 2022, through a wholly-owned US subsidiary, we acquired all of the outstanding
common units in TGE for cash consideration of $295 million (US$215 million) plus potential contingent
payments of up to $72 million (US$53 million) dependent on the achievement of performance milestones
by TGE (the TGE Acquisition). The TGE Acquisition is subject to customary closing and working capital
adjustments. TGE is an onshore renewable project developer in the US with a development portfolio of
wind and solar projects. The TGE Acquisition enhances Enbridge's renewable power platform and
accelerates our North American growth strategy.
We accounted for the TGE 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 are recorded at their estimated fair values as
at the date of acquisition.
The following table summarizes the estimated fair values that were assigned to the net assets of TGE:
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets
Property, plant and equipment
Long-term investments
Intangible assets (a)
Long-term assets
Current liabilities
Long-term debt (Note 18)
Long-term liabilities (b)
Goodwill (c)
Purchase price:
Cash
Contingent consideration (d)
September 27,
2022
5
3
8
117
3
61
18
105
392
295
49
344
a) Intangible assets consist of compensation expected to be earned by TGE on existing development
contracts once certain project development milestones are met. Fair value was determined using a
discounted cash flow method which is an income-based approach to valuation that estimates the
present value of future projected benefits from the contracts. The intangible assets will be amortized
on a straight-line basis over an expected useful life of three and a half years.
b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on the
timing of milestones being met for certain projects. Fair value represents the present value of the
future cash flow payments at the date of the TGE Acquisition.
124
c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and
solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio.
The goodwill balance recognized has been assigned to our Renewable Power Generation segment
and is tax deductible over 15 years.
d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former
common unit holders if performance milestones are met on certain projects. The US$36 million of
contingent consideration recognized in the purchase price represents the fair value of contingent
consideration at the date of acquisition. The fair value was determined using an income-based
approach.
Upon completion of the TGE Acquisition, we began consolidating TGE. For the period beginning
September 27, 2022 through to December 31, 2022, operating revenues and earnings attributable to
common shareholders generated by TGE were immaterial. The impact to our supplemental pro forma
consolidated operating revenues and earnings attributable to common shareholders for the years ended
December 31, 2022 and 2021, as if the TGE Acquisition had been completed on January 1, 2021, was
also immaterial.
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 Moda Acquisition). The Moda
Acquisition was 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 Moda 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 Moda 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 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)
125
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.
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 and was fully settled as at December 31, 2022.
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 Moda 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 Moda 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.
126
DISPOSITIONS
Athabasca Regional Oil Sands System
On October 5, 2022, we closed the sale of an 11.6% non-operating interest in seven pipelines in the
Athabasca region of northern Alberta from our Regional Oil Sands System to Athabasca Indigenous
Investments Limited Partnership (Aii), an entity representing 23 First Nation and Métis communities, for
total consideration of approximately $1.1 billion, less customary closing adjustments. No gain or loss was
recognized on the sale and a noncontrolling interest was recorded in our Consolidated Statements of
Financial Position as at December 31, 2022 to reflect the interest held by Aii (Note 20).
Subsequent to the sale, we maintained an 88.4% controlling interest in these assets, which are a
component of our Liquids Pipelines segment, and continue to manage, operate and provide
administrative services to them.
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. 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.
Montana-Alberta Tie Line
On May 1, 2020, we closed the sale of the Montana-Alberta Tie Line (MATL) transmission asset, a 345
kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta, 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. MATL was included in our
Renewable Power Generation segment.
Ozark Gas Transmission
On April 1, 2020, we closed the sale of our Ozark Gas Transmission and Ozark Gas Gathering assets
(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. 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.
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)
Gas imbalance
Taxes receivable
Other
2022
5,616
1,015
604
461
323
852
8,871
2021
4,957
529
259
276
407
434
6,862
1 Net of allowance for expected credit losses of $92 million and $87 million as at December 31, 2022 and 2021, respectively.
127
10. INVENTORY
December 31,
(millions of Canadian dollars)
Natural gas
Crude oil
Other
2022
1,491
652
112
2,255
2021
953
624
93
1,670
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
Weighted Average
Depreciation Rate
2022
2021
2.9 %
3.5 %
2.2 %
2.6 %
2.3 %
4.1 %
8.5 %
— %
66,528
37,028
3,637
14,491
3,477
4,912
1,611
2,316
134,000
(29,540)
104,460
62,997
34,331
3,320
13,606
3,099
4,912
1,507
2,268
126,040
(25,973)
100,067
1 The measurement of weighted average depreciation rate excludes non-depreciable assets.
Depreciation expense for the years ended December 31, 2022, 2021 and 2020 was $3.8 billion, $3.5
billion and $3.4 billion, respectively.
IMPAIRMENT
Magic Valley Wind Farm
Magic Valley Wind Farm (Magic Valley) has commercial challenges caused by electricity transmission
congestion and a negative price differential arising from higher transmission costs resulting in a lower
electricity sale price. As a result, we have recognized an impairment loss of $227 million to our investment
in Magic Valley, which is included in Impairment of long-lived assets in the Consolidated Statements of
Earnings and is part of our Renewable Power Generation segment.
Bakken Pipeline System
The Bakken Pipeline System currently has long-term take-or-pay contracts that are set to expire in 2023.
In connection with the upcoming expiration of the contracts, we have recognized an impairment loss of
$183 million on the US and Canadian components of the interstate pipeline transportation system within
the North Dakota System of our Bakken System, which is included in Impairment of long-lived assets in
the Consolidated Statements of Earnings and is part of our Liquids Pipelines segment.
Impairment charges were based on the amount by which the carrying value of the assets exceeded fair
value, determined using expected discounted future cash flows.
128
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. The creditors
of the liabilities of our consolidated VIEs 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
Accounts receivable from affiliates
Inventory
Property, plant and equipment, net
Long-term investments
Restricted long-term investments
Deferred amounts and other assets
Intangible assets, net
Liabilities
Accounts payable and other
Accounts payable to affiliates
Other long-term liabilities
Deferred income taxes
20221
2021
426
12
199
23
12
672
7,707
14
98
158
102
8,751
251
21
272
859
5
1,136
7,615
247
4
99
—
9
359
3,052
16
101
2
108
3,638
84
—
84
182
5
271
3,367
1 Includes assets and liabilities of newly created Enbridge Athabasca Midstream Trunkline LP and Enbridge Athabasca Midstream
Investor LP following the sale of a minority interest in certain Athabasca Regional Oil Sands System assets. Refer to Note 8 -
Acquisitions and Dispositions.
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 their 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.
129
The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31,
2022 and 2021 are presented below:
December 31, 2022
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.1
EIH S.á r.l.2
Rampion Offshore Wind Limited3
Vector Pipeline L.P.4
Woodfibre LNG Limited Partnership5,6
Other7
December 31, 2021
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.1
EIH S.á r.l.2
Enbridge Renewable Infrastructure Investments S.á r.l.8,9
Rampion Offshore Wind Limited3
Vector Pipeline L.P.4
Other7
Carrying
Amount of
the VIE
Maximum
Exposure to
Loss
91
37
413
195
635
245
1,616
117
637
468
325
2,476
443
4,466
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
1 As at December 31, 2022 and 2021, the maximum exposure to loss includes a guarantee by us for our respective share of the
VIE’s borrowing on a bank credit facility.
2 As at December 31, 2022 and 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 $56 million and $73 million held by us as at December 31, 2022 and 2021, respectively.
3 As at December 31, 2022 and 2021, 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.
4 As at December 31, 2022 and 2021, the maximum exposure to loss includes the carrying value of outstanding affiliate loans
receivable for $25 million and $80 million held by us as at December 31, 2022 and 2021, respectively, and an outstanding credit
facility for $105 million as at December 31, 2022 and 2021.
5 In November 2022, Enbridge acquired a 30% interest in Woodfibre LNG Limited Partnership (Woodfibre). Refer to Note 13 -
Long-Term Investments. Woodfibre is a VIE due to its lack of sufficient equity at risk to finance its activities. Enbridge does not
hold decision-making rights to direct Woodfibre's activities that most significantly impact its economic performance.
6 As at December 31, 2022, 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.
7 As at December 31, 2022 and 2021, the maximum exposure to loss includes our parental guarantees that have been committed
in connection with the projects for which we would be liable in the event of default by the VIE.
8 As at December 31, 2021, the maximum exposure to loss included 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 held by us as at December 31, 2021.
9 Following a reconsideration event in connection with an additional equity injection to facilitate debt and equity rebalancing of
Enbridge Renewable Infrastructure Investments S.á r.l. (ERII) in the third quarter of 2022, ERII's equity is now sufficient for it to
finance its activities without additional subordinated financial support. Therefore, it is no longer considered to be a VIE.
We do not have an obligation to and did not provide any additional financial support to the VIEs during the
years ended December 31, 2022 and 2021.
130
13. LONG-TERM INVESTMENTS
December 31,
(millions of Canadian dollars)
EQUITY INVESTMENTS
Liquids Pipelines
MarEn Bakken Company LLC1
DCP Midstream, LLC (Class B Units)2
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, LLC (Class A Units)7
Gulfstream Natural Gas System, L.L.C.
Nexus Gas Transmission, LLC
Sabal Trail Transmission, LLC
Southeast Supply Header, LLC
Steckman Ridge, LP
Vector Pipeline8
Woodfibre LNG Limited Partnership
Offshore - various joint ventures
Other
Gas Distribution and Storage
Other
Renewable Power Generation
Ownership
Interest
2022
2021
75.0%
90.0%
50.0%
65.0%
30.0%
30.0% - 43.8%
50.0%
42.7% - 50.0%
23.4%
50.0%
50.0%
50.0%
50.0%
50.0%
60.0%
30.0%
22.0% - 74.3%
20.0% - 33.3%
1,968
1,394
2,744
622
658
76
430
214
317
1,274
1,813
1,535
86
91
195
635
314
—
1,752
469
2,634
593
434
71
504
238
397
1,180
1,724
1,464
82
88
189
—
309
14
47.6% - 50.0%
20
20
EIH S.à.r.l.9
Enbridge Renewable Infrastructure Investments S.à.r.l.
Rampion Offshore Wind Limited
NextBridge Infrastructure LP
Other
51.0%
51.0%
24.9%
25.0%
15.8% - 50.0%
OTHER LONG-TERM INVESTMENTS
Gas Transmission and Midstream
Fairwood Peninsula Energy Corporation
Gas Distribution and Storage
Oakville Enterprises Corporation10
Renewable Power Generation
Emerging Technologies and Other
Eliminations and Other
Other11
37
163
413
241
107
22
48
31
38
54
450
186
92
20
—
32
488
290
15,936 13,324
1 Owns a 49.0% interest in Bakken Pipeline Investments L.L.C. Bakken Pipeline Investments L.L.C. owns 75.0% of the Bakken
Pipeline System, resulting in a 27.6% effective interest in the Bakken Pipeline System by us.
2 We own 90.0% of the Class B units of DCP Midstream, LLC. These units track to a 65.0% ownership in Gray Oak Pipeline, LLC
(Gray Oak), resulting in a 58.5% effective interest in Gray Oak by us. In 2021, we owned a 35.0% interest in Gray Oak Holdings
LLC, which owned a 65.0% interest in Gray Oak, resulting in a 22.8% effective interest in Gray Oak by us.
3 Owns the Southern Access Extension Project.
4 On October 12, 2021, we acquired an effective 20.0% interest in Cactus II through the acquisition of Moda. Refer to Note 8 -
Acquisitions and Dispositions for further discussion. On November 2, 2022, we acquired an additional 10.0% ownership in Cactus
II for cash payment of $241 million (US$177 million), bringing our total non-operating ownership to 30.0%.
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.
131
7 We own 23.4% of the Class A units of DCP Midstream, LLC. These units track to a 56.5% ownership in DCP Midstream, LP
(DCP), resulting in a 13.2% effective interest in DCP by us. In 2021, we owned an effective 28.3% interest in DCP.
8 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US.
9 On March 18, 2021, we sold 49.0% of EIH S.à.r.l., an entity that holds our 50.0% interest in Éolien Maritime France SAS (EMF),
to the Canada Pension Plan Investment Board. 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 effective interests in Saint-Nazaire (25.5%),
Fécamp (17.9%) and Calvados (21.7%).
10 On August 2, 2022, we acquired a 10.0% interest in Oakville Enterprises Corporation.
11 Consists of investments in debt and equity securities held by our wholly-owned captive insurance subsidiaries. Refer to Note 24 -
Risk Management and Financial Instruments.
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, 2022, this basis difference was
$3.4 billion (2021 - $2.5 billion), of which $1.5 billion (2021 - $730 million) was amortizable.
For the years ended December 31, 2022, 2021 and 2020, distributions received from equity investments
were $2.6 billion, $2.2 billion and $2.1 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
2022
2021
2020
27,043
23,043
4,334
2,056
20,021
16,706
3,022
1,711
2022
4,196
53,405
4,843
18,595
3,785
14,096
12,411
2,324
1,136
2021
3,639
44,863
3,741
16,979
3,786
DCP Midstream, LLC
On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 (P66) resulting in a
single joint venture, DCP Midstream, LLC, holding both our and P66's indirect ownership interests in Gray
Oak and DCP. Our ownership in DCP Midstream, LLC consists of Class A and Class B Interests which
track to our investments in DCP, included in the Gas Transmission and Midstream segment, and Gray
Oak, included in the Liquids Pipelines segment, respectively. Through our investment in DCP Midstream,
LLC, we increased our effective economic interest in Gray Oak to 58.5% from 22.8% and reduced our
effective economic interest in DCP to 13.2% from 28.3%. As a result of the transaction, Enbridge will
assume operatorship of Gray Oak in the second quarter of 2023.
We determined the fair value of our decrease in economic interest in DCP based on the unadjusted
quoted market price of DCP’s publicly traded common units on the transaction closing date. The fair value
of our increased economic interest in Gray Oak was determined using the fair value prescribed to the
change in our economic interest in DCP. As a result of the merger transaction and the realignment of our
economic interests in DCP and Gray Oak, we also received cash consideration of approximately
$522 million (US$404 million) and recorded an accounting gain of $1.1 billion (US$832 million) to Gain on
joint venture merger transaction in the Consolidated Statements of Earnings. Both DCP and Gray Oak
continue to be accounted for as equity method investments.
132
Woodfibre LNG Limited Partnership
On November 29, 2022, Enbridge acquired, for cash payment of $533 million (US$392 million), an
effective 30.0% interest in Woodfibre. Woodfibre will operate a liquified natural gas export facility in BC
being constructed by us and our partners.
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.
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 20.0% 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, 2022 and 2021 was nil and $12 million, respectively.
Steckman Ridge, LP
Steckman Ridge, LP (Steckman Ridge) is engaged in the storage of natural gas, is owned 50.0% 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. As a result, we recorded an other-than-temporary
impairment loss of $221 million on our investment for the year ended December 31, 2020 based on a
discounted cash flow analysis. The carrying value of this investment as at December 31, 2022 and 2021
was $91 million and $88 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, is owned 50.0% 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. As a result, we
recorded an other-than-temporary impairment loss of $394 million on our investment for the year ended
December 31, 2020 based on a discounted cash flow analysis. The carrying value of this investment as at
December 31, 2022 and 2021 was $86 million and $82 million, respectively.
DCP Midstream, LLC
DCP Midstream, LLC, an entity of which we had a 50.0% ownership interest in prior to the joint venture
merger transaction with P66, holds an equity interest in DCP. A decline in the market price of DCP's
publicly traded units during the first quarter of 2020 resulted in an other-than-temporary impairment loss
on our investment in DCP Midstream, LLC 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. The carrying value of our investment in DCP Midstream,
LLC (Class A Units) as at December 31, 2022 and 2021 was $317 million and $397 million, respectively.
133
Our investments in PennEast, Steckman, SESH and DCP Midstream, LLC (Class A Units) 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 in the
Consolidated Statements of Earnings and Restricted long-term investments in the Consolidated
Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to
Operating and administrative expense in the Consolidated Statements of Earnings and Other long-term
liabilities in the Consolidated Statements of Financial Position.
We routinely invest excess cash and various restricted balances in securities such as commercial paper,
bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money
market securities in the US and Canada.
As at December 31, 2022 and 2021, we had restricted long-term investments held in trust and classified
as available-for-sale of $593 million and $630 million, respectively.
We had Restricted long-term investments held in trust totaling $236 million and $217 million as at
December 31, 2022 and 2021, respectively, which are classified as Level 1 in the fair value hierarchy.
We also had Restricted long-term investments held in trust totaling $357 million (cost basis - $437 million)
and $413 million (cost basis - $383 million) as at December 31, 2022 and 2021, respectively, which are
classified as Level 2 in the fair value hierarchy. There were unrealized holding losses of $122 million and
$8 million on our Restricted long-term investments for the years ended December 31, 2022 and 2021,
respectively. Within Other long-term liabilities we had estimated future abandonment costs related to
LMCI of $610 million and $649 million as at December 31, 2022 and 2021, respectively (Note 7).
15. INTANGIBLE ASSETS
December 31, 2022
(millions of Canadian dollars)
Software
Power purchase agreements
Project agreement1
Customer relationships
Other intangible assets
Under development
Weighted Average
Amortization Rate
10.9%
4.2%
4.0%
8.6%
5.9%
—%
Cost
2,019
64
163
2,701
621
158
5,726
Accumulated
Amortization
(1,042)
(23)
(36)
(459)
(148)
—
(1,708)
Net
977
41
127
2,242
473
158
4,018
134
December 31, 2021
(millions of Canadian dollars)
Software
Power purchase agreements
Project agreement1
Customer relationships
Other intangible assets
Under development
Weighted Average
Amortization Rate
12.0%
4.5%
4.0%
8.5%
3.9%
—%
Cost
2,067
63
152
2,532
475
246
5,535
Accumulated
Amortization
(1,148)
(21)
(27)
(215)
(116)
—
(1,527)
Net
919
42
125
2,317
359
246
4,008
1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.
For the years ended December 31, 2022, 2021 and 2020, our amortization expense related to intangible
assets totaled $483 million, $348 million and $294 million, respectively. Our expected amortization
expense associated with existing intangible assets for each of the years 2023 to 2027 is $498 million.
16. GOODWILL
Liquids
Pipelines
Gas
Transmission
and Midstream
Gas
Distribution
and Storage
Renewable
Power
Generation
Energy
Services Consolidated
(millions of Canadian dollars)
Balance at January 1, 2021
Foreign exchange and other
Acquisition3
Balance at December 31, 20211,2
Impairment
Foreign exchange and other
Acquisition4
Balance at December 31, 20221,2
7,828
(55)
268
8,041
—
506
—
8,547
19,480
(145)
—
19,335
(2,465)
1,236
—
18,106
5,378
—
19
5,397
—
—
—
5,397
—
—
—
—
—
(4)
392
388
2
—
—
2
—
—
—
2
32,688
(200)
287
32,775
(2,465)
1,738
392
32,440
1 Gross goodwill as at December 31, 2022 and 2021 was $36.5 billion and $34.4 billion, respectively.
2 Accumulated impairment as at December 31, 2022 and 2021 was $4.1 billion and $1.6 billion, respectively.
3 In 2021 we recorded $268 million of goodwill related to the acquisition of Moda. Refer to Note 8 - Acquisitions and Dispositions.
4 In 2022, we recorded $392 million of goodwill related to the acquisition of TGE. Refer to Note 8 - Acquisitions and Dispositions.
IMPAIRMENT
Gas Transmission
During the year ended December 31, 2022, we recorded goodwill impairment of $2.5 billion related to our
Gas Transmission reporting unit. The fair value of the reporting unit, determined using a combination of
discounted cash flow and earnings multiples techniques, was impacted by a rise in cost of capital and
lower projected long term growth rates for our existing assets.
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
135
2022
5,235
1,825
1,056
937
898
683
758
11,392
2021
4,470
1,773
853
844
717
478
632
9,767
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
Other4
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
Algonquin Gas Transmission, LLC
Senior notes
East Tennessee Natural Gas, LLC
Senior notes
Texas Eastern Transmission, LP
Senior notes
Spectra Energy Partners, LP
Senior notes
Tri Global Energy, LLC
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
2022
2021
3.5%
3.8%
2.0%
4.1%
5.9%
4.8%
2023 - 2051 12,060 10,992
8,123
2023 - 2064
2,363
2032 - 2033
1,263
2080 - 2083
6,442
2077 - 2078
1,579
2023 - 2024
7,837
2023 - 2027
5
8,223
3,355
3,596
6,736
1,491
7,984
15
4.5%
2024 - 2027
4,199
7
4,845
7
6.5%
2025 - 2045
3,320
3,095
4.1%
9.1%
4.5%
2023 - 2052
2024 - 2025
2024
9,535
210
2,000
1
9,010
210
1,515
—
4.0%
4.2%
8.2%
4.6%
4.0%
2040
921
949
2023 - 2051
2024
2024
5,425
200
312
5,575
200
667
2040
222
240
7.0%
2032 - 2038
234
218
3.3%
2024 - 2029
1,152
1,074
3.1%
2024
258
240
3.3%
2028 - 2048
3,455
3,095
4.3%
2024 - 2045
4,336
4,042
12.7%
2024
18
—
4.9%
8.1%
2024 - 2041
2025 - 2026
1,225
275
608
(393)
1,475
275
667
(363)
80,980 75,640
(6,164)
(1,515)
72,939 67,961
(6,045)
(1,996)
1 For an initial five or 10 years, the notes carry a fixed interest rate. Subsequently, during each reset period the interest rate will be
reset to equal to the Five-Year US Treasury rate or Five-Year Government of Canada bond yield plus a margin. The notes would
be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.
2 For an initial five or 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 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 Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points and SOFR
plus a margin of 63 basis points.
4 Primarily finance lease obligations.
5 Included in medium-term notes is $100 million with a maturity date of 2112.
6 Primarily unamortized discounts, premiums and debt issuance costs.
7 2022 - $38 billion and US$31 billion; 2021 - $36 billion and US$31 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 4.5% as at December 31, 2022 (2021 - 0.5%).
9 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2022.
136
As at December 31, 2022, all outstanding debt was unsecured.
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at December 31, 2022:
(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
2023-2027
2024-2027
2024
2024
10,987
8,604
2,000
2,000
23,591
7,984
4,199
312
2,000
14,495
3,003
4,405
1,688
—
9,096
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, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility,
extending the maturity date out to July 2025.
On May 17, 2022, we entered into a three year term loan with a syndicate of Japanese banks for
approximately $806 million (¥84.8 billion), which will mature in May 2025 and replaces the approximately
$499 million (¥52.5 billion) term loan that matured in May 2022. Additionally, on May 24, 2022, we entered
into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023.
On June 23, 2022, we renewed approximately $5.5 billion of our 364-day extendible credit facilities to
July 2024, which includes a one-year term out provision from July 2023.
In July and August 2022, we renewed $12.7 billion of our credit facilities, extending the maturity dates of
our 364-day credit facilities to July 2024, inclusive of a one year term out provision from July 2023, and
our five year facilities out to July 2027. As a part of the renewals, we increased our credit facilities by
approximately $640 million.
On December 16, 2022, Enbridge (U.S.) Inc. entered into a five year delay draw term loan in support of
solar self-power projects for approximately $479 million, which will mature in December 2027.
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand
letter of credit facilities, of which $689 million was unutilized as at December 31, 2022. As at December
31, 2021, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $854 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
2023 to 2027.
As at December 31, 2022 and 2021, commercial paper and credit facility draws, net of short-term
borrowings and non-revolving credit facilities that mature within one year, of $10.5 billion and $11.3 billion,
respectively, were supported by the availability of long-term committed credit facilities and, therefore,
have been classified as long-term debt.
137
LONG-TERM DEBT ISSUANCES
During the year ended December 31, 2022, we completed the following long-term debt issuances totaling
US$3.2 billion and $3.4 billion:
Issue Date
Company
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
5.00% fixed-to-fixed subordinated notes due January 20821
January 2022
Floating rate senior notes due February 20242
February 2022
February 2022
2.15% senior notes due February 2024
2.50% senior notes due February 2025
February 2022
September 2022 7.38% fixed-to-fixed subordinated notes due January 20833
September 2022 7.63% fixed-to-fixed subordinated notes due January 20834
November 2022
November 2022
November 2022
5.70% medium-term notes due November 2027
6.10% sustainability-linked medium-term notes due November 20325
6.51% medium-term notes due November 2052
Enbridge Gas Inc.
August 2022
August 2022
4.15% medium-term notes due August 2032
4.55% medium-term notes due August 2052
Texas Eastern Transmission LP
December 2022
6.20% senior notes due December 2032
Principal
Amount
$750
US$600
US$400
US$500
US$500
US$600
$600
$900
$500
$325
$325
US$600
1 For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year
Government of Canada bond yield plus a margin of 3.54%. Subsequent to year 10, every five years, the Five-Year Government of
Canada bond yield is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield
plus a margin of 4.29%.
2 Notes carry an interest rate set to equal the SOFR plus a margin of 63 basis points.
3 For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be set to equal to the Five-Year US
Treasury rate plus a margin of 3.71%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a
margin of 3.96%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate
will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.71%.
4 For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US
Treasury rate plus a margin of 4.42%. Subsequent to year 10, every five years, the Five-Year US Treasury rate will be reset. At
year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.17%.
5 The sustainability-linked medium-term notes are subject to a sustainability performance target of 35% reduction in emissions
intensity at an observation date of December 31, 2030. If the target is not met, on November 9, 2031, the interest rate will be set
to equal 6.10% plus a margin of 70 basis points.
138
LONG-TERM DEBT REPAYMENTS
During the year ended December 31, 2022, we completed the following long-term debt repayments
totaling $1.5 billion and US$2.0 billion, respectively:
Company Repayment Date
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
February 2022
February 2022
July 2022
December 2022
December 2022
Floating rate notes1
4.85% medium-term notes
2.90% senior notes
3.19% medium-term notes
3.19% medium-term notes
Enbridge Gas Inc.
April 2022
4.85% medium-term notes
Enbridge Pipelines (Southern Lights) L.L.C.
June and December 2022 3.98% senior notes
Enbridge Pipelines Inc.
November 2022
Enbridge Southern Lights LP
2.93% medium-term notes
June and December 2022 4.01% senior notes
Texas Eastern Transmission, LP
October 2022
2.80% senior notes
Westcoast Energy Inc.
December 2022
3.12% medium-term notes
Principal
Amount
US$750
$200
US$700
$350
$450
$125
US$72
$150
$18
US$500
$250
1 Notes carried an interest rate set to equal the Three-Month LIBOR plus a margin of 50 basis points.
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, 2022, 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
2022
2021
2020
2,910
388
(45)
(74)
3,179
2,806
114
(50)
(215)
2,655
2,873
163
(54)
(192)
2,790
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, 2022 ranged from 1.5% to 9.0% (2021 - 0.9% to 9.0%).
139
A reconciliation of movements in our ARO liabilities is as follows:
December 31,
(millions of Canadian dollars)
Obligations at beginning of year
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
2022
502
30
(126)
51
24
7
488
83
405
488
2021
496
—
(67)
70
(3)
6
502
160
342
502
20. 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, LLC
Enbridge Athabasca Midstream Investor Limited Partnership1
Maritimes & Northeast Pipeline, L.L.C.
Renewable energy assets
Westcoast Energy Inc.2
Other
2022
400
1,106
582
1,302
117
4
3,511
2021
377
—
546
1,503
116
—
2,542
1 On October 5, 2022, we closed the sale of an 11.6% non-operating interest in certain assets from our Regional Oil Sands System
to Aii. Refer to Note 8 - Acquisitions and Dispositions.
2 During 2021, Westcoast Energy Inc. redeemed all of its remaining Cumulative Five-Year Minimum Rate Reset Redeemable First
Preferred Shares.
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
Share purchases at stated value1
Other
Balance at end of year
2022
Number
of
2021
Number
of
2020
Number
of
Shares Amount
Shares Amount
Shares Amount
2,026 64,799
2,026 64,768
2,025 64,746
2
(3)
—
53
(88)
(4)
2,025 64,760
—
—
—
31
—
—
2,026 64,799
1
—
—
22
—
—
2,026 64,768
1 Reflects the repurchase and cancellation of common shares under our normal course issuer bid.
140
PREFERENCE SHARES
December 31,
(millions of Canadian dollars; number of shares in
2022
Number
of
2021
Number
of
2020
Number
of
Shares Amount
Shares Amount
Shares Amount
millions)
Preference Shares, Series A
Preference Shares, Series B
Preference Shares, Series C1
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series J2
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 173
Preference Shares, Series 19
Issuance costs
Balance at end of year
5
20
—
18
20
14
—
16
18
16
16
16
24
8
10
11
20
14
11
—
20
125
500
—
450
500
350
—
411
450
400
400
411
600
206
250
275
500
350
275
—
500
(135)
6,818
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
1 On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B.
2 On June 1, 2022, we redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J.
3 On March 1, 2022, we redeemed our $750 million outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares,
Series 17.
141
Characteristics of our outstanding 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 B5
Preference Shares, Series D
Preference Shares, Series F
Preference Shares, Series H
Preference Shares, Series L6
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 19
$1.37500
5.50%
$1.30052
5.20%
$1.11500
4.46%
$1.17224
4.69%
$1.09400
4.38%
5.86% US$1.46448
$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%
$1.22500
4.90%
—
$25
$25
$25
US$25
$25
June 1, 2027
$25
March 1, 2023
$25
$25
June 1, 2023
$25 September 1, 2023
US$25 September 1, 2027
December 1, 2023
March 1, 2024
June 1, 2024
June 1, 2023
$25 September 1, 2024
March 1, 2024
US$25
March 1, 2024
$25
December 1, 2024
$25
March 1, 2025
$25
$25
June 1, 2025
$25 September 1, 2025
March 1, 2023
$25
—
Series C
Series E
Series G
Series I
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 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 Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial redemption
and conversion option date. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every
five years, will not be less than 4.90%. No other series of Preference Shares has this feature.
2 Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our
option, redeem all or a portion of the outstanding preference shares for the Base Redemption Value per share plus all accrued
and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.
3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference
Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an
ascribed issue price equal to the Base Redemption Value.
4 With the exception of Preference Shares, Series A, 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 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), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in
year) x Three-Month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6).
5 The quarterly dividend per share paid on Preference Shares, Series B was increased to $0.32513 from $0.21340 on June 1, 2022
due to reset of the annual dividend on June 1, 2022. On June 1, 2022, all outstanding Preference Shares, Series C were
converted to Preference Shares, Series B.
6 The quarterly dividend per share paid on Preference Shares, Series L was increased to US$0.36612 from US$0.30993 on
September 1, 2022, due to reset of the annual dividend on September 1, 2022.
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.
142
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, 2022, 2021
and 2020 was $260 million, $157 million and $145 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, 2022
(options in thousands; weighted average exercise price in
Canadian dollars; intrinsic value in millions of Canadian
dollars)
Options outstanding at beginning of year
Options granted
Options exercised1
Options cancelled or expired
Options outstanding at end of year
Options vested at end of year2
Number
34,017
3,430
(8,684)
(1,139)
27,624
17,631
Weighted
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
49.28
49.58
44.55
51.32
48.46
49.20
5.7
4.4
133
84
1 The total intrinsic value of ISOs exercised during the years ended December 31, 2022, 2021 and 2020 was $66 million, $24
million and $13 million, respectively, and cash received on exercise was $3 million, $2 million and $4 million, respectively.
2 The total fair value of ISOs exercised during the years ended December 31, 2022, 2021 and 2020 was $21 million, $25 million
and $30 million, respectively.
Weighted average assumptions used to determine the fair value of ISOs granted using the Black-
Scholes-Merton option pricing model are as follows:
Year ended December 31,
Fair value per option (Canadian dollars)1
Valuation assumptions
Expected option term (years)2
Expected volatility3
Expected dividend yield4
Risk-free interest rate5
2022
5.07
6
21.9%
6.5%
1.8%
2021
4.10
6
25.5%
7.6%
0.7%
2020
4.01
6
18.3%
5.9%
1.3%
1 Options granted to US employees are based on the New York Stock Exchange 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, 2022, 2021 and 2020 were $4.78, $3.91 and $3.75, respectively, for Canadian employees and US$4.62, US$3.65
and US$3.62, 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, 2022, 2021 and 2020 for ISOs was
$15 million, $16 million and $24 million, respectively. As at December 31, 2022, unrecognized
compensation expense related to non-vested stock-based compensation arrangements granted under the
ISO Plan was $12 million. The expense is expected to be fully recognized over a weighted average period
of approximately two years.
143
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 2.0 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, infrequent or other non-operating factors, relative to targets
established at the time of grant. To calculate the 2022 expense, a multiplier of 1.25 was used for 2022
PSU grants, 1.25 for 2021 PSU grants and 2.00 for the 2020 PSU grants.
December 31, 2022
(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
3,429
1,467
(131)
(1,700)
184
3,249
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
1.1
261
1 The total amount paid during the years ended December 31, 2022, 2021 and 2020 for PSUs was $90 million, $70 million and $14
million, respectively.
Compensation expense recorded for the years ended December 31, 2022, 2021 and 2020 for PSUs was
$169 million, $56 million and $76 million, respectively. As at December 31, 2022, unrecognized
compensation expense related to non-vested PSUs was $72 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
shares or cash equal to our weighted average share price for 20 days prior to the maturity of the grant
multiplied by the units outstanding on the maturity date.
December 31, 2022
(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
2,705
1,400
(134)
(602)
196
3,565
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
1.0
185
1 The total amount paid during the years ended December 31, 2022, 2021 and 2020 for RSUs was $32 million, $72 million and $27
million, respectively.
144
Compensation expense recorded for the years ended December 31, 2022, 2021 and 2020 for RSUs was
$76 million, $85 million and $44 million, respectively. As at December 31, 2022, unrecognized
compensation expense related to non-vested RSUs was $35 million. The expense is expected to be fully
recognized over a weighted average period of approximately two years.
23. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE
INCOME/(LOSS)
Changes in AOCI attributable to our common shareholders for the years ended December 31, 2022, 2021
and 2020 are as follows:
(millions of Canadian dollars)
Balance as at January 1, 2022
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive loss/(income)
reclassified to earnings
Interest rate contracts1
Foreign exchange contracts2
Other contracts3
Amortization of pension and OPEB
actuarial gain4
Other
Tax impact
Income tax on amounts retained in
AOCI
Income tax on amounts reclassified to
earnings
Balance as at December 31, 2022
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and
OPEB
Adjustment
Total
(897)
—
(166)
56
1,125
(35)
(971)
4,292
186
(4)
4
—
—
1,311
—
—
—
—
—
(35)
—
—
—
—
—
(971)
—
—
—
—
—
4,292
(250)
—
—
—
(43)
(293)
121
—
—
(35)
—
—
(1,137)
—
—
4,348
(5)
(6)
—
—
—
—
16
10
—
—
—
5
(84) (1,096)
411 4,816
—
—
—
186
(4)
4
(14)
—
(14)
16
397 5,004
(99)
(349)
(39)
4
(95)
(388)
218 3,520
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 as at January 1, 2021
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive loss/(income)
reclassified to earnings
Interest rate contracts1
Commodity contracts5
Foreign exchange contracts2
Other contracts3
Equity investment disposal
Amortization of pension and OPEB
actuarial loss and prior service costs4
Other
Tax impact
Income tax on amounts retained in
AOCI
Income tax on amounts reclassified to
earnings
Balance as at December 31, 2021
(1,326)
238
296
1
5
2
—
—
17
559
(61)
(69)
(130)
(897)
(215)
568
66
(499) (1,401)
49
(492)
(12)
520
298
—
—
—
—
—
—
—
49
—
—
—
—
—
—
(20)
(512)
—
—
—
—
(66)
—
3
(75)
—
—
—
—
—
28
—
548
296
1
5
2
(66)
28
—
564
—
—
—
(126)
(187)
—
—
(166)
—
—
56
4
4
(5)
(7)
(133)
(72)
(259)
(84) (1,096)
5
(5)
—
—
—
—
—
—
—
(5)
—
—
—
—
145
(millions of Canadian dollars)
Balance as at January 1, 2020
Other comprehensive income/(loss)
retained in AOCI
Other comprehensive loss/(income)
reclassified to earnings
Interest rate contracts1
Foreign exchange contracts2
Other contracts3
Amortization of pension and OPEB
actuarial loss and prior service costs4
Tax impact
Income tax on amounts retained in
AOCI
Income tax on amounts reclassified to
earnings
Balance as at December 31, 2020
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and
OPEB
Adjustment
Total
(1,073)
—
(317)
1,396
(591)
5
115
(828)
67
(2)
—
—
—
—
(2)
(345)
(272)
(221) (1,522)
—
—
—
253
5
(2)
17
17
(204) (1,249)
—
—
—
—
115
—
—
—
—
(828)
(13)
—
1
54
182
—
(13)
(215)
—
—
568
—
1
66
(4)
50
(62)
120
(499) (1,401)
253
5
(2)
—
(335)
140
(58)
82
(1,326)
—
—
—
—
5
—
—
—
5
1 Reported within Interest expense in the Consolidated Statements of Earnings.
2 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of
Earnings.
3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
4 These components are included in the computation of net periodic benefit (credit)/cost and are reported within Other income/
(expense) in the Consolidated Statements of Earnings.
5 Reported within Transportation and other services revenues, Commodity sales, Commodity costs and Operating and
administrative 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 cash flow, fair value 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.
146
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 hedging program to partially mitigate the impact of short-term
interest rate volatility on interest expense via execution of floating to fixed interest rate swaps. These
hedges have an average fixed rate of 4.0%.
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, 2022, 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 partially mitigate our exposure to long-term interest rate variability on forecasted term debt
issuances via execution of floating to fixed interest rate swaps with an average swap rate of 2.2%.
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
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.
147
The following table summarizes the Consolidated Statements of Financial Position location and carrying
value of our derivative instruments, as well as the maximum potential settlement amounts in the event of
the specific circumstances described above. All amounts are presented gross in the Consolidated
Statements of Financial Position.
December 31, 2022
(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
Commodity contracts
Other long-term liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net derivative asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as
Fair Value
Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as
Presented
Amounts
Available for
Offset
Total Net
Derivative
Instruments
—
649
—
—
649
—
254
—
1
255
—
(48)
(48)
—
(3)
(37)
(40)
—
900
(85)
1
816
—
—
—
—
—
156
—
—
—
156
(42)
—
(42)
—
—
—
—
114
—
—
—
114
46
11
302
7
366
153
—
61
2
216
(524)
(284)
(808)
(1,116)
(1)
(133)
(1,250)
(1,441)
10
(54)
9
(1,476)
46
660
302
7
1,015
309
254
61
3
627
(566)
(332)
(898)
(1,116)
(4)
(170)
(1,290)
(1,327)
910
(139)
10
(546)
(41)
—
(182)
—
(223)
(138)
—
(25)
—
(163)
41
182
223
138
—
25
163
—
—
—
—
—
5
660
120
7
792
171
254
36
3
464
(525)
(150)
(675)
(978)
(4)
(145)
(1,127)
(1,327)
910
(139)
10
(546)
148
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 long-term liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net derivative asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as
Fair Value
Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as
Presented
Amounts
Available for
Offset
Total Net
Derivative
Instruments
—
64
—
—
64
—
88
—
—
88
(15)
(150)
(14)
(179)
—
(1)
(17)
(18)
(15)
1
(31)
—
(45)
—
—
—
—
—
—
—
—
—
—
(112)
—
—
(112)
—
—
—
—
(112)
—
—
—
(112)
259
—
204
2
465
240
—
29
3
272
(176)
—
(250)
(426)
(423)
(23)
(67)
(513)
(100)
(23)
(84)
5
(202)
259
64
204
2
529
240
88
29
3
360
(303)
(150)
(264)
(717)
(423)
(24)
(84)
(531)
(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)
149
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))
2023
2024
2025
2026
2027 Thereafter
Total
2022
2021
Total
655
1,000
500
—
—
—
2,155
2,508
8,297
6,386
4,613
4,121
2,837
1,356
27,610
25,427
29
30
30
28
32
—
92
91
86
85
81
262
149
697
177
801
—
— 84,800
—
—
—
84,800
72,500
8,698
538
30
26
25
39
9,356
597
5,496
1,766
589
37
31
12
52
25
15
—
—
1
16
—
—
—
—
—
—
—
26
(25)
(44)
—
—
—
7,851
5,279
—
—
—
—
80
93
16
67
199
12
1
(14)
1
(43)
1 Total is an average net purchase/(sell) of power.
Fair Value Derivatives
For foreign exchange derivative instruments that are designated and qualify as fair value hedges, the gain
or loss on the derivative is included in Other income/(expense) or Interest expense in the Consolidated
Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is
included in Other income/(expense) in the Consolidated Statements of Earnings. Any excluded
components are included in the Consolidated Statements of Comprehensive Income.
Year ended December 31,
(millions of Canadian dollars)
Unrealized gain on derivative
Unrealized loss on hedged item
Realized loss on derivative
Realized gain on hedged item
2022
2021
262
(254)
(110)
85
8
(15)
(41)
45
150
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 contracts3
2022
2021
2020
3
1,151
(53)
(4)
(29)
252
(28)
1
(1)
(595)
2
(3)
(35)
(5)
5
—
1,062
13
186
—
4
203
—
191
5
296
1
2
304
13
(579)
5
253
—
(2)
256
1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of
Earnings.
2 Reported within Interest expense in the Consolidated Statements of Earnings.
3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
We estimate that a gain of $67 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, 2022.
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
2022
2021
2020
(1,344)
10
50
4
(1,280)
92
2
71
8
173
902
(25)
(114)
(7)
756
1 For the respective annual periods, reported within Transportation and other services revenue (2022 - $238 million loss; 2021 -
$98 million gain; 2020 - $533 million gain) and Other income/(expense) (2022 - $1,106 million loss; 2021 - $6 million loss; 2020 -
$369 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 (2022 - $13 million gain; 2021 - $9
million gain; 2020 - $2 million loss), Commodity sales (2022 - $89 million gain; 2021 - $160 million gain; 2020 - $321 million loss),
Commodity costs (2022 - $102 million loss; 2021 - $105 million loss; 2020 - $207 million gain) and Operating and administrative
expense (2022 - $50 million gain; 2021 - $7 million gain; 2020 - $2 million gain) in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
151
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. Our shelf prospectuses with securities regulators enable 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, 2022. As a result, all
credit facilities are available to us and the banks are obligated to fund 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.
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
2022
2021
644
277
334
224
105
1,584
424
130
181
30
122
887
1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at December 31, 2022, we did not provide any letters of credit 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, 2022 and
December 31, 2021.
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.
152
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 utility's large and diversified customer base and the
ability to recover an estimate for expected credit losses 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 utilize a loss allowance matrix which
contemplates historical credit losses by age of receivables, adjusted for any forward-looking information
and management expectations to measure lifetime expected credit losses of receivables. 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 financial 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 financial instruments 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 financial instrument 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, US and
Canadian treasury bills, investments in exchange-traded equity funds held by our captive insurance
subsidiaries, as well as restricted long-term investments in Canadian equity securities that are held in
trust in accordance with the CER's regulatory requirements under the LMCI.
Level 2
Level 2 includes financial instrument valuations determined using directly or indirectly observable inputs
other than quoted prices included within Level 1. Financial instruments in this category are valued using
models or other industry standard valuation techniques derived from observable market data. Such
valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker
quotes that can be observed or corroborated in the market for the entire duration of the financial
instrument. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as
over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps,
physical forward commodity contracts, as well as commodity swaps and options for which observable
inputs can be obtained.
We have also categorized the fair value of our long-term debt, investments in debt securities held by our
captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held
in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our
long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor.
When possible, the fair value of our restricted long-term investments is based on quoted market prices for
similar instruments and, if not available, based on broker quotes.
153
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, NGL and natural gas contracts, basis swaps,
commodity swaps, and 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.
We have categorized our derivative assets and liabilities measured at fair value as follows:
December 31, 2022
(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
Commodity contracts
Long-term derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net financial asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments
—
—
65
—
65
—
—
—
—
—
—
(60)
(60)
—
—
—
—
—
—
5
—
5
46
660
90
7
803
309
254
17
3
583
(566)
(77)
(643)
(1,116)
(4)
(38)
(1,158)
(1,327)
910
(8)
10
(415)
—
—
147
—
147
—
—
44
—
44
—
(195)
(195)
—
—
(132)
(132)
—
—
(136)
—
(136)
46
660
302
7
1,015
309
254
61
3
627
(566)
(332)
(898)
(1,116)
(4)
(170)
(1,290)
(1,327)
910
(139)
10
(546)
154
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
Long-term derivative liabilities
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Total net financial asset/(liability)
Foreign exchange contracts
Interest rate contracts
Commodity contracts
Other contracts
Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments
—
—
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)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
were as follows:
December 31, 2022
(fair value in millions of Canadian
dollars)
Commodity contracts - financial1
Natural gas
Crude
Power
Commodity contracts - physical1
Natural gas
Crude
Power
Fair Value
Unobservable Input
Minimum
Price
Maximum
Price
Weighted
Average Price
Unit of
Measurement
(35)
(4)
(71)
Forward gas price
Forward crude price
Forward power price
Forward gas price
Forward crude price
Forward power price
(41)
(2)
17
(136)
4.57
71.10
36.63
1.67
64.43
30.49
34.56
105.22
364.00
33.89
116.60
183.88
6.25
83.26
103.30
6.00
86.25
72.48
$/mmbtu2
$/barrel
$/MW/H
$/mmbtu2
$/barrel
$/MW/H
1 Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2 One million British thermal units (mmbtu).
155
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. Changes in
forward commodity prices could result in significantly different fair values for our Level 3 derivatives.
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
2022
2021
(108)
(191)
6
(54)
20
(136)
(39)
(29)
151
(108)
1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the
Consolidated Statements of Earnings.
There were no transfers into or out of Level 3 as at December 31, 2022 or 2021.
NET INVESTMENT HEDGES
We currently have designated a portion of our US dollar-denominated debt as a hedge of our net
investment in US dollar-denominated investments and subsidiaries.
During the years ended December 31, 2022 and 2021, we recognized an unrealized foreign exchange
loss of $954 million and gain of $49 million, respectively, on the translation of US dollar-denominated
debt, in OCI. No unrealized gains or losses on the change in fair value of our outstanding foreign
exchange forward contracts were recognized in OCI during the years ended December 31, 2022 and
2021. No realized gains or losses associated with the settlement of foreign exchange forward contracts
were recognized in OCI during the years ended December 31, 2022 and 2021. During the years ended
December 31, 2022 and 2021, we recognized a realized loss of $21 million and nil, respectively,
associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.
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
$102 million and $52 million as at December 31, 2022 and 2021, respectively.
As at December 31, 2022, the fair value of short- and long-term investments in equity funds and debt
securities held by our captive insurance subsidiaries was $145 million and $488 million, respectively
(2021 - $14 million and $290 million, respectively). These investments in equity funds and debt securities
are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, and are recorded
in Accounts receivable and other and Long-term investments, respectively, in the Consolidated
Statements of Financial Position. There were unrealized holding losses in equity funds and debt securities
of $26 million for the year ended December 31, 2022 (2021 - losses of $12 million).
As at December 31, 2022 and 2021, our long-term debt had a carrying value of $79.3 billion and $74.4
billion, respectively, before debt issuance costs and a fair value of $73.5 billion and $82.0 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, 2022
and 2021, the non-current notes receivable had a carrying value of $752 million and $954 million,
respectively, which also approximates their fair value.
156
The fair value of financial assets and liabilities other than derivative instruments, long-term investments,
restricted long-term investments, long-term debt and non-current notes receivable described above
approximate their carrying value 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 deductions
Part VI.1 tax, net of federal Part I deduction4
US Minimum Tax5
Non-taxable portion of gain on sale of investment6
Valuation allowance
Accounting impairment of non-deductible goodwill7
Noncontrolling interests8
Other9
Income tax expense
Effective income tax rate
2022
2021
2020
4,542
15%
681
108
295
(122)
—
76
107
—
6
370
9
74
1,604
35.3%
7,729
15%
1,159
228
134
(139)
—
73
—
(23)
5
—
(17)
(5)
1,415
18.3%
4,190
15%
629
288
(53)
(145)
(4)
76
44
—
(6)
—
(8)
(47)
774
18.5%
1 The change in provincial and state income taxes from 2021 to 2022 reflects the decrease in earnings from Canadian operations
and the effect of the reduction in the Pennsylvania corporate income tax rate in the US, partially offset by the increase in earnings
from US operations before the non-deductible goodwill impairment relating to the Gas Transmission reporting unit in combination
with state tax apportionment changes. Refer to Note 16 - Goodwill.
2 The change in foreign and other statutory rate differentials from 2021 to 2022 reflects the increase in earnings from US
operations, before the goodwill impairment relating to the Gas Transmission reporting unit. Refer to Note 16 - Goodwill.
3 The amount in 2022 relates to the federal component of the tax impact relating to the 2022 variable consideration attributable to
the Canadian Mainline. Refer to Note 4 - Revenue.
4 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada.
5 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation.
6 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco.
7 The amount in 2022 relates to the federal impact of the non-deductible goodwill impairment relating to the Gas Transmission
reporting unit. Refer to Note 16 - Goodwill.
8 The amount in 2022 includes the federal tax impact of an impairment to Magic Valley attributable to noncontrolling interests. Refer
to Note 11 - Property, Plant and Equipment.
9 The amount in 2022 includes the federal component of the tax impact relating to the 2021 variable consideration attributable to
the Canadian Mainline. Refer to Note 4 - Revenue.
157
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
2022
2021
2020
583
2,865
1,094
4,542
3,399
3,336
994
7,729
2,789
407
994
4,190
360
201
86
647
(358)
1,309
6
957
1,604
162
80
82
324
344
741
6
1,091
1,415
165
64
98
327
378
66
3
447
774
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
Pension and OPEB plans
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
2022
2021
(9,096)
(7,099)
(1,291)
(30)
(46)
(17,562)
456
—
2,259
1,753
4,468
(215)
4,253
(13,309)
472
(13,781)
(13,309)
(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)
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.
158
As at December 31, 2022, we recognized the benefit of unused tax loss carryforwards of $2.1 billion
(2021 - $1.9 billion) in Canada which expire in 2030 and beyond.
As at December 31, 2022, we recognized the benefit of unused tax loss carryforwards of $8.1 billion
(2021 - $11.0 billion) in the US. Unused tax loss carryforwards of $0.2 billion (2021 - $3.5 billion) begin to
expire in 2023, and unused tax loss carryforwards of $7.9 billion (2021 - $7.5 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 $8.0 billion and $4.3
billion for the periods ended December 31, 2022 and 2021, 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 applicable to 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 Québec). We are open to examination by Canadian tax
authorities for the 2015 to 2022 tax years and by US tax authorities for the 2019 to 2022 tax years. We
are currently under examination for income tax matters in Canada for the 2016 to 2019 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
2022
2021
76
—
(17)
1
(5)
55
121
1
(26)
(1)
(19)
76
The unrecognized tax benefits as at December 31, 2022, 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, 2022
and 2021 were a $1 million expense and $5 million recovery, respectively. As at December 31, 2022 and
2021, interest and penalties of $13 million and $12 million, respectively, have been accrued.
159
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
pension plans provide defined benefit and defined contribution pension benefits to our Canadian
employees. The US pension 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.
160
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 gain1
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/(loss) on plan assets
Employer contributions3
Participant contributions
Benefits paid
Foreign currency exchange rate changes
Other
Fair value of plan assets at end of year4
Overfunded/(underfunded) status at end of year
Presented as follows:
Deferred amounts and other assets
Accounts payable and other
Other long-term liabilities
Canada
US
2022
2021
2022
2021
4,600
131
127
29
(1,069)
(187)
—
(1)
3,630
4,536
(235)
91
29
(187)
—
—
4,234
604
764
(9)
(151)
604
4,855
139
101
28
(329)
(194)
—
—
4,600
4,077
505
120
28
(194)
—
—
4,536
(64)
250
(9)
(305)
(64)
1,184
43
24
—
(201)
(94)
77
(4)
1,029
1,160
(64)
4
—
(94)
78
(4)
1,080
51
141
(5)
(85)
51
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 Actuarial gains in 2022 and 2021 primarily due to increase in the discount rates used to measure the benefit obligations.
2 The accumulated benefit obligation for our Canadian pension plans was $3.4 billion and $4.3 billion as at December 31, 2022 and
2021, respectively. The accumulated benefit obligation for our US pension plans was $1.0 billion and $1.1 billion as at
December 31, 2022 and 2021, respectively.
3 Lower employer contributions in 2022 compared to 2021 primarily due to more plans in an overfunded status.
4 Assets in the amount of $10 million (2021 - $13 million) and $58 million (2021 - $84 million), related to our Canadian and US 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.
161
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
2022
2021
2022
2021
360
218
440
247
89
—
115
—
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
377
218
1,272
1,020
90
—
121
—
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 (gain)/loss
Prior service (credit)/cost
Total amount recognized in AOCI1
1 Excludes amounts related to CTA.
Canada
US
2022
2021
2022
2021
(64)
—
(64)
226
—
226
40
1
41
92
(1)
91
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:
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
2021
2022
2020
2022
US
2021
2020
131
127
(295)
8
—
(29)
10
(19)
(2)
—
(288)
(290)
(309)
139
101
(252)
54
—
42
7
49
(25)
—
(291)
(316)
(267)
148
128
(260)
42
—
58
6
64
(21)
—
118
97
161
43
24
(85)
—
(2)
(20)
—
(20)
—
2
(52)
(50)
(70)
44
17
(73)
11
—
(1)
—
(1)
(11)
—
(99)
(110)
(111)
44
31
(88)
1
(1)
(13)
—
(13)
(1)
1
100
100
87
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
162
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
2022
2021
2020
2022
2021
2020
5.1 %
2.9 %
N/A
3.2 %
6.6 %
2.9 %
N/A
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
4.9 %
2.8 %
4.3 %
2.6 %
7.4 %
2.8 %
4.3 %
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 %
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.
163
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
Accumulated postretirement benefit obligation at beginning
of year
Service cost
Interest cost
Participant contributions
Actuarial gain1
Benefits paid
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/(loss) 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
Canada
US
2022
2021
2022
2021
274
4
7
—
(66)
(8)
—
—
211
—
—
8
—
(8)
—
—
—
(211)
—
(12)
(199)
(211)
321
6
7
—
(51)
(9)
—
—
274
—
—
9
—
(9)
—
—
—
(274)
—
(12)
(262)
(274)
173
1
3
6
(37)
(21)
11
—
136
201
(21)
7
6
(21)
13
—
185
49
75
—
(26)
49
254
1
3
8
(69)
(22)
(3)
1
173
188
22
6
8
(22)
(3)
2
201
28
71
—
(43)
28
1 Actuarial gains in 2022 and 2021 primarily due to increase in the discount rates used to measure the benefit obligations.
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
2022
2021
2022
2021
211
—
274
—
76
50
94
51
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
Prior service credit
Total amount recognized in AOCI1
1 Excludes amounts related to CTA.
164
Canada
US
2022
2021
2022
2021
(101)
(1)
(102)
(35)
(1)
(36)
(102)
(30)
(132)
(104)
(37)
(141)
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
2021
2022
2020
2022
US
2021
1
3
(10)
(1)
(7)
2020
2
7
(12)
(1)
(2)
5
8
—
(1)
—
1
3
(12)
(6)
(7)
12
1
—
21
—
22
34
(21)
(14)
(6)
6
7
(4)
—
9
(12)
1
7
(80)
—
(72)
(86)
1
2
15
(33)
(15)
(21)
4
7
—
(1)
—
6
7
—
—
—
10
13
1
—
(67)
—
(66)
(56)
—
—
(50)
—
(50)
(37)
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
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
2022
2021
2020
2022
2021
2020
5.3 %
3.2 %
2.6 %
4.9 %
2.4 %
2.0 %
3.2 %
N/A
2.6 %
N/A
3.1 %
N/A
2.4 %
6.0 %
2.0 %
6.0 %
2.8 %
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
2022
4.0 %
4.0 %
N/A
2021
4.0 %
US1
2022
4.7 %
4.0 %
3.3 %
N/A 2021 - 2045
2021
7.0 %
4.5 %
2037
1 In addition, under the Enbridge Employee Services, Inc., Health Reimbursement Account Plan, health care costs will increase by
5.0% every three years.
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.
165
(millions of Canadian dollars)
December 31, 2022
Cash and cash equivalents
Equity securities
Canada
Global
Fixed income securities
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 %
28.4 %
27.8 %
December 31,
Target
2022
38.2 %
31.7 %
30.1 %
2021 Allocation
45.0 %
20.0 %
35.0 %
46.7 %
29.8 %
23.5 %
US
December 31,
2022
38.3 %
20.5 %
41.2 %
2021
52.5 %
18.4 %
29.1 %
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.
Pension Plans
The following table summarizes the fair value of plan assets for our pension plans recorded at each fair
value hierarchy level:
Level 11
Level 22
Level 33
Total
Level 11
Level 22
Level 33
Total
Canada
US
272
—
—
272
13
—
—
13
—
—
355
1,263
—
—
355
1,263
Government
Corporate
Alternatives4
Forward currency contracts
Total pension plan assets at fair value
201
—
—
—
473
435
433
—
(16)
2,470
—
—
1,291
—
1,291
636
433
1,291
(16)
4,234
—
—
—
—
—
—
13
—
414
87
121
—
—
622
—
—
—
414
—
—
445
—
445
87
121
445
—
1,080
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
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
—
—
—
—
—
337
—
337
—
—
609
86
118
337
—
1,160
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.
166
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
Purchases and settlements, net
Balance at end of year
Canada
US
2022
2021
2022
2021
1,064
155
72
1,291
912
77
75
1,064
337
78
30
445
289
38
10
337
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, 2022
Cash and cash equivalents
Equity securities
US
Global
Fixed income securities
Government
Corporate
Alternatives4
Total OPEB plan assets at fair value
December 31, 2021
Cash and cash equivalents
Equity securities
US
Global
Fixed income securities
Government
Corporate
Alternatives4
Total OPEB plan assets at fair value
2
—
—
46
—
—
48
4
—
—
47
—
—
51
—
34
62
5
8
—
109
—
39
75
6
8
—
128
—
—
—
—
—
28
28
—
—
—
—
—
22
22
2
34
62
51
8
28
185
4
39
75
53
8
22
201
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
2022
2021
22
4
2
28
22
2
(2)
22
167
EXPECTED BENEFIT PAYMENTS
Year ending December 31,
(millions of Canadian dollars)
Pension
Canada
US
OPEB
Canada
US
2023
2024
2025
2026
2027
2028-2032
204
88
12
16
210
87
12
15
216
87
13
14
221
88
13
13
226
90
13
12
1,208
424
68
49
EXPECTED EMPLOYER CONTRIBUTIONS
In 2023, we expect to contribute approximately $29 million and $5 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 year ended December 31, 2022, pre-tax employer matching contribution costs were $30
million ($27 million in each of 2021 and 2020).
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 1 month to 24 years as at December 31, 2022.
For the years ended December 31, 2022, 2021 and 2020, we incurred operating lease expenses of $118
million, $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, 2022, 2021 and 2020, operating lease payments to settle lease
liabilities were $123 million, $118 million and $133 million, respectively. Operating lease payments are
reported under Operating activities in the Consolidated Statements of Cash Flows.
168
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
Weighted average discount rate
Operating leases
Finance leases
December 31,
2022
December 31,
2021
680
87
677
764
62
17
39
56
645
92
612
704
49
13
33
46
12 years
5 years
12 years
7 years
4.2 %
4.4 %
4.1 %
3.8 %
1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2022 were $47 million (December
31, 2021 - $51 million), $5 million (December 31, 2021 - $5 million) and $43 million (December 31, 2021 - $47 million),
respectively.
2 Operating lease ROU 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 ROU 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, 2022, our operating and finance lease liabilities are expected to mature as follows:
(millions of Canadian dollars)
2023
2024
2025
2026
2027
Thereafter
Total undiscounted lease payments
Less imputed interest
Total
Operating
leases
Finance
leases
109
110
104
90
82
489
984
(220)
764
19
16
8
8
1
10
62
(6)
56
169
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 29 years as at December 31, 2022.
Year ended December 31,
(millions of Canadian dollars)
Operating lease income
Variable lease income
Total lease income1
2022
2021
2020
266
321
587
263
333
596
265
361
626
1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.
As at December 31, 2022, our future lease payments to be received under operating lease contracts
where we are the lessor are as follows:
(millions of Canadian dollars)
2023
2024
2025
2026
2027
Thereafter
Future lease payments
28. OTHER INCOME/(EXPENSE)
Year ended December 31,
(millions of Canadian dollars)
Gain/(loss) on dispositions
Realized foreign currency gain/(loss)
Unrealized foreign currency gain/(loss)
Net defined pension and OPEB credit
Other
Operating
leases
227
215
204
198
201
1,832
2,877
2022
2021
2020
(12)
92
(1,094)
239
186
(589)
319
126
160
150
224
979
(17)
(10)
191
148
(74)
238
29. 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
2022
2021
2020
(967)
17
(599)
1
1,100
16
58
362
(12)
(1,228)
(38)
(118)
(195)
87
52
43
(69)
(1,466)
1,546
8
(254)
(586)
(770)
1
31
117
93
170
30. 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.
Our transactions with significantly influenced investees are as follows:
Year ended December 31,
(millions of Canadian dollars)
Transportation and other revenues
Commodity sales
Operating and administrative1
Commodity costs2
Gas distribution costs
2022
2021
2020
185
51
503
778
136
237
20
380
790
131
219
21
338
518
135
1 During the years ended December 31, 2022, 2021 and 2020, we had Operating and administrative costs from the Seaway Crude
Pipeline System of $495 million, $389 million and $342 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.
2 During the years ended December 31, 2022, 2021 and 2020, we had Commodity costs from Aux Sable Canada LP of $571
million, $447 million and $91 million, respectively.
LONG-TERM NOTES RECEIVABLE FROM AFFILIATES
As at December 31, 2022, amounts receivable from affiliates include a series of loans totaling $752
million (2021 - $954 million), which require quarterly or semi-annual interest payments at annual interest
rates ranging from 3% to 8%. Interest income recognized from these notes totaled $30 million, $39 million
and $44 million for the years ended December 31, 2022, 2021 and 2020, respectively. The amounts
receivable from affiliates are included in Deferred amounts and other assets in the Consolidated
Statements of Financial position.
171
31. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As at December 31, 2022, we have commitments as detailed below:
(millions of Canadian dollars)
Annual debt maturities1
Purchase of services, pipe and other
materials, including transportation2
Maintenance agreements3
Right-of-ways commitments
Total
Less
than
Total
1 year 2 years 3 years 4 years 5 years Thereafter
78,742 6,024 8,220 6,051 3,730 10,344
44,373
10,661 3,553 1,513 1,070 1,001
53
46
767
55
536
46
1,474
91,413 9,675 9,831 7,220 4,830 11,212
53
45
53
45
53
46
2,757
269
1,246
48,645
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 capital and operating commitments. Consists primarily of firm capacity payments that provide us with uninterrupted firm
access to natural gas and crude oil transportation and storage contracts; contractual obligations to purchase physical quantities of
natural gas; and power commitments.
3 Consists primarily of maintenance service contracts for our wind and solar assets.
ENVIRONMENTAL
We are subject to various Canadian and US federal, provincial/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 obligations 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 costs 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.
172
OTHER LITIGATION
We and our subsidiaries are subject to various other legal and regulatory actions and proceedings which
arise in the normal course of business, including interventions in regulatory proceedings and challenges
to regulatory approvals and permits. 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.
INSURANCE
We maintain a comprehensive insurance program for us, our operating subsidiaries and certain equity
investments. This program includes insurance coverage in types and amounts and is subject to certain
deductibles, terms, exclusions and conditions that are generally consistent with coverage considered
customary for our industry, however insurance does not cover all events in all circumstances. We self-
insure a significant portion of expected losses relating to certain insurance property and casualty risk
exposures in the US and Canada through our wholly-owned captive insurance subsidiaries.
In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same
insurance period, the total insurance coverage will be allocated among entities on an equitable basis
based on an insurance allocation agreement we have entered into with us and other subsidiaries.
Insurance estimates include certain assumptions and management judgments regarding the frequency
and severity of claims, claim development and settlement practices and the selection of estimated loss
among estimates derived using different methods.
32. 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 in 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.
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.
173
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, 2022, 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.
33. QUARTERLY FINANCIAL DATA (UNAUDITED)
Q1
Q2
Q3
Q4
Total
(unaudited; millions of Canadian dollars, except per
share amounts)
2022
Operating revenues
Operating income/(loss)
Earnings/(loss)
Earnings/(loss) attributable to controlling
interests
Earnings/(loss) attributable to common
shareholders
Earnings/(loss) per common share
Basic
Diluted
2021
Operating revenues
Operating income
Earnings
Earnings attributable to controlling interests
Earnings attributable to common
shareholders
Earnings per common share
Basic
Diluted
15,097
2,420
2,057
13,215
1,520
607
11,573
1,778
1,383
13,424
(540)
(1,109)
53,309
5,178
2,938
2,029
595
1,362
(983)
3,003
1,927
450
1,279
(1,067)
2,589
0.95
0.95
0.22
0.22
0.63
0.63
(0.53)
(0.53)
1.28
1.28
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
174
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, 2022, 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, 2022, 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, 2022.
The effectiveness of our internal control over financial reporting as at December 31, 2022 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, 2022.
175
Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2022, there has been no material change in our internal
control over financial reporting.
ITEM 9B. OTHER INFORMATION
NORMAL COURSE ISSUER BID
On January 4, 2023, we announced that the TSX had approved our new NCIB to purchase, for
cancellation, up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of
up to $1.5 billion.
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 6, 2023 and continuing
until January 5, 2024, when the NCIB expires, or such earlier date on which Enbridge has either acquired
the maximum number of common shares allowable under the NCIB or otherwise decided not to make any
further repurchases under the NCIB.
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.
176
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, 2022. 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, 2022. 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, 2022. 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, 2022. 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, 2022. 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, 2022. This information will also be disclosed in the management proxy
information that we prepare in accordance with Canadian corporate and securities law requirements.
177
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.
178
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
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)
179
3.16
3.17
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
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)
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)
180
3.37
3.38
3.39
3.40
3.41
3.42
3.43
3.44
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
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)
Certificate of Amendment, dated January 17, 2022 (incorporated by reference to
Exhibit 3.1 to Enbridge’s Current Report on Form 8-K filed January 20, 2022)
Certificate of Amendment, dated January September 15, 2022 (incorporated by
reference to Exhibit 3.1 to Enbridge’s Current Report on Form 8-K filed September 20,
2022)
Certificate of Amendment, dated January September 15, 2022 (incorporated by
reference to Exhibit 3.2 to Enbridge’s Current Report on Form 8-K filed September 20,
2022)
General By-Law No. 1 of Enbridge Inc. (incorporated by reference to Exhibit 3.40 to
Enbridge’s Form 10-K filed February 11, 2022)
By-Law No. 2 of Enbridge Inc. (incorporated by reference to Enbridge’s Current Report
on Form 6-K filed December 5, 2014)
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)
Ninth Supplemental Indenture to the Indenture between Enbridge Inc. and Deutsche
Bank Trust Company Americas, dated September 20, 2022 (incorporated by reference
to Exhibit 4.1 to Enbridge’s Current Report on Form 8-K filed September 20, 2022)
181
4.11
4.12
4.13
10.1
10.2
10.3
10.4
10.5
10.6
Tenth Supplemental Indenture to the Indenture between Enbridge Inc. and Deutsche
Bank Trust Company Americas, dated September 20, 2022 (incorporated by reference
to Exhibit 4.2 to Enbridge’s Current Report on Form 8-K filed September 20, 2022)
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)
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)
10.7
+ 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)
10.8
+ Form of Executive Employment Agreement (2014-2016) (incorporated by reference to
10.9
10.10
10.11
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)
+ Form of Executive Employment Agreement (2022) with Enbridge Employee Services,
Inc. (incorporated by reference to Exhibit 10.1 to Enbridge’s Form 10-Q filed on July
29, 2022)
10.12
+ 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)
182
10.13
+ Enbridge Inc. 2019 Long Term Incentive Plan (incorporated by reference to Appendix A
10.14
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 Restricted Stock Unit Grant
Notice and Restricted Grant Unit Award Agreement (Share-settled) – Retention Award
Version (incorporated by reference to Exhibit 99.1 to Enbridge’s 8-K filed November
30, 2022)
10.15
+ 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)
10.16
+ 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)
10.17
+ 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)
10.18
+ 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)
10.19
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit - Energy
10.20
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)
10.21
+ 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)
10.22
+ 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)
10.23
+ 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)
10.24
+ Form of Enbridge Inc. 2019 Long Term Incentive Plan Stock Option Grant Notice and
10.25
10.26
10.27
10.28
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)
+ 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)
183
10.29
+ 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)
10.30
+ 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)
10.31
+ 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)
10.32
+ 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)
10.33
+ 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),
10.34
+ 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)
10.35
+ 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)
10.36
+ 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)
10.37
+ 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)
10.38
+ The Enbridge Supplemental Pension Plan, As Amended and Restated Effective
10.39
10.40
January 1, 2018 (incorporated by reference as Exhibit 10.1 to Enbridge’s Quarterly
Report on Form 10-Q filed May 10, 2018)
+ 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)
+ 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)
10.41
+ 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)
10.42 +* Fourth Amendment to The Enbridge Supplemental Pension Plan for United States
Employees (As Amended and Restated Effective January 1, 2005)
10.43 +* Fifth Amendment to The Enbridge Supplemental Pension Plan for United States
Employees (As Amended and Restated Effective January 1, 2005)
10.44
+ 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)
184
10.45
10.46
+ 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)
10.47
+ 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)
10.48
+ 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)
10.49
+ 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)
10.50
+ 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)
10.51
+ 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)
21.1
22.1
23.1
24.1
31.1
31.2
32.1
* 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).
185
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.
Date: February 10, 2023
ENBRIDGE INC.
(Registrant)
By: /s/ Gregory L. Ebel
Gregory L. Ebel
President and Chief Executive Officer
186
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below
on February 10, 2023 by the following persons on behalf of the registrant and in the capacities indicated.
/s/ Gregory L. Ebel
Gregory L. Ebel
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/ Susan M. Cunningham
Susan M. Cunningham
Director
/s/ Teresa S. Madden
Teresa S. Madden
Director
/s/ S. Jane Rowe
S. Jane Rowe
Director
/s/ Steven W. Williams
Steven W. Williams
Director
/s/ Vern D. Yu
Vern D. Yu
Executive Vice President, Corporate Development, Chief
Financial Officer and President, New Energy Technologies
(Principal Financial Officer)
/s/ Pamela L. Carter
Pamela L. Carter
Chair of the Board of Directors
/s/ Gaurdie E. Banister
Gaurdie E. Banister
Director
/s/ Jason B. Few
Jason B. Few
Director
/s/ Stephen S. Poloz
Stephen S. Poloz
Director
/s/ Dan C. Tutcher
Dan C. Tutcher
Director
187
Investor information
Investor inquiries
2023 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 3, 2023 at 1:30 p.m. MDT. 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
$0.89
Q2
$ – 2
Q3
$ – 2
Mar 01
Jun 01
Sep 01
Feb 15
May 15
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
(as of December 31, 2022)
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 D – ENB.PR.D
Series F – ENB.PR.F
Series H – ENB.PR.H
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 our corporate vision and strategy, the supply of and demand for energy, energy transition
and lower-carbon energy, ESG goals, and growth opportunities and outlook. 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 (MD&A), included in this Annual Report and available on both sedar.com and sec.gov.
Non-GAAP and other financial measures
The MD&A included in this Annual Report makes reference to non-GAAP and other financial
measures, including EBITDA. EBITDA is defined as earnings before interest, income taxes and
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 are not measures that have a standardized meaning
prescribed by the accounting principles generally accepted 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 in our earnings news releases and on our website, sedar.com or sec.gov.
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.